UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2012.

[ ] 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

(State or Other Jurisdiction of

Incorporation or Organization)

84-0811034

(I.R.S. Employer

Identification No.)

1703 Edelweiss Drive

Cedar Park, Texas 78613

(Address of Principal Executive Offices) (Zip Code)

(512) 250-8692

(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 [ X ] 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 [ x ]

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. [ X ]

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 [ X ] No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer,

or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller

reporting company” in Rule 12b-2 of the Exchange Act (check one):

Large accelerated filer [___] Accelerated filer [__]

Non-accelerated filer [___] (Do not check if a smaller reporting company) Smaller reporting company [ X ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes No X

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 March 20, 2013, was $19,301,344.

The number of shares outstanding of the registrant’s common stock as of March 20, 2013 is 8,064,836

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.
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PART I

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this Form 10-K constitute “forward-looking statements’ within the

meaning of the Private Securities Litigation Reform Act and Section 27A of the Securities Exchange Act

of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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 forwardlooking 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. Such factors include, among others, the following: the volatility of oil and

natural gas prices, the Company’s drilling and acquisition results, the Company’s ability to replace

reserves, the availability of capital resources, the reliance upon estimates of proved reserves, operating

hazards and uninsured risks, competition, government regulation, the ability of the Company to

implement its business strategy and other factors referenced in this Form 10-K.

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

The Company’s business strategy is to continue to expand its reserve base and increase production and

cash flow through the acquisition of producing oil and natural gas properties. Such acquisitions will be

based on an analysis of the properties' current cash flow and the Company's ability to profit from the

acquisition. The Company's ideal acquisition will include not only oil and natural gas production, but

also leasehold and other working interests in exploration areas.

The Company will also seek to identify promising areas for the exploration of oil and natural gas through

the use of outside consultants and the expertise of the Company. This identification will include

collecting and analyzing geological and geophysical data for exploration areas. Once promising

properties are identified, the Company will attempt to acquire the properties either for drilling oil and

natural gas wells, using independent contractors for drilling operations, or for sale to third parties.
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The Company recognizes that the ability to implement its business strategies is largely dependent on the

ability to raise additional debt or equity capital to 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.

Operations

As of December 31, 2012, the Company had varying ownership interest in 360 gross wells (100.33 net)

located in five states. The Company operates 65 of the 360 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.

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 natural gas industry is highly competitive in all aspects. The Company competes with major

oil companies, numerous independent oil and natural gas producers, individual proprietors, and

investment programs. Many of these competitors possess financial and personnel resources substantially

in excess of those which are available to the Company and may, therefore, be able to pay greater amounts

for desirable leases and define, evaluate, bid for and purchase a greater number of potential producing

prospects that the Company's own resources permit. The Company’s ability to generate resources will

depend not only on its ability to develop existing properties but also on its ability to identify and acquire

proven and unproven acreage and prospects for further exploration.

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 currently use 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 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
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undeveloped reserves associated with future drilling, completion and recompletion projects will require

hydraulic fracturing.

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. We also plan to reuse and recycle flow-back and produced water in 2013.

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
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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.

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 nondiscriminatory 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
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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 state in which we operate, Texas, has 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, Texas imposes 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:

• require the acquisition of various permits before drilling begins;

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

• 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;

• suspend, limit or prohibit construction, drilling and other activities in certain lands lying within

wilderness, wetlands, endangered species habitat, and other protected areas; and

• 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
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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.

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.
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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 new regulations are

designed to reduce volatile organic compound (“VOC”) emissions from hydraulically-fractured natural

gas wells, storage tanks and other equipment. The regulations established a phase-in period that extends

until January 2015. During the phase-in period, owners and operators of hydraulically-fractured natural

gas wells (wells drilled principally for the production of natural gas) must either flare their emissions or

use so-called “green completion” technology. Green completions allow for the recovery of natural gas

that formerly would have been vented or flared. After January 2015, all newly fractured natural gas wells

must use green completion technology. We do not expect that the NSPS or NESHAP will have 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 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 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 adopt and implement regulations that would restrict

emissions of GHGs under existing provisions of the federal Clean Air Act. In response to its

endangerment finding, 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 does not require immediate reductions in GHG emissions. In

March 2012, the EPA proposed GHG emissions standards for fossil fuel-powered electric utility

generating units that would require new plants to meet an output-based standard of 1,000 pounds of
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carbon dioxide equivalent per megawatt-hour. If the proposed regulation is adopted, it could have a

significant impact on the electrical generation industry and may favor the use of natural gas over other

fossil fuels such as coal in new plants. The EPA has also indicated that it will propose new GHG

emissions standards for refineries, but specific proposed regulations are not expected to be issued until

mid-2013.

In December 2010, the EPA enacted final rules on mandatory reporting of GHGs. In November and

December 2011, the EPA 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 beginning on September 28, 2012. Our operations in the Permian Basin are

subject to the EPA’s mandatory reporting rules and we believe that we are in substantial compliance with

such rules. 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 noncompliance with discharge permits or other requirements of the Clean Water Act and analogous state laws

and regulations.

In October 2011, the EPA announced that it intends to develop national standards for wastewater

discharges produced by natural gas extraction from shale and coalbed methane formations. The EPA is

expected to issue proposed regulations establishing wastewater discharge standards for coalbed methane

wastewater in 2013 and for shale gas wastewater in 2014. For shale gas wastewater, the EPA will

consider imposing pre-treatment standards for discharges to a wastewater treatment facility. Produced and

other flowback water from our current operations in the Permian Basin is typically re-injected into

underground formations that do not contain potable water. To the extent that re-injection is not available

for our operations and discharge to wastewater treatment facilities is required, new standards from the

EPA could increase the cost of disposing wastewater in connection with our operations.
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The Safe Drinking Water Act, Groundwater Protection and the Underground Injection Control

Program

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

salt water disposal wells. The EPA has delegated administration of the UIC program 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.

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. 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. Industry groups filed suit challenging the EPA’s

decision as a “final agency action” and, therefore, a violation of the notice-and-comment rulemaking

procedures of the Administrative Procedures Act. In February 2012, the EPA and industry reached a

settlement under which the EPA will modify the informal policy posted on its website concerning the

need for permits under the UIC program. However, the settlement does not reflect agreement on the issue

of hydraulic fracturing regulation under the SDWA, and 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.

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
12

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 SEC has issued subpoenas to certain shale gas producers requesting information on proved

reserve estimates from shale gas wells and the actual productivity of producing shale gas wells. The

media has also reported that the New York attorney general has issued subpoenas to certain oil and gas

companies seeking information regarding shale gas wells.

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. The EPA issued a progress report in December 2012, and final results are

expected in 2014. In addition, the U.S. Department of Energy conducted an investigation into practices

the agency could recommend to better protect the environment from using hydraulic fracturing. The Shale

Gas Subcommittee of the Secretary of Energy Advisory Board released its “90-day” report on August 18,

2011, and its final report on November 18, 2011, proposing recommendations to reduce the potential

environmental impacts from shale gas production. Also, the U.S. Department of the Interior is considering

disclosure requirements or other mandates for hydraulic fracturing on federal lands. These ongoing or

proposed investigations and studies, depending on their degree of pursuit and any meaningful results

obtained, could spur initiatives to further regulate 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
13

December 31, 2012. 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 2013. 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.

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 offices at 1703 Edelweiss Drive, Cedar

Park, Texas 78613, is currently provided by the President at a cost of $2,500 per month as of December

31, 2012.

Employees – As of March 20, 2013, the Company had 4 employees, and the Company considers its

relationship with its employees satisfactory.

ITEM 1A – RISK FACTORS.

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
14

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 substantial decrease 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 likely will

continue to be volatile in the future. This price volatility will also affect our common stock price. We

cannot predict oil and natural gas prices and prices may decline in the future. The following factors have

an influence on oil and natural gas prices, including but not limited to:

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

* storage availability;

* weather conditions;

* market uncertainty;

* domestic and foreign governmental regulations;

* the availability and cost of alternative fuel sources;

* the domestic and foreign supply of oil and natural gas;

* the price of foreign oil and natural gas;

* refining capacity;

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

* 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.

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.
15

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:

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

• the assumed effects of regulations by governmental agencies;

• assumptions concerning future oil, NGL and gas prices; and

• 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:

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

• the production and operating costs incurred;

• the amount and timing of future development expenditures; and

• 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
16

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 affect on our financial condition and operating results.

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:

* Value of the properties and likelihood of future production;

* Recoverable reserves;

* Operating costs;

* Potential environmental and other liabilities;

* Drilling and production difficulties; and

* 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:

* Fires;

* Explosions;

* Blowouts;

* Encountering formations with abnormal pressures;

* Spills

* Natural disasters;

* Pipeline ruptures;

* Cratering
17

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

* injury or loss of life;

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

* pollution or other environmental damage;

* clean-up responsibilities;

* regulatory investigation and penalties; and

* 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.

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 affect 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:

* from a well or drilling equipment at a drill site;

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

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

* 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.
18

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.

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.

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

President Obama’s Proposed Fiscal Year 2013 Budget includes 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:

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

• elimination of current deductions for intangible drilling costs;

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

• 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
19

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.

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.

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
20

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.

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 changed from time to time in response to economic conditions. Matters

subject to regulation by federal, state and local authorities include:

* Permits for drilling operations;

* The production and disposal of water;

* Reports concerning operations;

* Unitization and pooling of properties;

* Road and pipeline construction;

* The spacing of wells;

* Taxation;

* Production rates;

* The conservation of oil and natural gas; and

* 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
21

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, since the issuance of the Warrants in March 2012 we

reclassified $6,895,361 of retained earnings to additional paid-in capital, there may be no capacity for the

Company to declare a cash dividend in the near future.

ITEM 1B. – UNRESOLVED STAFF COMMENTS.

None.

ITEM 2-PROPERTIES

Principal Oil and Natural Gas Interests

Block A-49 and Block 6 Field, Andrews County, Texas is a producing oil field located in Andrews,

Texas. The Company owns a 74%-100% working interest in five 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% to 15% working interest in five oil and natural gas wells

producing out of the Spraberry formation at a depth of approximately 7,000 feet.

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.

Apache Field, Caddo County, Oklahoma is a waterflood project producing from the Viola/Bromide

formation. The Apache Bromide Unit is located approximately 5 miles west of the town of Apache and
22

25 miles north of Lawton, Oklahoma. The Company has a 25.23% working interest in the unit which

consists of 11 producing oil wells and 9 water injection wells.

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.

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 two oil and natural gas wells

producing out of the Bonesprings and Yates formations in section 15 at depth ranging from approximately

3,400 feet to approximately 10,000 feet and a 43.75% working interest in two wells drilled and producing

out of the Bonesprings formation. 14.06% working interest in one oil and natural gas well producing out

of the Wolfcamp formation in section 14. The Company also owns an 87.5% working interest in one

water disposal well.

Loving North Morrow Field, Eddy County, New Mexico is a producing natural gas field located 2

miles west of Loving, New Mexico and 12 miles south east of Carlsbad, New Mexico. The Company

owns a 4.3% - 12% working interest in three natural gas wells producing out of the Morrow formation

from a depth of approximately 12,300 feet to 12,450 feet.

Chickasha Field, Grady County, Oklahoma is a waterflood project producing from the Medrano Sand.

The Rush Springs Medrano Unit is located approximately 65 miles southwest of Oklahoma City,

Oklahoma. The Company has a 20.64% working interest in the unit which consists of 21 producing oil

and natural gas wells and 11 water injection wells.

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.

Giddings Field, Fayette County, Texas is in the Austin Chalk field located in various counties

surrounding the city of Giddings, Texas. In February 1998, the Company acquired a 97% working

interest in the Shade lease. The lease currently has three producing oil and natural gas wells. Oil and

natural gas are produced from the Austin chalk formation. The Company will evaluate whether additional

reserves can be developed by use of horizontal well technology.

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 three 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 working interest in 50

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.
23

Tuleta West Field, Bee County Texas, is a natural gas field located North of Corpus Christi, Texas. The

Company owns a 5% working interest in one natural gas well producing from the Wilcox formation at a

depth of approximately 12,000 feet.

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 2012 2011 2012 2011

Louisiana 33 32 9,200 9,286

New Mexico 49,897 16,568 118,564 86,228

Oklahoma 33,160 30,194 27,610 19,102

Texas 14,955 19,395 24,724 28,526

Wyoming 6,240 3,206 - -

TOTAL 104,285 69,395 180,098 143,142

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 end December 31, 2012,

purchases by three customers, Cimarex Energy Co.,Sunoco and Enterprise Crude represented more than

10% of total Company revenues. During the year ended December 31, 2011, purchases by each of four

customers, Sunoco, Enterprise Crude, Ram Energy Resources, and Quantum Resources 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.

Productive Wells

The table below sets forth certain information regarding the Company's ownership, as of December 31,

2012, 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 8 2.91 4 .61

Oklahoma 228 51.13 37 4.59

Texas 70 34.12 8 4.15

Wyoming 3 2.58 - -

Total 309 90.74 51 9.59

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.
24

Drilling Activity

The tables below set forth certain information regarding the number of productive and dry exploratory

and development wells drilled for the fiscal year ended December 31, 2012.

Exploratory Wells Development Wells

State Productive Dry Productive Dry

Louisiana -- -- -- --

New Mexico -- -- 1 --

Oklahoma -- -- -- --

Texas -- -- -- --

Wyoming -- -- -- --

_______ _______ _______ _______

Total -- -- 1 --

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, 2012 and 2011. See Notes 11 and 12 to the Consolidated Financial Statements and

the following discussion.

Estimated Proved Reserves

Proved Reserves Oil (Bbls) Gas (Mcf)

Estimated quantity, January 1, 2011 1,168,955 2,638,656

Revisions of previous estimates (20,872) (430,706)

Extensions and discoveries 123,526 204,740

Sales of reserves (1,950) -

Production (69,395) (143,142)

Estimated quantity, December 31, 2011 1,200,264 2,269,548

Revisions of previous estimates 13,854 48,955

Extensions and discoveries 115,093 209,930

Sales of reserves - -

Production (104,285) (180,098)

Estimated quantity, December 31, 2012 1,224,926 2,348,335
25

Proved Developed and Undeveloped Reserves

Developed Undeveloped Total

Oil (Bbls)

December 31, 2012 983,900 241,026 1,224,926

December 31, 2011 980,341 219,923 1,200,264

Gas (Mcf)

December 31, 2012 1,898,705 449,630 2,348,335

December 31, 2011 1,922,181 347,367 2,269,548

Proved Undeveloped Reserves

As of December 31, 2012, we had 315,964 BOE of proved undeveloped (“PUD”) reserves, which is an

increase of 38,147 BOE or 14%, compared with 277,818 BOE of PUD reserves at December 31, 2011. As

a percent of our total proved reserves, our PUD reserves increased from 18% in 2011 to 20% in 2012 due

to our ongoing development of our East Lusk field.

The following table summarizes the changes in our PUD reserves during 2012.

Oil (Bbls) Gas (Mcf) Total (BOE)

Balance – December 31, 2011 219,923 347,367 277,818

Extensions and discoveries 113,678 253,344 155,902

Revisions to previous estimates (23,120) (31,801) (28,421)

Conversion to proved developed reserves (69,455) (119,280) (89,335)

Balance – December 31, 2012 241,026 449,630 315,964

The following table sets forth our PUD reserves converted to proved developed reserves during 2012 and

2011 and the net investment required to convert PUD reserves to proved developed reserves during the

year.

Proved Undeveloped Reserves Converted

to Proved Developed Reserves

Investment in

Conversion of

Proved Undeveloped

Reserves to Proved

Developed Reserves

Year Ended December 31, Oil (Bbls) Gas (Mcf) Total (BOE)

2011 70,900 121,760 91,193 $ 4,200,000

2012 69,455 119,280 89,335 3,000,000

Total 140,355 241,040 180,528 $ 7,200,000
26

The following table sets forth our estimated future development costs relating to the development of PUD

reserves:

Year Ended December 31, Estimated Future Development Costs

2013 $ 2,625,000

2014 20,000

2015 1,877,000

2016 165,000

2017 -

Total $ 4,687,000

We monitor fluctuations in commodity prices, drilling and completion costs, operating expenses and

drilling success to determine adjustments to our drilling and development program. We plan to drill the

East Lusk Federal Well #3 starting mid-year 2013. Based on current expectations for cash flows,

commodity prices and operating costs and expenses, all PUD reserves are scheduled to be drilled before

the end of 2017.

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,

2012 and December 31, 2011 have been estimated by Fletcher Lewis Engineering, Inc., and PGH

Engineers. These 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. Ray Reaves, President and CEO, 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 employee responsible for reviewing their use

of our data and estimation of our reserves. Mr. Reaves, who has over twenty years of experience as a

chief executive officer 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. Reaves

also reviews the preliminary reserve estimates and the financial inputs in the estimates. Mr. Reaves

calculates 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
27

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.

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 Notes 11 and 12 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, 2012, 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
28

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 certified petroleum landmen to review title.

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, 2012. 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 320 78 - -

New Mexico 2,400 896 480 262

Oklahoma 8,826 1,300 200 19

Texas 3,263 1,200 1,360 1,000

Wyoming 560 268 2,306 1,880

Total 15,369 3,742 4,346 3,161

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

None.

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

None.
29

PART II

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

STOCKHOLDER MATTERS

Since September 20, 2005 the Company's common stock has been traded and listed on the NYSE MKT,

LLC, formerly the 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 MKT, LLC for the periods shown.

FISCAL 2011 CLOSING PRICE

HIGH LOW

First Quarter 5.48 3.61

Second Quarter 5.00 2.88

Third Quarter 3.33 2.01

Fourth Quarter 4.97 1.72

FISCAL 2012

HIGH LOW

First Quarter 6.00 3.81

Second Quarter 4.69 3.15

Third Quarter 5.21 3.60

Fourth Quarter 4.80 3.42

At March 20, 2013, the approximate number of shareholders of record was 319. The Company has not

paid any cash dividends on its common stock and does not expect to do so in the foreseeable future.
30

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.

Years Ended December 31,

2012 2011

Statements of Operations Data:

Total revenues $10,402,889 $ 7,235,860

Operating expenses 7,314,380 6,072,903

Net income 2,112,263 602,564

Basic earnings per share $ 0.26 $ 0.08

Shares used in computing basic earnings per share 8,006,959 8,015,878

Diluted earnings per share $ 0.25 $ 0.08

Shares used in computing diluted earnings per share 8,452,429 8,015,878

December 31,

Balance Sheet Data: 2012 2011

Working capital $ 2,109,552 $ 1,019,901

Total assets 23,135,430 21,362,889

Total liabilities 11,953,965 12,487,276

Stockholders' equity 11,181,465 8,875,613
31

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 its operating activities including sales of oil

and natural gas and operating oil and natural gas properties. The Company's capital for investment in

producing oil and natural gas properties has been provided by cash flow from operating activities and

from bank financing. The Company categorizes its operating expenses into the categories of production

expenses and other expenses.

Results of Operations

Years Ended December 31,

2012 2011

Revenues:

Oil sales $ 9,457,292 $ 6,364,308

Natural gas sales 783,336 745,017

Total $ 10,240,628 $ 7,109,325

Sales volumes:

Oil (Bbls) 104,285 69,395

Natural gas (Mcf) 180,098 143,142

Total (BOE) 134,301 93,252

Average sales prices

Oil ($/Bbl) $ 90.69 $ 91.71

Natural gas ($/Mcf) 4.35 5.20

Total ($/BOE) $ 76.25 $ 76.24

Costs and expenses ($/BOE)

Lease operating $ 16.39 $ 20.78

Production taxes 8.38 5.47

Depletion and depreciation 15.58 11.99

Impairment of oil and natural gas properties 1.52 14.56

Accretion of discount on asset retirement obligations 0.68 0.90

General and administrative 11.92 11.43

Total $ 54.47 $ 65.13
32

Revenues

Oil and natural gas sales revenues increased by $3,131,303 or 44%, primarily due to increased production.

Oil sales increased $3,093,000 due to increased production that contributed $3,200,000 to the increase in

oil sales revenues offset by $107,000 due to slightly lower prices. Oil sales volumes increased by 50%,

primarily due to production from the two new wells in New Mexico completed in December, 2011 and

September 2012. Natural gas sales increased $38,000 or 5%, due primarily to increased natural gas

production in 2012. Oil and natural gas prices have been volatile during 2012 and the Company expects

this to continue. FieldPoint’s oil and natural gas sales revenue will be highly dependent on commodity

prices in 2013.

Lease Operating Expenses

Lease operating expenses increased by $263,811 or 14% due to a combination of increased sales volumes

and decreased cost. Cost decreased by $4.39 per barrel equivalent (BOE) or 21% in 2012 as compared to

2011. Increased sales volumes contributed approximately $853,000 to the increase in costs and was offset

approximately $589,000 in lower costs as a result of reduced remedial repairs from the prior year. Many

of FieldPoint’s properties are mature and bear high operating expense which could result in increased

operating costs in the future.

Production Taxes

Production taxes increased $615,269 or 121%, primarily the result of increased oil and natural gas sales

revenues as discussed above and an increase in the tax paid to the Apache Tribe. Production taxes

amounted to approximately 11% of oil and natural gas sales revenue during 2012 and 7.2% during 2011.

The increase was a result of an unanticipated charge of previous years’ taxes paid to the Apache Tribe in

2012. Management expects production taxes to range between 7% and 9% of oil and natural gas sales

revenue.

Depletion and Depreciation

Depletion and depreciation expense increased by $974,000 or 87%. The increase in depletion and

depreciation was primarily due to depletion on two new wells completed in September 2011 and

December 2012.

Impairment of Oil and Natural Gas Properties

Impairment of $204,190 was recorded during the year ended December 31, 2012 on the Loving property.

During the year ended December 31, 2011 the Company recorded impairment of $390,000 on the Loving

property, $9,741 on the Stauss property, and $837,827 on the South Vacuum property for a total of

$1,237,568 on our proved oil and natural gas properties. Additionally, the Company recorded impairment

on unproved properties totaling $119,771 in 2011.

General and Administrative Expense

General and administrative expenses increased $534,546 or 50% primarily due to increases in

compensation expense and professional services fees. Significant components of general and

administrative expenses include personnel-related costs and professional services fees. Management

expects FieldPoint’s general and administrative expenses to remain relatively comparable to 2012 next

year.

Other Income (Expense)

Interest expense increased in 2012 by $25,325 or 11%. During the year ended December 31, 2012 the

Company realized a $254,151 gain on commodity derivatives. Also in 2012, the Company sold their

interest in the South Vacuum property at a gain of $204,000.
33

Liquidity and Capital Resources

Cash flow provided by operating activities was approximately $3.33 million for the year ended December

31, 2012, compared to $3.98 million for the year ended December 31, 2011. The decrease in cash flow

from operating activities was primarily due to a decrease in accounts payable and impairment offset by

changes in net income and increased depletion and deferred income tax expenses.

In 2012 FieldPoint used its operating cash flow along with cash on hand to fund $4.4 million of

development of oil and natural gas properties. The Company sold its interest in the South Vacuum

property for $204,000. These were the primary components of cash used in investing activites in 2012.

Cash provided by financing activities for 2012 was $193,589. The Company sold 60,761 shares of

common stock for $257,358 and related expenses were $63,769, pursuant to an At Market Issuance Sales

Agreement with MLV & Co., LLC. FieldPoint used its operating cash flow along with cash on hand in

2011 to fund $2.6 million of development of oil and natural gas properties and to repurchase an aggregate

of 94,000 shares of FieldPoint common stock for a total purchase price of $358,550. The sale of the

Whisler property provided $68,330 in cash flow during 2011. These were the principal components of

cash used in investing and financing activities in 2011. The repurchases of stock were undertaken

pursuant to a stock buy-back program approved by the Board of Directors. Further, management

evaluates the market price and trading volume of FieldPoint’s common stock and may repurchase shares

if capital is available and management believes that such repurchase would be advantageous to the

Company and its stockholders.

Capital Requirements

Management believes the Company will be able to meet its current operating needs through internally

generated cash from operations and borrowings under the Company’s revolving credit facility. As of

December 31, 2012, the Company had working capital of approximately $2.1 million and approximately

$4.3 million borrowing capacity under its line of credit based on a borrowing base of $11 million. The

borrowing base is subject to redetermination based on the value of proved reserves, and could be

increased or decreased during 2013.

Although the Company had no significant commitments for capital expenditures at December 31, 2012,

management anticipates continued investments in oil and natural gas properties during 2013. If bank

credit is not available, FieldPoint may not be able to continue to invest in strategic oil and natural gas

properties. Management cannot predict how oil and natural gas prices will fluctuate during 2013 and

what effect they will ultimately have on the Company, but management believes that the Company will be

able to generate sufficient cash from operations to service its bank debt and provide for maintaining

current production of its oil and natural gas properties. The timing of most capital expenditures is

relatively discretionary. Therefore, the Company can plan expenditures to coincide with available funds

in order to minimize business risks. As of December 31, 2012, the Company had approximately

$210,518 of capital items in accounts payable that will be paid from working capital.
34

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:

Obligation Due in Period

Cash Contractual

Obligations 2013 2014 2015 Thereafter Total

(in thousands)

Credit facility (secured) $ - $ - $ 6,740 $ - $ 6,740

Interest on credit facility 264 264 197 - 725

Total $ 264 $ 264 6,937 $ - $ 7,465

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

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.

Successful Efforts Method of Accounting

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
35

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.

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. There were $204,190 of impairments on our proved oil and natural gas properties in

2012 and $1,237,568 of impairments of oil and natural gas properties in 2011.
36

Reporting Requirements

Because our common stock is publicly traded, we are subject to certain rules and regulations of federal,

state and financial market exchange entities charges with the protection of investors and the oversight of

companies whose securities are publicly traded. These entities, including the SEC and the NYSE MKT,

LLC, have issued requirements and regulations and are currently developing additional regulations and

requirements in response to laws, enacted by Congress, most notably the Sarbanes-Oxley Act 2002 and

SEC reporting regulations which became effective January 1, 2010. Our compliance with current rules

requires the commitment of significant managerial resources. We concluded that our internal control over

financial reporting were effective as of December 31, 2012.

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, 2012 and December 31, 2011, there were no open positions.

We did have derivative transactions during 2012 and 2011.
F-1

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-17
F- 2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

FieldPoint Petroleum Corporation and Subsidiaries

Cedar Park, Texas

We have audited the accompanying consolidated balance sheets of FieldPoint Petroleum Corporation and

subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of

operations, changes in stockholders’ equity and cash flows for each of the years then ended. These

consolidated financial statements are the responsibility of the Company’s management. Our responsibility is

to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight

Board (United States). Those standards require that we plan and perform the audit to obtain reasonable

assurance about whether the financial statements are free of material misstatement. The Company is not

required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our 

audits included consideration of internal control over financial reporting as a basis for designing audit

procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in

the financial statements, assessing the accounting principles used and significant estimates made by

management, as well as evaluating the overall financial statement presentation. We believe that our audits

provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects,

the financial position of FieldPoint Petroleum Corporation and subsidiaries as of December 31, 2012 and

2011, and the results of their operations and their cash flows for each of the years then ended, in conformity

with U.S. generally accepted accounting principles.

/s/Hein & Associates LLP 

Dallas, Texas

March 20, 2013
FIELDPOINT PETROLEUM CORPORATION

See accompanying notes to these consolidated financial statements.

F-3

CONSOLIDATED BALANCE SHEETS

ASSETS

DECEMBER 31,

2012 2011

CURRENT ASSETS:

Cash and cash equivalents $ 1,408,075 $ 2,037,593

Certificates of deposit 44,702 44,469

Accounts receivable:

Oil and natural gas sales 1,193,495 1,007,025

Joint interest billings, less allowance for doubtful accounts of 

approximately $174,000 and $99,000 respectively 229,406 209,209

Income taxes receivable 196,555 332,134

Deferred income tax asset-current 171,000 58,000

Prepaid expenses and other current assets 42,349 121,745

Total current assets 3,285,582 3,810,175

PROPERTY AND EQUIPMENT:

Oil and natural gas properties (successful efforts method) 32,210,252 27,616,928

Other equipment 52,113 52,113

Less accumulated depletion and depreciation (12,412,517) (10,116,327)

Net property and equipment 19,849,848 17,552,714

Total assets $ 23,135,430 $ 21,362,889

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:

Accounts payable and accrued expenses $ 889,796 $ 2,506,145

Oil and natural gas revenues payable 286,234 259,129

Asset retirement obligation – current - 25,000

Total current liabilities 1,176,030 2,790,274

LINE OF CREDIT 6,740,000 6,740,000

DEFERRED INCOME TAXES 2,442,000 1,467,000

ASSET RETIREMENT OBLIGATION 1,595,935 1,490,002

Total liabilities 11,953,965 12,487,276

COMMITMENTS AND CONTINGENCIES (Notes 9 and 10)

STOCKHOLDERS’ EQUITY:

Common stock, $.01 par value, 75,000,000 shares authorized;

8,970,936 and 8,910,175 shares issued, respectively; and

8,043,936 and 7,983,175 outstanding, respectively 89,709 89,101

Additional paid-in capital 11,661,922 4,573,580

Retained earnings 1,396,726 6,179,824

Treasury stock, 927,000 shares, each period, at cost (1,966,892) (1,966,892)

Total stockholders’ equity 11,181,465 8,875,613

Total liabilities and stockholders’ equity $ 23,135,430 $ 21,362,889
FIELDPOINT PETROLEUM CORPORATION

See accompanying notes to these consolidated financial statements.

F-4

CONSOLIDATED STATEMENTS OF OPERATIONS

DECEMBER 31,

2012 2011

REVENUE:

Oil and natural gas sales $ 10,240,628 $ 7,109,325

Well operational and pumping fees 68,265 68,265

Disposal fees 93,996 58,270

Total revenue 10,402,889 7,235,860

COSTS AND EXPENSES:

Lease operating 3,326,624 2,447,544

Depletion and depreciation 2,092,000 1,118,000

Impairment of oil and natural gas properties 204,190 1,357,339

Accretion of discount on asset retirement obligations 91,000 84,000

General and administrative 1,600,566 1,066,020

Total costs and expenses 7,314,380 6,072,903

OPERATING INCOME 3,088,509 1,162,957

OTHER INCOME (EXPENSE):

Interest income 2,389 5,054

Interest expense (264,120) (238,795)

Realized gain on commodity derivatives 254,151 -

Gain (loss) on sale of oil and natural gas property 204,000 (10,670)

Miscellaneous 1,334 71,018

Total other income (expense) 197,754 (173,393)

INCOME BEFORE INCOME TAXES 3,286,263 989,564

INCOME TAX PROVISION – current (312,000) (12,000)

INCOME TAX PROVISION – deferred (862,000) (375,000)

TOTAL INCOME TAX PROVISION (1,174,000) (387,000)

NET INCOME $ 2,112,263 $ 602,564

EARNINGS PER SHARE:

BASIC $ 0.26 $ 0.08

DILUTED $ 0.25 $ 0.08

WEIGHTED AVERAGE SHARES OUTSTANDING:

Basic 8,006,959 8,015,878

Diluted 8,452,429 8,015,878