UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☒     Annual report under Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2018

☐     Transition report under Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ___________ to ___________

Commission File Number: 001-32624

FIELDPOINT PETROLEUM CORPORATION

(Name of Small Business Issuer in Its Charter)

Colorado	84-0811034
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

609 Castle Ridge Road, Suite 335

Austin, Texas 78746

(Address of Principal Executive Offices) (Zip Code)

 (512) 579-3560

(Issuer's Telephone Number, Including Area Code)

Securities registered under Section 12(b) of the Exchange Act:

(None)

Securities registered under Section 12(g) of the Exchange Act:

Common Stock, $.01 Par Value

Title of Class

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 15(d) of the Act. ☐

Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Exchange Act from their obligations under those Sections.

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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 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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See definition of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act (check one):

Large accelerated filer ☐	Accelerated filer ☐	Non-accelerated filer ☐	Smaller Reporting Company ☒
			Emerging Growth Company ☒

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company ☒

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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 sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second quarter, was $1,272,718.

The number of shares outstanding of the registrant’s common stock as of March 30, 2019, is 10,669,229.

List hereunder the following documents if incorporated by reference and the Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: (1) Any annual report to security holders; (2) Any proxy or information statement; and (3) Any prospectus filed pursuant to Rule 424(b) or (c) under the Securities Act of 1933. The listed documents should be clearly described for identification purposes

Exhibits

See Part IV, Item 15.

PART I

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this Form 10-K constitute “forward-looking statements”. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that FieldPoint Petroleum Corp. and its subsidiaries (collectively, the "Company", “we”, “us”, “our” or “ours”) expects, projects, believes or anticipates will or may occur in the future, including such matters as oil and natural gas reserves, future drilling and operations, future production of oil and natural gas, future net cash flows, future capital expenditures and other such matters, are forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements.

These forward-looking statements are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. We caution all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “Risk Factors” section and elsewhere in this report. All forward-looking statements speak only as of the date of this report. We disclaim any obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, unless required by law. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. The risks, contingencies and uncertainties relate to, among other matters, the following:

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our ability to continue as a going concern;

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our ability to comply with the covenants in our revolving credit facility;

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our leverage negatively affecting the semi-annual redetermination of our revolving credit facility;

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uncertainties in drilling, exploring for and producing oil and gas;

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oil, NGLs and natural gas prices;

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overall United States and global economic and financial market conditions;

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domestic and foreign demand and supply for oil, NGLs, natural gas and the products derived from such hydrocarbons;

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actions of the Organization of Petroleum Exporting Countries (“OPEC”), its members and other state-controlled oil companies relating to oil price and production controls;

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our ability to obtain additional financing necessary to fund our operations and capital expenditures and to meet our other obligations;

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our ability to maintain a sound financial position;

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issuance of our common stock in connection with potential refinancing transactions that may cause substantial dilution;

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our cash flows and liquidity;

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the effects of government regulation and permitting and other legal requirements, including laws or regulations that could restrict or prohibit hydraulic fracturing;

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disruption of credit and capital markets;

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disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver our oil, NGLs and natural gas and other processing and transportation considerations;

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marketing of oil, NGLs and natural gas;

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high costs, shortages, delivery delays or unavailability of drilling and completion equipment, materials, labor or other services;

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competition in the oil and gas industry;

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uncertainty regarding our future operating results;

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profitability of drilling locations;

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interpretation of 3-D seismic data;

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replacing our oil, NGLs and natural gas reserves;

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our ability to retain and attract key personnel;

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our business strategy, including our ability to recover oil, NGLs and natural gas;

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development of our current asset base or property acquisitions;

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estimated quantities of oil, NGLs and natural gas reserves and present value thereof;

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plans, objectives, expectations and intentions contained in this report that are not historical; and

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other factors discussed under Item 1A. “Risk Factors” in this report.

ITEM 1- BUSINESS

General

FieldPoint Petroleum Corporation, a Colorado corporation (the “Company”), was formed on March 11, 1980, to acquire and enhance mature oil and natural gas field production in the mid-continent and the Rocky Mountain regions. Since 1980, the Company had engaged in oil and natural gas operations and, in 1986, divested all oil and natural gas assets and operations. From December 1986, until its reverse acquisition on December 31, 1997, the Company did not engage in oil and natural gas operations. Since the reverse acquisition on December 31, 1997 the Company has been in the oil and natural gas exploration and production business.

Business Strategy

Our long-term business strategy is to create value by growing reserves and production in a cost efficient manner and at attractive rates of return by pursuing the strategies discussed below. The Company recognizes that the ability to implement its business strategy is largely dependent on the ability to raise additional debt or equity capital to regain compliance with our line of credit agreement (“the Loan Agreement”) before we can fund future acquisition, exploration, drilling and development activities. The Company’s capital resources are discussed more thoroughly in Part II, Item 7, in Management’s Discussion and Analysis.

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In response to deteriorating and volatile commodity prices, we halted our drilling activity beginning in 2015, which has led to a natural decline in production. Commodity prices have continued to remain volatile. As of December 31, 2018 and 2017, the Company had a working capital deficit of approximately $3,166,000 and $3,122,000, respectively, primarily due to the classification of our line of credit with Citibank as a current liability. The Loan Agreement provides for certain financial covenants and ratios measured quarterly, which include a current ratio, leverage ratio and interest coverage ratio requirements. The Company was out of compliance with all three ratios as of December 31, 2018 and 2017, and we do not expect to regain compliance in 2019.These factors raise substantial doubt about our ability to continue as a going concern. See Note 2 to our consolidated financial statements in this report for additional information regarding our plans to improve our leverage and our ability to regain compliance with the financial covenants under our revolving credit facility.

In order to improve our leverage position to regain compliance with our financial covenants under the revolving credit facility, we have been, and currently are, pursuing or considering a number of deleveraging and strategic actions, which in certain cases may require the consent of current lenders or stockholders.  

We are also considering other financing alternatives and deleveraging transactions, including without limitation (i) raising new capital in private or public markets and (ii) restructuring our balance sheet through agreements with creditors. We are also considering operational matters such as improving cash flows from operations by continuing to reduce costs and intend to continue to pursue and consider other strategic alternatives, including: (i) actively meeting with investors for possible equity investments, including business combinations; (ii) identifying and marketing all possible non-producing or low producing assets in our portfolio to maximize cash in-flows while minimizing a loss of cash flow; (iii) investigating other possible sources to refinance our debt as we continue to pay down our outstanding line of credit balance with a minimal effect on cash flow. There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in compliance with our credit facility covenants.

We also continue to position ourselves to resume production growth in the event of a continued and sustained commodity price recovery, by focusing on the following strategies:

Strengthen our balance sheet and financial flexibility. We intend to continue to explore a broad range of deleveraging alternatives as discussed above.

Operate our properties as a low-cost producer. We have significantly reduced per-unit lease operating expenses over the last three years.

Operations

As of December 31, 2018, the Company had varying ownership interest in 386 gross wells (95.71 net) located in five states. The Company operates 15 of the 386 wells; the other wells are operated by independent operators under contracts that are standard in the industry. It is a primary objective of the Company to operate some of the oil and natural gas properties in which it has an economic interest, and the Company will also partner with larger oil and natural gas companies to operate certain oil and natural gas properties in which the Company has an economic interest. The Company believes, with the responsibility and authority as operator, it is in a better position to control cost, safety, and timeliness of work as well as other critical factors affecting the economics of a well.

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The Company did not drill or complete any wells in 2018, and it is likely it will not drill or complete any wells in 2019. Our 2019 capital budget excludes acquisitions and lease extensions and renewals and is subject to change depending upon a number of factors, including prevailing and anticipated prices for oil, NGLs and gas, results of horizontal drilling and completions, economic and industry conditions at the time of drilling, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms. The eventual results of our strategic and deleveraging efforts may have a substantial impact on the Company’s capital expenditure budget. Although the impact of changes in these collective factors in the current commodity price environment is difficult to estimate. To the extent there is a significant increase or decrease in commodity prices in the future or a change to our capital structure, we will assess the impact on our development plan at that time, and we may respond to such changes by altering our capital budget or our development plan.

Market for Oil and Natural Gas

The demand for oil and natural gas is dependent upon a number of factors, including the availability of other domestic production, crude oil imports, the proximity and size of oil and natural gas pipelines in general, other transportation facilities, the marketing of competitive fuels, and general fluctuations in the supply and demand for oil and natural gas. The Company intends to sell all of its production to traditional industry purchasers, such as pipeline and crude oil companies, who have facilities to transport the oil and natural gas from the well site.

Competition

The oil and gas industry is highly competitive, and we compete for personnel, prospective properties, producing properties and services with a substantial number of other companies that have greater resources. Many of these companies explore for, produce and market oil and gas, carry on refining operations and market the end products on a worldwide basis. We also face competition from alternative fuel sources, including coal, heating oil, imported LNG, nuclear and other nonrenewable fuel sources, and renewable fuel sources such as wind, solar, geothermal, hydropower and biomass. Competitive conditions may also be substantially affected by various forms of energy legislation and/or regulation considered from time-to-time by the United States government. It is not possible to predict whether such legislation or regulation may ultimately be adopted or its precise effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil, NGLs and gas and may prevent or delay the commencement or continuation of our operations.

Hydraulic Fracturing

Hydraulic fracturing is an important process and has been commonly used in the completion of unconventional oil and gas wells in shale and tight sand formations since the 1950s. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate oil and gas production. It is important to us because it provides access to oil and gas reserves that previously were uneconomical to produce.

We have used hydraulic fracturing to complete both horizontal and vertical wells in the Permian Basin. We engage third parties to provide hydraulic fracturing services to us for completion of these wells. While hydraulic fracturing is not required to maintain our leasehold acreage that is currently held by production from existing wells, it will likely be required in the future to develop the proved non-producing and proved undeveloped reserves associated with this acreage. All of our proved non-producing and proved undeveloped reserves associated with future drilling, completion and recompletion projects could require hydraulic fracturing.

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We believe we have followed, and intend to continue to follow, applicable industry standard practices and legal requirements for groundwater protection in our operations that are subject to supervision by state regulators.

These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by applicable state regulatory agencies, and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This aspect of well design is intended to prevent contact between the fracturing fluid and any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure-tested before perforating the new completion interval.

Injection rates and pressures are monitored at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. We believe we have adequate procedures in place to address abrupt changes to the injection pressure or annular pressure.

Texas regulations currently require disclosure of the components in the solutions used in hydraulic fracturing operations. Over 99% (by mass) of the ingredients we use in hydraulic fracturing are water and sand. The remainder of the ingredients are chemical additives that are managed and used in accordance with applicable requirements.

Hydraulic fracturing requires the use of a significant amount of water. Upon flowback of the water, we dispose of it in a way that we believe minimizes the impact to nearby surface water by disposing into approved disposal facilities or injection wells. Currently our primary sources of water are nonpotable and potable aquifers. We use water from on-lease water wells that we have drilled, and we purchase water from off-lease water wells.

Operational Hazards and Insurance

The Company's operations are subject to the usual hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, pollution, releases of toxic gas and other environmental hazards and risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations.

The Company maintains insurance of various types to cover its operations. The Company's insurance does not cover every potential risk associated with the drilling and production of oil and natural gas. In particular, coverage is not obtainable for certain types of environmental hazards. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on the Company's financial condition and results of operations. Moreover, no assurance can be given that the Company will be able to maintain adequate insurance in the future at rates it considers reasonable.

Regulation

The oil and gas industry in the United States is subject to extensive regulation by federal, state and local authorities. At the federal level, various federal rules, regulations and procedures apply, including those issued by the U.S. Department of Interior, the U.S. Department of Transportation (the “DOT”) (Office of Pipeline Safety) and the U.S. Environmental Protection Agency (the “EPA”). At the state and local level, various agencies and commissions regulate drilling, production and midstream activities. These federal, state and local authorities have various permitting, licensing and bonding requirements. Various remedies are available for enforcement of these federal, state and local rules, regulations and procedures, including fines, penalties, revocation of permits and licenses, actions affecting the value of leases, wells or other assets, and suspension of production. As a result, there can be no assurance that we will not incur liability for fines, penalties or other remedies that are available to these federal, state and local authorities. However, we believe that we are currently in material compliance with federal, state and local rules, regulations and procedures, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations.

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Transportation and Sale of Oil

Sales of crude oil and condensate are not currently regulated and are made at negotiated prices. Our sales of crude oil are affected by the availability, terms and cost of transportation. Interstate transportation of oil by pipeline is regulated by the Federal Energy Regulation Commission (“FERC”) pursuant to the Interstate Commerce Act (“ICA”), Energy Policy Act of 1992 (“EPAct 1992”), and the rules and regulations promulgated under those laws. The ICA and its regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products, be just and reasonable and non-discriminatory and that such rates, terms and conditions of service be filed with FERC.

Intrastate oil pipeline transportation rates are also subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state-to-state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

The transportation of oil by truck is also subject to federal, state and local rules and regulations, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002. Regulations under these statutes cover the security and transportation of hazardous materials and are administered by the DOT.

Transportation and Sale of Natural Gas and NGLs

FERC regulates interstate gas pipeline transportation rates and service conditions under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those statutes. FERC also regulates interstate NGL pipelines under various federal laws and regulations. Although FERC does not regulate oil and gas producers such as us, FERC’s actions are intended to facilitate increased competition within all phases of the oil and gas industry and its regulation of third-party pipelines and facilities could indirectly affect our ability to transport or market our production. To date, FERC’s policies have not materially affected our business or operations.

Regulation of Production

Oil, NGL and gas production is regulated under a wide range of federal and state statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The states in which we operate, have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the regulation of spacing, and requirements for plugging and abandonment of wells. Also, some states, including Texas, impose a severance tax on production and sales of oil, NGLs and gas within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental Laws and Regulations

In the United States, the exploration for and development of oil and gas and the drilling and operation of wells, fields and gathering systems are subject to extensive federal, state and local laws and regulations governing environmental protection as well as discharge of materials into the environment. These laws and regulations may, among other things:

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require the acquisition of various permits before drilling begins;

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require the installation of expensive pollution controls or emissions monitoring equipment;

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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling, completion, production, transportation and processing activities;

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suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, endangered species habitat, and other protected areas; and

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require remedial measures to mitigate and remediate pollution from historical and ongoing operations, such as the closure of waste pits and plugging of abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.

Governmental authorities have the power to enforce compliance with environmental laws, regulations and permits, and violations are subject to injunction, as well as administrative, civil and criminal penalties. The effects of existing and future laws and regulations could have a material adverse impact on our business, financial condition and results of operations. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretations of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business, financial condition or results of operations. Moreover, accidental releases or spills and ground water contamination may occur in the course of our operations, and we may incur significant costs and liabilities as a result of such releases, spills or contamination, including any third-party claims for damage to property, natural resources or persons. We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this will continue in the future.

The following is a summary of some of the existing environmental laws, rules and regulations that apply to our business operations.

Hazardous Substance Release

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as the Superfund law, and comparable state statutes impose strict liability, and under certain circumstances, joint and several liability, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to strict, joint and several liabilities for the costs of investigating releases of hazardous substances, cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA.

Waste Handling

The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced water and most of the other wastes associated with the exploration, development and production of oil or gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could increase our operating expenses, which could have a material adverse effect on our business, financial condition and results of operations.

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We currently own or lease properties that for many years have been used for oil and gas exploration, production and development activities. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on, under or from the properties owned or leased by us or on, under or from other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and the materials disposed or released on, at, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or contamination, or to perform remedial activities to prevent future contamination.

Air Emissions

The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions at specified sources. In particular, on April 18, 2012, the EPA issued new regulations under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”). The regulations are designed to reduce volatile organic compound (“VOC”) emissions from hydraulically-fractured natural gas wells, storage tanks and other equipment. Since January 1, 2015, all newly fractured natural gas wells must use green completion technology, which allows for the recovery of natural gas that formerly would have been vented or flared. We do believe that the NSPS or NESHAP have had a material adverse effect on our business, financial condition or results of operations. However, any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements or use specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.

Greenhouse Gas Emissions

Congress has, from time-to-time, considered legislation to reduce emissions of greenhouse gases (“GHGs”). The current Congress is likely to continue to consider similar bills. Moreover, almost half of the states have already taken legal measures to reduce emissions of GHGs through the planned development of GHG emission inventories and/or regional GHG cap-and-trade programs or other mechanisms. Most cap-and-trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Many states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.

In response to the findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which would regulate emissions of GHGs from large stationary sources of emissions such as power plants or industrial facilities. The motor vehicle rule was finalized in April 2010 and became effective in January 2011, but it did not require immediate reductions in GHG emissions. In 2015, the EPA issued a final rule to limit carbon emissions from new power plants and simultaneously released a final rule to limit carbon emissions from existing power plants (the latter rule is also known as the “Clean Power Plan”). The Clean Power Plan has been heavily litigated since its promulgation, and the decision by the DC Circuit Court of Appeals in December 2018 to continue to hold a number of consolidated Clean Power Plan cases in abeyance without yet ruling on the merits of the Clean Power Plan has contributed to the current uncertainty as the Clean Power Plan’s future. Further, the EPA under the Trump administration proposed in October 2017 to repeal the Clean Power Plan and in August 2018 to replace it with the Affordable Clean Energy Rule (“ACE”). The regulatory procedures required to complete the repeal of the Clean Power Plan and/or to finalize the ACE Rule may take years. If the Clean Poser Plan regulations ultimately are upheld or replaced, it could have a significant impact on the electrical generation industry and may favor the use of natural gas over other fossil fuels in new plants. In the past, the EPA has also indicated that it will propose new GHG emissions standards for refineries, which has not yet occurred.

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In December 2010, the EPA enacted final rules on mandatory reporting of GHGs. The EPA has also published amendments to the rule containing technical and clarifying changes to certain GHG reporting requirements and a six-month extension for reporting GHG emissions from petroleum and natural gas industry sources. Under the amended rule, certain onshore oil and natural gas production, processing, transmission, storage and distribution facilities are required to report their GHG emissions on an annual basis. We do not expect that the EPA’s mandatory GHG reporting requirements will have a material adverse effect on our business, financial condition or results of operations.

The adoption of additional legislation or regulatory programs to monitor or reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory requirements. In addition, the EPA has stated that the data collected from GHG emissions reporting programs may be the basis for future regulatory action to establish substantive GHG emissions factors. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our future business, financial condition and results of operations.

Water Discharges

The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws, impose restrictions and strict controls on the discharge of pollutants and fill material, including spills and leaks of oil and other substances into regulated waters, including wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, an analogous state agency, or, in the case of fill material, the United States Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The Safe Drinking Water Act, Groundwater Protection and the Underground Injection Control Program

Fluids associated with oil and gas production result from operations on the Company’s properties and may be disposed by injection in underground disposal wells. The federal Safe Drinking Water Act (“SDWA”) and the Underground Injection Control program (the “UIC program”) promulgated under the SDWA and state programs regulate the drilling and operation of saltwater disposal wells. The EPA has delegated administration of the UIC program for Class II injection wells (including saltwater disposal wells) in Texas to the Railroad Commission of Texas (“RRC”). Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater to groundwater. Contamination of groundwater by oil and gas drilling, production and related operations may result in fines, penalties and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third-party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages and bodily injury.

In addition, several cases have recently spotlighted the issue of whether injection wells may be regulated under the CWA if a direct hydrological connection to jurisdictional surface water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019. Those petitions are currently pending. The EPA has also brought attention to the reach of the CWA’s jurisdiction in such instances by issuing a request for comment in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs. To date, no further action has been taken by the EPA with respect to the issue, but should CWA permitting be required for saltwater injections wells, the costs of permitting and compliance for our operations could increase.

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Currently, the Company believes that disposal well operations on its properties substantially comply with all applicable requirements under the SDWA and RRC rules. However, a change in the regulations or in how courts or governmental agencies interpret existing laws or the inability to obtain permits for new disposal wells in the future may affect the Company’s ability to dispose of produced waters and ultimately increase the cost of the Company’s operations. For example, there exists a growing concern that the injection of saltwater and other fluids into underground disposal wells triggers seismic activity in certain areas, including in some parts of Texas. In response to these concerns, in 2014, the RRC published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If thepermittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. These recent seismic permitting requirements applicable to disposal wells impose more stringent permitting requirements and are likely to result in added costs to comply or perhaps may require alternative methods of disposing of saltwater and other fluids, which could delay production schedules and also result in increased costs.

Hydraulic Fracturing

Hydraulic fracturing is the subject of significant focus among some environmentalists, regulators and the general public. Concerns over potential hazards associated with the use of hydraulic fracturing and its impact on the environment have been raised at all levels, including federal, state and local, as well as internationally. There have been claims that hydraulic fracturing may contaminate groundwater, reduce air quality or cause earthquakes. Hydraulic fracturing requires the use and disposal of water, and public concern has been growing over its possible effects on drinking water supplies, as well as the adequacy of water supply.

The Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. In the past, legislation has been introduced in, but not passed by, Congress that would amend the SDWA to repeal this exemption. Specifically, the FRAC Act has been introduced in each Congress since 2008 to accomplish these purposes, and on May 9, 2013, the FRAC Act was again introduced. If similar legislation were enacted, it could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations and meet plugging and abandonment requirements. Future federal legislation could also require the reporting and public disclosure of chemical additives used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemical additives used in the fracturing process could adversely affect groundwater. If federal legislation regulating hydraulic fracturing is adopted in the future, it could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

In 2010, the EPA asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the UIC program by posting a requirement on its website that requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations. Following a legal challenge by industry groups and a subsequent settlement, in February 2014, the EPA issued revised guidance on the use of diesel in hydraulic fracturing operations. Under the guidance, EPA broadly defined “diesel” to include fuels such as kerosene that have not traditionally been considered diesel. The EPA’s continued assertion of its regulatory authority under the SDWA could result in extensive requirements that could cause additional costs and delays in the hydraulic fracturing process.

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In addition to the above actions of the EPA, certain members of the Congress have called upon (i) the Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; (ii) the Securities and Exchange Commission (the “SEC”) to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale by means of hydraulic fracturing; and (iii) the Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. The EPA has also studied the potential environmental impacts of hydraulic fracturing on water resources, publishing draft results in 2015. These and future investigations and studies, depending on their degree of pursuit and any meaningful results obtained, could facilitate initiatives to further regulate hydraulic fracturing.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has also begun a study of the potential environmental impacts of hydraulic fracturing.

Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in hydraulic fracturing. For example, pursuant to legislation adopted by the State of Texas in June 2011, the RRC enacted a rule in December 2011, requiring disclosure to the RRC and the public of certain information regarding additives, chemical ingredients, concentrations and water volumes used in hydraulic fracturing. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general and hydraulic fracturing in particular.

If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted, it could become more difficult or costly for us to drill and produce oil and gas from shale and tight sands formations and become easier for third parties opposing hydraulic fracturing to initiate legal proceedings. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to delays, additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and higher costs. These new laws or regulations could cause us to incur substantial delays or suspensions of operations and compliance costs and could have a material adverse effect on our business, financial condition and results of operations.

Compliance

We believe that we are in substantial compliance with all existing environmental laws and regulations that apply to our current operations and that our ongoing compliance with existing requirements will not have a material adverse effect on our business, financial condition or results of operations. We did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2018. In addition, as of the date of this report, we are not aware of any environmental issues or claims that will require material capital or operating expenditures during 2019. However, the passage of additional or more stringent laws or regulations in the future could have a negative effect on our business, financial condition and results of operations, including our ability to develop our undeveloped acreage.

Threatened and Endangered Species, Migratory Birds and Natural Resources

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. The United States Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Where takings of, or harm to, species or damages to wetlands, habitat or natural resources occur or may occur, government entities or at times private parties may act to prevent oil and gas exploration activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and may seek natural resources damages and, in some cases, criminal penalties.

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OSHA and Other Laws and Regulations

We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Administration

Office Facilities – The office space for the Company's executive office is located at 609 Castle Ridge Road, Suite 335, Austin, Texas 78746.

Employees – As of March 28, 2019, the Company had 3 employees, and the Company considers its relationship with its employees satisfactory.

ITEM 1A – RISK FACTORS.

Going concern

We had a net loss of $3,252,258 for the year ended December 31, 2018, and had an operating loss of $3,436,279. We have net income of $2,666,253 for the year ended December 31, 2017, but had an operating loss of $1,112,597. We expect that the Company will continue to experience operating losses and may have negative cash flow for so long as commodity prices remain depressed. The notes to our financial statements for the fiscal years ended December 31, 2018 and 2017, include an explanatory paragraph expressing substantial doubt as to our ability to continue as a going concern. The financial statements have been prepared "assuming that the Company will continue as a going concern." Our ability to continue as a going concern is dependent on raising additional capital to fund our operations and ultimately on generating future profitable operations. There can be no assurance that we will be able to raise sufficient additional capital or continue to have positive cash flow from operations to address all of our cash flow needs. If we are not able to find alternative sources of cash or generate sufficient positive cash flow from operations, our business and shareholders may be materially and adversely affected.

Failure to comply with any of the financial covenants contained in our revolving credit facility could cause an event of default and have a material adverse effect on our business.

Our revolving credit facility includes three principal financial covenants: (i) an interest coverage ratio, (ii) a current ratio and (iii) a leverage ratio covenant. Failure to comply with these covenants could cause an event of default under our revolving credit facility and have a material adverse effect on our business. As of December 31, 2018, we were not in compliance with all three ratios. Without further deleveraging actions, we do not expect to regain compliance in 2019. A failure to comply with the covenants, ratios or tests in our revolving credit facility, or any future indebtedness, could result in an event of default. If an event of default occurs and is not cured or waived, our lenders, (i) would not be required to lend any additional amounts to us, (ii) could elect to declare all outstanding borrowings, together with accrued and unpaid interest and fees to be due and payable, (iii) could require us to apply all of our available cash to repay these borrowings and (iv) could prevent us from making debt service payments under our other agreements. A potential event of default and subsequent acceleration of indebtedness would have a material adverse effect on our business, financial condition and results of operations, and raises substantial doubt about our ability to continue as a going concern.

Our lenders can limit our borrowing capabilities, which may materially impact our operations.

The borrowing base under our revolving credit facility is redetermined semi-annually based upon a number of factors, including commodity prices and reserve levels. In addition to such semi-annual redeterminations, our lenders may request one additional redetermination during any 12-month period. Upon such redetermination, our borrowing base could be reduced, and if the amount outstanding under our revolving credit facility at any time exceeds the borrowing base at such time, we may be required to repay a portion of our outstanding borrowings. A downward redetermination would materially decrease our available liquidity, and if it causes our borrowings to exceed our borrowing base, we may not have sufficient liquidity to repay those amounts, which would result in an event of default under our revolving credit facility.

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In the current commodity price environment, our borrowing base may be reduced following the upcoming semi-annual redetermination. We use cash flow from operations and bank borrowings to fund our exploration, development and acquisition activities. A reduction in our borrowing base could limit those activities. In addition, we may significantly change our capital structure to cover our working capital needs, make future acquisitions or develop our properties. Changes in capital structure may significantly increase our debt. If we incur additional debt for these or other purposes, the related risks that we now face could intensify. A higher level of debt also increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of debt depends on our future performance, which is affected by general economic conditions and financial, business and other factors, many of which are beyond our control.

Oil and gas operations are risky.

We compete in the areas of oil and gas exploration, production, development and transportation with other companies, many of which may have substantially larger financial and other resources. The nature of the oil and gas business also involves a variety of risks, including the risks of operating hazards such as fires, explosions, cratering, blow-outs, and encountering formations with abnormal pressures, the occurrence of any of which could result in losses to us. We maintain insurance against some, but not all, of these risks in amounts that management believes to be reasonable in accordance with customary industry practices. The occurrence of a significant event, however, that is not fully insured could have a material adverse effect on our financial position.

A continuation of the decline in oil and natural gas prices would have a material impact on us.

Our future financial condition and results of operations are dependent upon the prices we receive for our oil and natural gas production. Oil and natural gas prices historically have been volatile and more recently depressed and likely will continue to be volatile and depressed in historical standards in the future. This price volatility and depression will also affect our common stock price. We cannot predict oil and natural gas prices and prices may decline even further in the future. The following factors have an influence on oil and natural gas prices, including but not limited to:

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changes in the supply of and demand for oil and natural gas;

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storage availability;

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weather conditions;

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market uncertainty;

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domestic and foreign governmental regulations;

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the availability and cost of alternative fuel sources;

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the domestic and foreign supply of oil and natural gas;

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the price of foreign oil and natural gas;

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refining capacity;

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political conditions in oil and natural gas producing regions, including the Middle East; and

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overall economic conditions.

To counter this volatility we, from time to time, may enter into agreements to receive fixed prices on our oil and gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, we would not benefit from such increases.

Our business will depend on transportation facilities owned by others.

The marketability of our gas production will depend in part on the availability, proximity, and capacity of pipeline systems owned by third parties.  Although we will have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions could adversely affect our ability to produce, gather, and transport oil and natural gas.

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Market conditions could cause us to incur losses on our transportation contracts.

Gas transportation contracts that we may enter into in the future may require us to transport minimum volumes of natural gas. If we ship smaller volumes, we may be liable for the shortfall. Unforeseen events, including production problems or substantial decreases in the price of natural gas, could cause us to ship less than the required volumes, resulting in losses on these contracts.

Our actual production, revenues and expenditures related to our reserves are likely to differ from our estimates of our proved reserves. We may experience production that is less than estimated and drilling costs that are greater than estimated in our reserve reports. These differences may be material.

The proved oil, NGL and gas reserves data included in this report are estimates. Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil, NGL and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:

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historical production from the area compared with production from other similar producing areas;

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the assumed effects of regulations by governmental agencies;

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assumptions concerning future oil, NGL and gas prices; and

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assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.

Because all reserves estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:

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the quantities of oil, NGL and gas that are ultimately recovered;

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the production and operating costs incurred;

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the amount and timing of future development expenditures; and

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future oil, NGL and gas prices.

Estimates of proved undeveloped reserves are even less reliable than estimates of proved developed reserves. Furthermore, different reserve engineers may make different estimates of reserves and future net revenues based on the same available data. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material.

Estimating our reserves future net cash flows is difficult to do with any certainty.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control. The reserve data included in this report represents only estimates.  Reserve engineering is a subjective process of estimating underground accumulations of 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, the precision of the engineering and geological interpretation, and judgment. As a result, estimates of different engineers often vary. The estimates of reserves, future cash flows, and present value are based on various assumptions, including those prescribed by the Securities and Exchange Commission, and are inherently imprecise. There is no assurance that our present oil and gas wells will continue to produce at current or anticipated rates of production, or that production rates achieved in early periods can be maintained. Actual future production, cash flows, taxes, operating expenses, and quantities of recoverable oil and natural gas reserves may vary substantially from our estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

Quantities of proved reserves are estimated based on economic conditions, including oil and natural gas prices in existence at the date of assessment. A reduction in oil and natural gas prices not only would reduce the value of any proved reserves, but also might reduce the amount of oil and natural gas that could be economically produced, thereby reducing the quantity of reserves. Our reserves and future cash flows may be subject to revisions, based upon changes in economic conditions, including oil and natural gas prices, as well as due to production results, operating costs, and other factors. Downward revisions of our reserves could have an adverse effect on our financial condition and operating results. 

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Acquiring interests in other properties involves substantial risks.

We evaluate and acquire interests in oil and natural gas properties which in management's judgment will provide attractive investment opportunities for the addition of production and oil and gas reserves. To acquire producing properties or undeveloped exploratory acreage will require an assessment of a number of factors including:

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Value of the properties and likelihood of future production;

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Recoverable reserves;

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Operating costs;

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Potential environmental and other liabilities;

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Drilling and production difficulties; and

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Other factors beyond our control

Such assessments will necessarily be inexact and uncertain. Because of our limited financial resources, we may not be able to evaluate properties in a manner that is consistent with industry practices. Such reviews, therefore, may not reveal all existing or potential problems, nor will they permit us to become sufficiently familiar with such properties to assess fully the deficiencies or benefits.

Operational risks in our business are numerous and could materially impact us.

Oil and natural gas drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. We can make no assurance that wells in which we have an interest will be productive or that we will recover all or any portion of investment costs.

Our operations are also subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, including, but not limited to, such hazards as:

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Fires;

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Explosions;

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Blowouts;

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Encountering formations with abnormal pressures;

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Spills

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Natural disasters;

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Pipeline ruptures;

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Cratering

If any of these events occur in our operations, we could experience substantial losses due to:

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injury or loss of life;

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severe damage to or destruction of property, natural resources and equipment;

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pollution or other environmental damage;

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clean-up responsibilities;

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regulatory investigation and penalties; and

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other losses resulting in suspension of our operations.

In accordance with customary industry practice, we maintain insurance against some, but not all, of the risks described above with a general liability limit of $1 million. We do not maintain insurance for damages arising out of exposure to radioactive material. Even in the case of risks against which we are insured, our policies are subject to limitations and exceptions that could cause us to be unprotected against some or all of the risk. The occurrence of an uninsured loss could have a material adverse effect on our financial condition or results of operations.

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We must comply with environmental regulations.

Exploratory and other oil and natural gas wells must be operated in compliance with complex and changing environmental laws and regulations adopted by federal, state and local government authorities. The implementation of new, or the modification of existing, laws and regulations could have a material adverse effect on properties in which we may have an interest. Discharge of oil, natural gas, water, or other pollutants to the oil, soil, or water may give rise to significant liabilities to government and third parties and may require us to incur substantial cost of remediation. We may be required to agree to indemnify sellers of properties purchased against certain liabilities for environmental claims associated with those properties. We can give no assurance that existing environmental laws or regulations, as currently interpreted, or as they may be reinterpreted in the future, or future laws or regulations will not materially adversely affect our results of operations and financial conditions.

Environmental liabilities could adversely affect our business

In the event of a release of oil, natural gas, or other pollutants from our operations into the environment, we could incur liability for personal injuries, property damage, cleanup costs, and governmental fines.

We could potentially discharge these materials into the environment in any of the following ways:

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from a well or drilling equipment at a drill site;

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leakage from gathering systems, pipelines, transportation facilities and storage tanks;

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damage to oil and natural gas wells resulting from accidents during normal operations; and

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blowouts, cratering, and explosions.

In addition, because we may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in our production of oil and gas and lower returns on our capital investments.

Bills were introduced in the previous U.S. Congress to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used in fracturing fluids by the oil and natural gas industry under the federal Safe Drinking Water Act (“SDWA”) and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, Emergency Planning and Community Right-to-Know Act (“EPCRA”) or other authority. Hydraulic fracturing is an important and commonly used process in the completion of unconventional oil and natural gas wells in shale and tight sand formations. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. We engage third parties to provide hydraulic fracturing or other well stimulation services to us for many of the wells that we drill and operate. Sponsors of such bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies, surface waters, and other natural resources, and threaten health and safety. In addition, the EPA has announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health and the EPA issued a draft study plan on hydraulic fracturing. Certain states have also considered or imposed reporting obligations relating to the use of hydraulic fracturing techniques.

Additional legislation or regulation could make it easier for parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. There has also been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated in Texas and other states implicating hydraulic fracturing practices.

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Legislation, regulation, litigation and enforcement actions at the federal, state or local level that restrict the provision of hydraulic fracturing services could limit the availability and raise the cost of such services, delay completion of new wells and production of our oil and gas, lower our return on capital expenditures and have a material adverse impact on our business, financial condition, results of operations and cash flows and quantities of oil and gas reserves that may be economically produced.

Our operations are subject to cybersecurity risks.

Cybersecurity risks and cyber attacks that threaten information technology systems continue to grow at a rapid pace. These risks include, among other things, terrorist attacks, utility outages, theft, viruses, cyber of phishing-attacks, ransomware, malware, design defects, or human error. Risks associated with these threats include, among other things:

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supply chain and transportation disruptions which could delay or halt our ability to produce and sell oil, NGLs and gas, resulting in a loss of revenues;

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disruption or impairment of our and our customers’ business operations and safety procedures; and

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inability to automatically process commercial transactions or engage in similar or computerized business activities.

Although we utilize various procedures and controls to mitigate our exposure to such risk, cybersecurity attacks and other cyber events are evolving and unpredictable. Any such incident could have a material adverse effect on our business, financial condition and results of operations.

We engage in commodity derivative transactions which involve risks that can harm our business.

To manage our exposure to price risks in the marketing of our production, we may enter into commodity derivative agreements. While intended to reduce the effects of volatile commodity prices, such transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the commodity derivative. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which our production is lower than expected. We are also exposed to the risk of non-performance by the counterparties to the commodity derivative agreements.

Federal and state legislation and regulatory initiatives and private litigation relating to hydraulic fracturing could stop or delay our development project and result in materially increased costs and additional operating restrictions.

All of our proved non-producing and proved undeveloped reserves associated with future drilling and completion projects could require hydraulic fracturing. If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to drill and produce from our proved reserves, as well as make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to permitting delays and increases in costs. These developments, as well as new laws or regulations, could cause us to incur substantial compliance costs, and compliance or the consequences of our failure to comply could have a material adverse effect on our financial condition and results of operations. In addition, if we are unable to use hydraulic fracturing in completing our wells or hydraulic fracturing becomes prohibited or significantly regulated or restricted, we could lose the ability to drill and complete the projects for our proved reserves and maintain our current leasehold acreage, which would have a material adverse effect on our future business, financial condition and results of operations.

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve using some of the latest drilling and completion techniques available to us and our service providers. Risks that we face while drilling horizontal wells include, but are not limited to:

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landing our wellbore in the desired drilling zone;

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staying in the desired drilling zone while drilling horizontally through the formation;

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running our casing the entire length of the wellbore; and

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being able to run tools and other equipment consistently through the horizontal wellbore.

Risks that we face while completing our wells include, but are not limited to:

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the ability to fracture stimulate the planned number of stages;

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the ability to run tools the entire length of the wellbore during completion operations; and

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the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

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Changes in tax laws may adversely affect our results of operations and cash flows.

In recent years there has been introduced, from time to time, proposed legislation that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain key United States federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to:  

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repeal of the percentage depletion allowance for oil and gas properties;

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elimination of current deductions for intangible drilling costs;

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elimination of the domestic manufacturing deduction for oil and gas companies; and

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extension of the amortization period for certain geological and geophysical expenditures.

It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or otherwise limit certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively impact our financial condition and results of operations.

U.S. federal income tax reform could adversely affect us.

On December 22, 2017, President Trump signed into law the Tax Cuts and Jobs Act (the “TCJA”) that significantly reforms the Code. The TCJA, among other things, includes changes to U.S. federal tax rates and allows for the expensing of capital expenditures. While past legislative proposals have included changes to certain key U.S. federal income tax provisions currently available to oil and gas companies including (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures, these specific changes are not included in the TCJA. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. However, the TCJA (i) eliminates the deduction for certain domestic production activities, (ii) imposes new limitations on the use of NOLs, (iii) limits the deductibility of performance based compensation to executive officers and (iv) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and significant additional limitations on the deductibility of interest, which may impact the taxation of oil and gas companies. This legislation or any future changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on our financial position, results of operations, and cash flows.

We do not expect tax reform to have a material impact to our projection of cash taxes or to our NOLs. Our net deferred tax assets and liabilities have been revalued at the newly enacted U.S. corporate rate, and the impact was recognized in our tax expense in the year of enactment. We continue to examine the impact this tax reform legislation may have on our business. The impact of this tax reform on holders of our common stock is uncertain and could be adverse.

Oil, NGL and gas prices are volatile. Continued depressed oil, NGL or gas prices would adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure requirements and financial commitments.

Our revenues, profitability and cash flow depend substantially upon the prices and demand for oil, NGLs and gas. The markets for these commodities are volatile, and even relatively modest drops in prices can affect significantly our financial results and impede our growth. Prices for oil, NGLs and gas fluctuate widely in response to changes in the supply and demand for these commodities, market uncertainty and a variety of additional factors beyond our control, such as:

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domestic and foreign supply of oil, NGLs and gas;

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domestic and foreign consumer demand for oil, NGLs and gas;

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overall United States and global economic conditions impacting the global supply of and demand for oil, NGLs and gas;

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the willingness and ability of OPEC to set and maintain oil price and production controls;

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commodity processing, gathering and transportation availability, the availability of refining capacity and other factors that result in differentials to benchmark prices;

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price and availability of alternative fuels;

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price and quantity of foreign imports;

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domestic and foreign governmental regulations;

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political conditions in or affecting other oil and natural gas producing countries;

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weather conditions, including unseasonably warm winter weather and tropical storms; and

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technological advances affecting oil, NGL and gas consumption.

Advanced drilling and completion technologies, such as horizontal drilling and hydraulic fracturing, have resulted in increased investment by oil and gas producers in developing U.S. shale oil and gas projects and, therefore, has resulted in increased production from these projects. The results of higher investment in the exploration for and production of U.S. shale oil, maintenance of production levels of oil from the Middle East, and other factors, such as global economic and financial conditions, have caused the price of oil to fall and become more volatile over the last several years. Over the six month period ending December 31, 2018, the WTI Spot prices for oil per barrel (“Bbl”) have decreased by approximately 40% from the year high of $76. During the 52-week period ended December 31, 2018, the prices for oil per barrel ranged from a high of $76 to a low of $44 per Bbl, with the closing price on December 31, 2018, of approximately $45. Prices have rebounded slightly but may continue to be volatile and possibly decrease back to levels experienced during the last few years.

The Company’s financial position, results of operations, access to capital and the amount of oil and gas that may be economically produced would be negatively impacted if oil and gas prices stay depressed for an extended period of time.

The ways that continued low oil and gas prices could affect us include the following:

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Cash flows would be reduced, decreasing funds available for capital expenditures needed to maintain or increase production and replace reserves;

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Future net cash flows from our properties would decrease, which could result in significant impairment expenses;

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Some reserves would no longer be economic to produce, leading to lower proved reserves, production and cash flows; and

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Access to capital, such as equity or long-term debt markets and current reserve-based lending levels, would be severely limited or unavailable.

If the current decline in oil prices continues, it is unlikely that our future cash flows will be sufficient to fund the capital expenditure levels necessary to maintain current production and reserve levels over the long term and our results of operations would be adversely affected.

Lower oil and gas prices would not only cause our revenues and cash flows to decrease but also would reduce the amount of oil and gas that we can produce economically. Substantial decreases in oil and gas prices will render uneconomic some or all of our drilling locations. This has and may continue to result in our having to impair our estimated proved reserves and could have a material adverse effect on our business, financial condition and results of operations. As we experienced with the recent downward adjustment of our borrowing base under our credit facility with Citibank, a decline in oil, NGL or gas prices for an extended period of time can result in our being unable to maintain or increase our borrowing capacity, repay current or future debt or obtain additional capital on attractive terms, all of which can affect the value of our common stock. The amount available for borrowing under our revolving credit facility is subject to a borrowing base, which is determined by our lenders taking into account our estimated proved reserves and is subject to semi-annual redeterminations based on pricing models determined by the lenders at such time.

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We may not be able to generate enough cash flow to meet our debt obligations.

We expect our earnings and cash flow to vary significantly from year to year due to the nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments. In December 2016, our borrowing base with our senior lender was $5.5 million, at which time our outstanding drawn balance was approximately $6.5 million. In 2017, our senior lender decreased our borrowing base to approximately $2.7 which was equivalent to our outstanding drawn balance as of December 31, 2017, and the revolving credit facility matured in October 2016. Our borrowing base was lowered again on June 30, 2018, to $2,585,132, which was equivalent to our outstanding drawn balance as of December 31, 2018. We entered into a Forbearance Agreement in October 2016, which ran through January 1, 2018, and was amended December 29, 2017, March 31, 2018, June 30, 2018 and September 30, 2018. Although the Forbearance Agreement was again amended September 30, 2018, and again March 31, 2019, and was extended to June 30, 2019, we are currently in default under the line of credit, and as senior secured lender, Citibank could foreclose on our assets. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control. If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

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selling assets;

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reducing or delaying capital investments;

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seeking to raise additional capital; or

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refinancing or restructuring our debt.

If, for any reason, we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable, which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements. If amounts outstanding under our revolving credit facility were to be accelerated, we cannot be certain that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders.

Our lenders can limit our borrowing capabilities, which may materially impact our operations.

At December 31, 2018, we had approximately $2.6 million in borrowings outstanding under our revolving credit facility. Our borrowing base was reduced by our senior lender to approximately $2.6 million due to the decrease in our reserve base in 2015 and sale of properties in 2017. The outstanding balance under our revolving credit facility is equal to the new borrowing base of $2.6 million. The borrowing base under our revolving credit facility is redetermined semi-annually based upon a number of factors, including commodity prices and reserve levels. In addition to such semi-annual redeterminations, our lenders may request one additional redetermination during any 12-month period. Upon a further redetermination in 2019, our borrowing base could be reduced again, and if the amount outstanding under our revolving credit facility at any time exceeds the borrowing base at such time, we may be required to repay a portion of our outstanding borrowings. If the significant reduction in commodity prices continues or accelerates, it is likely that our borrowing base will be reduced further in the next semi-annual borrowing base redetermination. We use cash flow from operations and bank borrowings to fund our exploration, development and acquisition activities. A reduction in our borrowing base could limit those activities. In addition, we may significantly change our capital structure to cover our working capital needs, make future acquisitions or develop our properties. Changes in capital structure may significantly increase our debt. If we incur additional debt for these or other purposes, the related risks that we now face could intensify. A higher level of debt also increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of debt depends on our future performance, which is affected by general economic conditions and financial, business and other factors, many of which are beyond our control.

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Our revolving credit facility and the indenture governing our revolving credit facility contain operating and financial restrictions and covenants that may restrict our business and financing activities or that economic conditions and commodity prices may cause us to breach.

Our revolving credit facility contains, and any future indebtedness we incur may contain, a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

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sell assets, including equity interests in our subsidiaries;

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consolidate, merge or transfer all or substantially all of our assets;

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incur or guarantee additional indebtedness or issue preferred stock;

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redeem or prepay other debt;

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pay distributions on, redeem or repurchase our common stock or redeem or repurchase our subordinated debt;

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create or incur certain liens;

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make certain acquisitions and investments;

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enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

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engage in transactions with affiliates;

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create unrestricted subsidiaries;

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enter into financing transactions; and

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engage in certain business activities.

Our revolving credit facility provides for certain financial covenants and ratios measured quarterly which include a current ratio, leverage ratio, and interest coverage ratio requirements. The Company is out of compliance with all three ratios as of December 31, 2018, and is in technical default of the agreement. Furthermore, the borrowing base under our line of credit was redetermined December 29, 2017, based on the value of proved reserves, and was reduced from $5.5 million to $2.7 million. Our borrowing base was lowered again on June 30, 2018, to $2,585,132. As a result of the redetermination of the credit base, the Company does not have any capacity in its borrowing base as of December 31, 2018.  

In October 2016, we executed a sixth amendment to the original loan agreement, which provided for Citibank’s forbearance from exercising remedies relating to the current defaults including the principal payment deficiencies. The Forbearance Agreement ran through January 1, 2018, and required that we make a $500,000 loan principal pay down by September 30, 2017, and adhere to other requirements including weekly cash balance reports, quarterly operating reports, monthly accounts payable reports and that we pay all associated legal expenses. Furthermore, under the agreement Citibank may sweep any excess cash balances exceeding a net amount of $800,000 less equity offering proceeds, which will be applied towards the outstanding principal balance. The Agreement was extended by a closing letter agreement to allow the Company time to pay the associated legal costs and solidify the Deposit/Withdraw at Custodian Agreements (“DEWAC”) as provided for in the Forbearance Agreement.

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On December 29, 2017, we executed the seventh amendment to the Loan Agreement and the first amendment to the Forbearance Agreement, which reduced our borrowing base to $2,761,632 (our line of credit balance at December 31, 2017), and provided for Citibank’s forbearance from exercising remedies relating to the existing defaults, including the principal payment deficiencies. This amended Forbearance Agreement ran through March 31, 2018, and required that we adhere to certain reporting requirements, such as weekly cash reports, and that we pay all fees and expenses of Citibank’s counsel invoiced on or before the effective date. On March 30, 2018, we executed the eighth amendment to the Loan Agreement and the second amendment to the Forbearance Agreement which extended it to June 30, 2018. The terms of the second amendment to the Forbearance Agreement remained the same as under the foregoing first amendment. On July 25, 2018, we executed the ninth amendment to the Loan Agreement and the third amendment to the Forbearance Agreement which extended it to September 30, 2018. The terms of the ninth amendment to the Loan Agreement and the third amendment to the Forbearance Agreement increased the interest rate 2% and reduced our borrowing base $176,500 to our current line of credit balance of $2,585,132. On November 7, 2018, we executed the tenth amendment to the Loan Agreement and the fourth amendment to the Forbearance Agreement which extended it to March 31, 2019. The terms of the fourth amendment to the Forbearance Agreement remained the same as the foregoing third amendment. On March 25, 2019, we executed the eleventh amendment to the Loan Agreement and the fifth amendment to the Forbearance Agreement, which extended it to June 30, 2019. The terms of the fifth amendment to the Forbearance Agreement are substantially the same as under the forgoing fourth amendment.

If an event of default under our revolving credit facility occurs and remains uncured, it could have a material adverse effect on our business, financial condition and results of operations. The lenders

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would not be required to lend any additional amounts to us;

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could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;

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may have the ability to require us to apply all of our available cash to repay these borrowings; or

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may prevent us from making debt service payments under our other agreements.

Price declines during 2015 resulted in a material write down of the carrying values of our properties, and further price declines could result in additional write downs in the future, which would negatively impact our net income and results of operations. Additionally, current SEC rules also could require us to write down our proved undeveloped reserves in the future.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write-down is a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. The risk that we will be required to write down the carrying value of our properties increases when oil and gas prices are low or volatile.

In addition, current SEC rules require that proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years, unless specific circumstances justify a longer time. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our development projects. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required timeframe or if continued, depressed prices cause us to change our development plan to decrease the number of wells to be drilled over the five-year period.

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The Standardized Measure of our estimated reserves and PV-10 included in this report should not be considered as the current market value of the estimated oil and gas reserves attributable to our properties.

Standardized Measure is a reporting convention that provides a common basis for comparing oil and gas companies subject to the rules and regulations of the SEC. Standardized Measure requires the use of specific pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. The non-GAAP financial measure, PV-10, is based on the average of the closing price on the first day of the month for the 12-month period prior to fiscal year end, while actual future prices and costs may be materially higher or lower.

Consequently, these measures may not reflect the prices ordinarily received or that will be received for oil and gas production because of varying market conditions, nor may they reflect the actual costs that will be required to produce or develop the oil and gas properties. Accordingly, estimates included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the Standardized Measure of our estimated reserves and PV-10 included in this report should not be construed as accurate estimates of the current fair value of our proved reserves. In addition, the 10% discount factor we use when calculating PV-10 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Actual future net revenues also will be affected by factors such as the amount and timing of actual production, prevailing operating and development costs, supply and demand for oil and gas, increases or decreases in consumption and changes in governmental regulations or taxation.

Competition in the oil and natural gas industry is intense, and we are smaller and have a more limited operating history than many of our competitors.

We compete with major integrated oil and gas companies and independent oil and gas companies in all areas of operation. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop these properties. Most of our competitors have substantially greater financial and other resources than we have. 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 properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than we can. Further, our competitors may have technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for natural gas and oil prospects and to acquire additional 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, most of our competitors have operated for a much longer time than we have and have demonstrated the ability to operate through industry cycles.

Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner.

Water is an essential component of our drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local landowners and other sources for use in our operations. During the last three years, much of the Southwest region where we operate has experienced extreme drought conditions. As a result of the severe drought, governmental authorities have restricted the use of water subject to their jurisdiction for drilling and hydraulic fracturing to protect the local water supply. If we are unable to obtain water to use in our operations, we may be unable to economically produce oil, NGLs and gas, which could have an adverse effect on our business, financial condition and results of operations.

Moreover, new environmental initiatives and regulations could include restrictions on disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas. Compliance with environmental regulations and permit requirements for the withdrawal, storage and use of surface water or ground water necessary for hydraulic fracturing may increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations and cash flows.

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Climate change legislation or regulations regulating emissions of GHGs and VOCs could result in increased operating costs and reduced demand for the oil and gas we produce.

Both houses of Congress have actively considered legislation to reduce emissions of GHGs, and some states have already taken measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap-and-trade programs. Most of these cap-and-trade programs require either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances are expected to escalate significantly in cost over time.

In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has also issued final regulations under the NSPS and NESHAP designed to reduce VOCs. The adoption of legislation or regulatory programs to reduce GHG or VOC emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG or VOC emissions could have a material adverse effect on our business, financial condition and results of operations.

Governmental regulations can hinder production.

Domestic oil and natural gas exploration, production and sales are extensively regulated at both the federal and state levels. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, have legal authority to issue, and have issued, rules and regulations affecting the oil and natural gas industry which often are difficult and costly to comply with and which carry substantial penalties for noncompliance. State statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning operations. Most states where we operate also have statutes and regulations governing conservation matters, including the unitization or pooling of properties. Our operations are also subject to numerous laws and regulations governing plugging and abandonment, discharging materials into the environment or otherwise relating to environmental protection. The heavy regulatory burden on the oil and natural gas industry increases its costs of doing business and consequently affects its profitability. Changes in the laws, rules or regulations, or the interpretation thereof, could have a materially adverse effect on our financial condition or results of operation.

Minority or royalty interest purchases do not allow us to control production completely.

We sometimes acquire less than the controlling working interest in oil and natural gas properties. In such cases, it is likely that these properties would not be operated by us. When we do not have controlling interest, the operator or the other co-owners might take actions we do not agree with and possibly increase costs or reduce production income in ways we do not agree with.

Environmental regulations can hinder production.

Oil and natural gas activities can result in liability under federal, state and local environmental regulations for activities involving, among other things, water pollution and hazardous waste transport, storage, and disposal. Such liability can attach not only to the operator of record of the well, but also to other parties that may be deemed to be current or prior operators or owners of the wells or the equipment involved. We have inspections performed on our properties to assure environmental law compliance, but inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken.

24

Government regulations could increase our operating costs

Oil and natural gas operations are subject to extensive federal, state and local laws and regulations relating to the exploration for, and development, production and transportation of, oil and natural gas, as well as safety matters, which may change from time to time in response to economic conditions. Matters subject to regulation by federal, state and local authorities include:

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Permits for drilling operations;

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The production and disposal of water;

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Reports concerning operations;

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Unitization and pooling of properties;

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Road and pipeline construction;

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The spacing of wells;

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Taxation;

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Production rates;

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The conservation of oil and natural gas; and

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Drilling bonds.

Many jurisdictions have at various times imposed limitations on the production of oil and natural gas by restricting the rate of flow for oil and natural gas wells below their actual capacity to produce. During the past few years there has been a significant amount of discussion by legislators and the presidential administration concerning a variety of energy tax proposals. There can be no certainty that any such measure will be passed or what its effect will be on oil and natural gas prices if it is passed. In addition, many states have raised state taxes on energy sources and additional increases may occur, although there can be no certainty of the effect that increases in state energy taxes would have on oil and natural gas prices. Although we believe it is in substantial compliance with applicable environmental and other government laws and regulations, there can be no assurance that significant costs for compliance will not be incurred in the future.

We have not paid cash dividends and do not anticipate paying any cash dividends on our common stock in the foreseeable future.

We anticipate that we will retain all future earnings and other cash resources for the future operation and development of our business. We do not intend to declare or pay any cash dividends in the foreseeable future. Payment of any future dividends will be at the discretion of our Board of Directors after taking into account many factors, including our operating results, financial condition, current and anticipated cash needs, and other factors. Moreover, there may be no capacity for the Company to declare a cash dividend in the near future.

We failed to regain compliance with NYSE MKT listing standards in November 2017 and our shares were delisted.

On May 11, 2016, the Company received notification from the NYSE MKT that it was noncompliant with the NYSE MKT continued listing standards; specifically, Section 1003(a)(i) of the NYSE MKT Company Guide in that the Company’s stockholders’ equity is below the $2.0 million threshold required for listed companies that have reported losses from continuing operations in two of its three most recently completed fiscal years. The notice also provided a warning on possible noncompliance with the continued listing standard set forth in Section 1003(a)(iv) related to financial impairment based upon the Company’s accumulated deficits.  In order to maintain its listing, the Company submitted a plan of compliance addressing how it intended to regain compliance with Section 1003(a)(i) of the Company Guide by November 13, 2017.

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On July 22, 2016, the Company received notification from NYSE Regulation that its plan of compliance submitted to NYSE Regulation on June 10, 2016, as supplemented, setting forth the Company’s plan to regain compliance with Section 1003(a)(i) of the NYSE MKT Company Guide was accepted and that our listing is being continued pursuant to an extension to November 13, 2017. Additionally, on April 28, 2017, the Company received notification from the NYSE American (formerly NYSE MKT) that it was noncompliant with the NYSE American (formerly NYSE MKT) continued listing standards; specifically, Section 1003(a)(ii) of the Company Guide.  The Company’s stockholders’ equity has been below the $2.0 million threshold required for listed companies that have reported losses from continuing operations in two of its three most recently completed fiscal years (Section 1003(a)(i)) and is now below the $4.0 million threshold required for listed companies that have reported losses from continuing operations in three of its four most recent fiscal years (Section 1003(a)(ii)). The Company was given the opportunity to and submitted a supplement to the Plan to address how it intends to regain compliance with Section 1003(a)(ii).  The Plan period to regain compliance with all of the continued listing standards by November 13, 2017, was the same. The Company was subject to periodic reviews by the Exchange.

The Company was not in compliance with the continued listing standards by November 13, 2017, and received an official delisting notice on November 16, 2017, which could have a significant adverse impact on our ability to raise additional capital.

Our warrants were also delisted from the NYSE American (formerly NYSE MKT) on November 17, 2017, and then expired March 23, 2018.

Our shares are now traded on the over-the-counter market under the symbol FPPP which is more volatile than the Exchange, and may result in a continued diminution in value of our shares. Our delisting also resulted in the loss of other advantages to an exchange listing, including marginability, blue sky exemptions and others.

ITEM 1B. – UNRESOLVED STAFF COMMENTS.

None.

ITEM 2-PROPERTIES

Principal Oil and Natural Gas Interests

Block A-49, Andrews County, Texas is a producing oil field located in Andrews, Texas. The Company owns a 74%-100% working interest in three producing oil wells and three injection wells producing out of the Devonian and Ellenburger formations at an approximate depth of 7,000 to 9,000 feet.

Spraberry Trend, Midland County, Texas is a producing oil and natural gas field located 6 miles east of Midland, Texas. The Company owns a 6.5% working interest in one oil and natural gas well producing out of the Spraberry formation at a depth of approximately 7,000 feet. We divested our Buchanan wells, being all of our working interest in the wellbores and associated acreage, dated effective April 1, 2018, but retained our interest in the McClintic A#1 wellbore.

Flying M Field, Lea County, New Mexico is a producing oil and natural gas field located outside of Hobbs, New Mexico. The Company owns a 39.25% working interest in two oil and natural gas wells producing out of the ABO formation at a depth of approximately 8,300 feet.

Sulimar Field, Chaves County, New Mexico is a producing oil field located 35 miles north east of Artesia, New Mexico. The Company has a 100% working interest in one oil well producing out of the Queen formation at a depth of approximately 1,800 feet.

North Bilbrey Field, Lea County, New Mexico is a producing natural gas field located outside of Hobbs, New Mexico. The Company owns a 50% working interest in the North Bilbrey #7 federal well producing out of the Atoka formation at approximately 13,000 feet.

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Longwood Field, Caddo Parish, Louisiana is a producing natural gas field located north of Greenwood, Louisiana. The Company owns a 12.22% working interest in two natural gas wells producing out of the Cotton Valley formation at a depth of approximately 7,800 feet.

Lusk Field, Lea County, New Mexico is a producing oil and natural gas field located outside of Hobbs, New Mexico. The Company owns an 87.5%-100% working interest in three oil and natural gas wells producing out of the Bone Spring and Yates formations in Section 15 at depths ranging from approximately 3,400 feet to approximately 10,000 feet and a 43.75% working interest in three wells drilled and producing out of the Bone Spring formation. We also have a 14.06% working interest in one oil and natural gas well producing out of the Wolfcamp formation in Section 14. The Company also owns a 100% working interest in one water disposal well.

West Allen Field, Pontotoc County, Oklahoma is a producing oil and natural gas field located approximately 100 miles south of Oklahoma City, Oklahoma. The Company has a working interest in 52 leases or a total of 224 wells, the leases have multiple wellbores and the Company has plans to participate in the future recompletion of behind pipe zones.

Big Muddy Field, Converse County, Wyoming is a producing oilfield located approximately 30 miles south of Casper, Wyoming. The Company owns a 100% working interest in the Elkhorn and J.C. Kinney lease which consists of four oil wells producing out of the Wallcreek and Dakota formations at depths ranging from approximately 3,200 feet to approximately 4,000 feet.

Serbin Field, Lee and Bastrop Counties Texas is an oil and natural gas field located approximately 50 miles east of Austin and 100 miles west of Houston. The Company has a 25% working interest in 143 producing oil and natural gas wells. Oil and natural gas are produced from the Taylor Sand at depths ranging from approximately 5,300 feet to approximately 5,600 feet; it is a 46-gravity oil sand including four horizontal wells.

Production

The table below sets forth oil and natural gas production from the Company's net interest in producing properties for each of its last two fiscal years.

	Oil (bbl)		Gas (mcf)
Production by State	2018	2017	2018	2017
Louisiana	-	-	5,319	5,534
New Mexico	18,208	20,532	66,480	80,424
Oklahoma	4,386	18,986	6,577	14,445
Texas	6,360	9,456	4,096	11,413
Wyoming	3,143	4,939	-	-
TOTAL	32,097	53,913	82,472	111,816

The Company's oil and natural gas production is sold on the spot market and the Company does not have any production that is subject to firm commitment contracts. During the year ended December 31, 2018, purchases by three customers, Cimarex Energy Co., CP Energy, LLC, and EnergyQuest II, LLC, represented more than 10% of total Company revenues. During the year ended December 31, 2017, purchases by four customers, Cimarex Energy Co., Sunoco, Inc., First River Energy, LLC, and Riley Exploration Group, Inc., represented more than 10% of total Company revenues. None of these customers, or any other customers of the Company, has a firm sales agreement with the Company. The Company believes that it would be able to locate alternate customers in the event of the loss of one or all of these customers. In addition, First River Energy, LLC (FEL) filed for protection under chapter 11 of the federal Bankruptcy code. We filed a proof of claim of approximately $27,000 for December 2017 crude oil production that FEL did not pay us for, although the crude oil was picked up by FEL. We accrued a receivable for this amount at December 31, 2017. However, we also recorded an allowance for bad debts in the same amount since the receipt is uncertain as of December 31, 2018.

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Productive Wells

The table below sets forth certain information regarding the Company's ownership, as of December 31, 2018, of productive wells in the areas indicated.

Productive Wells

	Oil		Gas
State	Gross(1)	Net(2)	Gross(1)	Net(2)
Louisiana	-	-	2	.24
New Mexico	10	6.25	1	.15
Oklahoma	186	42.11	37	4.59
Texas	139	34.82	7	4.10
Wyoming	4	3.45	-	-
Total	339	86.63	47	9.08

1 A gross well or acre is a well or acre 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. The number of gross acres is the total number of acres in which a working interest is owned.

2 A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres expressed as whole numbers and fractions thereof.

Drilling Activity

In December of 2017 the Company recompleted the Arrowhead #2 in Andrews County, Texas as an injection well. The well was perforated and completed in the Devonian and could possibly be completed as a producing Devonian well in the future depending on the availability of additional disposal capacity. The Company did not drill or complete any wells 2018 and we do not expect to drill or complete any wells in 2019.

Reserves

Estimated Proved Reserves/Developed and Undeveloped Reserves: The following tables set forth the estimated proved developed and proved undeveloped oil and gas reserves of FieldPoint for the years ended December 31, 2018 and 2017. See Note 14 to the Consolidated Financial Statements and the following discussion.

Estimated Proved Reserves

Proved Reserves	Oil (Bbls)	Gas (Mcf)
Estimated quantity, January 1, 2017	490,226	756,512
Revisions of previous estimates	33,784	86,221
Extensions and discoveries	-	-
Sale of reserves	(42,085)	(19,657)
Production	(53,913)	(111,816)
Estimated quantity, December 31, 2017	428,012	711,260
Revisions of previous estimates	(46,166)	107,828
Extensions and discoveries	-	-
Sale of reserves	-	-
Production	(32,097)	(82,472)
Estimated quantity, December 31, 2018	349,749	736,616

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Proved Developed and Undeveloped Reserves

	Developed	Undeveloped	Total
Oil (Bbls)
December 31, 2018	349,749	-	349,749
December 31, 2017	428,012	-	428,012
Gas (Mcf)
December 31, 2018	736,616	-	736,616
December 31, 2017	711,260	-	711,260

Proved Undeveloped Reserves

As of December 31, 2018 and 2017, we had no BOE of proved undeveloped (“PUD”) reserves due to lower commodity prices rendering PUD reserves uneconomic.

The Company did not convert any PUD reserves to proved developed reserves during 2018 or 2017 and had no net investment required to convert PUD reserves to proved developed reserves during 2018 or 2017.

The Company has no estimated future development costs relating to the development of PUD reserves at December 31, 2018.

We monitor fluctuations in commodity prices, drilling and completion costs, operating expenses and drilling success to determine adjustments to our drilling and development program. Based on current expectations for cash flows, commodity prices and operating costs and expenses, as well as drilling and completion prices, the company has no plans to drill any wells in the near future.

Preparation of Proved Reserves Estimates

Internal Controls Over Preparation of Proved Reserves Estimates

Our policies regarding internal controls over the recording of reserve estimates require reserve estimates to be in compliance with SEC rules, regulations and guidance and prepared in accordance with generally accepted petroleum engineering principles. Our proved oil and natural gas reserves as of December 31, 2018 and 2017, have been estimated by Russell K. Hall & Associates, Inc. The independent consultants are responsible for overseeing the preparation of our reserve estimates and for internal compliance of our reserve estimates with SEC rules, regulations and generally accepted petroleum engineering principles. Phillip Roberson, President and CFO, provides company data (such as well ownership interests, oil and gas prices, production volumes and well operating costs) to consulting petroleum engineers and is the primary Company officer responsible for reviewing their use of our data and estimation of our reserves. Mr. Roberson, who has over sixteen years of experience in various capacities in the oil and gas exploration industry, provides our consulting petroleum engineers with technical data (such as well logs, geological information and well histories). Mr. Roberson reviews the disclosed changes in reserve estimates and the disclosed changes in the Standardized Measure relating to proved oil and gas reserves.

As defined in the Securities and Exchange Commission Rules, proved reserves are the estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include considerations of changes in existing prices provided only by contractual arrangements but not on escalations based on future conditions. Reservoirs are considered proved if economic production is supported by either actual production or conclusive formation tests. Reserves which can be produced economically through application of improved recovery techniques, such as fluid injections, are included in the “proved” classification when successful testing by a pilot project, or the operations of an installed program in the reservoir, provide support for the engineering analysis on which the project or program was based. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors.

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For information concerning the standardized measure of discounted future net cash flows, estimated future net cash flows and present values of such cash flows attributable to our proved oil and gas reserves as well as other reserve information, see Note 14 to the Consolidated Financial Statements.

Technologies Used in Preparation of Proved Reserves Estimates

Estimates of reserves were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

When applicable, the volumetric method was used to estimate the original oil in place, or OOIP, and the original gas in place, or OGIP. Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure and gas-oil ratio behavior, was used in the estimation of reserves.

Because our proved reserves are located in depletion-type reservoirs and reservoirs whose performance demonstrates a reliable decline in producing-rate trends, reserves were also estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-declining curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses or leases as appropriate.

Reserves Sensitivity Analysis

As permitted by the recently adopted SEC regulations, we have elected not to undertake a sensitivity analysis of our reserves estimates.

Oil and Gas Reserves Reported to Other Agencies:

We did not file any estimates of total proved net oil or gas reserves with, or include such information in reports to, any federal authority or agency during the fiscal year ended December 31, 2018, or subsequently thereafter.

Title Examinations: Oil and Gas:

As is customary in the oil and gas industry, we perform only a perfunctory title examination at the time of acquisition of undeveloped properties. Prior to the commencement of drilling, in most cases, and in any event where we are the Operator, a thorough title examination is conducted and significant defects remedied before proceeding with operations. We believe that the title to our properties is generally acceptable to a reasonably prudent operator in the oil and gas industry. The properties we own are subject to royalty, overriding royalty and other interests customary in the industry, liens incidental to operating agreements, current taxes and other burdens, minor encumbrances, easements and restrictions. We do not believe that any of these burdens materially detract from the value of the properties or will materially interfere with our business.

We have purchased producing properties on which no updated title opinion was prepared. In some, but not all, cases, we have retained third party petroleum landmen to review title.

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Acreage

The following tables set forth the gross and net acres of developed and undeveloped oil and natural gas leases in which the Company had working interest and royalty interest as of December 31, 2018. The category of "Undeveloped Acreage" in the table includes leasehold interest that already may have been classified as containing proved undeveloped reserves.

	Developed		Undeveloped
State	Gross (1)	Net (2)	Gross (1)	Net (2)
Louisiana	160	20	1,120	137
New Mexico	1,320	727	1,960	1,047
Oklahoma	3,580	215	-	-
Texas	5,988	1,844	793	430
Wyoming	320	260	1,136	622
Total	11,368	3,066	5,009	2,236

1 A gross well or acre is a well or acre 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. The number of gross acres is the total number of acres in which a working interest is owned.

2 A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres expressed as whole numbers and fractions thereof.

ITEM 3-LEGAL PROCEEDINGS

We were notified that the operator of our Ranger and Taylor Serbin fields, Riley Exploration Group, Inc., sold all of its working interest to Trivista Operating LLC, which is controlled by one of our major shareholders, Natale Rea (2013) Trust. Along with the working interest, Trivista also claims to have acquired an outstanding disputed invoice of approximately $84,000. We received a demand letter from Trivista’s counsel for this sum. We responded that the invoice was in dispute and we had previously sent a letter to the prior operator demanding an audit of their operations and billing but received no response. Trivista sent a second letter threatening litigation. Trivista claims to have taken over operations of this field in October 2017 but has failed to provide revenue, expense and operating information since April 2018 which is in direct violation of the joint operating agreements which govern these wells. Trivista filed suit for non-payment of outstanding disputed invoices of approximately $107,000 plus attorney fees and court costs on February 26, 2018. We intend to defend ourselves against these claims and possibly seek legal remedies of our own.

The Company was a party to a civil action captioned A.C.T. Equipment Company, LLC v. Fieldpoint Petroleum Corporation, Cause No. 21,191 in the 109th Judicial District Court of Andrews, Andrews County, Texas (the “A.C.T. Litigation”). A.C.T. filed suit for non-payment of outstanding disputed invoices of $18,832 plus attorney fees and court costs on July 24, 2018. The Company settled the lawsuit on September 10, 2018, for a total payment of $13,500. An Order Granting Dismissal with Prejudice was signed by the presiding judge.

On January 12, 2018, we were notified that one of our crude oil purchasers filed Chapter 11 bankruptcy and we would not be receiving payment for our December 2017 production in the amount of approximately $27,000. We have filed a proof of claim in this matter. Since there is no guarantee that we will recover all or any of the amounts owed, the Company has recorded an allowance for bad debt for the same amount as of December 31, 2018.

ITEM 4-SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

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PART II

ITEM 5-MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Since November 17, 2017, the Company’s common stock has been listed on the OTC.QB of the OTC Markets Group, Inc. under the symbol FPPP subsequent to our delisting by the NYSE American LLC, formerly the NYSE Amex. Prior to that and beginning in September 20, 2005, the Company's common stock has been traded and listed on the NYSE American, LLC, formerly the NYSE MKT, LLC, and formerly NYSE Amex and before that the NYSE Alternext and formerly the American Stock Exchange, under the symbol "FPP." Prior to September 20, 2005, the Company’s common stock was listed on the OTC Bulletin Board under the symbol FPPC. The following sets forth the high and low closing prices of our common stock on the NYSE American, LLC for the periods shown.

FISCAL 2017	CLOSING PRICE
	HIGH	LOW
First Quarter	0.78	0.40
Second Quarter	0.52	0.30
Third Quarter	0.41	0.29
Fourth Quarter	0.38	0.10

FISCAL 2018
	HIGH	LOW
First Quarter	0.19	0.15
Second Quarter	0.22	0.12
Third Quarter	0.24	0.17
Fourth Quarter	0.22	0.07

At March 31, 2019, the approximate number of shareholders of record was 226. The Company has not paid any cash dividends on its common stock and does not expect to do so in the foreseeable future.

EQUITY COMPENSATION PLAN INFORMATION

	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuances under equity compensation plans (excluding securities reflected in column
Equity compensation plans approved by security holders	-	-	-
Equity compensation plans not approved by security holders	-	-	-
Total	-	-	-

ITEM 6    SELECTED FINANCIAL DATA

We have set forth below certain selected financial data. The information has been derived from the financial statements, financial information and notes thereto included elsewhere in this report.

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	Years Ended December 31,
	2018	2017
Statements of Operations Data:
Total revenues	$2,169,859	$3,036,132
Operating expenses	5,606,138	4,148,729
Net income (loss)	(3,252,258)	2,666,253
Basic income (loss) per share	$(0.30)	$0.25
Shares used in computing basic earnings per share	10,669,229	10,656,506
Diluted income (loss) per share	$(0.30)	$0.25
Shares used in computing diluted earnings per share	10,669,229	10,656,506

	December 31,
Balance Sheet Data:	2018	2017
Working capital (deficit)	$(3,165,608)	$(3,122,192)
Total assets	4,686,196	7,713,435
Total liabilities	6,136,097	5,911,078
Stockholders' equity (deficit)	(1,449,901)	1,802,357

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

The following discussion should be read in conjunction with the Company's Financial Statements, and respective notes thereto, included elsewhere herein. The information below should not be construed to imply that the results discussed herein will necessarily continue into the future or that any conclusion reached herein will necessarily be indicative of actual operating results in the future. Such discussion represents only the best present assessment of the management of FieldPoint Petroleum Corporation.

Overview

FieldPoint Petroleum Corporation derives its revenues from our operating activities including sales of oil and natural gas and operating oil and natural gas properties. Our capital for investment in producing oil and natural gas properties has been provided by cash flow from operating activities and from bank financing. We categorize our operating expenses into the categories of production expenses and other expenses.

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Results of Operations

	Years Ended December 31,
	2018	2017
Revenues:
Oil sales	$1,875,330	$2,621,019
Natural gas sales	222,357	321,641
Total	$2,097,687	$2,942,660
Sales volumes:
Oil (Bbls)	32,097	53,913
Natural gas (Mcf)	82,472	111,816
Total (BOE)	45,842	72,549
Average sales prices
Oil ($/Bbl)	$58.43	$48.62
Natural gas ($/Mcf)	2.70	2.88
Total ($/BOE)	$45.76	$40.56
Costs and expenses ($/BOE)
Lease operating expense (lifting costs)	$21.93	$25.42
Production taxes	4.55	4.65
Depletion and depreciation	10.24	9.63
Impairment of oil and natural gas properties	56.75	-
Accretion of discount on asset retirement obligations	2.38	1.45
General and administrative	26.44	16.04
Total	$122.29	$57.19

Revenues

Oil and natural gas sales revenues decreased by $844,973 or 29%, due to lower sales volumes of approximately $1,145,000 offset by increased commodity prices of approximately $300,000. Oil sales decreased by approximately $746,000 due to decreased volumes of approximately $1,061,000 but offset by increased prices of $315,000. Oil sales volumes decreased by 40%, primarily due to the sale of our Apache Bromide and Chickasaw Fields in 2017 and natural declines in our Bone Spring and Ranger Horizontal Taylor Serbin wells which were drilled in late 2013 and 2014. Natural gas sales decreased approximately $99,000 or 31%, due to decreased commodity prices of approximately $15,000 plus $84,000 due to lower sales volumes in 2018. Oil and natural gas prices have been volatile during 2018 and 2017, and we expect this to continue. Our oil and natural gas sales revenue will be highly dependent on commodity prices in 2019.

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Lease Operating Expenses

Lease operating expenses decreased $838,798 or 45% primarily due to lower production during 2018. Costs decreased by $3.49 per barrel equivalent (BOE) or 14% in 2018 as compared to 2017. Decreased commodity prices accounted for approximately $160,000 decrease in costs and approximately $679,000 due to lower sales volumes in 2018. Many of our properties are mature and bear high operating expense which could result in increased operating costs in the future.

Production Taxes

Production taxes decreased $128,808 or 38%, primarily the result of lower production volumes in 2018. Production taxes amounted to approximately 10% and 11% of oil and natural gas sales revenue during 2018 and 2017, respectively. We expect production taxes to range between 8% and 11% of oil and natural gas sales revenue.

Depletion and Depreciation

Depletion and depreciation expense decreased by $228,921 or 33% during the year ended December 31, 2018 over the same period in 2017. The decrease in depletion and depreciation was primarily due to a lower depletable base after the sale of oil and natural gas properties in 2017 and to natural declines in production during 2018.

Impairment of Oil and Natural Gas Properties

During the year ended December 31, 2017, the fair value of our properties exceeded the carrying value so no impairment was recorded. During the year ended December 31, 2018, the Company recorded impairment charges of $2,601,714 as a result of writing down the carrying value of two properties to their fair value. The carrying value of the North Block field was written down approximately $2.4 million to its fair value as of December 31, 2018, due to down-hole problems in several well bores. The Company decided they were not economic to workover at this time.

General and Administrative Expense

General and administrative expenses increased $48,223 or 4% primarily due to increases in compensation expense and bad debt expense, offset by decreases in professional services fees and consulting fees. Significant components of general and administrative expenses include personnel-related costs and professional services fees.

Other Income (Expense)

Other income, net for the year ended December 31, 2018, was $178,225 compared to other income, net for the comparable 2017 period of $3,627,829. Gain on sale of oil and natural gas properties was $345,399 and $3,831,837 for the years ended December 31, 2018 and 2017, respectively. Interest expense was $167,734 in 2018, which was a reduction of $36,969 from the prior year.

Going Concern and Liquidity

Our accompanying consolidated financial statements have been prepared assuming that we will continue as a “going concern”, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date that these consolidated financial statements are issued. Crude oil and natural gas prices during 2018 and 2017 have remained considerably lower than their historical highs and these lower prices have had a significant adverse impact on our business and, as a result, on our financial condition and our working capital. Accordingly, substantial doubt exists that we will be able to continue as a “going concern”.

As of December 31, 2018 and 2017, the Company had a working capital deficit of approximately $3,166,000 and $3,122,000, respectively, primarily due to the classification of our line of credit with Citibank as a current liability. The line of credit agreement (“the Loan Agreement”) provides for certain financial covenants and ratios measured quarterly, which include a current ratio, leverage ratio and interest coverage ratio requirements. The Company was out of compliance with all three ratios as of December 31, 2018 and 2017, and we do not expect to regain compliance in 2019. A Forbearance Agreement (“the Forbearance Agreement”) was executed in October 2016 and amended on December 29, 2017, March 30, 2018, June 30, 2018, September 30, 2018 and March 29, 2019, as discussed below.

Citibank is in a first lien position on all of our oil and natural gas properties under the terms of the Loan Agreement. Citibank lowered our borrowing base from $11,000,000 to $5,500,000 on December 1, 2015, and lowered it again to $2,761,632 on December 29, 2017. Our borrowing base was lowered again on June 30, 2018 to $2,585,132.

In October 2016, we executed the sixth amendment to the Loan Agreement, and also executed a Forbearance Agreement which provided for Citibank’s forbearance from exercising remedies relating to the existing defaults, including the principal payment deficiencies. The Forbearance Agreement ran through January 1, 2018, and required that we make a $500,000 loan principal pay down by September 30, 2017, and adhere to other requirements including weekly cash balance reports, quarterly operating reports and monthly accounts payable reports, The Forbearance Agreement also required us to pay all of Citibank’s associated legal expenses. Furthermore, under the Forbearance Agreement, Citibank was allowed to sweep any excess cash balances exceeding a net amount of $800,000 less equity offering proceeds, which would be applied towards the outstanding principal balance of the line of credit.

 35

On December 29, 2017, we executed the seventh amendment to the Loan Agreement and the first amendment to the Forbearance Agreement, which reduced our borrowing base to $2,761,632 (our line of credit balance at December 31, 2017), and provided for Citibank’s forbearance from exercising remedies relating to the existing defaults, including the principal payment deficiencies. This amended Forbearance Agreement ran through March 31, 2018, and required that we adhere to certain reporting requirements, such as weekly cash reports, and that we pay all fees and expenses of Citibank’s counsel invoiced on or before the effective date. On March 30, 2018, we executed the eighth amendment to the Loan Agreement and the second amendment to the Forbearance Agreement which extended it to June 30, 2018. The terms of the second amendment to the Forbearance Agreement remained the same as under the foregoing first amendment. On July 25, 2018, we executed the ninth amendment to the Loan Agreement and the third amendment to the Forbearance Agreement which extended it to September 30, 2018. The terms of the ninth amendment to the Loan Agreement and the third amendment to the Forbearance Agreement increased the interest rate 2% and reduced our borrowing base $176,500 to our current line of credit balance of $2,585,132. On November 7, 2018, we executed the tenth amendment to the Loan Agreement and the fourth amendment to the Forbearance Agreement which extended it to March 31, 2019. The terms of the fourth amendment to the Forbearance Agreement remained the same as the foregoing third amendment. On March 29, 2019, we executed the eleventh amendment to the Loan Agreement and the fifth amendment to the Forbearance Agreement, which extended it to June 30, 2019. The terms of the fifth amendment to the Forbearance Agreement are substantially the same as under the forgoing fourth amendment.

We are taking the following steps to mitigate our current financial situation. We are actively meeting with investors for possible equity investments, including business combinations. We are continuing our effort to identify and market all possible non-producing or low producing assets in our portfolio to maximize cash in-flows while minimizing a loss of cash flow. We are also investigating other possible sources to refinance our debt as we continue to pay down our outstanding line of credit balance with a minimal effect on cash flow. Finally, we are continuing discussions with various individuals and groups that could be willing to provide capital to fund the operations and growth of the Company.

The Company was not in compliance with the NYSE American continued listing standards and received an official delisting notice on November 16, 2017, which could have a significant adverse impact on our ability to raise additional equity capital.

Our warrants were also delisted from the NYSE American on November 17, 2017, and subsequently expired on March 23, 2018.

Our shares are now traded on the over-the-counter market under the symbol FPPP, which is more volatile than the NYSE and may result in a continued diminution in value of our shares. The delisting also resulted in the loss of other advantages to an exchange listing, including marginability, blue sky exemptions and others.

Our ability to continue as a “going concern” is dependent on many factors, including, among other things, our ability to comply with the covenants in our Loan Agreement, our ability to cure any defaults that occur under our Loan Agreement or to obtain waivers or forbearances with respect to any such defaults, and our ability to pay, retire, amend, replace or refinance our indebtedness as defaults occur or as interest and principal payments come due. Our ability to continue as a “going concern” is also dependent on raising additional capital to fund our operations and ultimately on generating future profitable operations. While we are actively involved in seeking new sources of working capital, there can be no assurance that we will be able to raise sufficient additional capital or to have positive cash flow from operations to address all our cash flow needs. Additional capital could be on terms that are highly dilutive to our shareholders. If we are not able to find alternative sources of cash or to generate positive cash flow from operations, our business and shareholders may be materially and adversely affected.

Cash flow used in operating activities was approximately $160,000 and $737,000 for the years ended December 31, 2018 and 2017, respectively. The increase in cash flow from operating activities was primarily due to changes in working capital.

In 2018, we used cash on hand to fund approximately $158,000 of development of oil and natural gas properties and purchase other equipment. We received proceeds of $370,000 from the sale of oil and natural gas properties in 2018. In 2017, we used cash on hand to fund approximately $167,000 of development of oil and natural gas properties and purchase other equipment. We received proceeds of $3,961,607 from the sale of oil and natural gas properties in 2017.

Cash flow used in financing activities for the year ended December 31, 2018, included payments on long term debt of approximately $176,500. Cash flow used in financing activities for the year ended December 31, 2017, included payments on long term debt of approximately $3,717,000. The Company received $187,220 for issuance of 442,282 shares of restricted shares of common stock in 2017.

Contractual Obligations and Commitments

We have contractual obligations and commitments that affect our consolidated results of operations, financial condition and liquidity. The following table is a summary of our significant cash contractual obligations:

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Obligation Due in Period

Cash Contractual Obligations	2019	2020	Thereafter	Total
	(in thousands)
Credit facility (secured)	$2,585	$-	$-	$2,585
Interest on credit facility	-	-	-	-
Office lease	28	-	-	28
Total	$2,613	$-	$-	$2,613

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements other than operating leases.

Subsequent Events

On March 29, 2019, we executed the eleventh amendment to the Loan Agreement and the fifth amendment to the Forbearance Agreement, which extended it to June 30, 2019. See Note 5 Line of Credit for further information on the Forbearance Agreement. As part of the eleventh amendment to the Loan Agreement and the fifth amendment to the Forbearance Agreement, Citibank will apply the balance of a Collateral Account with a balance of approximately $59,000 first to accrued and unpaid interest and then to the unpaid principal balance of the line of credit. To the extent that the funds are used to reduce the outstanding principal balance, the Borrowing Base will be automatically reduced by the same amount.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our accounting policies are described in Note 1 of Notes to Consolidated Financial Statements in Item 8. We prepare our Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("U.S. GAAP"), which require us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the year. Actual results could differ from those estimates. We consider the following policies to be most critical in understanding the judgments that are involved in preparing our financial statements and the uncertainties that could impact our results of operations, financial condition and cash flows.

SuccessfulEffortsMethodofAccounting

We account for our exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

The successful efforts method of accounting can have a significant impact on the operational results reported when we enter a new exploratory area in hopes of finding an oil and natural gas field that will be the focus of future developmental drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

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Reserve Estimates

Estimates of oil and natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and natural gas properties and/or the rate of depletion of the oil and natural gas properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Impairment of Oil and Natural Gas Properties

We review our oil and natural gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. We estimate the expected future cash flows of our oil and natural gas properties and compare such future cash flows to the carrying amount of our oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to their fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.

Because of the precipitous drop in energy prices starting the last quarter of 2014 and the continuing volitivity since then, we use a 5 year NYMEX strip price. The Company recorded impairment charges of $2,601,714 for the year ended December 31, 2018, as a result of writing down the carrying value of two properties to fair value. The Company had no impairment for the year ended December 31, 2017.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We periodically enter into certain commodity price risk management transactions to manage our exposure to oil and natural gas price volatility. These transactions may take the form of futures contracts, swaps or options. All data relating to our derivative positions is presented in accordance with requirements of authoritative accounting guidance. Unrealized gains and losses related to the change in fair value of derivative contracts that qualify and are designated as cash flow hedges are recorded as other comprehensive income or loss and such amounts are reclassified to oil and natural gas sales revenues as the associated production occurs. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of commodity price risk management activities. At December 31, 2018 and 2017, there were no open commodity positions.

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ITEM 8    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements

	Page
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets	F-3
Consolidated Statements of Operations	F-4
Consolidated Statements of Changes in Stockholders' Equity	F-5
Consolidated Statements of Cash Flows	F-6
Notes to Consolidated Financial Statements	F-7
Supplemental Oil and Natural Gas Information (Unaudited)	F-26

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and the Board of Directors of

FieldPoint Petroleum Corporation and Subsidiaries

Opinion on the Financial Statements

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

Going Concern Uncertainty

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated 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 consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated 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 consolidated 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 consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated 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 consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Moss Adams LLP

Dallas, Texas

April 15, 2019

We have served as the Company’s auditor since 2017.

F-2

FIELDPOINT PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

ASSETS

	December 31,
	2018	2017
CURRENT ASSETS:
Cash and cash equivalents	$284,945	$408,656
Accounts receivable:
Oil and natural gas sales, less allowance for doubtful accounts of approximately $27,000 and $0, respectively	459,384	366,939
Joint interest billings, less allowance for doubtful accounts of approximately $265,000 and $237,000, respectively	237,674	260,816
Income taxes receivable- current	119,616	25,057
Prepaid expenses and other current assets	82,853	48,998
Total current assets	1,184,472	1,110,466
PROPERTY AND EQUIPMENT:
Oil and natural gas properties (successful efforts method)	33,798,095	33,753,833
Other equipment	117,561	117,561
Less accumulated depletion, depreciation and impairment	(30,493,146)	(27,425,652)
Net property and equipment	3,422,510	6,445,742
INCOME TAX RECEIVABLE – LONG TERM	79,214	157,227
Total assets	$4,686,196	$7,713,435
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES:
Line of credit - current	$2,585,132	$2,761,632
Accounts payable and accrued expenses	1,183,970	897,101
Oil and natural gas revenues payable	426,418	427,859
Asset retirement obligation - current	154,560	146,066
Total current liabilities	4,350,080	4,232,658
ASSET RETIREMENT OBLIGATION	1,786,017	1,678,420
Total liabilities	6,136,097	5,911,078
COMMITMENTS AND CONTINGENCIES (Notes 2, 9 and 10)
STOCKHOLDERS’ EQUITY (DEFICIT):
Common stock, $.01 par value, 75,000,000 shares authorized; 11,596,229 and 10,669,229 shares issued and outstanding, respectively	115,962	115,962
Additional paid-in capital	13,715,668	13,715,668
Accumulated deficit	(13,314,639)	(10,062,381)
Treasury stock, 927,000 shares, each period, at cost	(1,966,892)	(1,966,892)
Total stockholders’ equity (deficit)	(1,449,901)	1,802,357
Total liabilities and stockholders’ equity (deficit)	$4,686,196	$7,713,435

See accompanying notes to these consolidated financial statements.

F-3

FIELDPOINT PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

	December 31,
	2018	2017
REVENUE:
Oil and natural gas sales	$2,097,687	$2,942,660
Well operational and pumping fees	7,194	2,901
Disposal fees	64,978	90,571
Total revenue	2,169,859	3,036,132
COSTS AND EXPENSES:
Production expense	1,213,770	2,181,377
Depletion and depreciation	469,416	698,337
Impairment of oil and natural gas properties	2,601,714	-
Accretion of discount on asset retirement obligations	109,000	105,000
General and administrative	1,212,238	1,164,015
Total costs and expenses	5,606,138	4,148,729
OPERATING LOSS	(3,436,279)	(1,112,597)
OTHER INCOME (EXPENSE):
Interest income	201	201
Interest expense	(167,734)	(204,703)
Gain on sale of oil and natural gas properties	345,399	3,831,837
Miscellaneous	359	494
Total other income	178,225	3,627,829
INCOME (LOSS) BEFORE INCOME TAXES	(3,258,054)	2,515,232
INCOME TAX EXPENSE – CURRENT	(14,395)	(6,206)
INCOME TAX BENEFIT – DEFERRED	20,191	157,227
TOTAL INCOME TAX BENEFIT	5,796	151,021
NET INCOME (LOSS)	$(3,252,258)	$2,666,253
INCOME (LOSS) PER SHARE:
BASIC	$(0.30)	$0.25
DILUTED	$(0.30)	$0.25
WEIGHTED AVERAGE SHARES OUTSTANDING:
BASIC	10,669,229	10,656,506
DILUTED	10,669,229	10,656,506

See accompanying notes to these consolidated financial statements.

F-4

FIELDPOINT PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)

For the Years Ended December 31, 2018 and 2017

	Common Stock		Additional Paid-in	Retained Earnings(Accumulated	Treasury Stock
	Shares	Amount	Capital	Deficit)	Shares	Amount	Total
BALANCES, January 1, 2017	11,153,947	$111,539	$13,532,871	$(12,728,634)	927,000	$(1,966,892)	$(1,051,116)
Issuance of common stock, net of costs	442,282	4,423	182,797	-	-	-	187,220
Net income	-	-	-	2,666,253	-	-	2,666,253
BALANCES, December 31, 2017	11,596,229	115,962	13,715,668	(10,062,381)	927,000	(1,966,892)	1,802,357
Net loss	-	-	-	(3,252,258)	-	-	(3,252,258)
BALANCES, December 31, 2018	11,596,229	$115,962	$13,715,668	$(13,314,639)	927,000	$(1,966,892)	$(1,449,901)

See accompanying notes to these consolidated financial statements.

F-5

FIELDPOINT PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	December 31,
	2018	2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$(3,252,258)	$2,666,253
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion and depreciation	469,416	698,337
Impairment of oil and natural gas properties	2,601,714	-
Accretion of discount on asset retirement obligations	109,000	105,000
Gain on sale of oil and natural gas properties	(345,399)	(3,831,837)
Deferred income tax benefit	(20,191)	(157,227)
Changes in current assets and liabilities:
Accounts receivable	(45,303)	(63,149)
Income taxes receivable	(16,546)	(16,281)
Prepaid expenses and other current assets	(33,855)	(11,161)
Accounts payable and accrued expenses	375,278	(93,379)
Oil and natural gas revenues payable	(1,441)	(33,368)
Net cash used in operating activities	(159,585)	(736,812)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and natural gas properties and other equipment	(157,626)	(166,725)
Proceeds from the sale of oil and natural gas properties	370,000	3,961,607
Net cash provided by investing activities	212,374	3,794,882
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuance of common stock	-	187,220
Payments on line of credit	(176,500)	(3,716,701)
Net cash used in financing activities	(176,500)	(3,529,481)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(123,711)	(471,411)
CASH AND CASH EQUIVALENTS, beginning of year	408,656	880,067
CASH AND CASH EQUIVALENTS, end of the year	$284,945	$408,656
SUPPLEMENTAL INFORMATION:
Cash paid during the year for interest	$117,400	$272,120
Cash paid during the year for income taxes	$15,515	$20,214
Change in accrued capital expenditures	$76,217	$58,498

See accompanying notes to these consolidated financial statements.

F-6

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.

Summary of Significant Accounting Policies

Organization and Nature of Operations

FieldPoint Petroleum Corporation (the “Company”, “we” or “our”) is incorporated under the laws of the state of Colorado. We are engaged in the acquisition, operation and development of oil and natural gas properties, which are located in Louisiana, New Mexico, Oklahoma, Texas and Wyoming as of December 31, 2018 and 2017.

Consolidation Policy and Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, and include the accounts of the Company and its wholly owned subsidiaries, Bass Petroleum, Inc. and Raya Energy Corp. All material intercompany accounts and transactions have been eliminated in consolidation.

Cash and Cash Equivalents

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. At times, we maintain deposit balances in excess of FDIC insurance limits. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on cash and cash equivalents.

Oil and Natural Gas Properties

Our oil and natural gas properties consisted of the following at December 31:

	2018	2017
Mineral interests in properties:
Unproved properties	$250,217	$250,217
Proved properties	9,755,983	9,762,108
Wells and related equipment and facilities	23,791,895	23,741,508
Total costs	33,798,095	33,753,833
Less accumulated depletion, depreciation and impairment	(30,384,325)	(27,319,847)
	$3,413,770	$6,433,986

We follow the successful efforts method of accounting for our oil and natural gas producing activities. Costs to acquire mineral interests in oil and natural gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have found proved reserves. If we determine that the wells have not found proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determinations of whether the wells found proved reserves at December 31, 2018 or 2017. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties are charged to expense as incurred.

We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. Through December 31, 2018, we have capitalized no interest costs because our exploration and development projects generally last less than six months. Costs to maintain wells and related equipment are charged to expense as incurred.

F-7

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depletion and depreciation are eliminated from the property accounts, and the resulting gain or loss is recognized. On the sale of a partial unit of proved property, the amount received is treated as a reduction of the cost of the interest retained.

Capitalized amounts attributable to proved oil and natural gas properties are depleted by the unit-of-production method of proved reserves using the unit conversion ratio of 6 Mcf of gas to 1 bbl of oil. Depletion and depreciation expense for oil and natural gas producing property and related equipment was $466,400 and $680,000 for the years ended December 31, 2018 and 2017, respectively.

Capitalized costs related to proved oil and natural gas properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows, which is a non-recurring fair value measurement classified as Level 3 in the fair value hierarchy. We recorded impairment of $2,601,714 during the year ended December 31, 2018, but recorded no impairment on our proved oil and natural gas properties during the year ended December 31, 2017.

Unproved oil and natural gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. No impairment of unproved properties was recorded during the years ended December 31, 2018 and 2017.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Oil and Natural Gas Sales Receivable

Oil and natural gas sales receivable principally consist of accrued oil and natural gas sales proceeds receivable and are typically collected within 20 to 56 days. We ordinarily do not require collateral for such receivables, nor do we charge interest on past due balances. As of December 31, 2018 and 2017, our accounts receivable were primarily with several independent purchasers of our crude oil and natural gas production. At December 31, 2018, we had balances due from three purchasers which were greater than 10% of our accounts receivable related to crude oil and natural gas production. These three purchasers accounted for 84% of accounts receivable at December 31, 2018. At December 31, 2017, we had balances due from three purchasers which were greater than 10% of our accounts receivable related to crude oil and natural gas production. These three purchasers accounted for 66% of accounts receivable at December 31, 2017. In the event one or more of these significant purchasers cease doing business with us, we believe that there are potential alternative purchasers with whom we could establish new relationships and that those relationships will result in the replacement of one or more lost purchasers.

F-8

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We periodically review accounts receivable for collectability and reduce the carrying amount of any accounts receivable deemed potentially uncollectible by establishing an allowance for doubtful accounts. On January 12, 2018, one of our purchasers, First River Energy, LLC (“FEL”), notified us that they had filed for Chapter 11 bankruptcy and that we would not be receiving payment for our December 2017 production in the amount of approximately $27,000. We have filed a proof of claim in this matter. Since there is no guarantee that we will recover all or any of the amounts owed, the Company has recorded an allowance for doubtful accounts for the same amount as of December 31, 2018.

Joint Interest Billings Receivable and Oil and Natural Gas Revenues Payable

Joint interest billings receivable represents amounts receivable for lease operating expenses and other costs due from third party working interest owners in the wells that the Company operates. The receivable is recognized when the cost is incurred and the related payable and the Company’s share of the cost is recorded. We often have the ability to offset amounts due against the participant’s share of production revenue from the related property.

The Company uses the reserve for bad debt method of valuing doubtful joint interest billings receivable based on historical experience, coupled with a review of the current status of existing receivables. The balance of the reserve for doubtful accounts was approximately $265,000 and $237,000 at December 31, 2018 and 2017, respectively.

Oil and natural gas revenues payable represents amounts due to third party revenue interest owners for their share of oil and natural gas revenue collected on their behalf by the Company. The payable is recorded when the Company recognizes oil and natural gas sales and records the related oil and natural gas sales receivable.

Other Property

Other assets classified as property and equipment are primarily office furniture and equipment and vehicles, which are carried at cost. Depreciation is provided using the straight-line method over estimated useful lives ranging from three to five years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition. Depreciation expense for other property and equipment was $3,016 and $18,337 for the years ended December 31, 2018 and 2017, respectively.

Asset Retirement Obligations

Our financial statements reflect our asset retirement obligations, consisting of future plugging and abandonment expenditures related to our oil and natural gas properties, which can be reasonably estimated. The asset retirement obligation is recorded at fair value on a discounted basis as a liability at the asset's inception, with an offsetting increase to producing properties on the consolidated balance sheets. Significant inputs to determining fair value include applying a credit adjusted risk free rate which is a Level 3 measurement in the fair value hierarchy. Periodic accretion of the discount of the estimated liability is recorded as an expense in the consolidated statements of operations.

F-9

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following is a reconciliation of the Company’s asset retirement obligations for the years ended December 31:

	2018	2017
Asset retirement obligation at January 1,	$1,824,486	$1,741,907
Accretion of discount	109,000	105,000
Liabilities settled during the year	(1,403)	(15,170)
Liabilities sold	(6,596)	(42,418)
Revision in estimated cash flows	15,090	35,167
Asset retirement obligation at December 31,	1,940,577	1,824,486
Less: current asset retirement obligations	(154,560)	(146,066)
Long-term asset retirement obligations	$1,786,017	$1,678,420

Income Taxes

Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently due, if any, plus net deferred taxes related to differences between the bases of assets and liabilities for financial and income tax reporting. Deferred tax assets and liabilities represent the future tax consequences of those differences, which will either be taxable or deductible when the assets and liabilities are recovered or settled. Valuation allowances are recognized to limit recognition of deferred tax assets where appropriate. Such allowances may be reversed when circumstances provide evidence that the deferred tax assets will more likely than not be realized.

On December 22, 2017, the President of the United States signed into law what is informally called the Tax Cuts and Jobs Act of 2017 (the “Act”), a comprehensive U.S. tax reform package that, effective January 1, 2018, among other things, lowered the corporate income tax rate from 35% to 21%, repealed the Alternative Minimum Tax and made the AMT credit refundable. Accounting rules require companies to recognize the effects of changes in tax laws and tax rates on deferred tax assets and liabilities in the period in which the new legislation is enacted. We recorded a total income tax benefit of $157,227 in the year ended December 31, 2017, the amount of our AMT credit that will be refundable in tax years beginning after 2017. For the tax year ended December 31, 2017, the Company owed $20,191 in alternative minimum tax. The tax liability was reduced $18,990 by the AMT credit from prior years, leaving a balance due of $1,201 on Form 1120. The net amount of AMT paid by the Company increased the AMT credit refundable by $1,201 to $158,428. Half of this refund is expected to be refundable for the tax year ended December 31, 2018 and is reported as a short-term asset included in income tax receivable - current. The remaining $79,214 is reported as a long-term asset in income tax receivable – long-term on the consolidated balance sheet as of December 31, 2018.

The Company also reassessed the realizability of our deferred tax assets but determined that it continues to be more likely than not that the deferred tax assets will not be utilized in the future and continue to record a full valuation allowance of the deferred tax assets.

At December 31, 2017, the Company reported provisional amounts, as allowed by SAB 118, which we believe represented a reasonable estimate of the accounting implications of this tax reform. We completed our review of the Act during the year ended December 31, 2018, and made no adjustments to its provisional amounts.

F-10

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Production Taxes and Ad Valorem Taxes

Production taxes and ad valorem taxes are included in production expense. Total production and ad valorem taxes were $223,843 and $348,195 for the years ended December 31, 2018 and 2017, respectively.

Use of Estimates and Certain Significant Estimates

The preparation of the Company’s financial statements in conformity with accounting principles generally accepted in the United States of America requires the Company’s management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Actual results could differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which as described above may affect the amount at which oil and natural gas properties are recorded. The Company’s allowance for doubtful accounts is a significant estimate and is based on management’s estimates of uncollectible receivables. The asset retirement obligations require estimates of future plugging and abandonment expenditures. It is at least reasonably possible these estimates could be revised in the near term and the revisions could be material.

Our estimates of proved reserves materially impact depletion and impairment expense. If proved reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in estimates of proved reserves may result from lower prices, evaluation of additional operating history, mechanical problems at our wells and catastrophic events such as explosions, hurricanes and floods. Lower prices also may make it uneconomical to drill wells or produce from fields with high operating costs. In addition, a decline in proved reserves may impact our assessment of our oil and natural gas properties for impairment.

Our proved reserve estimates are a function of many assumptions, all of which could deviate materially from actual results. As such, reserve estimates may vary materially from the ultimate quantities of oil and natural gas actually produced.

Revenue Recognition

On January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) Topic 606 “Revenue from Contracts with Customers” (“ASC 606”) using the modified retrospective approach, which only applies to contracts that were not completed as of the date of the adoption. The adoption did not require an adjustment to operating retained earnings for the cumulative effect adjustment and does not have a material impact on the Company’s ongoing consolidated balance sheet, statement of operations, statement of stockholders’ equity or statement of cash flows.

The Company recognizes revenues from the sales of oil, natural gas and natural gas liquids (“NGL”) to its customers in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under contracts with customers (purchasers) are satisfied, which generally occurs with the transfer of control of the products to the purchasers. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the sales, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contracts. Consideration under the marketing contracts is typically received from the purchaser one to two months after production and, as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. Such differences have historically not been significant as the Company uses knowledge of its properties and their historical performance, spot market prices and other factors as the basis for these estimates. At December 31, 2018, the Company had receivables related to contracts with customers of $459,384, net of the foregoing allowance for doubtful accounts of approximately $27,000.

F-11

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes revenue by major source for the years ended December 31, 2018 and 2017. There was no impact related to the adoption of ASC 606 as compared to the previous revenue recognition standard, ASC Topic 605, “Revenue Recognition” (“ASC 605”):

	For the Years Ended
	December 31,
	2018	2017
Revenues
Oil	$1,875,330	$2,621,019
Natural Gas and NGL	222,357	321,641
Total oil, natural gas and NGL	$2,097,687	$2,942,660

Oil Contracts. Under its oil sales contracts, the Company sells oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. At the delivery point, the purchaser takes custody, title and risk of loss of the product and, therefore, control as defined under ASC 606 passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser.

Natural Gas and NGL Contracts. The majority of the Company’s natural gas and NGL is sold at the lease location, which is generally when control of the natural gas and NGL has been transferred to the purchaser, and revenue is recognized as the amount received from the purchaser.

The Company does not disclose the value of unsatisfied performance obligations under its contracts with purchasers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 605-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the purchaser. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Comprehensive Income

The Company has no elements of comprehensive income other than net income.

Share-Based Compensation

We measure and record compensation expense for all share-based payment awards to employees and directors based on estimated fair values. Additionally, compensation costs for share-based awards are recognized over the requisite grant-date service period based on the grant-date fair value.

Financial Instruments

The Company’s financial instruments are cash, accounts receivable, accounts payable and the line of credit. Management believes the fair values of these instruments, with the exception of the line of credit, approximate the carrying values, due to the short-term nature of the instruments. Management believes the fair value of the line of credit also reasonably approximates its carrying value, based on expected cash flows and interest rates.

F-12

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Recently Issued Accounting Pronouncements

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, “Leases”, to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The new standard applies to all leases with a term greater than one year. This authoritative guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Company adopted the standard on January 1, 2019.

The Company has completed the process of reviewing and determining the contracts to which this new guidance applies. Upon adoption, on January 1, 2019, the Company had no leases greater than one year. The Company does not believe this standard will have a material impact on our financial statements. Accordingly, the Company did not recognize any right-of-use assets, or any associated lease liabilities on adoption.

In January 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” which provides an optional practical expedient to not evaluate land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under Topic 840. The Company enters into land easements on a routine basis as part of its ongoing operations and has many such agreements currently in place; however, the Company does not currently account for any land easements under Topic 840. As this guidance serves as an amendment to ASU 2016-02, the Company will elect this practical expedient, which becomes effective upon the date of adoption of ASU 2016-02. After the adoption of ASU 2016-02, the Company will assess any new land easements to determine whether the arrangement should be accounted for as a lease.

In July 2018, the FASB issued ASU No. 2018-11, “Targeted Improvements,” which provides a transition election to not restate comparative periods for the effects of applying the new lease standard. This transition election permits entities to change the date of initial application to the beginning of the year of adoption and to recognize the effects of applying the new standard as a cumulative-effect adjustment to the opening balance of retained earnings. The Company elected this transition approach, however the cumulative impact of adoption in the opening balance of retained earnings as of January 1, 2019 was zero.

In July 2018, the FASB issued ASU No. 2018-09, “Codification Improvements,” (“ASU 2018-09”) which makes amendments to multiple codification topics to clarify, correct errors in, or make minor improvements to the accounting standards codification. The effective date of the standard is dependent on the facts and circumstances of each amendment. Some amendments do not require transition guidance and will be effective upon the issuance of this standard. Many of the amendments in ASU 2018-09 will be effective in annual periods beginning after December 15, 2018. The Company will be required to adopt this standard in the first quarter of fiscal 2019. The Company is currently assessing the effect that this ASU will have on its financial position, results of operations, and disclosures.

On August 17, 2018, the SEC issued a final rule that amends certain of its disclosure requirements that have become redundant, duplicative, overlapping, outdated or superseded, in light of other disclosure requirements, U.S. GAAP or changes in the information environment. The amendments are intended to facilitate the disclosure of information to investors and simplify compliance without significantly altering the total mix of information provided to investors. The final rule amends numerous SEC rules, items and forms covering a diverse group of topics, including, but not limited to, changes in stockholders’ equity. The final rule extends to interim periods the annual disclosure requirement in SEC Regulation S-X, Rule 3-04, of presenting changes in stockholders’ equity. The registrants will be required to analyze changes in stockholders’ equity in the form of a reconciliation for the current quarter and year-to-date interim periods and comparative periods in the prior year. The final rule became effective for all filings submitted on or after November 5, 2018.

F-13

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In November 2018, the FASB issued ASU No. 2018-18, “Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606,” (“ASU 2018-18”) which, among other things, clarifies that (i) certain transactions between collaborative arrangement participants should be accounted for as revenue under Topic 606 when the collaborative arrangement participant is a customer in the context of a unit of account, (ii) adds unit-of-account guidance in Topic 808 to align with the guidance in Topic 606 and (iii) requires that in a transaction with a collaborative arrangement participant that is not directly related to sales to third parties, presenting the transaction together with revenue recognized under Topic 606 is precluded if the collaborative arrangement participant is not a customer. ASU 2018-18 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years and early adoption is permitted. The amendments in this update should be applied retrospectively to the date of initial application of Topic 606. An entity should recognize the cumulative effect of initially applying the amendments as an adjustment to the opening balance of retained earnings of the later of the earliest annual period presented and the annual period that includes the date of the entity’s initial application of Topic 606. The Company is currently assessing the effect that ASU 2018-18 will have on its financial position, results of operations and disclosures.

2.

Liquidity and Going Concern

Our accompanying consolidated financial statements have been prepared assuming that we will continue as a “going concern”, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date that these consolidated financial statements are issued. Crude oil and natural gas prices during 2018 and 2017 have remained considerably lower than their historical highs and these lower prices have had a significant adverse impact on our business and, as a result, on our financial condition and our working capital. Accordingly, substantial doubt exists that we will be able to continue as a “going concern”.

As of December 31, 2018 and 2017, the Company had a working capital deficit of approximately $3,166,000 and $3,122,000, respectively, primarily due to the classification of our line of credit with Citibank as a current liability. The line of credit agreement (“the Loan Agreement”) provides for certain financial covenants and ratios measured quarterly, which include a current ratio, leverage ratio and interest coverage ratio requirements. The Company was out of compliance with all three ratios as of December 31, 2018 and 2017, and we do not expect to regain compliance in 2019. A Forbearance Agreement (“the Forbearance Agreement”) was executed in October 2016 and amended on December 29, 2017, March 30, 2018, June 30, 2018, September 30, 2018 and March 29, 2019, as discussed below.

Citibank is in a first lien position on all of our oil and natural gas properties under the terms of the Loan Agreement. Citibank lowered our borrowing base from $11,000,000 to $5,500,000 on December 1, 2015, and lowered it again to $2,761,632 on December 29, 2017. Our borrowing base was lowered again on June 30, 2018 to $2,585,132.

F-14

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In October 2016, we executed the sixth amendment to the Loan Agreement, and also executed a Forbearance Agreement which provided for Citibank’s forbearance from exercising remedies relating to the existing defaults, including the principal payment deficiencies. The Forbearance Agreement ran through January 1, 2018, and required that we make a $500,000 loan principal pay down by September 30, 2017, and adhere to other requirements including weekly cash balance reports, quarterly operating reports and monthly accounts payable reports, The Forbearance Agreement also required us to pay all of Citibank’s associated legal expenses. Furthermore, under the Forbearance Agreement, Citibank was allowed to sweep any excess cash balances exceeding a net amount of $800,000 less equity offering proceeds, which would be applied towards the outstanding principal balance of the line of credit.

On December 29, 2017, we executed the seventh amendment to the Loan Agreement and the first amendment to the Forbearance Agreement, which reduced our borrowing base to $2,761,632 (our line of credit balance at December 31, 2017), and provided for Citibank’s forbearance from exercising remedies relating to the existing defaults, including the principal payment deficiencies. This amended Forbearance Agreement ran through March 31, 2018, and required that we adhere to certain reporting requirements, such as weekly cash reports, and that we pay all fees and expenses of Citibank’s counsel invoiced on or before the effective date. On March 30, 2018, we executed the eighth amendment to the Loan Agreement and the second amendment to the Forbearance Agreement which extended it to June 30, 2018. The terms of the second amendment to the Forbearance Agreement remained the same as under the foregoing first amendment. On July 25, 2018, we executed the ninth amendment to the Loan Agreement and the third amendment to the Forbearance Agreement which extended it to September 30, 2018. The terms of the ninth amendment to the Loan Agreement and the third amendment to the Forbearance Agreement increased the interest rate 2% and reduced our borrowing base $176,500 to our current line of credit balance of $2,585,132. On November 7, 2018, we executed the tenth amendment to the Loan Agreement and the fourth amendment to the Forbearance Agreement which extended it to March 31, 2019. The terms of the fourth amendment to the Forbearance Agreement remained the same as the foregoing third amendment. On March 29, 2019, we executed the eleventh amendment to the Loan Agreement and the fifth amendment to the Forbearance Agreement, which extended it to June 30, 2019. The terms of the fifth amendment to the Forbearance Agreement are substantially the same as under the forgoing fourth amendment.

We are taking the following steps to mitigate our current financial situation. We are actively meeting with investors for possible equity investments, including business combinations. We are continuing our effort to identify and market all possible non-producing or low producing assets in our portfolio to maximize cash in-flows while minimizing a loss of cash flow. We are also investigating other possible sources to refinance our debt as we continue to pay down our outstanding line of credit balance with a minimal effect on cash flow. Finally, we are continuing discussions with various individuals and groups that could be willing to provide capital to fund the operations and growth of the Company.

The Company was not in compliance with the NYSE American continued listing standards and received an official delisting notice on November 16, 2017, which could have a significant adverse impact on our ability to raise additional equity capital.

F-15

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Our warrants were also delisted from the NYSE American on November 17, 2017, and subsequently expired on March 23, 2018.

Our shares are now traded on the over-the-counter market under the symbol FPPP, which is more volatile than the NYSE and may result in a continued diminution in value of our shares. The delisting also resulted in the loss of other advantages to an exchange listing, including marginability, blue sky exemptions and others.

Our ability to continue as a “going concern” is dependent on many factors, including, among other things, our ability to comply with the covenants in our Loan Agreement, our ability to cure any defaults that occur under our Loan Agreement or to obtain waivers or forbearances with respect to any such defaults, and our ability to pay, retire, amend, replace or refinance our indebtedness as defaults occur or as interest and principal payments come due. Our ability to continue as a “going concern” is also dependent on raising additional capital to fund our operations and ultimately on generating future profitable operations. While we are actively involved in seeking new sources of working capital, there can be no assurance that we will be able to raise sufficient additional capital or to have positive cash flow from operations to address all our cash flow needs. Additional capital could be on terms that are highly dilutive to our shareholders. If we are not able to find alternative sources of cash or to generate positive cash flow from operations, our business and shareholders may be materially and adversely affected.

3.

Oil and Natural Gas Properties

The Company sold its net interest in the Buchanan wells and associated acreage in the Spraberry field during 2018 that were not economic to our interests. Gross proceeds from the sale were $370,000 and the Company recognized a gain of $345,399 from the sale of these oil and natural gas properties during the year ended December 31, 2018.

The Company sold its net interest in non- producing leasehold and net interest in the Hermes, Cronos and Mercury wells which were not economic to our interests and also sold its net interest in the unproved Bilbrey acreage that was held by production during 2017. The gross proceeds from the sale of our net interest in these two oil and natural gas properties was $2,145,000. In addition, the Company sold 401 net acres of non-producing leasehold in Lea County, New Mexico for gross proceeds of $1,200,000 during 2017. We also sold our interest in the Apache Bromide field for $603,607, net of liabilities of $296,393, and our interest in Rush Springs for $11,700 during 2017. We recognized aggregate gains of $3,831,837 from the sale of oil and natural gas properties during the year ended December 31, 2017.

We continue to evaluate our portfolio for other properties we could divest in order to regain compliance with the Loan Agreement’s debt covenants.

The Company made no purchases of oil and natural gas properties during the years ended December 31, 2018 and 2017. The Company did not drill or complete any development wells during 2018 and 2017.

F-16

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company recorded impairment charges of $2,601,714 during the year ended December 31, 2018, as a result of writing down the carrying value of certain oil and natural gas properties to fair value. The Company had no impairment to properties during the year ended December 31, 2017. In order to determine the amounts of the impairment charges, the Company compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management's expectations of economically recoverable proved reserves. If the net capitalized cost exceeds the undiscounted future net cash flows, the Company impairs the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. In order to determine the fair value, the Company estimates reserves, future operating and development costs, future commodity prices and a discounted cash flow model utilizing a 10 percent discount rate. The estimates used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements are classified as Level 3 of the fair value hierarchy.

4.

Fair Value Measurements

The Company follows fair value measurement authoritative guidance, which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

●

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

●

Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable.

●

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. The fair value of oil and gas properties used in estimating our recognized impairment loss represents a non-recurring Level 3 measurement.

Financial and non-financial assets and liabilities are to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

F-17

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following tables present the Company’s financial and non-financial assets and liabilities that were accounted for at fair value as of December 31, 2018, and their classification within the fair value hierarchy:

	As of December 31, 2018
	Level 1	Level 2	Level 3
Proved properties (1)	$-	$-	$178,064
Unproved properties (1)	$-	$-	$-

(1)

This represents non-financial assets that are measured at fair value on a nonrecurring basis due to impairments. This is the fair value of the asset base that was subjected to impairment and does not reflect the entire asset balance as presented on the accompanying balance sheets. Please refer to the Proved Oil and Gas Properties and Unproved Oil and Gas Properties sections below for additional discussion.

Proved Oil and Gas Properties

Proved oil and natural gas properties are evaluated for impairment and reduced to fair value whenever events and circumstances indicate the carrying value exceeds the sum of the undiscounted cash flows. We estimate the expected net future cash flows of our oil and natural gas properties using management's expectations of economically recoverable proved reserves and compare such future net cash flows to the carrying amount of our oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we adjust the carrying amount of the oil and natural gas properties to their fair value. We estimated the fair value of the proved oil and natural gas properties and equipment using a discounted cash flow model, which is a non-recurring Level 3 fair value measurement. Significant inputs used to determine the fair value include estimates of (i) future sales prices for oil and gas based on NYMEX strip prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) future oil and natural gas reserves to be recovered and the timing thereof, and (vi) discount rate. The Company impaired two proved oil and natural gas properties which had a total carrying value of $2,779,778 to their fair value of $178,064 as of December 31, 2018. The carrying value was less than the fair market value of the proved oil and natural gas properties as of December 31, 2017.

Unproved Oil and Gas Properties

Unproved oil and natural gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be fully recoverable. The fair value of unproved oil and gas properties used in estimating our recognized impairment loss represents a non-recurring Level 3 measurement. To measure the fair value of unproved properties, the Company used inputs including, but not limited to, future development plans, risk weighted potential resource recovery, remaining lease life and estimated per acreage value. The carrying value was less than the fair market value of the unproved oil and natural gas properties as of December 31, 2018 and 2017.

F-18

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.

Line of Credit

The Company has a line of credit with Citibank with a borrowing base and outstanding principal balance of $2,585,132 and $2,761,632 at December 31, 2018 and 2017, respectively.

The line of credit agreement (“the Loan Agreement”) requires quarterly interest-only payments until maturity on March 31, 2019. The interest rate is based on a LIBOR or Prime option. The Prime option provides for the interest rate to be prime plus a margin ranging between 1.75% and 2.25% and the LIBOR option to be the 3-month LIBOR rate plus a margin ranging between 2.75% and 3.25%, both depending on the borrowing base usage. On July 25, 2018, we executed the ninth amendment to the Loan Agreement which increased the interest rate 2% for the term of the loan. On November 7, 2018, we executed the tenth amendment to the Loan Agreement with no change in borrowing rate from the ninth amendment to the Loan Agreement. Currently, we have elected the LIBOR interest rate option in which our interest rate was approximately 8% as of December 31, 2018.

The bank’s commitment fee is .50% of the unused borrowing base. The Loan Agreement provides for certain financial covenants and ratios which include a current ratio that cannot be less than 1.10:1.00, a leverage ratio that cannot be more than 3.50:1.00, and an interest coverage ratio that cannot be less than 3.50:1.00. The Company was out of compliance with all three ratios as of December 31, 2018 and 2017, and is in technical default of the Loan Agreement. The Company made payments of $176,500 and $3,716,701 toward the line of credit principal balance during the years ended December 31, 2018 and 2017, respectively. Citibank lowered our borrowing base from $5,500,000 to $2,761,632 on December 29, 2017, which was equal to our outstanding loan balance at that date. Our borrowing base was lowered again on June 30, 2018, to $2,585,132, which was equal to our outstanding loan balance at that date and also at December 31, 2018. Citibank is in a first lien position on all of our oil and natural gas properties.

In October 2016, we executed a sixth amendment to the Loan Agreement, and also executed a Forbearance Agreement which provided for Citibank’s forbearance from exercising remedies relating to the existing defaults, including the principal payment deficiencies. The Forbearance Agreement ran through January 1, 2018, and required that we make a $500,000 loan principal pay down by September 30, 2017, and adhere to other requirements including weekly cash balance reports, quarterly operating reports and monthly accounts payable reports. The Forbearance Agreement also required us to pay all of Citibank’s associated legal expenses. Furthermore, under the Forbearance Agreement, Citibank was allowed to sweep any excess cash balances exceeding a net amount of $800,000 less equity offering proceeds, which would be applied towards the outstanding principal balance.

On December 29, 2017, we executed the seventh amendment to the Loan Agreement and the first amendment to the Forbearance Agreement, which reduced our borrowing base to $2,761,632 (our loan balance at December 31, 2017) and provided for Citibank’s forbearance from exercising remedies relating to the existing defaults, including the principal payment deficiencies. The first amendment to the Forbearance Agreement ran through March 31, 2018, and required that we adhere to certain reporting requirements such as weekly cash reports, and to pay all fees and expenses of Citibank’s counsel invoiced on or before the effective date. On March 30, 2018, we executed the eighth amendment to the Loan Agreement and the second amendment to the Forbearance Agreement, which extended it to June 30, 2018. The terms of the second amendment to the Forbearance Agreement were the same as under the foregoing first amendment. On July 25, 2018, we executed the ninth amendment to the original Loan Agreement and the third amendment to the Forbearance Agreement, which extended it to September 30, 2018. The terms of the ninth amendment to the Loan Agreement increased the interest rate 2% and reduced our borrowing base $176,500 to our current loan balance of $2,585,132. The terms of the third amendment to the Forbearance Agreement remain the same as under the foregoing second amendment. On November 7, 2018, we executed the tenth amendment to the Loan Agreement and the fourth amendment to the Forbearance Agreement, which extended it to March 31, 2019. The terms of the fourth amendment to the Forbearance Agreement are substantially the same as under the forgoing third amendment. On March 29, 2019, we executed the eleventh amendment to the Loan Agreement and the fifth amendment to the Forbearance Agreement, which extended it to June 30, 2019. The terms of the fifth amendment to the Forbearance Agreement are substantially the same as under the forgoing fourth amendment.

F-19

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6.

Income Taxes

Our provision for income taxes comprised the following (expense) benefit during the years ended December 31:

	2018	2017
Current:
Federal	$(20,191)	$-
State	5,796	(6,206)
Total current	(14,395)	(6,206)
Deferred:
Federal	20,191	157,227
State	-	-
Total deferred	20,191	157,227
Total income tax provision	$5,796	$151,021

Total income tax (expense) benefit differed from the amounts computed by applying the U.S. Federal statutory tax rates and estimated state rates to pre-tax income for the years ended December 31, 2018 and 2017 as follows:

	2018	2017
Statutory rate (benefit)	(21%)	(34%)
State taxes, net of federal benefit	(2%)	(1%)
Permanent differences	-	(1%)
Impact of U.S. tax reform	-	(36%)
Change in valuation allowance on deferred tax assets	23%	78%
Effective rate (benefit)	0%	6%

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax bases of assets and liabilities. The Company’s deferred tax assets were reduced in full by a valuation allowance due to our determination that it is more likely than not that some or all of the deferred tax assets will not be realized in the future. Significant components of net deferred tax assets and liabilities are:

	December 31,
	2018	2017
Deferred tax assets:
Asset retirement obligation	$462,000	$434,000
Allowance for doubtful accounts	71,000	57,000
State taxes and other	2,000	(1,000)
Difference in depreciation, depletion and capitalization methods – oil and gas properties	320,000	(161,000)
Net operating loss carryforward	1,538,000	1,320,000
Total deferred tax assets	2,393,000	1,649,000
Valuation allowance on deferred tax assets	(2,393,000)	(1,649,000)
Total deferred tax assets, net of valuation allowance	-	-
Deferred tax liability:
Difference in depreciation, depletion and capitalization methods – oil and gas properties	-	-
Total deferred tax liabilities	-	-
Net deferred tax liability	$-	$-

F-20

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Our net deferred tax assets and liabilities are recorded as follows:

	2018	2017
Non-current asset	$-	$-
Non-current liability	-	-
Total	$-	$-

The Company had no material uncertain tax positions as of December 31, 2018 and 2017.

The decrease in deferred tax assets before the valuation allowance was primarily due to the federal tax rate decreasing from 34% to 21% under the Tax Cuts and Jobs Act signed into law in 2017. Also, the Company had an AMT credit of approximately $157,000 for alternative minimum tax paid in prior years that will be refundable under the same tax reform act. The AMT credit was increased by approximately $1,200 due to additional AMT tax paid in 2018 when it filed its the federal corporate income tax return for the year ended December 31, 2017. The AMT credit is approximately $158,000 at December 31, 2018. Half of this refund, approximately $79,000, is expected to be refundable for the tax year ended December 31, 2018, and is reported as a short-term asset included in income tax receivable. Approximately $79,000 is reported as a long-term asset in income tax receivable – long-term on the consolidated balance sheet.

At December 31, 2018, the Company expects to have net operating loss carryforwards of approximately $6.6 million. Losses from the years ended December 31, 2015 and 2016, expire at various dates from December 31, 2035 to 2036. Losses from the year ended December 31, 2018, will be carried forward indefinitely. As a result of the net operating losses, our deferred tax assets exceeded our deferred tax liabilities. The Company reassessed the realizability of our deferred tax assets but determined that it continues to be more likely than not that the deferred tax assets will not be utilized in the future. The Company established a valuation allowance of $2,393,000 and $1,649,000 against our deferred tax assets for the years ended December 31, 2018 and 2017, respectively.

The Company’s policy regarding income tax interest and penalties is to record those items as general and administrative expense. During the years ended December 31, 2018 and 2017, there were no significant income tax interest and penalty items in the income statement, nor as a liability on the balance sheet at December 31, 2018 and 2017.

The Company files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Generally, the Company is no longer subject to U.S. federal or state income tax examination by tax authorities for years before 2015. The Company is not currently involved in any income tax examinations.

7.

Earnings (Loss) Per Share

Basic earnings per share are computed based on the weighted average number of shares of common stock outstanding during the year. Diluted earnings per share take common stock equivalents (such as options and warrants) into consideration using the treasury stock method. The Company distributed warrants as a dividend to stockholders as of the record date, March 23, 2012. The Company had 7,177,010 warrants outstanding with an exercise price of $4.00 at December 31, 2017. The Warrants expired on March 23, 2018. The dilutive effect of the warrants for the twelve months ended December 31, 2018 and 2017, is presented below.

F-21

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	December 31,
	2018	2017
Net income (loss)	$(3,252,258)	$2,666,253
Weighted average common stock outstanding	10,669,229	10,656,506
Weighted average dilutive effect of stock warrants	-	-
Dilutive weighted average shares	10,669,229	10,656,506
Loss per share:
Basic	$(0.30)	$0.25
Diluted	$(0.30)	$0.25

8.

Stockholders’ Equity

We approved a stock warrant dividend of one warrant per one common share in March 2012. The warrants had an exercise price of $4.00 and were exercisable over 6 years from the record date. Our warrants were delisted from the NYSE American (formerly NYSE MKT) on November 17, 2017, and then subsequently expired on March 23, 2018. The following table summarizes the warrant activity for the year ending December 31, 2018:

	Warrants	Weighted Average Exercise Price	Weighted Average Expected Life (Years)
Outstanding, December 31, 2017	7,177,010	$4.00	0.25
Issued	-	-
Exercised	-	-
Expired	(7,177,010)	-
Outstanding, December 31, 2018	-	$0.00	0.00

The Company entered into an “at will” employment agreement with Phillip Roberson as President and Chief Financial Officer (“CFO”) for a three-year period beginning July 1, 2014. Mr. Roberson was awarded, as part of his annual compensation, 5,000 shares on his third anniversary date, 6,000 shares on his fourth anniversary date, 7,000 shares on his fifth anniversary date, 8,000 shares on his sixth anniversary date, 9,000 shares on his seventh anniversary date, and 10,000 shares on each annual anniversary date thereafter. However, Mr. Roberson declined the 5,000 and 6,000 shares that would have been awarded on his third and fourth anniversary dates, July 1, 2017 and 2018, respectively. On August 10, 2018, the Compensation Committee ratified the automatic extension of Mr. Roberson’s contract to July 1, 2019.

F-22

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 On August 12, 2016, the Company entered into a binding Stock and Mineral Purchase Agreement (the “SMPA”) with HFT Enterprises, LLC (the “Buyer”) in order to provide liquidity to the Company. The original closing date of September 30, 2016, was extended to November 3, 2016, by mutual consent. The Buyer purchased in two equal tranches, a number of newly-issued shares of common stock of the Company equal to 19.9% of the total number of issued and outstanding shares of the Company, as measured on the date of the SMPA, for a price of $0.45 per share (the shares to be purchased, (the “Shares”). The first tranche was purchased on November 3, 2016, for gross proceeds of $398,053 paid in consideration for 884,564 shares of unregistered common stock. Half of the second tranche was purchased on December 29, 2016, for gross proceeds of $199,027 paid in consideration for 442,282 shares of unregistered common stock. The remaining 442,282 shares of the second tranche were purchased in January 2017 for net proceeds of $187,220 paid in consideration for 442,282 shares of unregistered common stock. The Shares are restricted shares that are also not registered under the Securities Act of 1933, as amended (the “Securities Act”), and therefore the Buyer must hold the Shares indefinitely unless they are registered with the Securities and Exchange Commission and qualified by state authorities, or an exemption from such registration and qualification requirements is available. Also, the Buyer was granted the right to nominate one member of the Board of Directors.

9.Environmental Issues

We are engaged in oil and natural gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures as they relate to the drilling of oil and natural gas wells and the operation thereof. In our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean-up or restoration, the liability to cure such a violation could fall upon the Company. No claim has been made, nor are we aware of any liability which we may have, as it relates to any environmental cleanup, restoration or the violation of any rules or regulations relating thereto.

10.

Commitments and Contingencies

As of December 31, 2018 and 2017, we had a $30,000 outstanding standby letter of credit in favor of the State of Wyoming as a plugging bond. As of December 31, 2018 and 2017, we had a $25,000 outstanding letter of credit in the favor of the Bureau of Land Management.

In January 2014, the Company entered into a two-year operating lease for office space in Austin, Texas, which was renewed for another two years until January 31, 2018. On February 1, 2018, the Company executed an amendment to extend the lease until July 31, 2018. On August 1, 2018, the Company executed an amendment to extend the lease until July 31, 2019. Rent expense under this lease was approximately $38,300 and $45,100 for the years ended December 31, 2018 and 2017, respectively. As of December 31, 2018, minimum future rentals during 2019 on this non-cancelable operating lease are $23,443.

F-23

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company entered into an “at will” employment agreement with Phillip Roberson as President and CFO for a three-year period beginning July 1, 2014, with a beginning base salary of $200,000 annually. Beginning January 1, 2015, the Board of Directors may in its sole discretion award an annual performance-based bonus award to Mr. Roberson.

The Board of Directors adopted a resolution effective as of January 1, 2016, to temporarily accept voluntary reductions in annual retainers for executive and all non-executive directors until such time as economic conditions shall improve and the Board determines that the voluntary reductions shall cease. Annual reductions in annual retainers is approximately $75,000 per year, for a cumulative savings of approximately $225,000 from January 1, 2016, to December 31, 2018. All voluntary reductions shall be retroactively reinstated and payable in the case of (and only in the case of) a Change of Control Event as defined in the resolution. 

Occasionally, we are involved in various legal and regulatory proceedings arising in the normal course of business. Management cannot predict the outcome of these proceedings with certainty and does not believe that an adverse result would be material to the Company’s financial position or results of operations.

In the fourth quarter of 2017, we were notified that the former operator of our Ranger and Taylor Serbin fields, Riley Exploration Group, Inc. (“REG”), sold all of its working and revenue ownership interests in those fields to Trivista Operating LLC (“Trivista”), which is controlled by Natale Rea (2013) Trust, one of our major shareholders. Along with acquiring the working interest in those fields, Trivista also claims to have acquired a joint interest billing invoice from REG aggregating approximately $84,000, which we had previously disputed with REG. We received a demand letter from Trivista’s counsel for this sum. We responded that the joint interest billing invoice was in dispute and that we had previously sent a letter to REG demanding an audit of their operations and the joint interest billing but had received no response. Trivista claims to have taken over operations of these fields in October 2017, but has failed to provide revenue, expense and operating information to us since April 2018, which is in direct violation of the joint operating agreements which govern these wells. Trivista filed suit for non-payment of outstanding disputed invoices of approximately $107,000 plus attorney fees and court costs on February 26, 2018. We are vigorously defending ourselves against these claims and are performing discovery to potentially seek legal remedies of our own. See Footnote 12-Related Party Transactions for additional disclosures regarding how the transactions with Trivista with respect to these wells impacted our 2018 and 2017 consolidated financial statements.

11.

Oil and Natural Gas Producing Activities

The following table sets forth the costs incurred for oil and natural gas property activities of the Company:

	Years Ended December 31,
	2018	2017
Costs incurred in oil and natural gas producing activities:
Acquisition of unproved properties	$-	$-
Acquisition of proved properties	-	-
Exploration costs	-	-
Development costs	157,626	160,914
Total costs incurred	$157,626	$160,914

F-24

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table includes certain information regarding the results of operations for oil and natural gas producing activities:

	Years Ended December 31,
	2018	2017
Revenues	$2,097,687	$2,942,660
Expenses
Production expense	1,213,770	2,181,377
Depletion and depreciation	469,416	698,337
Impairment of oil and natural gas properties	2,601,714	-
Accretion of discount on asset retirement obligations	109,000	105,000
Total expenses	4,393,900	2,984,714
Loss before income taxes	(2,296,213)	(42,054)
Income tax benefit, net of valuation allowance (1)	-	-
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$(2,296,213)	$(42,054)

(1)

Reflects the Company’s effective tax rate.

12.

Related Party Transactions

During 2017, the Company received notification that Trivista, an entity controlled by Natale Rea, a beneficial owner of approximately 7.00% of our common stock, had become the operator of certain oil and natural gas properties where we have both working and revenue ownership interests. See Footnote 10- Commitments and Contingencies for more disclosures and information regarding Trivista.

During 2017, the Company received joint interest billing statements related to our working interest in these properties subsequent to Trivista becoming the operator aggregating approximately $58,000, which represented 2.6% of our production expenses for theyear ended December 31, 2017 and 32.5% of our lease operating expense accrual as of December 31, 2017. In addition, during 2017, we recorded oil and natural gas revenues associated with our revenue ownership interest in these wells subsequent to Trivista becoming the operator aggregating $82,000, which represented 2.8% of our oil and natural gas sales for the year ended December 31, 2017 and 21.8% of our oil and natural gas sales accounts receivable as of December 31, 2017.

During 2018, the Company accrued approximately $123,000 for joint interest billings associated with our working interest in these oil and natural gas properties, which represented 10.2% of our production expenses for the year ended December 31, 2018 and 81.1% of our lease operating expense accrual as of December 31, 2018. In addition, during 2018, we recorded oil and natural gas revenues associated with our revenue ownership interest in these wells aggregating $212,000, which represented 10.1% of our oil and natural gas sales for the year ended December 31, 2018 and 53.7% of our oil and natural gas sales accounts receivable as of December 31, 2018.

Director and Committee fees were accrued but have not been paid during the year ended December 31, 2018. In addition, Committee fees for December 2017 were accrued but have not been paid. The amounts accrued but not paid as of December 31, 2018 and 2017, were approximately $172,000 and $19,000, respectively.

F-25

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During October 2018, the Company sold used surplus production tubing to an entity controlled by a shareholder, Mike Herman, for $24,000.

13.

Subsequent Events

On March 29, 2019, we executed the eleventh amendment to the Loan Agreement and the fifth amendment to the Forbearance Agreement, which extended it to June 30, 2019. See Note 5 Line of Credit for further information on the Forbearance Agreement. As part of the eleventh amendment to the Loan Agreement and the fifth amendment to the Forbearance Agreement, Citibank will apply the balance of a Collateral Account with a balance of approximately $59,000 first to accrued and unpaid interest and then to the unpaid principal balance of the line of credit. To the extent that the funds are used to reduce the outstanding principal balance, the Borrowing Base will be automatically reduced by the same amount.

14.

Disclosures About Oil and Natural Gas Producing Activities (Unaudited)

The following table summarizes changes in the estimates of the Company’s net interest in total proved reserves of crude oil and condensate and natural gas and liquids, all of which are domestic reserves. There can be no assurance that such estimates will not be materially revised in subsequent periods.

	Oil (Barrels)	Gas (MCF)
Balance, January 1, 2017	490,226	756,512
Revisions of previous estimates	33,784	86,221
Extensions and discoveries	-	-
Sale of reserves	(42,085)	(19,657)
Purchase of minerals in place	-	-
Production	(53,913)	(111,816)
Balance, December 31, 2017	428,012	711,260
Revisions of previous estimates	(46,166)	107,828
Extensions and discoveries	-	-
Sale of reserves	-	-
Purchase of minerals in place	-	-
Production	(32,097)	(82,472)
Balance, December 31, 2018	349,749	736,616
Proved developed reserves, December 31, 2018	349,749	736,616
Proved developed reserves, December 31, 2017	428,012	711,260

F-26

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Proved oil and natural gas reserves are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. The above estimated net interests in proved reserves are based upon subjective engineering judgments and may be affected by the limitations inherent in such estimation. The process of estimating reserves is subject to continual revision as additional information becomes available as a result of drilling, testing, reservoir studies and production history, and market prices for oil and natural gas. Significant fluctuations in market prices have a direct impact on recoverability and will result in changes in estimated recoverable reserves without regard to actual increases or decreases in reserves in place.

Year Ended December 31, 2017

The average natural gas price used in our proved reserves estimate at December 31, 2017, was $4.55 per Mcf, which is higher than market because of the inclusion of NGLs. The average oil price used in our proved reserves estimate at December 31, 2017, was $47.03 per barrel. We did not drill any new wells or purchase any reserves during the year ended December 31, 2017. We sold one unproved property, one non-producing property, and three producing properties.

Year Ended December 31, 2018

The average natural gas price used in our proved reserves estimate at December 31, 2018, was $4.81 per Mcf, which is higher than market because of the inclusion of NGLs. The average oil price used in our proved reserves estimate at December 31, 2018, was $62.17 per barrel. We did not drill any new wells or purchase any reserves during the year ended December 31, 2018. We sold one producing property.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows at December 31, 2018 and 2017, relating to proved oil and natural gas reserves is set forth below. The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and, as such, do not necessarily reflect our expectations of actual revenues to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with prescribed accounting and SEC standards. Future cash inflows were computed by applying the unweighted, arithmetic average of the closing price on the first day of each month for the 12-month period prior to December 31, 2018 and 2017, to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming continuation of existing economic conditions.

F-27

FIELDPOINT PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of our oil and natural gas properties.

	Years Ended December 31,
	(in thousands)
	2018	2017
Future cash inflows	$28,639	$24,866
Future production costs	(13,630)	(13,105)
Future development cost	(14)	(86)
Future income taxes	(2,303)	(1,848)
Future net cash flows	12,692	9,827
10% annual discount	(6,218)	(4,202)
Standardized measure of discounted future net cash flows	$6,474	$5,625

The following are the principal sources of change in the standardized measure of discounted future net cash flows, in thousands:

	Years Ended December 31,
	2018	2017
Balance, beginning of year	$5,625	$5,501
Sales of oil and natural gas produced, net of production costs	(857)	(696)
Sale of reserves	-	(573)
Extensions and discoveries	-	-
Net changes in prices and production costs	3,137	1,820
Net changes in future development costs	37	41
Revisions and other changes	118	139
Accretion of discount	686	557
Net change in income taxes	(2,272)	(1,164)
Balance, end of year	$6,474	$5,625

* * * * * * *

F-28

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

None.

ITEM 9A.     CONTROLS AND PROCEDURES

a)

Our Principal Executive Officer, Roger D. Bryant, and our Principal Financial Officer, Phillip H. Roberson, have established and are currently maintaining disclosure controls and procedures for the Company. The disclosure controls and procedures have been designed to provide reasonable assurance that the information required to be disclosed by the Company in reports that it files under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed by the Company is accumulated and communicated to the Company's management as appropriate to allow timely decisions regarding required disclosure.

The Principal Executive Officer and Principal Financial Officer conducted a review and evaluation of the effectiveness of the Company's disclosure controls and procedures and have concluded, based on their evaluation as of the end of the period covered by this Report, that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed 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 Commission’s rules and forms and to ensure that the information required to be disclosed by the Company is accumulated and communicated to management, including our Principal Executive Officer and our Principal Financial Officer, to allow timely decisions regarding required disclosure.

b)

There has been no change in our internal control over financial reporting during the fourth quarter ended December 31, 2018, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Our Principal Executive and Financial Officer do not expect that our disclosure controls or internal controls will prevent all error and all fraud. Although our disclosure controls and procedures were designed to provide reasonable assurance of achieving their objectives and Principal Executive and Financial Officer have determined that our disclosure controls and procedures are effective at doing so, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute assurance that the objectives of the system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented if there exists in an individual a desire to do so. There can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. Internal control over financial reporting refers to the process designed by, or under the supervision of, our Principal Executive Officer and Principal Financial Officer, and effected by our Board of Directors, management and other personnel, 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, and includes those policies and procedures that:

39

1)

Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

2)

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and,

3)

Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has used the framework set forth in the report entitled “Internal Control – Integrated Framework” published by the Committee of Sponsoring Organizations of the Treadway Commission to evaluate the effectiveness of the Company’s internal control over financial reporting. Management has concluded that the Company’s internal control over financial reporting was effective as of the end of the most recent fiscal year.

This annual report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Form 10-K.

ITEM 9B.    OTHER INFORMATION

None.

40

PART III

ITEM 10    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

(a)    Identification of Directors and Executive Officers. The following table sets forth the names and ages of the Directors and Executive Officers of the Company, all positions and offices with the Company held by such person, and the time during which each such person has served:

Name	Age	Position with Company	Period Served
Roger D. Bryant	76	Principal Executive Officer,	June 9, 2013-present
		Director	July 1997-present
Phillip H. Roberson	50	President,	December 2013-present
		Principal Financial Officer,	July 2013-present
		Director	November 11, 2014 - present
Karl W. Reimers	77	Director	October 2004-October 2018
Dan Robinson	71	Director	August 2004-present
Nancy Stephenson	65	Director	October 2012-October 2018

Mr. Bryant serves as Chairman of the Board of the Corporation, and as its Principal Executive. He has been a Director of the Company since July 1997. For more than thirty years, Mr. Bryant has held senior management positions with public and private companies in a number of different industries. Positions include Chief Executive Officer and Chairman of Canmax, Inc., a publicly traded software development company, President of Network Data Corporation, President of Dresser Industries, Inc., Wayne Division, President of Schlumberger Limited, Retail Petroleum Systems Division, U.S.A., and President of Autogas Systems, Inc., the developer of “Pay-at-the-Pump” technology for the retail petroleum industry. Mr. Bryant holds a Bachelor of Science degree in Electrical Engineering from the University of Alabama and has served on the Board of Directors of more than ten private and public companies. He currently serves on the Board of Directors of two private companies, HOBI International, Inc. and Leopard Mobility, Inc., both in the electronics remanufacturing and distribution business.

Mr. Roberson, age 50, was engaged to take operational control of the business on June 14, 2013. He was named Principal Operating Officer and Principal Financial Officer on July 1, 2013. Prior to joining FieldPoint, he was founder of AEG Operating LLC, an independent oil and gas exploration company, where he was instrumental in the funding, acquisition and day to operations of the firm’s operated and non-operated properties. Previously, he served as a director of Energy Investment Banking with Tejas Securities, Inc. where he assisted Exploration & Production and Energy Service companies with debt & equity offerings. Until it was acquired by Tejas Securities, Mr. Roberson was an Equity Analyst with Arabella Securities, LLC, covering Energy and Special Situation companies. Mr. Roberson received a Bachelor of Business Administration in Finance from the University of Texas at Austin and is a licensed Certified Public Accountant.

Mr. Reimers, age 77, served as a director of the Company from October 2004 to October 2018. Mr. Reimers has held the position of President and CFO of B.A.G. Corp. from 1993 until his retirement in 2010. He served as Vice President and CFO of Supreme Beef Company from 1989 to 1993. He also held the position of Vice President of Accounting at OKC Corp., a NYSE listed oil and gas company from 1975 to 1989. He was employed by Peat, Marwick, Mitchell, Certified Public Accountants, from 1973 to 1975, and he holds an MBA from the University of Texas at Arlington. Mr. Reimers did not stand for reelection to the Board in October 2018.

Mr. Robinson, age 71, has served as a director of the Company since August 2004. He has held the position of President and Chief Executive Officer of Placid Refining Company LLC from December 1994 to the present. Prior to his current position, he served in many capacities with Placid Oil Company beginning in March 1975, including the roles of Project Engineer, Manager of Refinery Operations, Assistant Secretary, Assistant Treasurer, Secretary, and Treasurer. Before beginning his 42 year oil and gas career he was briefly employed as a commercial credit analyst at First National Bank in Dallas. Mr. Robinson received a BS degree in Mechanical Engineering in 1971 and an MBA degree in Finance in 1973, both from the University of Wisconsin. He currently sits on the Board of Directors of the American Fuel & Petrochemical Manufacturers (AFPM).

41

Nancy Stephenson, age 65, was a director of the Company from October 2012 to October 2018.  From August 2011 to August 2012 she served as Chief Accounting Officer, Treasurer and Secretary of Cross Border Resources Inc. (XBOR) and served as Assistant Controller at Forge Energy, LLC, a private company, from January 2014 through March 2015. Ms. Stephenson is semi-retired and does occasional consulting engagements. Ms. Stephenson has over 30 years of accounting experience, primarily in publicly traded companies in the energy business. From March 2003 to February 2010, she served as Compliance Reporting Manager for TXCO Resources Inc. (TXCO). For both XBOR and TXCO she prepared financial statements and was responsible for periodic reporting compliance with the SEC. Since March 2010, she has provided consulting services relating to periodic reporting with the SEC on a project basis for various companies. Ms. Stephenson holds a BBA in Accounting from the University of Houston and is a Certified Public Accountant. Ms. Stephenson did not stand for reelection to the Board in October 2018.

No family relationship exists between any director or executive officer.

There are no material proceedings to which any director, officer or affiliate of the Company, any owner of record or beneficially of more than five percent (5%) of any class of voting securities of the Company, or any associate of any such director, officer, affiliate of the Company, or security holder is a party adverse to the Company or any of its subsidiaries or has a material interest adverse to the Company or any of its subsidiaries.

During the last ten (10) years no director or officer of the Company has:

a.

had any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time;

b.

been convicted in a criminal proceeding or subject to a pending criminal proceeding;

c.

been subject to any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities; or

d.

been found by a court of competent jurisdiction in a civil action, the Commission 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.

Any transactions between the Company and its officers, directors, principal shareholders, or other affiliates have been and will be on terms no less favorable to the Company than the Board of Directors believes could be obtained from unaffiliated third parties on an arms-length basis and will be approved by a majority of the Company's independent, outside disinterested directors.

Meetings and Committees of the Board of Directors

a.       Meetings of the Board of Directors

During the fiscal year ended December 31, 2018, the Board of Directors held one meeting which was attended by all of the directors.

42

At the December 6, 2013, meeting, the Board approved the Compensation Committee's recommendation to restructure Board compensation effective for 2014. The structure increased the fee for in-person meetings to $1,000 and provides for fees to compensate committee chairmen. Each board member received approximately $39,500 for their service during 2014. Roger Bryant was paid $10,000 per month plus meeting fees as Executive Chairman. Each board member received approximately $27,000 for their service during 2015 and Roger Bryant was paid $91,000 as Executive Chairman. At the October 23, 2015, meeting the Board reaffirmed and ratified its previously adopted action to provide annual cash retainers of $120,000 per year for Roger Bryant, and $30,000 per year for all non-executive directors (which shall be in addition to Committee fees), and $1,000 for each in-person meeting effective January 1, 2016.  However, it also adopted a measure to temporarily accept a voluntary reduction in Roger Bryant's annual retainer to $90,000 per year, and to temporarily accept a voluntary reduction of the annual cash retainer to $15,000 for all non-executive directors, and to temporarily accept a voluntary reduction to $500 per in-person meeting until such time as economic conditions shall improve, provided that each and all of these voluntary reductions shall be retroactively reinstated and payable in the case of (and only in the case of) a Change of Control Event.  All voluntary reductions were temporarily effective as of January 1, 2016, and shall continue until such time as the Board determines that they shall cease.

Director and Committee fees of approximately $153,000 were accrued but have not been paid during the year ended December 31, 2018. In addition, Board and Committee fees of approximately $19,000 for December 2017 were accrued but have not been paid. The amounts accrued but not paid as of December 31, 2018 and 2017, were approximately $172,000 and $19,000, respectively.

b.       Committees

The Board appoints committees to help carry out its duties. In particular, Board committees work on key issues in greater detail than would be possible at full Board meetings. Each committee reviews the result of its meetings with the full Board.

During the year ended December 31, 2017, the Board had a standing Audit Committee, a standing Compensation Committee, and a standing Nomination Committee. However, these committees became inactive effective October 28, 2018, when two independent board members did not stand for reelection, and their positions were not required to be filled. All matters that were formerly addressed by Committees are now taken up at the Board level until new independent directors are elected or named.

Audit Committee

The Audit Committee was composed of the following directors from January 1 to October 28, 2018:

Nancy Stephenson, Chairperson

Karl W. Reimers

Dan Robinson

The Board of Directors has determined that Messrs. Reimers, Robinson, and Ms. Stephenson are "independent" within the meaning of the NYSE American, LLC's listing standards and Item 407(a) of Regulation S-K. For this purpose, an Audit Committee member is deemed to be independent if he or she does not possess any vested interests related to those of management and does not have any financial, family or other material personal ties to management. Karl Reimers and Nancy Stephenson, each a member of the Audit Committee, qualify as an "audit committee financial expert" within the meaning of Item 407(d)(5) of Regulation S-K.

43

During the fiscal year ended December 31, 2018, the Audit Committee had three meetings. The committee is responsible for accounting and internal control matters. The Audit Committee:

-

reviews with management, the external consultants and the independent auditors policies and procedures with respect to internal controls;

-

reviews significant accounting matters;

-

approves any significant changes in accounting principles of financial reporting practices;

-

reviews independent auditor services; and

-

recommends to the Board of Directors the firm of independent auditors to audit our consolidated financial statements.

In addition to its regular activities, the committee is available to meet with the independent accountants, external consultants whenever a special situation arises.

The Audit Committee of the Board of Directors has adopted a written charter, which has been previously filed with the Commission.

Compensation Advisory Committee

The Compensation Advisory Committee was composed of the following directors from January 1 to October 28, 2018:

Dan Robinson, Chairman

Karl Reimers

Nancy Stephenson

The Board of Directors has determined that Messrs. Robinson, Reimers and Stephenson are "independent" within the meaning of the NYSE American, LLC's listing standards and Item 407(a) of Regulation S-K. For this purpose, a Compensation Committee member is deemed to be independent if he does not possess any vested interests related to those of management and does not have any financial, family or other material personal ties to management.

From January 1 to October 28, 2018, the Compensation Advisory Committee had one meeting. The Compensation Advisory Committee:

-

Recommends to the Board of Directors the compensation and cash bonus opportunities based on the achievement of objectives set by the Compensation Advisory Committee with respect to our Chairman of the Board and President, our Chief Executive Officer and the other executive officers;

-

administers our compensation plans for the same executives;

-

determines equity compensation for all employees;

-

reviews and approves the cash compensation and bonus objectives for the executive officers; and

-

reviews various matters relating to employee compensation and benefits.

44

Nomination Committee

The Nomination Committee was composed of the following directors from January 1 to October 28, 2018:

Karl Reimers, Chairman

Nancy Stephenson

Dan Robinson

The Board of Directors has determined that Mr. Reimers, Mrs. Stephenson and Mr. Robinson are “independent” within the meaning of the NYSE American, LLC's listing standards and Item 407(a) of Regulation S-K. For this purpose, a director is deemed to be independent if he does not possess any vested interests related to those of management and does not have any financial, family or other material personal ties to management. The committee had one meeting in 2018.

The Board of Directors has not adopted a policy with regard to the consideration of any director candidates recommended by security holders, since to date the Board has not received from any security holder a director nominee recommendation. The Board of Directors will consider candidates recommended by security holders in the future. Security holders wishing to recommend a director nominee for consideration should contact Mr. Phillip H. Roberson, President, Chief Operating Officer and Chief Financial Officer, at the Company's principal executive offices located in Austin, Texas and provide to Mr. Roberson, in writing, the recommended director nominee's professional resume covering all activities during the past five years, the information required by Item 401 of Regulation S-X, and a statement of the reasons why the security holder is making the recommendation. Such recommendation must be received by year end for consideration in the next year’s elections.

The Board of Directors believes that any director nominee must possess significant experience in business and/or financial matters as well as a particular interest in the Company's activities.

Shareholder Communications

Any shareholder of the Company wishing to communicate to the Board of Directors may do so by sending written communication to the Board of Directors to the attention of Mr. Roger Bryant, Principal Executive Officer, or Mr. Phillip Roberson, Chief Financial Officer, at the principal executive offices of the Company. The Board of Directors will consider any such written communication at its next regularly scheduled meeting.

Any transactions between the Company and its officers, directors, principal shareholders, or other affiliates have been and will be on terms no less favorable to the Company than could be obtained from unaffiliated third parties on an arms-length basis and will be approved by a majority of the Company's independent, outside disinterested directors.

Code of Ethics

Our Board of Directors adopted a Code of Business Conduct and Ethics for all of our directors, officers and employees during the fiscal year ended December 31, 2003. Our Code of Business Conduct and Ethics can be found at our website address: http://www.fppcorp.com. We will provide to any person without charge, upon request, a copy of our Code of Business Conduct and Ethics. Such request should be made in writing and addressed to Investor Relations, FieldPoint Petroleum Corporation, 609 Castle Ridge Road, Suite 335, Austin, Texas 78746. Further, our Code of Business Conduct and Ethics is filed as an exhibit to the Company’s Annual Report on Form 10-KSB for the fiscal year ending December 31, 2003.

COMPLIANCE WITH SECTION 16(a) OF THE SECURITIES EXCHANGE ACT

Section 16 (a) of the Securities Exchange Act of 1934, as amended, requires the Company's executive officers, directors and persons who own more than ten percent of the Common Stock (collectively, "Reporting Persons") to file initial reports of ownership and changes of ownership of the Common Stock with the SEC and the NYSE MKT. Reporting Persons are required to furnish the Company with copies of all forms that they file under Section 16(a). Based solely upon our search of publicly available information or information provided to the Company from Reporting Persons, during the two years ended December 31, 2018, the Company is not aware of any failure on the part of any Reporting Persons to timely file reports required pursuant to Section 16(a).

45

ITEM 11     EXECUTIVE COMPENSATION

COMPENSATION DISCUSSION AND ANALYSIS

Introduction. This Compensation Discussion and Analysis (“CD&A”) provides an overview of the Company’s executive compensation program together with a description of the material factors underlying the decisions which resulted in the compensation provided for 2018 to the Company’s “Named Executive Officers” (or “NEOs”), as presented in the tables which follow this CD&A. The following discussion and analysis contains statements regarding future individual and Company performance targets and goals. These targets and goals are disclosed in the limited context of the Company’s compensation programs and should not be understood to be statements of management’s expectations or estimates of financial results or other guidance. The Company specifically cautions investors not to apply these statements to other contexts.

Compensation Committee. The Compensation Committee (the “Committee”) of the Board of Directors was until October 28, 2018 composed of three non-employee directors, all of whom are independent under the guidelines of the NYSE American listing standards. Until October 28, 2018, the Committee members were Dan Robinson, Karl Reimers and Nancy Stephenson. The Committee had responsibility for determining and implementing the Company’s philosophy with respect to executive compensation. To implement this philosophy, the Committee oversaw the establishment and administration of the Company’s executive compensation program.

Since October 28, 2018, the Board of Directors as a whole assumed the functions of the Compensation Committee. All references to the Compensation Committee in this Report related to periods after October 28, 2018 refer to the Board of Directors performing the functions of the Compensation Committee.

Compensation Philosophy and Objectives. The guiding principle of the Committee’s executive compensation philosophy is that the executive compensation program should enable the Company to attract, retain and motivate a team of highly qualified executives who will create long-term value for the shareholders. To achieve this objective, the Committee has developed an executive compensation program that is ownership-oriented and that rewards the attainment of specific annual, long-term and strategic goals that will result in improvement in total shareholder return. To that end, the Committee believes that the executive compensation program should include both cash and equity-based compensation that rewards specific performance. In addition, the Committee continually monitors the effectiveness of the program to ensure that the compensation provided to executives remains competitive relative to the compensation paid to executives in a peer group comprised of select container industry and other manufacturing companies. The Committee annually evaluates the components of the compensation program as well as the desired mix of compensation among these components. The Committee believes that a substantial portion of the compensation paid to the Company’s NEOs should be at risk, contingent on the Company’s operating and market performance. Consistent with this philosophy, the Committee will continue to place significant emphasis on stock-based compensation and performance measures, in an effort to more closely align compensation with shareholder interests and to increase executives’ focus on the Company’s long-term performance.

Committee Process. The Committee meets as often as necessary to perform its duties and responsibilities. The Committee usually meets with the Executive Chairman and the President and CFO. In addition, the Committee periodically meets in executive session without management.

The Committee’s meeting agenda is normally established by the Committee Chairperson in consultation with the Executive Chairman and the President and CFO. Committee members receive and review materials in advance of each meeting. Depending on the meeting’s agenda, such materials may include: financial reports regarding the Company’s performance, reports on achievement of individual and corporate objectives, reports detailing executives’ stock ownership and options, tally sheets setting forth total compensation and information regarding the compensation programs and levels of certain peer group companies.

Role of Executive Officers in Compensation Decisions. The Committee makes all compensation decisions for the NEOs. Decisions regarding the compensation of other employees are made by the Executive Chairman and the President and CFO in consultation with the Committee. In this regard, the NEOs provide the Committee evaluations of executive performance, business goals and objectives and recommendations regarding salary levels and equity awards.

46

Market-Based Compensation Strategy. The Committee adopted the following market-based compensation strategy:

●

Pay levels are evaluated and calibrated relative to other companies of comparable size operating in the oil and gas exploration business (the “Peer Group”) as the primary market reference point. In addition, general industry data is reviewed as an additional market reference and to ensure robust competitive data.

●

Target total direct compensation (target total cash compensation plus the annualized expected value of long-term incentives) levels for NEOs are calibrated relative to the Peer Group.

●

Base salary and target total cash compensation levels (base salary plus target annual incentive) for NEOs are calibrated to the Peer Group.

●

The long-term incentive component of the executive compensation program is discretionary and viewed in light of the target total direct compensation level.

The Committee retains discretion, however, to vary compensation above or below the targeted percentile based upon each NEO’s experience, responsibilities and performance.

Total Direct Compensation

Our objective is to target total direct compensation, consisting of cash salary, cash bonus and long term equity compensation at levels consistent with the surveyed companies, if specified corporate and business unit performance metrics and individual performance objectives are met. We selected this target for compensation to remain competitive in attracting and retaining talented executives. Many of our competitors are significantly larger and have financial resources greater than our own. The competition for experienced, technically proficient executive talent in the oil and gas industry is currently particularly acute, as companies seek to draw from a limited pool of such executives to explore for and develop hydrocarbons that increasingly are in more remote areas and are technologically more difficult to access.

Components of Compensation. For the years ended December 31, 2017 and 2018, the largest component of compensation for the Officers of the Company was base salary. We did provide additional compensation in the form of a stock bonus to the President/CFO in 2016. Mr. Roberson was entitled to a stock bonus of 6,000 shares in July 2018 but declined the bonus.

Base Salary. The Company provides the NEOs with base salaries to compensate them for services rendered during the year. The Committee believes that competitive salaries must be paid in order to attract and retain high quality executives. The Committee reviews the NEO’s salaries at the end of each year, with any adjustments to base salary becoming effective on January 1 of the succeeding year.

In determining base salary level for executive officers, the committee considers the following qualitative and quantitative factors:  

●

job level and responsibilities,

●

relevant experience,

●

individual performance,

●

recent corporate performance.

We review base salaries annually, but we do not necessarily award salary increases each year. From time to time base salaries may be adjusted other than as a result of an annual review, in order to address competitive pressures or in connection with a promotion.

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Base salaries paid to the NEOs are deductible for federal income tax purposes except to the extent that the executive’s aggregate compensation which is subject to Section 162(m) of the Internal Revenue Code (the “Code”) exceeds $1 million.

The Company entered into an “at will” employment agreement with Phillip Roberson as President and Chief Financial Officer (“CFO”) for a three-year period beginning July 1, 2014. Mr. Roberson was awarded, as part of his annual compensation, 5,000 shares on his third anniversary date, 6,000 shares on his fourth anniversary date, 7,000 shares on his fifth anniversary date, 8,000 shares on his sixth anniversary date, 9,000 shares on his seventh anniversary date, and 10,000 shares on each annual anniversary date thereafter. However, Mr. Roberson declined the 5,000 and 6,000 shares that would have been awarded on his third and fourth anniversary dates, July 1, 2017 and 2018, respectively. On August 10, 2018, the Compensation Committee ratified the automatic extension of Mr. Roberson’s contract to July 1, 2019.

The following tables and discussion set forth information with respect to all plan and non-plan compensation awarded to, earned by or paid to the Company's four (4) most highly compensated executive officers, for all services rendered in all capacities to the Company and its subsidiaries for each of the Company's last three (3) completed fiscal years; provided, however, that no disclosure has been made for any executive officer, other than the CEO, whose total annual salary and bonus does not exceed $100,000.

SUMMARY COMPENSATION TABLE

Name and Principal Position	Year	Salary ($)	Bonus	Stock Awards	Options Awards	Non equity Incentive Plan Compensation	Nonqualified Deferred Compensation Earnings	All Other Compensation	Total
Phillip H. Roberson, President, and CFO	2018	$200,000	$-	$-	-	-	-	$6,000(1)	$206,000
Phillip H. Roberson, President, and CFO	2017	$200,000	$-	$-	-	-	-	$6,000(1)	$206,000
Phillip H. Roberson, President, and CFO	2016	$200,000	$-	$12,800	-	-	-	$6,186(1)	$218,986

(1)

Automobile allowance

The following table sets forth information concerning unexercised options, stock that has not vested and equity incentive plan awards for each named executive officer outstanding as of the end of the most recently completed fiscal year:

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OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END TABLE

	Option Awards				Stock Awards
Name	Number of Securities Underlying Unexercised Options Exercisable	Number of Securities Underlying Unexercised Options Unexercisable	Equity Incentive Plan Awards; Number of Securities Underlying Unexercised Unearned Options	Option Exercise Price	Option Exercise Date	Number of Shares or Units of Stock That Have Not Vested	Market Value of Shares of Units That Have Not Vested	Equity Incentive Plan Awards; Number of Unearned Shares, Units or Other Rights That Have Not Vested	Equity Incentive Plan Awards; Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested
Roger Bryant	- 0 -	- 0 -	-	-	-	- 0 -	-	-	-
Phillip Roberson	- 0 -	- 0 -	-	-	-	- 0 -	- 0 -	-	-

The following table sets forth information concerning compensation paid to the Company’s directors during the most recently completed fiscal year:

DIRECTOR COMPENSATION TABLE

Name	Fees Earned or Paid in Cash	Stock Awards	Option Awards	Non-Equity Incentive Plan Compensation	Nonqualified Deferred Compensation Earnings	All Other Compensation	Total
Roger Bryant	$91,000(1)	-	-	-	-	-	$91,000
Karl Reimers	$18,500(1)	-	-	-	-	-	$18,500
Dan Robinson	$23,500(1)	-	-	-	-	-	$23,500
Nancy Stephenson	$19,750(1)	-	-	-	-	-	$19,750
Phillip Roberson	$-						$-

(1)

Board and Committee fees of $152,750 were accrued but have not been paid during the year ended December 31, 2018. In addition, Board and Committee fees for December 2017 of $18,852 were accrued but have not been paid.

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Option Grants Table

There were no stock option grants for fiscal years ended December 31, 2017 and 2018.

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

The following table sets forth information with respect to beneficial ownership of our common stock by:

●

each person who beneficially owns more than 5% of the common stock;

●

each of our executive officers named in the Management section;

●

each of our directors; and

●

all executive officers and directors as a group.

The table shows the number of shares owned as of March 29, 2019 and the percentage of outstanding common stock owned as of March 29, 2019. Each person has sole voting and investment power with respect to the shares shown, except as noted.

Name and Address Of Beneficial Owner(2)	Amount and Nature of Beneficial Owner	Percent of Class(1)
Estate of Ray D. Reaves(3)	2,351,350	22.0%
2352007 Ontario Inc. (4)	744,212	7.0%
Michael Herman (5)	663,423	6.2%
LeRoy Landhuis (6)	884,564	8.3%
Roger D. Bryant	34,000	*
Dan Robinson	96,000	*
Karl Reimers	58,100	*
Nancy Stephenson	2,500	*
Phillip Roberson	50,000	*
All Officers and Directors as a Group(5 persons)	240,600	2.3%

___________________________

*      indicates less than 1%

(1)            

The percentages shown are calculated based upon 10,669,229 shares of common stock issued and outstanding at March 29, 2019. In calculating the percentage of ownership, unless as otherwise indicated, all shares of common stock that the identified person or group had the right to acquire within 60 days of the date of this Proxy Statement upon the exercise of options and warrants or conversion of notes are deemed to be outstanding for the purpose of computing the percentage of shares of common stock owned by such person or group, but are not deemed to be outstanding for the purpose of computing the percentage of the shares of common stock owned by any other person.

(2)            

Unless otherwise stated, the beneficial owner's address is 609 Castle Ridge Road, Suite 335, Austin, Texas 78746.

(3)            

Voting and investment power with respect to the shares of common stock held in the Estate of Ray D. Reaves is exercised by the Administrator of the Estate.

(4)            

2352007 Ontario Inc. is a wholly-owned subsidiary of the Natale Rea (2013) Trust. The principal address of 2352007 Ontario Inc. and the Natale Rea (2013) Trust is 9200 Weston Road, Piazzza Villagio, P.O. Box 92030, Vaughan, Ontario L4H 3J3 Canada. The Company has relied exclusively on the Schedule 13D filed by these affiliated stockholders with the SEC on May 4, 2016, in making these disclosures.

(5)            

Includes shares owned by HFT Enterprises, LLC, a Nevada limited liability company, of which Mr. Herman is a control person. The principal address of Michael Herman and HFT Enterprises, LLC., is P.O. Box 81740, Las Vegas, Nevada 89180.

(6)            

The address for LeRoy Landhuis is 212 N. Wahsatch Avenue, Suite 301, Colorado Springs, Colorado 80903

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

During 2017, the Company received notification that Trivista, an entity controlled by Natale Rea, a beneficial owner of approximately 7.00% of our common stock, had become the operator of certain oil and natural gas properties where we have both working and revenue ownership interests. See Footnote 10- Commitments and Contingencies for more disclosures and information regarding Trivista.

During 2017, the Company received joint interest billing statements related to our working interest in these properties subsequent to Trivista becoming the operator aggregating approximately $58,000, which represented 2.6% of our production expenses for the year ended December 31, 2017 and 32.5% of our lease operating expense accrual as of December 31, 2017. In addition, during 2017, we recorded oil and natural gas revenues associated with our revenue ownership interest in these wells subsequent to Trivista becoming the operator aggregating $82,000, which represented 2.8% of our oil and natural gas sales for the year ended December 31, 2017 and 21.8% of our oil and natural gas sales accounts receivable as of December 31, 2017.

During 2018, the Company accrued approximately $123,000 for joint interest billings associated with our working interest in these oil and natural gas properties, which represented 10.2% of our production expenses for the year ended December 31, 2018 and 81.1% of our lease operating expense accrual as of December 31, 2018. In addition, during 2018, we recorded oil and natural gas revenues associated with our revenue ownership interest in these wells aggregating $212,000, which represented 10.1% of our oil and natural gas sales for the year ended December 31, 2018 and 53.7% of our oil and natural gas sales accounts receivable as of December 31, 2018.

During 2018 and 2017, the Company accrued Board of Director fees of approximately $153,000 and $19,000, respectively, but the fees have not been paid by the Company.

During October 2018, the Company sold approximately 6,000 feet of used surplus production tubing to an entity controlled by a shareholder, Mike Herman, for $24,000. We believe this is a fair market price for the tubing as we did not have a facility to store it and did not have any other offers to purchase the tubing.

There were no related party transactions during the year ended December 31, 2017.

ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES

In the last two fiscal years, we have retained Moss Adams LLP as our independent registered public accounting firm. We understand the need for our principal accountants to maintain objectivity and independence in their audit of our financial statements. To minimize relationships that could appear to impair the objectivity of our principal accountants, our Audit Committee has restricted the non-audit services that our principal accountants may provide to us primarily to tax services and audit related services. The Board has adopted policies and procedures for pre-approving work performed by our principal accountants.

After careful consideration, the Audit Committee of the Board of Directors has determined that payment of the below audit fees is in conformance with the independent status of the Company's principal independent accountants. Before engaging the auditors in additional services, the Audit Committee considers how these services will impact the entire engagement and independence factors.

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The following is an aggregate of fees billed for each of the last two fiscal years for professional services rendered by our principal accountants:

	2018	2017	2017
	Moss Adams	Moss Adams	Hein & Associates
Audit fees - audit of annual financial statements and review of financial statements included in our quarterly reports, services normally provided by the accountant in connection with statutory and regulatory filings.	$101,265	$48,641	$61,800
Audit-related fees - related to the performance of audit or review of financial statements not reported under "audit fees" above	-	-	-
Tax fees - tax compliance, tax advice and tax planning	24,990	-	25,400
All other fees - services provided by our principal accountants  other than those identified above	-	-	-
Total fees paid or accrued to our principal accountants	$126,255	$48,641	$87,200

ITEM 15     EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)    Exhibits

3.1	Articles of Incorporation (incorporated by reference to Amendment No. 1 to Form S-2 dated August 1, 1980.)
3.2(b)	Articles of Amendment of Articles of Incorporation, dated December 31, 1997 (incorporated by reference to the Company's 10KSB for the year ended December 31, 1997.)
3.3	Bylaws (incorporated by reference to Amendment No. 1 to Form S-2 dated August 1, 1980.)
4.1	Plan of Exchange (incorporated by reference to the Company's definitive proxy statement dated December 8, 1997.)
4.2	Indenture (Term Loan) dated June 21, 1999 by and among the Company and Union Planters Bank (incorporated by reference to the Company's 10KSB for the year ended December 31, 1999.)
4.3	Indenture (Term Loan) dated August 18, 1999 by and among the Company and Union Planters Bank (incorporated by reference to the Company's 10KSB for the year ended December 31, 1999.)
4.4.	Stock Option Agreement (incorporated by reference to the Company’s Form S-8 dated May 27, 2005 as filed with the Commission on May 27, 2005.)
4.5	Warrant Agreement and Form of Warrant Certificate (incorporated by reference to the Company’s Form S-3 as filed with the Commission on November 22, 2011.)
10.1	Consulting Agreement dated May 9, 2000 between FieldPoint Petroleum Corp. and Parrish Brian & Co. (incorporated by reference to the Company's 10QSB/A for the quarter ended September 30, 2000.)
10.2	Executive Employment Agreement, dated March 28, 2001, by and among FieldPoint Petroleum Corp. and Ray D. Reaves (incorporated by reference to the Company's 10KSB for the year ended December 31, 2000.)
10.3	Credit Agreement (Revolving Credit Note) dated December 14, 2000 by and among FieldPoint Petroleum Corp. and Union Planters Bank (incorporated by reference to the Company's 10KSB for the year ended December 31, 2000.)

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10.4	Audit Committee Charter adopted by the Company on March 28, 2001(incorporated by reference to the Company's 10KSB for the year ended December 31, 2000.)
10.5	Consulting Agreement dated November 13, 2001 between FieldPoint Petroleum Corp. and TRG Group LLC. (incorporated by reference to the Company's 10QSB for the quarter ended September 30, 2001.)
10.6	Loan and Security Agreement with CitiBank, N.A., dated October 18, 2006 (incorporated by reference from the Company’s current report on Form 8k dated October 18, 2006 as filed with the Commission on October 20, 2006.)
10.7	Lease Assignment from PXP Gulf Coast, Inc., dated March 11, 2004, (incorporated by reference from the Company's Current Report on Form 8-K dated March 11, 2004, as filed with the Commission on March 26, 2004.)
10.8	Securities Purchase Agreement (incorporated by reference to the Company’s Form SB-2 dated September 20, 2005 as filed with the Commission on September 20, 2005.)
10.9	Registration Rights Agreement (incorporated by reference to the Company’s Form S-8 dated May 27, 2005 as filed with the Commission on May 27, 2005.)
10.10	Stock Purchase Agreement (incorporated by reference to the Company’s Form 8-K dated February 6, 2006 as filed with the Commission on February 9, 2006.)
10.11	Board Compensation Agreement (incorporated by reference to the Company’s Form 8-K dated February 6, 2006 as filed with the Commission on February 9, 2006.)
10.12	Security Agreement (incorporated by reference to the Company’s Form 8-K dated October 18, 2006 as filed with the Commission on October 20, 2006).
10.13	Bonus Program (incorporated by reference to the Company’s Form 8-K dated October 24, 2008 as filed with the Commission on October 29, 2008.)
10.14	Guaranty Agreement (incorporated by reference to the Company’s Form 10-Q dated September 30, 2009 as filed with the Commission on November 16, 2009.)
10.15	First Amendment to Loan & Security Agreement (incorporated by reference to the Company’s Form 10-Q dated September 30, 2009 as filed with the Commission on November 16, 2009.)
10.16	Second Amendment to Loan & Security Agreement (incorporated by reference to the Company’s Form 10-Q dated September 30, 2009 as filed with the Commission on November 16, 2009.)
10.17	Third Amendment to Loan & Security Agreement (incorporated by reference to the Company’s Form 10-Q dated September 30, 2009 as filed with the Commission on November 16, 2009.)
10.18	Fourth Amendment to Loan & Security Agreement (incorporated by reference to the Company’s Form 10-Q dated September 30, 2009 as filed with the Commission on November 16, 2009.)
10.19	Fifth Amendment to Loan & Security Agreement (incorporated by reference to the Company’s Form 8-K dated March 21, 2014, as filed with the Commission on March 21, 2014.)

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10.20	Executive Employment Agreement dated July 1, 2014, between FieldPoint Petroleum Corp. and Phillip H. Roberson (incorporated by reference to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014 as filed with the Commission on March 30, 2015.)
10.21	Stock and Mineral Lease Purchase Agreement dated August 12, 2016 (incorporated by reference to the Company’s 8-K dated August 12, 2016, as filed with the Commission on August 17, 2016.)
10.22	Sixth Amendment to Loan and Forbearance Agreement dated October 4, 2016 (incorporated by reference to the Company’s 8-K dated October 4, 2016, as filed with the Commission on October 7, 2016.)
10.23	Amendment No. 1 to Stock and Mineral Lease Purchase Agreement dated January 9, 2017 (incorporated by reference to the Company’s 8-K dated January 9, 2017, as filed with the Commission on January 20, 2017.)
10.24	Seventh Amendment to Loan and Forbearance Agreement dated December 29, 2017 (incorporated by reference to the Company’s 8-K dated December 29, 2017, as filed with the Commission on January 9, 2018.)
10.25	Eighth Amendment to Loan and Forbearance Agreement dated March 30, 2018 (incorporated by reference to the Company’s Annual Report on Form 10-K for the year ended December 31, 2017, as filed with the Commission on April 2, 2018.).
10.26	Ninth Amendment to Loan and Forbearance Agreement dated July 25, 2018 (incorporated by reference to the Company’s Current Report on Form 8-K/A dated July 25, 2018, and filed with the Commission on April 2, 2019.)
10.27	Tenth Amendment to Loan and Forbearance Agreement dated November 7, 2018 (incorporated by reference to the Company’s Current Report on Form 8-K/A dated July 25, 2018, and filed with the Commission on April 2, 2019.)
10.28	Eleventh Amendment to Loan and Forbearance Agreement dated March 29, 2019 (incorporated by reference to the Company’s Current Report on Form 8-K/A dated July 25, 2018, and filed with the Commission on April 2, 2019.)
14.	Code of Ethics (incorporated by reference to the Company’s Annual Report on Form 10-KSB for the year ended December 31, 2003 as filed with the Commission on April 14, 2004.)
31.1	Certification of Principal Executive Officer required by Section 13a-14(a) of the Exchange Act.
31.2	Certification of Principal Operating Officer and Principal Financial Officer required by Section 13a-14(a) of the Exchange Act.
32.1	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Principal Operating Officer and Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1	Evaluation of Oil and Gas Reserves by Russell K. Hall & Associates, Inc. (incorporated by reference to the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 as filed with the Commission on April 15, 2019.)

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SIGNATURES

       In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	FIELDPOINT PETROLEUM CORPORATION
	(Registrant)
Date:    April 15, 2019	By:	/s/ Roger D. Bryant
		Roger D. Bryant
		Principal Executive Officer

Date:    April 15, 2019	By:	/s/ Phillip H. Roberson
		Phillip H. Roberson
		Principal Financial Officer

       In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

By:	/s/ Roger D. Bryant	Date: April 15, 2019
	Roger D. Bryant
	Principal Executive Officer, Director
By:	/s/ Phillip H. Roberson	Date: April 15, 2019
	Phillip H. Roberson
	President, Principal Operating Officer, Principal Financial Officer, and Director
By:	/s/ Dan Robinson	Date: April 15, 2019
	Dan Robinson
	Director

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