Attached files
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, 2017
[
] 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.)
|
609
Castle Ridge Road, Suite 335
Austin,
Texas
78746
(Address
of Principal Executive Offices) (Zip Code)
(512)
579-3560
(Issuer's
Telephone Number, Including Area Code)
Securities
registered under Section 12(b) of the Exchange Act:
(None)
Securities
registered under Section 12(g) of the Exchange Act:
Common Stock, $.01 Par Value
Title
of Class
Indicate
by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act
[___]
Yes [ 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, a smaller reporting
company, or an emerging growth company. See definition of
“large accelerated filer”, “accelerated
filer”, “smaller reporting company”, and
“emerging growth company” in Rule 12b-2 of the Exchange
Act (check one):
|
Large
accelerated filer [ ]
|
Accelerated
filer [ ]
|
Non-accelerated
filer [ ]
|
Smaller
Reporting Company [ ]
|
|
|
|
|
Emerging
Growth Company [X]
|
Indicate by check mark whether the registrant is an emerging growth
company as defined in Rule 405 of the Securities Act of 1933
(§230.405 of this chapter) or Rule 12b-2 of the Securities
Exchange Act of 1934 (§240.12b-2 of this
chapter).
Emerging growth
company [
X ]
If an emerging growth company, indicate by check
mark if the registrant has elected not to use the extended
transition period for complying with any new or revised
financial accounting standards provided pursuant to Section
13(a) of the Exchange Act. [ ]
Indicate
by check mark whether the registrant is a shell company (as defined
in Rule 12b-2 of the Exchange Act).
Yes
No 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 the last business day of the registrant's
most recently completed second quarter, was
$1,851,226.
The
number of shares outstanding of the registrant’s common stock
as of March 30, 2018, is 10,669,229.
List
hereunder the following documents if incorporated by reference and
the Part of the Form 10-K (e.g., Part I, Part II, etc.) into which
the document is incorporated: (1) Any annual report to security
holders; (2) Any proxy or
information statement; and (3) Any prospectus
filed pursuant to Rule 424(b) or (c) under the Securities Act of
1933. The listed documents should be clearly described for
identification purposes
Exhibits
See
Part IV, Item 15.
PART I
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain
statements contained in this Form 10-K constitute
“forward-looking statements”. All statements, other
than statements of historical facts, included in this Form 10-K
that address activities, events or developments that FieldPoint
Petroleum Corp. and its subsidiaries (collectively, the "Company",
“we”, “us”, “our” or
“ours”) expects, projects, believes or anticipates will
or may occur in the future, including such matters as oil and
natural gas reserves, future drilling and operations, future
production of oil and natural gas, future net cash flows, future
capital expenditures and other such matters, are forward-looking
statements. Such forward-looking statements involve known and
unknown risks, uncertainties and other factors which may cause the
actual results, performance or achievements of the Company to be
materially different from any future results, performance or
achievements expressed or implied by such forward-looking
statements. 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.
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.
3
Operations
As of
December 31, 2017, the Company had varying ownership interest in
390 gross wells (96.21 net) located in five states. The Company
operates 15 of the 390 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 likely be required in the future to develop
the proved non-producing and proved undeveloped reserves associated
with this acreage. All of our proved non-producing and proved
undeveloped reserves associated with future drilling, completion
and recompletion projects will probably require hydraulic
fracturing.
4
We
believe we have followed, and intend to continue to follow,
applicable industry standard practices and legal requirements for
groundwater protection in our operations that are subject to
supervision by state regulators.
These
protective measures include setting surface casing at a depth
sufficient to protect fresh water zones as determined by applicable
state regulatory agencies, and cementing the well to create a
permanent isolating barrier between the casing pipe and surrounding
geological formations. This aspect of well design is intended to
prevent contact between the fracturing fluid and any aquifers
during the hydraulic fracturing operations. For recompletions of
existing wells, the production casing is pressure-tested before
perforating the new completion interval.
Injection
rates and pressures are monitored at the surface during our
hydraulic fracturing operations. Pressure is monitored on both the
injection string and the immediate annulus to the injection string.
We believe we have adequate procedures in place to address abrupt
changes to the injection pressure or annular pressure.
Texas
regulations currently require disclosure of the components in the
solutions used in hydraulic fracturing operations. Over 99% (by
mass) of the ingredients we use in hydraulic fracturing are water
and sand. The remainder of the ingredients are chemical additives
that are managed and used in accordance with applicable
requirements.
Hydraulic
fracturing requires the use of a significant amount of water. Upon
flowback of the water, we dispose of it in a way that we believe
minimizes the impact to nearby surface water by disposing into
approved disposal facilities or injection wells. Currently our
primary sources of water are nonpotable and potable aquifers. We
use water from on-lease water wells that we have drilled, and we
purchase water from off-lease water wells.
Operational Hazards and Insurance
The
Company's operations are subject to the usual hazards incident to
the drilling and production of oil and natural gas, such as
blowouts, cratering, explosions, uncontrollable flows of oil,
natural gas or well fluids, fires, pollution, releases of toxic gas
and other environmental hazards and risks. These hazards can cause
personal injury and loss of life, severe damage to and destruction
of property and equipment, pollution or environmental damage and
suspension of operations.
The
Company maintains insurance of various types to cover its
operations. The Company's insurance does not cover every potential
risk associated with the drilling and production of oil and natural
gas. In particular, coverage is not obtainable for certain types of
environmental hazards. The occurrence of a significant adverse
event, the risks of which are not fully covered by insurance, could
have a material adverse effect on the Company's financial condition
and results of operations. Moreover, no assurance can be given that
the Company will be able to maintain adequate insurance in the
future at rates it considers reasonable.
5
Regulation
The oil
and gas industry in the United States is subject to extensive
regulation by federal, state and local authorities. At the federal
level, various federal rules, regulations and procedures apply,
including those issued by the U.S. Department of Interior, the U.S.
Department of Transportation (the “DOT”) (Office of
Pipeline Safety) and the U.S. Environmental Protection Agency (the
“EPA”). At the state and local level, various agencies
and commissions regulate drilling, production and midstream
activities. These federal, state and local authorities have various
permitting, licensing and bonding requirements. Various remedies
are available for enforcement of these federal, state and local
rules, regulations and procedures, including fines, penalties,
revocation of permits and licenses, actions affecting the value of
leases, wells or other assets, and suspension of production. As a
result, there can be no assurance that we will not incur liability
for fines, penalties or other remedies that are available to these
federal, state and local authorities. However, we believe that we
are currently in material compliance with federal, state and local
rules, regulations and procedures, and that continued substantial
compliance with existing requirements will not have a material
adverse effect on our financial position, cash flows or results of
operations.
Transportation and Sale of Oil
Sales
of crude oil and condensate are not currently regulated and are
made at negotiated prices. Our sales of crude oil are affected by
the availability, terms and cost of transportation. Interstate
transportation of oil by pipeline is regulated by the Federal
Energy Regulation Commission (“FERC”) pursuant to the
Interstate Commerce Act (“ICA”), Energy Policy Act of
1992 (“EPAct 1992”), and the rules and regulations
promulgated under those laws. The ICA and its regulations require
that tariff rates for interstate service on oil pipelines,
including interstate pipelines that transport crude oil and refined
products, be just and reasonable and non-discriminatory and that
such rates, terms and conditions of service be filed with
FERC.
Intrastate
oil pipeline transportation rates are also subject to regulation by
state regulatory commissions. The basis for intrastate oil pipeline
regulation, and the degree of regulatory oversight and scrutiny
given to intrastate oil pipeline rates, varies from state-to-state.
Insofar as effective interstate and intrastate rates are equally
applicable to all comparable shippers, we believe that the
regulation of oil transportation rates will not affect our
operations in any way that is of material difference from those of
our competitors who are similarly situated.
Further,
interstate and intrastate common carrier oil pipelines must provide
service on a non-discriminatory basis. Under this open access
standard, common carriers must offer service to all similarly
situated shippers requesting service on the same terms and under
the same rates. When oil pipelines operate at full capacity, access
is governed by prorationing provisions set forth in the
pipelines’ published tariffs. Accordingly, we believe that
access to oil pipeline transportation services generally will be
available to us to the same extent as to our similarly situated
competitors.
The
transportation of oil by truck is also subject to federal, state
and local rules and regulations, including the Federal Motor
Carrier Safety Act and the Homeland Security Act of 2002.
Regulations under these statutes cover the security and
transportation of hazardous materials and are administered by the
DOT.
Transportation and Sale of Natural Gas and NGLs
FERC
regulates interstate gas pipeline transportation rates and service
conditions under the Natural Gas Act of 1938, the Natural Gas
Policy Act of 1978 and regulations issued under those statutes.
FERC also regulates interstate NGL pipelines under various federal
laws and regulations. Although FERC does not regulate oil and gas
producers such as us, FERC’s actions are intended to
facilitate increased competition within all phases of the oil and
gas industry and its regulation of third-party pipelines and
facilities could indirectly affect our ability to transport or
market our production. To date, FERC’s policies have not
materially affected our business or operations.
6
Regulation of Production
Oil,
NGL and gas production is regulated under a wide range of federal
and state statutes, rules, orders and regulations. State and
federal statutes and regulations require permits for drilling
operations, drilling bonds and reports concerning operations. The
states in which we operate, have regulations governing conservation
matters, including provisions for the unitization or pooling of oil
and gas properties, the establishment of maximum rates of
production from oil and gas wells, the regulation of spacing, and
requirements for plugging and abandonment of wells. Also, some
states, including Texas 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 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.
7
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.
8
Air Emissions
The
federal Clean Air Act and comparable state laws regulate emissions
of various air pollutants through air emissions permitting programs
and other requirements. In addition, the EPA has developed, and
continues to develop, stringent regulations governing emissions at
specified sources. In particular, on April 18, 2012, the EPA
issued new regulations under the New Source Performance Standards
(“NSPS”) and National Emission Standards for Hazardous
Air Pollutants (“NESHAP”). The regulations are designed
to reduce volatile organic compound (“VOC”) emissions
from hydraulically-fractured natural gas wells, storage tanks and
other equipment. Since January 1, 2015, all newly fractured natural
gas wells must use green completion technology, which allows for
the recovery of natural gas that formerly would have been vented or
flared. We do believe that the NSPS or NESHAP have had a material
adverse effect on our business, financial condition or results of
operations. However, any future laws and their implementing
regulations, may require us to obtain pre-approval for the
expansion or modification of existing facilities or the
construction of new facilities expected to produce air emissions,
impose stringent air permit requirements or use specific equipment
or technologies to control emissions. Our failure to comply with
these requirements could subject us to monetary penalties,
injunctions, conditions or restrictions on operations and,
potentially, criminal enforcement actions. We believe that we
currently are in substantial compliance with all air emissions
regulations and that we hold all necessary and valid construction
and operating permits for our current operations.
Greenhouse Gas Emissions
Congress
has, from time-to-time, considered legislation to reduce emissions
of greenhouse gases (“GHGs”). The current Congress is
likely to continue to consider similar bills. Moreover, almost half
of the states have already taken legal measures to reduce emissions
of GHGs through the planned development of GHG emission inventories
and/or regional GHG cap-and-trade programs or other mechanisms.
Most cap-and-trade programs work by requiring major sources of
emissions, such as electric power plants, or major producers of
fuels such as refineries and gas processing plants, to acquire and
surrender emission allowances corresponding with their annual
emissions of GHGs. The number of allowances available for purchase
is reduced each year until the overall GHG emission reduction goal
is achieved. As the number of GHG emission allowances declines each
year, the cost or value of allowances is expected to escalate
significantly. Many states have enacted renewable portfolio
standards, which require utilities to purchase a certain percentage
of their energy from renewable fuel sources.
In
response to the findings that emissions of carbon dioxide, methane
and other GHGs present an endangerment to human health and the
environment, the EPA has adopted regulations under existing
provisions of the federal Clean Air Act. The EPA has adopted two
sets of rules regarding possible future regulation of GHG emissions
under the Clean Air Act, one of which purports to regulate
emissions of GHGs from motor vehicles and the other of which would
regulate emissions of GHGs from large stationary sources of
emissions such as power plants or industrial facilities. The motor
vehicle rule was finalized in April 2010 and became effective in
January 2011, but it 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 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 we do not know when the agency will
issue any regulations.
9
In
December 2010, the EPA enacted final rules on mandatory reporting
of GHGs. In 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. We do
not expect that the EPA’s mandatory GHG reporting
requirements will have a material adverse effect on our business,
financial condition or results of operations.
The
adoption of additional legislation or regulatory programs to
monitor or reduce GHG emissions could require us to incur increased
operating costs, such as costs to purchase and operate emissions
control systems, acquire emissions allowances or comply with new
regulatory requirements. In addition, the EPA has stated that the
data collected from GHG emissions reporting programs may be the
basis for future regulatory action to establish substantive GHG
emissions factors. Any GHG emissions legislation or regulatory
programs applicable to power plants or refineries could increase
the cost of consuming, and thereby reduce demand for, the oil and
natural gas we produce. Consequently, legislation and regulatory
programs to reduce GHG emissions could have an adverse effect on
our future business, financial condition and results of
operations.
Water Discharges
The
Federal Water Pollution Control Act (the “Clean Water
Act”) and analogous state laws, impose restrictions and
strict controls on the discharge of pollutants and fill material,
including spills and leaks of oil and other substances into
regulated waters, including wetlands. The discharge of pollutants
into regulated waters is prohibited, except in accordance with the
terms of a permit issued by the EPA, an analogous state agency, or,
in the case of fill material, the United States Army Corps of
Engineers. Federal and state regulatory agencies can impose
administrative, civil and criminal penalties for non-compliance
with discharge permits or other requirements of the Clean Water Act
and analogous state laws and regulations.
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 and for shale
gas wastewater in 2015. 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 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.
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.
10
Hydraulic Fracturing
Hydraulic
fracturing is the subject of significant focus among some
environmentalists, regulators and the general public. Concerns over
potential hazards associated with the use of hydraulic fracturing
and its impact on the environment have been raised at all levels,
including federal, state and local, as well as internationally.
There have been claims that hydraulic fracturing may contaminate
groundwater, reduce air quality or cause earthquakes. Hydraulic
fracturing requires the use and disposal of water, and public
concern has been growing over its possible effects on drinking
water supplies, as well as the adequacy of water
supply.
The
Energy Policy Act of 2005, which exempts hydraulic fracturing from
regulation under the SDWA, prohibits the use of diesel fuel in the
fracturing process without a UIC permit. In the past, legislation
has been introduced in, but not passed by, Congress that would
amend the SDWA to repeal this exemption. Specifically, the FRAC Act
has been introduced in each Congress since 2008 to accomplish these
purposes, and on May 9, 2013, the FRAC Act was again introduced. If
similar legislation were enacted, it could require hydraulic
fracturing operations to meet permitting and financial assurance
requirements, adhere to certain construction specifications,
fulfill monitoring, reporting and recordkeeping obligations and
meet plugging and abandonment requirements. Future federal
legislation could also require the reporting and public disclosure
of chemical additives used in the fracturing process, which could
make it easier for third parties opposing the hydraulic fracturing
process to initiate legal proceedings based on allegations that
specific chemical additives used in the fracturing process could
adversely affect groundwater. If federal legislation regulating
hydraulic fracturing is adopted in the future, it could lead to
operational delays or increased operating costs and could result in
additional regulatory burdens that could make it more difficult to
perform hydraulic fracturing and increase our costs of compliance
and doing business.
In
2010, the EPA asserted federal regulatory authority over hydraulic
fracturing involving diesel additives under the UIC program by
posting a requirement on its website that requires facilities to
obtain permits to use diesel fuel in hydraulic fracturing
operations. Following a legal challenge by industry groups and a
subsequent settlement, in February 2014, the EPA issued revised
guidance on the use of diesel in hydraulic fracturing operations.
Under the guidance, EPA broadly defined “diesel” to
include fuels such as kerosene that have not traditionally been
considered diesel. The EPA’s continued assertion of its
regulatory authority under the SDWA could result in extensive
requirements that could cause additional costs and delays in the
hydraulic fracturing process.
In
addition to the above actions of the EPA, certain members of the
Congress have called upon (i) the Government Accountability
Office to investigate how hydraulic fracturing might adversely
affect water resources; (ii) the Securities and Exchange
Commission (the “SEC”) to investigate the natural gas
industry and any possible misleading of investors or the public
regarding the economic feasibility of pursuing natural gas deposits
in shale by means of hydraulic fracturing; and (iii) the
Energy Information Administration to provide a better understanding
of that agency’s estimates regarding natural gas reserves,
including reserves from shale formations, as well as uncertainties
associated with those estimates. The EPA has also studied the
potential environmental impacts of hydraulic fracturing on water
resources, publishing draft results in 2015. These and future
investigations and studies, depending on their degree of pursuit
and any meaningful results obtained, could facilitate initiatives
to further regulate hydraulic fracturing.
11
There
are also certain governmental reviews either underway or being
proposed that focus on environmental aspects of hydraulic
fracturing. The White House Council on Environmental Quality is
coordinating an administration-wide review of hydraulic fracturing,
and a committee of the United States House of Representatives has
conducted an investigation of hydraulic fracturing. Furthermore, a
number of federal agencies are analyzing, or have been requested to
review, a variety of environmental issues associated with hydraulic
fracturing. The EPA has also begun a study of the potential
environmental impacts of hydraulic fracturing.
Some
states have adopted, and other states are considering adopting,
regulations that could restrict hydraulic fracturing in certain
circumstances or otherwise require the public disclosure of
chemicals used in hydraulic fracturing. For example, pursuant to
legislation adopted by the State of Texas in June 2011, the RRC
enacted a rule in December 2011, requiring disclosure to the RRC
and the public of certain information regarding additives, chemical
ingredients, concentrations and water volumes used in hydraulic
fracturing. In addition to state law, local land use restrictions,
such as city ordinances, may restrict or prohibit drilling in
general and hydraulic fracturing in particular.
If
these or any other new laws or regulations that significantly
restrict hydraulic fracturing are adopted, it could become more
difficult or costly for us to drill and produce oil and gas from
shale and tight sands formations and become easier for third
parties opposing hydraulic fracturing to initiate legal
proceedings. In addition, if hydraulic fracturing is regulated at
the federal level, fracturing activities could become subject to
delays, additional permitting and financial assurance requirements,
more stringent construction specifications, increased monitoring,
reporting and recordkeeping obligations, plugging and abandonment
requirements and higher costs. These new laws or regulations could
cause us to incur substantial delays or suspensions of operations
and compliance costs and could have a material adverse effect on
our business, financial condition and results of
operations.
Compliance
We
believe that we are in substantial compliance with all existing
environmental laws and regulations that apply to our current
operations and that our ongoing compliance with existing
requirements will not have a material adverse effect on our
business, financial condition or results of operations. We did not
incur any material capital expenditures for remediation or
pollution control activities for the year ended December 31,
2017. 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 2018. 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.
12
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
office is located at 609 Castle Ridge Road, Suite 335, Austin,
Texas 78746.
Employees
– As of March 28, 2018, the Company had 3 employees, and the
Company considers its relationship with its employees
satisfactory.
13
ITEM 1A – RISK FACTORS.
Going concern
We have
net income of $2,666,253 for the year ended December 31, 2017 but
had an operating loss of $1,112,597. We had a net loss of
$2,473,147 for the year ended December 31, 2016. We expect that the
Company will continue to experience operating losses and may have
negative cash flow for so long as commodity prices remain
depressed. The notes to our financial statements for the fiscal
years ended December 31, 2017 and 2016, include an explanatory
paragraph expressing substantial doubt as to our ability to
continue as a going concern. The financial statements have been
prepared "assuming that the Company will continue as a going
concern." Our ability to continue as a going concern is dependent
on raising additional capital to fund our operations and ultimately
on generating future profitable operations. There can be no
assurance that we will be able to raise sufficient additional
capital or continue to have positive cash flow from operations to
address all of our cash flow needs. If we are not able to find
alternative sources of cash or generate sufficient positive cash
flow from operations, our business and shareholders may be
materially and adversely affected.
Oil and gas operations are risky.
We
compete in the areas of oil and gas exploration, production,
development and transportation with other companies, many of which
may have substantially larger financial and other resources. The
nature of the oil and gas business also involves a variety of
risks, including the risks of operating hazards such as fires,
explosions, cratering, blow-outs, and encountering formations with
abnormal pressures, the occurrence of any of which could result in
losses to us. We maintain insurance against some, but not all, of
these risks in amounts that management believes to be reasonable in
accordance with customary industry practices. The occurrence of a
significant event, however, that is not fully insured could have a
material adverse effect on our financial position.
A continuation of the decline in oil and natural gas prices would
have a material impact on us.
Our
future financial condition and results of operations are dependent
upon the prices we receive for our oil and natural gas
production. Oil and natural gas prices historically have been
volatile and more recently depressed and likely will continue to
be volatile and depressed in historical standards in the
future. This price volatility and depression will also affect our
common stock price. We cannot predict oil and natural gas
prices and prices may decline even further in the future. The
following factors have an influence on oil and natural gas
prices, including but not limited to:
●
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.
14
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.
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.
15
Estimates
of proved undeveloped reserves are even less reliable than
estimates of proved developed reserves. Furthermore, different
reserve engineers may make different estimates of reserves and
future net revenues based on the same available data. Our actual
production, revenues and expenditures with respect to reserves will
likely be different from estimates and the differences may be
material.
Estimating our reserves future net cash flows is difficult to do
with any certainty.
There
are numerous uncertainties inherent in estimating quantities of
proved oil and natural gas reserves and their values,
including many factors beyond our control. The reserve data
included in this report represents only estimates. Reserve
engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot
be measured in an exact manner. The accuracy of any reserve
estimate is a function of the quality of available data, the
precision of the engineering and geological interpretation,
and judgment. As a result, estimates of different engineers
often vary. The estimates of reserves, future cash flows, and
present value are based on various assumptions, including
those prescribed by the Securities and Exchange Commission,
and are inherently imprecise. There is no assurance that our
present oil and gas wells will continue to produce at
current or anticipated rates of production, or that production
rates achieved in early periods can be maintained. Actual
future production, cash flows, taxes, operating expenses, and
quantities of recoverable oil and natural gas reserves may
vary substantially from our estimates. Also, the use of a 10%
discount factor for reporting purposes may not necessarily
represent the most appropriate discount factor, given
actual interest rates and risks to which our business or the
oil and natural gas industry in general are
subject.
Quantities
of proved reserves are estimated based on economic
conditions, including oil and natural gas prices in existence
at the date of assessment. A reduction in oil and natural gas
prices not only would reduce the value of any proved reserves,
but also might reduce the amount of oil and natural gas that could
be economically produced, thereby reducing the quantity of
reserves. Our reserves and future cash flows may be subject to
revisions, based upon changes in economic conditions,
including oil and natural gas prices, as well as due
to production results, operating costs, and other factors.
Downward revisions of our reserves could have an adverse
effect on our financial condition and operating
results.
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.
16
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
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 effect
on properties in which we may have an interest. Discharge of
oil, natural gas, water, or other pollutants to the oil, soil,
or water may give rise to significant liabilities to
government and third parties and may require us to incur
substantial cost of remediation. We may be required to agree
to indemnify sellers of properties purchased against certain
liabilities for environmental claims associated with those
properties. We can give no assurance that existing
environmental laws or regulations, as currently interpreted, or
as they may be reinterpreted in the future, or future laws or
regulations will not materially adversely affect our results
of operations and financial conditions.
17
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.
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.
18
We engage in commodity derivative transactions which involve risks
that can harm our business.
To
manage our exposure to price risks in the marketing of our
production, we enter into commodity derivative agreements. While
intended to reduce the effects of volatile commodity prices, such
transactions may limit our potential gains and increase our
potential losses if commodity prices were to rise substantially
over the price established by the commodity derivative. In
addition, such transactions may expose us to the risk of loss in
certain circumstances, including instances in which our production
is lower than expected. We are also exposed to the risk of
non-performance by the counterparties to the commodity derivative
agreements.
Federal and state legislation and regulatory initiatives and
private litigation relating to hydraulic fracturing could stop or
delay our development project and result in materially increased
costs and additional operating restrictions.
All of
our proved non-producing and proved undeveloped reserves associated
with future drilling and completion projects will require hydraulic
fracturing. If these or any other new laws or regulations that
significantly restrict hydraulic fracturing are adopted, such laws
could make it more difficult or costly for us to drill and produce
from our proved reserves, as well as make it easier for third
parties opposing hydraulic fracturing to initiate legal
proceedings. In addition, if hydraulic fracturing is regulated at
the federal level, fracturing activities could become subject to
additional permitting and financial assurance requirements, more
stringent construction specifications, increased monitoring,
reporting and recordkeeping obligations, plugging and abandonment
requirements and also to permitting delays and increases in costs.
These developments, as well as new laws or regulations, could cause
us to incur substantial compliance costs, and compliance or the
consequences of our failure to comply could have a material adverse
effect on our financial condition and results of operations. In
addition, if we are unable to use hydraulic fracturing in
completing our wells or hydraulic fracturing becomes prohibited or
significantly regulated or restricted, we could lose the ability to
drill and complete the projects for our proved reserves and
maintain our current leasehold acreage, which would have a material
adverse effect on our future business, financial condition and
results of operations.
Part of our strategy involves using some of the latest available
horizontal drilling and completion techniques, which involve risks
and uncertainties in their application.
Our
operations involve using some of the latest drilling and completion
techniques as developed by us and our service providers. Risks that
we face while drilling horizontal wells include, but are not
limited to:
●
landing our
wellbore in the desired drilling zone;
●
staying in the
desired drilling zone while drilling horizontally through the
formation;
●
running our
casing the entire length of the wellbore; and
●
being able to
run tools and other equipment consistently through the horizontal
wellbore.
19
Risks
that we face while completing our wells include, but are not
limited to:
●
the
ability to fracture stimulate the planned number of
stages;
●
the
ability to run tools the entire length of the wellbore during
completion operations; and
●
the
ability to successfully clean out the wellbore after completion of
the final fracture stimulation stage.
The
results of our drilling in new or emerging formations are more
uncertain initially than drilling results in areas that are more
developed and have a longer history of established production.
Newer or emerging formations and areas have limited or no
production history and, consequently, we are more limited in
assessing future drilling results in these areas. If our drilling
results are less than anticipated, the return on our investment for
a particular project may not be as attractive as we anticipated and
we could incur material write-downs of unevaluated properties and
the value of our undeveloped acreage could decline in the
future.
Changes in tax laws may adversely affect our results of operations
and cash flows.
In recent years there has been introduced, from time to time,
proposed legislation that would, if enacted into law, make
significant changes to U.S. tax laws, including the
elimination of certain key United States federal income tax
incentives currently available to oil and gas exploration and
production companies. These changes include, but are not limited
to:
●
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 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.
Oil, NGL and gas prices are volatile. Continued depressed oil, NGL
or gas prices would adversely affect our business, financial
condition and results of operations and our ability to meet our
capital expenditure requirements and financial
commitments.
Our
revenues, profitability and cash flow depend substantially upon the
prices and demand for oil, NGLs and gas. The markets for these
commodities are volatile, and even relatively modest drops in
prices can affect significantly our financial results and impede
our growth. Prices for oil, NGLs and gas fluctuate widely in
response to changes in the supply and demand for these commodities,
market uncertainty and a variety of additional factors beyond our
control, such as:
20
●
domestic and
foreign supply of oil, NGLs and gas;
●
domestic and
foreign consumer demand for oil, NGLs and gas;
●
overall United
States and global economic conditions impacting the global supply
of and demand for oil, NGLs and gas;
●
the
willingness and ability of OPEC to set and maintain oil price and
production controls;
●
commodity
processing, gathering and transportation availability, the
availability of refining capacity and other factors that result in
differentials to benchmark prices;
●
price and
availability of alternative fuels;
●
price and
quantity of foreign imports;
●
domestic and
foreign governmental regulations;
●
political
conditions in or affecting other oil and natural gas producing
countries;
●
weather
conditions, including unseasonably warm winter weather and tropical
storms; and
●
technological
advances affecting oil, NGL and gas consumption.
Advanced
drilling and completion technologies, such as horizontal drilling
and hydraulic fracturing, have resulted in increased investment by
oil and gas producers in developing U.S. shale oil and gas projects
and, therefore, has resulted in increased production from these
projects. The results of higher investment in the exploration for
and production of U.S. shale oil, maintenance of production levels
of oil from the Middle East, and other factors, such as global
economic and financial conditions, have caused the price of oil to
fall and become more volatile over the last several years. However,
prices have begun to increase during the 52 week period ending
December 31, 2017. Over the six months ending December 31, 2017,
prices have increased, the WTI Spot prices for oil per barrel
(“Bbl”) have increased by approximately 24%. During the
52 week period ended December 31, 2017, the prices for oil per
barrel ranged from a high of $57 and a low of $45 per Bbl, with the
closing price at December 31, 2017, of approximately $57. Prices
may continue to be volatile and possibly decrease back to levels
experienced during the last few years.
21
The Company’s financial position, results of operations,
access to capital and the amount of oil and gas that may be
economically produced would be negatively impacted if oil and gas
prices stay depressed for an extended period of time.
The
ways that continued low oil and gas prices could affect us include
the following:
●
Cash
flows would be reduced, decreasing funds available for capital
expenditures needed to maintain or increase production and replace
reserves;
●
Future net cash
flows from our properties would decrease, which could result in
significant impairment expenses;
●
Some
reserves would no longer be economic to produce, leading to lower
proved reserves, production and cash flows; and
●
Access to
capital, such as equity or long-term debt markets and current
reserve-based lending levels, would be severely limited or
unavailable.
If the
current decline in oil prices continues, it is unlikely that our
future cash flows will be sufficient to fund the capital
expenditure levels necessary to maintain current production and
reserve levels over the long term and our results of operations
would be adversely affected.
Lower
oil and gas prices would not only cause our revenues and cash flows
to decrease but also would reduce the amount of oil and gas that we
can produce economically. Substantial decreases in oil and gas
prices will render uneconomic some or all of our drilling
locations. This has and may continue to result in our having to
impair our estimated proved reserves and could have a material
adverse effect on our business, financial condition and results of
operations. As we experienced with the recent downward adjustment
of our borrowing base under our credit facility with Citibank, a
decline in oil, NGL or gas prices for an extended period of time
can result in our being unable to maintain or increase our
borrowing capacity, repay current or future debt or obtain
additional capital on attractive terms, all of which can affect the
value of our common stock. The amount available for borrowing under
our revolving credit facility is subject to a borrowing base, which
is determined by our lenders taking into account our estimated
proved reserves and is subject to semi-annual redeterminations
based on pricing models determined by the lenders at such time. As
we saw in December 2015, with the lowering of our borrowing base,
the recent decline in oil and gas prices has adversely impacted the
value of our estimated proved reserves and, in turn, the market
values used by our lenders to determine our borrowing
base.
We may not be able to generate enough cash flow to meet our debt
obligations.
We
expect our earnings and cash flow to vary significantly from year
to year due to the nature of our industry. As a result, the amount
of debt that we can manage in some periods may not be appropriate
for us in other periods. Additionally, our future cash flow may be
insufficient to meet our debt obligations and other commitments. In
December 2016, our borrowing base with our senior lender was $5.5
million, at which time our outstanding drawn balance was
approximately $6.5 million. In 2017 our senior lender decreased our
borrowing base to approximately $2.7 which is equivalent to our
outstanding drawn balance, and the revolving credit facility
matured in October 2016. We entered into a Forbearance Agreement in
October 2016, which ran through January 1, 2018, and was amended
December 29, 2017, and extended to March 31, 2018. Although the
Forbearance Agreement was again amended March 30, 2018, and was
extended to June 30, 2018, we are currently in default under the
line of credit, and as senior secured lender, Citibank could
foreclose on our assets. A range of economic, competitive, business
and industry factors will affect our future financial performance,
and, as a result, our ability to generate cash flow from operations
and to pay our debt. Many of these factors, such as oil and gas
prices, economic and financial conditions in our industry and the
global economy and initiatives of our competitors, are beyond our
control. If we do not generate enough cash flow from operations to
satisfy our debt obligations, we may have to undertake alternative
financing plans, such as:
●
selling
assets;
●
reducing or
delaying capital investments;
●
seeking to raise
additional capital; or
●
refinancing or
restructuring our debt.
22
If, for
any reason, we are unable to meet our debt service and repayment
obligations, we would be in default under the terms of the
agreements governing our debt, which would allow our creditors at
that time to declare all outstanding indebtedness to be due and
payable, which would in turn trigger cross-acceleration or
cross-default rights between the relevant agreements. If amounts
outstanding under our revolving credit facility were to be
accelerated, we cannot be certain that our assets would be
sufficient to repay in full the money owed to the lenders or to our
other debt holders.
Our lenders can limit our borrowing capabilities, which may
materially impact our operations.
At
December 31, 2017, we had approximately $2.7 million in
borrowings outstanding under our revolving credit facility. Our
borrowing base was reduced by our senior lender to approximately
$2.7 million due to impairments in 2015 and sale of properties in
2017. The outstanding balance under our revolving credit facility
is equal to the new borrowing base of $2.7 million. The borrowing
base under our revolving credit facility is redetermined
semi-annually based upon a number of factors, including commodity
prices and reserve levels. In addition to such semi-annual
redeterminations, our lenders may request one additional
redetermination during any 12-month period. Upon a further
redeterminationin 2018, our borrowing base could be reduced again,
and if the amount outstanding under our revolving credit facility
at any time exceeds the borrowing base at such time, we may be
required to repay a portion of our outstanding borrowings. If the
significant reduction in commodity prices continues or accelerates,
it is likely that our borrowing base will be reduced further in the
next semi-annual borrowing base redetermination. We use cash flow
from operations and bank borrowings to fund our exploration,
development and acquisition activities. A reduction in our
borrowing base could limit those activities. In addition, we
may significantly change
our capital structure to cover our working capital needs, make
future acquisitions or develop our properties. Changes in capital
structure may significantly increase our debt. If we incur
additional debt for these or other purposes, the related risks that
we now face could intensify. A higher level of debt also increases
the risk that we may default on our debt obligations. Our ability
to meet our debt obligations and to reduce our level of debt
depends on our future performance, which is affected by general
economic conditions and financial, business and other factors, many
of which are beyond our control.
Our revolving credit facility and the indenture governing our
revolving credit facility contain operating and financial
restrictions and covenants that may restrict our business and
financing activities or that economic conditions and commodity
prices may cause us to breach.
Our
revolving credit facility contains, and any future indebtedness we
incur may contain, a number of restrictive covenants that will
impose significant operating and financial restrictions on us,
including restrictions on our ability to, among other
things:
●
sell
assets, including equity interests in our
subsidiaries;
●
consolidate,
merge or transfer all or substantially all of our
assets;
●
incur or
guarantee additional indebtedness or issue preferred
stock;
●
redeem or prepay
other debt;
23
●
pay
distributions on, redeem or repurchase our common stock or redeem
or repurchase our subordinated debt;
●
create or incur
certain liens;
●
make
certain acquisitions and investments;
●
enter into
agreements that restrict distributions or other payments from our
restricted subsidiaries to us;
●
engage in
transactions with affiliates;
●
create
unrestricted subsidiaries;
●
enter into
financing transactions; and
●
engage in
certain business activities.
Our
revolving credit facility provides for certain financial covenants
and ratios measured quarterly which include a current ratio,
leverage ratio, and interest coverage ratio requirements. The
Company is out of compliance with all three ratios as of December
31, 2017, and is in technical default of the agreement.
Furthermore, the borrowing base under our line of credit was
redetermined December 29, 2017, based on the value of proved
reserves, and was reduced from $5.5 million to $2.7 million. As a
result of the redetermination of the credit base, the Company does
not have any capacity in its borrowing base as of December 31,
2017.
In
October 2016, we executed a sixth amendment to the original loan
agreement, which provided for Citibank’s forbearance from
exercising remedies relating to the current defaults including the
principal payment deficiencies. The Forbearance Agreement ran
through January 1, 2018, and required that we make a $500,000 loan
principal pay down by September 30, 2017, and adhere to other
requirements including weekly cash balance reports, quarterly
operating reports, monthly accounts payable reports and that we pay
all associated legal expenses. Furthermore, under the agreement
Citibank may sweep any excess cash balances exceeding a net amount
of $800,000 less equity offering proceeds, which will be applied
towards the outstanding principal balance. The Agreement was
extended by a closing letter agreement to allow the Company time to
pay the associated legal costs and solidify the Deposit/Withdraw at
Custodian Agreements (“DEWAC”) as provided for in the
Forbearance Agreement.
On
December 29, 2017, we executed a seventh amendment to the original
loan agreement and first amendment to the forbearance, which
reduced our borrowing base to our current loan balance of
approximately $2.7 million and it provided for Citibank’s
forbearance from exercising remedies relating to the current
defaults including the principal payment deficiencies. The
Forbearance Agreement ran through March 31, 2018, and required that
we adhere to certain reporting requirements such as weekly cash
reports and pay all of the fees and expenses of the Lender’s
counsel invoiced on or before the effective date. On March 30,
2018, we executed an eighth amendment to the original loan
agreement and second amendment to the forbearance which extended it
to June 30, 2018. The terms of the second amendment remain the same
as under the first amendment to the forbearance.
24
If an
event of default under our revolving credit facility occurs and
remains uncured, it could have a material adverse effect on our
business, financial condition and results of operations. The
lenders
●
would not be
required to lend any additional amounts to us;
●
could elect to
declare all borrowings outstanding, together with accrued and
unpaid interest and fees, to be due and payable;
●
may
have the ability to require us to apply all of our available cash
to repay these borrowings; or
●
may
prevent us from making debt service payments under our other
agreements.
Price declines during 2015 resulted in a material write down of the
carrying values of our properties, and further price declines could
result in additional write downs in the future, which would
negatively impact our net income and results of operations.
Additionally, current SEC rules also could require us to write down
our proved undeveloped reserves in the future.
Accounting
rules require that we periodically review the carrying value of our
properties for possible impairment. Based on prevailing commodity
prices and specific market factors and circumstances at the time of
impairment reviews, and the continuing evaluation of development
plans, production data, economics and other factors, we may be
required to write down the carrying value of our properties. A
write-down is a non-cash charge to earnings. We may incur
impairment charges in the future, which could have a material
adverse effect on our results of operations for the periods in
which such charges are taken. The risk that we will be required to
write down the carrying value of our properties increases when oil
and gas prices are low or volatile.
In
addition, current SEC rules require that proved undeveloped
reserves may only be booked if they relate to wells scheduled to be
drilled within five years, unless specific circumstances justify a
longer time. This rule may limit our potential to book additional
proved undeveloped reserves as we pursue our development projects.
Moreover, we may be required to write down our proved undeveloped
reserves if we do not drill those wells within the required
timeframe or if continued, depressed prices cause us to change our
development plan to decrease the number of wells to be drilled over
the five-year period.
The Standardized Measure of our estimated reserves and PV-10
included in this report should not be considered as the current
market value of the estimated oil and gas reserves attributable to
our properties.
Standardized
Measure is a reporting convention that provides a common basis for
comparing oil and gas companies subject to the rules and
regulations of the SEC. Standardized Measure requires the use of
specific pricing as required by the SEC as well as operating and
development costs prevailing as of the date of computation. The
non-GAAP financial measure, PV-10, is based on the average of the
closing price on the first day of the month for the 12-month period
prior to fiscal year end, while actual future prices and costs may
be materially higher or lower.
Consequently,
these measures may not reflect the prices ordinarily received or
that will be received for oil and gas production because of varying
market conditions, nor may they reflect the actual costs that will
be required to produce or develop the oil and gas properties.
Accordingly, estimates included herein of future net cash flow may
be materially different from the future net cash flows that are
ultimately received. Therefore, the Standardized Measure of our
estimated reserves and PV-10 included in this report should not be
construed as accurate estimates of the current fair value of our
proved reserves. In addition, the 10% discount factor we use when
calculating PV-10 may not be the most appropriate discount factor
based on interest rates in effect from time to time and risks
associated with us or the oil and gas industry in general. Actual
future net revenues also will be affected by factors such as the
amount and timing of actual production, prevailing operating and
development costs, supply and demand for oil and gas, increases or
decreases in consumption and changes in governmental
regulations or taxation.
25
Competition in the oil and natural gas industry is intense, and we
are smaller and have a more limited operating history than
many of our competitors.
We
compete with major integrated oil and gas companies and independent
oil and gas companies in all areas of operation. In
particular, we compete for property acquisitions and for the
equipment and labor required to operate and develop these
properties. Most of our competitors have substantially
greater financial and other resources than we have. In
addition, larger competitors may be able to absorb the burden
of any changes in federal, state and local laws
and regulations more easily than we can, which would adversely
affect our competitive position. These competitors may be able
to pay more for properties and may be able to define, evaluate, bid
for, and purchase a greater number of properties and prospects
than we can. Further, our competitors may have technological
advantages and may be able to implement new technologies
more rapidly than we can. Our ability to explore for natural
gas and oil prospects and to acquire additional properties in
the future will depend on our ability to conduct operations,
to evaluate and select suitable properties and to
consummate transactions in this highly competitive
environment. In addition, most of our competitors have
operated for a much longer time than we have and
have demonstrated the ability to operate through industry
cycles.
Our operations substantially depend on the availability of water.
Restrictions on our ability to obtain, dispose of or recycle water
may impact our ability to execute our drilling and development
plans in a timely or cost-effective manner.
Water
is an essential component of our drilling and hydraulic fracturing
processes. Historically, we have been able to secure water from
local landowners and other sources for use in our operations.
During the last three years, much of the Southwest region where we
operate has experienced extreme drought conditions. As a result of
the severe drought, governmental authorities have restricted the
use of water subject to their jurisdiction for drilling and
hydraulic fracturing to protect the local water supply. If we are
unable to obtain water to use in our operations, we may be unable
to economically produce oil, NGLs and gas, which could have an
adverse effect on our business, financial condition and results of
operations.
Moreover,
new environmental initiatives and regulations could include
restrictions on disposal of waste, including, but not limited to,
produced water, drilling fluids and other wastes associated with
the exploration, development or production of oil and gas.
Compliance with environmental regulations and permit requirements
for the withdrawal, storage and use of surface water or ground
water necessary for hydraulic fracturing may increase our operating
costs and cause delays, interruptions or cessation of our
operations, the extent of which cannot be predicted, and all of
which would have an adverse effect on our business, financial
condition, results of operations and cash flows.
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.
26
In
addition, in December 2009, the EPA determined that emissions of
carbon dioxide, methane and other GHGs present an endangerment to
human health and the environment, because emissions of such gases
are, according to the EPA, contributing to warming of the
earth’s atmosphere and other climatic changes. These findings
by the EPA allow the agency to proceed with the adoption and
implementation of regulations that would restrict emissions of GHGs
under existing provisions of the federal Clean Air Act. The EPA has
also issued final regulations under the NSPS and NESHAP designed to
reduce VOCs. The adoption of legislation or regulatory programs to
reduce GHG or VOC emissions could require us to incur increased
operating costs, such as costs to purchase and operate emissions
control systems, to acquire emissions allowances or comply with new
regulatory requirements. Any GHG emissions legislation or
regulatory programs applicable to power plants or refineries could
also increase the cost of consuming, and thereby reduce demand for,
the oil and natural gas we produce. Consequently, legislation and
regulatory programs to reduce GHG or VOC emissions could have a
material adverse effect on our business, financial condition and
results of operations.
Governmental regulations can hinder production.
Domestic
oil and natural gas exploration, production and sales are
extensively regulated at both the federal and state levels.
Legislation affecting the oil and natural gas industry is under
constant review for amendment or expansion, frequently increasing
the regulatory burden. Also, numerous departments and agencies,
both federal and state, have legal authority to issue, and have
issued, rules and regulations affecting the oil and natural gas
industry which often are difficult and costly to comply with and
which carry substantial penalties for noncompliance. State statutes
and regulations require permits for drilling operations, drilling
bonds, and reports concerning operations. Most states where we
operate also have statutes and regulations governing conservation
matters, including the unitization or pooling of properties. Our
operations are also subject to numerous laws and regulations
governing plugging and abandonment, discharging materials into the
environment or otherwise relating to environmental protection. The
heavy regulatory burden on the oil and natural gas industry
increases its costs of doing business and consequently affects its
profitability. Changes in the laws, rules or regulations, or the
interpretation thereof, could have a materially adverse effect on
our financial condition or results of operation.
Minority or royalty interest purchases do not allow us to control
production completely.
We
sometimes acquire less than the controlling working interest in oil
and natural gas properties. In such cases, it is likely that these
properties would not be operated by us. When we do not have
controlling interest, the operator or the other co-owners might
take actions we do not agree with and possibly increase costs or
reduce production income in ways we do not agree with.
Environmental regulations can hinder production.
Oil and
natural gas activities can result in liability under federal, state
and local environmental regulations for activities involving, among
other things, water pollution and hazardous waste transport,
storage, and disposal. Such liability can attach not only to the
operator of record of the well, but also to other parties that may
be deemed to be current or prior operators or owners of the wells
or the equipment involved. We have inspections performed on our
properties to assure environmental law compliance, but inspections
may not always be performed on every well, and structural and
environmental problems are not necessarily observable even when an
inspection is undertaken.
27
Government regulations could increase our operating
costs
Oil and
natural gas operations are subject to extensive federal, state
and local laws and regulations relating to the exploration
for, and development, production and transportation of, oil
and natural gas, as well as safety matters, which may change
from time to time in response to economic conditions. Matters
subject to regulation by federal, state and local authorities
include:
●
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 past few years there has been a significant
amount of discussion by legislators and the presidential
administration concerning a variety of energy tax proposals. There
can be no certainty that any such measure will be passed or what
its effect will be on oil and natural gas prices if it is passed.
In addition, many states have raised state taxes on energy sources
and additional increases may occur, although there can be no
certainty of the effect that increases in state energy taxes would
have on oil and natural gas prices. Although we believe it is in
substantial compliance with applicable environmental and other
government laws and regulations, there can be no assurance that
significant costs for compliance will not be incurred in the
future.
We have not paid cash dividends and do not anticipate paying any
cash dividends on our common stock in the foreseeable
future.
We
anticipate that we will retain all future earnings and other cash
resources for the future operation and development of our business.
We do not intend to declare or pay any cash dividends in the
foreseeable future. Payment of any future dividends will be at the
discretion of our Board of Directors after taking into account many
factors, including our operating results, financial condition,
current and anticipated cash needs, and other factors. Moreover,
there may be no capacity for the Company to declare a cash dividend
in the near future.
We failed to regain compliance with NYSE MKT listing standards in
November 2017 and our shares were delisted.
On May 11, 2016, the Company received notification from the NYSE
MKT that it was noncompliant with the NYSE MKT continued listing
standards; specifically, Section 1003(a)(i) of the NYSE MKT Company
Guide in that the Company’s stockholders’ equity is
below the $2.0 million threshold required for listed companies that
have reported losses from continuing operations in two of its three
most recently completed fiscal years. The notice also provided a
warning on possible noncompliance with the continued listing
standard set forth in Section 1003(a)(iv) related to financial
impairment based upon the Company’s accumulated deficits.
In order to maintain its listing, the Company submitted a
plan of compliance addressing how it intended to regain compliance
with Section 1003(a)(i) of the Company Guide by November 13,
2017.
28
On July 22, 2016, the Company received notification from NYSE
Regulation that its plan of compliance submitted to NYSE Regulation
on June 10, 2016, as supplemented, setting forth the
Company’s plan to regain compliance with Section 1003(a)(i)
of the NYSE MKT Company Guide was accepted and that our listing is
being continued pursuant to an extension to November 13,
2017. Additionally, on April 28, 2017, the Company received
notification from the NYSE American (formerly NYSE MKT) that it was
noncompliant with the NYSE American (formerly NYSE MKT) continued
listing standards; specifically, Section 1003(a)(ii) of the
Company Guide. The Company’s stockholders’ equity
has been below the $2.0 million threshold required for listed
companies that have reported losses from continuing operations in
two of its three most recently completed fiscal years (Section
1003(a)(i)) and is now below the $4.0 million threshold required
for listed companies that have reported losses from continuing
operations in three of its four most recent fiscal years (Section
1003(a)(ii)). The Company was given the opportunity to and
submitted a supplement to the Plan to address how it intends to
regain compliance with Section 1003(a)(ii). The Plan period
to regain compliance with all of the continued listing standards by
November 13, 2017, was the same. The Company was subject to
periodic reviews by the Exchange.
The
Company was not in compliance with the continued listing standards
by November 13, 2017, and received an official delisting notice on
November 16, 2017, and it could have a significant adverse impact
on our ability to raise additional capital.
Our
warrants were also delisted from the NYSE American (formerly NYSE
MKT) on November 17, 2017, and then expired March 23,
2018.
Our shares are now traded on the over-the-counter market under the
symbol FPPP which is more volatile than the Exchange, and may
result in a continued diminution in value of our shares. Our
delisting also resulted in the loss of other advantages to an
exchange listing, including marginability, blue sky exemptions and
others.
ITEM 1B. – UNRESOLVED STAFF
COMMENTS.
None.
ITEM 2
– PROPERTIES
Principal Oil and Natural Gas Interests
Block A-49, Andrews County, Texas is a producing oil field
located in Andrews, Texas. The Company owns a 74%-100% working
interest in three producing oil wells and three injection wells
producing out of the Devonian and Ellenburger formations at an
approximate depth of 7,000 to 9,000 feet.
Spraberry Trend, Midland County, Texas is a producing oil
and natural gas field located 6 miles east of Midland, Texas. The
Company owns a 6% 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.
29
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 25
miles north of Lawton, Oklahoma. The Company had a 25.23% working
interest in the unit which consisted of 23 producing oil wells and
9 water injection wells. We sold all of our working interest in
this project on October 10, 2017.
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.
We sold our interest in the associated acreage but maintained our
interest in the working interest and production.
Longwood Field, Caddo Parish, Louisiana is a producing
natural gas field located north of Greenwood, Louisiana. The
Company owns a 12.22% working interest in two natural gas wells
producing out of the Cotton Valley formation at a depth of
approximately 7,800 feet.
Lusk Field, Lea County, New Mexico is a producing oil and
natural gas field located outside of Hobbs, New Mexico. The Company
owns an 87.5%-100% working interest in three oil and natural gas
wells producing out of the Bone Spring and Yates formations in
Section 15 at depths ranging from approximately 3,400 feet to
approximately 10,000 feet and a 43.75% working interest in three
wells drilled and producing out of the Bone Spring formation. We
also have a 14.06% working interest in one oil and natural gas well
producing out of the Wolfcamp formation in Section 14. The Company
also owns 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
owned 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. The Company sold its interest in this
field on June 5, 2017.
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 had a 20.64% working interest in the unit
which consists of 22 producing oil and natural gas wells and 11
water injection wells. We sold all of our working interest in this
project on November 1, 2017.
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.
30
Big Muddy Field, Converse County, Wyoming is a producing
oilfield located approximately 30 miles south of Casper, Wyoming.
The Company owns a 100% working interest in the Elkhorn and J.C.
Kinney lease which consists of four oil wells producing out of the
Wallcreek and Dakota formations at depths ranging from
approximately 3,200 feet to approximately 4,000 feet.
Serbin Field, Lee and Bastrop Counties Texas is an oil and
natural gas field located approximately 50 miles east of Austin and
100 miles west of Houston. The Company has a 25% working interest
in 143 producing oil and natural gas wells. Oil and natural gas are
produced from the Taylor Sand at depths ranging from approximately
5,300 feet to approximately 5,600 feet; it is a 46-gravity oil sand
including four horizontal wells.
Production
The
table below sets forth oil and natural gas production from the
Company's net interest in producing properties for each of its last
two fiscal years.
|
|
Oil
(bbl)
|
Gas
(mcf)
|
||
|
Production by
State
|
2017
|
2016
|
2017
|
2016
|
|
Louisiana
|
-
|
19
|
5,534
|
5,672
|
|
New
Mexico
|
20,532
|
24,650
|
80,424
|
78,185
|
|
Oklahoma
|
18,986
|
23,865
|
14,445
|
20,852
|
|
Texas
|
9,456
|
11,496
|
11,413
|
15,198
|
|
Wyoming
|
4,939
|
4,851
|
-
|
13
|
|
TOTAL
|
53,913
|
64,881
|
111,816
|
119,920
|
The
Company's oil and natural gas production is sold on the spot market
and the Company does not have any production that is subject to
firm commitment contracts. During the year ended December 31, 2017,
purchases by four customers, Cimarex Energy Co., Sunoco, Inc.,
First River Energy, LLC, and Riley Exploration Group, Inc.,
represented more than 10% of total Company revenues. During the
year ended December 31, 2016, purchases by three customers, Cimarex
Energy Co., Sunoco, Inc., and Riley Exploration Group, Inc.,
represented more than 10% of total Company revenues. None of these
customers, or any other customers of the Company, has a firm sales
agreement with the Company. The Company believes that it would be
able to locate alternate customers in the event of the loss of one
or all of these customers. In addition, First River Energy, LLC
(FEL) filed for protection under chapter 11 of the federal
Bankruptcy code. We filed a proof of claim of approximately $27,000
for December 2017 crude oil production that FEL did not pay us for,
although the crude oil was picked up by FEL. We believe that we
will be reimbursed for these funds through the bankruptcy process
and have accrued a receivable for this amount.
31
Productive Wells
The
table below sets forth certain information regarding the Company's
ownership, as of December 31, 2017, of productive wells in the
areas indicated.
|
|
Productive
Wells
|
|
|
|
|
|
Oil
|
Gas
|
||
|
State
|
Gross(1)
|
Net(2)
|
Gross(1)
|
Net(2)
|
|
Louisiana
|
-
|
-
|
2
|
.24
|
|
New
Mexico
|
10
|
6.25
|
1
|
.15
|
|
Oklahoma
|
186
|
42.11
|
37
|
4.59
|
|
Texas
|
143
|
35.32
|
7
|
4.10
|
|
Wyoming
|
4
|
3.45
|
-
|
-
|
|
Total
|
343
|
87.13
|
47
|
9.08
|
1 A gross well or acre is a well or acre in which a working
interest is owned. The number of gross wells is the total number of
wells in which a working interest is owned. The number of gross
acres is the total number of acres in which a working interest is
owned.
2 A net well or acre is deemed to exist when the sum of
fractional ownership working interests in gross wells or acres
equals one. The number of net wells or acres is the sum of the
fractional working interests owned in gross wells or acres
expressed as whole numbers and fractions thereof.
Drilling Activity
In
December of 2017 the Company recompleted the Arrowhead #2 in
Andrews County, Texas as an injection well. The well was perforated
and completed in the Devonian and could possibly be completed as a
producing Devonian well in the future depending on the availability
of additional disposal capacity.
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,
2017 and 2016. See Note 12 to the Consolidated Financial Statements
and the following discussion.
Estimated Proved Reserves
|
Proved Reserves
|
Oil (Bbls)
|
Gas (Mcf)
|
|
Estimated
quantity, January 1, 2016
|
405,773
|
787,942
|
|
Revisions of previous estimates
|
68,592
|
88,490
|
|
Extensions and discoveries
|
80,742
|
-
|
|
Production
|
(64,881)
|
(119,920)
|
|
Estimated
quantity, December 31, 2016
|
490,226
|
756,512
|
|
Revisions of previous estimates
|
33,784
|
86,221
|
|
Extensions and discoveries
|
-
|
-
|
|
Sale of reserves
|
(42,085)
|
(19,657)
|
|
Production
|
(53,913)
|
(111,816)
|
|
Estimated
quantity, December 31, 2017
|
428,012
|
711,260
|
32
Proved Developed and Undeveloped Reserves
|
|
Developed
|
Undeveloped
|
Total
|
|
Oil
(Bbls)
|
|
|
|
|
December 31, 2017
|
428,012
|
-
|
428,012
|
|
December 31, 2016
|
490,226
|
-
|
490,226
|
|
|
|||
|
Gas
(Mcf)
|
|
|
|
|
December 31, 2017
|
711,260
|
-
|
711,260
|
|
December 31, 2016
|
756,512
|
-
|
756,512
|
Proved Undeveloped Reserves
As of
December 31, 2017 or 2016, we had no BOE of proved undeveloped
(“PUD”) reserves due to lower commodity prices
rendering PUD reserves uneconomic.
The
Company did not convert any PUD reserves to proved developed
reserves during 2017 or 2016 and had no net investment required to
convert PUD reserves to proved developed reserves during 2017 or
2016.
The
Company has no estimated future development costs relating to the
development of PUD reserves at December 31, 2017.
We
monitor fluctuations in commodity prices, drilling and completion
costs, operating expenses and drilling success to determine
adjustments to our drilling and development program. Based on
current expectations for cash flows, commodity prices and operating
costs and expenses, as well as drilling and completion prices, the
company has no plans to drill any wells in the near
future.
Preparation of Proved Reserves Estimates
Internal Controls Over Preparation of Proved Reserves
Estimates
Our policies regarding internal controls over the recording of
reserve estimates require reserve estimates to be in compliance
with SEC rules, regulations and guidance and prepared in accordance
with generally accepted petroleum engineering principles.
Our proved oil and natural gas reserves as of December 31, 2017 and
2016, have been estimated by Russell K. Hall & Associates, Inc.
and Joe C. Neal and Associates, respectively. The independent
consultants are responsible for overseeing the preparation of our reserve
estimates and for internal compliance of our reserve estimates with
SEC rules, regulations and generally accepted petroleum engineering
principles. Phillip Roberson, President and CFO, provides company
data (such as well ownership interests, oil and gas prices,
production volumes and well operating costs) to consulting
petroleum engineers and is the primary Company employee responsible
for reviewing their use of our data and estimation of our reserves.
Mr. Roberson, who has over sixteen years of experience in various
capacities in the oil and gas exploration industry, provides our
consulting petroleum engineers with technical data (such as well
logs, geological information and well histories). Mr. Roberson also
reviews the preliminary reserve estimates and the financial inputs
in the estimates. Mr. Roberson calculates the disclosed changes in
reserve estimates and the disclosed changes in the Standardized
Measure relating to proved oil and gas
reserves.
33
As
defined in the Securities and Exchange Commission Rules, proved
reserves are the estimated quantities of oil, natural gas and
natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future
years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is
made. Prices include considerations of changes in existing prices
provided only by contractual arrangements but not on escalations
based on future conditions. Reservoirs are considered proved if
economic production is supported by either actual production or
conclusive formation tests. Reserves which can be produced
economically through application of improved recovery techniques,
such as fluid injections, are included in the “proved”
classification when successful testing by a pilot project, or the
operations of an installed program in the reservoir, provide
support for the engineering analysis on which the project or
program was based. Due to the inherent uncertainties and the
limited nature of reservoir data, such estimates are subject to
change as additional information becomes available. The reserves
actually recovered and the timing of production of these reserves
may be substantially different from the original estimate.
Revisions result primarily from new information obtained from
development drilling and production history and from changes in
economic factors.
For information concerning the standardized measure of discounted
future net cash flows, estimated future net cash flows and present
values of such cash flows attributable to our proved oil and gas
reserves as well as other reserve information, see Note 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.
34
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, 2017, or subsequently thereafter.
Title Examinations: Oil and Gas:
As is customary in the oil and gas industry, we perform only a
perfunctory title examination at the time of acquisition of
undeveloped properties. Prior to the commencement of drilling, in
most cases, and in any event where we are the Operator, a thorough
title examination is conducted and significant defects remedied
before proceeding with operations. We believe that the title to our
properties is generally acceptable to a reasonably prudent operator
in the oil and gas industry. The properties we own are subject to
royalty, overriding royalty and other interests customary in the
industry, liens incidental to operating agreements, current taxes
and other burdens, minor encumbrances, easements and restrictions.
We do not believe that any of these burdens materially detract from
the value of the properties or will materially interfere with our
business.
We have purchased producing properties on which no updated title
opinion was prepared. In some, but not all, cases, we have retained
third party petroleum landmen to review title.
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, 2017. The
category of "Undeveloped Acreage" in the table includes leasehold
interest that already may have been classified as containing proved
undeveloped reserves.
|
|
Developed
|
Undeveloped
|
||
|
State
|
Gross
(1)
|
Net
(2)
|
Gross
(1)
|
Net
(2)
|
|
Louisiana
|
160
|
20
|
1,120
|
137
|
|
New
Mexico
|
1,320
|
772
|
1,960
|
1,092
|
|
Oklahoma
|
3,580
|
215
|
-
|
-
|
|
Texas
|
6,788
|
1,934
|
1,243
|
484
|
|
Wyoming
|
320
|
260
|
1,136
|
622
|
|
Total
|
12,168
|
3,201
|
5,459
|
2,335
|
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.
35
ITEM 3-LEGAL
PROCEEDINGS
We were
notified that the operator of our Ranger and Taylor Serbin fields,
Riley Exploration Group, Inc., sold all of its working interest to
Trivista Operating LLC, which is controlled by one of our major
shareholders, Natale Rea (2013)
Trust. Along with the working interest, Trivista also claims
to have acquired an outstanding disputed invoice of approximately
$84,000. We received a demand letter from Trivista’s counsel
for this sum. We responded that the invoice was in dispute and we
had previously sent a letter to the prior operator demanding an
audit of their operations and billing but received no response.
Trivista sent a second letter threatening litigation. Trivista
claims to have taken over operations of this field in October of
2017 but has failed to provide revenue, expense and operating
information since this date which is in direct violation of the
joint operating agreements which govern these wells. Trivista filed
suit for non-payment of outstanding disputed invoices of $107,000
plus attorney fees and court costs on February 26, 2018. We intend
to defend ourselves against these claims and possibly seek legal
remedies of our own.
On
January 12, 2018, we were notified that one of our crude oil
purchasers filed Chapter 11 bankruptcy and we would not be
receiving payment for our December 2017 production in the amount of
approximately $27,000. We have filed a proof of claim in this
matter and currently believe it is collectible. However, there is
no guarantee that we will recover all or any of the amounts
owed.
ITEM 4-SUBMISSION OF
MATTERS TO A VOTE OF SECURITY HOLDERS
None.
36
PART II
ITEM 5-MARKET FOR
REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Since
November 17, 2017, the Company’s common stock has been listed
on the OTC.QB of the OTC Markets Group, Inc. under the symbol FPPP
subsequent to our delisting by the NYSE American LLC, formerly the
NYSE Amex. Prior to that and beginning in September 20, 2005, the
Company's common stock has been traded and listed on the NYSE
American, LLC, formerly the NYSE MKT, LLC, and formerly NYSE Amex
and before that the NYSE Alternext and formerly the American Stock
Exchange, under the symbol "FPP." Prior to September 20, 2005, the
Company’s common stock was listed on the OTC Bulletin Board
under the symbol FPPC. The following sets forth the high and low
closing prices of our common stock on the NYSE American, LLC for
the periods shown.
|
FISCAL
2016
|
CLOSING
PRICE
|
|
|
|
|
|
|
|
HIGH
|
LOW
|
|
First
Quarter
|
0.72
|
0.31
|
|
Second
Quarter
|
0.87
|
0.38
|
|
Third
Quarter
|
0.91
|
0.55
|
|
Fourth
Quarter
|
0.89
|
0.50
|
|
|
|
|
|
FISCAL
2017
|
|
|
|
|
HIGH
|
LOW
|
|
First
Quarter
|
0.78
|
0.40
|
|
Second
Quarter
|
0.52
|
0.30
|
|
Third
Quarter
|
0.41
|
0.29
|
|
Fourth
Quarter
|
0.38
|
0.10
|
At
March 28, 2018, the approximate number of shareholders of record
was 153. The Company has not paid any cash dividends on its common
stock and does not expect to do so in the foreseeable
future.
EQUITY COMPENSATION PLAN INFORMATION
|
|
Number of
securities to be issued upon
exercise of
outstanding
options,
warrants and rights
|
Weighted
average
exercise
price
of
outstanding
options,
warrants and
rights
|
Number of
securities
remaining
available for
future
issuances
under equity
compensation
plans
(excluding
securities
reflected in
column
|
|
|
|
|
|
|
Equity
compensation plans approved by security holders
|
-
|
-
|
-
|
|
Equity
compensation plans not approved by security holders
|
-
|
-
|
-
|
|
Total
|
-
|
-
|
-
|
37
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,
|
|
|
|
2017
|
2016
|
|
Statements
of Operations Data:
|
|
|
|
|
|
|
|
Total
revenues
|
$3,036,132
|
$2,800,921
|
|
Operating
expenses
|
4,148,729
|
5,015,984
|
|
Net income
(loss)
|
2,666,253
|
(2,473,147)
|
|
Basic income (loss)
per share
|
$0.25
|
$(0.27)
|
|
Shares used in
computing basic earnings per share
|
10,656,506
|
9,040,085
|
|
Diluted income
(loss) per share
|
$0.25
|
$(0.27)
|
|
Shares used in
computing diluted earnings per share
|
10,656,506
|
9,040,885
|
|
|
December
31,
|
|
|
Balance
Sheet Data:
|
2017
|
2016
|
|
Working capital
(deficit)
|
$(3,122,192)
|
$(6,629,308)
|
|
Total
assets
|
7,713,435
|
8,769,947
|
|
Total
liabilities
|
5,911,078
|
9,821,063
|
|
Stockholders'
equity (deficit)
|
1,802,357
|
(1,051,116)
|
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATION
The
following discussion should be read in conjunction with the
Company's Financial Statements, and respective notes thereto,
included elsewhere herein. The information below should not be
construed to imply that the results discussed herein will
necessarily continue into the future or that any conclusion reached
herein will necessarily be indicative of actual operating results
in the future. Such discussion represents only the best present
assessment of the management of FieldPoint Petroleum
Corporation.
Overview
FieldPoint
Petroleum Corporation derives its revenues from our operating
activities including sales of oil and natural gas and operating oil
and natural gas properties. Our capital for investment in producing
oil and natural gas properties has been provided by cash flow from
operating activities and from bank financing. We categorize our
operating expenses into the categories of production expenses and
other expenses.
38
In
December 2017, the Company recompleted the Arrowhead #2 in Andrews
County, Texas as an injection well. The well was perforated and
completed in the Devonian and could possibly be completed as a
producing Devonian well in the future depending on the availability
of additional disposal capacity.
Going concern
We have
net income of $2,666,253 for the year ended December 31, 2017 but
had an operating loss of $1,112,597. We had a net loss of
$2,473,147 for the year ended December 31, 2016. We expect that the
Company will continue to experience operating losses and negative
cash flow for so long as commodities prices remain depressed. Our
financial statements for the fiscal years ended December 31, 2017
and 2016, include an explanatory paragraph expressing substantial
doubt as to our ability to continue as a going concern. The
financial statements have been prepared "assuming that the Company
will continue as a going concern." Our ability to continue as a
going concern is dependent on raising additional capital to fund
our operations and ultimately on generating future profitable
operations.
To
mitigate our current financial situation, we are taking the
following steps. We are actively meeting with investors for
possible equity investments, including business combinations. We
are continuing our effort to identify and market all possible
non-producing assets in our portfolio to maximize cash in-flows
while minimizing a loss of cash flow. We are also investigating
other possible sources to refinance our debt as we continue to pay
down our outstanding senior debt balance with a minimal effect on
cash flow and our assets by selling properties that are
non-producing or low producing. Finally, we are continuing
discussion with various individuals and groups that could be
willing to provide capital to fund operations and growth of the
Company.
The
Company was not in compliance with the NYSE MKT continued listing
standards and received an official delisting notice on November 16,
2017, and it could have a significant adverse impact on our ability
to raise additional capital.
Our
warrants were also delisted from the NYSE American (formerly NYSE
MKT) on November 17, 2017, and then expired March 23,
2018.
Our
shares are now traded on the over-the-counter market under the
symbol FPPP which is more volatile than the Exchange and may result
in a continued diminution in value of our shares and resulted in
the loss of other advantages to an exchange listing, including
marginability, blue sky exemptions and others.
There
can be no assurance that we will be able to raise sufficient
additional capital or continue to have positive cash flow from
operations to address all of our cash flow needs. If we are not
able to find alternative sources of cash or generate positive cash
flow from operations, our business and shareholders may be
materially and adversely affected.
39
Results of Operations
|
|
Years Ended
December 31,
|
|
|
|
2017
|
2016
|
|
Revenues:
|
|
|
|
Oil
sales
|
$2,621,019
|
$2,429,293
|
|
Natural gas
sales
|
321,641
|
267,564
|
|
Total
|
$2,942,660
|
$2,696,857
|
|
|
|
|
|
Sales
volumes:
|
|
|
|
Oil
(Bbls)
|
53,913
|
64,881
|
|
Natural gas
(Mcf)
|
111,816
|
119,920
|
|
Total
(BOE)
|
72,549
|
84,868
|
|
|
|
|
|
Average sales
prices
|
|
|
|
Oil
($/Bbl)
|
$48.62
|
$37.44
|
|
Natural gas
($/Mcf)
|
2.88
|
2.23
|
|
Total
($/BOE)
|
$40.56
|
$31.78
|
|
|
|
|
|
Costs and expenses
($/BOE)
|
|
|
|
Lease operating
expense (lifting costs)
|
$25.42
|
$26.06
|
|
Production
taxes
|
4.65
|
3.51
|
|
Depletion and
depreciation
|
9.63
|
13.00
|
|
Impairment of oil
and natural gas properties
|
-
|
0.63
|
|
Accretion of
discount on asset retirement obligations
|
1.45
|
1.28
|
|
General and
administrative
|
16.04
|
14.74
|
|
Total
|
$57.19
|
$59.22
|
Revenues
Oil and
natural gas sales revenues increased by $245,803 or 9%, due to
increased commodity prices of approximately $675,000 offset by
$429,000 due to lower sales volumes. Oil sales increased by
approximately $192,000 due to increased prices of approximately
$603,000 and offset by $411,000 due to lower production. Oil sales
volumes decreased by 17%, primarily due to natural declines in our
Bone Spring and Ranger Horizontal Taylor Serbin wells which were
drilled in late 2013 and 2014, as well as maintenance issues with
our North Block 12 production and the sale of our Apache Bromide
and Chickasaw Fields. Natural gas sales increased approximately
$54,000 or 20%, due to increased commodity prices of approximately
$72,000 but was offset $18,000 due to lower sales volumes in 2017.
Oil and natural gas prices have been volatile during 2017 and 2016
and we expect this to continue. Our oil and natural gas sales
revenue will be highly dependent on commodity prices in
2018.
Lease Operating Expenses
Lease
operating expenses decreased $367,047 or 17% primarily due to lower
production during 2017. Costs decreased by $0.63 per barrel
equivalent (BOE) or 2% in 2017 as compared to 2016. Decreased
commodity prices accounted for approximately $46,000 decrease in
costs and $321,000 due to lower sales volumes in 2017. Many of our
properties are mature and bear high operating expense which could
result in increased operating costs in the future.
40
Production Taxes
Production
taxes increased $39,217 or 13%, primarily the result of higher
pricing per barrel equivalent. Production taxes amounted to
approximately 11% of oil and natural gas sales revenue during 2017
and 2016. We expect production taxes to range between 8% and 11% of
oil and natural gas sales revenue.
Depletion and Depreciation
Depletion
and depreciation expense decreased by $405,003 or 37%. The decrease
in depletion and depreciation was primarily due to lower production
during 2017.
Impairment of Oil and Natural Gas Properties
During
the year ended December 31, 2016, we recorded impairment of $53,899
on two proved properties. The largest impairment was on the Flying
M field in New Mexico of $50,664. During the year ended December
31, 2017, the fair value of our properties exceeded the carrying
value so no impairment was recorded.
General and Administrative Expense
General
and administrative expenses decreased $76,524 or 6% primarily due
to decreases in compensation expense, professional services fees
and legal fees. Significant components of general and
administrative expenses include personnel-related costs and
professional services fees.
Other Income (Expense)
Other
income, net for the year ended December 31, 2017, was $3,627,829
compared to other expense, net of $258,084 for the comparable 2016
period. Gain on sale of oil and natural gas properties was
$3,831,837 for the year ended December 31, 2017. Interest expense
was $204,703 in 2017, which was a reduction of $54,453 from the
prior year.
Liquidity and Capital Resources
Cash
flow used in operating activities was approximately $737,000 and
$964,000 for the years ended December 31, 2017 and 2016,
respectively. The increase in cash flow from operating activities
was primarily due to higher commodity prices and
revenue.
In
2017, we used cash on hand to fund approximately $167,000 of
development of oil and natural gas properties and purchase other
equipment. We received proceeds of $3,961,607 from the sale of oil
and natural gas properties in 2017. In 2016, we used cash on hand
to fund approximately $165,000 of development of oil and natural
gas properties. We sold used equipment for $11,037 in
2016.
Cash
flow used in financing activities for the year ended December 31,
2017, included payments on long term debt of approximately
$3,717,000. The Company received $187,220 for issuance of 442,282
shares of restricted shares of common stock. Cash flow provided by
financing activities for the year ended December 31, 2016, included
inflow of $531,143 net, received in consideration of 1,326,846
shares of unregistered common stock for a price of $0.45 per share,
or $597,080, less expenses of $65,937.
41
Capital Requirements
As of
December 31, 2017 and 2016, we had working capital deficits of
approximately $3.1 and $6.6 million, respectively. Our line of
credit provides for certain financial covenants and ratios measured
quarterly which include a current ratio, leverage ratio, and
interest coverage ratio requirements. The Company is out of
compliance with all three ratios as of December 31, 2017, and is in
technical default of the agreement. Furthermore, the borrowing base
under our line of credit was redetermined December 1, 2015, based
on the value of proved reserves, and was reduced from $11 million
to $5.5 million. As a result of the redetermination of the credit
base, the Company had a borrowing base deficiency in the amount of
$1,495,000 on December 1, 2015. As an election under the Loan
Agreement, the Company agreed to pay and cure the deficiency in
three equal monthly installments of $498,333 each, due on December
31, 2015, January 31, 2016, and February 29, 2016. We made our
first required deficiency payment in the amount of $516,667 on
December 29, 2015, reducing our loan balance to $6,478,333 and our
borrowing base deficiency to $978,333 as of December 31, 2015.
However, we did not make the required deficiency payments in
January or February 2016.
In
October 2016, we executed a sixth amendment to the original loan
agreement, which provided for Citibank’s forbearance from
exercising remedies relating to the current defaults including the
principal payment deficiencies. The Forbearance Agreement ran
through January 1, 2018, and required that we make a $500,000 loan
principal pay down by September 30, 2017, and adhere to other
requirements including weekly cash balance reports, quarterly
operating reports, monthly accounts payable reports and that we pay
all associated legal expenses. Furthermore, under the agreement
Citibank may sweep any excess cash balances exceeding a net amount
of $800,000 less equity offering proceeds, which will be applied
towards the outstanding principal balance. The Agreement was
extended by a closing letter agreement to allow the Company time to
pay the associated legal costs and solidify the Deposit/Withdraw at
Custodian Agreements (“DEWAC”) as provided for in the
Forbearance Agreement. We were in compliance with the agreement as
of December 31, 2017.
On
December 29, 2017, we executed a seventh amendment to the original
loan agreement and first amendment to the forbearance, which
reduced our borrowing base to our current loan balance of
$2,761,632 and it provided for Citibank’s forbearance from
exercising remedies relating to the current defaults including the
principal payment deficiencies. The Forbearance Agreement ran
through March 31, 2018, and required that we adhere to certain
reporting requirements such as weekly cash reports and pay all of
the fees and expenses of the Lender’s counsel invoiced on or
before the effective date. On March 30, 2018, we executed an eighth
amendment to the original loan agreement and second amendment to
the forbearance which extended it to June 30, 2018. The terms of
the second amendment remain the same as under the first amendment
to the forbearance.
We
cannot predict how oil and natural gas prices will fluctuate during
2018 and what effect they will ultimately have on our operations.
The timing of most capital expenditures is relatively
discretionary. Therefore, we can plan expenditures to coincide with
available funds in order to minimize business risks.
On
January 1, 2014, FieldPoint signed an exploration agreement ("the
agreement") with Riley Exploration, LLC ("Riley"). The agreement
provided for an Area of Mutual Interest ("AMI") and a 90 day due
diligence period, after which both companies cross assigned their
working interest and vertical wells with a targeted ownership for
FieldPoint of 25%. The agreement also provides for a development
plan with the intent to drill up to twelve horizontal wells during
the initial twelve month period after closing. FieldPoint may elect
to be the drilling operator of every fifth well. The agreement also
provides for a standard Joint Operating Agreement which allows
either partner to participate or decline to participate in every
well with no obligatory wells. All of
the acreage in the Ranger Project is held by production so we
agreed with our joint venture partner Riley to suspend development
until we experience a substantial increase in commodity
pricing. On May 6, 2016, the
exploration agreement with Riley was terminated, however we
maintain our right to participate to the extent of our pro-rata
share of any future wells that we currently
own.
42
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
|
2018
|
2019
|
Thereafter
|
Total
|
|
|
(in thousands)
|
|||
|
Credit
facility (secured)
|
$2,761
|
$-
|
$-
|
$2,761
|
|
Interest
on credit facility
|
-
|
-
|
-
|
-
|
|
Office
lease
|
26
|
-
|
-
|
26
|
|
Total
|
$2,787
|
$-
|
$-
|
$2,787
|
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.
43
The
application of the successful efforts method of accounting requires
managerial judgment to determine the proper classification of wells
designated as developmental or exploratory which will ultimately
determine the proper accounting treatment of the costs incurred.
The results from a drilling operation can take considerable time to
analyze and the determination that commercial reserves have been
discovered requires both judgment and industry experience. Wells
may be completed that are assumed to be productive and actually
deliver oil and natural gas in quantities insufficient to be
economic, which may result in the abandonment of the wells at a
later date. The evaluation of oil and natural gas leasehold
acquisition costs requires managerial judgment to estimate the fair
value of these costs with reference to drilling activity in a given
area.
The
successful efforts method of accounting can have a significant
impact on the operational results reported when we enter a new
exploratory area in hopes of finding an oil and natural gas field
that will be the focus of future developmental drilling activity.
The initial exploratory wells may be unsuccessful and will be
expensed. Seismic costs can be substantial which will result in
additional exploration expenses when incurred.
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.
44
Because
of the precipitous drop in energy prices starting the last quarter
of 2014 and the continuing volitivity since then, we use a 5 year
NYMEX strip price rather than the average pricing that is normally
used in our estimate of expected future cash flows. This resulted
in impairment expense of $53,899 of oil and natural gas properties
in 2016. The Company had no impairment for the year ended December
31, 2017.
Subsequent Events
On
January 12, 2018 one of our purchasers, First River Energy, LLC
(“FEL’) declared bankruptcy and we filed a proof of
claim of approximately $27,000 for December 2017 crude oil
production that FEL did not pay us for, although the crude oil was
picked up by FEL. We believe that we will be reimbursed for these
funds through the bankruptcy process and have accrued a receivable
for this amount.
On
February 26, 2018 the Company was served with a summons and civil
complaint by Trivista Operating, LLC for the non-payment of
approximately $107,000 in outstanding Joint Interest Billings plus
attorney fees and court costs. The Company has hired its own
counsel and has answered this suit and intends to vigorously
defend. The amounts under this claim are represented in our
currently accrued lease operating expenses and accounts
payable.
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, 2017 and 2016, there were no
open commodity positions.
45
ITEM
8
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements
|
|
Page
|
|
Reports
of Independent Registered Public Accounting Firms
|
F-2
|
|
Consolidated
Balance Sheets
|
F-4
|
|
Consolidated
Statements of Operations
|
F-5
|
|
Consolidated
Statements of Changes in Stockholders' Equity
|
F-6
|
|
Consolidated
Statements of Cash Flows
|
F-7
|
|
Notes
to Consolidated Financial Statements
|
F-8
|
|
Supplemental
Oil and Natural Gas Information (Unaudited)
|
F-25
|
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM
To the
Stockholders and the Board of Directors of
FieldPoint
Petroleum Corporation and Subsidiaries
Opinion on the Financial Statements
We have
audited the accompanying consolidated balance sheet of FieldPoint
Petroleum Corporation and Subsidiaries (the “Company”)
as of December 31, 2017, the related consolidated statements
of operations, changes in stockholders’ equity and cash flows
for the year then ended, and the related notes (collectively
referred to as the “financial statements”). In our
opinion, the financial statements present fairly, in all material
respects, the financial position of the Company as of December 31,
2017, and the consolidated results of its operations and its cash
flows for the year then ended, in conformity with accounting
principles generally accepted in the United States of
America.
Going Concern Uncertainty
The
accompanying consolidated financial statements have been prepared
assuming that the Company will continue as a going concern. As
discussed in Note 2 to the consolidated financial statements, the
Company has suffered recurring losses from operations and has a net
capital deficiency that raise substantial doubt about its ability
to continue as a going concern. Management’s plans in regard
to these matters are also described in Note 2. The consolidated
financial statements do not include any adjustments that might
result from the outcome of this uncertainty.
Basis for Opinion
These
consolidated financial statements are the responsibility of the
Company’s management. Our responsibility is to express an
opinion on the Company’s consolidated financial statements
based on our audit. We are a public accounting firm registered with
the Public Company Accounting Oversight Board (United States)
(“PCAOB”) and are required to be independent with
respect to the Company in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.
We
conducted our audit in accordance with the standards of the PCAOB.
Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the consolidated
financial statements are free of material misstatement, whether due
to error or fraud. The Company is not required to have, nor were we
engaged to perform, an audit of its internal control over financial
reporting. As part of our audit we are required to obtain an
understanding of internal control over financial reporting but not
for the purpose of expressing an opinion on the effectiveness of
the Company’s internal control over financial reporting.
Accordingly, we express no such opinion.
Our
audit included performing procedures to assess the risks of
material misstatement of the consolidated financial statements,
whether due to error or fraud, and performing procedures to respond
to those risks. Such procedures included examining, on a test
basis, evidence regarding the amounts and disclosures in the
consolidated financial statements. Our audit also included
evaluating the accounting principles used and significant estimates
made by management, as well as evaluating the overall presentation
of the consolidated financial statements. We believe that our audit
provides a reasonable basis for our opinion.
/s/ Moss Adams LLP
Dallas,
Texas
April
2, 2018
We have
served as the Company’s auditor since 2017.
F-2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM
Board
of Directors and Stockholders
FieldPoint
Petroleum Corporation and Subsidiaries
We have
audited the accompanying consolidated balance sheet of FieldPoint
Petroleum Corporation and subsidiaries (the “Company”)
as of December 31, 2016, and the related consolidated statements of
operations, changes in stockholders’ equity and cash flows
for the year 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 audit.
We
conducted our audit 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 audit 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 audit provides 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, 2016, and the results of their operations and their cash flows
for the year then ended, in conformity with U.S. generally accepted
accounting principles.
The
accompanying consolidated financial statements have been prepared
assuming that the Company will continue as a going concern. As
discussed in Note 2 to the consolidated financial statements, the
Company has suffered recurring losses, and has a working capital
deficit. This raises substantial doubt about the Company’s
ability to continue as a going concern. Management’s plans in
regard to these matters also are discussed in Note 2. The
consolidated financial statements do not include any adjustments
that might result from the outcome of this
uncertainty.
/s/
Hein & Associates
LLP
Dallas,
Texas
March
31, 2017
F-3
FIELDPOINT PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
|
|
December 31,
|
|
|
|
2017
|
2016
|
|
CURRENT
ASSETS:
|
|
|
|
Cash and cash
equivalents
|
$408,656
|
$880,067
|
|
Accounts
receivable:
|
|
|
|
Oil and natural gas
sales
|
366,939
|
321,500
|
|
Joint interest
billings, less allowance for doubtful accounts of approximately
$237,000 each period
|
260,816
|
243,106
|
|
Income taxes
receivable
|
25,057
|
8,776
|
|
Prepaid expenses
and other current assets
|
48,998
|
37,837
|
|
Total current
assets
|
1,110,466
|
1,491,286
|
|
|
|
|
|
PROPERTY
AND EQUIPMENT:
|
|
|
|
Oil and natural gas
properties (successful efforts method)
|
33,753,833
|
41,288,964
|
|
Other
equipment
|
117,561
|
111,750
|
|
Less accumulated
depletion, depreciation and impairment
|
(27,425,652)
|
(34,147,053)
|
|
Net property and
equipment
|
6,445,742
|
7,253,661
|
|
|
|
|
|
INCOME
TAX RECEIVABLE – LONG TERM
|
157,227
|
-
|
|
|
|
|
|
OTHER
ASSETS
|
-
|
25,000
|
|
|
|
|
|
Total
assets
|
$7,713,435
|
$8,769,947
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS’ EQUITY
|
||
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
Line of credit -
current
|
$2,761,632
|
$6,478,333
|
|
Accounts payable
and accrued expenses
|
897,101
|
1,139,596
|
|
Oil and natural gas
revenues payable
|
427,859
|
461,227
|
|
Asset retirement
obligation - current
|
146,066
|
41,438
|
|
Total current
liabilities
|
4,232,658
|
8,120,594
|
|
|
|
|
|
ASSET
RETIREMENT OBLIGATION
|
1,678,420
|
1,700,469
|
|
Total
liabilities
|
5,911,078
|
9,821,063
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES (Notes 2,
9 and 10)
|
|
|
|
STOCKHOLDERS’ EQUITY:
|
|
|
|
Common stock, $.01
par value, 75,000,000 shares authorized;
11,596,229 and
11,153,947 shares issued, respectively; and 10,669,229 and
10,226,947 outstanding, respectively
|
115,962
|
111,539
|
|
Additional paid-in
capital
|
13,715,668
|
13,532,871
|
|
Accumulated
deficit
|
(10,062,381)
|
(12,728,634)
|
|
Treasury stock,
927,000 shares, each period, at cost
|
(1,966,892)
|
(1,966,892)
|
|
Total
stockholders’ equity (deficit)
|
1,802,357
|
(1,051,116)
|
|
Total liabilities
and stockholders’ equity
|
$7,713,435
|
$8,769,947
|
See accompanying notes to these consolidated financial
statements.
F-4
FIELDPOINT PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
December 31,
|
|
|
|
2017
|
2016
|
|
REVENUE:
|
|
|
|
Oil and natural gas
sales
|
$2,942,660
|
$2,696,857
|
|
Well operational
and pumping fees
|
2,901
|
5,047
|
|
Disposal
fees
|
90,571
|
99,017
|
|
Total
revenue
|
3,036,132
|
2,800,921
|
|
|
|
|
|
COSTS
AND EXPENSES:
|
|
|
|
Production
expense
|
2,181,377
|
2,509,206
|
|
Depletion and
depreciation
|
698,337
|
1,103,340
|
|
Impairment of oil
and natural gas properties
|
-
|
53,899
|
|
Accretion of
discount on asset retirement obligations
|
105,000
|
109,000
|
|
General and
administrative
|
1,164,015
|
1,240,539
|
|
Total costs and
expenses
|
4,148,729
|
5,015,984
|
|
|
|
|
|
OPERATING
LOSS
|
(1,112,597)
|
(2,215,063)
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
Interest
income
|
201
|
801
|
|
Interest
expense
|
(204,703)
|
(259,156)
|
|
Gain on sale of oil
and natural gas properties
|
3,831,837
|
-
|
|
Miscellaneous
|
494
|
271
|
|
Total other income
(expense)
|
3,627,829
|
(258,084)
|
|
|
|
|
|
INCOME
(LOSS) BEFORE INCOME TAXES
|
2,515,232
|
(2,473,147)
|
|
|
|
|
|
INCOME TAX EXPENSE –
CURRENT
|
(6,206)
|
-
|
|
INCOME TAX BENEFIT –
DEFERRED
|
157,227
|
-
|
|
|
|
|
|
TOTAL
INCOME TAX BENEFIT
|
151,021
|
-
|
|
|
|
|
|
NET
INCOME (LOSS)
|
$2,666,253
|
$(2,473,147)
|
|
|
|
|
|
INCOME (LOSS) PER SHARE:
|
|
|
|
BASIC
|
$0.25
|
$(0.27)
|
|
DILUTED
|
$0.25
|
$(0.27)
|
|
|
|
|
|
WEIGHTED
AVERAGE SHARES OUTSTANDING:
|
|
|
|
BASIC
|
10,656,506
|
9,040,085
|
|
DILUTED
|
10,656,506
|
9,040,085
|
See accompanying notes to these consolidated financial
statements.
F-5
FIELDPOINT PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’
EQUITY
For the Years Ended December 31, 2017 and 2016
|
|
Common
Stock
|
Additional
Paid-in
|
Retained
Earnings (Accumulated)
|
Treasury
Stock
|
|
||
|
|
Shares
|
Amount
|
Capital
|
Deficit)
|
Shares
|
Amount
|
Total
|
|
|
|
|
|
|
|
|
|
|
BALANCES, January 1,
2016
|
9,807,101
|
$98,070
|
$13,001,447
|
$(10,255,487)
|
927,000
|
$(1,966,892)
|
$877,138
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock, net of
costs
|
1,326,846
|
13,269
|
517,874
|
-
|
-
|
-
|
531,143
|
|
|
|
|
|
|
|
|
|
|
Stock
compensation
|
20,000
|
200
|
13,550
|
-
|
-
|
-
|
13,750
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
-
|
-
|
-
|
(2,473,147)
|
-
|
-
|
(2,473,147)
|
|
|
|
|
|
|
|
|
|
|
BALANCES, December 31,
2016
|
11,153,947
|
111,539
|
13,532,871
|
(12,728,634)
|
927,000
|
(1,966,892)
|
(1,051,116)
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock, net of
costs
|
442,282
|
4,423
|
182,797
|
-
|
-
|
-
|
187,220
|
|
|
|
|
|
|
|
|
|
|
Net income
|
-
|
-
|
-
|
2,666,253
|
-
|
-
|
2,666,253
|
|
|
|
|
|
|
|
|
|
|
BALANCES, December 31,
2017
|
11,596,229
|
$115,962
|
$13,715,668
|
$(10,062,381)
|
927,000
|
$(1,966,892)
|
$1,802,357
|
See accompanying notes to these consolidated financial
statements.
F-6
FIELDPOINT PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
December 31,
|
|
|
|
2017
|
2016
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
Net income
(loss)
|
$2,666,253
|
$(2,473,147)
|
|
Adjustments to
reconcile net income (loss) to net cash provided by (used in)
operating activities:
|
|
|
|
Depletion and
depreciation
|
698,337
|
1,103,340
|
|
Impairment of oil
and natural gas properties
|
-
|
53,899
|
|
Accretion of
discount on asset retirement obligations
|
105,000
|
109,000
|
|
Stock compensation
expense
|
-
|
13,750
|
|
Gain on sale of oil
and natural gas properties
|
(3,831,837)
|
-
|
|
Deferred income tax
benefit
|
(157,227)
|
-
|
|
Changes in current
assets and liabilities:
|
|
|
|
Accounts
receivable
|
(63,149)
|
192,966
|
|
Income taxes
receivable
|
(16,281)
|
14,666
|
|
Prepaid expenses
and other current assets
|
(11,161)
|
29,399
|
|
Accounts payable
and accrued expenses
|
(93,379)
|
(9,574)
|
|
Oil and natural gas
revenues payable
|
(33,368)
|
1,600
|
|
Net cash used in
operating activities
|
(736,812)
|
(964,101)
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
Additions to oil
and natural gas properties and other equipment
|
(166,725)
|
(165,291)
|
|
Proceeds from the
sale of oil and natural gas properties
|
3,961,607
|
11,037
|
|
Net cash provided
by (used in) investing activities
|
3,794,882
|
(154,254)
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
Net proceeds from
issuance of common stock
|
187,220
|
531,143
|
|
Payments on line of
credit
|
(3,716,701)
|
-
|
|
Net cash provided
by (used in) financing activities
|
(3,529,481)
|
531,143
|
|
|
|
|
|
NET
DECREASE IN CASH AND CASH EQUIVALENTS
|
(471,411)
|
(587,212)
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, beginning of
year
|
880,067
|
1,467,279
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, end of the
year
|
$408,656
|
$880,067
|
|
|
|
|
|
SUPPLEMENTAL
INFORMATION:
|
|
|
|
Cash paid during
the year for interest
|
$272,120
|
$256,1733
|
|
Cash paid during
the year for income taxes
|
$20,214
|
$4,117
|
|
Change in accrued
capital expenditures
|
$58,498
|
$98,671
|
F-7
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Summary of Significant Accounting Policies
Organization and Nature of Operations
FieldPoint
Petroleum Corporation (the “Company”, “we”
or “our”) is incorporated under the laws of the state
of Colorado. We are engaged in the acquisition, operation and
development of oil and natural gas properties, which are located in
Louisiana, New Mexico, Oklahoma, South Central Texas and Wyoming as
of December 31, 2017 and 2016.
Consolidation Policy and Basis of Presentation
The
accompanying consolidated financial statements have been prepared
in accordance with accounting principles generally accepted in the
United States of America and include the accounts of the Company
and its wholly owned subsidiaries, Bass Petroleum, Inc., and Raya
Energy Corp. All material intercompany accounts and transactions
have been eliminated in consolidation.
Cash and Cash Equivalents
We
consider all highly liquid investments purchased with an original
maturity of three months or less to be cash equivalents. At times,
we maintain deposit balances in excess of FDIC insurance limits. We
have not experienced any losses in such accounts and believe we are
not exposed to any significant credit risk on cash and cash
equivalents.
Oil and Natural Gas Properties
Our oil
and natural gas properties consisted of the following at December
31:
|
|
2017
|
2016
|
|
Mineral interests
in properties:
|
|
|
|
Unproved
properties
|
$250,217
|
$850,000
|
|
Proved
properties
|
9,762,108
|
13,433,966
|
|
Wells and related
equipment and facilities
|
23,741,508
|
27,004,998
|
|
Total
costs
|
33,753,833
|
41,288,964
|
|
Less accumulated
depletion, depreciation and impairment
|
(27,319,847)
|
(34,059,585)
|
|
|
$6,433,986
|
$7,229,379
|
We
follow the successful efforts method of accounting for our oil and
natural gas producing activities. Costs to acquire mineral
interests in oil and natural gas properties, to drill and equip
exploratory wells that find proved reserves, to drill and equip
development wells and related asset retirement costs are
capitalized. Costs to drill exploratory wells are capitalized
pending determination of whether the wells have found proved
reserves. If we determine that the wells have not found proved
reserves, the costs are charged to expense. There were no
exploratory wells capitalized pending determinations of whether the
wells found proved reserves at December 31, 2017 or 2016.
Geological and geophysical costs, including seismic studies and
costs of carrying and retaining unproved properties are charged to
expense as incurred.
We
capitalize interest on expenditures for significant exploration and
development projects that last more than six months while
activities are in progress to bring the assets to their intended
use. Through December 31, 2017, we have capitalized no
interest costs because our exploration and development projects
generally last less than six months. Costs to maintain wells and
related equipment are charged to expense as incurred.
F-8
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On the
sale or retirement of a complete unit of a proved property, the
cost and related accumulated depletion and depreciation are
eliminated from the property accounts, and the resulting gain or
loss is recognized. On the sale of a partial unit of proved
property, the amount received is treated as a reduction of the cost
of the interest retained.
Capitalized amounts
attributable to proved oil and natural gas properties are depleted
by the unit-of-production method of proved reserves using the unit
conversion ratio of 6 Mcf of gas to 1 bbl of oil. Depletion and
depreciation expense for oil and natural gas producing property and
related equipment was $680,000 and $1,084,000 for the years ended
December 31, 2017 and 2016, respectively.
Unproved oil and
natural gas properties that are individually significant are
periodically assessed for impairment of value, and a loss is
recognized at the time of impairment by providing an impairment
allowance. No impairment of unproved properties was recorded during
the years ended December 31, 2017 and 2016.
Capitalized costs
related to proved oil and natural gas properties, including wells
and related equipment and facilities, are evaluated for impairment
based on an analysis of undiscounted future net cash flows. If
undiscounted cash flows are insufficient to recover the net
capitalized costs related to proved properties, then we recognize
an impairment charge in income from operations equal to the
difference between the net capitalized costs related to proved
properties and their estimated fair values based on the present
value of the related future net cash flows, which is a
non-recurring fair value measurement classified as Level 3 in the
fair value hierarchy. We recorded no impairment on our proved oil
and natural gas properties during the year ended December 31, 2017,
but recorded impairment of $53,899 during the year ended December
31, 2016.
On the
sale of an entire interest in an unproved property for cash or cash
equivalent, gain or loss on the sale is recognized, taking into
consideration the amount of any recorded impairment if the property
had been assessed individually. If a partial interest in an
unproved property is sold, the amount received is treated as a
reduction of the cost of the interest retained.
Oil and Natural Gas Sales Receivable
Oil and
natural gas sales receivable principally consist of accrued oil and
natural gas sales proceeds receivable and are typically collected
within 20 to 56 days. We ordinarily do not require collateral for
such receivables, nor do we charge interest on past due balances.
We periodically review accounts receivable for collectability and
reduce the carrying amount of the accounts receivable by an
allowance. The allowance for doubtful accounts was approximately
$237,000 at December 31, 2017 and 2016. As of December 31, 2017,
our accounts receivable were primarily with several independent
purchasers of our crude oil and natural gas production. At December
31, 2017, we had balances due from three customers which were
greater than 10% of our accounts receivable related to crude oil
and natural gas production. These three customers accounted for 66%
of accounts receivable at December 31, 2017. At December 31, 2016,
we had balances due from three customers which were greater than
10% of our accounts receivable related to crude oil and natural gas
production. These three customers accounted for 69% of accounts
receivable at December 31, 2016. In the event that one or more of
these significant customers cease doing business with us, we
believe that there are potential alternative customers with whom we
could establish new relationships and that those relationships will
result in the replacement of one or more lost
customers.
F-9
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Joint Interest Billings Receivable and Oil and Natural Gas Revenues
Payable
Joint
interest billings receivable represents amounts receivable for
lease operating expenses and other costs due from third party
working interest owners in the wells that the Company operates. The
receivable is recognized when the cost is incurred and the related
payable and the Company’s share of the cost is recorded. We
often have the ability to offset amounts due against the
participant’s share of production revenue from the related
property.
The
Company uses the reserve for bad debt method of valuing doubtful
joint interest billings receivable based on historical experience,
coupled with a review of the current status of existing
receivables. The balance of the reserve for doubtful accounts,
deducted against joint interest billings receivable to properly
reflect the realizable value was approximately $237,000 at December
31, 2017 and 2016.
Oil and
natural gas revenues payable represents amounts due to third party
revenue interest owners for their share of oil and natural gas
revenue collected on their behalf by the Company. The payable is
recorded when the Company recognizes oil and natural gas sales and
records the related oil and natural gas sales
receivable.
Other Property
Other
assets classified as property and equipment are primarily office
furniture and equipment and vehicles, which are carried at cost.
Depreciation is provided using the straight-line method over
estimated useful lives ranging from three to five years. Gain or
loss on retirement or sale or other disposition of assets is
included in income in the period of disposition. Depreciation
expense for other property and equipment was $18,337 and $19,340
for the years ended December 31, 2017 and 2016,
respectively.
Asset Retirement Obligations
Our
financial statements reflect our asset retirement obligations,
consisting of future plugging and abandonment expenditures related
to our oil and natural gas properties, which can be reasonably
estimated. The asset retirement obligation is recorded at fair
value on a discounted basis as a liability at the asset's
inception, with an offsetting increase to producing properties on
the consolidated balance sheets. Significant inputs to determining
fair value include applying a credit adjusted risk free rate which
is a Level 3 measurement in the fair value hierarchy. Periodic
accretion of the discount of the estimated liability is recorded as
an expense in the consolidated statements of
operations.
The
following is a reconciliation of the Company’s asset
retirement obligations for the years ended December
31:
|
|
2017
|
2016
|
|
Asset retirement
obligation at January 1,
|
$1,741,907
|
$1,812,980
|
|
Accretion of
discount
|
105,000
|
109,000
|
|
Liabilities settled
during the year
|
(15,170)
|
(180,073)
|
|
Liabilities
sold
|
(42,418)
|
-
|
|
Revision in
estimated cash flows
|
35,167
|
-
|
|
Asset retirement
obligation at December 31,
|
1,824,486
|
1,741,907
|
|
Less: current asset
retirement obligations
|
(146,066)
|
(41,438)
|
|
Long-term asset
retirement obligations
|
$1,678,420
|
$1,700,469
|
F-10
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income Taxes
Income
taxes are provided for the tax effects of transactions reported in
the financial statements and consist of taxes currently due, if
any, plus net deferred taxes related to differences between the
bases of assets and liabilities for financial and income tax
reporting. Deferred tax assets and liabilities represent the future
tax consequences of those differences, which will either be taxable
or deductible when the assets and liabilities are recovered or
settled. Valuation allowances are recognized to limit recognition
of deferred tax assets where appropriate. Such allowances may be
reversed when circumstances provide evidence that the deferred tax
assets will more likely than not be realized.
In
November 2015, the FASB issued Accounting Standards Update No.
2015-17 – Balance Sheet Classification of Deferred Taxes that
simplifies the presentation of deferred income taxes on the balance
sheet. Under the new standard, deferred tax assets and liabilities
are classified as noncurrent on the balance sheet. This new update
is effective for financial statements issued for fiscal years
beginning after December 15, 2016, (and interim periods within
those fiscal years), with early adoption permitted and allows
prospective or retrospective application. The Company adopted this
accounting standard update prospectively as of January 1, 2016. The
adoption of this standard had no impact on the consolidated balance
sheet as of December 31, 2016.
On
December 22, 2017, the President of the United States signed into
law what is informally called the Tax Cuts and Jobs Act of 2017
(the “Act”), a comprehensive U.S. tax reform package
that, effective January 1, 2018, among other things, lowered the
corporate income tax rate from 35% to 21%, repealed the Alternative
Minimum Tax and made the AMT credit refundable. Accounting rules
require companies to recognize the effects of changes in tax laws
and tax rates on deferred tax assets and liabilities in the period
in which the new legislation is enacted. We recorded a total income
tax benefit of $157,227 in the year ended December 31, 2017, the
amount of our AMT credit that will be refundable in tax years
beginning after 2017. We also reassessed the realizability of our
deferred tax assets but determined that it continues to be more
likely than not that the deferred tax assets will not be utilized
in the future and continue to record a full valuation allowance of
the deferred tax assets.
As we
do not have all the necessary information to analyze all income tax
effects of the Act, this is a provisional amount which we believe
represents a reasonable estimate of the accounting implications of
this tax reform. We will continue to evaluate the Act and adjust
the provisional amounts as additional information is obtained. The
ultimate impact of tax reform may differ from our provisional
amounts due to changes in our interpretations and assumptions, as
well as additional regulatory guidance that may be issued. We
expect to complete our detailed analysis no later than the fourth
quarter of 2018.
Production Taxes and Ad Valorem Taxes
Production taxes
and ad valorem taxes are included in production expense. Total
production and ad valorem taxes were $348,195 and $330,722 for the
years ended December 31, 2017 and 2016, respectively.
F-11
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Use of Estimates and Certain Significant Estimates
The
preparation of the Company’s financial statements in
conformity with accounting principles generally accepted in the
United States of America requires the Company’s management to
make estimates and assumptions that affect the amounts reported in
these financial statements and accompanying notes. Actual results
could differ from those estimates. Significant assumptions are
required in the valuation of proved oil and natural gas reserves,
which as described above may affect the amount at which oil and
natural gas properties are recorded. The Company’s allowance
for doubtful accounts is a significant estimate and is based on
management’s estimates of uncollectible receivables. The
asset retirement obligations require estimates of future plugging
and abandonment expenditures. It is at least reasonably possible
these estimates could be revised in the near term and the revisions
could be material.
Our
estimates of proved reserves materially impact depletion and
impairment expense. If proved reserves decline, then the rate at
which we record depletion expense increases, reducing net income. A
decline in estimates of proved reserves may result from lower
prices, evaluation of additional operating history, mechanical
problems at our wells and catastrophic events such as explosions,
hurricanes and floods. Lower prices also may make it uneconomical
to drill wells or produce from fields with high operating costs. In
addition, a decline in proved reserves may impact our assessment of
our oil and natural gas properties for impairment.
Our
proved reserve estimates are a function of many assumptions, all of
which could deviate materially from actual results. As such,
reserve estimates may vary materially from the ultimate quantities
of oil and natural gas actually produced.
Revenue Recognition
The
Company uses the sales method of accounting for oil and natural gas
revenues. Under this method, revenues are based on actual volumes
of oil and natural gas sold to purchasers. The volumes of natural
gas sold may differ from the volumes to which the Company is
entitled based on its interest in the properties. Differences
between volumes sold and volumes based on entitlements create
natural gas imbalances. Material imbalances are reflected as
adjustments to reported natural gas reserves and future cash flows.
There were no material natural gas imbalances as of December 31,
2017 and 2016.
We
recognize revenue when crude oil and natural gas quantities are
delivered to or collected by the respective purchaser. Title to the
produced quantities transfers to the purchaser at the time the
purchaser receives or collects the quantities. Prices for such
production are defined in sales contracts and are readily
determinable based on certain publicly available indices. The
purchasers of such production have historically made payment for
crude oil and natural gas purchases within 20 to 56 days. We
periodically review the difference between the dates of production
and the dates we collect payment for such production to ensure that
accounts receivable from those purchasers are
collectible.
As
previously discussed, we sold our crude oil and natural gas
production to several independent purchasers. During the year ended
December 31, 2017, we had sales of 10% or more of our total oil and
natural gas sales revenue to four customers which represented 63%
of total oil and natural gas sales revenue for the year. During the
year ended December 31, 2016, we had sales of 10% or more of our
total oil and natural gas sales revenue to three customers which
represented 69% of total oil and natural gas sales revenue for the
year.
Comprehensive Income
The
Company has no elements of comprehensive income other than net
income.
F-12
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Share-Based Compensation
We
measure and record compensation expense for all share-based payment
awards to employees and directors based on estimated fair values.
Additionally, compensation costs for share-based awards are
recognized over the requisite grant-date service period based on
the grant-date fair value.
Financial Instruments
The
Company’s financial instruments are cash, accounts receivable
and payable and long-term debt. Management believes the fair values
of these instruments, with the exception of the long-term debt,
approximate the carrying values, due to the short-term nature of
the instruments. Management believes the fair value of long-term
debt also reasonably approximates its carrying value, based on
expected cash flows and interest rates.
Recently Issued Accounting Pronouncements
The
FASB issued ASU 2016-09, “Compensation – Stock
Compensation”, simplifying the accounting for share-based
payment transactions including the income tax consequences,
classification of awards as either equity or liabilities and
classification on the statements of cash flows. Under the new
standard, all excess tax benefits and tax deficiencies (including
tax benefits of dividends on share-based payment awards) should be
recognized as income tax expense or benefit on the statements of
income. Under current GAAP, excess tax benefits are recognized in
additional paid-in capital while tax deficiencies are recognized
either as an offset to accumulated excess tax benefits, if any, or
on the statements of income. The new accounting guidance is
effective for annual periods beginning after December 15,
2016. Early adoption is permitted in any interim or annual
period. Certain provisions require retrospective/modified
retrospective transition while others are to be applied
prospectively. Management adopted ASU 2016-09 effective January 1,
2017. The adoption of this standard did not have a material impact
on the consolidated financial statements.
In
February 2016, the FASB issued Update No.
2016-02, “Leases”, to increase transparency and
comparability among organizations by recognizing lease assets and
lease liabilities on the balance sheet and disclosing key
information about leasing arrangements. This authoritative guidance
is effective for fiscal years beginning after December 15, 2018,
and interim periods within those fiscal years. The Company is still
evaluating the impact of this guidance on its consolidated
financial statements.
In
November 2016, the FASB issued Accounting Standards Update No.
2016-18, “Statement of Cash Flows: Restricted Cash”, to
require amounts generally described as restricted cash and
restricted cash equivalents to be included with cash and cash
equivalents when reconciling the beginning-of-period and
end-of-period total amounts shown on the statement of cash flows.
The guidance is effective for the annual period ending after
December 15, 2017, and interim periods within those fiscal years,
using a retrospective transition method to each period presented.
The Company adopted the new standard December 31, 2017, and it did
not impact our consolidated statement of cash flows.
In May
2014, the FASB issued Accounting Standards Update No. 2014-09,
“Revenue from Contracts with Customers”. Under this new
standard, revenue is recognized at the time goods or services are
transferred to a customer for the amount of consideration the
entity expects to be entitled in exchange for the specific goods or
services. We have completed a detailed
review of our individual purchaser contracts and adopted this
standard on January 1, 2018, using the modified retrospective
approach. Adoption of this standard did not have a significant
impact on our consolidated statements of operations or cash flows
and prior period financial statements will not be restated.
Additional disclosures will be required to describe the nature,
amount, timing and uncertainty of revenue and cash flows from
contracts with customers, beginning with our Form 10-Q for the
three months ended March 31, 2018.
F-13
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2.
Liquidity and Going Concern
Our
accompanying consolidated financial statements have been prepared
assuming that we will continue as a going concern, which
contemplates realization of assets and the satisfaction of
liabilities in the normal course of business for the twelve-month
period following the date of these consolidated financial
statements are issued. Continued low oil and natural gas prices
during 2017 and 2016 have had a significant adverse impact on our
business, and as a result of our financial condition, substantial
doubt exists that we will be able to continue as a going
concern.
As of December 31,
2017 and 2016, the Company has a working capital deficit of
approximately $3,122,000 and $6,629,000, respectively, primarily
due to the classification of our line of credit as a current
liability. The line of credit provides for certain financial
covenants and ratios measured quarterly which include a current
ratio, leverage ratio, and interest coverage ratio
requirements. The Company is out of compliance with all three
ratios as of December 31, 2017, and we do not expect to regain
compliance in 2018. A Forbearance Agreement was executed in
October 2016 and amended on December 29, 2017, and March 30, 2018,
as discussed below.
Citibank is in a
first lien position on all of our properties. Citibank lowered our
borrowing base from $11,000,000 to $5,500,000 on December 1, 2015,
and lowered it again to $2,761,632 on December 29,
2017.
In
October 2016, we executed a sixth amendment to the original loan
agreement, which provides for Citibank’s forbearance from
exercising remedies relating to the current defaults including the
principal payment deficiencies. The Forbearance Agreement ran
through January 1, 2018, and required that we make a $500,000 loan
principal pay down by September 30, 2017, and adhere to other
requirements including weekly cash balance reports, quarterly
operating reports, monthly accounts payable reports and that we pay
all associated legal expenses. Furthermore, under the agreement
Citibank may sweep any excess cash balances exceeding a net amount
of $800,000 less equity offering proceeds, which will be applied
towards the outstanding principal balance.
On
December 29, 2017, we executed a seventh amendment to the original
loan agreement and first amendment to the forbearance, which
reduced our borrowing base to our current loan balance of
$2,761,632 and it provided for Citibank’s forbearance from
exercising remedies relating to the current defaults including the
principal payment deficiencies. The Forbearance Agreement ran
through March 31, 2018, and required that we adhere to certain
reporting requirements such as weekly cash reports and pay all of
the fees and expenses of the Lender’s counsel invoiced on or
before the effective date. On March 30, 2018, we executed an eighth
amendment to the original loan agreement and second amendment to
the forbearance which extended it to June 30, 2018. The terms of
the second amendment remain the same as under the first amendment
to the forbearance.
F-14
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
To
mitigate our current financial situation, we are taking the
following steps. We are actively meeting with investors for
possible equity investments, including business combinations. We
are continuing our effort to identify and market all possible
non-producing assets in our portfolio to maximize cash in-flows
while minimizing a loss of cash flow. We are also investigating
other possible sources to refinance our debt as we continue to pay
down our outstanding senior debt balance with a minimal effect on
cash flow and our assets by selling properties that are
non-producing or low producing. Finally we are continuing
discussion with various individuals and groups that could be
willing to provide capital to fund operations and growth of the
Company.
The
Company was not in compliance with the NYSE MKT continued listing
standards and received an official delisting notice on November 16,
2017, and it could have a significant adverse impact on our ability
to raise additional capital.
Our
warrants were also delisted from the NYSE American (formerly NYSE
MKT) on November 17, 2017, and then expired March 23,
2018.
Our
shares are now traded on the over-the-counter market under the
symbol FPPP which is more volatile than the Exchange and may result
in a continued diminution in value of our shares. The delisting
also resulted in the loss of other advantages to an exchange
listing, including marginability, blue sky exemptions and
others.
3.
Oil and Natural Gas Properties
The
Company sold its interest in several properties during the year
ended December 31, 2017. The Company sold its net interest in non-
producing leasehold, and net interest in the Hermes, Cronos and
Mercury wells which were not economic to our interests. The Company
also sold its net interest in the unproved Bilbrey acreage that was
held by production. The gross proceeds from the sale of our net
interest in these two properties was $2,145,000. The Company sold
401 net acres of non-producing leasehold in Lea County, New Mexico.
The gross proceeds from the sale of our net interest in these
properties was $1,200,000. We also sold our interest in the Apache
Bromide field for $603,607 net of liabilities of $296,393. We sold
our interest in Rush Springs for $11,700. We recognized total gains
of $3,831,837. We continue to evaluate our portfolio for other
properties to divest in order to regain compliance with our
bank’s debt covenants. In December 2016, the Company assigned
its interests in the Giddings Field, Fayette County, Texas to
another operator in exchange for the plugging
liability.
The
Company made no purchases of oil and natural gas properties during
the years ended December 31, 2017 and 2016. The Company did not
drill or complete any development wells during 2017 and
2016.
The
Company had no impairment to properties during the year ended
December 31, 2017. The Company recorded impairment charges of
$53,899 during the year ended December 31, 2016, as a result of
writing down the carrying value of certain properties to fair
value. In order to determine the amounts of the impairment charges,
the Company compares net capitalized costs of proved oil and
natural gas properties to estimated undiscounted future net cash
flows using management's expectations of economically recoverable
proved reserves. If the net capitalized cost exceeds the
undiscounted future net cash flows, the Company impairs the net
cost basis down to the discounted future net cash flows, which is
management's estimate of fair value. In order to determine the fair
value, the Company estimates reserves, future operating and
development costs, future commodity prices and a discounted cash
flow model utilizing a 10 percent discount rate. The estimates used
by management for the fair value measurements utilized in this
review include significant unobservable inputs, and therefore, the
fair value measurements are classified as Level 3 of the fair value
hierarchy.
F-15
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4.
Fair Value Measurements
The
Company follows fair value measurement authoritative guidance,
which defines fair value, establishes a framework for using fair
value to measure assets and liabilities, and expands disclosures
about fair value measurements. The authoritative accounting
guidance defines fair value as the price that would be received to
sell an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date.
The statement establishes a hierarchy for inputs used in measuring
fair value that maximizes the use of observable inputs and
minimizes the use of unobservable inputs by requiring that the most
observable inputs be used when available. Observable inputs are
inputs that market participants would use in pricing the asset or
liability developed based on market data obtained from sources
independent of the Company. Unobservable inputs are inputs that
reflect the Company’s assumptions of what market participants
would use in pricing the asset or liability developed based on the
best information available in the circumstances. The hierarchy is
broken down into three levels based on the reliability of the
inputs as follows:
●
Level
1 – Quoted prices are available in active markets for
identical assets or liabilities as of the reporting
date.
●
Level 2:
Quoted prices in active markets for similar assets and liabilities,
quoted prices for identical or similar instruments in markets that
are not active, and model-derived valuations whose inputs are
observable or whose significant value drivers are
observable.
●
Level
3 – Pricing inputs include significant inputs that are
generally less observable from objective sources. These inputs may
be used with internally developed methodologies that result in
management’s best estimate of fair value. The fair value of
oil and gas properties used in estimating our recognized impairment
loss represents a non-recurring Level 3 measurement.
Financial and
non-financial assets and liabilities are to be classified based on
the lowest level of input that is significant to the fair value
measurement. The Company’s assessment of the significance of
a particular input to the fair value measurement requires judgment
and may affect the valuation of the fair value of assets and
liabilities and their placement within the fair value hierarchy
levels.
F-16
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The
following tables present the Company’s financial and
non-financial assets and liabilities that were accounted for at
fair value as of December 31, 2017 and 2016, and their
classification within the fair value hierarchy:
|
|
As of December
31, 2017
|
||
|
|
Level
1
|
Level
2
|
Level
3
|
|
|
|
|
|
|
Proved
properties(1)
|
$-
|
$-
|
$-
|
|
Unproved
properties(1)
|
$-
|
$-
|
$-
|
|
|
As of December
31, 2016
|
||
|
|
Level
1
|
Level
2
|
Level
3
|
|
|
|
|
|
|
Proved properties
(1)
|
$-
|
$-
|
$82,806
|
|
Unproved properties
(1)
|
$-
|
$-
|
$-
|
___________________________
|
|
|
|
(1)
|
This
represents non-financial assets that are measured at fair
value on a nonrecurring basis due to impairments. This is the fair
value of the asset base that was subjected to impairment and does
not reflect the entire asset balance as presented on the
accompanying balance sheets. Please refer to the Proved Oil and Gas Properties and
Unproved Oil and Gas
Properties sections below for additional
discussion.
|
Proved Oil and Gas Properties
Proved
oil and natural gas properties are evaluated for impairment and
reduced to fair value whenever events and circumstances indicate
the carrying value exceeds the sum of the undiscounted cash flows.
We estimate the expected net future cash flows of our oil and
natural gas properties using management's expectations of
economically recoverable proved reserves and compare such future
net cash flows to the carrying amount of our oil and natural gas
properties to determine if the carrying amount is recoverable. If
the carrying amount exceeds the estimated undiscounted future cash
flows, we adjust the carrying amount of the oil and natural gas
properties to their fair value. We estimated the fair value of the
proved oil and gas properties and equipment using a discounted cash
flow model, which is a non-recurring Level 3 fair value
measurement. Significant inputs used to determine the fair value
include estimates of (i) future sales prices for oil and gas
based on NYMEX strip prices, (ii) pricing adjustments for
differentials, (iii) production costs, (iv) capital
expenditures, (v) future oil and gas reserves to be recovered
and the timing thereof, and (vi) discount rate. The Company
impaired two proved oil and gas properties which had a total
carrying value of $136,705 to the fair value of $82,806 for the
year ended December 31, 2016. The carrying value was less than the
fair market value of the proved oil and gas properties as of
December 31, 2017.
F-17
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unproved Oil and Gas Properties
Unproved oil and
gas property costs are evaluated for impairment and reduced to fair
value when there is an indication that the carrying costs may not
be fully recoverable. The fair value
of unproved oil and gas properties used in estimating our
recognized impairment loss represents a non-recurring Level 3
measurement. To measure the fair value of unproved
properties, the Company used inputs including, but not limited to,
future development plans, risk weighted potential resource
recovery, remaining lease life and estimated reserve values. The
carrying value was less than the fair market value of the unproved
oil and gas properties as of December 31, 2017 and
2016.
5.
Line of Credit
The
Company has a line of credit with a bank with a borrowing base of
$2,761,632 and $5,500,000 at December 31, 2017 and 2016,
respectively. The amount outstanding under this line of credit was
$2,761,632 at December 31, 2017, and was $6,478,333 at December 31,
2016, which was $978,333 over the borrowing base at December 31,
2016.
The
agreement requires quarterly interest-only payments until maturity
on March 31, 2017. The interest rate is based on a LIBOR or Prime
option. The Prime option provides for the interest rate to be prime
plus a margin ranging between 1.75% and 2.25% and the LIBOR option
to be the 3-month LIBOR rate plus a margin ranging between 2.75%
and 3.25%, both depending on the borrowing base usage. Currently,
we have elected the LIBOR interest rate option in which our
interest rate was approximately 5% and 4% as of December 31, 2017
and 2016, respectively. The commitment fee is .50% of the unused
borrowing base.
The
line of credit provides for certain financial covenants and ratios
which include a current ratio that cannot be less than 1.10:1.00, a
leverage ratio that cannot be more than 3.50:1.00, and an interest
coverage ratio that cannot be less than 3.50:1.00. The Company is
out of compliance with all three ratios as of December 31, 2017 and
2016, and is in technical default of the agreement. The
Company made payments of $3,716,701 toward the loan balance during
the year ended December 31, 2017. Citibank lowered our borrowing
base from $5,500,000 to $2,761,632 on December 29, 2017, which was
equal to our outstanding loan balance at December 31, 2017.
Citibank is in a first lien position on all of our
properties.
In
October 2016, we executed a sixth amendment to the original loan
agreement, which provides for Citibank’s forbearance from
exercising remedies relating to the current defaults including the
principal payment deficiencies. The Forbearance Agreement ran
through January 1, 2018, and required that we make a $500,000 loan
principal pay down by September 30, 2017, and adhere to other
requirements including weekly cash balance reports, quarterly
operating reports, monthly accounts payable reports and that we pay
all associated legal expenses. Furthermore, under the agreement
Citibank may sweep any excess cash balances exceeding a net amount
of $800,000 less equity offering proceeds, which will be applied
towards the outstanding principal balance.
On
December 29, 2017, we executed a seventh amendment to the original
loan agreement and first amendment to the forbearance, which
reduced our borrowing base to our current loan balance of
$2,761,632 and it provided for Citibank’s forbearance from
exercising remedies relating to the current defaults including the
principal payment deficiencies. The Forbearance Agreement ran
through March 31, 2018, and required that we adhere certain
reporting requirements such as weekly cash reports and pay all of
the fees and expenses of the Lender’s counsel invoiced on or
before the effective date. On March 30, 2018, we executed an eighth
amendment to the original loan agreement and second amendment to
the forbearance which extended it to June 30, 2018. The terms of
the second amendment remain the same as under the first amendment
to the forbearance.
F-18
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In
addition to our revolving line of credit with Citibank, N.A., the
Company also has two irrevocable standby letters of credit with
Citibank securing our well plugging liabilities of various operated
wells in the amounts of $25,000 and $30,000. These letters of
credit automatically renew every year and were most recently
renewed in May 2017.
6.
Income Taxes
Our
provision for income taxes comprised the following (expense)
benefit during the years ended December 31:
|
|
2017
|
2016
|
|
Current:
|
|
|
|
Federal
|
$-
|
$-
|
|
State
|
(6,206)
|
-
|
|
Total
current
|
(6,206)
|
-
|
|
|
|
|
|
Deferred:
|
|
|
|
Federal
|
157,227
|
-
|
|
State
|
-
|
-
|
|
Total
deferred
|
157,227
|
-
|
|
|
|
|
|
Total income tax
provision
|
$151,021
|
$-
|
Total
income tax (expense) benefit differed from the amounts computed by
applying the U.S. Federal statutory tax rates and estimated state
rates to pre-tax income for the years ended December 31, 2017 and
2016 as follows:
|
|
2017
|
2016
|
|
Statutory rate
(benefit)
|
(34%)
|
(34%)
|
|
State taxes, net of
federal benefit
|
(1%)
|
(2%)
|
|
Permanent
differences
|
(1%)
|
1%
|
|
Impact of U.S. tax
reform
|
(36%)
|
-
|
|
Change in valuation
allowance on deferred tax assets
|
78%
|
35%
|
|
Effective rate
(benefit)
|
6%
|
(0%)
|
F-19
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Deferred tax assets
and liabilities are the result of temporary differences between the
financial statement carrying values and tax bases of assets and
liabilities. The Company’s deferred tax assets were reduced
in full by a valuation allowance due to our determination that it
is more likely than not that some or all of the deferred tax assets
will not be realized in the future. Significant components of net
deferred tax assets and liabilities are:
|
|
December
31,
|
|
|
|
2017
|
2016
|
|
Deferred tax
assets:
|
|
|
|
Asset retirement
obligation
|
$434,000
|
$569,000
|
|
Allowance for
doubtful accounts
|
57,000
|
87,000
|
|
Stock compensation
and other
|
(1,000)
|
(4,000)
|
|
Alternative minimum
tax credit carryforward
|
-
|
157,000
|
|
Difference in
depreciation, depletion and capitalization methods – oil and
gas properties
|
(161,000)
|
555,000
|
|
Net operating loss
carryforward
|
1,320,000
|
2,216,000
|
|
Total deferred tax
assets
|
1,649,000
|
3,580,000
|
|
Valuation allowance
on deferred tax assets
|
(1,649,000)
|
(3,580,000)
|
|
Total deferred tax
assets, net of valuation allowance
|
-
|
-
|
|
|
|
|
|
Deferred tax
liability:
|
|
|
|
Difference in
depreciation, depletion and capitalization methods – oil and
gas properties
|
-
|
-
|
|
Total deferred tax
liabilities
|
-
|
-
|
|
|
|
|
|
Net deferred tax
liability
|
$-
|
$-
|
Our net
deferred tax assets and liabilities are recorded as
follows:
|
|
2017
|
2016
|
|
Non-current
asset
|
$-
|
$-
|
|
Non-current
liability
|
-
|
-
|
|
Total
|
$-
|
$-
|
The
Company had no material uncertain tax positions as of December 31,
2017 and 2016.
The
decrease in deferred tax assets before the valuation allowance was
primarily due to the federal tax rate decreasing from 34% to 21%
under the Tax Cuts and Jobs Act signed into law in 2017. Also, the
Company had an AMT credit of approximately $157,000 for alternative
minimum tax paid in prior years that will be refundable under the
same tax reform act.
At
December 31, 2017, the Company expects to have net operating loss
carryforwards of approximately $5.6 million which expire at various
dates from December 31, 2035 to 2036. As a result of the net
operating losses, our deferred tax assets exceeded our deferred tax
liabilities. Since it is more likely than not that the tax benefits
will not be utilized, the Company established a valuation allowance
of $1,649,000 and $3,580,000 against our deferred tax assets for
the years ended December 31, 2017 and 2016,
respectively.
F-20
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The
Company’s policy regarding income tax interest and penalties
is to record those items as general and administrative expense.
During the years ended December 31, 2017 and 2016, there were no
significant income tax interest and penalty items in the income
statement, nor as a liability on the balance sheet at December 31,
2017 and 2016.
The
Company files income tax returns in the U.S. federal jurisdiction
and various state jurisdictions. Generally, the Company is no
longer subject to U.S. federal or state income tax examination by
tax authorities for years before 2014. The Company is not currently
involved in any income tax examinations.
7.
Earnings (Loss) Per Share
Basic
earnings per share are computed based on the weighted average
number of shares of common stock outstanding during the year.
Diluted earnings per share take common stock equivalents (such as
options and warrants) into consideration using the treasury stock
method. The Company distributed warrants as a dividend to
stockholders as of the record date, March 23, 2012. The Company had
7,177,010 warrants outstanding with an exercise price of $4.00 at
December 31, 2017 and 2016. The Warrants expired on March 23, 2018.
The dilutive effect of the warrants for the twelve months ended
December 31, 2017 and 2016, is presented below.
|
|
December
31,
|
|
|
|
2017
|
2016
|
|
|
|
|
|
Net income
(loss)
|
$2,666,253
|
$(2,473,147)
|
|
|
|
|
|
Weighted average
common stock outstanding
|
10,656,506
|
9,040,085
|
|
Weighted average
dilutive effect of stock warrants
|
-
|
-
|
|
Dilutive weighted
average shares
|
10,656,506
|
9,040,085
|
|
|
|
|
|
Loss per
share:
|
|
|
|
Basic
|
$0.25
|
$(0.27)
|
|
Diluted
|
$0.25
|
$(0.27)
|
F-21
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8.
Stockholders’ Equity
We
approved a stock warrant dividend of one warrant per one common
share in March 2012. The warrants have an exercise price of $4.00
and are exercisable over 6 years from the record date. Our warrants
were delisted from the NYSE American (formerly NYSE MKT) on
November 17, 2017, and then expired on March 23, 2018. The
following table summarizes the warrant activity for the year ending
December 31, 2017:
|
|
Warrants
|
Weighted
Average Exercise Price
|
Weighted
Average Expected Life (Years)
|
|
|
|
|
|
|
Outstanding,
December 31, 2016
|
7,177,010
|
$4.00
|
1.25
|
|
Issued
|
-
|
-
|
|
|
Exercised
|
-
|
-
|
|
|
Exercised during
temporary modification period
|
-
|
-
|
|
|
Expired
|
-
|
-
|
|
|
Outstanding,
December 31, 2017
|
7,177,010
|
$4.00
|
0.25
|
The
Company entered into an “at will” employment agreement
with Phillip Roberson as President and CFO for a three year period
beginning July 1, 2014. As a signing bonus, Mr. Roberson is
entitled to receive a total of 50,000 shares of common stock, of
which 10,000 shares were immediately vested. Ten thousand shares
were received and vested at each of the six month, twelve month,
eighteen month, and twenty four month anniversary dates of the
commencement date. The fair value of this stock grant was $275,000
of which $13,750 was recognized as non-cash stock compensation
expense during the twelve months ended December 31, 2016. The
signing bonus grant was fully vested on July 1, 2016. Mr. Roberson
will be entitled to receive, as part of his annual compensation, on
his third anniversary date 5,000 shares, on his fourth anniversary
date 6,000 shares, on his fifth anniversary date 7,000 shares, on
his sixth anniversary date 8,000 shares, on his seventh anniversary
date 9,000 shares, and each annual anniversary date thereafter
10,000 shares. Mr. Roberson declined the 5,000 shares he was to
receive on his third anniversary date, July 1, 2017.
On August 12,
2016, the Company entered into a binding Stock and Mineral Purchase
Agreement (the “SMPA”) with HFT Enterprises, LLC (the
“Buyer”) in order to provide liquidity to the Company.
The original closing date of September 30, 2016, was extended to
November 3, 2016, by mutual consent. The Buyer purchased in two
equal tranches, a number of newly-issued shares of common stock of
the Company equal to 19.9% of the total number of issued and
outstanding shares of the Company, as measured on the date of the
Agreement, for a price of $0.45 per share (the shares to be
purchased, the “Shares”). The first tranche was
purchased on November 3, 2016, for gross proceeds of $398,053 paid
in consideration of 884,564 shares of unregistered common stock.
Half of the second tranche was purchased on December 29, 2016, for
gross proceeds of $199,027 paid in consideration of 442,282 shares
of unregistered common stock. The remaining 442,282 shares of the
second tranche were purchased in January 2017 for gross proceeds of
$199,027 paid in consideration of 442,282 shares of unregistered
common stock. Costs incurred by the Company to issue the stock was
$65,937 for the year ended December 31, 2016. The shares are
restricted shares that are also not registered under the Securities
Act of 1933, as amended (the “Securities Act”), and
therefore the Buyer must hold the Shares indefinitely unless they
are registered with the Securities and Exchange Commission and
qualified by state authorities, or an exemption from such
registration and qualification requirements is available. Also, the
Buyer was granted the right to nominate one member of the Board of
Directors.
F-22
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9.
Environmental Issues
We are
engaged in oil and natural gas exploration and production and may
become subject to certain liabilities as they relate to
environmental cleanup of well sites or other environmental
restoration procedures as they relate to the drilling of oil and
natural gas wells and the operation thereof. In our acquisition of
existing or previously drilled well bores, we may not be aware of
what environmental safeguards were taken at the time such wells
were drilled or during such time the wells were operated. Should it
be determined that a liability exists with respect to any
environmental clean up or restoration, the liability to cure such a
violation could fall upon the Company. No claim has been made, nor
are we aware of any liability which we may have, as it relates to
any environmental cleanup, restoration or the violation of any
rules or regulations relating thereto.
10.
Commitments and Contingencies
As of
December 31, 2017 and 2016, we had a $30,000 outstanding standby
letter of credit in favor of the State of Wyoming as a plugging
bond. As of December 31, 2017 and 2016, we had a $25,000
outstanding letter of credit in the favor of the Bureau of Land
Management. Citibank has requested that we leave at least $60,000
in cash in a Citibank account to cover our plugging bond line of
credit since the Company is in technical default on our line of
credit as of December 31, 2017.
In January 2014, the Company entered into a two
year operating lease for office space in Austin, Texas, which was
renewed for another two years until January 31, 2018. On
February 1, 2018, the Company executed an amendment to extend the
lease until July 31, 2018. Rent expense under this lease was
approximately $45,100 and $40,300 for the years ended December 31,
2017 and 2016, respectively. As of December 31, 2017, minimum
future rentals during 2018 on this non-cancelable operating lease
are $25,563.
The
Company entered into an “at will” employment agreement
with Phillip Roberson as President and CFO for a three year period
beginning July 1, 2014, with a beginning base salary of $200,000
annually. Beginning January 1, 2015, the Board of Directors may in
its sole discretion award an annual performance based bonus award
to Mr. Roberson.
At the
October 23, 2015, meeting the Board adopted a measure effective as
of January 1, 2016, to temporarily accept voluntary reductions in
annual retainers for executive and all non-executive directors by a
total of approximately $75,000 per year until such time as economic
conditions shall improve and the Board determines that the
voluntary reductions shall cease. All of these voluntary reductions
shall be retroactively reinstated and payable in the case of (and
only in the case of) a Change of Control Event.
Occasionally, we
are involved in various legal and regulatory proceedings arising in
the normal course of business. Management cannot predict the
outcome of these proceedings with certainty and does not believe
that an adverse result would be material to the Company’s
financial position or results of operations.
F-23
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11.
Oil and Gas Producing Activities
The
following table sets forth the costs incurred for oil and natural
gas property activities of the Company:
|
|
Years Ended
December 31,
|
|
|
|
2017
|
2016
|
|
Costs incurred in
oil and natural gas producing activities:
|
|
|
|
Acquisition of
unproved properties
|
$-
|
$-
|
|
Acquisition of
proved properties
|
-
|
-
|
|
Exploration
costs
|
-
|
-
|
|
Development
costs
|
160,914
|
162,001
|
|
Total costs
incurred
|
$160,914
|
$162,001
|
The
following table includes certain information regarding the results
of operations for oil and natural gas producing
activities:
|
|
Years Ended
December 31,
|
|
|
|
2017
|
2016
|
|
Revenues
|
$2,942,660
|
$2,696,857
|
|
Expenses
|
|
|
|
Production
expense
|
2,181,377
|
2,509,206
|
|
Depletion and
depreciation
|
698,337
|
1,103,340
|
|
Impairment of oil
and natural gas properties
|
-
|
53,899
|
|
Accretion of
discount on asset retirement obligations
|
105,000
|
109,000
|
|
Total
expenses
|
2,984,714
|
3,775,445
|
|
Loss before income
taxes
|
(42,054)
|
(1,078,588)
|
|
Income tax benefit,
net of valuation allowance (1)
|
-
|
-
|
|
Results of
operations for oil and natural gas producing activities (excluding
corporate overhead and interest costs)
|
$(42,054)
|
$(1,078,588)
|
(1) Reflects the
Company’s effective tax rate.
F-24
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12.
Disclosures About Oil and Gas Producing Activities
(Unaudited)
The
following table summarizes changes in the estimates of the
Company’s net interest in total proved reserves of crude oil
and condensate and natural gas and liquids, all of which are
domestic reserves. There can be no assurance that such estimates
will not be materially revised in subsequent periods.
|
|
Oil
(Barrels)
|
Gas
(MCF)
|
|
|
|
|
|
Balance, January 1,
2016
|
405,773
|
787,942
|
|
Revisions of
previous estimates
|
68,592
|
88,490
|
|
Extensions and
discoveries
|
80,742
|
-
|
|
Sale of
reserves
|
-
|
-
|
|
Purchase of
minerals in place
|
-
|
-
|
|
Production
|
(64,881)
|
(119,920)
|
|
Balance, December
31, 2016
|
490,226
|
756,512
|
|
Revisions of
previous estimates
|
33,784
|
86,221
|
|
Extensions and
discoveries
|
-
|
-
|
|
Sale of
reserves
|
(42,085)
|
(19,657)
|
|
Purchase of
minerals in place
|
-
|
-
|
|
Production
|
(53,913)
|
(111,816)
|
|
Balance, December
31, 2017
|
428,012
|
711,260
|
|
|
|
|
|
Proved developed
reserves, December 31, 2017
|
428,012
|
711,260
|
|
Proved developed
reserves, December 31, 2016
|
490,226
|
756,512
|
Proved
oil and natural gas reserves are the estimated quantities of crude
oil, condensate, natural gas and natural gas liquids which
geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved developed
oil and natural gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and
operating methods. The above estimated net interests in proved
reserves are based upon subjective engineering judgments and may be
affected by the limitations inherent in such estimation. The
process of estimating reserves is subject to continual revision as
additional information becomes available as a result of drilling,
testing, reservoir studies and production history, and market
prices for oil and natural gas. Significant fluctuations in market
prices have a direct impact on recoverability and will result in
changes in estimated recoverable reserves without regard to actual
increases or decreases in reserves in place.
Year Ended December 31, 2016
The
average natural gas price used in our proved reserves estimate at
December 31, 2016, was $2.96 per Mcf. The average oil price used in
our proved reserves estimate at December 31, 2016, was $35.26 per
barrel. We did not drill any new wells, or purchase or sell any
reserves during the year ended December 31, 2016.
F-25
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Ended December 31, 2017
The
average natural gas price used in our proved reserves estimate at
December 31, 2017, was $2.98 per Mcf. The average oil price used in
our proved reserves estimate at December 31, 2017, was $47.03 per
barrel. We did not drill any new wells or purchase any reserves
during the year ended December 31, 2017. We sold one unproved
property, one non-producing property, and three producing
properties.
Standardized Measure of Discounted Future Net Cash
Flows
The
standardized measure of discounted future net cash flows at
December 31, 2017 and 2016, relating to proved oil and natural gas
reserves is set forth below. The assumptions used to compute the
standardized measure are those prescribed by the Financial
Accounting Standards Board and, as such, do not necessarily reflect
our expectations of actual revenues to be derived from those
reserves nor their present worth. The limitations inherent in the
reserve quantity estimation process are equally applicable to the
standardized measure computations since these estimates are the
basis for the valuation process.
The
standardized measure of discounted future net cash flows relating
to proved oil and natural gas reserves and the changes in
standardized measure of discounted future net cash flows relating
to proved oil and natural gas reserves were prepared in accordance
with prescribed accounting and SEC standards. Future cash inflows
were computed by applying the unweighted, arithmetic average of the
closing price on the first day of each month for the 12-month
period prior to December 31, 2017 and 2016, to estimated future
production. Future production and development costs are computed by
estimating the expenditures to be incurred in developing and
producing the proved oil and natural gas reserves at year end,
based on year-end costs and assuming continuation of existing
economic conditions.
Future income tax
expenses are calculated by applying appropriate year-end tax rates
to future pre-tax net cash flows relating to proved oil and natural
gas reserves, less the tax basis of properties involved. Future
income tax expenses give effect to permanent differences, tax
credits and loss carryforwards relating to the proved oil and
natural gas reserves. Future net cash flows are discounted at a
rate of 10% annually to derive the standardized measure of
discounted future net cash flows. This calculation procedure does
not necessarily result in an estimate of the fair market value of
our oil and natural gas properties.
|
|
Years Ended
December 31,
|
|
|
|
(in
thousands)
|
|
|
|
2017
|
2016
|
|
|
|
|
|
Future cash
inflows
|
$24,866
|
$21,081
|
|
Future production
costs
|
(13,105)
|
(11,418)
|
|
Future development
cost
|
(86)
|
(131)
|
|
Future income
taxes
|
(1,848)
|
(105)
|
|
|
|
|
|
Future net cash
flows
|
9,827
|
9,427
|
|
10% annual
discount
|
(4,202)
|
(3,926)
|
|
|
|
|
|
Standardized
measure of discounted future net cash flows
|
$5,625
|
$5,501
|
F-26
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The
following are the principal sources of change in the standardized
measure of discounted future net cash flows, in
thousands:
|
|
Years Ended
December 31,
|
|
|
|
2017
|
2016
|
|
Balance, beginning
of year
|
$5,501
|
$7,011
|
|
Sales of oil and
natural gas produced, net of production costs
|
(696)
|
(188)
|
|
Sale of
reserves
|
(573)
|
-
|
|
Extensions and
discoveries
|
-
|
740
|
|
Net changes in
prices and production costs
|
1,820
|
(3,149)
|
|
Net changes in
future development costs
|
41
|
(19)
|
|
Revisions and other
changes
|
139
|
434
|
|
Accretion of
discount
|
557
|
705
|
|
Net change in
income taxes
|
(1,164)
|
(33)
|
|
Balance, end of
year
|
$5,625
|
$5,501
|
13.
Subsequent Events (unaudited)
On
January 12, 2018, one of our purchasers, First River Energy, LLC
(“FEL’) declared bankruptcy and we filed a proof of
claim of approximately $27,000 for December crude oil production
that FEL did not pay us for, although the crude oil was picked up
by FEL. We believe that we will be reimbursed for these funds
through the bankruptcy process and we have accrued a receivable for
this amount.
On
February 26, 2018, the Company was served by Trivista Operating,
LLC, which is controlled by one of our major shareholders,
Natale Rea (2013) Trust, for
the non-payment of approximately $107,000 in outstanding Joint
Interest Billings plus attorney fees and court costs. The Company
has hired its own counsel and has answered this suit. The amounts
under this claim are represented in our currently accrued lease
operating expenses and accounts payable.
* * * *
* * *
F-27
|
ITEM
9
|
CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
|
None.
ITEM 9A.
CONTROLS AND PROCEDURES
|
a)
|
Our Principal Executive Officer, Roger D. Bryant, and our Principal
Financial Officer, Phillip H. Roberson, have established and
are currently maintaining disclosure controls and procedures
for the Company. The disclosure controls and procedures have been
designed to provide reasonable assurance that the information
required to be disclosed by the Company in reports that it files
under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the rules and forms
of the SEC and to ensure that information required to be disclosed
by the Company is accumulated and communicated to the Company's
management as appropriate to allow timely decisions regarding
required disclosure.
The
Principal Executive Officer and Principal Financial Officer
conducted a review and evaluation of the effectiveness of the
Company's disclosure controls and procedures and have concluded,
based on their evaluation as of the end of the period covered by
this Report, that our disclosure controls and procedures are
effective to provide reasonable assurance that information required
to be disclosed in the reports that we file or submit under the
Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the Commission’s rules and
forms and to ensure that the information required to be disclosed
by the Company is accumulated and communicated to management,
including our principal executive officer and our principal
financial officer, to allow timely decisions regarding required
disclosure.
|
|
b)
|
There
has been no change in our internal control over financial reporting
during the fourth quarter ended December 31, 2017, that has
materially affected, or is reasonably likely to materially affect,
our internal control over financial reporting.
|
Our
principal executive and financial officer do not expect that our
disclosure controls or internal controls will prevent all error and
all fraud. Although our disclosure controls and procedures were
designed to provide reasonable assurance of achieving their
objectives and our principal executive and financial officer have
determined that our disclosure controls and procedures are
effective at doing so, a control system, no matter how well
conceived and operated, can provide only reasonable, not absolute
assurance that the objectives of the system are met. Further, the
design of a control system must reflect the fact that
there
are resource constraints, and the benefits of controls must be
considered relative to their costs. Because of the inherent
limitations in all control systems, no evaluation of controls can
provide absolute assurance that all control issues and instances of
fraud, if any, within the Company have been detected. These
inherent limitations include the realities that judgments in
decision-making can be faulty, and that breakdowns can occur
because of simple error or mistake. Additionally, controls can be
circumvented if there exists in an individual a desire to do so.
There can be no assurance that any design will succeed in achieving
its stated goals under all potential future
conditions.
46
Management’s Report on Internal Control Over Financial
Reporting
Management
is responsible for establishing and maintaining adequate internal
control over financial reporting for the Company. Internal control
over financial reporting refers to the process designed by, or
under the supervision of, our Principal Executive Officer and
Principal Financial Officer, and effected by our Board of
Directors, management and other personnel, to provide reasonable
assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in
accordance with generally accepted accounting principles, and
includes those policies and procedures that:
1)
Pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of
the assets of the Company;
2)
Provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that
receipts and expenditures of the Company are being made only in
accordance with authorizations of management and directors of the
Company; and,
3)
Provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of the
Company’s assets that could have a material effect on the
Company’s financial statements.
Because
of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods
are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
Management
has used the framework set forth in the report entitled
“Internal Control – Integrated Framework”
published by the Committee of Sponsoring Organizations of the
Treadway Commission to evaluate the effectiveness of the
Company’s internal control over financial reporting.
Management has concluded that the Company’s internal control
over financial reporting was effective as of the end of the most
recent fiscal year.
This
annual report does not include an attestation report of the
Company’s independent registered public accounting firm
regarding internal control over financial reporting.
Management’s report was not subject to attestation by the
Company’s independent registered public accounting firm
pursuant to rules of the Securities and Exchange Commission that
permit the Company to provide only management’s report in
this Form 10-K.
ITEM
9B.
OTHER INFORMATION
None.
47
PART III
|
ITEM 10
|
DIRECTORS,
EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
|
|
(a)
|
Identification
of Directors and Executive Officers. The following table sets forth
the names and ages of the Directors and Executive Officers of the
Company, all positions and offices with the Company held by such
person, and the time during which each such person has
served:
|
|
Name
|
|
Age
|
|
Position with
Company
|
|
Period
Served
|
|
Roger
D. Bryant
|
|
75
|
|
Principal
Executive Officer,
|
|
June 9,
2013-present
|
|
|
|
|
|
Director
|
|
July
1997-present
|
|
Phillip
H. Roberson
|
|
49
|
|
President,
|
|
December
2013-present
|
|
|
|
|
|
Principal
Financial Officer,
|
|
July
2013-present
|
|
|
|
|
|
Director
|
|
November
11, 2014 - present
|
|
Karl W.
Reimers
|
|
76
|
|
Director
|
|
October
2004-present
|
|
Dan
Robinson
|
|
70
|
|
Director
|
|
August
2004-present
|
|
Nancy
Stephenson
|
|
64
|
|
Director
|
|
October
2012 - present
|
Mr.
Bryant serves as Chairman of the Board of the Corporation, and as
its principal executive. He has been a Director of the Company
since July 1997. For more than thirty years, Mr. Bryant has held
senior management positions with public and private companies in a
number of different industries. He is currently a Founder and
Partner of Co-Partners, LLC, a business consulting firm. Prior
positions include Chief Executive Officer and Chairman of Canmax,
Inc., a publicly traded software development company, President of
Network Data Corporation, President of Dresser Industries, Inc.,
Wayne Division, President of Schlumberger Limited, Retail Petroleum
Systems Division, U.S.A., and President of Autogas Systems, Inc.,
the developer of “Pay-at-the-Pump” technology for the
retail petroleum industry. Mr. Bryant holds a Bachelor of Science
degree in Electrical Engineering from the University of Alabama,
and has served on the Board of Directors of more than ten private
and public companies. He currently serves on the Board of Directors
of two private companies, HOBI International, Inc. and Leopard
Mobility, Inc., both in the electronics remanufacturing and
distribution business.
Mr.
Roberson, age 49, was engaged to take operational control of the
business on June 14, 2013. He was named Principal Operating Officer
and Principal Financial Officer on July 1, 2013. Prior to joining
FieldPoint, he was founder of AEG Operating LLC, an independent oil
and gas exploration company, where he was instrumental in the
funding, acquisition and day to operations of the firm’s
operated and non-operated properties. Previously, he served as a
director of Energy Investment Banking with Tejas Securities, Inc.
where he assisted Exploration & Production and Energy Service
companies with debt & equity offerings. Until it was acquired
by Tejas Securities, Mr. Roberson was an Equity Analyst with
Arabella Securities, LLC, covering Energy and Special Situation
companies. Mr. Roberson received a Bachelor of Business
Administration in Finance from the University of Texas at Austin
and is a licensed Certified Public Accountant.
Mr.
Reimers, age 76, has served as a director of the Company since
October 2004. Mr. Reimers has held the position of President and
CFO of B.A.G. Corp. from 1993 until his retirement in 2010. He
served as Vice President and CFO of Supreme Beef Company from 1989
to 1993. He also held the position of Vice President of Accounting
at OKC Corp., a NYSE listed oil and gas company from 1975 to 1989.
He was employed by Peat, Marwick, Mitchell, Certified Public
Accountants, from 1973 to 1975, and he holds an MBA from the
University of Texas at Arlington.
48
Mr.
Robinson, age 70, has served as a director of the Company since
August 2004. He has held the position of President and Chief
Executive Officer of Placid Refining Company LLC from December 1994
to the present. Prior to his current position, he served in many
capacities with Placid Oil Company beginning in March 1975,
including the roles of Project Engineer, Manager of Refinery
Operations, Assistant Secretary, Assistant Treasurer, Secretary,
and Treasurer. Before beginning his 42 year oil and gas career he
was briefly employed as a commercial credit analyst at First
National Bank in Dallas. Mr. Robinson received a BS degree in
Mechanical Engineering in 1971 and an MBA degree in Finance in
1973, both from the University of Wisconsin. He currently sits on
the Board of Directors of the American Fuel & Petrochemical
Manufacturers (AFPM).
Nancy
Stephenson, age 64, has been a Director of the Company since
October 2012. From August 2011 to August 2012 she served as
Chief Accounting Officer, Treasurer and Secretary of Cross Border
Resources Inc. (XBOR) and served as Assistant Controller at Forge
Energy, LLC, a private company, from January 2014 through March
2015. Ms. Stephenson is semi-retired and does occasional
consulting engagements. Ms. Stephenson has over 30 years of
accounting experience, primarily in publicly traded companies in
the energy business. From March 2003 to February 2010, she
served as Compliance Reporting Manager for TXCO Resources Inc.
(TXCO). For both XBOR and TXCO she prepared financial statements
and was responsible for periodic reporting compliance with the SEC.
Since March 2010, she has provided consulting services relating to
periodic reporting with the SEC on a project basis for various
companies. Ms. Stephenson holds a BBA in Accounting from the
University of Houston and is a Certified Public
Accountant.
No
family relationship exists between any director or executive
officer.
There
are no material proceedings to which any director, officer or
affiliate of the Company, any owner of record or beneficially of
more than five percent (5%) of any class of voting securities of
the Company, or any associate of any such director, officer,
affiliate of the Company, or security holder is a party adverse to
the Company or any of its subsidiaries or has a material interest
adverse to the Company or any of its subsidiaries.
During
the last ten (10) years no director or officer of the Company
has:
|
|
a.
|
had any
bankruptcy petition filed by or against any business of which such
person was a general partner or executive officer either at the
time of the bankruptcy or within two years prior to that
time;
|
|
|
|
|
|
|
b.
|
been
convicted in a criminal proceeding or subject to a pending criminal
proceeding;
|
|
|
|
|
|
|
c.
|
been
subject to any order, judgment, or decree, not subsequently
reversed, suspended or vacated, of any court of competent
jurisdiction, permanently or temporarily enjoining, barring,
suspending or otherwise limiting his involvement in any type of
business, securities or banking activities; or
|
|
|
|
|
|
|
d.
|
been
found by a court of competent jurisdiction in a civil action, the
Commission or the Commodity Futures Trading Commission to have
violated a federal or state securities or commodities law, and the
judgment has not been reversed, suspended, or vacated.
|
49
Any
transactions between the Company and its officers, directors,
principal shareholders, or other affiliates have been and will be
on terms no less favorable to the Company than the Board of
Directors believes could be obtained from unaffiliated third
parties on an arms-length basis and will be approved by a majority
of the Company's independent, outside disinterested
directors.
Meetings and Committees of the Board of Directors
a. Meetings
of the Board of Directors
During
the fiscal year ended December 31, 2017, seven meetings of the
Board of Directors were held, including regularly scheduled and
special meetings, each of which were attended by all of the
directors. Meetings are conducted either in person or by telephone
conference.
At the
December 6, 2013, meeting, the Board approved the Compensation
Committee's recommendation to restructure Board compensation
effective for 2014. The structure increased the fee for in-person
meetings to $1,000 and provides for fees to compensate committee
chairmen. Each board member received approximately $39,500 for
their service during 2014. Roger Bryant was paid $10,000 per month
plus meeting fees as Executive Chairman. Each board member received
approximately $27,000 for their service during 2015 and Roger
Bryant was paid $91,000 as Executive Chairman. At the October 23,
2015, meeting the Board reaffirmed and ratified its previously
adopted action to provide annual cash retainers of $120,000 per
year for Roger Bryant, and $30,000 per year for all non-executive
directors (which shall be in addition to Committee fees), and
$1,000 for each in-person meeting effective January 1, 2016.
However, it also adopted a measure to temporarily accept a
voluntary reduction in Roger Bryant's annual retainer to $90,000
per year, and to temporarily accept a voluntary reduction of the
annual cash retainer to $15,000 for all non-executive directors,
and to temporarily accept a voluntary reduction to $500 per
in-person meeting until such time as economic conditions shall
improve, provided that each and all of these voluntary reductions
shall be retroactively reinstated and payable in the case of (and
only in the case of) a Change of Control Event. All voluntary
reductions were temporarily effective as of January 1, 2016, and
shall continue until such time as the Board determines that they
shall cease.
b. Committees
The
Board appoints committees to help carry out its duties. In
particular, Board committees work on key issues in greater detail
than would be possible at full Board meetings. Each committee
reviews the result of its meetings with the full
Board.
During
the year ended December 31, 2017, the Board had a standing Audit
Committee, a standing Compensation Committee, and a standing
Nomination Committee.
50
Audit Committee
The
Audit Committee was composed of the following
directors:
Nancy
Stephenson, Chairperson
Karl W.
Reimers
Dan
Robinson
The
Board of Directors has determined that Messrs. Reimers, Robinson,
and Ms. Stephenson are "independent" within the meaning of the NYSE
MKT, LLC's listing standards and Item 407(a) of Regulation S-K. For
this purpose, an Audit Committee member is deemed to be independent
if he or she does not possess any vested interests related to those
of management and does not have any financial, family or other
material personal ties to management. Karl Reimers and Nancy
Stephenson, each a member of the Audit Committee, qualify as an
"audit committee financial expert" within the meaning of Item
407(d)(5) of Regulation S-K.
During
the fiscal year ended December 31, 2017, the Audit Committee had
four meetings. The committee is responsible for accounting and
internal control matters. The Audit Committee:
|
|
-
|
reviews
with management, the external consultants and the independent
auditors policies and procedures with respect to internal
controls;
|
|
|
|
|
|
|
-
|
reviews
significant accounting matters;
|
|
|
|
|
|
|
-
|
approves
any significant changes in accounting principles of financial
reporting practices;
|
|
|
|
|
|
|
-
|
reviews
independent auditor services; and
|
|
|
|
|
|
|
-
|
recommends
to the Board of Directors the firm of independent auditors to audit
our consolidated financial statements.
|
In
addition to its regular activities, the committee is available to
meet with the independent accountants, external consultants
whenever a special situation arises.
The
Audit Committee of the Board of Directors has adopted a written
charter, which has been previously filed with the
Commission.
Audit Committee Report
The
Audit Committee has reviewed and discussed the audited financial
statements with management and with Moss Adams LLP and the matters
required to be discussed by AU Section 380. The Audit Committee has
received the written disclosures and the letter from Moss Adams LLP
required by Independence Standards Board Standard No. 1 and has
discussed with them their independence. Based on the review and
discussions referred to above, the Audit Committee has recommended
to the Board of Directors that the audited financial statements be
included in the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 2017, for filing with the
Commission.
51
By the Audit Committee
Nancy Stephenson
Karl Reimers
Dan Robinson
Compensation Advisory Committee
The
Compensation Advisory Committee is currently composed of the
following directors:
Dan
Robinson, Chairman
Karl
Reimers
Nancy
Stephenson
The
Board of Directors has determined that Messrs. Robinson, Reimers
and Stephenson are "independent" within the meaning of the NYSE
MKT, LLC's listing standards and Item 407(a) of Regulation S-K. For
this purpose, a Compensation Committee member is deemed to be
independent if he does not possess any vested interests related to
those of management and does not have any financial, family or
other material personal ties to management.
During
the fiscal year ended December 31, 2017, the Compensation Advisory
Committee had one meeting. The Compensation Advisory
Committee:
|
|
-
|
Recommends
to the Board of Directors the compensation and cash bonus
opportunities based on the achievement of objectives set by the
Compensation Advisory Committee with respect to our Chairman of the
Board and President, our Chief Executive Officer and the other
executive officers;
|
|
|
|
|
|
|
-
|
administers
our compensation plans for the same executives;
|
|
|
|
|
|
|
-
|
determines
equity compensation for all employees;
|
|
|
|
|
|
|
-
|
reviews
and approves the cash compensation and bonus objectives for the
executive officers; and
|
|
|
|
|
|
|
-
|
reviews
various matters relating to employee compensation and
benefits.
|
Nomination Committee
The
Nomination Committee was composed of the following
directors:
Karl
Reimers, Chairman
Nancy
Stephenson
Dan
Robinson
52
The
Board of Directors has determined that Mr. Reimers, Mrs. Stephenson
and Mr. Robinson are “independent” within the meaning
of the NYSE MKT, LLC's listing standards and Item 407(a) of
Regulation S-K. For this purpose, a director is deemed to be
independent if he does not possess any vested interests related to
those of management and does not have any financial, family or
other material personal ties to management. The committee had one
meeting in 2017.
The
Board of Directors has not adopted a policy with regard to the
consideration of any director candidates recommended by security
holders, since to date the Board has not received from any security
holder a director nominee recommendation. The Board of Directors
will consider candidates recommended by security holders in the
future. Security holders wishing to recommend a director nominee
for consideration should contact Mr. Phillip H. Roberson,
President, Chief Operating Officer and Chief Financial Officer, at
the Company's principal executive offices located in Austin, Texas
and provide to Mr. Roberson, in writing, the recommended director
nominee's professional resume covering all activities during the
past five years, the information required by Item 401 of Regulation
S-X, and a statement of the reasons why the security holder is
making the recommendation. Such recommendation must be received by
year end for consideration in the next year’s
elections.
The
Board of Directors believes that any director nominee must possess
significant experience in business and/or financial matters as well
as a particular interest in the Company's activities.
All
director nominees identified in this proxy statement were
recommended by our President and Chief Financial Officer and
unanimously approved by the Board of Directors.
Shareholder Communications
Any
shareholder of the Company wishing to communicate to the Board of
Directors may do so by sending written communication to the Board
of Directors to the attention of Mr. Roger Bryant, Principal
Executive Officer, or Mr. Phillip Roberson, Chief Financial
Officer, at the principal executive offices of the Company. The
Board of Directors will consider any such written communication at
its next regularly scheduled meeting.
Any
transactions between the Company and its officers, directors,
principal shareholders, or other affiliates have been and will be
on terms no less favorable to the Company than could be obtained
from unaffiliated third parties on an arms-length basis and will be
approved by a majority of the Company's independent, outside
disinterested directors.
Code of Ethics
Our
Board of Directors adopted a Code of Business Conduct and Ethics
for all of our directors, officers and employees during the fiscal
year ended December 31, 2003. Our Code of Business Conduct and
Ethics can be found at our website address: http://www.fppcorp.com. We will
provide to any person without charge, upon request, a copy of our
Code of Business Conduct and Ethics. Such request should be made in
writing and addressed to Investor Relations, FieldPoint Petroleum
Corporation, 609 Castle Ridge Road, Suite 335, Austin, Texas 78746.
Further, our Code of Business Conduct and Ethics is filed as an
exhibit to the Company’s Annual Report on Form 10-KSB for the
fiscal year ending December 31, 2003.
53
COMPLIANCE WITH SECTION 16(a) OF THE SECURITIES EXCHANGE
ACT
Section
16 (a) of the Securities Exchange Act of 1934, as amended, requires
the Company's executive officers, directors and persons who own
more than ten percent of the Common Stock (collectively, "Reporting
Persons") to file initial reports of ownership and changes of
ownership of the Common Stock with the SEC and the NYSE MKT.
Reporting Persons are required to furnish the Company with copies
of all forms that they file under Section 16(a). Based solely upon
our search of publicly available information or information
provided to the Company from Reporting Persons, during the two
years ended December 31, 2017, the Company is not aware of any
failure on the part of any Reporting Persons to timely file reports
required pursuant to Section 16(a).
ITEM 11 EXECUTIVE
COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
Introduction. This Compensation
Discussion and Analysis (“CD&A”) provides an
overview of the Company’s executive compensation program
together with a description of the material factors underlying the
decisions which resulted in the compensation provided for 2017 to
the Company’s “Named Executive Officers” (or
“NEOs”), as presented in the tables which follow this
CD&A. The following discussion and analysis contains statements
regarding future individual and Company performance targets and
goals. These targets and goals are disclosed in the limited context
of the Company’s compensation programs and should not be
understood to be statements of
management’s expectations or estimates of financial results
or other guidance. The Company specifically cautions investors not
to apply these statements to other contexts.
Compensation Committee. The
Compensation Committee (the “Committee”) of the Board
of Directors is composed of three non-employee directors, all of
whom are independent under the guidelines of the NYSE MKT listing
standards. The current Committee members are Dan Robinson, Karl
Reimers and Nancy Stephenson. The Committee has responsibility for
determining and implementing the Company’s philosophy with
respect to executive compensation. To implement this philosophy,
the Committee oversees the establishment and administration of the
Company’s executive compensation program.
Compensation Philosophy and Objectives. The guiding principle of the Committee’s
executive compensation philosophy is that the executive
compensation program should enable the Company to attract, retain
and motivate a team of highly qualified executives who will create
long-term value for the shareholders. To achieve this objective,
the Committee has developed an executive compensation program that
is ownership-oriented and that rewards the attainment of specific
annual, long-term and strategic goals that will result in
improvement in total shareholder return. To that end, the Committee
believes that the executive compensation program should include
both cash and equity-based compensation that rewards specific
performance. In addition, the Committee continually monitors the
effectiveness of the program to ensure that the compensation
provided to executives remains competitive relative to the
compensation paid to executives in a peer group comprised of select
container industry and other manufacturing companies. The Committee
annually evaluates the components of the compensation program as
well as the desired mix of compensation among these components. The
Committee believes that a substantial portion of the compensation
paid to the Company’s NEOs should be at risk, contingent on
the Company’s operating and market performance. Consistent
with this philosophy, the Committee will continue to place
significant emphasis on stock-based compensation and performance
measures, in an effort to more closely align compensation with
shareholder interests and to increase executives’ focus on
the Company’s long-term performance.
54
Committee Process. The
Committee meets as often as necessary to perform its duties and
responsibilities. The Committee usually meets with the Executive
Chairman and the President and CFO. In addition, the Committee
periodically meets in executive session without
management.
The Committee’s meeting agenda is normally established by the
Committee Chairperson in consultation with the Executive Chairman
and the President and CFO. Committee members receive and review
materials in advance of each meeting. Depending on the meeting’s agenda, such materials may
include: financial reports regarding the Company’s
performance, reports on achievement of individual and corporate
objectives, reports detailing executives’ stock ownership and
options, tally sheets setting forth total compensation and
information regarding the compensation programs and levels of
certain peer group companies.
Role of Executive Officers in Compensation Decisions.
The Committee makes all compensation
decisions for the NEOs. Decisions regarding the compensation of
other employees are made by the Executive Chairman and the
President and CFO in consultation with the Committee. In this
regard, the NEOs provide the Committee evaluations of executive
performance, business goals and objectives and recommendations
regarding salary levels and equity awards.
Market-Based Compensation Strategy. The Committee adopted the following market-based
compensation strategy:
●
Pay levels are evaluated and calibrated relative to other companies
of comparable size operating in the oil and gas exploration
business (the “Peer Group”) as the primary market
reference point. In addition, general industry data is reviewed as
an additional market reference and to ensure robust competitive
data.
●
Target total direct compensation (target total cash compensation
plus the annualized expected value of long-term incentives) levels
for NEOs are calibrated relative to the Peer Group.
●
Base salary and target total cash compensation levels (base salary
plus target annual incentive) for NEOs are calibrated to the Peer
Group.
●
The long-term incentive component of the executive compensation
program is discretionary and viewed in light of the target total
direct compensation level.
The Committee retains discretion, however, to vary compensation
above or below the targeted percentile based upon each NEO’s
experience, responsibilities and performance.
55
Total Direct Compensation
Our objective is to target total direct compensation, consisting of
cash salary, cash bonus and long term equity compensation at levels
consistent with the surveyed companies, if specified corporate and
business unit performance metrics and individual performance
objectives are met. We selected this target for compensation to
remain competitive in attracting and retaining talented executives.
Many of our competitors are significantly larger and have financial
resources greater than our own. The competition for experienced,
technically proficient executive talent in the oil and gas industry
is currently particularly acute, as companies seek to draw from a
limited pool of such executives to explore for and develop
hydrocarbons that increasingly are in more remote areas and are
technologically more difficult to access.
Components of Compensation. For
the years ended December 31, 2016 and 2017, the largest component
of compensation for the Officers of the Company was base salary. We
did provide additional compensation in the form of a stock bonus to
the President/CFO in 2016. Mr. Roberson was entitled to a stock
bonus of 5,000 shares in July 2017 but declined the
bonus.
Base Salary. The Company
provides the NEOs with base salaries to compensate them for
services rendered during the year. The Committee believes that
competitive salaries must be paid in order to attract and retain
high quality executives. The Committee reviews the NEO’s
salaries at the end of each year, with any adjustments to base
salary becoming effective on January 1 of the succeeding
year.
In determining base salary level for executive officers, the
committee considers the following qualitative and quantitative
factors:
●
job level and responsibilities,
●
relevant experience,
●
individual performance,
●
recent corporate performance.
We review base salaries annually, but we do not necessarily award
salary increases each year. From time to time base salaries may be
adjusted other than as a result of an annual review, in order to
address competitive pressures or in connection with a
promotion.
Base salaries paid to the NEOs are deductible for federal income
tax purposes except to the extent that the executive’s
aggregate compensation which is subject to Section 162(m) of the
Internal Revenue Code (the “Code”) exceeds $1
million.
The Company entered into an “at will” employment
agreement with Phillip Roberson as President and CFO for a three
year period beginning July 1, 2014. As a signing bonus, Mr.
Roberson is entitled to receive a total of 50,000 shares of common
stock, of which 10,000 shares were immediately vested. Ten thousand
shares will be received and vested at each of the six month, twelve
month, eighteen month, and twenty four month anniversary dates of
the commencement date. Once the signing bonus grant has been fully
vested and paid, Mr. Roberson will be entitled to receive, as part
of his annual compensation, on his third anniversary date 5,000
shares, which he declined in 2017, on his fourth anniversary date
6,000 shares, on his fifth anniversary date 7,000 shares, on his
sixth anniversary date 8,000 shares, on his seventh anniversary
date 9,000 shares, and each annual anniversary date thereafter
10,000 shares. The Board of Directors may in its sole discretion
award an annual Performance Based Bonus Award to Mr.
Roberson.
56
The
following tables and discussion set forth information with respect
to all plan and non-plan compensation awarded to, earned by or paid
to the Company's four (4) most highly compensated executive
officers, for all services rendered in all capacities to the
Company and its subsidiaries for each of the Company's last three
(3) completed fiscal years; provided, however, that no disclosure
has been made for any executive officer, other than the CEO, whose
total annual salary and bonus does not exceed
$100,000.
SUMMARY
COMPENSATION TABLE
|
Name
and
Principal
Position
|
|
Year
|
|
Salary
($)
|
Bonus
|
Stock
Awards
|
Options
Awards
|
Non
equity
Incentive
Plan
Compensa
-tion
|
Nonqualified
Deferred
Compensation
Earnings
|
All
Other
Compensa-
tion
|
Total
|
|
Phillip H.
Roberson, President, and CFO
|
|
2017
|
|
$200,000
|
$-
|
$-
|
-
|
-
|
-
|
$6,000(1)
|
$206,000
|
|
Phillip H.
Roberson, President, and CFO
|
|
2016
|
|
$200,000
|
$-
|
$12,800
|
-
|
-
|
-
|
$6,186(1)
|
$218,986
|
|
Phillip H.
Roberson, President, and CFO
|
|
2015
|
|
$200,000
|
$-
|
$30,300
|
-
|
-
|
-
|
$6,000(1)
|
$236,300
|
(1)
Automobile
allowance
57
The
following table sets forth information concerning unexercised
options, stock that has not vested and equity incentive plan awards
for each named executive officer outstanding as of the end of the
most recently completed fiscal year:
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END TABLE
|
|
Option
Awards
|
Stock
Awards
|
||||||||
|
Name
|
|
Number
of
Securities
Underlying
Unexercised
Options
Exercisable
|
Number
of
Securities
Underlying
Unexercised
Options
Unexercisable
|
Equity
Incentive
Plan
Awards;
Number
of
Securities
Underlying
Unexercised
Unearned
Options
|
Option
Exercise
Price
|
Option
Exercise
Date
|
Number
of
Shares
or
Units
of
Stock
That
Have
Not
Vested
|
Market
Value
of
Shares
of
Units
That
Have
Not
Vested
|
Equity
Incentive
Plan
Awards;
Number
of
Unearned
Shares,
Units
or
Other
Rights
That
Have
Not
Vested
|
Equity
Incentive
Plan
Awards;
Market
or
Payout
Value
of
Unearned
Shares,
Units
or
Other
Rights
That
Have
Not
Vested
|
|
Roger
Bryant
|
|
- 0 -
|
- 0 -
|
-
|
-
|
-
|
- 0 -
|
-
|
-
|
-
|
|
Phillip
Roberson
|
|
- 0 -
|
- 0 -
|
-
|
-
|
-
|
- 0 -
|
- 0 -
|
-
|
-
|
The
following table sets forth information concerning compensation paid
to the Company’s directors during the most recently completed
fiscal year:
DIRECTOR COMPENSATION TABLE
|
Name
|
Fees
Earned
or
Paid
in
Cash
|
Stock
Awards
|
Option
Awards
|
Non-Equity
Incentive
Plan
Compensation
|
Nonqualified
Deferred
Compensation
Earnings
|
All
Other
Compensation
|
Total
|
|
Roger
Bryant
|
$91,000
|
-
|
-
|
-
|
-
|
-
|
$91,000
|
|
Karl
Reimers
|
$26,000
|
-
|
-
|
-
|
-
|
-
|
$26,000
|
|
Dan
Robinson
|
$26,000
|
-
|
-
|
-
|
-
|
-
|
$26,000
|
|
Nancy
Stephenson
|
$28,500
|
-
|
-
|
-
|
-
|
-
|
$28,500
|
|
Phillip
Roberson
|
$-
|
|
|
|
|
|
$-
|
Option Grants Table
There
were no stock option grants for fiscal years ended December 31,
2016 and 2017.
58
|
ITEM 12
|
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
|
The
following table sets forth information with respect to beneficial
ownership of our common stock by:
●
* each person who
beneficially owns more than 5% of the common stock;
●
* each of our
executive officers named in the Management section;
●
* each of our
directors; and
●
* all executive
officers and directors as a group.
The
table shows the number of shares owned as of March 26, 2018 and the
percentage of outstanding common stock owned as of March 26, 2018.
Each person has sole voting and investment power with respect to
the shares shown, except as noted.
|
Name and
Address
Of Beneficial Owner(2)
|
Amount and
Nature
of Beneficial
Owner
|
Percent of Class(1)
|
|
Estate of Ray D.
Reaves(3)
|
2,351,350
|
22.0%
|
|
2352007 Ontario
Inc. (4)
|
744,212
|
7.0%
|
|
Michael Herman
(5)
|
663,423
|
6.2%
|
|
LeRoy Landhuis
(6)
|
884,564
|
8.3%
|
|
Roger D.
Bryant
|
34,000
|
*
|
|
Dan
Robinson
|
96,000
|
*
|
|
Karl
Reimers
|
58,100
|
*
|
|
Nancy
Stephenson
|
2,500
|
*
|
|
Phillip
Roberson
|
50,000
|
*
|
|
All Officers and
Directors as a Group(5 persons)
|
240,600
|
2.3%
|
___________________________
* indicates
less than 1%
(1)
The percentages
shown are calculated based upon 10,669,229 shares of common stock
issued and outstanding at March 26, 2018. In calculating the percentage of ownership, unless
as otherwise indicated, all shares of common stock that the
identified person or group had the right to acquire within 60 days
of the date of this Proxy Statement upon the exercise of options
and warrants or conversion of notes are deemed to be outstanding
for the purpose of computing the percentage of shares of common
stock owned by such person or group, but are not deemed to be
outstanding for the purpose of computing the percentage of the
shares of common stock owned by any other
person.
(2)
Unless otherwise
stated, the beneficial owner's address is 609 Castle Ridge Road,
Suite 335, Austin, Texas 78746.
(3)
Voting and investment power with
respect to the shares of common stock held in the Estate of Ray D.
Reaves is exercised by the Administrator of the
Estate.
59
(4)
2352007 Ontario Inc. is a wholly-owned subsidiary
of the Natale Rea (2013) Trust. The principal address of 2352007 Ontario Inc. and
the Natale Rea (2013) Trust is 9200 Weston Road, Piazzza Villagio,
P.O. Box 92030, Vaughan, Ontario L4H 3J3 Canada. The Company has
relied exclusively on the Schedule 13D filed by these affiliated
stockholders with the SEC on May 4, 2016, in making these
disclosures.
(5)
Includes
shares owned by HFT Enterprises, LLC, a Nevada limited liability
company, of which Mr. Herman is a control person. The principal
address of Michael Herman and HFT Enterprises, LLC., is P.O. Box
81740, Las Vegas, Nevada 89180.
(6)
The
address for LeRoy Landhuis is 212 N. Wahsatch Avenue, Suite 301,
Colorado Springs, Colorado 80903
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
There
were no related party transactions during the years ended December
31, 2017 and 2016.
ITEM
14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
In the
last two fiscal years, we have retained Moss Adams LLP and Hein
& Associates LLP, respectively, as our independent registered
public accounting firms. Hein & Associates audited our
consolidated financial statements for fiscal 2016 and Moss Adams
LLP for fiscal 2017. We understand the need for our principal
accountants to maintain objectivity and independence in their audit
of our financial statements. To minimize relationships that could
appear to impair the objectivity of our principal accountants, our
Audit Committee has restricted the non-audit services that our
principal accountants may provide to us primarily to tax services
and audit related services. The Board has adopted policies and
procedures for pre-approving work performed by our principal
accountants.
After
careful consideration, the Audit Committee of the Board of
Directors has determined that payment of the below audit fees is in
conformance with the independent status of the Company's principal
independent accountants. Before engaging the auditors in additional
services, the Audit Committee considers how these services will
impact the entire engagement and independence factors.
60
The
following is an aggregate of fees billed for each of the last two
fiscal years for professional services rendered by our principal
accountants:
|
|
2017
|
2017
|
2016
|
|
|
Moss
Adams
|
Hein &
Associates
|
Hein &
Associates
|
|
Audit fees - audit
of annual financial statements and review of
financial
statements included in our quarterly reports, services
normally
provided by the accountant in connection with statutory and
regulatory filings.
|
$48,300
|
$61,800
|
$118,900
|
|
|
|
|
|
|
Audit-related fees
- related to the performance of audit or review of financial
statements not reported under "audit fees" above
|
-
|
-
|
-
|
|
|
|
|
|
|
Tax fees - tax
compliance, tax advice and tax planning
|
-
|
25,400
|
24,200
|
|
|
|
|
|
|
All other fees -
services provided by our principal accountants other than those
identified above
|
-
|
-
|
-
|
|
|
|
|
|
|
Total fees paid or
accrued to our principal accountants
|
$48,300
|
$87,200
|
$143,100
|
ITEM 15 EXHIBITS AND FINANCIAL STATEMENT
SCHEDULES
|
(a)
|
Exhibits
|
|
|
|
|
|
|
|
|
|
3.1
|
Articles
of Incorporation (incorporated by reference to Amendment No. 1 to
Form S-2 dated August 1, 1980.)
|
|
|
|
|
|
|
|
|
Articles
of Amendment of Articles of Incorporation, dated December 31, 1997
(incorporated by reference to the Company's 10KSB for the year
ended December 31, 1997.)
|
||
|
|
|
|
|
|
|
3.3
|
Bylaws
(incorporated by reference to Amendment No. 1 to Form S-2 dated
August 1, 1980.)
|
|
|
|
|
|
|
|
|
Plan of
Exchange (incorporated by reference to the Company's definitive
proxy statement dated December 8, 1997.)
|
||
|
|
|
|
|
|
|
Indenture
(Term Loan) dated June 21, 1999 by and among the Company and Union
Planters Bank (incorporated by reference to the Company's 10KSB for
the year ended December 31, 1999.)
|
||
|
|
|
|
|
|
|
Indenture
(Term Loan) dated August 18, 1999 by and among the Company and
Union Planters Bank (incorporated by reference to the Company's
10KSB for the year ended December 31, 1999.)
|
||
|
|
|
|
|
|
|
Stock
Option Agreement (incorporated by reference to the Company’s
Form S-8 dated May 27, 2005 as filed with the Commission on May 27,
2005.)
|
||
|
|
|
|
|
61
|
|
Warrant
Agreement and Form of Warrant Certificate (incorporated by
reference to the Company’s Form S-3 as filed with the
Commission on November 22, 2011.)
|
|
|
|
|
|
|
|
Consulting
Agreement dated May 9, 2000 between FieldPoint Petroleum Corp. and
Parrish Brian & Co. (incorporated by reference to the Company's
10QSB/A for the quarter ended September 30, 2000.)
|
|
|
|
|
|
|
|
Executive
Employment Agreement, dated March 28, 2001, by and among FieldPoint
Petroleum Corp. and Ray D. Reaves (incorporated by reference to the
Company's 10KSB for the year ended December 31, 2000.)
|
|
|
|
|
|
|
|
Credit
Agreement (Revolving Credit Note) dated December 14, 2000 by and
among FieldPoint Petroleum Corp. and Union Planters Bank
(incorporated by reference to the Company's 10KSB for the year
ended December 31, 2000.)
|
|
|
|
|
|
|
|
Audit
Committee Charter adopted by the Company on March 28,
2001(incorporated by reference to the Company's 10KSB for the year
ended December 31, 2000.)
|
|
|
|
|
|
|
|
Consulting
Agreement dated November 13, 2001 between FieldPoint Petroleum
Corp. and TRG Group LLC. (incorporated by reference to the
Company's 10QSB for the quarter ended September 30,
2001.)
|
|
|
|
|
|
|
|
Loan
and Security Agreement with CitiBank, N.A., dated October 18, 2006
(incorporated by reference from the Company’s current report
on Form 8k dated October 18, 2006 as filed with the Commission on
October 20, 2006.)
|
|
|
|
|
|
|
|
Lease
Assignment from PXP Gulf Coast, Inc., dated March 11, 2004,
(incorporated by reference from the Company's Current Report on
Form 8-K dated March 11, 2004, as filed with the Commission on
March 26, 2004.)
|
|
|
|
|
|
|
|
Securities
Purchase Agreement (incorporated by reference to the
Company’s Form SB-2 dated September 20, 2005 as filed with
the Commission on September 20, 2005.)
|
|
|
|
|
|
|
|
10.9
|
Registration
Rights Agreement (incorporated by reference to the Company’s
Form S-8 dated May 27, 2005 as filed with the Commission on May 27,
2005.)
|
|
|
|
|
|
|
Stock
Purchase Agreement (incorporated by reference to the
Company’s Form 8-K dated February 6, 2006 as filed with the
Commission on February 9, 2006.)
|
|
|
|
|
|
|
|
Board
Compensation Agreement (incorporated by reference to the
Company’s Form 8-K dated February 6, 2006 as filed with the
Commission on February 9, 2006.)
|
|
|
|
|
|
|
|
Security
Agreement (incorporated by reference to the Company’s Form
8-K dated October 18, 2006 as filed with the Commission on October
20, 2006).
|
|
|
|
|
|
|
|
Bonus
Program (incorporated by reference to the Company’s Form 8-K
dated October 24, 2008 as filed with the Commission on October 29,
2008.)
|
|
|
|
|
|
62
|
|
Guaranty
Agreement (incorporated by reference to the Company’s Form
10-Q dated September 30, 2009 as filed with the Commission on
November 16, 2009.)
|
|
|
|
|
|
|
|
First
Amendment to Loan & Security Agreement (incorporated by
reference to the Company’s Form 10-Q dated September 30, 2009
as filed with the Commission on November 16, 2009.)
|
|
|
|
|
|
|
|
Second
Amendment to Loan & Security Agreement (incorporated by
reference to the Company’s Form 10-Q dated September 30, 2009
as filed with the Commission on November 16, 2009.)
|
|
|
|
|
|
|
|
Third
Amendment to Loan & Security Agreement (incorporated by
reference to the Company’s Form 10-Q dated September 30, 2009
as filed with the Commission on November 16, 2009.)
|
|
|
|
|
|
|
|
10.18
|
Fourth
Amendment to Loan & Security Agreement (incorporated by
reference to the Company’s Form 10-Q dated September 30, 2009
as filed with the Commission on November 16, 2009.)
|
|
|
|
|
|
|
Fifth
Amendment to Loan & Security Agreement (incorporated by
reference to the Company’s Form 8-K dated March 21, 2014, as
filed with the Commission on March 27, 2014.)
|
|
|
|
|
|
|
|
Executive
Employment Agreement dated July 1, 2014, between FieldPoint
Petroleum Corp. and Phillip H. Roberson (incorporated by reference
to the Company’s Annual Report on Form 10-K for the year
ended December 31, 2014 as filed with the Commission on March 30,
2015.)
|
|
|
|
|
|
|
|
Stock
and Mineral Lease Purchase Agreement dated August 12, 2016
(incorporated by reference to the Company’s 8-K dated August
12, 2016, as filed with the Commission on August 17,
2016.)
|
|
|
|
|
|
|
|
Sixth
Amendment to Loan and Forbearance Agreement dated October 4, 2016
(incorporated by reference to the Company’s 8-K dated October
4, 2016, as filed with the Commission on October 7,
2016.)
|
|
|
|
|
|
|
|
Amendment
No. 1 to Stock and Mineral Lease Purchase Agreement dated January
9, 2017 (incorporated by reference to the Company’s 8-K dated
January 9, 2017, as filed with the Commission on January 20,
2017.)
|
|
|
|
|
|
|
|
Seventh
Amendment to Loan and Forbearance Agreement dated December 29, 2017
(incorporated by reference to the Company’s 8-K dated
December 29, 2017, as filed with the Commission on January 9,
2018.)
|
|
|
|
|
|
|
|
Eighth Amendment to
Loan and Forbearance Agreement dated
March 30, 2018 (incorporated by reference to the Company’s
Annual Report on Form 10-K for the year ended December 31, 2017 as
filed with the Commission on April 2,
2018.).
|
|
|
|
|
|
|
|
Code of
Ethics (incorporated by reference to the Company’s Annual
Report on Form 10-KSB for the year ended December 31, 2003 as filed
with the Commission on April 14, 2004.)
|
|
|
|
|
|
|
|
Certification
of Principal Executive Officer required by Section 13a-14(a) of the
Exchange Act.
|
|
|
|
|
|
|
|
Certification
of Principal Operating Officer and Principal Financial Officer
required by Section 13a-14(a) of the Exchange Act.
|
|
|
|
|
|
|
|
Certification
of Principal Executive Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
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Certification
of Principal Operating Officer and Principal Financial Officer
pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
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Evaluation
of Oil and Gas Reserves by Russell K. Hall & Associates, Inc.
(incorporated by reference to the Company’s Annual Report on
Form 10-K for the year ended December 31, 2017 as filed with the
Commission on April 2, 2018.)
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63
SIGNATURES
In
accordance with Section 13 or 15(d) of the Exchange Act, the
registrant caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
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FIELDPOINT PETROLEUM
CORPORATION
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(Registrant)
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Date:
April 2, 2018
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By:
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/s/
Roger
D. Bryant
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Roger D.
Bryant
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Principal Executive
Officer
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Date:
April 2,
2018
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By:
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/s/
Phillip
H. Roberson
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Phillip H.
Roberson
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Principal Financial
Officer
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In
accordance with the Exchange Act, this report has been signed below
by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
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Signature
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Title
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Date
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/s/
Roger
D. Bryant
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Principal Executive
Officer, Director
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Date:
April
2, 2018
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|
Roger D.
Bryant
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/s/
Phillip
H. Roberson
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President,
Principal Operating
Officer,Principal Financial
Officer, and Director
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Date:
April
2, 2018
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Phillip H.
Roberson
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/s/
Dan
Robinson
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Director
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Date:
April
2, 2018
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Dan
Robinson
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/s/ Karl W.
Reimers
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Director
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Date:
April
2, 2018
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Karl W.
Reimers
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/s/ Nancy
Stephenson
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Director
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Date:
April
2, 2018
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Nancy
Stephenson
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64