10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

___________________________________________________________________________________________

Form 10-K

___________________________________________________________________________________________

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2018

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period from ______ to ______

Commission file number 000-54369

 

CITADEL EXPLORATION, INC.

(Exact name of registrant as specified in its charter)

Nevada	27-1550482
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

417 31^st Street, Unit A

Newport Beach, CA 92663

(Address of principal executive offices)

(949) 612-8040

(Registrant’s telephone number, including area code)

Securities registered pursuant to	Securities registered pursuant to
Section 12(b) of the Act:	Section 12(g) of the Act:
None	Common Stock, $0.001 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer (Do not check if a smaller reporting company)	☐	Smaller reporting company	☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐  No ☒

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of December 29, 2018 (the last business day of the registrant's most recently completed fourth fiscal quarter) was $6,750,000 based on a share value of $0.15. The number of shares of Common Stock, $0.001 par value, outstanding on April 16, 2019 was 48,956,147 shares.    

DOCUMENTS INCORPORATED BY REFERENCE: None.

CITADEL EXPLORATION, INC.

FOR THE FISCAL YEAR ENDED

DECEMBER 31, 2018

Index to Report

on Form 10-K

PART I		Page
Item 1.	Business	1
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	22
Item 2.	Properties	1
Item 3.	Legal Proceedings	22
Item 4.	Mine Safety Disclosures	22

PART II
Item 5.	Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 6.	Selected Financial Data	25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 8.	Consolidated Financial Statements and Supplementary Data	30
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	30
Item 9A.	Control and Procedures	30
Item 9B.	Other Information	31

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	32
Item 11.	Executive Compensation	35
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	38
Item 13.	Certain Relationships and Related Transactions, and Director Independence	39
Item 14	Principal Accounting Fees and Services	40

PART IV
Item 15.	Exhibits, Consolidated Financial Statement Schedules	41

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements and involves risks and uncertainties that could materially affect expected results of operations, liquidity, cash flows, and business prospects. These statements include, among other things, statements regarding:

• our ability to diversify our operations;
• exploration risks such as drilling unsuccessful wells;
• our ability to attract key personnel;
• our ability to operate profitably;
• our ability to efficiently and effectively finance our operations, and/or purchase orders;
• inability to achieve future sales levels or other operating results;
• inability to raise additional financing for working capital;
• inability to efficiently manage our operations;
• the inability of management to effectively implement our strategies and business plans;
• the unavailability of funds for capital expenditures and/or general working capital;
• the fact that our accounting policies and methods are fundamental to how we report our financial condition and results of operations, and they may require management to make estimates about matters that are inherently uncertain;
• deterioration in general or regional economic conditions;
• changes in U.S. GAAP or in the legal, regulatory and legislative environments in the markets in which we operate;
• adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations;

as well as other statements regarding our future operations, financial condition and prospects, and business strategies. Forward-looking statements may appear throughout this report, including without limitation, the following sections: Item 1 “Business,” Item 1A “Risk Factors,” and Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Forward-looking statements generally can be identified by words such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will be,” “will continue,” “will likely result,” and similar expressions. These forward-looking statements are based on current expectations and assumptions that are subject to risks and uncertainties, which could cause our actual results to differ materially from those reflected in the forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in this Annual Report on Form 10-K, and in particular, the risks discussed under the caption “Risk Factors” in Item 1A and those discussed in other documents we file with the Securities and Exchange Commission (SEC). We undertake no obligation to revise or publicly release the results of any revision to these forward-looking statements, except as required by law. Given these risks and uncertainties, readers are cautioned not to place undue reliance on such forward-looking statements.

Throughout this Annual Report references to “we”, “our”, “us”, “Citadel”, “COIL”, “the Company”, and similar terms include to Citadel Exploration, Inc. and its subsidiaries, unless the context indicates otherwise.

AVAILABLE INFORMATION

We file annual, quarterly and other reports and other information with the SEC. You can read these SEC filings and reports over the Internet at the SEC’s website at www.sec.gov or on our website at www.citadelexploration.com. You can also obtain copies of the documents at prescribed rates by writing to the Public Reference Section of the SEC at 100 F Street, NE, Washington, DC 20549 on official business days between the hours of 10:00 am and 3:00 pm. Please call the SEC at (800) SEC-0330 for further information on the operations of the public reference facilities. We will provide a copy of our annual report to security holders, including audited consolidated financial statements, at no charge upon receipt of a written request to us at Citadel Exploration, Inc., 417 31^st Street Unit A, Newport Beach, California 92663.

INDUSTRY AND MARKET DATA

The market data and certain other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources. In addition, some data are based on our good faith estimates.

PART I

ITEM 1. BUSINESS AND 2. PROPERTIES

Business Development

Citadel Exploration, Inc. (“Citadel”) was formed as a Nevada corporation in December 2009. On March 2, 2011, Citadel changed its name from Subprime Advantage, Inc. to Citadel Exploration, Inc. Effective May 3, 2011, Citadel completed the acquisition of the Indian Shallow Oil Development Project, located in the Bitterwater sub-basin of the Salinas Basin in California, consisting of 689 acres of leased property from Vintage Petroleum, LLC (Vintage), then a division of Occidental Petroleum (NYSE: OXY), through the acquisition of 100% of the outstanding membership interest of Citadel Exploration, LLC, a California Limited Liability Company (“CEL”) pursuant to the Membership Purchase Agreement and Plan of Reorganization (“Membership Purchase Agreement”).

As a result of our acquisition of CEL, we have a broad portfolio of capital investment opportunities that arise from CEL’s extensive knowledge of the geology and the history of oil and gas exploration and development in California as well as long-term presence and familiarity and relationships with other companies engaged in the oil and gas industry in California.

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Business of Citadel

Citadel is an energy company engaged in the exploration and development of oil and natural gas properties. Our primary focus is on properties are located in the San Joaquin Basin of California. Subject to availability of capital, we strive to implement an accelerated development program utilizing capital resources, a regional operating focus, an experienced management and technical team, and enhanced recovery technologies to attempt to increase production and increase returns for our stockholders. Our corporate strategy is to build value in the Company through acquisition of gas and oil leases with significant upside potential, successful exploration and exploitation and the efficient development of these assets.

Our Projects

KERN BLUFF OIL FIELD

In July of 2015, Citadel purchased approximately 1,100 acres encompassing the Kern Bluff Oil Field in Kern County, California for $2,000,000 in cash and 6,000,000 shares of its common stock valued at $480,000. The seller also retained a royalty that varies on a lease by lease basis; Citadel has 100% working interest in the field with an 77% net revenue interest. In 2015, Citadel re-entered 7 idle well bores, and began to return those wells to production. Production as of December 31, 2018 was approximately 60-80 barrels of oil per day (BOPD). The field had 29 idle well bores upon acquisition, Citadel plans to re-enter each of these well bores in 2019 and 2020 and attempt to return them to production.

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 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. To facilitate the remediation, Citadel elected to shut down the eight producing wells in early January of 2016. Citadel completed the facility remediation in July of 2016, the facilities are estimated to have production capability of 500 BOPD. Citadel returned 8 wells to production in the third quarter of 2016 and drilled three new wells.

In December of 2017, Citadel completed the installation of a 25MM BTU steam generator. Kern Bluff is characterized as a heavy oil field, as such, to increase production steam injection is required. Citadel began cyclic steam operations in the first quarter of 2018. The company expects a significant increase in production following the first round of cyclic steam injection.

In February of 2018, Citadel completed the drilling of three new wells. The company currently has approximately 14 wells on production and has seen field wide production increase from approximately 20 barrels per day to approximately 100 barrels per day.

In July of 2018, Citadel announced it had produced 3,000 barrels of oil in the month of June, equating to 100 barrels per day average.

As of December 2018, production was in the 60-80 barrel per day range.

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Proved Reserves

Evaluation and Review of Proved Reserves: Our proved reserve estimates as of December 31, 2018 were prepared based on reports by MHA Petroleum Consultants (“MHA”). MHA does not own an interest in any of our properties, nor is it employed by us on a contingent basis. Within MHA, the technical person primarily responsible for preparing the estimates set forth in the MHA letter dated March 18, 2019, filed as an exhibit to this Annual Report, was Mr. Alan Burzlaff. Mr. Burzlaff, Managing Partner at MHA and a Licensed Professional Engineer in the State of California, has been practicing consulting petroleum engineering at MHA since 2009 and has over 38 years of prior industry experience.

We do not maintain an internal staff of petroleum engineers or geoscience professionals although our management team did meet with our independent reserve engineers to provide as accurate data as reasonable for use in calculating our proved reserves relating to our assets.

Estimation of Proved Reserves: Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2017 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods; and (4) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. As our Kern Bluff property is new to the Company in 2015 and we had limited current production history, our reserves were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.

To estimate economically recoverable proved reserves and related future net cash flows, MHA considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. The current pricing environment could impact future economics.

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Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, current or estimated well cost and operating expense data.

Summary of Oil, NGLs, and Natural Gas Reserves. The following table presents our estimated net proved oil, NGLs, and natural gas reserves as of the periods indicated:

	December 31,
	2018		2017
Proved developed reserves:
Oil (MBbls)		254		282
Natural gas (MMcf)		—		—
Combined (MBoe)(1)		254		282
Proved undeveloped reserves:
Oil (MBbls)		1,018		952
Natural gas (MMcf)		—		—
Combined (MBoe)(1)		1,018		952
Proved reserves:
Oil (MBbls)		1,272		1,234
Natural gas (MMcf)		—		—
Combined (MBoe)(1)		1,272		1,234

(1) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

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Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read “Item 1A. Risk Factors.”

Additional information regarding our proved reserves can be found in the notes to our consolidated and combined financial statements included elsewhere in this Annual Report and the proved reserve report as of December 31, 2018, which is included as an exhibit to this Annual Report.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2018, our proved undeveloped reserves were composed of 1,018 MBbls of oil, 0 MMcf of natural gas, for a total of 1,018 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells are drilled and begin production.

The following table summarizes our changes in PUDs during the year ended December 31, 2018 (in MBoe):

Balance, December 31, 2017	952
Purchases of reserves	0
Extensions and discoveries	0
Revisions of previous estimates	125
Transfers to proved developed	(59	)
Balance, December 31, 2018	1,018

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Estimated future development costs relating to the development of PUDs at December 31, 2018 were projected to be approximately $840.0 thousand in the year ended December 31, 2019, $1.05 million in 2020, $.630 million in 2021, $3.6 million in 2022, and $1,680 million in future periods. As we continue to develop our properties and have more well production and completion data, we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years. All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking.

As of December 31, 2018, 48 MBbls of our total proved reserves were classified as proved developed non-producing.

Oil and Natural Gas Industry Overview

Oil and natural gas prices have been extremely volatile over the past twelve months and are currently at five year lows. Based on worldwide supply and demand projections and the potential for instability in areas that currently provide a large proportion of the world’s petroleum, we believe that prices are likely to remain volatile for the foreseeable future. We believe that this presents both a tremendous challenge and opportunity for our Company to grow quickly. We have assembled an experienced senior team of professionals to evaluate, acquire and manage available prospects. The experience of this team and its ability to quickly and accurately evaluate prospects and subsequently apply modern exploration, development and production techniques should be key to our Company’s success. A number of factors, including high product prices, the ease and availability of capital, and the influx of that capital into the oil and natural gas sector has resulted in tremendous competition for prospects, people, equipment and services in recent years. We believe that our planned ability to quickly and accurately assess opportunities worth pursuing, to negotiate the best possible terms and to attract the people, equipment and services required to finance and effect the projects should constitute a competitive advantage. Our goal is to grow our Company and increase stockholder value in a favorable petroleum pricing environment. We believe a focus on oil and gas will result in success and growth through added reserves and cash flow which will, in turn, provide a base for further growth and increases in stockholder value.

Our Business Strategy

Our principal strategy has been to focus on the acquisition and drilling of prospective oil and natural gas mineral leases. Once we have tested a prospect as productive, subject to availability of capital, we will implement a development program with a regional operating focus in order to increase production and increase returns for our stockholders. Our strategy is now equally focused on pursuing by-passed oil opportunities that contain significant potential reserves. Exploration, acquisition and development activities are currently focused in California. Depending on availability of capital, and other constraints, our goal is to increase stockholder value by finding and developing oil and natural gas reserves at costs that provide an attractive rate of return on our investments. The principal elements of our business strategy are:

· Develop Our Existing Properties. We intend to create reserve and production growth from our drilling locations we have identified on our property. The expected ultimate recovery and production rates of our properties, are anticipated to yield long-term profitability.

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· Maximize Operational Control. We seek to operate our properties and maintain a substantial working interest. We believe the ability to control our drilling inventory will provide us with the opportunity to more efficiently allocate capital, manage resources, control operating and development costs, and utilize our experience and knowledge of oilfield technologies.

· Pursue Selective Acquisitions and Joint Ventures. We believe we are well-positioned to pursue selected acquisitions, subject to availability of capital, from the fragmented and capital-constrained owners of mineral rights throughout California.

· Reduce Unit Costs Through Economies of Scale and Efficient Operations. As we increase our oil production and develop our existing property, we expect that our unit cost structure will benefit from economies of scale. In particular, we anticipate reducing unit costs by greater utilization of our existing infrastructure over a larger number of wells.

We are continually evaluating oil and natural gas opportunities in California and are also in various stages of discussions with potential joint venture (“JV”) partners who may contribute capital to develop leases we currently own or would acquire for the JV. This economic strategy is anticipated to allow us to utilize our own financial assets toward the growth of our leased acreage holdings, pursue the acquisition of strategic oil and natural gas producing properties or companies and generally expand our existing operations while further diversifying risk. Subject to availability of capital, we plan to continue to bring potential acquisition and JV opportunities to various financial partners for evaluation and funding options.

Our future financial results will continue to depend on: (i) our ability to source and screen potential projects; (ii) our ability to discover commercial quantities of natural gas and oil; (iii) the market price for oil and natural gas; and (iv) our ability to fully implement our exploration, work-over and development program, which is in part dependent on the availability of capital resources. There can be no assurance that we will be successful in any of these respects, that the prices of oil and natural gas prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding at terms favorable to us to increase our currently limited capital resources. For a detailed description of these and other factors that could materially impact actual results, please see “Risk Factors” in this report.

Competition

The oil and natural gas industry is intensely competitive. We compete with numerous individuals and companies, including many major oil and natural gas companies, which have substantially greater technical, financial and operational resources and staff. Accordingly, there is a high degree of competition for desirable oil and natural gas leases, suitable properties for drilling operations and necessary drilling equipment, as well as for access to funds.

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Governmental Regulations

Regulation of Oil and Natural Gas Production. Our oil and natural gas exploration, production and related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, some states in which we may operate, including California, require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, well stimulation techniques such as hydraulic fracturing, acid matrix stimulation, cyclic steam injection and the regulation of spacing, plugging and abandonment of such wells. Failure to comply with any such rules and regulations can result in substantial penalties. Moreover, such states may place burdens from previous operations on current lease owners, and the burdens could be significant. The regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations.

        Federal Regulation of Natural Gas. The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas transportation rates and service conditions, which may affect the marketing of natural gas produced by us, as well as the revenues that may be received by us for sales of such production. Since the mid-1980’s, FERC has issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B (“Order 636”), that have significantly altered the marketing and transportation of natural gas. Order 636 mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other components of the city-gate sales services such pipelines previously performed. One of FERC’s purposes in issuing the order was to increase competition within all phases of the natural gas industry. The United States Court of Appeals for the District of Columbia Circuit largely upheld Order 636 and the Supreme Court has declined to hear the appeal from that decision. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation service, and has substantially increased competition and volatility in natural gas markets.

The price we may receive from the sale of oil and natural gas liquids will be affected by the cost of transporting products to markets. Effective September 28, 1995, FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. We are not able to predict with certainty the effect, if any, of these regulations on our intended operations. However, the regulations may increase transportation costs or reduce well head prices for oil and natural gas liquids.

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Environmental Matters

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue.

These laws and regulations may:

· require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;

· limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and

· impose substantial liabilities for pollution resulting from its operations, or due to previous operations conducted on any leased lands.

The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general.

The Comprehensive Environmental, Response, Compensation, and Liability Act, as amended (“CERCLA”), and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring land owners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.

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The Federal Water Pollution Control Act of 1972, as amended (“Clean Water Act”), and analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters. These laws also regulate the discharge of storm water in process areas. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for the discharge of wastewater and storm water and develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of greater than threshold quantities of oil. The EPA issued revised SPCC rules in July 2002 whereby SPCC plans are subject to more rigorous review and certification procedures. We believe that our operations are in substantial compliance with applicable Clean Water Act and analogous state requirements, including those relating to wastewater and storm water discharges and SPCC plans.

The Endangered Species Act, as amended (“ESA”), seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. ESA provides for criminal penalties for willful violations of the Act. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations will be in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject us to significant expenses to modify our operations or could force us to discontinue certain operations altogether.

Personnel

We currently have three full-time employees, our Chief Executive Officer, our Chief Financial Officer and our General Counsel. As production and drilling activities increase or decrease, we may have to adjust our technical, operational and administrative personnel as appropriate. We are using and will continue to use independent consultants and contractors to perform various professional services, particularly in the area of land services, legal services, reservoir engineering, geology drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain operating and general expenses, and capital costs.

Glossary of Terms

Term	Definition
API Gravity	Is a measure of how heavy or light a petroleum liquid is compared to water. If its API gravity is greater than 10, it is lighter and floats on water; if less than 10, it is heavier and sinks.
Barrel	In the energy industry, a barrel is a unit of volume measurement used for petroleum and is equivalent to 42 U.S. gallons measured at 60 º Fahrenheit.
Basin	A depressed area where sediments have accumulated during geologic time and considered to be prospective for oil and gas deposits.

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Blowout	An uncontrolled flow of oil, gas, water or mud from a wellbore caused when drilling activity penetrates a rock layer with natural pressures greater than the drilling mud in the borehole.
Completion / Completing	A well-made ready to produce oil or natural gas. Completion involves cleaning out the well, running and cementing steel casing in the hole, adding permanent surface control equipment, and perforating the casing so oil or gas can flow into the well and be brought to the surface.
Desorb	The release of materials (e.g., gas molecules) from being adsorbed onto a surface. The opposite of adsorb.
Development	The phase in which a proven oil or gas field is brought into production by drilling production (development) wells.
Division order	A contract for the sale of oil or gas, by the holder of a revenue interest in a well or property, to the purchaser (often a pipeline transmission company).
Drilling	The using of a rig and crew for the drilling, suspension, production testing, capping, plugging and abandoning, deepening, plugging back, sidetracking, re-drilling or reconditioning of a well. Contrast to "Completion" definition.
Drilling logs	Recorded observations made of rock chips cut from the formation by the drill bit, and brought to the surface with the mud, as well as rate of penetration of the drill bit through rock formations. Used by geologists to obtain formation data.
Exploration	The phase of operations which covers the search for oil or gas by carrying out detailed geological and geophysical surveys followed up where appropriate by exploratory drilling. Compare to "Development" phase.
Farm out	Assignment or partial assignment of an oil and gas lease from one lessee to another lessee.
Gathering line / system	A pipeline that transports oil or gas from a central point of production to a transmission line or mainline.
Gross acre	An acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
Gross well	A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.
Held-By-Production (HBP)	Refers to an oil and gas property under lease, in which the lease continues to be in force, because of production from the property.

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Land services	Services performed by an oil and gas company or agent, or landman, who negotiates oil and gas leases with mineral owners, cures title defects, and negotiates with other companies on agreements concerning the lease.
Logging (electric logging)	Process of lowering sensors into a wellbore to acquire downhole recordings that indicate a well's rock formation characteristics and indications of hydrocarbons.
Methane	An organic chemical compound of hydrogen and carbon (i.e., hydrocarbon), with the simplest molecular structure (CH4).
Mineral Lease	A legal instrument executed by a mineral owner granting exclusive right to another to explore, drill, and produce oil and gas from a piece of land.
Natural gas quality	The value of natural gas is calculated by its BTU content. A cubic foot of natural gas on the average gives off 1000 BTU, but the range of values is between 500 and 1500 BTU. Energy content of natural gas is variable and depends on its accumulations which are influenced by the amount and types of energy gases they contain: the more non-combustible gases in a natural gas, the lower the Btu value.
Net acre	A net acre is deemed to exist when the sum of fractional working interests owned in gross acres equals one. The number of net acres is the sum of fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
Net well	A net well is deemed to exist when the sum of fractional working interests owned in gross wells equals one. The number of net wells is the sum of fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.
Operator	A person, acting for himself or as an agent for others and designated to the state authorities as the one who has the primary responsibility for complying with its rules and regulations in any and all acts subject to the jurisdiction of the state.
Permeability	The property of a rock formation which quantifies the flow of a fluid through the pore spaces and into the wellbore.
Pooled, Pooled Unit	A term frequently used interchangeably with "Unitization" but more properly used to denominate the bringing together of small tracts sufficient for the granting of a well permit under applicable spacing rules.

 -12-

Proved Reserves	Estimated quantities of crude oil, natural gas, condensate, or other hydrocarbons that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in the future from known reservoirs under existing conditions using established operating procedures and under current governmental regulations. Further definitions of oil and gas reserves, as defined by the SEC, can be found in Rule 4-10(a)(2)(i)-(iii) and Rule 4-10(a)(3) and (4). These Rules are available at the SEC’s website; http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml
Re-completion	Completion of an existing well for production from one formation or reservoir to another formation or reservoir that exists behind casing of the same well.
Reserves	Generally the amount of oil or gas in a particular reservoir that is available for production.
Reservoir	The underground rock formation where oil and gas has accumulated. It consists of a porous rock to hold the oil or gas, and a cap rock that prevents its escape.
Reservoir Pressure	The pressure at the face of the producing formation when the well is shut-in. It equals the shut in pressure at the wellhead plus the weight of the column of oil in the hole.
Shut-in well	A well which is capable of producing but is not presently producing. Reasons for a well-being shut-in may be lack of equipment, market or other.
Stratigraphic Trap	A variety of sealed geologic containers capable of retaining hydrocarbons, formed by changes in rock type or pinch-outs, unconformities, or sedimentary features.
Structural Trap	A variety of sealed geologic structures capable of retaining hydrocarbons, such as  faults or a folds.
Undeveloped acreage	Leased acreage which has yet to be drilled on to test the potential for hydrocarbons.
Unitize, Unitization	Joint operations to maximize produced hydrocarbon recovery among separate operators within a common reservoir.
Working Interest	The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

 -13-

ITEM 1A. RISK FACTORS

RISKS ASSOCIATED WITH OIL AND GAS OPERATIONS

Drilling wells is speculative, often involving significant costs that may be more than our estimates, and may not result in any addition to our production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business.

Developing and exploring for natural gas and oil involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services. Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economic. Our initial drilling and development sites, and any potential additional sites that may be developed, require significant additional exploration and development, regulatory approval and commitments of resources prior to commercial development. Any success that we may have with these wells or any future drilling operations will most likely not be indicative of our current or future drilling success rate, particularly, because we intend to emphasize on exploratory drilling. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.

Development of our reserves, when established, may not occur as scheduled and the actual results may not be as anticipated. Drilling activity may result in downward adjustments in reserves or higher than anticipated costs. Our estimates will be based on various assumptions, including assumptions required by the Securities and Exchange Commission relating to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating our natural gas and oil reserves is anticipated to be extremely complex, and will require significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Due to our inexperience in the oil and gas industry, our estimates may not be reliable enough to allow us to be successful in our intended business operations. Our actual production, revenues, taxes, development expenditures and operating expenses will likely vary from those anticipated. These variances may be material.

Gas and Oil prices are volatile. This volatility may occur in the future, causing negative change in cash flows which may result in our inability to cover our capital expenditures.

Our future revenues, profitability, future growth and the carrying value of our properties is anticipated to depend substantially on the prices we may realize for our natural gas and oil production.

Our realized prices may also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.

 -14-

Natural gas and oil prices are subject to wide fluctuations in response to relatively minor changes in or perceptions regarding supply and demand. Historically, the markets for natural gas and oil have been volatile, and they are likely to continue to be volatile in the future. For example, oil prices declined significantly in late 2014 through 2016. Oil prices unexpectedly collapsed during the 4Q18 and remain volatile; among the factors that can cause this volatility are:

• worldwide or regional demand for energy, which is affected by economic conditions;
• the domestic and foreign supply of natural gas and oil;
• weather conditions;
• domestic and foreign governmental regulations;
• political conditions in natural gas and oil producing regions;
• the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production levels;
• the price and availability of other fuels.
• President Donald J. Trump
• Climate Change Policies enacted to limit the production of oil and natural gas

It is impossible to predict natural gas and oil price movements with certainty. Lower natural gas and oil prices may not only decrease our future revenues on a per unit basis but also may reduce the amount of natural gas and oil that we can produce economically. A substantial or extended decline in natural gas and oil prices may materially and adversely affect our future business enough to force us to cease our business operations. In addition, our financial condition, results of operations, liquidity and ability to finance planned capital expenditures will also suffer in such a price decline. Further, natural gas and oil prices do not necessarily move together.

We may incur substantial write-downs of the carrying value of our gas and oil properties, which would adversely impact our earnings.

We periodically review the carrying value of our gas and oil properties under the successful effort method accounting rules of the Securities and Exchange Commission. Under these rules, capitalized costs of proved gas and oil properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at an annual rate of 10%. Application of this “ceiling” test requires pricing future revenue at the un-escalated prices in effect as of the end of each fiscal quarter and requires a write-down for accounting purposes if the ceiling is exceeded, even if prices were depressed for only a short period of time. We may be required to write down the carrying value of our gas and oil properties when natural gas and oil prices are depressed or unusually volatile, which would result in a charge against our earnings. Once incurred, a write-down of the carrying value of our natural gas and oil properties is not reversible at a later date.

 -15-

Competition in our industry is intense. We are small and have an extremely limited operating history as compared to the vast majority of our competitors, and we may not be able to compete effectively.

We intend to compete with major and independent natural gas and oil companies for property acquisitions. We will also compete for the equipment and labor required to operate and to develop natural gas and oil properties. The majority of our anticipated competitors have substantially greater financial and other resources than we do. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for natural gas and oil properties and may be able to define, evaluate, bid for and acquire a greater number of properties than we can. Our ability to acquire additional properties and develop new and existing properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, some of our competitors have been operating in our core areas for a much longer time than we have and have demonstrated the ability to operate through industry cycles.

The natural gas and oil business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our development, exploitation and exploration activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas and oil well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves.

The natural gas and oil business involves a variety of operating risks, including:

• fires;
• explosions;
• blow-outs and surface cratering;
• uncontrollable flows of oil, natural gas, and formation water;
• natural disasters, such as hurricanes and other adverse weather conditions;
• pipe, cement, or pipeline failures;
• casing collapses;
• embedded oil field drilling and service tools;
• abnormally pressured formations; and
• environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

 -16-

If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:

• injury or loss of life;
• severe damage to and destruction of property, natural resources and equipment;
• pollution and other environmental damage;
• clean-up responsibilities;
• regulatory investigation and penalties;
• suspension of our operations; and
• repairs to resume operations.

Because we intend to use third-party drilling contractors to drill our wells, we may not realize the full benefit of worker compensation laws in dealing with their employees. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could impact our operations enough to force us to cease our operations.

The high cost of drilling rigs, equipment, supplies, personnel and other services could adversely affect our ability to execute on a timely basis our development, exploitation and exploration plans within our budget.

Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or interrupt our operations, which could impact our financial condition and results of operations. Drilling activity in the geographic areas in which we conduct drilling activities may increase, which would lead to increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. Increased drilling activity in these areas may also decrease the availability of rigs. We do not have any contracts with providers of drilling rigs and we cannot assure you that drilling rigs will be readily available when we need them. Drilling and other costs may increase further and necessary equipment and services may not be available to us at economical prices.

Our lease ownership may be diluted due to financing strategies we may employ in the future due to our lack of capital or due to our focus on producing leases.

To accelerate our development efforts we plan to take on working interest partners that will contribute to the costs of drilling and completion and then share in revenues derived from production. In addition, we may in the future, due to a lack of capital or other strategic reasons, establish joint venture partnerships or farm out all or part of our development efforts. These economic strategies may have a dilutive effect on our lease ownership and will more than likely reduce our operating revenues.

 -17-

In addition, our lease ownership is subject to forfeiture in the event we are unwilling or unable to continue making lease payments. Our leases vary in price per acre and on the term period of the lease. Each lease requires payment to maintain an active lease, or have a producing well to hold the lease. In the event we are unable or unwilling to make our lease payments or renew expiring leases, then we will forfeit our rights to such leases. Such forfeiture would prevent us from pursuing development activity on the leased property and could have a substantial impact on our gross leased acreage.

We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.

Development, production and sale of natural gas and oil in the United States are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:

• location and density of wells;
• the handling of drilling fluids and obtaining discharge permits for drilling operations;
• accounting for and payment of royalties on production from state, federal and Indian lands;
• bonds for ownership, development and production of natural gas and oil properties;
• transportation of natural gas and oil by pipelines;
• operation of wells and reports concerning operations; and
• taxation.

Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations enough to possibly force us to cease our business operations.

Our oil and gas operations may expose us to environmental liabilities.

Any leakage of crude oil and/or gas from the subsurface portions of our wells, our gathering system or our storage facilities could cause degradation of fresh groundwater resources, as well as surface damage, potentially resulting in suspension of operation of the wells, fines and penalties from governmental agencies, expenditures for remediation of the affected resource, and liabilities to third parties for property damages and personal injuries. In addition, any sale of residual crude oil collected as part of the drilling and recovery process could impose liability on us if the entity to which the oil was transferred fails to manage the material in accordance with applicable environmental health and safety laws.

 -18-

Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may prove to be lower than estimated.

Many uncertainties exist in estimating quantities of proved reserves and related future net cash flows. Our estimates are based on various assumptions, which may ultimately prove to be inaccurate. 

Tax law changes may adversely affect our operations.

In California, there have been proposals for tax increases for the past several years including a severance tax as high as 10% of the value of petroleum production in California. Although the proposals have not become law, campaigns by various interest groups could lead to future oil and gas severance taxes. The imposition of such a tax could severely reduce our profit margins and cash flow and could ultimately result in lower oil and natural gas production, which may reduce our capital investments and growth plans.

In addition, President Trump’s budget proposal for fiscal year 2019 could recommend the elimination of certain federal income tax preferences currently available to oil and gas exploration and production companies as well as new taxes, all of which could harm us. The elimination of tax preferences includes (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of expensing intangible drilling costs, (iii) an increase in the amortization period from two years to seven years for geological and geophysical costs paid or incurred by independent producers and (iv) repealing the domestic manufacturing deduction for income derived from the production of oil and gas in the United States.

Restrictions on our ability to obtain, use, manage or dispose of water may have an adverse effect on our operations.

Water management is an essential component of our operations. We treat and re-use water for a substantial portion of our needs related to activities such as steamflooding, waterflooding, pressure management, well completion and stimulation, including limited hydraulic fracturing, and we provide reclaimed water for agricultural use in certain areas. We also use supplied water from various local and regional sources, particularly for power plants and to support operations like steam injection in certain fields. Due to severe drought in California, some local and regional water districts and the state government are implementing regulations and policies that restrict water usage and increase the cost of water. Existing laws and regulations restrict our ability and increase our cost to manage and dispose of water and other fluids. The federal Clean Water Act and Safe Drinking Water Act and analogous state laws impose restrictions and strict controls on the discharge of and injection of fluids, including produced water. We must obtain permits or waivers for certain surface discharges and subsurface injection, as well as for construction activities that may affect regulated water resources. Certain government agencies have investigated and continue to study whether the discharge or injection of produced water could affect water quality or induce ground movement or seismicity, which may result in additional regulations under federal and state laws. Our enhanced production operations or fluid disposal could give rise to litigation over claims related to alleged damage to the environment or private or public property. The laws, regulations, policies and attendant liabilities relating to the use, disposal and injection of water and other fluids could increase our costs and negatively affect our development and production activities.

 -19-

Concerns about climate change and other air quality issues may affect our operations or results.

Concerns about climate change and regulation of greenhouse gases (GHGs) may affect our business in many ways, including increasing the costs to provide our products and services, and reducing demand for, and consumption of, our products and services. In addition, legislative and regulatory responses to climate change may increase our operating costs. California has led other states in adopting GHG emission reduction requirements as well as mandates for renewable fuel sources. In 2006, California adopted AB 32, which established a statewide cap on GHG emissions, including on the oil and natural gas production industry, and a “cap-and-trade” program. Since 2012, California Air Resources Board (CARB) regulations have required us to obtain GHG emissions allowances corresponding to reported GHG emissions from operations and, starting in 2015, from the sale of certain products to customers for use in California. The EPA has also adopted regulations requiring the reporting of GHG emissions from certain onshore oil and natural gas production facilities on an annual basis. In 2015, the EPA expanded the scope of the GHG monitoring and reporting rule to include gathering and compression facilities as well as completions and workovers from wells that have undergone hydraulic fracturing. The EPA also proposed regulations in 2015 that would require emission controls for methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. These additional regulations could increase our costs.

In addition, other current and proposed international agreements and federal and state laws, regulations and policies seek to restrict or reduce the use of petroleum products in transportation fuels and electricity generation, impose additional taxes and costs on producers and consumers of petroleum products and require or subsidize the use of renewable energy, which could increase our costs and reduce demand for our products and services. Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

Risks Relating To Our Common Stock

Because our common stock is deemed a low-priced “Penny” stock, an investment in our common stock should be considered high risk and subject to marketability restrictions.

Since our common stock is currently under $5 per share, it is considered a penny stock, as defined in Rule 3a51-1 under the Securities Exchange Act, it will be more difficult for investors to liquidate their investment even if and when a market develops for the common stock. Until the trading price of the common stock rises above $5.00 per share, if ever, trading in the common stock is subject to the penny stock rules of the Securities Exchange Act specified in rules 15g-1 through 15g-10. Those rules require broker-dealers, before effecting transactions in any penny stock, to:

• Deliver to the customer, and obtain a written receipt for, a disclosure document;
• Disclose certain price information about the stock;
• Disclose the amount of compensation received by the broker-dealer or any associated person of the broker-dealer;
• Send monthly statements to customers with market and price information about the penny stock; and
• In some circumstances, approve the purchaser’s account under certain standards and deliver written statements to the customer with information specified in the rules.

 -20-

Consequently, the penny stock rules may restrict the ability or willingness of broker-dealers to sell the common stock and may affect the ability of holders to sell their common stock in the secondary market and the price at which such holders can sell any such securities. These additional procedures could also limit our ability to raise additional capital in the future.

FINRA sales practice requirements may also limit a stockholder's ability to buy and sell our stock.

In addition to the “penny stock” rules described above, the Financial Industry Regulatory Authority (FINRA) has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer's financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. The FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.

If we fail to remain current on our reporting requirements, we could be removed from the OTC Markets BB (OTCBB), which would limit the ability of broker-dealers to sell our securities and the ability of stockholders to sell their securities in the secondary market.

Companies trading on the OTC Markets QB (OTCBB), such as us, generally must be reporting issuers under Section 12 of the Securities Exchange Act of 1934, as amended, and must be current in their reports under Section 13, in order to maintain price quotation privileges on the OTCBB. More specifically, FINRA has enacted Rule 6530, which determines eligibility of issuers quoted on the OTCBB by requiring an issuer to be current in its filings with the Commission. Pursuant to Rule 6530(e), if we file our reports late with the Commission three times in a two-year period or our securities are removed from the OTCBB for failure to timely file twice in a two-year period, then we will be ineligible for quotation on the OTCBB. As a result, the market liquidity for our securities could be severely adversely affected by limiting the ability of broker-dealers to sell our securities and the ability of stockholders to sell their securities in the secondary market. As of the date of this filing, we have one late filing reported by FINRA.

 -21-

Our internal controls may be inadequate, which could cause our financial reporting to be unreliable and lead to misinformation being disseminated to the public.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. As defined in Exchange Act Rule 13a-15(f), internal control over financial reporting is a process designed by, or under the supervision of, the principal executive and principal financial officer and effected by the board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of Citadel; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of Citadel are being made only in accordance with authorizations of management and directors of Citadel, and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Citadel’s assets that could have a material effect on the consolidated financial statements.

We have two individuals performing the functions of all officers and directors. These individuals developed our internal control procedures and are responsible for monitoring and ensuring compliance with those procedures. As a result, our internal controls may be inadequate or ineffective, which could cause our financial reporting to be unreliable and lead to misinformation being disseminated to the public. Investors relying upon this misinformation may make an uninformed investment decision.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business.

ITEM 4. MINE SAFETY DISCLOSURES

None

 -22-

PART II

ITEM 5. MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND SMALL BUSINESS ISSUER PURCHASE OF EQUITY SECURITIES

Market Information

Our common stock is quoted on the OTC Markets QB (OTCBB), under the symbol “COIL.” Historically, there has not been an active trading market for our common stock. We have been eligible to participate on the OTCBB since November 2010.

The following table sets forth the quarterly high and low bid prices for our common stock during our last two fiscal years, as reported by a Quarterly Trade and Quote Summary Report of the OTC Bulletin Board. The quotations reflect inter-dealer prices, without retail mark-up, markdown or commission, and may not necessarily represent actual transactions.

	2018				2017
		BID PRICES				BID PRICES
		High		Low		High		Low
1st Quarter	$	0.21	$	0.05	$	0.23	$	0.10
2nd Quarter	$	0.20	$	0.15	$	0.15	$	0.08
3rd Quarter	$	0.29	$	0.17	$	0.22	$	0.06
4th Quarter	$	0.25	$	0.10	$	0.20	$	0.11

Holders of Common Stock

As of April 16, 2019, we had approximately 106 stockholders of record of the 48,956,147 shares outstanding.

Dividends

The payment of dividends is subject to the discretion of our Board of Directors and will depend, among other things, upon our earnings, our capital requirements, our financial condition, and other relevant factors. We have not paid or declared any dividends upon our common stock since our inception and, by reason of our present financial status and our contemplated financial requirements, do not anticipate paying any dividends upon our common stock in the foreseeable future.

We intend to reinvest any earnings in the development and expansion of our business. Any cash dividends in the future to common stockholders will be payable when, as and if declared by our Board of Directors, based upon the Board’s assessment of:

• our financial condition;
• earnings;
• need for funds;
• capital requirements;
• prior claims of preferred stock to the extent issued and outstanding; and
• other factors, including any applicable laws.

Therefore, there can be no assurance that any dividends on the common stock will ever be paid.

 -23-

Securities Authorized for Issuance under Equity Compensation Plans

On September 1, 2012, we adopted the 2012 Stock Incentive Plan. We have reserved for issuance an aggregate of 10,000,000 shares of common stock under our 2012 Stock Incentive Plan. To date, 10,000,000 options and no shares of common stock have been granted under this plan.

On December 15, 2017, we adopted the 2017 Restricted Stock Unit Plan (RTU) authorizing the issuance of 10,000,000 restricted stock units to management and future employees. In conjunction with adopting this plan, the Compensation Committee of the Board of Directors authorized the issuance of 5,500,000 shares to the Company’s three employees. The RTU’s have a 2-year vesting period. The Compensation Committee believes that it is in the best interest of shareholders to incentive management via equity to align shareholders interest with management.

Recent Sales of Unregistered Securities

In March of 2016, the Company approved the sale of up to 500,000 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 payable. In addition, the Company has sold 21,250 shares of Series A Convertible Participating Preferred Stock payable 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 payable 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 payable 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 payable 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 payable 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 payable for cash in the amount of $266,000.

In March of 2017, the Company sold 10,000 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $200,000.

In March of 2017, the Company issued 2,034,002 common shares as a special dividend to Series A Preferred Shareholders for interest incurred during the 2016 offering period of the Series A.

In June of 2017, the Company sold 13,750 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $275,000.

 -24-

In September of 2017, the Company sold 22,500 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $450,000.

In December of 2017, the Company sold 17,750 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $355,000.

In December of 2017, the Company issued 3,101,736 shares of common stock as payment for interest accrued on the Series A Preferred Stock during 2017.

In January of 2019, the Company issued 3,956,147 shares of common stock as payment for interest accrued on the Series A Preferred Stock during 2018.

In March of 2019, the Company sold 5,000 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $100,000.

Issuer Purchases of Equity Securities

The Company did not repurchase any of its equity securities during the year ended December 31, 2018.

ITEM 6. SELECTED FINANCIAL DATA

This item is not applicable, as we are considered a smaller reporting company.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW AND OUTLOOK

Background

Citadel Exploration, Inc. was incorporated in the State of Nevada in December of 2009. On February 28, 2011, we entered into an agreement for the acquisition of 100% of the membership interest of Citadel Exploration, LLC (“CEL”), a California limited liability company.

On March 2, 2011, we changed our name from Subprime Advantage, Inc. to Citadel Exploration, Inc. in anticipation of the completion of the acquisition of 100% of all of the outstanding membership interest of CEL. The acquisition of 100% of the outstanding membership interest of CEL was completed on May 3, 2011. As a result of the completion of the acquisition, we became an oil and gas exploration company with operations in the Salinas and San Joaquin Basins of California. We have since expanded our focus to be an oil and gas exploration, development and production company.

 -25-

Our Operations

 Our principal strategy is to focus on the acquisition of oil and natural gas mineral leases that have known hydrocarbons or are in close proximity to known hydrocarbons that have been underdeveloped. Once acquired, we strive to implement an accelerated development program utilizing capital resources, a regional operating focus, an experienced management and technical team, and enhanced recovery technologies to attempt to increase production and increase returns for our stockholders. Our oil and natural gas acquisition and development activities are currently focused in the State of California. 

On July 31, 2015 Citadel acquired approximately 1,100 acres of leases, production facilities and equipment that encompassed the Kern Bluff Oil Field. As consideration for this acquisition Citadel issued 6,000,000 shares of common stock and paid $2,000,000 in cash. The transaction was financed via a $3,500,000 one year term loan from Cibolo Creek Partners, of Midland Texas. In March of 2016, Cibolo Creek Partners converted the $3,500,000 term loan into Series A Convertible Participating Preferred Stock.

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.

In July of 2016, Citadel completed its facility upgrades; the new facilities have production capacity of 500 BOPD. Citadel drilled three wells in June and returned to production 9 idle wells. Production from the new wells continues to increase as the wells clean up. As of December 31, 2017 the Company was producing approximately 50 barrels of oil per day.

In December of 2017, Citadel completed the installation of a 25MM BTU steam generator. The oil and Kern Bluff is characterized as heavy oil, therefore requiring stimulation via steam injection. This steam generator has capacity of over 1,400 barrels of steam per day (BOSPD) which will allow the Company to steam approximately 50 wells per year. The company currently has approximately 14 wells on production and has seen field wide production increase from approximately 20 barrels per day to approximately 60-80 barrels per day.

Going Concern

The consolidated financial statements included in this filing have been prepared in conformity with generally accepted accounting principles that contemplate the continuance of the Company as a going concern, which contemplates the realization of assets and liquidation of liabilities in the normal course of business. However, the Company is in the exploration stage and, accordingly, has not generated any significant revenues from operations. As shown on the accompanying consolidated financial statements, the Company has incurred a net loss of $2,590,548 for the year ending December 31, 2018. These conditions raise substantial doubt about the Company’s ability to continue as a going concern.

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The future of the Company is dependent upon its ability to obtain financing and upon future profitable operations from the development of its oil and gas business opportunities.

RESULTS OF OPERATIONS

For accounting purposes, the acquisition of Citadel Exploration, LLC by the Company has been recorded as a reverse acquisition of a public company and recapitalization of Citadel Exploration, LLC based on the factors demonstrating that Citadel Exploration, LLC represents the accounting acquirer. The historic financial statements of Citadel Exploration, LLC and related entities, while historically presented as an LLC equity structure, have been retroactively presented as a corporation for comparability purposes.

During the year ended December 31, 2018 we generated $1,066,314 in revenue from oil sales. During the year ended December 31, 2017, we generated $166,355 in revenue.

Operating expenses totaled $3,186,418 during the year ended December 31, 2018 as compared to $1,894,340 in the prior year ended December 31, 2017. Operating expenses primarily consisted of lease operating expenses, executive compensation, and general and administrative expenses in the year ended December 31, 2018 and December 31, 2017.

General and administrative fees increased $39,918 from the year ended December 31, 2017 to the year ended December 31, 2018. This increase was primarily due to insurance, marketing and meals and entertainment expenses.

Professional fees increased $75,262 from the year ended December 31, 2017 to the year ended December 31, 2018. The increase was primarily due to an increase in services provided to the Company for accounting, engineering consulting, and legal.

Executive compensation increased $576,529 from the year ended December 31, 2017 to the year ended December 31, 2018. The increase was due to a contractual increase in salaries and stock based executive compensation and the issuance of an Overriding Royalty Interest (ORRI) of 2% to management.

Liquidity and Capital Resources

The Company has established a capital budget for 2019 of $3,000,000 to drill up to 10 wells. The Company’s ability to complete this capital budget will be highly dependent on oil prices and access to capital.

As of December 31, 2018, we had $254,898 of current assets; of this amount $86,441 was cash. The following table provides detailed information about our net cash flow for all consolidated financial statement periods presented in this Annual Report. To date, we have financed our operations through the issuance of stock and borrowings.

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The following table sets forth a summary of our cash flows for the years ended December 31, 2018 and 2017:

	Years Ended December 31,
	2018			2017
Net cash used in operating activities	$	(436,135	)	$	(341,887	)
Net cash used in investing activities		(1,609,149	)		(987,786	)
Net cash provided by financing activities		1,359,622			1,913,073
Net decrease in cash		(685,662	)		583,310
Cash and restricted cash beginning of year		972,103			188,793
Cash and restricted cash at end of year	$	286,441		$	772,103

Investing activities

Net cash used in investing activities was $1,609,149 for the year ended December 31, 2018. The net cash used in investing activities consisted primarily of payments for the development of Kern Bluff Oil Field and related facility upgrades.

Financing activities

Net cash provided by financing activities for the year ended December 31, 2018 was $1,359,622. The net cash provided by financing activities substantially consisted of proceeds from a $3,000,000 senior secured credit facility of which the Company had draws totaling $2,350,000 and year end.

As of December 31, 2018, we continue to use traditional and/or debt financing as well as through the issuance of stock to provide the capital we need to run our business.

Without cash flow from operations we will require additional cash resources, including the sale of equity or debt securities, to meet our planned capital expenditures and working capital requirements for the next 12 months. We will require additional cash resources due to changed business conditions, implementation of our strategy to successfully develop our projects, or acquisitions we may decide to pursue. If our own financial resources and then current cash-flows from operations are insufficient to satisfy our capital requirements, we may seek to sell additional equity or debt securities or obtain additional credit facilities. The sale of additional equity securities will result in dilution to our stockholders. The incurrence of indebtedness will result in increased debt service obligations and could require us to agree to operating and financial covenants that could restrict our operations or modify our plans to grow the business. Financing may not be available in amounts or on terms acceptable to us, if at all. Any failure by us to raise additional funds on terms favorable to us, or at all, will limit our ability to expand our business operations and could harm our overall business prospects.

Our ability to obtain additional capital through additional equity and/or debt financing, and Joint Venture or Working Interest partnerships will also be important to our expansion plans. In the event we experience any significant problems assimilating acquired assets into our operations or cannot obtain the necessary capital to pursue our strategic plan, we may have to reduce the growth of our operations. This may materially impact our ability to increase revenue and continue our growth.

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Contractual Obligations

An operating lease for rental office space was entered into beginning March 1, 2013 for two years at $2,150 per month. The original lease was amended to include additional space at a price of $1,100 per month for the same term. The original term of the lease expired on March 1, 2015. As such our office lease is now on a month to month basis at a rate of $3,000 per month.

Off-Balance Sheet Arrangements

As of the date of this Report, we did not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Operation Plan

Our plan is to focus on the acquisition and drilling of prospective oil and natural gas mineral leases. Once we have tested a prospect as productive, subject to availability of capital, we will implement a development program with a regional operating focus in order to increase production and increase returns for our stockholders. Exploration, acquisition and development activities are currently focused in California. Depending on availability of capital, and other constraints, our goal is to increase stockholder value by finding and developing oil and natural gas reserves at costs that provide an attractive rate of return on our investments.

We expect to achieve these results by:

• Investing capital in exploration and development drilling and in secondary and tertiary recovery of oil as well as natural gas;

• Using the latest technologies available to the oil and natural gas industry in our operations;

• Finding additional oil and natural gas reserves on the properties we acquire.

In addition to raising additional capital we plan to take on Joint Venture (JV) or Working Interest (WI) partners who may contribute to the capital costs of drilling and completion and then share in revenues derived from production. This economic strategy may allow us to utilize our own financial assets toward the growth of our leased acreage holdings, pursue the acquisition of strategic oil and gas producing properties or companies and generally expand our existing operations.

Because of our limited operating history we have only generated minimal revenue from the sale of oil or natural gas. Our activities have been limited to raising capital, negotiating WI agreements, becoming a publicly traded company and preliminary analysis of reserves and production capabilities from our exploratory test wells.

Our future financial results will depend primarily on: (i) the ability to continue to source and screen potential projects; (ii) the ability to discover commercial quantities of natural gas and oil; (iii) the market price for oil and natural gas; and (iv) the ability to fully implement our exploration and development program, which is dependent on the availability of capital resources. There can be no assurance that we will be successful in any of these respects, that the prices of oil and gas prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding to increase our currently limited capital resources.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

This item in not applicable as we are currently considered a smaller reporting company.

ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 

	PAGES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	F-1
CONSOLIDATED BALANCE SHEETS	F-2
CONSOLIDATED STATEMENTS OF OPERATIONS	F-3
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)	F-4
CONSOLIDATED STATEMENTS OF CASH FLOWS	F-5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	F-6 – F-27

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

We have had no disagreements with our independent auditors on accounting or financial disclosures.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our Principal Executive Officer, Armen Nahabedian and Principal Financial Officer, Philip McPherson, have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended) as of the end of the period covered by this Report. Based on their evaluation, they concluded that our disclosure controls and procedures are not designed at a reasonable assurance level and are not effective to provide reasonable assurance that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

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Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control, as is defined in the Securities Exchange Act of 1934. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of consolidated financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal controls, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting financial information.

Our internal control over financial reporting includes policies and procedures that: (i) pertain to maintaining records that in reasonable detail accurately and fairly reflect our transactions; (ii) provide reasonable assurance that transactions are recorded as necessary for preparation of our consolidated financial statements in accordance with generally accepted accounting principles and the receipts and expenditures of company assets are made and in accordance with our management and directors authorization; and (iii) provide reasonable assurance regarding the prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on our consolidated financial statements.

Management has undertaken an assessment of the effectiveness of our internal control over financial reporting based on the framework and criteria established in the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based upon this evaluation, management concluded that our internal control over financial reporting was not effective as of December 31, 2018. The evaluation concluded that there is a lack of segregation of duties within the control environment and a lack of formal review procedures, including a multiple level review. Both weaknesses are due to limited personnel.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to the temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors and Executive Officers

The names of our directors and executive officers and their ages, positions, and biographies are set forth below. Our executive officers are appointed by, and serve at the discretion of, our board of directors. There are no family relationships among any of our directors or executive officers.

Name	Age	Title	Director Since
Armen Nahabedian	40	Chief Executive Officer, President & Director	8/9/2011
Philip J. McPherson	44	Chief Financial Officer, Secretary, Treasurer & Director	9/1/2012
Jim Walesa	58	Chairman of the Board	9/1/2014
James Borgna	40	Director	5/3/2011

Armen Nahabedian, 40, President, Chief Executive Officer, and Director: Mr. Nahabedian is a fourth generation oil and gas explorer in the state of California. In 1999, Mr. Nahabedian joined the United States Marine Corp as an infantryman and reached the rank of Corporal (E-4) before serving in operation Iraqi Freedom and receiving an honorable discharge in 2003. Mr. Nahabedian immediately thereafter went to work in the oil fields of the South San Joaquin Valley for his family’s oil company, The Nahabedian Exploration Group. After early success in his exploration efforts Mr. Nahabedian became a regional supervisor and managed the drilling operations for some of the deepest exploratory wells drilled in the state of California from 2004 through 2007. In 2007, Mr. Nahabedian then joined The Nahabedian Exploration Group as a partner and supervised land acquisition efforts (over 750,000 acres leased or optioned) and prospect generation. Mr. Nahabedian continued to act as an operational supervisor and in 2009; he became involved in business development and finance. Acting as the company’s primary fund raiser Mr. Nahabedian educated himself in public financing and securities and with the assistance of an experienced legal team formed Citadel Exploration, Inc. in 2011. 

Philip J. McPherson, 44, Chief Financial Officer and Director: Mr. McPherson joined Citadel Exploration in September of 2012 with nearly two decades of experience in the capital markets and financial services sectors.  He started his career as a retail stock broker with Mission Capital in 1997 and became partner before it was acquired by oil and gas boutique C. K. Cooper & Company. At C.K. Cooper, Mr. McPherson was a research analyst specializing in small cap exploration & production companies.  In 2007, he joined Global Hunter Securities as a partner and managing director of the energy research group. During his Wall Street career, Mr. McPherson was presented the Wall Street Journal “Best on the Street” Award was named a Zack’s 5-Start Analyst for three consecutive years.  He is a recognized expert on California E&P firms. Mr. McPherson received his Bachelors in Economics from East Carolina University.

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James Walesa, 58, Chairman of the Board: Mr. Walesa has more than three decades of experience in financial services with an emphasis on the energy industry. He started in 1982 with First Investors (FIC) as a registered representative in Chicago and became the youngest vice president in firm history at age 26. He left FIC to form Asset Management & Protection Corporation (AMPC) in May 1988. AMPC started from scratch and today manages over $500 million. Mr. Walesa entered the energy industry in 1992 in the Permian Basin. He and some of his clients were original investors in Basic Energy Services (BAS: NYSE) and Southwest Royalties, now part of Clayton Williams Energy (CWE: NYSE). He is also a founding member of the Offshore Energy Center in Galveston, Texas. Mr. Walesa and AMPC clients continue to provide startup capital for energy related companies and was an original investor in Citadel’s first offering. Mr. Walesa previously served on the board of NASDAQ-traded Financial Assurance and several private companies. He was the Chicago Chairman for the National Multiple Sclerosis Society and is a member of the Alzheimer’s Alois Society in recognition of his leadership and support of the Alzheimer’s Association to prevent and cure dementia related disease.

James Borgna, 40, Director: Mr. Borgna is a third generation oil and gas industry supplier and producer. Mr. Borgna currently owns and operates Grey Energy LLC which supplies production facilities and process equipment in California.  Mr. Borgna specializes in scalable facilities that are fabricated work in-house. Mr. Borgna has supervised the fabrication of oil and gas facilities for many of the major operators in the San Joaquin Basin. Mr. Borgna gained valuable experience with project management, facilities design, and gained familiarity with permitting guidelines and restrictions. Prior to joining his family in the oil and gas industry Mr. Borgna served six years in the United States Navy and achieved the rank of E-5.

Indemnification of Directors and Officers

Our Articles of Incorporation and Bylaws both provide for the indemnification of our officers and directors to the fullest extent permitted by Nevada law.

Limitation of Liability of Directors

Pursuant to the Nevada General Corporation Law, our Articles of Incorporation exclude personal liability for our Directors for monetary damages based upon any violation of their fiduciary duties as Directors, except as to liability for any breach of the duty of loyalty, acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, or any transaction from which a Director receives an improper personal benefit. This exclusion of liability does not limit any right which a Director may have to be indemnified and does not affect any Director’s liability under federal or applicable state securities laws. We have agreed to indemnify our directors against expenses, judgments, and amounts paid in settlement in connection with any claim against a Director if he acted in good faith and in a manner he believed to be in our best interests.

Election of Directors and Officers

Directors are elected to serve until the next annual meeting of stockholders and until their successors have been elected and qualified. Officers are appointed to serve until the meeting of the Board of Directors following the next annual meeting of stockholders and until their successors have been elected and qualified.

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Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), requires our executive officers and directors, and persons who beneficially own more than ten percent of our common stock, to file initial reports of ownership and reports of changes in ownership with the SEC.  Executive officers, directors and greater-than-ten-percent beneficial owners are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file.  Based upon a review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that as of the date of this filing they were current in their filings.

Code of Ethics

A code of ethics relates to written standards that are reasonably designed to deter wrongdoing and to promote:

(1) Honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;

(2) Full, fair, accurate, timely and understandable disclosure in reports and documents that are filed with, or submitted to, the Commission and in other public communications made by an issuer;

(3) Compliance with applicable governmental laws, rules and regulations;

(4) The prompt internal reporting of violations of the code to an appropriate person or persons identified in the code; and

(5) Accountability for adherence to the code.

We have not adopted a corporate code of ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions.

Our decision to not adopt such a code of ethics results from our having a small management for the Company. We believe that the limited interaction which occurs having such a small management structure for the Company eliminates the current need for such a code, in that violations of such a code would be reported to the party generating the violation.

Corporate Governance

We currently do not have standing audit, nominating and compensation committees of the board of directors, or committees performing similar functions. Until formal committees are established, our entire board of directors perform the same functions as an audit, nominating and compensation committee.

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Involvement in Certain Legal Proceedings

To the best of our knowledge, none of our directors or executive officers has, during the past five years:

• been convicted in a criminal proceeding or been subject to a pending criminal proceeding (excluding traffic violations and other minor offences);
• had any bankruptcy petition filed by or against the business or property of the person, or of any partnership, corporation or business association of which he was a general partner or executive officer, either at the time of the bankruptcy filing or within two years prior to that time;
• been subject to any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction or federal or state authority, permanently or temporarily enjoining, barring, suspending or otherwise limiting, his involvement in any type of business, securities, futures, commodities, investment, banking, savings and loan, or insurance activities, or to be associated with persons engaged in any such activity;
• been found by a court of competent jurisdiction in a civil action or by the SEC or the Commodity Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended, or vacated;
• been the subject of, or a party to, any federal or state judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated (not including any settlement of a civil proceeding among private litigants), relating to an alleged violation of any federal or state securities or commodities law or regulation, any law or regulation respecting financial institutions or insurance companies including, but not limited to, a temporary or permanent injunction, order of disgorgement or restitution, civil money penalty or temporary or permanent cease-and-desist order, or removal or prohibition order, or any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or
• been the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in Section 3(a)(26) of the Exchange Act (15 U.S.C. 78c(a)(26))), any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange Act (7 U.S.C. 1(a)(29))), or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.

ITEM 11. EXECUTIVE COMPENSATION

Overview of Compensation Program

In December of 2017 we formed our Compensation Committee, the Committee is chaired by James Borgna and James Walesa as member. The Compensation Committee ensures that the total compensation paid to the executives is fair, reasonable and competitive.

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Compensation Philosophy and Objectives

The Board of Directors believes that the most effective executive compensation program is one that is designed to reward the achievement of specific annual, long-term and strategic goals by the Company and that aligns executives’ interests with those of the stockholders by rewarding performance above established goals, with the ultimate objective of improving stockholder value. As a result of the size of the Company, the Board evaluates both performance and compensation on an informal basis. To that end, the Board believes executive compensation packages provided by the Company to its executives, including the named executive officers, should include both cash and stock-based compensation that reward performance as measured against established goals.

Role of Executive Officers in Compensation Decisions

The Compensation Committee makes all compensation decisions for, and approves recommendations regarding equity awards to, the executive officers and Directors of the Company. Decisions regarding the non-equity compensation of other employees of the Company are made by management.

Summary Compensation

During the year ended December 31, 2015, we entered into new employment contracts with both our CEO and CFO on September 1, 2015. The contract calls for each to receive a base salary of $20,000 per month for the first 12 months. The base salary shall increase to $25,000 per month for the next 12 month period and then increase to $30,000 per month for the final 12 months of the three year contract. As of the date of the salary increase, the CEO and CFO have deferred payment of approximately $10,000 per month of salary during the first year of the contract and $15,000 per month during the second year of the contract and $20,000 per month during the third year. The CEO and CFO are also entitled to quarterly and annual bonuses upon reaching mutually agreeable objectives set by Employer and Employee. The CEO and CFO shall be entitled to receive and or participate in all benefit plans and programs of Employer currently existing or hereafter made available to executives and or senior management of the Employer.

Summary Compensation Table

The table below summarizes the total compensation earned by our Executive Officers but does not account for deferred compensation as discussed above, for the last two fiscal years ended December 31, 2018 and 2017.

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SUMMARY COMPENSATION TABLE
Name and Principal Positions	Year		Salary ($)	Bonus ($)	Stock Awards ($)	Option Awards ($)	Non-Equity Incentive Plan Compen- sation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compen-sation ($)		Total ($)
Armen Nahabedian,	2018	$	360,000	-0-	-0-	-0-	-0-	-0-	-0-	$	360,000
Chief Executive Officer, President, and Director (1)	2017	$	320,000	-0-	-0-	-0-	-0-	-0-	-0-	$	340,000
Philip McPherson	2018	$	360,000	-0-	-0-	-0-	-0-	-0-	-0-	$	360,000
Chief Financial Officer, Secretary, Treasurer, and Director (2)	2017	$	320,000	-0-	-0-	-0-	-0-	-0-	-0-	$	340,000

(1) Mr. Nahabedian was appointed Chief Executive Officer, President, and a Director of the Company on August 9, 2011.

(2) Mr. McPherson was appointed Chief Financial Officer, Secretary, Treasurer, and a Director of the Company on September 1, 2012.

Termination of Employment

Pursuant to the terms of the employment contracts for the company’s CEO and CFO, in the event of a change of control the CEO and CFO are entitled to five years of current monthly salary and five years of medical insurance. Additionally all unvested stock options immediately vest.

Option Grants in Last Fiscal Year

On August 1, 2018 the Board of Directors approved the granting of 500,000 stock options at $0.20 per share for a term of seven years to three of the five board members. These stock options were granted under the current 2012 Stock Incentive Plan for up to 10,000,000 shares. Currently the Company has granted 10,000,000 shares under this plan.

Director Compensation

As a result of having limited capital resources we do not currently have an established compensation package for our board members. Therefore, the Board of Directors approved issuing 500,000 stock options at $0.20 per share in 2018 as compensation.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth information, to the best of our knowledge, about the beneficial ownership of our common stock on April 16, 2019 relating to the beneficial ownership of our common stock by those persons known to beneficially own more than 5% of our capital stock and by our directors and executive officers. The percentage of beneficial ownership for the following table is based on 48,956,147 shares of common stock outstanding.

Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and does not necessarily indicate beneficial ownership for any other purpose. Under these rules, beneficial ownership includes those shares of common stock over which the stockholder has sole or shared voting or investment power. The percentage ownership of the outstanding common stock, however, is based on the assumption, expressly required by the rules of the Securities and Exchange Commission, that only the person or entity whose ownership is being reported has converted options or warrants into shares of our common stock.

Security Ownership of Certain Beneficial Owners and Management

Title of Class		Name and address of Beneficial Owner(1)	Number Of Shares		Percent Beneficially Owned
	Common	Armen Nahabedian, CEO, President & Director		4,421,500		9.0	%
	Common	Philip J. McPherson, CFO & Director		2,030,000		4.0	%
	Common	James Walesa, Director(2)		7,223,686		15.0	%
	Common	James Borgna, Director		200,000		0.5	%
	Common	Kern Bluff Resources, LLC		6,000,000		12.0	%
	Common	Vahagn Nahabedian		4,000,000		9.0	%
		All Beneficial Owners as a Group		23,875,186		49.0	%

(1) As used in this table, “beneficial ownership” means the sole or shared power to vote, or to direct the voting of, a security, or the sole or shared investment power with respect to a security (i.e., the power to dispose of, or to direct the disposition of, a security). Each Parties’ address is care of the Company at 417 31^st St. Unit A, Newport Beach, CA 92663

(2) Includes 5,503,353 shares owned by Cibolo Creek Partners of which Mr. Walesa is a member.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Transactions with Related Persons

During the year ended December 31, 2018, the Company made the following purchases from entities considered related parties; $125,217 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.

In December 2014, we entered 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.

Promoters and Certain Control Persons

We did not have any promoters at any time since our inception in December 2009.

Director Independence

We currently have two independent directors, as the term “independent” is defined in Section 803A of the NYSE Amex LLC Company Guide. Since the OTCBB does not have rules regarding director independence, the Board makes its determination as to director independence based on the definition of “independence” as defined under the rules of the New York Stock Exchange (“NYSE”) and American Stock Exchange (“Amex”).

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

(1) AUDIT FEES

Audit and Non-Audit Fees

The following table sets forth the fees paid or accrued by us for the audit and other services provided by Malone-Bailey, LLP for the audit of our annual consolidated financial statements for the year ended December 31, 2018 and 2017 respectively

	Fiscal Year Ended December 31, 2018		Fiscal Year Ended December 31, 2017
Audit Fees(1)	$	61,000	$	47,000
Tax Fees	$	—	$	—
All Other Fees	$	—	$	—
Total	$	61,000	$	47,000

(1) Audit Fees: This category represents fees for professional services provided in connection with the audit of our consolidated financial statements and review of our quarterly consolidated financial statements.

(2) AUDIT-RELATED FEES

None.

(3) TAX FEES

None.

(4) ALL OTHER FEES

None.

(5) AUDIT COMMITTEE POLICIES AND PROCEDURES

We do not have an audit committee.

(6) If greater than 50 percent, disclose the percentage of hours expended on the principal accountant's engagement to audit the registrant's consolidated financial statements for the most recent fiscal year that were attributed to work performed by persons other than the principal accountant's full-time, permanent employees.

Not applicable. 

 -40-

PART IV

ITEM 15. EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

(a) We have filed the following documents as part of this Annual Report on Form 10-K:

1. The consolidated financial statements listed in the "Index to Consolidated Financial Statements" at page are filed as part of this report.

2. Consolidated financial statement schedules are omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.

3. Exhibits included or incorporated herein: See index to Exhibits.

Exhibit Index

			Incorporated by reference
Exhibit		Filed		Period		Filing
Number	Exhibit Description	herewith	Form	ending	Exhibit	date
3(i)(a)	Articles of Incorporation of Citadel Exploration, Inc.		S-1		3(i)(a)	2/11/10
3(i)(b)	Certificate of Amendment – Name Change – Dated March 3, 2011		8-K		3(i)(b)	3/10/11
3(i)(c)	Certificate of Change – Dated March 3, 2011		8-K		3(i)(c)	3/10/11
3(ii)(a)	Bylaws of Citadel Exploration, Inc.		S-1		3(ii)(a)	2/11/10
10.1	Membership Purchase Agreement and Plan of Reorganization– Dated February 28, 2011		8-K		2.1	3/01/11
10.2	Addendum No. 1 to Membership Purchase Agreement and Plan of Reorganization – Dated April 27, 2011		8-K		2.2	5/3/11
10.3	Letter Agreement – Dated February 22, 2012		8-K		10.1	3/22/12
10.4	Bridge Loan Agreement		8-K		10.4	4/4/14
31.1	Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	X
31.2	Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	X
32.1	Certifications of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	X
32.2	Certifications of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	X
99.2	Presentation – Dated November 10, 2011		8-K		EX. 99.2	11/15/12
99.3	MHA Reserve Report – Dated March 19, 2019		10-K		EX. 99.3	04/16/19
101.INS**	XBRL Instance Document	X
101.SCG**	XBRL Taxonomy Extension Schema	X
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase	X
101.DEF	XBRL Taxonomy Extension Definition Linkbase	X
101.LAB**	XBRL Taxonomy Extension Label Linkbase	X
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase	X

** XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

 -41-

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused the report to be signed on its behalf by the undersigned, thereunto duly authorized.

CITADEL EXPLORATION, INC.

By: /s/Armen Nahabedian

Armen Nahabedian, President

Date: April 16, 2019

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/Armen Nahabedian	Chief Executive Officer (Principal Executive Officer), President, and Director	April 16, 2019
Armen Nahabedian
/s/Philip J. McPherson	Chief Financial Officer (Principal Financial Officer) Secretary, Treasurer,  and Director	April 16, 2019
Philip J. McPherson
/s/James Walesa	Chairman of the Board	April 16, 2019
James Walesa
/s/James Borgna	Director	April 16, 2019
James Borgna

 -42-

CITADEL EXPLORATION, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2018 AND 2017

	PAGES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	F-1
CONSOLIDATED BALANCE SHEETS	F-2
CONSOLIDATED STATEMENTS OF OPERATIONS	F-3
CONSOLIDATED STATEMENT OF STOCKHOLDERS' DEFICIT	F-4
CONSOLIDATED STATEMENTS OF CASH FLOWS	F-5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	F-6 – F-27

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of

Citadel Exploration, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Citadel Exploration Inc. and its subsidiaries (collectively, the “Company”) as of December 31, 2018 and 2017, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Going Concern Matter

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has suffered recurring losses from operations and has a net capital deficiency that raises substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ MaloneBailey, LLP

www.malonebailey.com

We have served as the Company's auditor since 2018.

Houston, Texas

April 16, 2019

F-1

CITADEL EXPLORATION, INC.

Consolidated Balance Sheets

	December 31,			December 31,
	2018			2017
ASSETS
Current assets:
Cash	$	86,441		$	772,103
Other receivable		135,824			16,540
Prepaid expenses		32,633			29,280
Product inventory		—			20,107
Total current assets		254,898			838,030
Deposits		35,100			10,100
Restricted cash		200,000			200,000
Oil and gas properties (successful efforts basis)
Proved, net		5,685,535			5,018,086
Unproved		1,172,034			1,170,000
Equipment, net		67,326			82,969
Total assets	$	7,414,893		$	7,319,185
LIABILITIES AND STOCKHOLDERS' DEFICIT
Current liabilities:
Accounts payable and accrued liabilities	$	2,657,590		$	2,220,938
Accrued interest payable		390,224			459,416
Drilling obligation, net of discount of $42,000 and $126,000 as of December 31, 2018 and December 31, 2017, respectively		676,060			700,000
Notes payable, net		2,353,003			579,951
Production payment liability, related party		300,000			300,000
Total current liabilities		6,376,877			4,260,305
Asset retirement obligation		250,358			224,380
		—			—
Total liabilities	$	6,627,235		$	4,484,685
Commitments and Contingencies – See Note 4
Stockholders' equity/deficit:
Common stock, $0.001 par value, 300,000,000 shares authorized, 45,000,000 and 44,449,742 shares issued and outstanding as of December 31, 2018 and December 31, 2017 respectively		45,000			44,450
Series A Preferred stock, $20.00 par value, 500,000 shares authorized, 395,615 and 394,365 shares issued and outstanding as of December 31, 2018 and December 31, 2017 respectively		7,912,300			7,887,300
Additional paid-in capital		6,150,871			5,691,239
Accumulated deficit		(13,320,513	)		(10,788,489	)
Total stockholders’ equity		787,658			2,834,500
Total liabilities and stockholders’ equity	$	7,414,893		$	7,319,185

See accompanying notes to consolidated financial statements.

F-2

CITADEL EXPLORATION, INC.

Consolidated Statements of Operations

	For the years
	ended
	December 31,
	2018			2017
Revenue	$	1,066,314		$	166,355
Operating expenses:
Lease operating expense		822,674			232,081
General and administrative		298,889			246,764
Depreciation, depletion and amortization		571,301			134,619
Professional fees		277,025			201,763
Executive compensation		1,216,529			651,760
Dry hole, abandonment, impairment, and exploration		—			427,353
Total operating expenses		3,186,418			1,894,340
Other income (expenses):
Gain on settlement of prior year preferred stock liability		—			50,122
Gain – other		—			4,000
Interest expense		(411,920	)		(79,481	)
Total other income (expenses)		(411,920	)		(25,359	)
Loss before provision for income taxes		(2,532,024	)		(1,753,344	)
Provision for income taxes expenses(benefits)		—			—
Net loss		(2,532,024	)		(1,753,344	)
Series A preferred stock dividends		(791,230	)		(620,347	)
Deemed dividend, ORRI issued with preferred stock		—			(442,136	)
Net loss available to common stockholders	$	(3,323,254	)	$	(2,815,827	)
Weighted average number of common shares		44,726,467			40,891,604
outstanding – basic and diluted
Net loss per common share - basic and diluted	$	(0.07	)	$	(0.07	)

See accompanying notes to consolidated financial statements.

F-3

CITADEL EXPLORATION, INC.

Consolidated Statements of Stockholder Equity

									Additional
	Common Stock				Preferred Stock				Paid-In			Accumulated			Total
	Shares		Amount		Shares		Amount		Amount			Deficit			Equity
Balance at December 31, 2016		39,314,004	$	39,314		—		—	$	5,790,060		$	(9,035,145	)	$	(3,205,771	)
Preferred shares issued for cash		—		—		58,750		1,175,000		—			—			1,175,000
Preferred shares issued to settle note payable		—		—		5,250		105,000		—			—			105,000
Preferred shares issued to settle preferred stock payable		—		—		330,365		6,607,300		—			—			6,607,300
Common shares issued for special preferred stock dividend		3,101,736		3,102		—		—		(3,102	)		—			—
Common shares issued to settle accrued interest on preferred stock		2,034,002		2,0334		—		—		242,046			—			244,080
Contribution from related party on preferred stock interest		—		—		—		—		104,371			—			104,371
Deemed dividend, ORRI issued with preferred stock		—		—		—		—		(442,136	)		—			(442,136	)
Net Loss													(1,753,344	)		(1,753,344	)
Balance at January 1, 2017		44,449,742	$	44,450		394,365	$	7,887,300	$	5,691,239		$	(10,788,489	)	$	2,834,500
Common shares issued for services rendered		450,262		450		—		—		89,602			—			90,052
Common shares issued to settle bonus payable		100,000		100		—		—		19,900			—			20,000
Preferred shares issued for cash		—		—		1,250		25,000		—			—			25,000
Warrants on senior secured facility		—		—		—		—		225,170			—			225,170
Stock option expense, related to stock-based compensation issued with executive compensation		—		—		—		—		124,960			—			124,960
Net loss													(2,532,024	)		(2,532,024	)
Balance at December 31, 2018		45,000,004	$	45,000		395,615	$	7,912,300	$	6,150,871		$	(13,320,513	)	$	787,658

See accompanying notes to consolidated financial statements.

F-4

CITADEL EXPLORATION, INC.

Consolidated Statements of Cash Flows 

	For the years
	Ended
	December 31,
	2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(2,532,024	)		(1,753,344	)
Depreciation, amortization and accretion		571,302			134,619
Amortization of debt discount		248,035			—
Abandonment and impairment		—			427,353
Stock based compensation expense		215,011			—
Gain on settlement of prior year preferred stock liability		—			(50,122	)
Overriding royalty interest granted as compensation		430,092			—
Changes in operating assets and liabilities:
Decrease (increase) in inventory		—			(191	)
Decrease (increase) in other receivable		(119,284	)		(9,398	)
Decrease (increase) in prepaid expenses		58,884			57,076
Increase in deposits		(25,000	)		(200	)
Decrease in restricted cash					45,000
Increase in accrued interest payable		160,196			170,640
Increase in accounts payable and accrued liabilities		556,652			636,680
Net cash used in operating activities		(436,135	)		(341,887	)
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration and development of oil and gas properties		(1,602,400	)		(981,622	)
Purchase of equipment		(6,749	)		(6,214	)
Net cash used in investing activities		(1,609,149	)		(987,876	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from sale of preferred stock, net of costs		25,000			1,175,000
Proceeds from loans payable		1,520,612			605,000
Proceeds (payments) from drilling liability		(107,940	)		700,000
Repayments of notes payable		(78,050	)		(566,927	)
Net cash provided by financing activities		1,359,622			1,913,073
Net increase in cash and restricted cash at beginning of year		(685,662	)		583,310
Cash and restricted cash at beginning of year		972,103			188,793
Cash and restricted cash at end of year	$	286,441		$	772,103
Supplemental disclosures of cash flow information:
Income taxes paid	$	—		$	2,300
Reclass of inventory to O&G properties	$	20,107		$	—
Non-cash investing and financing activities:
Preferred shares issued to settle preferred stock payable	$	—		$	6,607,300
Preferred shares issued to settle note payable	$	—		$	105,000
Debt Discount from drilling liability	$	—		$	126,000
Common Stock issued for preferred stock dividend	$	—		$	3,102
Financing of vehicles	$	—		$	67,078
Financing of insurance premium	$	—		$	52,920
Common shares issued to settle accrued interest on preferred stock	$	—		$	244,080
Deemed dividend, ORRI issued with preferred stock	$	—		$	442,136
Gain of settlement of prior year preferred stock liability recorded in APIC	$	—		$	104,371
Debt discount for warrants issued on loans	$	225,170		$	—
Accrued interest payable rolled over to senior loan facility	$	229,388		$	—
Asset retirement obligation	$	12,128		$	—
Insurance premium financing		62,237
Non-cash addition to loan payable for payment of San Benito litigation	$	100,000		$	—
Shares issued to settle bonus payable	$	20,000		$	—

See accompanying notes to consolidated financial statements. 

F-5

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Summary of Significant Accounting Policies

Organization

Citadel Exploration, Inc. ("Citadel Inc") was incorporated on December 17, 2009 in the State of Nevada originally under the name Subprime Advantage, Inc.  On March 2, 2011, the Company changed its name from Subprime Advantage, Inc. to Citadel Exploration, Inc.

On May 3, 2011, Citadel Inc completed the acquisition of 100% interest in Citadel Exploration, LLC, a California limited liability company, ("Citadel LLC") pursuant to a Membership Purchase Agreement (the "MPA"). Under the MPA, Citadel Inc issued 14,000,000 shares of the its common stock an individual in exchange for a 100% interest in Citadel LLC. Additionally under the MPA, the former officers and directors of Citadel Inc agreed to cancel 7,696,000 shares of its common stock. For accounting purposes, the acquisition of the Citadel LLC by Citadel Inc has been accounted for as a recapitalization, similar to a reverse acquisition except no goodwill is recorded, whereby the private company, Citadel LLC, in substance acquired a non-operational public company (Citadel Inc) with nominal assets and liabilities for the purpose of becoming a public company. Accordingly, Citadel LLC are considered the acquirer for accounting purposes and thus, the historical financials are primarily that of Citadel LLC. As a result of this transaction, Citadel Inc changed its business direction and is now involved in the acquisition and development of oil and gas resources in California. Citadel LLC was incorporated on November 6, 2006 (Date of Inception) and accordingly, the accompanying consolidated financial statements are from the Date of Inception of Citadel LLC through ending reporting periods reflected.

The consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America applicable to exploration stage enterprises, and are expressed in U.S. dollars. The Company’s fiscal year end is December 31.

Principles of consolidation

For the years ended December 31, 2018 and 2017, the consolidated financial statements include the accounts of Citadel Exploration, Inc. and Citadel Exploration, LLC.   All significant intercompany balances and transactions have been eliminated.   Citadel Exploration, Inc. and Citadel Exploration, LLC will be collectively referred herein to as the “Company”.

Nature of operations

Currently, the Company is focused on the acquisition and development of oil and gas resources in California.

Assumptions, Judgments and Estimates

In the course of preparing the consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.

Assumptions, Judgments and Estimates (continued)

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.

F-6

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Summary of Significant Accounting Policies (continued)

Fair value of financial instruments

Fair value estimates discussed herein are based upon certain market assumptions and pertinent information available to management as of December 31, 2018 and 2017. See Footnote No. 13, “Fair Value of Financial Instruments,” for further information. The respective carrying value of certain on-balance-sheet financial instruments approximated their fair values. These financial instruments include cash, prepaid expenses and accounts payable. Fair values were assumed to approximate carrying values for payables because they are short term in nature and their carrying amounts approximate fair values or they are payable on demand.

Level 1: The preferred inputs to valuation efforts are “quoted prices in active markets for identical assets or liabilities,” with the caveat that the reporting entity must have access to that market. Information at this level is based on direct observations of transactions involving the same assets and liabilities, not assumptions, and thus offers superior reliability. However, relatively few items, especially physical assets, actually trade in active markets.

Level 2: FASB acknowledged that active markets for identical assets and liabilities are relatively uncommon and, even when they do exist, they may be too thin to provide reliable information. To deal with this shortage of direct data, the board provided a second level of inputs that can be applied in three situations.

Level 3: If inputs from levels 1 and 2 are not available, FASB acknowledges that fair value measures of many assets and liabilities are less precise. The board describes Level 3 inputs as “unobservable,” and limits their use by saying they “shall be used to measure fair value to the extent that observable inputs are not available.” This category allows “for situations in which there is little, if any, market activity for the asset or liability at the measurement date”. Earlier in the standard, FASB explains that “observable inputs” are gathered from sources other than the reporting company and that they are expected to reflect assumptions made by market participants.

Inventories

Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence. Finished goods include oil and natural gas products, which are valued at the lower of cost or market.

Oil and Natural Gas Properties

The Company accounts for our oil and gas exploration and development costs using the successful efforts method. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found.

If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

F-7

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Summary of Significant Accounting Policies (continued)

Oil and Natural Gas Properties (continued)

The costs of development wells are capitalized whether productive or nonproductive. We review our oil and natural gas producing properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if a field contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 inputs which are based upon estimates, the most significant of which is the estimate of net proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates.

Property, Plant and Equipment

The Company records all property and equipment at cost less accumulated depreciation.  Improvements are capitalized while repairs and maintenance costs are expensed as incurred. Depreciation is calculated on a straight-line basis over estimated useful lives ranging from 5 to 30 years for buildings and improvements and 3 to 10 years for machinery and equipment. Leasehold improvements include the cost of the Company’s internal development and construction department. The Company capitalizes the costs associated with the development of the Company’s website pursuant to ASC Topic 350.

Stock-based compensation

The Company records stock-based compensation in accordance with the guidance in ASC Topic 505 and 718 which requires the Company to recognize expenses related to the fair value of its employee stock option awards.  The Company recognizes the cost of all share-based awards on a graded vesting basis over the vesting period of the award. 

The Company accounts for equity instruments issued in exchange for the receipt of goods or services from other than employees in accordance with FASB ASC 505-50. Costs are measured at the estimated fair market value of the consideration received or the estimated fair value of the equity instruments issued, whichever is more reliably measurable. The value of equity instruments issued for consideration other than employee services is determined on the earliest of a performance commitment or completion of performance by the provider of goods or services as defined by FASB ASC 505-50.

Earnings per share

The Company follows ASC Topic 260 to account for the earnings per share. Basic earnings per common share (“EPS”) calculations are determined by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per common share calculations are determined by dividing net income by the weighted average number of common shares and dilutive common share equivalents outstanding. During periods when common stock equivalents, if any, are anti-dilutive they are not considered in the computation.

F-8

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Summary of Significant Accounting Policies (Continued)

Cash and cash equivalents

The Company considers all highly liquid instruments with maturity of three months or less at the time of issuance to be cash equivalents.

Concentrations of credit risk

Financial instruments that subject the Company to credit risk could consist of cash balances maintained in excess of federal depository insurance limits. The Company maintains its cash and cash equivalent balances with high credit quality financial institutions. At times, cash and cash equivalent balances may be in excess of Federal Deposit Insurance Corporation limits. To date, the Company has not experienced any such losses.

Restricted cash

Restricted cash consisted of a blanket bond totaling $200,000. Bonds are required to meet financial bonding requirements in the state of California. The blanket bond, which will cover 50 wells, was purchased in August 2015 following the acquisition of the Kern Bluff Oil Field.

Debt discount

The Company records debt discount as a contra liability account and is presented net of the associated loan. The discount is amortized over the life on the loan using the straight-line method because the straight-line method approximates the effective interest method.

Revenue Recognition

 The new revenue standard (ASC606) requires more quantitative and qualitative disclosure that prior guidance. More specifically the following areas have been a concern for the SEC. As such Citadel will address each of these matters in the following bullet points.

As background, Citadel Exploration has one source of revenue, Phillips 66, the refiner that purchases our crude oil. Citadel receives a check from the purchaser Phillips 66 on the 20^th of the Month following said production. The revenue amount is net of transportation costs, currently $1.45 per barrel. The price received is based upon the purchaser contract which is the average of the posted price for heavy oil in California. For natural gas, there is no revenue as our field does not produce economic quantities of natural gas. For gathering and transportation sales, there are no sales or revenues. We own and operate all gathering equipment and infrastructure. Revenues from oil and gas sales are recognized when once we have received payment from the refiner.

• Performance Obligations: Phillips 66 has been our purchaser for the last two years and has never missed a payment. From a qualitative measure they could not perform any better.
• Variable Consideration: The price Citadel receives for its oil, is tracked daily by several services including Bloomberg.com, oilprice.com and on Chevron’s webpage. This price is wildly available and transparent. Citadel does not calculate, or control said price. From a quantitative standpoint, we do not have any control. From a qualitative standpoint, we compare what we are paid, versus what prices averaged for the quarter.
• Recognizing revenue: Citadel is sent an oil ticket summary on or around the 10^th of the month, depending on if the date is on a weekend. That summary provides a detailed summary of date and barrels sold and at what price. The revenue is recognized in the quarter that the oil is sold, as we are paid for the oil on the 20^th of the following month.
• Costs to obtain a contract: The only cost that Citadel incurs is a transportation cost. The actual contract has no costs. As an example, prior to Phillips 66 we sold to Plains All American (PAA). Our PAA contract charged us $1.95 for transportation. Through various contacts we were introduced to Phillips 66, and they quoted Citadel a transportation cost of $1.45. Both contracts were based on the exact same California heavy oil index for price, therefore the ability to save/realize an additional $0.50 per barrel was the motivation for the change. From a qualitative standpoint, Phillips 66 and PAA are both multibillion-dollar companies. Therefore, we did not see a difference in credit risk to getting paid.
• Gross versus net presentation: This does not apply as we are paid the gross value of our oil minus transportation costs. We do not accept a discount.
• Disaggregated revenue: This does not apply as we sell oil from one facility at one oil field and do not have multiple fields or multiple refiners.

In conclusion, Citadel’s business and hence revenue is pretty simple and straight forward. We sell one product, to one refiner, and we are paid once a month.

Asset Retirement Obligation

The Company's asset retirement obligations (AROs) relate to future costs associated with plugging and abandonment of oil wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred (typically when the asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability.

Revenue & Expense Recognition

The Company utilizes accrual basis of accounting when measuring financial position and operating results. The accrual basis recognizes revenues and expenses in the accounting period in which those transactions, events, or circumstances occur (goods or services are received) and become measurable.

F-9

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Summary of Significant Accounting Policies (Continued)

Revenue & Expense Recognition (continued)

The Company recognizes its expenses when the expenses are incurred, not necessarily when they are paid. Expenses are generally incurred when the company receives tangible goods or services are provided.

Lease operating expense

Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities.

Depreciation, Depletion and Amortization

The provision for DD&A-oil and natural gas production is calculated on a field-by-field basis using the unit-of-production method. Projected future production rates, the timing of future capital expenditures as well as changes in commodity prices, may significantly impact estimated reserve quantities. Depreciation, depletion and amortization —oil and natural gas production is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections. These estimates are subject to change as additional information and technologies become available. Accordingly, oil and natural gas quantities ultimately recovered and the timing of production may be substantially different than projected. Reduction in reserve estimates may result in increased depreciation, depletion and amortization oil and natural gas production, which in turn reduces net earnings. Changes in reserve estimates are applied on a prospective basis. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher costs fields.

Income taxes

The Company follows ASC Topic 740 for recording the provision for income taxes. Deferred tax assets and liabilities are computed based upon the difference between the consolidated financial statements and income tax basis of assets and liabilities using the enacted marginal tax rate applicable when the related asset or liability is expected to be realized or settled. Deferred income tax expenses or benefits are based on the changes in the asset or liability each period.

If available evidence suggests that it is more likely than not that some portion or all of the deferred tax assets will not be realized, a valuation allowance is required to reduce the deferred tax assets to the amount that is more likely than not to be realized. Future changes in such valuation allowance are included in the provision for deferred income taxes in the period of change.

Deferred income taxes may arise from temporary differences resulting from income and expense items reported for financial accounting and tax purposes in different periods. Deferred taxes are classified as current or non-current, depending on the classification of assets and liabilities to which they relate. Deferred taxes arising from temporary differences that are not related to an asset or liability are classified as current or non-current depending on the periods in which the temporary differences are expected to reverse. The net operating loss carryforward for the year ended December 31, 2018 is $11,534,488 and the deferred tax asset is $3,595,000. The Company maintains a full valuation allowance for the deferred tax asset of $3,595,000.

F-10

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Summary of Significant Accounting Policies (Continued)

The Company applies a more-likely-than-not recognition threshold for all tax uncertainties. ASC Topic 740 only allows the recognition of those tax benefits that have a greater than fifty percent likelihood of being sustained upon examination by the taxing authorities. As of December 31, 2018 and 2017, the Company reviewed its tax positions and determined there were no outstanding, or retroactive tax positions with less than a 50% likelihood of being sustained upon examination by the taxing authorities, therefore this standard has not had a material effect on the Company.

The Company does not anticipate any significant changes to its total unrecognized tax benefits within the next 12 months. 

The Company classifies tax-related penalties and net interest as income tax expense. As of December 31, 2018 and 2017, no income tax expense has been recorded.

Long-lived Assets

In accordance with the Financial Accounting Standards Board ("FASB") Accounts Standard Codification (ASC) ASC 360-10, "Property, Plant and Equipment," the carrying value of intangible assets and other long-lived assets is reviewed on a regular basis for the existence of facts or circumstances that may suggest impairment. Proved oil properties are reviewed for impairment on a field-by-field basis, annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. The Company estimates the expected future cash flows of its oil properties and compares these undiscounted cash flows to the carrying amount of the oil properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil properties to fair value.

The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates commensurate with the risk associated with realizing the projected cash flows.

Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. The impairment assessment is affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time.

Leases

The Company had two types of leases. A capital lease for the financing of vehicles. An operational lease on its steam generator, in which the Company had previously purchased the generator and then sold the generator with an agreement to lease the equipment. Thus, this meets the definition of a sales lease-back arrangement. Since there was no gain or loss from the sale, there is no affect in the income statement.

Recent pronouncements

In May 2014, the FASB issued ASC updated No. 2014-09, Revenue from Contracts with Customers (Topic 606 (ASU 2014-09). Under the amendments in this update, recognition of revenue occurs when a customer obtains control of promised goods or services in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, the new standard requires that reporting companies disclose the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The amendments in this update are effective for fiscal years and interim periods within those years beginning after December 15, 2017 and supersedes any previous revenue recognition guidance. Implementation of Topic 606, which was adopted by the Company as of January 1, 2018, was done using the modified retrospective approach. Adoption of this new standard did not have an impact on the Company’s balance sheet, statement of operations, statement of stockholders’ equity or statement of cash flows.

In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash” (“ASU 2016-18”). The update is effective for years beginning December 15, 2017, including interim reporting periods within those fiscal years. Early adoption is permitted. These accounting pronouncements were adopted by the Company as of January 1, 2018. The purpose of Update 2016 -18 is to clarify guidance and presentation related to restricted cash in the Statements of Cash Flows. The amendment requires beginning-of-period and end-of- period total amounts shown on the Statements of Cash Flows to include cash and cash equivalents as well as restricted cash and restricted cash equivalents. Adoption of this new standard did not have a material impact on the Company’s financial statements.

F-11

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 2 – Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the recoverability of assets and the satisfaction of liabilities in the normal course of business. As noted above, the Company is in the exploration stage and, accordingly, has not yet generated significant revenues from operations. Since its inception, the Company has been engaged substantially in financing activities and developing its business plan and incurring startup costs and expenses. As a result, the Company incurred a net loss for year ended December 31, 2018 of $2,532,025. In addition, the Company’s exploration activities since inception have been financially sustained through debt and equity financing. These factors raise substantial doubt regarding the Company’s ability to continue as a going concern.  These financial statements do not include any adjustments to the recoverability and classification of recorded asset amounts and classification of liabilities that might be necessary should we be unable to continue as a going concern.

The ability of the Company to continue as a going concern is dependent upon its ability to raise additional capital from the sale of common stock and, ultimately, the achievement of significant operating revenues. These consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts, or amounts and classification of liabilities that might result from this uncertainty.

Note 3 – Restricted Cash

Restricted cash consists of one bond totaling $200,000 which is a blanket bond that will cover up to 50 wells. This bond was required in the normal course of business in the oil and gas industry. The bond totaling $200,000 was purchased in August 2015 following the acquisition of the Kern Bluff Oil Field. The detail breakdown of restricted cash and cash is depicted in the Consolidated Statement of Cash Flows as follows:

Note 4 – Commitments and Contingencies

Operating Leases

No operating leases for year ended December 31, 2018

Legal Proceedings

Various lawsuits, claims and other contingencies arise in the ordinary course of the Company’s business activities. While the ultimate outcome of the aforementioned contingencies are not determinable at this time, management believes that any liability or loss resulting therefrom will not materially affect the financial position, results of operations or cash flows of the Company.

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected areas. The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.

The Company is not aware of any environmental claims existing as of December 31, 2018. There can be no assurance, however, that the current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties.

F-12

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5 – Oil and Gas Properties, Buildings, and Equipment

Oil and natural gas properties consist of the following:

	2018			2017
Oil and Natural Gas:
Proved properties	$	4,121,940		$	3,468,306
Unproved properties		1,172,034			1,170,000
Facilities		2,231,561			2,244,716
		7,525,535			6,883,022
Less oil property impairment					(562,030	)
Less accumulated depreciation, depletion, and amortization		(667,966	)		(132,906	)
	$	6,857,569		$	6,188,086

During the year ended December 31, 2018, the Company spent $1,602,400 to continue to develop the Kern Bluff field and associated facilities. Also, during the year, the Company granted a 2% overriding royalty interest to management which was valued at $430,092.

As an annual process, Citadel reviewed the field to determine if asset impairment is required. If the carrying amount of the asset exceeds the sum of the undiscounted estimated future net cash flows, the Company will recognize impairment expense equal to the difference between the carrying value and the fair value of the asset, which is estimated to be the expected present value of discounted future net cash flows from proved reserves, utilizing a 10% rate of return. This process includes a projection of future oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. Citadel cannot predict the amount of impairment charges that may be recorded in the future. During the year ended December 31, 2017, the Company reduced the asset value by $427,353 due to focusing CAPEX at Kern Bluff and idling operations at Yowlumne. During the year ended December 31, 2018, the Company did not have any impairment of assets.

Kern Bluff Oil Field

The Kern Bluff Oil Field is comprised of approximately 1,100 acres. The field currently has 15 producing wells and an additional 20 idle well bores.

F-13

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 – Income Taxes

The (benefit) provision for income taxes from continuing operations consists of the following (in thousands):

	Year Ended December 31,
		2018			2017
Current:
Federal	$	—		$	—
State		4			2
		4			2
Deferred:
Federal		—			—
State		—			—
		—			—
Total	$	4		$	2
The components of the net deferred income tax liabilities consist of the following:
		Year Ended December 31,
		2018			2017
Deferred income tax assets:
Equity and deferred compensation		255			239
Net operating loss		2,442			1,918
State net operating loss carry forward		1,020			808
Other, net		—			—
Total deferred tax assets		3,697			2,965
Valuation allowance		(3,211	)		(2,907	)
		486			58
Deferred income tax liabilities:
Depreciation and depletion		(486	)		(58	)
Net deferred income tax liabilities	$	—		$	—

As of the year ended December 31, 2018, the Company does not have any uncertain tax positions. As of December 31, 2018, we had approximately $11,534,488 in net operating loss carryforwards for each federal and state income tax purposes. The net operating loss carryforward will begin to expire in 20 years if left unused. In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management has concluded that there is no assurance that the company will have taxable income in the future; therefore 100% of the deferred income tax assets is not recognized.

F-14

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6 – Income Taxes (Continued)

On December 22, 2017, the U.S. enacted the Tax Cuts and Jobs Act (the “Act”) which made significant changes to the Internal Revenue Code of 1986, including lowering the maximum federal corporate income tax rate from 35 percent to 21 percent, repealing the corporate alternative minimum tax (AMT), and imposing limitations on the use of net operating losses arising in taxable years beginning after December 31, 2017. Although most of the provisions of the Act are not effective until tax years ending after December 31, 2017, the effects of new legislation are recognized upon enactment in accordance with GAAP. As a result, recognition of the tax effects of the Act is required in the consolidated financial statements for the fiscal year ended December 31, 2017. In accordance with this Act, the Company has calculated its deferred tax asset at December 31, 2017 using the newly enacted corporate tax rate of 21%.

We consider the scheduled reversal of deferred tax assets, the level of historical taxable income and tax planning strategies in making the assessment of the realizability of deferred tax assets. We have identified the U.S. federal and California as our "major" tax jurisdiction.  With limited exceptions, we remain subject to IRS examination of our income tax returns filed within the last three (3) years, and to California Franchise Tax Board examination of our income tax returns filed within the last four (4) years.

Note 7 – Equipment

Equipment as of December 31, 2018 and 2017 are as follows:

	2018			2017
Vehicles	$	83,578		$	83,578
Website		1,375			1,375
Furniture/Computer Equip		20,380			20,380
Material/Pipe Supplies		6,750			0
Less: Accumulated depreciation		(44,758	)		(22,364	)
	$	67,325		$	18,530

Two vehicles were purchased during the year ended December 31, 2017 totaling $73,292. Of this amount, $67,078 was financed and $6,214 was paid in cash. Depreciation expense for the years ended December 31, 2018 and 2017, respectively, was $22,392 and $8,854.

F-15

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 8 – Debt

Loan payable

Notes payable consists of the following:

	December 31, 2018			December 31, 2017
Note payable to an entity for the financing of insurance premiums, unsecured; 7.99% interest, due March 2019	$	13,939		$	14,548
Note payable to an entity for the financing of a company vehicle, secured; 4.95% interest, due October 2022		25,598			32,351
Note payable to an entity for the financing of a company vehicle, secured; 4.95% interest, due November 2022		26,390			33,052
Senior Secured Debt, 10% interest; due March 31, 2019 and March 31,2017 respectively		2,350,000			500,000
Unamortized debt discount		(62,924	)		—
Notes Payable/Senior Secured Credit Facility – Total	$	2,353,003		$	579,951

During the 2018 period, the Company received proceeds of $2,350,000 in the form of a senior secured credit facility. The senior secured credit facility carries a 10% interest rate and also includes one five-year warrant at $0.10 per share for every two dollars outstanding. As of March 31^st, 2019, the entire principal and interest was due on the loan. The loan carried a financial covenant requiring the Company to generate one million in EBITDA as of December 31, 2018, the Company did not meet that obligation. Do to this non-compliance the Company is currently in default on the loan. Additionally, the Company was not able to repay the loan on its maturity date and is therefore in default on the loan. Repayments of notes for year ended December 31, 2018 and 2017, respectively, was $78,050 and $566,927. Interest expense for the year ended December 31, 2018 was $165,673 and relates to notes payable and insurance financing. Interest expense for the year ended December 31, 2017 was $79,481 and relates to notes payable and insurance financing. For year ended December 31, 2017 a note of $52,920 was used to finance insurance for the year.

Drilling Obligation

The Company entered into a drilling Joint Venture agreement with investors to drill two exploration wells in 2017. The $700,000 drilling liability has an 18% rate of return due to the investor and as such, the Company booked a discount of $126,000 of which $84,000 has been amortized during the year ended December 31, 2018, leaving a balance at December 31, 2018 of $42,000. The discount is being amortized over 18 months. The term is an estimate based on when management expects this liability to be fully settled.

Note 9 – Production Payment Liability

In December 2014, the Company entered into a financing agreement with two related party entities. The Company received $300,000 in total from both entities to fund costs of the Yowlumne 2-26 well recompletion. In return for the funds received, the two entities will receive a combined 75% of the net revenue from the well until the $300,000 is repaid. At the time of repayment, the entities will own a total 3% overriding royalty on the well. This liability is completely dependent on the well generating revenue.

If the well fails to generate enough revenue to repay the $300,000, Citadel is not responsible for the unpaid amount. According to ASC 932-470-25 Section B, Funds advanced to an operator that are repayable in cash out of the proceeds from a specified share of future production of a producing property, until the amount advanced $300,000 is paid in full, shall be accounted for as a borrowing. The advance is a payable for the recipient of the cash invested. Given the well is not currently on production coupled with the high cost of water disposal, we believe it will take more than two years for payback to occur; therefore this has been classified as a long-term payable.

F-16

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10 – Asset Retirement Obligations (AROs)

The Company's ARO relates to future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. In periods subsequent to the initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. The increases in the ARO liability due to the passage of time impact net earnings as accretion expense. The related capital cost, including revisions thereto, is charged to expense through depreciation, depletion and amortization of oil and natural gas production over the life of the oil and natural gas field.

The following table summarizes the activity for the Company's abandonment obligations:

	Year Ended December 31,
	2018		2017
Beginning balance at January 1	$	224,380	$	217,212
Liabilities incurred from property acquisition		12,129		—
Accretion expense		13,848		7,168
Ending balance at December 31	$	250,357	$	224,380

Note 11 – Stockholders’ Equity

The Company is authorized to issue 300,000,000 shares of its $0.001 par value common stock.

In March of 2016, the Company approved the sale of up to 500,000 shares of Series A Convertible Participating Preferred Stock. The following are terms of the Series A Convertible Participating Preferred Stock:

1. Series A – Senior to Common Stock

2. Three-Year Term – Series a Convertible at any time at the holder’s discretion, during the three year-term. Issuer, Citadel Exploration, Inc., can only force convert Series A, if the company’s common stock trades at $1.00 or more for 90 consecutive days.

3. Convertible into Citadel Exploration, Inc. common stock at a term of 1 share of preferred par value $20.00 to 100 shares of Common Stock par value $0.001 – implied conversion rate of $0.20 per share.

4. 10% Coupon, $2.00 per share, paid in semi-annual installments at $1.00 per share and payable in cash or payment in kind of additional Series A Convertible Participating Preferred Stock during first year.

5. 2% Over Riding Royalty Interest (ORRI) on the Kern Bluff Oil Field until conversion into common stock. Upon conversion, ORRI will be reduced to 1% in perpetuity.

6. Royalty to be paid on a quarterly basis, starting at 90 days after the close of the offering.

7. There is no redemption right by the company or the shares holders

The Company sold 175,000 shares of Series A Convertible Participating Preferred Stock to convert its $3,500,000 related party note payable to preferred stock. In addition, the Company has sold 21,250 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $425,000 through March 31, 2016.

F-17

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 11 – Stockholders’ Equity (Continued)

A 2% overriding royalty interest was issued in conjunction with the Series A Convertible Participating Preferred Stock. That value of $442,136 reduces the Company’s proved property valuation.

In June of 2016, the Company sold 50,000 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $1,000,000.

In September of 2016, the Company sold 26,500 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $530,000. The Company issued 500,000 shares of common stock for cash in the amount of $100,000. 

In October of 2016, the Company sold 10,350 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $207,000.

In November of 2016, the Company sold 29,330 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $586,600.

In December of 2016, the Company sold 13,300 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $266,000.

As detailed above in the related 2016 issuances, the Company issued 330,365 shares of Series A Convertible Participating Preferred stock to settle the 2016 preferred stock payable in the amount of 6,607,300. These shares were sold in 2016, but issued in 2017.

In March of 2017, the Company sold 10,000 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $200,000.

In March of 2017, the Company issued 2,034,002 common shares as a special dividend to Series A Preferred Shareholders to settle accrued interest on preferred stock during the 2016 offering period of the Series A totaling $244,080. A gain occurred on the issuance which totaled $50,122.

In June of 2017, the Company sold 13,750 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $275,000.

In September of 2017, the Company sold 22,500 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $450,000.

In October of 2017, the Company issued 5,250 shares of Series A Convertible Participating Preferred Stock as payment to settle note payable in the amount of $105,000.

In December of 2017, the Company sold 12,500 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $250,000.

In December of 2017, the Company issued 3,101,736 shares of common stock as payment for dividend on the Series A Preferred Stock during 2017.

In December of 2017, the Company adopted the 2017 Restricted Stock Unit Plan (RSU) authorizing the issuance of 10,000,000 restricted stock units to management and future employees. 

In January of 2018, the Company sold 1,250 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $25,000.

In March of 2018, the Company awarded 5,500,000 Restricted Stock Units (RSU) to its CEO, CFO and General Counsel. The Restricted Stock Units have a 2-year vesting period and therefore have not been issued.

In January of 2019, the Company issued 3,956,147 shares of common stock as payment for dividend on the Series A Preferred Stock during 2018.

F-18

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 Note 12 – Stock Option Plan

On August 1, 2018 as approved by the Board of Directors, the Company granted 500,000 stock options to three members of the Board of Directors.  These options vest over a three year period, at $0.15 per share for a term of seven years. using the Black Scholes option pricing model with an expected life of 7 years, risk free interest rate of 1.872%, dividend yield of 0%, and expected volatility of 333%.

The following is a summary of the status of all of the Company’s stock options as of December 31, 2018 and changes during the period ended on that date:

	Number of Options		Weighted-Average Exercise Price		Aggregate Intrinsic Value		Weighted-Average Remaining Life (Years)
Outstanding at January 1, 2017		9,500,000	$	0.20	$	—		3.26
Exercisable at January 1, 2017		9,500,000	$	0.20	$	—		3.26
Granted			$	0.00	$	—		—
Exercised		—	$	0.00	$	—		—
Cancelled		—	$	0.00	$	—		—
Outstanding at December 31, 2017		9,500,000	$	0.20	$	—		3.26
Exercisable at December 31, 2017		9,500,000	$	0.20	$	—		3.26
Granted		500,000	$	0.20	$	—		2.48
Exercised		—	$	0.00	$	—		—
Cancelled		—	$	0.00	$	—		—
Outstanding at December 31, 2018		10,000,000	$	0.20	$	—		2.48
Exercisable at December 31, 2018		10,000,000	$	0.20	$	235,000		2.48

Note 13 – Warrants

In March 2018, the Company closed on a $3,000,000 Senior Secured Credit Facility with $1,750,000 drawn. As per the terms of the agreement, the investors receive one warrant for every two dollars invested. As such the Company issued 875,000 warrants at $0.10 per share with a five-year term. The Company closed on an additional $500,000 of debt in August of 2018 and $100,000 of debt in October 2018 as such the Company issued 250,000 warrants and 50,000 warrants all at the same price and duration as the original tranche. These warrants were fair valued using the Black-Sholes method with an assumption of an average volatility rate of 253%. The relative fair value was recognized as debt discount

F-19

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 13 – Warrants (Continued)

The following is a summary of the status of the Company’s stock warrants as of December 31, 2018 and changes during the period ended on that date:

	Number of Warrants		Weighted-Average Exercise Price		Weighted-Average Remaining Life (Years)
Outstanding at January 1, 2017		—	$	0.00		—
Granted		875,000	$	0.20		4.21
Exercised		—	$	0.00		—
Cancelled		—	$	0.00		—
Outstanding at March 31, 2018		875,000	$	0.20		4.21
Exercisable at March 31, 2018		875,000	$	0.20		4.21
Granted		250,000	$	0.20		4.73
Exercised		—	$	0.00		—
Cancelled		—	$	0.00		—
Forfeited		—	$	0.00		—
Outstanding at September 30, 2018		1,125,000	$	0.20		4.32
Exercisable at September 30, 2018		1,125,000	$	0.20		4.32
Granted		50,000	$	0.20		4.79
Exercised		—	$	0.00		—
Outstanding at December 31, 2018		1,175,000	$	0.20		4.34

Note 14 – Related Party Transactions

In December 2014, the Company entered into an agreement with Jim Walesa and Cibolo Creek Partners to fund $300,000 towards the Yowlumne #2-26 recompletion. In this agreement Mr. Walesa and Cibolo Creek will receive 75% of the net revenue after expenses, until they have received $300,000 in payment. Upon full repayment, Mr. Walesa and Cibolo Creek will receive a 3% royalty on the well. Mr. Walesa is currently on the Board of Directors of Citadel and a member of Cibolo Creek Partners.

During the year ended December 31, 2018 and December 31, 2017, Jim Walesa and Cibolo Creek Partners invested a total of $0 and $630,000 into the Company’s Series A Preferred Shares. During 2017, the Company has issued Jim Walesa and Cibolo Creek Partners a total of 2,413,867 shares in common stock.

During the year ended December 31, 2018 and December 31, 2017, the Company made the following purchases in the amount of $125,217 and $71,328, respectively, from an entity considered a related party for oil field equipment and services from Grey Energy. Grey Energy is owned by James Borgna, who is a member of our Board of Directors.

F-20

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 15 – Subsequent Events

On April 15^th 2019, the Company entered into an extension agreement with its Senior Secured Lender. As of March 31, 2018, the entire principal and interest on its Senior Secured Credit Facility was due and the Company was in default for non-payment. The Lender has granted the Company an extension to allow more time to refinance. There is no certainty that the Company will be able to refinance its debt, which could result in the Lender foreclosing on the Kern Bluff Oil Field or pursuing a sale of the assets to meet the Company’s obligations.

Note 16 - Supplemental Information about Oil & Natural Gas Producing Activities (Unaudited)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized Costs

	December 31,
	2018			2017
Oil and natural gas properties:	(in thousands)
Proved properties	$	4,513		$	3,513
Unproved properties		1,172			1,170
Facilities		2,415			2,200
Total oil and natural gas properties		8,100			6,883
Less oil property impairment		(562	)		(562	)
Less accumulated depreciation, depletion and amortization		(668	)		(133	)
Net oil and natural gas properties capitalized	$	6,870		$	6,188

Costs Incurred for Oil and Natural Gas Producing Activities

	Year Ended December 31,
	2018		2017		2016
Acquisition costs:	(in thousands)
Proved properties	$	—	$	—	$	—
Unproved properties		—		—		—
Development costs		2,211		344		2,171
Total	$	2,211	$	344	$	2,171

F-21

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 - Supplemental Information about Oil & Natural Gas Producing Activities (Unaudited)(Continued)

Reserve Quantity Information

The following information represents estimates of the Company’s proved reserves as of December 31, 2018, which have been prepared and presented under SEC rules. These rules require SEC reporting companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2018 was based on an unweighted average 12-month average WTI posted price per Bbl for oil as set forth in the following table:

	Year Ended December 31,
	2018		2017		2016
Oil (per Bbl)	$	65.01	$	45.94	$	45.53

Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement has limited, and may continue to limit, the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves within the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more.

The Company’s proved oil reserves are located in the United States in the San Joaquin Valley of California. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.

Oil reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates.

Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

F-22

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 - Supplemental Information about Oil & Natural Gas Producing Activities (Unaudited)(Continued)

The following table provides a roll forward of the total proved reserves for the years ended December 31, 2018, 2017, and 2016, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:   

	Year Ended December 31, 2018
	Crude Oil			Natural Gas
	(Bbls)			(Mcf)		Boe
	(in thousands)
Proved Developed and Undeveloped Reserves:
Beginning of the year		1,234			—		1,234
Extensions and discoveries		—			—		—
Revisions of previous estimates		55			—		55
Purchases of reserves in place					—
Divestures of reserves in place		—			—		—
Production		(17	)		—		(17	)
End of the year		1,272			—		1,272
Proved Developed Reserves:
Beginning of the year		282			—		282
End of the year		254			—		254
Proved Undeveloped Reserves:
Beginning of the year		952			—		952
End of the year		1,018			—		1,018

F-23

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 - Supplemental Information about Oil & Natural Gas Producing Activities (Unaudited)(Continued)

	Year Ended December 31, 2017
	Crude Oil			Natural Gas
	(Bbls)			(Mcf)		Boe
	(in thousands)
Proved Developed and Undeveloped Reserves:
Beginning of the year		1,160			—		1,160
Extensions and discoveries		—			—		—
Revisions of previous estimates		78			—		78
Purchases of reserves in place					—
Divestures of reserves in place		—			—		—
Production		(4	)		—		(4	)
End of the year		1,234			—		1,234
Proved Developed Reserves:
Beginning of the year		240			—		240
End of the year		282			—		282
Proved Undeveloped Reserves:
Beginning of the year		920			—		920
End of the year		952			—		952

F-24

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 - Supplemental Information about Oil & Natural Gas Producing Activities (Unaudited)(Continued)

	Year Ended December 31, 2016
	Crude Oil			Natural Gas
	(Bbls)			(Mcf)		Boe
	(in thousands)
Proved Developed and Undeveloped Reserves:
Beginning of the year		1,414			—		1,414
Extensions and discoveries		—			—		—
Revisions of previous estimates		(251	)		—		(251	)
Purchases of reserves in place					—
Divestures of reserves in place		—			—		—
Production		(3	)		—		(3	)
End of the year		1,160			—		1,160
Proved Developed Reserves:
Beginning of the year		358			—		358
End of the year		240			—		240
Proved Undeveloped Reserves:
Beginning of the year		1,056			—		1,056
End of the year		920			—		920

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

F-25

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 - Supplemental Information about Oil & Natural Gas Producing Activities (Unaudited)(Continued)

The estimates of future cash flows and future production and development costs as of December 31, 2018, 2017, and 2016 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows:

	December 31,
	2018			2017			2016
	(in thousands)
Future cash inflows	$	82,708		$	56,674		$	41,220
Future development costs		(9,575	)		(9,350	)		(8,785	)
Future production costs		(36,289	)		(29,232	)		(25,567	)
Future income tax expenses		(5,476	)		(1,521	)		(860	)
Future net cash flows		31,368			16,571			6,008
10% discount to reflect timing of cash flows		(14,033	)		(6,871	)		(2,927	)
Standardized measure of discounted future net cash flows	$	17,335		$	3,081		$	7,107

In the foregoing determination of future cash inflows, sales prices used for oil and natural gas for December 31, 2018, 2017, and 2016, were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory income tax rates to the estimated future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax bases of the properties involved. The future income tax expenses give effect to income tax deductions, credits, NOL’s and allowances relating to the proved oil and gas reserves. All cash flow amounts, including income taxes, are discounted at 10%.

F-26

CITADEL EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 - Supplemental Information about Oil & Natural Gas Producing Activities (Unaudited)(Continued)

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: 

	Year Ended December 31,
	2018			2017			2016
	(in thousands)
Standardized measure of discounted future net cash flows at the beginning of the year	$	9,700		$	3,081		$	7,107
Sales of oil and natural gas, net of production costs		(271	)		(66	)		(5	)
Purchase of minerals in place		—			—			—
Divestiture of minerals in place		—			—			—
Extensions and discoveries, net of future development costs		—			—			—
Previously estimated development costs incurred during the period		1,559			334			—
Net changes in prices and production costs		8,839			4,826			8,927
Changes in estimated future development costs		(121	)		(324	)		4,356
Revisions of previous quantity estimates		1,329			(1,896	)		(21,886)
Accretion of discount		970			267			420
Net change in income taxes		(2,122	)		314			2,114
Net changes in timing of production and other		(2,548	)		—			2,048
Standardized measure of discounted future net cash flows at the end of the year	$	17,335		$	9,700		$	3,081

F-27

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Armen Nahabedian, certify that:

1. I have reviewed this Annual Report on Form 10-K of Citadel Exploration, Inc. (the “Company”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented ire this report;

4. The Company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the Company’s internal control over financial reporting that occurred during the Company’s most recent fiscal quarter (the Company’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting; and

5. The Company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Company’s auditors and the audit committee of the Company’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal control over financial reporting.

Date: April 16, 2019

/s/Armen Nahabedian

Armen Nahabedian

Chief Executive Officer and

Principal Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Philip J. McPherson , certify that:

1. I have reviewed this Annual Report on Form 10-K of Citadel Exploration, Inc. (the “Company”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented ire this report;

4. The Company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the Company’s internal control over financial reporting that occurred during the Company’s most recent fiscal quarter (the Company’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting; and

5. The Company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Company’s auditors and the audit committee of the Company’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal control over financial reporting.

Date: April 16, 2019

 /s/Philip J. McPherson 

Philip J. McPherson

Chief Financial Officer and

Principal Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Citadel Exploration, Inc. (the “Company”) on Form 10-K for the period ended December 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Armen Nahabedian, Chief Executive Officer and Principal Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/Armen Nahabedian

Armen Nahabedian

Chief Executive Officer

Principal Executive Office

April 16, 2019

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Citadel Exploration, Inc. (the “Company”) on Form 10-K for the period ended December 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Philip J. McPherson, Chief Financial Officer and Principal Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

3. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

4. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

 /s/Philip J. McPherson 

Philip J. McPherson

Chief Financial Officer and

Principal Financial Officer

April 16, 2019

EX-99.3

ESTIMATED RESERVES

AND

FUTURE NET INCOME

AS OF

DECEMBER 31, 2018

ATTRIBUTABLE TO CERTAIN

MINERAL AND LEASEHOLD INTERESTS OF

CITADEL EXPLORATION, INC.

PREPARED ACCORDING TO

U.S. SECURITIES AND EXCHANGE COMMISSION REGULATIONS

MARCH 2019

 

MHA Petroleum Consultants

4700 Stockdale Highway, Suite 110

Bakersfield, CA 93309

730 17^th Street, Suite 410

Denver, CO 80202

-1-

March 18, 2019

Citadel Exploration, Inc.

Attention: Mr. Phil McPherson, CFO

417 31^st Street, Unit A

Newport Beach, California 92663

Subject: Estimated Proved Reserves and Future Net Income as of December 31, 2018

Dear Mr. McPherson:

MHA Petroleum Consultants, LLC (MHA) prepared an estimate of the proved oil reserves, production and future net income as of December 31, 2018 attributable to certain leasehold interests of Citadel Exploration, Inc. (Citadel) located in the Kern Bluff oil field, Township 29 South, Range 29 East, MDB&M, Kern County, California. A map of the field is shown by FIGURE 1. The primary purpose of our evaluation report is to provide estimates of reserves information in support of Citadel’s year-end reserves reporting requirements under U.S. Securities Regulation S-K and for other internal business and financial needs of Citadel.

The estimated net proved reserves and future net income are shown below.

Estimated Proved Reserves as of December 31, 2018 Consolidated Economic Summary – Before Income Tax (BIT) SEC Parameters
Reserves Category	Net Reserves		Income Data (Before Taxes)
	Crude Oil	Natural Gas	Future Net Revenue	Net Operating Expense1	Net Capital Expense	Undisc. Net Cash Flow	Discounted Net Cash Flow @ 10%
	MBbls	MMscf	M$	M$	M$	M$	M$
Proved Dev Producing	205.8	0.0	13,383.1	7,048.3	1,375.0	4,577.9	3,547.5
Proved Dev       Non-Producing	48.3	0.0	3,138.2	1,399.7	420.0	1,228.9	790.7
Proved Undeveloped	1,018.1	0.0	66,186.9	25,481.3	7,780.0	31,037.1	15,428.4
Total Proved	1,272.2	0.0	82,708.2	33,929.3	9,575.0	36,843.9	19,766.6
MBbls = Thousand barrels; MMscf = Million standard cubic feet; M$ = Thousand US Dollars 1 Net operating expenses include severance and ad valorem taxes

4700 Stockdale Hwy., Suite 110, Bakersfield, CA 93309 ; Ph: 661-325-0038

730 17^TH Street, Suite 410, Denver, CO 80202; Ph: 303-277-0270 Fax: 303-277-0267, www.mhausa.com

-2-

This report has been prepared in accordance with our understanding of the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). The proved reserves included herein conform to the definitions as set forth in the SEC’s Regulations Part 210.4-10(a) and are referred to as the SEC Parameters Case (SEC Case). The SEC definitions as set forth in the SEC’s Regulations of Part 210.4-10(a) are presented in APPENDIX A.

The future net revenue is based on net oil volume sold multiplied by anticipated price under existing economic conditions. Expenses include assessment and ad valorem taxes, and the normal cost of operating the wells. The SEC Case assumes constant oil price and constant (un-escalated) operating costs and expenses.

Certification

Results of this report are certified as independent, reasonable assessments of the oil and natural gas remaining to be produced as of December 31, 2018. MHA and its employees do not have any interest in these properties. MHA’s compensation for this report is not contingent on the estimate of reserves or future income attributable to the properties. This report was completed at the request of Citadel and was prepared for the exclusive use and sole benefit of Citadel. We reviewed Citadel’s Kern Bluff field reserves only in connection with the preparation of this report.

The estimated reserves and valuations presented in this report are based on reservoir engineering work performed by MHA. Citadel furnished MHA all of the accounts, records, and data required for this evaluation. MHA staff did conduct a site inspection of the properties presented in this report. The ownership interests and other factual data provided to MHA by Citadel were accepted without independent verification.

Reserves Analysis

The reserves in this report are estimated using guidelines endorsed by the Society of Petroleum Engineers (SPE) and the Society of Petroleum Evaluation Engineers (SPEE) and in our opinion, the reserve estimates conform to the SEC regulations and requirements.

Oil and gas reserves, as considered in this report, are classified as proved reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in the future years from the known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made).

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods (no major capital investment required). Proved developed reserves may be subcategorized as producing or non-producing. Proved developed producing reserves (PDP) are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

4700 Stockdale Hwy., Suite 110, Bakersfield, CA 93309 ; Ph: 661-325-0038

730 17^TH Street, Suite 410, Denver, CO 80202; Ph: 303-277-0270 Fax: 303-277-0267, www.mhausa.com

-3-

Reserves subcategorized as proved developed non-producing (PDNP) include shut-in and behind-pipe reserves (PDBP). Shut-in reserves are expected to be recovered from completion intervals which are open at the time of the estimate but which have not started producing, or wells not capable of production for mechanical reasons or waiting on stimulation treatments. Behind-pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production. The PDNP reserves in this report are assigned to inactive wells which are proposed to be returned-to-production (RTP).

Proved undeveloped (PUD) oil and gas reserves are reserves expected to be recovered from new wells on undrilled acreage, from deepening existing wells to a different reservoir, or from existing wells where a relatively major expenditure is required for new equipment and/or recompletion. In this report, proved undeveloped reserves are assigned to infill drilling locations directly offsetting oil-productive wells. Undrilled locations are classified as having undeveloped reserves if a development plan has been adopted indicating that they are scheduled to be drilled within five years.

Probable and Possible reserves are not evaluated or provided in this report.

Reserves Estimates

The PDP production (reserves) forecast is based on historical production data provided by Citadel and/or obtained from public records through the last production month available (December 2018) at the time of this report. The lease production is evaluated using a decline curve analysis technique to determine the forecast of future oil production. The PDNP reserves are assigned to wells which Citadel proposes to RTP through a workover and/or re-entry of an existing shut-in or idle wellbore.

Historical well production data were analyzed for the Citadel leases to develop type curves of forecasted oil production for the RTP wells and for new wells. The PUD reserves are assigned to infill oil wells proposed to be drilled on the Needham-Bloemer, Titus and Wells-McGregor leases. There are no gas sales or gas reserves for the existing or planned wells at this time of this report. All associated natural gas production is used on lease.

The historical field production and future forecasts for the PDP, PDNP and PUD reserves categories are shown by FIGURES 2 through 4, respectively. FIGURE 5 presents the stacked plot of the future oil production forecast for the Proved oil reserves. The individual production plots and forecasts by reserves case are included in APPENDIX B.

Discounted Cash Flow Evaluation

Reserves in this report are determined as of December 31, 2018 to the defined economic limit based on a discounted cash flow analysis using the prices, interests, and operating cost inputs provided by Citadel. The economic summaries by reserves category are given in TABLES 1 through 4. One-line summaries of the individual reserves cases are presented in TABLE 5. The cash flow analyses of the individual reserves cases are presented in APPENDIX C.

4700 Stockdale Hwy., Suite 110, Bakersfield, CA 93309 ; Ph: 661-325-0038

730 17^TH Street, Suite 410, Denver, CO 80202; Ph: 303-277-0270 Fax: 303-277-0267, www.mhausa.com

-4-

Crude Oil Prices

The crude oil price parameter for the SEC Case is defined by SEC as the unweighted arithmetic average of the first-of-the-month prices for the 12-month period prior to the “as of” date. For this report the 12-month period is January to December 2018.

For oil volumes, MHA determined the SEC pricing based on the average West Texas Intermediate (WTI) Spot Price adjusted for quality, local market differentials, and transportation (APPENDIX D). The price adjustment depends on the sales price differentials between the WTI Spot Price and the Kern Bluff realized prices. The quality of the Kern Bluff crude oil is 15 degree API gravity.

Hydrocarbon Product	Price Benchmark	12-mo Average WTI Spot Price	Average Price Differential	Adjusted              Oil Price
Crude Oil	NYMEX WTI Cushing  Spot Price	$65.56/barrel	-$0.55/barrel	$65.01/barrel

Using this methodology, the SEC crude oil price is $65.01/barrel, which is held constant for the life of the reserves.

Costs

Operating costs used in this report are based on operating expense records of Citadel. Calendar Year 2018 lease operating expense (OPEX) data were provided by Citadel for the Kern Bluff field operations (APPENDIX D). MHA analyzed these costs and determined fixed and variable cost projections based on the active wells producing from the Santa Margarita and Transition zones. The lease has been under continuous cyclic steam stimulation (CSS) of existing and new wells since January 2018 so there was a track record of steaming costs available for this report.

The projected OPEX include only those costs directly applicable to the leases and wells. Headquarters general and administrative overhead expenses are not included. Per SEC guidelines, costs and expenses are un-escalated over the life of the reserves.

Development Plan

Capital costs used in this report were provided by Citadel and are based on authorizations for expenditure and actual costs from past drilling activity. Based on a review of Citadel’s future development plans and records provided to MHA, the estimated capital costs are regarded as reasonable for the Kern Bluff properties.

MHA assigned PUD reserves to new development wells identified in Citadel’s adopted development plan up to a total of 30 locations. The Citadel UIC Permit from the California Division of Oil, Gas and Geothermal Resources (DOGGR) provides for CSS of up to 55 wells at Kern Bluff. Well recompletion, new well construction, and facility capital investments are estimated to be a total of 8.2 million dollars over a five-year period (APPENDIX E).

4700 Stockdale Hwy., Suite 110, Bakersfield, CA 93309 ; Ph: 661-325-0038

730 17^TH Street, Suite 410, Denver, CO 80202; Ph: 303-277-0270 Fax: 303-277-0267, www.mhausa.com

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The development plan used in this reserves analysis is summarized below:

PDNP (RTP wells):

· Three idle wells on the Needham-Bloemer lease will be re-worked and returned to production in 2019.

PUD (Facilities)

· An upgrade to the steam distribution system is planned for 2019. Additional investments in steam generation capacity and oil production treatment capability are anticipated during the next five years.

PUD (New wells):

· A total of 30 locations are identified as infill wells to be constructed during the next five years. The new wells are located on undrilled acreage directly offsetting existing production on the Needham-Bloemer, Wells-McGregor and Titus leases.

· Drilling, completion and equipping costs (per Citadel’s prepared Authorization for Expenditure) are estimated at 210 M$ for a vertical well (250 M$ deviated well).

All capital investments are un-escalated. The capital estimates also include an Asset Retirement Obligation for the abandonment costs (net of salvage) to plug and abandon the Citadel Kern Bluff wells at the end of the reserves life.

The net income values presented in the economic summary tables include a deduction for estimated local ad valorem and state assessment taxes as follows:

Assessment and Ad Valorem Taxation Rates Used in Economic Analyses
State	Assessment	Ad Valorem
California - Oil	$0.5548 per barrel	2.0%

Report Qualifications

The reserves and valuations indicated in this report are estimates only and should not be considered as exact quantities. They represent our best judgments, after having utilized generally accepted engineering, geologic, and economic procedures. Moreover, the net revenues indicated herein should not be construed as fair market values.

It is MHA’s opinion that the estimated proved reserves and other reserve information as specified in this report are reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles, as set forth in the SEC regulations. Notwithstanding the aforementioned opinion, MHA makes no warranties concerning the data and interpretations of such data. In no event shall MHA be liable for any special or consequential damages arising from Citadel’s use of MHA’s interpretation, reports, or services produced as a result of its work for Citadel.

4700 Stockdale Hwy., Suite 110, Bakersfield, CA 93309 ; Ph: 661-325-0038

730 17^TH Street, Suite 410, Denver, CO 80202; Ph: 303-277-0270 Fax: 303-277-0267, www.mhausa.com

-6-

All the information furnished by Citadel was accepted without any attempt at independent verification. MHA carried out such tests as we considered necessary to check the veracity of the oil production data, operating costs, and engineering procedures. In evaluating the information at our disposal, we excluded from our consideration all legal and accounting matters, which may be controlling.

Statement of Risk

The accuracy of reserves and economic evaluations is always subject to uncertainty. The magnitude of this uncertainty is generally proportional to the quantity and quality of data available for analysis. As a well matures and new information becomes available, revisions may be required which may either increase or decrease the previous reserve assignments. Sometimes these revisions may result not only in a significant change to the reserves and value assigned to a property, but also may impact the total company reserve and economic status.

The reserves and forecasts contained in this report were based upon a technical analysis of the available data using accepted engineering principles. However, they must be accepted with the understanding that further information and future reservoir performance subsequent to the date of the estimate may justify their revision.

Consent

We hereby consent to the references to our firm, in the context in which they appear, and to our reserve estimates as of December 31, 2018, included in the Annual Report on Form 10-K of Citadel Exploration Inc. for the fiscal year ended December 31, 2018, as well as in the notes to the financial statements included therein. We also hereby consent to the incorporation by reference of the references to our firm, in the context in which they appear, and to the reserve estimates as of December 31, 2018, in our report dated March 18, 2019 for the Citadel Annual Report on Form 10-K.

Thank you for the opportunity to prepare this report. All the basic petroleum engineering calculations and supporting data remain in MHA files for future reference by Citadel or its representatives. Please feel free to contact us with any questions or to request further information.

Very truly yours,

MHA PETROLEUM CONSULTANTS, LLC

Alan A. Burzlaff, P.E.

Managing Partner

Professional Petroleum Engineer

Licensed by the California Board for

Professional Engineers and Land Surveyors

License No. P1386

Date Signed: March 18, 2019

4700 Stockdale Hwy., Suite 110, Bakersfield, CA 93309 ; Ph: 661-325-0038

730 17^TH Street, Suite 410, Denver, CO 80202; Ph: 303-277-0270 Fax: 303-277-0267, www.mhausa.com

-7-

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Apr. 16, 2019	Dec. 29, 2018
Document And Entity Information
Entity Registrant Name	Citadel Exploration, Inc.
Entity Central Index Key	0001482075
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 6,750,000
Entity Common Stock, Shares Outstanding		48,956,147
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2018
Entity Shell Company	false
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Ex Transition Period	false

XML

CONSOLIDATED BALANCE SHEETS - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash	$ 86,441	$ 772,103
Other receivable	135,824	16,540
Prepaid expenses	32,633	29,280
Product inventory		20,107
Total current assets	254,898	838,030
Deposits	35,100	10,100
Restricted cash	200,000	200,000
Oil and gas properties, successful efforts basis
Proved, net	5,685,535	5,018,086
Unproved	1,172,034	1,170,000
Equipment, net	67,326	82,969
Total assets	7,414,893	7,319,185
Current liabilities:
Accounts payable and accrued payables	2,657,590	2,220,938
Accrued interest payable	390,224	459,416
Drilling obligation, net of discount of $63,000 and $126,000 as of September 30, 2018 and December 31, 2017 respectively	676,060	700,000
Notes payable, net	2,353,003	579,951
Related party production payment liability	300,000	300,000
Total current liabilities	6,376,877	4,260,305
Asset retirement obligation	250,358	224,380
Total liabilities	6,627,235	4,484,685
Stockholders' equity:
Common stock, $0.001 par value, 300,000,000 shares authorized, 45,000,000 and 44,449,742 shares issued and outstanding as of December 31, 2018 and December 31, 2017 respectively	45,000	44,450
Series A Preferred stock, $20.00 par value, 500,000 shares authorized, 395,615 and 394,365 shares issued and outstanding as of December 31, 2018 and December 31, 2017 respectively	7,912,300	7,887,300
Additional paid-in capital	6,150,871	5,691,239
Accumulated deficit	(13,320,513)	(10,788,489)
Total stockholders' equity	787,658	2,834,500
Total liabilities and stockholders' equity	$ 7,414,893	$ 7,319,185

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	100,000,000	100,000,000
Common stock, issued	45,000,000	44,449,742
Common stock, outstanding	45,000,000	44,449,742
Preferred stock, par value	$ 20.00	$ 20.00
Preferred stock, shares authorized	500,000	500,000
Preferred stock, issued	395,615	394,365
Preferred stock, outstanding	395,615	394,365

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income Statement [Abstract]
Revenue	$ 1,066,314	$ 166,355
Operating expenses:
Lease operating expense	822,674	232,081
General and administrative	298,889	246,764
Depreciation, depletion and amortization	571,301	134,619
Professional fees	277,025	201,763
Executive compensation	1,216,529	651,760
Dry hole, abandonment, impairment, and exploration		427,353
Total operating expenses	3,186,418	1,894,340
Other expenses:
Gain on settlement of prior year preferred stock liability		50,122
Gain - other		4,000
Interest expense	(411,920)	(79,481)
Total other expenses	(411,920)	(25,359)
Loss before provision for income taxes	(2,532,024)	(1,753,344)
Provision for income taxes
Net loss	(2,532,024)	(1,753,344)
Series A preferred stock dividends	(791,230)	(620,347)
Deemed dividend, ORRI issued with preferred stock		(442,136)
Net loss available to common stockholders	$ (3,323,254)	$ (2,815,827)
Weighted average number of common shares - outstanding - basic and diluted	44,726,467	40,891,604
Net loss per share - basic and diluted	$ (0.07)	$ (0.07)

XML

CONSOLIDATED STATEMENTS OF STOCKHOLDER EQUITY - USD ($)	Common Stock	Preferred Stock	Additional Paid-In Capital	Accumulated Deficit	Total
Beginning Balance at Dec. 31, 2016	$ 39,314		$ 5,790,060	$ (9,035,145)	$ (3,205,771)
Beginning Balance, Shares at Dec. 31, 2016	39,314,004
Shares issued for cash		$ 1,175,000			1,175,000
Shares issued for cash, shares		58,750
Shares issued to settle bonus payable
Preferred shares issued for settlement of notes payable		$ 105,000			105,000
Preferred shares issued for settlement of notes payable, shares		5,250
Preferred shares issued to settle preferred stock payable		$ 6,607,300			6,607,300
Preferred shares issued to settle preferred stock payable, shares		330,365
Common shares issued for special preferred stock dividend	$ 3,102		(3,102)
Common shares issued for special preferred stock dividend, shares	3,101,736
Common shares issued to settle accrued interest on preferred stock	$ 20,334		242,046		244,080
Common shares issued to settle accrued interest on preferred stock, shares	2,034,002
Contribution from related party on preferred stock interest			104,371		104,371
Deemed dividend, overriding royalty interest issued with preferred stock			(442,136)		(442,136)
Warrants on senior secured facility
Net loss				(1,753,344)	(1,753,344)
Ending Balance at Dec. 31, 2017	$ 44,450	$ 7,887,300	5,691,239	(10,788,489)	2,834,500
Ending Balance, Shares at Dec. 31, 2017	44,449,742	394,365
Common shares issued for services rendered	$ 450		89,602		90,052
Common shares issued for services rendered, Shares	450,262
Shares issued for cash		$ 25,000			25,000
Shares issued for cash, shares		1,250
Shares issued to settle bonus payable	$ 100		19,900		20,000
Shares issued to settle bonus payable, Shares	100,000
Preferred shares issued for settlement of notes payable
Preferred shares issued to settle preferred stock payable
Common shares issued to settle accrued interest on preferred stock
Contribution from related party on preferred stock interest
Deemed dividend, overriding royalty interest issued with preferred stock
Warrants on senior secured facility			225,170		225,170
Stock option expense, related to stock-based compensation issued with executive compensation			124,960		124,960
Net loss				(2,532,024)	(2,532,024)
Ending Balance at Dec. 31, 2018	$ 45,000	$ 7,912,300	$ 6,150,871	$ (13,320,513)	$ 787,658
Ending Balance, Shares at Dec. 31, 2018	45,000,004	395,615

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
OPERATING ACTIVITIES
Net loss	$ (2,532,024)	$ (1,753,344)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, amortization and accretion	571,301	134,619
Amortization of debt discount	248,035
Abandonment and impairment		427,353
Stock based compensation expense	215,011
Gain on settlement of prior year preferred stock liability		(50,122)
Overriding royalty interest granted as compensation	430,092
Changes in operating assets and liabilities:
Decrease (increase) in inventory		(191)
Decrease (increase) in other receivable	(119,284)	(9,398)
Decrease (increase) in prepaid expenses	58,884	57,076
Increase in deposits	(25,000)	(200)
Decrease in restricted cash		45,000
Increase in accrued interest payable	160,196	170,640
Increase in accounts payable and accrued	556,652	636,680
Net cash used in operating activities	(436,135)	(341,887)
INVESTING ACTIVITIES
Exploration and development of oil and gas properties	(1,602,400)	(981,622)
Purchase of equipment	(6,749)	(6,214)
Net cash used in investing activities	(1,609,149)	(987,876)
FINANCING ACTIVITIES
Proceeds from sale of preferred stock, net of costs	25,000	1,175,000
Proceeds from loans payable	1,520,612	605,000
Repayments to drilling liability	(107,940)	700,000
Repayments of notes payable	(78,050)	(566,927)
Net cash provided by financing activities	1,359,622	1,913,073
Net increase in cash and restricted cash	(685,662)	583,310
Cash and restricted cash at beginning of year	772,103	188,793
Cash and restricted cash at end of the period	286,441	772,103
SUPPLEMENTAL INFORMATION:
Income taxes paid		2,300
Reclass of inventory to O&G properties	20,107
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Preferred shares issued to settle preferred stock payable		6,607,300
Preferred shares issued to settle note payable		105,000
Debt Discount from drilling liability		126,000
Common Stock issued for preferred stock dividend		3,102
Financing of vehicles		67,078
Financing of insurance premium		52,920
Common shares issued to settle accrued interest on preferred stock		244,080
Deemed dividend, ORRI issued with preferred stock		442,136
Gain of settlement of prior year preferred stock liability recorded in APIC		104,371
Debt discount for warrants issued on loans	225,170
Accrued interest payable rolled over to senior loan facility	229,388
Asset retirement obligation	12,128
Insurance premium financing	62,237
Shares issued to settle bonus payable	20,000
Non-cash addition of senior loan facility for payment of San Benito litigation	$ 100,000

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Note 1 – Summary of Significant Accounting Policies

Organization

Citadel Exploration, Inc. ("Citadel Inc") was incorporated on December 17, 2009 in the State of Nevada originally under the name Subprime Advantage, Inc.  On March 2, 2011, the Company changed its name from Subprime Advantage, Inc. to Citadel Exploration, Inc.

On May 3, 2011, Citadel Inc completed the acquisition of 100% interest in Citadel Exploration, LLC, a California limited liability company, ("Citadel LLC") pursuant to a Membership Purchase Agreement (the "MPA"). Under the MPA, Citadel Inc issued 14,000,000 shares of the its common stock an individual in exchange for a 100% interest in Citadel LLC. Additionally under the MPA, the former officers and directors of Citadel Inc agreed to cancel 7,696,000 shares of its common stock. For accounting purposes, the acquisition of the Citadel LLC by Citadel Inc has been accounted for as a recapitalization, similar to a reverse acquisition except no goodwill is recorded, whereby the private company, Citadel LLC, in substance acquired a non-operational public company (Citadel Inc) with nominal assets and liabilities for the purpose of becoming a public company. Accordingly, Citadel LLC are considered the acquirer for accounting purposes and thus, the historical financials are primarily that of Citadel LLC. As a result of this transaction, Citadel Inc changed its business direction and is now involved in the acquisition and development of oil and gas resources in California. Citadel LLC was incorporated on November 6, 2006 (Date of Inception) and accordingly, the accompanying consolidated financial statements are from the Date of Inception of Citadel LLC through ending reporting periods reflected.

The consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America applicable to exploration stage enterprises, and are expressed in U.S. dollars. The Company’s fiscal year end is December 31.

Principles of consolidation

For the years ended December 31, 2018 and 2017, the consolidated financial statements include the accounts of Citadel Exploration, Inc. and Citadel Exploration, LLC.   All significant intercompany balances and transactions have been eliminated.   Citadel Exploration, Inc. and Citadel Exploration, LLC will be collectively referred herein to as the “Company”.

Nature of operations

Currently, the Company is focused on the acquisition and development of oil and gas resources in California.

Assumptions, Judgments and Estimates

In the course of preparing the consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.

The more significant areas requiring the use of assumptions, judgments, and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) income taxes; (7) valuation of derivative instruments; and (8) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Fair value of financial instruments

Fair value estimates discussed herein are based upon certain market assumptions and pertinent information available to management as of December 31, 2018 and 2017. See Footnote No. 13, “Fair Value of Financial Instruments,” for further information. The respective carrying value of certain on-balance-sheet financial instruments approximated their fair values. These financial instruments include cash, prepaid expenses and accounts payable. Fair values were assumed to approximate carrying values for payables because they are short term in nature and their carrying amounts approximate fair values or they are payable on demand.

Level 1: The preferred inputs to valuation efforts are “quoted prices in active markets for identical assets or liabilities,” with the caveat that the reporting entity must have access to that market. Information at this level is based on direct observations of transactions involving the same assets and liabilities, not assumptions, and thus offers superior reliability. However, relatively few items, especially physical assets, actually trade in active markets.

Level 2: FASB acknowledged that active markets for identical assets and liabilities are relatively uncommon and, even when they do exist, they may be too thin to provide reliable information. To deal with this shortage of direct data, the board provided a second level of inputs that can be applied in three situations.

Level 3: If inputs from levels 1 and 2 are not available, FASB acknowledges that fair value measures of many assets and liabilities are less precise. The board describes Level 3 inputs as “unobservable,” and limits their use by saying they “shall be used to measure fair value to the extent that observable inputs are not available.” This category allows “for situations in which there is little, if any, market activity for the asset or liability at the measurement date”. Earlier in the standard, FASB explains that “observable inputs” are gathered from sources other than the reporting company and that they are expected to reflect assumptions made by market participants.

Inventories

Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence. Finished goods include oil and natural gas products, which are valued at the lower of cost or market.

Oil and Natural Gas Properties

The Company accounts for our oil and gas exploration and development costs using the successful efforts method. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found.

If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

The costs of development wells are capitalized whether productive or nonproductive. We review our oil and natural gas producing properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if a field contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 inputs which are based upon estimates, the most significant of which is the estimate of net proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates.

Property, Plant and Equipment

The Company records all property and equipment at cost less accumulated depreciation.  Improvements are capitalized while repairs and maintenance costs are expensed as incurred. Depreciation is calculated on a straight-line basis over estimated useful lives ranging from 5 to 30 years for buildings and improvements and 3 to 10 years for machinery and equipment. Leasehold improvements include the cost of the Company’s internal development and construction department. The Company capitalizes the costs associated with the development of the Company’s website pursuant to ASC Topic 350.

Stock-based compensation

The Company records stock-based compensation in accordance with the guidance in ASC Topic 505 and 718 which requires the Company to recognize expenses related to the fair value of its employee stock option awards.  The Company recognizes the cost of all share-based awards on a graded vesting basis over the vesting period of the award. 

The Company accounts for equity instruments issued in exchange for the receipt of goods or services from other than employees in accordance with FASB ASC 505-50. Costs are measured at the estimated fair market value of the consideration received or the estimated fair value of the equity instruments issued, whichever is more reliably measurable. The value of equity instruments issued for consideration other than employee services is determined on the earliest of a performance commitment or completion of performance by the provider of goods or services as defined by FASB ASC 505-50.

Earnings per share

The Company follows ASC Topic 260 to account for the earnings per share. Basic earnings per common share (“EPS”) calculations are determined by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per common share calculations are determined by dividing net income by the weighted average number of common shares and dilutive common share equivalents outstanding. During periods when common stock equivalents, if any, are anti-dilutive they are not considered in the computation.

Cash and cash equivalents

The Company considers all highly liquid instruments with maturity of three months or less at the time of issuance to be cash equivalents.

Concentrations of credit risk

Financial instruments that subject the Company to credit risk could consist of cash balances maintained in excess of federal depository insurance limits. The Company maintains its cash and cash equivalent balances with high credit quality financial institutions. At times, cash and cash equivalent balances may be in excess of Federal Deposit Insurance Corporation limits. To date, the Company has not experienced any such losses.

Restricted cash

Restricted cash consisted of a blanket bond totaling $200,000. Bonds are required to meet financial bonding requirements in the state of California. The blanket bond, which will cover 50 wells, was purchased in August 2015 following the acquisition of the Kern Bluff Oil Field.

Debt discount

The Company records debt discount as a contra liability account and is presented net of the associated loan. The discount is amortized over the life on the loan using the straight-line method because the straight-line method approximates the effective interest method.

Revenue Recognition

 The new revenue standard (ASC606) requires more quantitative and qualitative disclosure that prior guidance. More specifically the following areas have been a concern for the SEC. As such Citadel will address each of these matters in the following bullet points.

As background, Citadel Exploration has one source of revenue, Phillips 66, the refiner that purchases our crude oil. Citadel receives a check from the purchaser Phillips 66 on the 20^th of the Month following said production. The revenue amount is net of transportation costs, currently $1.45 per barrel. The price received is based upon the purchaser contract which is the average of the posted price for heavy oil in California. For natural gas, there is no revenue as our field does not produce economic quantities of natural gas. For gathering and transportation sales, there are no sales or revenues. We own and operate all gathering equipment and infrastructure. Revenues from oil and gas sales are recognized when once we have received payment from the refiner.

• Performance Obligations: Phillips 66 has been our purchaser for the last two years and has never missed a payment. From a qualitative measure they could not perform any better.

• Variable Consideration: The price Citadel receives for its oil, is tracked daily by several services including Bloomberg.com, oilprice.com and on Chevron’s webpage. This price is wildly available and transparent. Citadel does not calculate, or control said price. From a quantitative standpoint, we do not have any control. From a qualitative standpoint, we compare what we are paid, versus what prices averaged for the quarter.

• Recognizing revenue: Citadel is sent an oil ticket summary on or around the 10^th of the month, depending on if the date is on a weekend. That summary provides a detailed summary of date and barrels sold and at what price. The revenue is recognized in the quarter that the oil is sold, as we are paid for the oil on the 20^th of the following month.

• Costs to obtain a contract: The only cost that Citadel incurs is a transportation cost. The actual contract has no costs. As an example, prior to Phillips 66 we sold to Plains All American (PAA). Our PAA contract charged us $1.95 for transportation. Through various contacts we were introduced to Phillips 66, and they quoted Citadel a transportation cost of $1.45. Both contracts were based on the exact same California heavy oil index for price, therefore the ability to save/realize an additional $0.50 per barrel was the motivation for the change. From a qualitative standpoint, Phillips 66 and PAA are both multibillion-dollar companies. Therefore, we did not see a difference in credit risk to getting paid.

• Gross versus net presentation: This does not apply as we are paid the gross value of our oil minus transportation costs. We do not accept a discount.

• Disaggregated revenue: This does not apply as we sell oil from one facility at one oil field and do not have multiple fields or multiple refiners.

In conclusion, Citadel’s business and hence revenue is pretty simple and straight forward. We sell one product, to one refiner, and we are paid once a month.

Asset Retirement Obligation

The Company's asset retirement obligations (AROs) relate to future costs associated with plugging and abandonment of oil wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred (typically when the asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability.

Revenue & Expense Recognition

The Company utilizes accrual basis of accounting when measuring financial position and operating results. The accrual basis recognizes revenues and expenses in the accounting period in which those transactions, events, or circumstances occur (goods or services are received) and become measurable.

The Company recognizes its expenses when the expenses are incurred, not necessarily when they are paid. Expenses are generally incurred when the company receives tangible goods or services are provided.

Lease operating expense

Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities.

Depreciation, Depletion and Amortization

The provision for DD&A-oil and natural gas production is calculated on a field-by-field basis using the unit-of-production method. Projected future production rates, the timing of future capital expenditures as well as changes in commodity prices, may significantly impact estimated reserve quantities. Depreciation, depletion and amortization —oil and natural gas production is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections. These estimates are subject to change as additional information and technologies become available. Accordingly, oil and natural gas quantities ultimately recovered and the timing of production may be substantially different than projected. Reduction in reserve estimates may result in increased depreciation, depletion and amortization oil and natural gas production, which in turn reduces net earnings. Changes in reserve estimates are applied on a prospective basis. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher costs fields.

Income taxes

The Company follows ASC Topic 740 for recording the provision for income taxes. Deferred tax assets and liabilities are computed based upon the difference between the consolidated financial statements and income tax basis of assets and liabilities using the enacted marginal tax rate applicable when the related asset or liability is expected to be realized or settled. Deferred income tax expenses or benefits are based on the changes in the asset or liability each period.

If available evidence suggests that it is more likely than not that some portion or all of the deferred tax assets will not be realized, a valuation allowance is required to reduce the deferred tax assets to the amount that is more likely than not to be realized. Future changes in such valuation allowance are included in the provision for deferred income taxes in the period of change.

Deferred income taxes may arise from temporary differences resulting from income and expense items reported for financial accounting and tax purposes in different periods. Deferred taxes are classified as current or non-current, depending on the classification of assets and liabilities to which they relate. Deferred taxes arising from temporary differences that are not related to an asset or liability are classified as current or non-current depending on the periods in which the temporary differences are expected to reverse. The net operating loss carryforward for the year ended December 31, 2018 is $11,534,488 and the deferred tax asset is $3,595,000. The Company maintains a full valuation allowance for the deferred tax asset of $3,595,000.

The Company applies a more-likely-than-not recognition threshold for all tax uncertainties. ASC Topic 740 only allows the recognition of those tax benefits that have a greater than fifty percent likelihood of being sustained upon examination by the taxing authorities. As of December 31, 2018 and 2017, the Company reviewed its tax positions and determined there were no outstanding, or retroactive tax positions with less than a 50% likelihood of being sustained upon examination by the taxing authorities, therefore this standard has not had a material effect on the Company.

The Company does not anticipate any significant changes to its total unrecognized tax benefits within the next 12 months. 

The Company classifies tax-related penalties and net interest as income tax expense. As of December 31, 2018 and 2017, no income tax expense has been recorded.

Long-lived Assets

In accordance with the Financial Accounting Standards Board ("FASB") Accounts Standard Codification (ASC) ASC 360-10, "Property, Plant and Equipment," the carrying value of intangible assets and other long-lived assets is reviewed on a regular basis for the existence of facts or circumstances that may suggest impairment. Proved oil properties are reviewed for impairment on a field-by-field basis, annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. The Company estimates the expected future cash flows of its oil properties and compares these undiscounted cash flows to the carrying amount of the oil properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil properties to fair value.

The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates commensurate with the risk associated with realizing the projected cash flows.

Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. The impairment assessment is affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time.

Leases

The Company had two types of leases. A capital lease for the financing of vehicles. An operational lease on its steam generator, in which the Company had previously purchased the generator and then sold the generator with an agreement to lease the equipment. Thus, this meets the definition of a sales lease-back arrangement. Since there was no gain or loss from the sale, there is no affect in the income statement.

Recent pronouncements

In May 2014, the FASB issued ASC updated No. 2014-09, Revenue from Contracts with Customers (Topic 606 (ASU 2014-09). Under the amendments in this update, recognition of revenue occurs when a customer obtains control of promised goods or services in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, the new standard requires that reporting companies disclose the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The amendments in this update are effective for fiscal years and interim periods within those years beginning after December 15, 2017 and supersedes any previous revenue recognition guidance. Implementation of Topic 606, which was adopted by the Company as of January 1, 2018, was done using the modified retrospective approach. Adoption of this new standard did not have an impact on the Company’s balance sheet, statement of operations, statement of stockholders’ equity or statement of cash flows.

In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash” (“ASU 2016-18”). The update is effective for years beginning December 15, 2017, including interim reporting periods within those fiscal years. Early adoption is permitted. These accounting pronouncements were adopted by the Company as of January 1, 2018. The purpose of Update 2016 -18 is to clarify guidance and presentation related to restricted cash in the Statements of Cash Flows. The amendment requires beginning-of-period and end-of- period total amounts shown on the Statements of Cash Flows to include cash and cash equivalents as well as restricted cash and restricted cash equivalents. Adoption of this new standard did not have a material impact on the Company’s financial statements.

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GOING CONCERN

12 Months Ended

Dec. 31, 2018

Notes to Financial Statements

GOING CONCERN

Note 2 – Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the recoverability of assets and the satisfaction of liabilities in the normal course of business. As noted above, the Company is in the exploration stage and, accordingly, has not yet generated significant revenues from operations. Since its inception, the Company has been engaged substantially in financing activities and developing its business plan and incurring startup costs and expenses. As a result, the Company incurred a net loss for year ended December 31, 2018 of $2,532,025. In addition, the Company’s exploration activities since inception have been financially sustained through debt and equity financing. These factors raise substantial doubt regarding the Company’s ability to continue as a going concern.  These financial statements do not include any adjustments to the recoverability and classification of recorded asset amounts and classification of liabilities that might be necessary should we be unable to continue as a going concern.

The ability of the Company to continue as a going concern is dependent upon its ability to raise additional capital from the sale of common stock and, ultimately, the achievement of significant operating revenues. These consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts, or amounts and classification of liabilities that might result from this uncertainty.

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RESTRICTED CASH

12 Months Ended

Dec. 31, 2018

Restricted Cash

RESTRICTED CASH

Note 3 – Restricted Cash

Restricted cash consists of one bond totaling $200,000 which is a blanket bond that will cover up to 50 wells. This bond was required in the normal course of business in the oil and gas industry. The bond totaling $200,000 was purchased in August 2015 following the acquisition of the Kern Bluff Oil Field. The detail breakdown of restricted cash and cash is depicted in the Consolidated Statement of Cash Flows as follows:

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

Note 4 – Commitments and Contingencies

Operating Leases

No operating leases for year ended December 31, 2018

Legal Proceedings

Various lawsuits, claims and other contingencies arise in the ordinary course of the Company’s business activities. While the ultimate outcome of the aforementioned contingencies are not determinable at this time, management believes that any liability or loss resulting therefrom will not materially affect the financial position, results of operations or cash flows of the Company.

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected areas. The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.

The Company is not aware of any environmental claims existing as of December 31, 2018. There can be no assurance, however, that the current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties.

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OIL AND GAS PROPERTIES, BUILDINGS AND EQUIPMENT

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

OIL AND GAS PROPERTIES, BUILDINGS AND EQUIPMENT

Note 5 – Oil and Gas Properties,   Buildings, and Equipment

Oil and natural gas properties consist of the following:

	2018			2017
Oil and Natural Gas:
Proved properties	$	4,121,940		$	3,468,306
Unproved properties		1,172,034			1,170,000
Facilities		2,231,561			2,244,716
		7,525, 535			6,883,022
Less oil property impairment					(562,030	)
Less accumulated depreciation, depletion, and amortization		(667,966	)		(132,906	)
	$	6,857, 569		$	6,188,086

During the year ended December 31, 2018, the Company spent $1,602,400 to continue to develop the Kern Bluff field and associated facilities. Also, during the year, the Company granted a 2% overriding royalty interest to management which was valued at $430,092.

As an annual process, Citadel reviewed the field to determine if asset impairment is required. If the carrying amount of the asset exceeds the sum of the undiscounted estimated future net cash flows, the Company will recognize impairment expense equal to the difference between the carrying value and the fair value of the asset, which is estimated to be the expected present value of discounted future net cash flows from proved reserves, utilizing a 10% rate of return. This process includes a projection of future oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. Citadel cannot predict the amount of impairment charges that may be recorded in the future. During the year ended December 31, 2017, the Company reduced the asset value by $427,353 due to focusing CAPEX at Kern Bluff and idling operations at Yowlumne. During the year ended December 31, 2018, the Company did not have any impairment of assets.

Kern Bluff Oil Field

The Kern Bluff Oil Field is comprised of approximately 1,100 acres. The field currently has 15 producing wells and an additional 20 idle well bores.

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INCOME TAXES

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

INCOME TAXES

Note 6 – Income Taxes

The (benefit) provision for income taxes from continuing operations consists of the following (in thousands):

	Year Ended December 31,
		2018		2017
Current:
Federal	$	—	$	—
State		4		2
		4		2
Deferred:
Federal		—		—
State		—		—
		—		—
Total	$	4	$	2

The components of the net deferred income tax liabilities consist of the following: 

		Year Ended December 31,
		2018			2017
Deferred income tax assets:
Equity and deferred compensation		255			239
Net operating loss		2,442			1,918
State net operating loss carry forward		1,020			808
Other, net		—			—
Total deferred tax assets		3,697			2,965
Valuation allowance		(3,211	)		(2,907	)
		486			58
Deferred income tax liabilities:
Depreciation and depletion		(486	)		(58	)
Net deferred income tax liabilities	$	—		$	—

As of the year ended December 31, 2018, the Company does not have any uncertain tax positions. As of December 31, 2018, we had approximately $11,534,488 in net operating loss carryforwards for each federal and state income tax purposes. The net operating loss carryforward will begin to expire in 20 years if left unused. In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management has concluded that there is no assurance that the company will have taxable income in the future; therefore 100% of the deferred income tax assets is not recognized.

On December 22, 2017, the U.S. enacted the Tax Cuts and Jobs Act (the “Act”) which made significant changes to the Internal Revenue Code of 1986, including lowering the maximum federal corporate income tax rate from 35 percent to 21 percent, repealing the corporate alternative minimum tax (AMT), and imposing limitations on the use of net operating losses arising in taxable years beginning after December 31, 2017. Although most of the provisions of the Act are not effective until tax years ending after December 31, 2017, the effects of new legislation are recognized upon enactment in accordance with GAAP. As a result, recognition of the tax effects of the Act is required in the consolidated financial statements for the fiscal year ended December 31, 2017. In accordance with this Act, the Company has calculated its deferred tax asset at December 31, 2017 using the newly enacted corporate tax rate of 21%.

We consider the scheduled reversal of deferred tax assets, the level of historical taxable income and tax planning strategies in making the assessment of the realizability of deferred tax assets. We have identified the U.S. federal and California as our "major" tax jurisdiction.  With limited exceptions, we remain subject to IRS examination of our income tax returns filed within the last three (3) years, and to California Franchise Tax Board examination of our income tax returns filed within the last four (4) years.

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EQUIPMENT

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Abstract]

EQUIPMENT

Note 7 – Equipment

Equipment as of December 31, 2018 and 2017 are as follows:

	2018			2017
Vehicles	$	83,578		$	83,578
Website		1,375			1,375
Furniture/Computer Equip		20,380			20,380
Material/Pipe Supplies		6,750			0
Less: Accumulated depreciation		(44,758	)		(22,364	)
	$	67,325		$	18,530

Two vehicles were purchased during the year ended December 31, 2017 totaling $73,292. Of this amount, $67,078 was financed and $6,214 was paid in cash. Depreciation expense for the years ended December 31, 2018 and 2017, respectively, was $22,392 and $8,854.

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DEBT

12 Months Ended

Dec. 31, 2018

Notes to Financial Statements

DEBT

Note 8 – Debt

Loan payable 

Notes payable consists of the following:

	December 31, 2018			December 31, 2017
Note payable to an entity for the financing of insurance premiums, unsecured; 7.99% interest, due March 2019	$	13,939		$	14,548
Note payable to an entity for the financing of a company vehicle, secured; 4.95% interest, due October 2022		25,598			32,351
Note payable to an entity for the financing of a company vehicle, secured; 4.95% interest, due November 2022		26,390			33,052
Senior Secured Debt, 10% interest; due March 31, 2019 and March 31,2017 respectively		2,350,000			500,000
Unamortized debt discount		(62,924	)		—
Notes Payable/Senior Secured Credit Facility – Total	$	2,353,003		$	579,951

During the 2018 period, the Company received proceeds of $2,350,000 in the form of a senior secured credit facility. The senior secured credit facility carries a 10% interest rate and also includes one five-year warrant at $0.10 per share for every two dollars outstanding. As of March 31^st, 2019, the entire principal and interest was due on the loan. The loan carried a financial covenant requiring the Company to generate one million in EBITDA as of December 31, 2018, the Company did not meet that obligation. Do to this non-compliance the Company is currently in default on the loan. Additionally, the Company was not able to repay the loan on its maturity date and is therefore in default on the loan. Repayments of notes for year ended December 31, 2018 and 2017, respectively, was $78,050 and $566,927. Interest expense for the year ended December 31, 2018 was $165,673 and relates to notes payable and insurance financing. Interest expense for the year ended December 31, 2017 was $79,481 and relates to notes payable and insurance financing. For year ended December 31, 2017 a note of $52,920 was used to finance insurance for the year.

Drilling Obligation

The Company entered into a drilling Joint Venture agreement with investors to drill two exploration wells in 2017. The $700,000 drilling liability has an 18% rate of return due to the investor and as such, the Company booked a discount of $126,000 of which $84,000 has been amortized during the year ended December 31, 2018, leaving a balance at December 31, 2018 of $42,000. The discount is being amortized over 18 months. The term is an estimate based on when management expects this liability to be fully settled.

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PRODUCTION PAYMENT LIABIITY

12 Months Ended

Dec. 31, 2018

Notes to Financial Statements

Production Payment Liability

Note 9 – Production Payment Liability

In December 2014, the Company entered into a financing agreement with two related party entities. The Company received $300,000 in total from both entities to fund costs of the Yowlumne 2-26 well recompletion. In return for the funds received, the two entities will receive a combined 75% of the net revenue from the well until the $300,000 is repaid. At the time of repayment, the entities will own a total 3% overriding royalty on the well. This liability is completely dependent on the well generating revenue.

If the well fails to generate enough revenue to repay the $300,000, Citadel is not responsible for the unpaid amount. According to ASC 932-470-25 Section B, Funds advanced to an operator that are repayable in cash out of the proceeds from a specified share of future production of a producing property, until the amount advanced $300,000 is paid in full, shall be accounted for as a borrowing. The advance is a payable for the recipient of the cash invested. Given the well is not currently on production coupled with the high cost of water disposal, we believe it will take more than two years for payback to occur; therefore this has been classified as a long-term payable.

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ASSET RETIREMENT OBLIGATION

12 Months Ended

Dec. 31, 2018

Notes to Financial Statements

Asset Retirement Obligations (AROs)

Note 10 – Asset Retirement Obligations (AROs)

The Company's ARO relates to future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. In periods subsequent to the initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. The increases in the ARO liability due to the passage of time impact net earnings as accretion expense. The related capital cost, including revisions thereto, is charged to expense through depreciation, depletion and amortization of oil and natural gas production over the life of the oil and natural gas field.

The following table summarizes the activity for the Company's abandonment obligations:

	Year Ended December 31,
	2018		2017
Beginning balance at January 1	$	224,380	$	217,212
Liabilities incurred from property acquisition		12,129		—
Accretion expense		13,848		7,168
Ending balance at December 31	$	250,357	$	224,380

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STOCKHOLDERS' EQUITY

12 Months Ended

Dec. 31, 2018

Notes to Financial Statements

STOCKHOLDERS' EQUITY

Note 11 – Stockholders’ Equity

The Company is authorized to issue 300,000,000 shares of its $0.001 par value common stock.

In March of 2016, the Company approved the sale of up to 500,000 shares of Series A Convertible Participating Preferred Stock. The following are terms of the Series A Convertible Participating Preferred Stock:

1. Series A – Senior to Common Stock

2. Three-Year Term – Series a Convertible at any time at the holder’s discretion, during the three year-term. Issuer, Citadel Exploration, Inc., can only force convert Series A, if the company’s common stock trades at $1.00 or more for 90 consecutive days.

3. Convertible into Citadel Exploration, Inc. common stock at a term of 1 share of preferred par value $20.00 to 100 shares of Common Stock par value $0.001 – implied conversion rate of $0.20 per share.

4. 10% Coupon, $2.00 per share, paid in semi-annual installments at $1.00 per share and payable in cash or payment in kind of additional Series A Convertible Participating Preferred Stock during first year.

5. 2% Over Riding Royalty Interest (ORRI) on the Kern Bluff Oil Field until conversion into common stock. Upon conversion, ORRI will be reduced to 1% in perpetuity.

6. Royalty to be paid on a quarterly basis, starting at 90 days after the close of the offering.

7. There is no redemption right by the company or the shares holders

The Company sold 175,000 shares of Series A Convertible Participating Preferred Stock to convert its $3,500,000 related party note payable to preferred stock. In addition, the Company has sold 21,250 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $425,000 through March 31, 2016.

A 2% overriding royalty interest was issued in conjunction with the Series A Convertible Participating Preferred Stock. That value of $442,136 reduces the Company’s proved property valuation.

In June of 2016, the Company sold 50,000 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $1,000,000.

In September of 2016, the Company sold 26,500 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $530,000. The Company issued 500,000 shares of common stock for cash in the amount of $100,000. 

In October of 2016, the Company sold 10,350 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $207,000.

In November of 2016, the Company sold 29,330 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $586,600.

In December of 2016, the Company sold 13,300 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $266,000.

As detailed above in the related 2016 issuances, the Company issued 330,365 shares of Series A Convertible Participating Preferred stock to settle the 2016 preferred stock payable in the amount of 6,607,300. These shares were sold in 2016, but issued in 2017.

In March of 2017, the Company sold 10,000 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $200,000.

In March of 2017, the Company issued 2,034,002 common shares as a special dividend to Series A Preferred Shareholders to settle accrued interest on preferred stock during the 2016 offering period of the Series A totaling $244,080. A gain occurred on the issuance which totaled $50,122.

In June of 2017, the Company sold 13,750 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $275,000.

In September of 2017, the Company sold 22,500 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $450,000.

In October of 2017, the Company issued 5,250 shares of Series A Convertible Participating Preferred Stock as payment to settle note payable in the amount of $105,000.

In December of 2017, the Company sold 12,500 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $250,000.

In December of 2017, the Company issued 3,101,736 shares of common stock as payment for dividend on the Series A Preferred Stock during 2017.

In December of 2017, the Company adopted the 2017 Restricted Stock Unit Plan (RSU) authorizing the issuance of 10,000,000 restricted stock units to management and future employees. 

In January of 2018, the Company sold 1,250 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $25,000.

In January of 2019, the Company issued 3,956,147   shares of common stock as payment for dividend on the Series A Preferred Stock during 2018.

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STOCK OPTION PLAN

12 Months Ended

Dec. 31, 2018

Notes to Financial Statements

STOCK OPTION PLAN

 Note 12 – Stock Option Plan

On August 1, 2018 as approved by the Board of Directors, the Company granted 500,000 stock options to three members of the Board of Directors.  These options vest over a three year period, at $0.15 per share for a term of seven years. using the Black Scholes option pricing model with an expected life of 7 years, risk free interest rate of 1.872%, dividend yield of 0%, and expected volatility of 333%.

The following is a summary of the status of all of the Company’s stock options as of December 31, 2018 and changes during the period ended on that date:

	Number of Options		Weighted-Average Exercise Price		Aggregate Intrinsic Value		Weighted-Average Remaining Life (Years)
Outstanding at January 1, 2017		9,500,000	$	0.20	$	—		3.26
Exercisable at January 1, 2017		9,500,000	$	0.20	$	—		3.26
Granted			$	0.00	$	—		—
Exercised		—	$	0.00	$	—		—
Cancelled		—	$	0.00	$	—		—
Outstanding at December 31, 2017		9,500,000	$	0.20	$	—		3.26
Exercisable at December 31, 2017		9,500,000	$	0.20	$	—		3.26
Granted		500,000	$	0.20	$	—		2.48
Exercised		—	$	0.00	$	—		—
Cancelled		—	$	0.00	$	—		—
Outstanding at December 31, 2018		10,000,000	$	0.20	$	—		2.48
Exercisable at December 31, 2018		10,000,000	$	0.20	$	235,000		2.48

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WARRANTS

12 Months Ended

Dec. 31, 2018

Notes to Financial Statements

WARRANTS

Note 13 – Warrants

In March 2018, the Company closed on a $3,000,000 Senior Secured Credit Facility with $1,750,000 drawn. As per the terms of the agreement, the investors receive one warrant for every two dollars invested. As such the Company issued 875,000 warrants at $0.10 per share with a five-year term. The Company closed on an additional $500,000 of debt in August of 2018 and $100,000 of debt in October 2018 as such the Company issued 250,000 warrants and 50,000 warrants all at the same price and duration as the original tranche. These warrants were fair valued using the Black-Sholes method with an assumption of an average volatility rate of 253%. The relative fair value was recognized as debt discount

The following is a summary of the status of the Company’s stock warrants as of December 31, 2018 and changes during the period ended on that date:

	Number of Warrants		Weighted-Average Exercise Price		Weighted-Average Remaining Life (Years)
Outstanding at January 1, 2017		—	$	0.00		—
Granted		875,000	$	0.20		4.21
Exercised		—	$	0.00		—
Cancelled		—	$	0.00		—
Outstanding at March 31, 2018		875,000	$	0.20		4.21
Exercisable at March 31, 2018		875,000	$	0.20		4.21
Granted		250,000	$	0.20		4.73
Exercised		—	$	0.00		—
Cancelled		—	$	0.00		—
Forfeited		—	$	0.00		—
Outstanding at September 30, 2018		1,125,000	$	0.20		4.32
Exercisable at September 30, 2018		1,125,000	$	0.20		4.32
Granted		50,000	$	0.20		4.79
Exercised		—	$	0.00		—
Outstanding at December 31, 2018		1,175,000	$	0.20		4.34

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RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2018

Notes to Financial Statements

RELATED PARTY TRANSACTIONS

Note 14 – Related Party Transactions 

In December 2014, the Company entered into an agreement with Jim Walesa and Cibolo Creek Partners to fund $300,000 towards the Yowlumne #2-26 recompletion. In this agreement Mr. Walesa and Cibolo Creek will receive 75% of the net revenue after expenses, until they have received $300,000 in payment. Upon full repayment, Mr. Walesa and Cibolo Creek will receive a 3% royalty on the well. Mr. Walesa is currently on the Board of Directors of Citadel and a member of Cibolo Creek Partners.

During the year ended December 31, 2018 and December 31, 2017, Jim Walesa and Cibolo Creek Partners invested a total of $0 and $630,000 into the Company’s Series A Preferred Shares. During 2017, the Company has issued Jim Walesa and Cibolo Creek Partners a total of 2,413,867 shares in common stock.

During the year ended December 31, 2018 and December 31, 2017, the Company made the following purchases in the amount of $125,217   and $71,328, respectively, from an entity considered a related party for oil field equipment and services from Grey Energy. Grey Energy is owned by James Borgna, who is a member of our Board of Directors.

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SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2018

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

Note 15 – Subsequent Events

On April 15^th 2019,  the Company entered into an extension agreement with its Senior Secured Lender. As of March 31, 2018, the entire principal and interest on its Senior Secured Credit Facility was due and the Company was in default for non-payment. The Lender has granted the Company an extension to allow more time to refinance. There is no certainty that the Company will be able to refinance its debt, which could result in the Lender foreclosing on the Kern Bluff Oil Field or pursuing a sale of the assets to meet the Company’s obligations.

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SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Unaudited)

12 Months Ended

Dec. 31, 2018

Notes to Financial Statements

SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Unaudited)

Note 16  - Supplemental Information about Oil & Natural Gas Producing Activities (Unaudited)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized Costs 

	December 31,
	2018			2017
Oil and natural gas properties:	(in thousands)
Proved properties	$	4,513		$	3,513
Unproved properties		1,172			1,170
Facilities		2,415			2,200
Total oil and natural gas properties		8,100			6,883
Less oil property impairment		(562	)		(562	)
Less accumulated depreciation, depletion and amortization		(668	)		(133	)
Net oil and natural gas properties capitalized	$	6,870		$	6,188

Costs Incurred for Oil and Natural Gas Producing Activities 

	Year Ended December 31,
	2018		2017		2016
Acquisition costs:	(in thousands)
Proved properties	$	—	$	—	$	—
Unproved properties		—		—		—
Development costs		2,211		344		2,171
Total	$	2,211	$	344	$	2,171

Reserve Quantity Information

The following information represents estimates of the Company’s proved reserves as of December 31, 2018, which have been prepared and presented under SEC rules. These rules require SEC reporting companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2018 was based on an unweighted average 12-month average WTI posted price per Bbl for oil as set forth in the following table: 

	Year Ended December 31,
	2018		2017		2016
Oil (per Bbl)	$	65.01	$	45.94	$	45.53

Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement has limited, and may continue to limit, the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves within the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more.

The Company’s proved oil reserves are located in the United States in the San Joaquin Valley of California. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.

Oil reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates.

Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

The following table provides a roll forward of the total proved reserves for the years ended December 31, 2018, 2017, and 2016, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:

	Year Ended December 31, 2018
	Crude Oil			Natural Gas
	(Bbls)			(Mcf)		Boe
	(in thousands)
Proved Developed and Undeveloped Reserves:
Beginning of the year		1,234			—		1,234
Extensions and discoveries		—			—		—
Revisions of previous estimates		55			—		55
Purchases of reserves in place					—
Divestures of reserves in place		—			—		—
Production		(17	)		—		(17	)
End of the year		1,272			—		1,272
Proved Developed Reserves:
Beginning of the year		282			—		282
End of the year		254			—		254
Proved Undeveloped Reserves:
Beginning of the year		952			—		952
End of the year		1,018			—		1,018

	Year Ended December 31, 2017
	Crude Oil			Natural Gas
	(Bbls)			(Mcf)		Boe
	(in thousands)
Proved Developed and Undeveloped Reserves:
Beginning of the year		1,160			—		1,160
Extensions and discoveries		—			—		—
Revisions of previous estimates		78			—		78
Purchases of reserves in place					—
Divestures of reserves in place		—			—		—
Production		(4	)		—		(4	)
End of the year		1,234			—		1,234
Proved Developed Reserves:
Beginning of the year		240			—		240
End of the year		282			—		282
Proved Undeveloped Reserves:
Beginning of the year		920			—		920
End of the year		952			—		952

	Year Ended December 31, 2016
	Crude Oil			Natural Gas
	(Bbls)			(Mcf)		Boe
	(in thousands)
Proved Developed and Undeveloped Reserves:
Beginning of the year		1,414			—		1,414
Extensions and discoveries		—			—		—
Revisions of previous estimates		(251	)		—		(251	)
Purchases of reserves in place					—
Divestures of reserves in place		—			—		—
Production		(3	)		—		(3	)
End of the year		1,160			—		1,160
Proved Developed Reserves:
Beginning of the year		358			—		358
End of the year		240			—		240
Proved Undeveloped Reserves:
Beginning of the year		1,056			—		1,056
End of the year		920			—		920

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs as of December 31, 2018, 2017, and 2016 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows:

	December 31,
	2018			2017			2016
	(in thousands)
Future cash inflows	$	82,708		$	56,674		$	41,220
Future development costs		(9,575	)		(9,350	)		(8,785	)
Future production costs		(36,289	)		(29,232	)		(25,567	)
Future income tax expenses		(5,476	)		(1,521	)		(860	)
Future net cash flows		31,386			16,571			6,008
10% discount to reflect timing of cash flows		(14,033	)		(6,871	)		(2,927	)
Standardized measure of discounted future net cash flows	$	17,335		$	3,081		$	7,107

In the foregoing determination of future cash inflows, sales prices used for oil and natural gas for December 31, 2018, 2017, and 2016, were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory income tax rates to the estimated future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax bases of the properties involved. The future income tax expenses give effect to income tax deductions, credits, NOL’s and allowances relating to the proved oil and gas reserves. All cash flow amounts, including income taxes, are discounted at 10%.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: 

	Year Ended December 31,
	2018			2017			2016
	(in thousands)
Standardized measure of discounted future net cash flows at the beginning of the year	$	9,700		$	3,081		$	7,107
Sales of oil and natural gas, net of production costs		(271	)		(66	)		(5	)
Purchase of minerals in place		—			—			—
Divestiture of minerals in place		—			—			—
Extensions and discoveries, net of future development costs		—			—			—
Previously estimated development costs incurred during the period		1,559			334			—
Net changes in prices and production costs		8,839			4,826			8,927
Changes in estimated future development costs		(121	)		(324	)		4,356
Revisions of previous quantity estimates		1,329			(1,896	)		(21,886)
Accretion of discount		970			267			420
Net change in income taxes		(2,122	)		314			2,114
Net changes in timing of production and other		(2,548	)		—			2,048
Standardized measure of discounted future net cash flows at the end of the year	$	17,335		$	9,700		$	3,081

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Basis of presentation

Organization

Citadel Exploration, Inc. ("Citadel Inc") was incorporated on December 17, 2009 in the State of Nevada originally under the name Subprime Advantage, Inc.  On March 2, 2011, the Company changed its name from Subprime Advantage, Inc. to Citadel Exploration, Inc.

On May 3, 2011, Citadel Inc completed the acquisition of 100% interest in Citadel Exploration, LLC, a California limited liability company, ("Citadel LLC") pursuant to a Membership Purchase Agreement (the "MPA"). Under the MPA, Citadel Inc issued 14,000,000 shares of the its common stock an individual in exchange for a 100% interest in Citadel LLC. Additionally under the MPA, the former officers and directors of Citadel Inc agreed to cancel 7,696,000 shares of its common stock. For accounting purposes, the acquisition of the Citadel LLC by Citadel Inc has been accounted for as a recapitalization, similar to a reverse acquisition except no goodwill is recorded, whereby the private company, Citadel LLC, in substance acquired a non-operational public company (Citadel Inc) with nominal assets and liabilities for the purpose of becoming a public company. Accordingly, Citadel LLC are considered the acquirer for accounting purposes and thus, the historical financials are primarily that of Citadel LLC. As a result of this transaction, Citadel Inc changed its business direction and is now involved in the acquisition and development of oil and gas resources in California. Citadel LLC was incorporated on November 6, 2006 (Date of Inception) and accordingly, the accompanying consolidated financial statements are from the Date of Inception of Citadel LLC through ending reporting periods reflected.

The consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America applicable to exploration stage enterprises, and are expressed in U.S. dollars. The Company’s fiscal year end is December 31.

Principles of consolidation

Principles of consolidation

For the years ended December 31, 2018 and 2017, the consolidated financial statements include the accounts of Citadel Exploration, Inc. and Citadel Exploration, LLC.   All significant intercompany balances and transactions have been eliminated.   Citadel Exploration, Inc. and Citadel Exploration, LLC will be collectively referred herein to as the “Company”.

Nature of operations

Nature of operations

Currently, the Company is focused on the acquisition and development of oil and gas resources in California.

Assumptions, Judgments and Estimates

Assumptions, Judgments and Estimates

In the course of preparing the consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.

The more significant areas requiring the use of assumptions, judgments, and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) income taxes; (7) valuation of derivative instruments; and (8) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Fair value of financial instruments

Fair value of financial instruments

Fair value estimates discussed herein are based upon certain market assumptions and pertinent information available to management as of December 31, 2018 and 2017. See Footnote No. 13, “Fair Value of Financial Instruments,” for further information. The respective carrying value of certain on-balance-sheet financial instruments approximated their fair values. These financial instruments include cash, prepaid expenses and accounts payable. Fair values were assumed to approximate carrying values for payables because they are short term in nature and their carrying amounts approximate fair values or they are payable on demand.

Level 1: The preferred inputs to valuation efforts are “quoted prices in active markets for identical assets or liabilities,” with the caveat that the reporting entity must have access to that market. Information at this level is based on direct observations of transactions involving the same assets and liabilities, not assumptions, and thus offers superior reliability. However, relatively few items, especially physical assets, actually trade in active markets.

Level 2: FASB acknowledged that active markets for identical assets and liabilities are relatively uncommon and, even when they do exist, they may be too thin to provide reliable information. To deal with this shortage of direct data, the board provided a second level of inputs that can be applied in three situations.

Level 3: If inputs from levels 1 and 2 are not available, FASB acknowledges that fair value measures of many assets and liabilities are less precise. The board describes Level 3 inputs as “unobservable,” and limits their use by saying they “shall be used to measure fair value to the extent that observable inputs are not available.” This category allows “for situations in which there is little, if any, market activity for the asset or liability at the measurement date”. Earlier in the standard, FASB explains that “observable inputs” are gathered from sources other than the reporting company and that they are expected to reflect assumptions made by market participants.

Inventories

Inventories

Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence. Finished goods include oil and natural gas products, which are valued at the lower of cost or market.

Oil and Natural Gas Properties

Oil and Natural Gas Properties

The Company accounts for our oil and gas exploration and development costs using the successful efforts method. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found.

If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

The costs of development wells are capitalized whether productive or nonproductive. We review our oil and natural gas producing properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if a field contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 inputs which are based upon estimates, the most significant of which is the estimate of net proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates.

Property, Plant and Equipment

Property, Plant and Equipment

The Company records all property and equipment at cost less accumulated depreciation.  Improvements are capitalized while repairs and maintenance costs are expensed as incurred. Depreciation is calculated on a straight-line basis over estimated useful lives ranging from 5 to 30 years for buildings and improvements and 3 to 10 years for machinery and equipment. Leasehold improvements include the cost of the Company’s internal development and construction department. The Company capitalizes the costs associated with the development of the Company’s website pursuant to ASC Topic 350.

Stock-based compensation

Stock-based compensation

The Company records stock-based compensation in accordance with the guidance in ASC Topic 505 and 718 which requires the Company to recognize expenses related to the fair value of its employee stock option awards.  The Company recognizes the cost of all share-based awards on a graded vesting basis over the vesting period of the award. 

The Company accounts for equity instruments issued in exchange for the receipt of goods or services from other than employees in accordance with FASB ASC 505-50. Costs are measured at the estimated fair market value of the consideration received or the estimated fair value of the equity instruments issued, whichever is more reliably measurable. The value of equity instruments issued for consideration other than employee services is determined on the earliest of a performance commitment or completion of performance by the provider of goods or services as defined by FASB ASC 505-50.

Earnings per share

Earnings per share

The Company follows ASC Topic 260 to account for the earnings per share. Basic earnings per common share (“EPS”) calculations are determined by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per common share calculations are determined by dividing net income by the weighted average number of common shares and dilutive common share equivalents outstanding. During periods when common stock equivalents, if any, are anti-dilutive they are not considered in the computation.

Cash and Cash Equivalents

Cash and cash equivalents

The Company considers all highly liquid instruments with maturity of three months or less at the time of issuance to be cash equivalents.

Concentrations of credit risk

Concentrations of credit risk

Financial instruments that subject the Company to credit risk could consist of cash balances maintained in excess of federal depository insurance limits. The Company maintains its cash and cash equivalent balances with high credit quality financial institutions. At times, cash and cash equivalent balances may be in excess of Federal Deposit Insurance Corporation limits. To date, the Company has not experienced any such losses.

Restricted Cash

Restricted cash

Restricted cash consisted of a blanket bond totaling $200,000. Bonds are required to meet financial bonding requirements in the state of California. The blanket bond, which will cover 50 wells, was purchased in August 2015 following the acquisition of the Kern Bluff Oil Field.

Debt discount

Debt discount

The Company records debt discount as a contra liability account and is presented net of the associated loan. The discount is amortized over the life on the loan using the straight-line method because the straight-line method approximates the effective interest method.

Revenue recognition

Revenue Recognition

 The new revenue standard (ASC606) requires more quantitative and qualitative disclosure that prior guidance. More specifically the following areas have been a concern for the SEC. As such Citadel will address each of these matters in the following bullet points.

As background, Citadel Exploration has one source of revenue, Phillips 66, the refiner that purchases our crude oil. Citadel receives a check from the purchaser Phillips 66 on the 20^th of the Month following said production. The revenue amount is net of transportation costs, currently $1.45 per barrel. The price received is based upon the purchaser contract which is the average of the posted price for heavy oil in California. For natural gas, there is no revenue as our field does not produce economic quantities of natural gas. For gathering and transportation sales, there are no sales or revenues. We own and operate all gathering equipment and infrastructure. Revenues from oil and gas sales are recognized when once we have received payment from the refiner.

• Performance Obligations: Phillips 66 has been our purchaser for the last two years and has never missed a payment. From a qualitative measure they could not perform any better.

• Variable Consideration: The price Citadel receives for its oil, is tracked daily by several services including Bloomberg.com, oilprice.com and on Chevron’s webpage. This price is wildly available and transparent. Citadel does not calculate, or control said price. From a quantitative standpoint, we do not have any control. From a qualitative standpoint, we compare what we are paid, versus what prices averaged for the quarter.

• Recognizing revenue: Citadel is sent an oil ticket summary on or around the 10^th of the month, depending on if the date is on a weekend. That summary provides a detailed summary of date and barrels sold and at what price. The revenue is recognized in the quarter that the oil is sold, as we are paid for the oil on the 20^th of the following month.

• Costs to obtain a contract: The only cost that Citadel incurs is a transportation cost. The actual contract has no costs. As an example, prior to Phillips 66 we sold to Plains All American (PAA). Our PAA contract charged us $1.95 for transportation. Through various contacts we were introduced to Phillips 66, and they quoted Citadel a transportation cost of $1.45. Both contracts were based on the exact same California heavy oil index for price, therefore the ability to save/realize an additional $0.50 per barrel was the motivation for the change. From a qualitative standpoint, Phillips 66 and PAA are both multibillion-dollar companies. Therefore, we did not see a difference in credit risk to getting paid.

• Gross versus net presentation: This does not apply as we are paid the gross value of our oil minus transportation costs. We do not accept a discount.

• Disaggregated revenue: This does not apply as we sell oil from one facility at one oil field and do not have multiple fields or multiple refiners.

In conclusion, Citadel’s business and hence revenue is pretty simple and straight forward. We sell one product, to one refiner, and we are paid once a month.

Asset retirement obligation

Asset Retirement Obligation

The Company's asset retirement obligations (AROs) relate to future costs associated with plugging and abandonment of oil wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred (typically when the asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability.

Revenue & Expense Recognition

Revenue & Expense Recognition

The Company utilizes accrual basis of accounting when measuring financial position and operating results. The accrual basis recognizes revenues and expenses in the accounting period in which those transactions, events, or circumstances occur (goods or services are received) and become measurable.

The Company recognizes its expenses when the expenses are incurred, not necessarily when they are paid. Expenses are generally incurred when the company receives tangible goods or services are provided.

Lease operating expense

Lease operating expense

Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities.

Depreciation, Depletion and Amortization

Depreciation, Depletion and Amortization

The provision for DD&A-oil and natural gas production is calculated on a field-by-field basis using the unit-of-production method. Projected future production rates, the timing of future capital expenditures as well as changes in commodity prices, may significantly impact estimated reserve quantities. Depreciation, depletion and amortization —oil and natural gas production is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections. These estimates are subject to change as additional information and technologies become available. Accordingly, oil and natural gas quantities ultimately recovered and the timing of production may be substantially different than projected. Reduction in reserve estimates may result in increased depreciation, depletion and amortization oil and natural gas production, which in turn reduces net earnings. Changes in reserve estimates are applied on a prospective basis. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher costs fields.

Income taxes

Income taxes

The Company follows ASC Topic 740 for recording the provision for income taxes. Deferred tax assets and liabilities are computed based upon the difference between the consolidated financial statements and income tax basis of assets and liabilities using the enacted marginal tax rate applicable when the related asset or liability is expected to be realized or settled. Deferred income tax expenses or benefits are based on the changes in the asset or liability each period.

If available evidence suggests that it is more likely than not that some portion or all of the deferred tax assets will not be realized, a valuation allowance is required to reduce the deferred tax assets to the amount that is more likely than not to be realized. Future changes in such valuation allowance are included in the provision for deferred income taxes in the period of change.

Deferred income taxes may arise from temporary differences resulting from income and expense items reported for financial accounting and tax purposes in different periods. Deferred taxes are classified as current or non-current, depending on the classification of assets and liabilities to which they relate. Deferred taxes arising from temporary differences that are not related to an asset or liability are classified as current or non-current depending on the periods in which the temporary differences are expected to reverse. The net operating loss carryforward for the year ended December 31, 2018 is $11,534,488 and the deferred tax asset is $3,595,000. The Company maintains a full valuation allowance for the deferred tax asset of $3,595,000.

The Company applies a more-likely-than-not recognition threshold for all tax uncertainties. ASC Topic 740 only allows the recognition of those tax benefits that have a greater than fifty percent likelihood of being sustained upon examination by the taxing authorities. As of December 31, 2018 and 2017, the Company reviewed its tax positions and determined there were no outstanding, or retroactive tax positions with less than a 50% likelihood of being sustained upon examination by the taxing authorities, therefore this standard has not had a material effect on the Company.

The Company does not anticipate any significant changes to its total unrecognized tax benefits within the next 12 months. 

The Company classifies tax-related penalties and net interest as income tax expense. As of December 31, 2018 and 2017, no income tax expense has been recorded.

Long-lived Assets

Long-lived Assets

In accordance with the Financial Accounting Standards Board ("FASB") Accounts Standard Codification (ASC) ASC 360-10, "Property, Plant and Equipment," the carrying value of intangible assets and other long-lived assets is reviewed on a regular basis for the existence of facts or circumstances that may suggest impairment. Proved oil properties are reviewed for impairment on a field-by-field basis, annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. The Company estimates the expected future cash flows of its oil properties and compares these undiscounted cash flows to the carrying amount of the oil properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil properties to fair value.

The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates commensurate with the risk associated with realizing the projected cash flows.

Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. The impairment assessment is affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time.

Leases

Leases

The Company had two types of leases. A capital lease for the financing of vehicles. An operational lease on its steam generator, in which the Company had previously purchased the generator and then sold the generator with an agreement to lease the equipment. Thus, this meets the definition of a sales lease-back arrangement. Since there was no gain or loss from the sale, there is no affect in the income statement.

Recent pronouncements

Recent pronouncements

In May 2014, the FASB issued ASC updated No. 2014-09, Revenue from Contracts with Customers (Topic 606 (ASU 2014-09). Under the amendments in this update, recognition of revenue occurs when a customer obtains control of promised goods or services in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, the new standard requires that reporting companies disclose the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The amendments in this update are effective for fiscal years and interim periods within those years beginning after December 15, 2017 and supersedes any previous revenue recognition guidance. Implementation of Topic 606, which was adopted by the Company as of January 1, 2018, was done using the modified retrospective approach. Adoption of this new standard did not have an impact on the Company’s balance sheet, statement of operations, statement of stockholders’ equity or statement of cash flows.

In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash” (“ASU 2016-18”). The update is effective for years beginning December 15, 2017, including interim reporting periods within those fiscal years. Early adoption is permitted. These accounting pronouncements were adopted by the Company as of January 1, 2018. The purpose of Update 2016 -18 is to clarify guidance and presentation related to restricted cash in the Statements of Cash Flows. The amendment requires beginning-of-period and end-of- period total amounts shown on the Statements of Cash Flows to include cash and cash equivalents as well as restricted cash and restricted cash equivalents. Adoption of this new standard did not have a material impact on the Company’s financial statements.

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OIL AND GAS PROPERTIES, BUILDINGS AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Schedule of Oil and natural gas properties, buildings and equipment

Oil and natural gas properties consist of the following:

	2018			2017
Oil and Natural Gas:
Proved properties	$	4,121,940		$	3,468,306
Unproved properties		1,172,034			1,170,000
Facilities		2,231,561			2,244,716
		7,525, 535			6,883,022
Less oil property impairment					(562,030	)
Less accumulated depreciation, depletion, and amortization		(667,966	)		(132,906	)
	$	6,857, 569		$	6,188,086

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Schedule of provision for income taxes

The (benefit) provision for income taxes from continuing operations consists of the following (in thousands):

	Year Ended December 31,
		2018		2017
Current:
Federal	$	—	$	—
State		4		2
		4		2
Deferred:
Federal		—		—
State		—		—
		—		—
Total	$	4	$	2

Schedule of Deferred Income Tax Liabilities

The components of the net deferred income tax liabilities consist of the following: 

		Year Ended December 31,
		2018			2017
Deferred income tax assets:
Equity and deferred compensation		255			239
Net operating loss		2,442			1,918
State net operating loss carry forward		1,080			808
Other, net		—			—
Total deferred tax assets		3,697			2,965
Valuation allowance		(3,211	)		(2,907	)
		486			58
Deferred income tax liabilities:
Depreciation and depletion		(486	)		(58	)
Net deferred income tax liabilities	$	—		$	—

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EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Abstract]

Schedule of Equipment

Equipment as of December 31, 2018 and 2017 are as follows:

	2018			2017
Vehicles	$	83,578		$	83,578
Website		1,375			1,375
Furniture/Computer Equip		20,380			20,380
Material/Pipe Supplies		6,750			0
Less: Accumulated depreciation		(44,758	)		(22,364	)
	$	67,325		$	18,530

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DEBT (Tables)

12 Months Ended

Dec. 31, 2018

Notes to Financial Statements

Schedule of Notes Payable

Notes payable consists of the following:

	December 31, 2018			December 31, 2017
Note payable to an entity for the financing of insurance premiums, unsecured; 7.99% interest, due March 2019	$	13,939		$	14,548
Note payable to an entity for the financing of a company vehicle, secured; 4.95% interest, due October 2022		25,598			32,351
Note payable to an entity for the financing of a company vehicle, secured; 4.95% interest, due November 2022		26,390			33,052
Senior Secured Debt, 10% interest; due March 31, 2019 and March 31,2017 respectively		2,350,000			500,000
Unamortized debt discount		(62,924	)		—
Notes Payable/Senior Secured Credit Facility – Total	$	2,353,003		$	579,951

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ASSET RETIREMENT OBLIGATION (Tables)

12 Months Ended

Dec. 31, 2018

Notes to Financial Statements

Company announced its first oil production

The following table summarizes the activity for the Company's abandonment obligations:

	Year Ended December 31,
	2018		2017
Beginning balance at January 1	$	224,380	$	217,212
Liabilities incurred from property acquisition		12,129		—
Accretion expense		13,848		7,168
Ending balance at December 31	$	250,357	$	224,380

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STOCK OPTION PLAN (Tables)

12 Months Ended

Dec. 31, 2018

Notes to Financial Statements

Schedule of Company's stock options

The following is a summary of the status of all of the Company’s stock options as of December 31, 2018 and changes during the period ended on that date:

	Number of Options		Weighted-Average Exercise Price		Aggregate Intrinsic Value		Weighted-Average Remaining Life (Years)
Outstanding at January 1, 2017		9,500,000	$	0.20	$	—		3.26
Exercisable at January 1, 2017		9,500,000	$	0.20	$	—		3.26
Granted			$	0.00	$	—		—
Exercised		—	$	0.00	$	—		—
Cancelled		—	$	0.00	$	—		—
Outstanding at December 31, 2017		9,500,000	$	0.20	$	—		3.26
Exercisable at December 31, 2017		9,500,000	$	0.20	$	—		3.26
Granted		500,000	$	0.20	$	—		2.48
Exercised		—	$	0.00	$	—		—
Cancelled		—	$	0.00	$	—		—
Outstanding at December 31, 2018		10,000,000	$	0.20	$	—		2.48
Exercisable at December 31, 2018		10,000,000	$	0.20	$	235,000		2.48

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WARRANTS (Tables)

12 Months Ended

Dec. 31, 2018

Notes to Financial Statements

Schedule of Warrants

The following is a summary of the status of the Company’s stock warrants as of December 31, 2018 and changes during the period ended on that date:

	Number of Warrants		Weighted-Average Exercise Price		Weighted-Average Remaining Life (Years)
Outstanding at January 1, 2017		—	$	0.00		—
Granted		875,000	$	0.20		4.21
Exercised		—	$	0.00		—
Cancelled		—	$	0.00		—
Outstanding at March 31, 2018		875,000	$	0.20		4.21
Exercisable at March 31, 2018		875,000	$	0.20		4.21
Granted		250,000	$	0.20		4.73
Exercised		—	$	0.00		—
Cancelled		—	$	0.00		—
Forfeited		—	$	0.00		—
Outstanding at September 30, 2018		1,125,000	$	0.20		4.32
Exercisable at September 30, 2018		1,125,000	$	0.20		4.32
Granted		50,000	$	0.20		4.79
Exercised		—	$	0.00		—
Outstanding at December 31, 2018		1,175,000	$	0.20		4.34

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SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Tables)

12 Months Ended

Dec. 31, 2018

Notes to Financial Statements

Schedule of Oil and Natural Gas Reserves that are Attributable

Capitalized Costs 

	December 31,
	2018			2017
Oil and natural gas properties:	(in thousands)
Proved properties	$	4,513		$	3,513
Unproved properties		1,172			1,170
Facilities		2,415			2,200
Total oil and natural gas properties		8,100			6,883
Less oil property impairment		(562	)		(562	)
Less accumulated depreciation, depletion and amortization		(668	)		(133	)
Net oil and natural gas properties capitalized	$	6,870		$	6,188

Costs Incurred for Oil and Natural Gas Producing Activities 

	Year Ended December 31,
	2018		2017		2016
Acquisition costs:	(in thousands)
Proved properties	$	—	$	—	$	—
Unproved properties		—		—		—
Development costs		2,211		344		2,171
Total	$	2,211	$	344	$	2,171

Schedule of Reserve Quantity Information

The pricing that was used for estimates of the Company’s reserves as of December 31, 2018 was based on an unweighted average 12-month average WTI posted price per Bbl for oil as set forth in the following table: 

	Year Ended December 31,
	2018		2017		2016
Oil (per Bbl)	$	65.01	$	45.94	$	45.53

Schedule of Proved Developed and Undeveloped Reserves

The following table provides a roll forward of the total proved reserves for the years ended December 31, 2018, 2017, and 2016, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:

	Year Ended December 31, 2018
	Crude Oil			Natural Gas
	(Bbls)			(Mcf)		Boe
	(in thousands)
Proved Developed and Undeveloped Reserves:
Beginning of the year		1,234			—		1,234
Extensions and discoveries		—			—		—
Revisions of previous estimates		55			—		55
Purchases of reserves in place					—
Divestures of reserves in place		—			—		—
Production		(17	)		—		(17	)
End of the year		1,272			—		1,272
Proved Developed Reserves:
Beginning of the year		282			—		282
End of the year		254			—		254
Proved Undeveloped Reserves:
Beginning of the year		952			—		952
End of the year		1,018			—		1,018

	Year Ended December 31, 2017
	Crude Oil			Natural Gas
	(Bbls)			(Mcf)		Boe
	(in thousands)
Proved Developed and Undeveloped Reserves:
Beginning of the year		1,160			—		1,160
Extensions and discoveries		—			—		—
Revisions of previous estimates		78			—		78
Purchases of reserves in place					—
Divestures of reserves in place		—			—		—
Production		(4	)		—		(4	)
End of the year		1,234			—		1,234
Proved Developed Reserves:
Beginning of the year		240			—		240
End of the year		282			—		282
Proved Undeveloped Reserves:
Beginning of the year		920			—		920
End of the year		952			—		952

	Year Ended December 31, 2016
	Crude Oil			Natural Gas
	(Bbls)			(Mcf)		Boe
	(in thousands)
Proved Developed and Undeveloped Reserves:
Beginning of the year		1,414			—		1,414
Extensions and discoveries		—			—		—
Revisions of previous estimates		(251	)		—		(251	)
Purchases of reserves in place					—
Divestures of reserves in place		—			—		—
Production		(3	)		—		(3	)
End of the year		1,160			—		1,160
Proved Developed Reserves:
Beginning of the year		358			—		358
End of the year		240			—		240
Proved Undeveloped Reserves:
Beginning of the year		1,056			—		1,056
End of the year		920			—		920

Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows:

	December 31,
	2018			2017			2016
	(in thousands)
Future cash inflows	$	82,708		$	56,674		$	41,220
Future development costs		(9,575	)		(9,350	)		(8,785	)
Future production costs		(36,289	)		(29,232	)		(25,567	)
Future income tax expenses		(5,476	)		(1,521	)		(860	)
Future net cash flows		31,386			16,571			6,008
10% discount to reflect timing of cash flows		(14,033	)		(6,871	)		(2,927	)
Standardized measure of discounted future net cash flows	$	17,335		$	3,081		$	7,107

Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: 

	Year Ended December 31,
	2018			2017			2016
	(in thousands)
Standardized measure of discounted future net cash flows at the beginning of the year	$	9,700		$	3,081		$	7,107
Sales of oil and natural gas, net of production costs		(271	)		(66	)		(5	)
Purchase of minerals in place		—			—			—
Divestiture of minerals in place		—			—			—
Extensions and discoveries, net of future development costs		—			—			—
Previously estimated development costs incurred during the period		1,559			334			—
Net changes in prices and production costs		8,839			4,826			8,927
Changes in estimated future development costs		(121	)		(324	)		4,356
Revisions of previous quantity estimates		1,329			(1,896	)		(21,886)
Accretion of discount		970			267			420
Net change in income taxes		(2,122	)		314			2,114
Net changes in timing of production and other		(2,548	)		—			2,048
Standardized measure of discounted future net cash flows at the end of the year	$	17,335		$	9,700		$	3,081

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RESTRICTED CASH (Details Narrative) - USD ($)	Dec. 31, 2018	Dec. 31, 2017	Aug. 25, 2015
Disclosure Restricted Cash Details Narrative Abstract
Restricted Cash	$ 200,000	$ 200,000	$ 200,000

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OIL AND GAS PROPERTIES, BUILDINGS AND EQUIPMENT (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Oil and Natural Gas:
Proved properties	$ 5,685,535	$ 5,018,086
Unproved properties	1,172,034	1,170,000
Facilities	2,231,561	2,244,716
Oil and Natural Gas Total	7,525,535	6,883,022
Less oil property impairment		(562,030)
Less accumulated depreciation, depletion, and amortization	(667,967)	(132,906)
Oil and Natural Gas, Net	$ 6,869,697	$ 6,188,086

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INCOME TAXES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Current:
Federal
State	4,000	2,000
Total	4,000	2,000
Deferred:
Federal
State
Total
Total

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INCOME TAXES (Details 2) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Deferred income tax assets:
Equity and deferred compensation	$ 255	$ 239
Net operating loss	2,442	1,918
State net operating loss carry forward	1,020	808
Other, net
Total deferred tax assets	3,697	2,965
Valuation allowance	(3,211)	(2,907)
Deferred Tax Assets, Net	486	58
Deferred income tax liabilities:
Depreciation and depletion	(486)	(58)
Total deferred tax liabilities
Net deferred income tax liabilities

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INCOME TAXES (Details Narrative)	Dec. 31, 2018 USD ($)
Income Tax Disclosure [Abstract]
Operating Loss Carryforwards, Fedral	$ 11,534,488
Operating Loss Carryforwards, State	$ 11,534,488

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EQUIPMENT (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Less: Accumulated depreciation	$ (44,758)	$ (22,364)
Fixed assets, net	67,326	82,969
Website [Member]
Fixed Assets	1,375	1,375
Furniture [Member]
Fixed Assets	20,380	20,380
Material/Pipe Supplies [Member]
Fixed Assets	6,750	0
Vehicles [Member]
Fixed Assets	$ 83,578	$ 83,578

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EQUIPMENT (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Depreciation expense	$ 22,392	$ 8,854

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NOTES PAYABLE (Details Narrative) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Notes Payable
Note payable to an entity for the financing of insurance premiums, unsecured; 7.99% interest, due March 2019	$ 13,939	$ 14,548
Note payable to an entity for the financing of a company vehicle, secured; 4.95% interest, due October 2022	25,598	32,351
Note payable to an entity for the financing of a company vehicle, secured; 4.95% interest, due November 2022	26,390	33,052
Senior Secured Debt, 10% interest; due March 31, 2019 and March 31,2017 respectively	2,350,000	500,000
Unamortized debt discount	(62,924)
Notes payable	$ 2,353,003	$ 579,951

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STOCK OPTION PLAN (Details) - Stock Option [Member] - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Number of Options
Outstanding, Beginning	9,500,000	9,500,000
Granted	500,000	9,500,000
Exercised
Cancelled
Outstanding, Ending	10,000,000	9,500,000
Exercisable at end of period		10,000,000
Weighted-Average Exercise Price
Outstanding, Beginning	$ 0.20	$ 0.20
Granted	0.20
Exercised	0.00
Cancelled	0.00
Outstanding, Ending	$ 0.20	0.20
Exercisable at end of period		$ 0.20
Weighted-Average Remaining Life (Years)
Outstanding, Beginning	3 years 3 months 4 days	3 years 3 months 4 days
Granted	2 years 5 months 23 days
Outstanding, Ending	2 years 5 months 23 days	3 years 3 months 4 days
Exercisable at end of period	2 years 5 months 23 days	3 years 3 months 4 days

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WARRANTS (Details) - Warrant [Member] - $ / shares	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Mar. 31, 2018	Sep. 30, 2017
Number of Options
Outstanding, Beginning	1,125,000	875,000	875,000
Granted	50,000	250,000		875,000
Exercised
Cancelled
Outstanding, Ending	1,175,000	1,125,000	1,175,000	875,000
Exercisable at end of period					875,000	1,125,000
Weighted-Average Exercise Price
Outstanding, Beginning	$ 0.20	$ 0.20	$ 0.20	$ 0.00
Granted		0.20		0.20
Exercised		0.00		0.00
Cancelled		0.00		0.00
Outstanding, Ending	$ 0.20	$ 0.20	$ 0.20	$ 0.20
Exercisable at end of period					$ 0.20	$ 0.20
Weighted-Average Remaining Life (Years)
Granted	4 years 9 months 14 days	4 years 8 months 23 days		4 years 2 months 16 days
Outstanding at at end of period	4 years 10 months 6 days	4 years 3 months 25 days		4 years 2 months 16 days
Exercisable at at end of period		4 years 3 months 25 days		4 years 2 months 16 days

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SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil and natural gas properties:
Facilities	$ 2,231,561	$ 2,244,716
Oil and Natural Gas Properties [Member]
Oil and natural gas properties:
Proved properties	4,513,000	3,513,000
Unproved properties	1,172,000	1,170,000
Facilities	2,415,000	2,200,000
Total oil and natural gas properties	8,100,000	6,883,000
Less oil property impairment	(562,000)	(562,000)
Less accumulated depreciation, depletion and amortization	(668,000)	(133,000)
Net oil and natural gas properties capitalized	6,870,000	6,188,000
Acquisition costs:
Proved properties
Unproved properties
Development costs	2,211,000	344,000	2,171,000
Total	$ 2,211,000	$ 344,000	$ 2,171,000

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SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Details 2) - USD ($)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Disclosure Of Oil And Natural Gas Operations Details 2
Future cash inflows	$ 82,708,000	$ 56,674,000	$ 41,220,000
Future development costs	(9,575,000)	(9,350,000)	(8,785,000)
Future production costs	(36,289,000)	(29,232,000)	(25,567,000)
Future income tax expenses	(5,476,000)	(1,521,000)	(860,000)
Future net cash flows	31,368,000	16,571,000	6,008,000
Ten percent discount to reflect timing of cash flows	(14,033,000)	(6,871,000)	(2,927,000)
Standardized measure of discounted future net cash flows	$ 17,335,000	$ 9,700,000	$ 3,081,000	$ 7,107,000

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SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Details 3) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Disclosure Of Oil And Natural Gas Operations Details 3
Standardized measure of discounted future net cash flows at the beginning of the year	$ 9,700,000	$ 3,081,000	$ 7,107,000
Sales of oil and natural gas, net of production costs	(271,000)	(66,000)	(5,000)
Purchase of minerals in place
Previously estimated development costs incurred during the period	1,559,000	334,000
Net changes in prices and production costs	8,839,000	4,826,000	8,927,000
Changes in estimated future development costs	(121,000)	(324,000)	4,356,000
Revisions of previous quantity estimates	13,290,000	(1,896,000)	(21,886,000)
Accretion of discount	970,000	267,000	420,000
Net change in income taxes	(2,122,000)	(314,000)	2,114,000
Net changes in timing of production and other	(2,548,000)		2,048,000
Standardized measure of discounted future net cash flows at the end of the year	$ 17,335,000	$ 9,700,000	$ 3,081,000