The following discussion should be read in conjunction with our audited
financial statements and notes thereto date July 31, 2019. In connection with,
and because we desire to take advantage of, the "safe harbor" provisions of the
Private Securities Litigation Reform Act of 1995, we caution readers regarding
certain forward-looking statements in the following discussion and elsewhere in
this report and in any other statement made by us, or on our behalf, whether or
not in future filings with the Securities and Exchange Commission.
Forward-looking statements are statements not based on historical information
and which relate to future operations, strategies, financial results or other
developments. Forward-looking statements are necessarily based upon estimates
and assumptions that are inherently subject to significant business economic and
competitive uncertainties and contingencies, many of which are beyond our
control and many of which, with respect to future business decisions, are
subject to change. These uncertainties and contingencies can affect actual
results and could cause actual results to differ materially from those expressed
in any forward-looking statements made by us, or on our behalf. We disclaim any
obligation to update forward-looking statements.
The independent registered public accounting firm's report on the Company's
financial statements as of July 31, 2019, and for each of the fiscal years in
the two-year period then ended, includes a "going concern" explanatory paragraph
that describes substantial doubt about the Company's ability to continue as a
going concern.
Safe Harbor Provision
This Management's Discussion and Analysis includes a number of forward-looking
statements that reflect our current views with respect to future events and
financial performance. Forward-looking statements are often identified by words
like: "believe," "expect," "plan," "estimate," "anticipate," "intend,"
"project," "will," "predicts," "seeks," "may," "would," "could," "potential,"
"continue," "ongoing," "should," and similar expressions, or words which, by
their nature, refer to future events. You should not place undue certainty on
these forward-looking statements, which apply only as of the date of this Form
10-Q. These forward-looking statements are subject to certain risks or
uncertainties that could cause actual results to differ materially from
historical results or from our predictions. We undertake no obligation to update
or revise publicly any forward-looking statements, whether because of new
information, future events, or otherwise.
Overview
We are in the business of exploration, development, and production of oil and
gas in the Permian Basin of West Texas, in southeastern New Mexico, and in
Mississippi. The Permian Basin, which is one of the major producing basins in
the United States, is characterized by an extensive production history, a
favorable operating environment, mature infrastructure, long reserve life,
multiple producing horizons, enhanced recovery potential and a large number of
operators. The Permian Basin is characterized by high oil and liquids rich
natural gas, multiple vertical and horizontal target horizons, extensive
production history, long-lived reserves and high drilling success rates. As of
January 31, 2020, the Company has leasehold rights located within approximately
70,000 acres in Pecos County, Texas, 5,385 gross acres (4,682 net acres) in Lea
County, New Mexico and approximately 900 acres in Walthall County, Mississippi.
We believe that our concentrated acreage positions provides us with an
opportunity to achieve cost, operating and recovery efficiencies in the
development of our drilling inventory. Historically, our activities have been
primarily focused on vertical development of the Queen formation over the
Central Basin platform, which separates the Midland Basin from the Delaware
Basin, all of which are part of the Permian Basin in West Texas. Recently,
however, the Company has had several successful completions in the deeper San
Andres zone of its Pecos County, Texas and Lea County, New Mexico properties.
Future drilling targets could include the Grayburg, Clear Fork, Glorietta, and
Devonian zones in Pecos County, Texas and the Devonian, Pennsylvanian and
Wolfcamp/Wolfbone zones in Lea County, New Mexico and Lower Tuscaloosa Stinger
B,C, and D Sands, Yequa, Cook Mountain, and Sparta pay zones.
The properties acquired in Mississippi include eleven production capable wells
and three salt water disposal wells. The Company intends to begin a program of
workover and recompletion in 2020. Existing wellbores, field infrastructure, and
saltwater disposal well reduces cost and time. To date the primary saltwater
well has been reworked with a successful Mechanical Integrity Test approved by
the Mississippi Oil and Gas Board. The well in now in operation. The first well
on the schedule to be reworked is the Doster A-1 Well. Operations are now
underway in the 11,000-foot-deep formation called the Lower Tuscaloosa Stringer
pay sand
Our near-term success depends primarily on attracting developmental capital to
continue to drill, develop reserves and increase production within the leased
acreage that we currently control. We are also open to acquiring oil and gas
producing properties that would add value to our shareholders. We are the
operator of 100% of our Permian Basin acreage. This operating control allows us
to better execute on our strategies of enhancing returns through operational and
cost efficiencies and increasing ultimate hydrocarbon recovery by seeking to
continually improve our drilling techniques, completion methodologies and
reservoir evaluation processes. Additionally, as the operator of all of our
acreage, we retain the ability to increase or decrease our capital expenditure
program based on commodity price outlooks. This operating control also enables
us to obtain data needed for efficient exploration of our prospects. The Company
owns a small drilling rig (2,500'), completion rig, pulling unit and various
equipment to operate the property.
We have been operating at a net loss situation. Given the current oil prices,
and the inherent expenses of running a public company in the oil and gas
industry, it is uncertain if and when we may achieve profitable operations as a
small company.
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Commodity Prices.
Our results of operations are heavily influenced by commodity prices. Factors
that may impact future commodity prices, including the price of oil and natural
gas, include: (1) weather conditions in the United States and where the
Company's property interests are located; (2) economic conditions, including
demand for petroleum-based products, in the United States and the rest of the
world; (3) actions by OPEC, the Organization of Petroleum Exporting Countries;
(4) political instability in the Middle East and other major oil and natural gas
producing regions; (5) governmental regulations; (6) domestic tax policy; (7)
the price of foreign imports of oil and natural gas; (8) the cost of exploring
for, producing and delivering oil and natural gas; (9) the discovery rate of new
oil and natural gas reserves; (9) the rate of decline of existing and new oil
and natural gas reserves; (10) available pipeline and other oil and natural gas
transportation capacity; (11) the ability of oil and natural gas companies to
raise capital; (12) the overall supply and demand for oil and natural gas; and
(13) the availability of alternate fuel sources.
The Company cannot predict the occurrence of events that may affect future
commodity prices or the degree to which these prices will be affected, the
prices for any commodity that we produce will generally approximate current
market prices in the geographic region of the production. Furthermore, the
Company has not entered into any derivative contracts, including swap agreements
for oil and gas.
Fiscal Year 2019 Activity
During the fiscal year ended July 31, 2019, the Company continued to raise funds
to drill oil and gas wells located within the approximately 70,000 acres, in
Pecos County, Texas and the approximate 5,385 acres in Lea County, New Mexico,
where our leasehold rights currently exist. Our fund raising activities were
primarily through joint venture working interest holder participations, whereby
the Company retained a carried working interest. In order to keep the leasehold
in good standing, we adhered to the Continuous Drilling Clause for each
respective lease and strictly adhered to the requirements within said Drilling
Clauses.
Additionally, the WWJD #30 well was drilled to a total depth of 1,768 feet and
Amazing encountered approximately fourteen feet of pay zone thickness based on
comparison to a southern offset well. The Company completed the well utilizing a
technique known as an "open hole completion". Once the well quit flowing on its
own, a pump jack system was installed to restart oil production. The well is
currently producing an average of 5-7 BOPD.
On October 17, 2018 the Company closed on the acquisition of the deep rights in
26,000 mostly contiguous acres in the Permian Basin in Pecos County, Texas.
Post-closing the Company now controls all rights to all depths within the 61,000
acres with undivided mineral interest and rights to the depth of 3,000 feet to
surface on its additional ~9,000 acres. The purchased acreage is subject to the
same option terms that are applicable to the other Pecos County, Texas acreage
controlled by the Company. Jilpetco, Inc. will be the operator of record on all
current and future wells, if any, on the acquired acreage. The cost of the
acquisition was $500,000.
During the fiscal quarter ended October 31, 2019, the Company drilled and
completed the Wilson 498 well and recompleted the Wilson 49-2 well on the Pecos
County, Texas leasehold that was acquired in the transaction with Wyatt Energy,
LLC. Management is still in the process of evaluating the results of both wells
as the just entered the initial production stage. At January 31, 2020, the
Company has a 100% working interest in twenty-seven (27) wells and a 37% working
interest in the WWJD #31-H well located in the Pecos County, Texas leasehold
premises. The Company has drilled 27 wells throughout the property, and
recompleted one well that was drilled by a previous operator. Twenty-six of the
wells either current producers or subjects of a scheduled workover/recompletion
plan. Two wells are currently shut-in and will probably be converted to
injection wells associated with a future water-flood plan. The level of capital
expenditures for the remainder of the fiscal year will significantly depend on
the future market prices for oil and the Company's ability to source the
necessary capital to fund the drilling of any wells in the future.
Fiscal Year 2020 Activity
At January 31, 2020, the Company has seven producing wells and three saltwater
disposal wells in the Lea County project. A location has been selected and a
drilling pad has been built for the Curly Well.
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Amazing will leverage the extensive geological work done on the Pecos County,
Texas acreage to select new well drilling locations. Identified and prolific pay
zone horizons proven on the acreage include the Queen, Grayburg, Clear- Fork,
Wolfcamp, Pennsylvanian, Devonian and Ellenberger. Modern 3-D seismic covers
most of the leasehold, where 17 deep exploratory wells were drilled in the early
2000's targeting Devonian and Ellenberger pay at depths of 8,000-9,000 foot
Measured Depth. The Seismic data set primarily targeted Devonian wells which
have produced 4 BCFG and 150,000 barrels of oil in the area. Additionally, the
data has identified prospects that have yet to be drilled on the acreage and a
recent new field discovery by an offset operator in 2017 which will provide
additional detailed geological insight as to rock properties, reserves, and
production potentials. Amazing plans to shoot a larger 3-D survey which has the
potential to uncover additional new target areas from the deeper horizons.
On November 22, 2019 Amazing Energy MS, LLC ("AMS") a newly formed, wholly-owned
subsidiary of the Company closed on the acquisition of assets consisting of
certain oil and gas leases encompassing approximately 900 acres, nine oil wells
and a saltwater disposal well, all located in Mississippi and generally known as
the "Denver Mint Project." The company plans to restore and enhance production
with multiple workovers identified in proven Lower Tuscaloosa pay zones as well
as expand production into shallow regional pay zones. Shallow Yegua, Cook
Mountain, and Sparta pay zones above 3,300 ft. are regional pay zones that have
not been produced in Dinan Field to date. Existing well bores, field
infrastructure, and saltwater disposal well reduces cost and time.
In the past Amazing has focused on shallower plays available under our existing
options to incrementally increase production. Our strategy is getting a
tremendous boost with the addition of these deep rights and associated
well-known pay zones. We expect this acquisition to add several hundred
potential new well locations to our current drilling inventory. The potential of
our acreage is now on par with many of our much larger peers and in the same
well-known plays where they are experiencing marked success.
The Company's Expansion Strategy for 2020 includes the following subject to
economic and liquidity conditions:
? Capital Expenditure Strategy for Pecos County, Texas, Lea County, New
Mexico, and Mississippi assets:
? Pecos County, Texas and Lea County, New Mexico acreage represent
the main revenue drivers for Amazing Energy.
? Management plans to implement a monthly capital budget to drill
additional wells and workover/recomplete existing wells in all
areas.
? Seek to Acquire Additional Assets:
? Potential pipeline acquisition with current positive cash flow.
? The Company is geographically agnostic within the U.S. and is
comfortable participating in both operated and non-operated
transactions in most geological basins located in the lower 48
states, but on a more practical basis prefers locations proximate
to our current operations in Texas and New Mexico.
? Growth through JV/ Farm Out
? The Company intends to initiate discussions with other operators
and investors for the purpose of forming joint-ventures on acreage
that we currently hold as well as any acreage that we may acquire
in the future.
? Any such joint-ventures would allow Amazing to leverage the
financial resources and knowledge of leading operators in an effort
to enhance Amazing's shareholders' value.
Overview of Current Operations
Through January 31, 2020, the Company has drilled twenty-seven wells and
recompleted one well on its leasehold in Pecos County, Texas. Twenty-six of the
twenty-eight wells are either currently producing or awaiting
workover/recompletion and two wells are currently shut in. The wells have not
been commercially productive. As a result of the recent Lea County, New Mexico
acquisition, the Company has seven wells that are currently producing oil and
gas. The Company also acquired three salt-water disposal wells in the Lea
County, New Mexico asset acquisition transaction. In August, 2019, the Company
began disposing salt-water in one of its Lea County, New Mexico salt-water
disposal wells for another unrelated local operator. The Company will be paid an
amount each month based on the total number of barrels of salt-water disposed.
The newly acquired Mississippi properties are being reviewed to develop plans to
restore and enhance production with multiple workovers identified in proven
Lower Tuscaloosa pay zones as well as expand production into shallow regional
pay zones. Shallow Yegua, Cook Mountain, and Sparta pay zones above 3,300 ft.
are regional pay zones that have not been produced in Dinan Field. Existing
wellbores, field infrastructure, and saltwater disposal well reduces cost and
time. To date the primary saltwater well has been reworked with a successful
Mechanical Integrity Test approved by the Mississippi Oil and Gas Board. The
well in now in operation. The first well on the schedule to be reworked is the
Doster A-1 Well. Operations are now underway in the 11,000-foot-deep formation
called the Lower Tuscaloosa Stringer pay sand.
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Compliance with Government Regulations
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 Office of Pipeline
Safety (the "DOT") 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. For the state of Texas, the regulatory
agency is the Texas Railroad Commission. 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,
suspension of production, and, in certain cases, criminal prosecution. 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
Historically, the Company's oil and gas revenues originated from production from
its properties in Texas. Beginning February 1, 2019, the Company will also begin
generating oil and gas from its newly acquired properties in New Mexico. Each
revenue stream is sold to a single customer through month to month contracts.
While this creates a customer concentration, there are alternate buyers of the
production in event the sole customer is unable or unwilling to purchase.
During the six months ended January 31, 2020, the Company sold its oil and gas
production to only four customers. Oil production was sold to Rio Energy
International, Inc. (Pecos County, Texas) and to Plains Marketing L.P. (Lea
County, New Mexico), and natural gas production was sold to Trans-Pecos Natural
Gas Company, LLC (Pecos County, Texas) and Targa Resources (Lea County, New
Mexico). During the six months ended January 31, 2019, oil and gas production in
Pecos County, Texas was sold to Sunoco, LP and Trans-Pecos Natural Gas Company,
LLC, respectively.
Regulation of Production
Oil 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, Texas and New Mexico,
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, Texas and New Mexico
impose a severance tax on production and sales of oil, 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 Matters and Regulation
Our oil and natural gas exploration, development and production operations are
subject to stringent laws and regulations governing the discharge of materials
into the environment or otherwise relating to environmental protection. Numerous
federal, state and local governmental agencies, such as the EPA, issue
regulations that often require difficult and costly compliance measures that
carry substantial administrative, civil and criminal penalties and may result in
injunctive obligations for non-compliance. These laws and regulations may
require the acquisition of a permit before drilling commences; restrict the
types, quantities and concentrations of various substances that can be released
into the environment in connection with drilling and production activities;
limit or prohibit construction or drilling activities on certain lands lying
within wilderness, wetlands, ecologically or seismically sensitive and other
protected areas; require action to prevent or remediate pollution (from current
or former operations), such as plugging abandoned wells or closing pits; take
action resulting in the suspension or revocation of necessary permits, licenses
and authorizations; and/or require that additional pollution controls be
installed and impose substantial liabilities for pollution resulting from our
operations or related to our owned or operated facilities. Liability under such
laws and regulations is often strict (i.e., no showing of "fault" is required)
and can be joint and several. Moreover, it is not uncommon for neighboring
landowners and other third-parties to file claims for personal injury and
property damage allegedly caused by the release of hazardous substances,
hydrocarbons or other waste products into the environment. Changes in
environmental laws and regulations occur frequently, and any changes that result
in more stringent and costly pollution control or waste handling, storage,
transport, disposal or cleanup requirements could materially adversely affect
our operations and financial position, as well as the oil and natural gas
industry in general. Our management believes that we are in substantial
compliance with applicable environmental laws and regulations and we have not
experienced any material adverse effect from compliance with these environmental
requirements. This trend, however, may not continue in the future.
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Waste Handling. The Resource Conservation and Recovery Act, as amended, and
comparable state statutes and regulations promulgated thereunder, affect oil and
natural gas exploration, development and production activities by imposing
requirements regarding the generation, transportation, treatment, storage,
disposal and cleanup of hazardous and non-hazardous wastes. With federal
approval, the individual states administer some or all the provisions of the
Resource Conservation and Recovery Act, sometimes in conjunction with their own,
more stringent requirements. Although most wastes associated with the
exploration, development and production of crude oil and natural gas are exempt
from regulation as hazardous wastes under the Resource Conservation and Recovery
Act, such wastes may constitute "solid wastes" that are subject to the less
stringent non-hazardous waste requirements. Moreover, the EPA or state or local
governments may adopt more stringent requirements for the handling of
non-hazardous wastes or categorize some non-hazardous wastes as hazardous for
future regulation. Indeed, legislation has been proposed from time to time in
Congress to re-categorize certain oil and natural gas exploration, development
and production wastes as "hazardous wastes." Also, in December 2016, the EPA
agreed in a consent decree to review its regulation of oil and gas waste by
March, 2019 to determine whether any revisions are necessary. Any such changes
in the laws and regulations could have a material adverse effect on our capital
expenditures and operating expenses.
Administrative, civil and criminal penalties can be imposed for failure to
comply with waste handling requirements. We believe that we are in substantial
compliance with applicable requirements related to waste handling, and that we
hold all necessary and up-to-date permits, registrations and other
authorizations to the extent that our operations require them under such laws
and regulations. Although we do not believe the current costs of managing our
wastes, as presently classified, to be significant, any legislative or
regulatory reclassification of oil and natural gas exploration and production
wastes could increase our costs to manage and dispose of such wastes.
Remediation of Hazardous Substances. The Comprehensive Environmental Response,
Compensation and Liability Act, as amended, which we refer to as CERCLA or the
"Superfund" law, and analogous state laws, generally impose liability, without
regard to fault or legality of the original conduct, on classes of persons who
are considered to be responsible for the release of a "hazardous substance" into
the environment. These persons include the current owner or operator of a
contaminated facility, a former owner or operator of the facility at the time of
contamination, and those persons that disposed or arranged for the disposal of
the hazardous substance at the facility. Under CERCLA and comparable state
statutes, persons deemed "responsible parties" are subject to strict liability
that, in some circumstances, may be joint and several for the costs of removing
or remediating previously disposed wastes (including wastes disposed of or
released by prior owners or operators) or property contamination (including
groundwater contamination), 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. During our operations, we use materials that, if released, would be
subject to CERCLA and comparable state statutes. Therefore, governmental
agencies or third parties may seek to hold us responsible under CERCLA and
comparable state statutes for all or part of the costs to clean up sites at
which such "hazardous substances" have been released.
Water Discharges. The Federal Water Pollution Control Act of 1972, as amended,
also known as the "Clean Water Act," the Safe Drinking Water Act, the Oil
Pollution Act and analogous state laws and regulations promulgated thereunder
impose restrictions and strict controls regarding the unauthorized discharge of
pollutants, including produced waters and other gas and oil wastes, into
navigable waters of the United States, as well as state waters. The discharge of
pollutants into regulated waters is prohibited, except in accordance with the
terms of a permit issued by the EPA or the state. Spill prevention, control and
countermeasure plan requirements under federal law require appropriate
containment berms and similar structures to help prevent the contamination of
navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or
leak. The Clean Water Act and regulations implemented thereunder also prohibit
the discharge of dredge and fill material into regulated waters, including
jurisdictional wetlands, unless authorized by an appropriately issued permit.
The EPA has also adopted regulations requiring certain oil and natural gas
exploration and production facilities to obtain individual permits or coverage
under general permits for storm water discharges. In addition, on June 28, 2016,
the EPA published a final rule prohibiting the discharge of wastewater from
onshore unconventional oil and gas extraction facilities to publicly owned
wastewater treatment plants, which regulations are discussed in more detail
below under the caption "-Regulation of Hydraulic Fracturing." Costs may be
associated with the treatment of wastewater or developing and implementing storm
water pollution prevention plans, as well as for monitoring and sampling the
storm water runoff from certain of our facilities. Some states also maintain
groundwater protection programs that require permits for discharges or
operations that may impact groundwater conditions.
The Oil Pollution Act is the primary federal law for oil spill liability. The
Oil Pollution Act contains numerous requirements relating to the prevention of
and response to petroleum releases into waters of the United States, including
the requirement that operators of offshore facilities and certain onshore
facilities near or crossing waterways must develop and maintain facility
response contingency plans and maintain certain significant levels of financial
assurance to cover potential environmental cleanup and restoration costs. The
Oil Pollution Act subjects owners of facilities to strict liability that, in
some circumstances, may be joint and several for all containment and cleanup
costs and certain other damages arising from a release, including, but not
limited to, the costs of responding to a release of oil to surface waters.
Non-compliance with the Clean Water Act or the Oil Pollution Act may result in
substantial administrative, civil and criminal penalties, as well as injunctive
obligations. We believe we are in material compliance with the requirements of
each of these laws.
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Air Emissions. The federal Clean Air Act, as amended, and comparable state laws
and regulations, regulate emissions of various air pollutants through the
issuance of permits and the imposition of other requirements. The EPA has
developed, and continues to develop, stringent regulations governing emissions
of air pollutants at specified sources. New facilities may be required to obtain
permits before work can begin, and existing facilities may be required to obtain
additional permits and incur capital costs to remain in compliance. For example,
on August 16, 2012, the EPA published final regulations under the federal Clean
Air Act that establish new emission controls for oil and natural gas production
and processing operations, which regulations are discussed in more detail below
in "Regulation of Hydraulic Fracturing." Also, on May 12, 2016, the EPA issued a
final rule regarding the criteria for aggregating multiple small surface sites
into a single source for air-quality permitting purposes applicable to the oil
and gas industry. This rule could cause small facilities, on an aggregate basis,
to be deemed a major source, thereby triggering more stringent air permitting
processes and requirements. These laws and regulations may increase the costs of
compliance for some facilities we own or operate, and federal and state
regulatory agencies can impose administrative, civil and criminal penalties for
non-compliance with air permits or other requirements of the federal Clean Air
Act and associated state laws and regulations. We believe that we are in
substantial compliance with all applicable air emissions regulations and that we
hold all necessary and valid construction and operating permits for our
operations. Obtaining or renewing permits has the potential to delay the
development of oil and natural gas projects.
Climate Change. In December 2009, the EPA issued an Endangerment Finding that
determined that emissions of carbon dioxide, methane and other greenhouse gases
present an endangerment to public health and the environment because, according
to the EPA, emissions of such gases contribute to warming of the earth's
atmosphere and other climatic changes. In May 2010, the EPA adopted regulations
establishing new greenhouse gas emissions thresholds that determine when
stationary sources must obtain permits under the Prevention of Significant
Deterioration, or PSD, and Title V programs of the Clean Air Act. On June 23,
2014, in Utility Air Regulatory Group v. EPA, the U.S. Supreme Court held that
stationary sources could not become subject to PSD or Title V permitting solely
because of their greenhouse gas emissions. The Court ruled, however, that the
EPA may require installation of best available control technology for greenhouse
gas emissions at sources otherwise subject to the PSD and Title V programs. On
August 26, 2016, the EPA proposed changes needed to bring the EPA's air
permitting regulations in line with the Supreme Court's decision on greenhouse
gas permitting. The proposed rule was published in the Federal Register on
October 3, 2016 and the public comment period closed on December 2, 2016.
Additionally, in September 2009, the EPA issued a final rule requiring the
reporting of greenhouse gas emissions from specified large greenhouse gas
emission sources in the U.S., including natural gas liquids fractionators and
local natural gas distribution companies, beginning in 2011 for emissions
occurring in 2010. In November 2010, the EPA expanded the greenhouse gas
reporting rule to include onshore and offshore oil and natural gas production
and onshore processing, transmission, storage and distribution facilities, which
may include certain of our facilities, beginning in 2012 for emissions occurring
in 2011. In October 2015, the EPA amended the greenhouse gas reporting rule to
add the reporting of greenhouse gas emissions from gathering and boosting
systems, completions and workovers of oil wells using hydraulic fracturing, and
blowdowns of natural gas transmission pipelines.
The EPA has continued to adopt greenhouse gas regulations applicable to other
industries, such as its August 2015 adoption of three separate, but related,
actions to address carbon dioxide pollution from power plants, including final
Carbon Pollution Standards for new, modified and reconstructed power plants, a
final Clean Power Plan to cut carbon dioxide pollution from existing power
plants, and a proposed federal plan to implement the Clean Power Plan emission
guidelines. Upon publication of the Clean Power Plan on October 23, 2015, more
than two dozen states as well as industry and labor groups challenged the Clean
Power Plan in the D.C. Circuit Court of Appeals. On February 9, 2016, the
Supreme Court stayed the implementation of the Clean Power Plan while legal
challenges to the rule proceed. Because of this continued regulatory focus,
future greenhouse gas regulations of the oil and gas industry remain a
possibility. In addition, the U.S. Congress has from time to time considered
adopting legislation to reduce emissions of greenhouse gases and almost one-half
of the states have already taken legal measures to reduce emissions of
greenhouse gases primarily through the planned development of greenhouse gas
emission inventories and/or regional greenhouse gas cap and trade programs.
Although the U.S. Congress has not adopted such legislation at this time, it may
do so in the future and many states continue to pursue regulations to reduce
greenhouse gas emissions. Most of these 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 greenhouse
gases. The number of allowances available for purchase is reduced each year
until the overall greenhouse gas emission reduction goal is achieved. As the
number of greenhouse gas emission allowances declines each year, the cost or
value of allowances is expected to escalate significantly.
In December 2015, the United States participated in the 21st Conference of the
Parties of the United Nations Framework Convention on Climate Change in Paris,
France (the "Paris Accords"). The Paris Accords call for the parties to
undertake "ambitious efforts" to limit the average global temperature, and to
conserve and enhance sinks and reservoirs of greenhouse gases. The Agreement
went into effect on November 4, 2016. On June 1, 2017, President Trump announced
the United States would withdraw from the Paris Accords. The Agreement
establishes a framework for the parties to cooperate and report actions to
reduce greenhouse gas emissions. Also, on June 29, 2016, the leaders of the
United States, Canada and Mexico announced an Action Plan to, among other
things, boost clean energy, improve energy efficiency, and reduce greenhouse gas
emissions. The Action Plan specifically calls for a reduction in methane
emissions from the oil and gas sector by 40% to 45% by 2025.
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Restrictions on emissions of methane or carbon dioxide that may be imposed could
adversely affect the oil and natural gas industry. At this time, it is not
possible to accurately estimate how potential future laws or regulations
addressing greenhouse gas emissions would impact our business.
In addition, claims have been made against certain energy companies alleging
that greenhouse gas emissions from oil and natural gas operations constitute a
public nuisance under federal and/or state common law. As a result, private
individuals may seek to enforce environmental laws and regulations against us
and could allege personal injury or property damages. While our business is not
a party to any such litigation, we could be named in actions making similar
allegations. An unfavorable ruling in any such case could significantly impact
our operations and could have an adverse impact on our financial condition.
Moreover, there has been public discussion that climate change may be associated
with extreme weather conditions such as more intense hurricanes, thunderstorms,
tornadoes and snow or ice storms, as well as rising sea levels. Another possible
consequence of climate change is increased volatility in seasonal temperatures.
Some studies indicate that climate change could cause some areas to experience
temperatures substantially colder than their historical averages. Extreme
weather conditions can interfere with our production and increase our costs and
damage resulting from extreme weather may not be fully insured. However, at this
time, we are unable to determine the extent to which climate change may lead to
increased storm or weather hazards affecting our operations.
Regulation of Hydraulic Fracturing
Hydraulic fracturing is an important common practice that is used to stimulate
production of hydrocarbons, particularly natural gas, from tight formations,
including shales. The process, which involves the injection of water, sand and
chemicals under pressure into formations to fracture the surrounding rock and
stimulate production, is typically regulated by state oil and natural gas
commissions. However, legislation has been proposed in recent sessions of
Congress to amend the Safe Drinking Water Act to repeal the exemption for
hydraulic fracturing from the definition of "underground injection," to require
federal permitting and regulatory control of hydraulic fracturing, and to
require disclosure of the chemical constituents of the fluids used in the
fracturing process. Furthermore, several federal agencies have asserted
regulatory authority over certain aspects of the process. For example, the EPA
has recently taken the position that hydraulic fracturing with fluids containing
diesel fuel is subject to regulation under the Underground Injection Control
program, specifically as "Class II" Underground Injection Control wells under
the Safe Drinking Water Act.
In addition, the EPA plans to develop a Notice of Proposed Rulemaking by June
2018, which would describe a proposed mechanism - regulatory, voluntary, or a
combination of both - to collect data on hydraulic fracturing chemical
substances and mixtures. Also, on June 28, 2016, the EPA published a final rule
prohibiting the discharge of wastewater from onshore unconventional oil and gas
extraction facilities to publicly owned wastewater treatment plants. The EPA is
also conducting a study of private wastewater treatment facilities (also known
as centralized waste treatment, or CWT, facilities) accepting oil and gas
extraction wastewater. The EPA is collecting data and information related to the
extent to which CWT facilities accept such wastewater, available treatment
technologies (and their associated costs), discharge characteristics, financial
characteristics of CWT facilities, and the environmental impacts of discharges
from CWT facilities.
On August 16, 2012, the EPA published final regulations under the federal Clean
Air Act that establish new air emission controls for oil and natural gas
production and natural gas processing operations. Specifically, the EPA's rule
package includes New Source Performance standards to address emissions of sulfur
dioxide and volatile organic compounds and a separate set of emission standards
to address hazardous air pollutants frequently associated with oil and natural
gas production and processing activities. The final rule seeks to achieve a 95%
reduction in volatile organic compounds emitted by requiring the use of reduced
emission completions or "green completions" on all hydraulically-fractured wells
constructed or refractured after January 1, 2015. The rules also establish
specific new requirements regarding emissions from compressors, controllers,
dehydrators, storage tanks and other production equipment. The EPA received
numerous requests for reconsideration of these rules from both industry and the
environmental community, and court challenges to the rules were also filed. In
response, the EPA has issued, and will likely continue to issue, revised rules
responsive to some of the requests for reconsideration. On May 12, 2016, the EPA
amended its regulations to impose new standards for methane and volatile organic
compounds emissions for certain new, modified, and reconstructed equipment,
processes, and activities across the oil and natural gas sector. On the same
day, the EPA finalized a plan to implement its minor new source review program
in Indian country for oil and natural gas production, and it issued for public
comment an information request that will require companies to provide extensive
information instrumental for the development of regulations to reduce methane
emissions from existing oil and gas sources. These standards, as well as 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 mandate the use of specific equipment or
technologies to control emissions.
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Furthermore, there are certain governmental reviews either underway or being
proposed that focus on environmental aspects of hydraulic fracturing practices.
The EPA is currently evaluating the potential impacts of hydraulic fracturing on
drinking water resources. On December 13, 2016, the EPA released a study
examining the potential for hydraulic fracturing activities to impact drinking
water resources, finding that, under some circumstances, the use of water in
hydraulic fracturing activities can impact drinking water resources. Also, on
February 6, 2015, the EPA released a report with findings and recommendations
related to public concern about induced seismic activity from disposal wells.
The report recommends strategies for managing and minimizing the potential for
significant injection-induced seismic events. Other governmental agencies,
including the U.S. Department of Energy, the U.S. Geological Survey, and the
U.S. Government Accountability Office, have evaluated or are evaluating various
other aspects of hydraulic fracturing. These ongoing or proposed studies could
spur initiatives to further regulate hydraulic fracturing and could ultimately
make it more difficult or costly for us to perform fracturing and increase our
costs of compliance and doing business.
Several states, including Texas, and local jurisdictions, have adopted, or are
considering adopting, regulations that could restrict or prohibit hydraulic
fracturing in certain circumstances, impose more stringent operating standards
and/or require the disclosure of the composition of hydraulic fracturing fluids.
The Texas Legislature adopted legislation, effective September 1, 2011,
requiring oil and gas operators to publicly disclose the chemicals used in the
hydraulic fracturing process. The Texas Railroad Commission adopted rules and
regulations implementing this legislation that apply to all wells for which the
Texas Railroad Commission issues an initial drilling permit after February 1,
2012. The law requires that the well operator disclose the list of chemical
ingredients subject to the requirements of OSHA for disclosure on an internet
website and file the list of chemicals with the Texas Railroad Commission with
the well completion report. The total volume of water used to hydraulically
fracture a well must also be disclosed to the public and filed with the Texas
Railroad Commission. Also, in May 2013, the Texas Railroad Commission adopted
rules governing well casing, cementing and other standards for ensuring that
hydraulic fracturing operations do not contaminate nearby water resources. The
rules took effect in January 2014. Additionally, on October 28, 2014, the Texas
Railroad Commission adopted disposal well rule amendments designed, among other
things, to require applicants for new disposal wells that will receive
non-hazardous produced water and hydraulic fracturing flow-back fluid to conduct
seismic activity searches utilizing the U.S. Geological Survey. The searches are
intended to determine the potential for earthquakes within a circular area of
100 square miles around a proposed new disposal well. The disposal well rule
amendments, which became effective on November 17, 2014, also clarify the Texas
Railroad Commission's authority to modify, suspend or terminate a disposal well
permit if scientific data indicates a disposal well is likely to contribute to
seismic activity. The Texas Railroad Commission has used this authority to deny
permits for waste disposal wells. Similar types of legislation are under
consideration in New Mexico and Mississippi where the Company has existing oil
and gas operations.
There has been increasing public controversy regarding hydraulic fracturing with
regard to the use of fracturing fluids, induced seismic activity, 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 across the country implicating hydraulic
fracturing practices. If new laws or regulations that significantly restrict
hydraulic fracturing are adopted, such laws could make it more difficult or
costly for us to perform fracturing to stimulate production from tight
formations as well as make it easier for third 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. In addition, if hydraulic fracturing is further regulated at the
federal, state or local level, our 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 attendant
permitting delays and potential increases in costs. Such legislative changes
could cause us to incur substantial compliance costs, and compliance or the
consequences of any failure to comply by us could have a material adverse effect
on our financial condition and results of operations. Currently, it is not
possible to estimate the impact on our business of newly enacted or potential
federal, state or local laws governing hydraulic fracturing.
Other Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by numerous federal,
state and local authorities. 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, are authorized by statute to issue rules and regulations that
are binding on the oil and natural gas industry and its individual members, some
of which carry substantial penalties for failure to comply. Although the
regulatory burden on the oil and natural gas industry increases our cost of
doing business and, consequently, affects our profitability, these burdens
generally do not affect us any differently or to any greater or lesser extent
than they affect other companies in the industry with similar types, quantities
and locations of production.
The availability, terms and cost of transportation significantly affect sales of
oil and natural gas. The interstate transportation and sale for resale of oil
and natural gas is subject to federal regulation, including regulation of the
terms, conditions and rates for interstate transportation, storage and various
other matters, primarily by FERC. Federal and state regulations govern the price
and terms for access to oil and natural gas pipeline transportation. FERC's
regulations for interstate oil and natural gas transmission in some
circumstances may also affect the intrastate transportation of oil and natural
gas.
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Although oil and natural gas prices are currently unregulated, Congress
historically has been active in oil and natural gas regulation. We cannot
predict whether new legislation to regulate oil and natural gas might be
proposed, what proposals, if any, might actually be enacted by Congress or the
various state legislatures, and what effect, if any, the proposals might have on
our operations. Sales of condensate and oil and natural gas liquids are not
currently regulated and are made at market prices.
Drilling and Production. Our operations are subject to various types of
regulation at the federal, state and local level. These types of regulation
include requiring permits for the drilling of wells, drilling bonds and reports
concerning operations. The state, and some counties and municipalities, in which
we operate also regulate one or more of the following:
the locations of wells;
the method of drilling and casing wells;
the timing of constructions or drilling activities, including seasonal wildlife
closures;
the rates of productions or "allowables";
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells; and
notice to, and consultation with, surface owners and other third-parties
State laws regulate the size and shape of drilling and spacing units or
proration units governing the pooling of oil and natural gas properties. Some
states allow forced pooling or integration of tracts to facilitate exploration
while other states rely on voluntary pooling of lands and leases. In some
instances, forced pooling or unitization may be implemented by third parties and
may reduce our interest in the unitized properties. In addition, state
conservation laws establish maximum rates of production from oil and natural gas
wells, generally prohibit the venting or flaring of natural gas and impose
requirements regarding the ratability of production. These laws and regulations
may limit the amount of oil and natural gas we can produce from our wells or
limit the number of wells or the locations at which we can drill. Moreover, each
state generally imposes a production or severance tax with respect to the
production and sale of oil, natural gas and natural gas liquids within its
jurisdiction. States do not regulate wellhead prices or engage in other similar
direct regulation, but we cannot assure you that they will not do so in the
future. The effect of such future regulations may be to limit the amounts of oil
and natural gas that may be produced from our wells, negatively affect the
economics of production from these wells or to limit the number of locations we
can drill.
Federal, state and local regulations provide detailed requirements for the
abandonment of wells, closure or decommissioning of production facilities and
pipelines and for site restoration in areas where we operate. The U.S. Army
Corps of Engineers and many other state and local authorities also have
regulations for plugging and abandonment, decommissioning and site restoration.
Although the U.S. Army Corps of Engineers does not require bonds or other
financial assurances, some state agencies and municipalities do have such
requirements.
Natural Gas Sales and Transportation. Historically, federal legislation and
regulatory controls have affected the price of the natural gas we produce and
the manner in which we market our production. FERC has jurisdiction over the
transportation and sale for resale of natural gas in interstate commerce by
natural gas companies under the Natural Gas Act of 1938 and the Natural Gas
Policy Act of 1978. Since 1978, various federal laws have been enacted which
have resulted in the complete removal of all price and non-price controls for
sales of domestic natural gas sold in "first sales," which include all of our
sales of our own production. Under the Energy Policy Act of 2005, FERC has
substantial enforcement authority to prohibit the manipulation of natural gas
markets and enforce its rules and orders, including the ability to assess
substantial civil penalties.
FERC also regulates interstate natural gas transportation rates and service
conditions and establishes the terms under which we may use interstate natural
gas pipeline capacity, which affects the marketing of natural gas that we
produce, as well as the revenues we receive for sales of our natural gas and
release of our natural gas pipeline capacity. Commencing in 1985, FERC
promulgated a series of orders, regulations and rule makings that significantly
fostered competition in the business of transporting and marketing gas. Today,
interstate pipeline companies are required to provide nondiscriminatory
transportation services to producers, marketers and other shippers, regardless
of whether such shippers are affiliated with an interstate pipeline company.
FERC's initiatives have led to the development of a competitive, open access
market for natural gas purchases and sales that permits all purchasers of
natural gas to buy gas directly from third-party sellers other than pipelines.
However, the natural gas industry historically has been very heavily regulated;
therefore, we cannot guarantee that the less stringent regulatory approach
currently pursued by FERC and Congress will continue indefinitely into the
future nor can we determine what effect, if any, future regulatory changes might
have on our natural gas related activities.
Under FERC's current regulatory regime, transmission services are provided on an
open-access, non-discriminatory basis at cost-based rates or negotiated rates.
Gathering service, which occurs upstream of jurisdictional transmission
services, is regulated by the states onshore and in state waters. Although its
policy is still in flux, FERC has in the past reclassified certain
jurisdictional transmission facilities as non-jurisdictional gathering
facilities, which has the tendency to increase our costs of transporting gas to
point-of-sale locations.
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Oil Sales and Transportation. Sales of crude oil, condensate and natural gas
liquids are not currently regulated and are made at negotiated prices.
Nevertheless, Congress could reenact price controls in the future.
Our crude oil sales are affected by the availability, terms and cost of
transportation. The transportation of oil in common carrier pipelines is also
subject to rate regulation. FERC regulates interstate oil pipeline
transportation rates under the Interstate Commerce Act and intrastate oil
pipeline transportation rates are 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 materially
different way than such regulation will affect the operations of our
competitors.
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 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
competitors.
State Regulation. Texas, Mississippi and New Mexico regulate the drilling for,
and the production, gathering and sale of, oil and natural gas, including
imposing severance taxes and requirements for obtaining drilling permits. Texas
currently imposes a 4.6% severance tax on oil production and a 7.5% severance
tax on natural gas production, while New Mexico currently imposes a 3.75%
severance tax on oil and gas production as well as an additional emergency
school tax (3.15%), a conservation tax (1.9%) and a production ad-valorem tax
(2.2886%). Mississippi has similar severance tax structures that will apply to
the Company's future production. States also regulate the method of developing
new fields, the spacing and operation of wells and the prevention of waste of
oil and natural gas resources. States may regulate rates of production and may
establish maximum daily production allowable from oil and natural gas wells
based on market demand or resource conservation, or both. States do not regulate
wellhead prices or engage in other similar direct economic regulation, but we
cannot assure you that they will not do so in the future. The effect of these
regulations may be to limit the amount of oil and natural gas that may be
produced from our wells and to limit the number of wells or locations we can
drill.
The petroleum industry is also subject to compliance with various other federal,
state and local regulations and laws. Some of those laws relate to resource
conservation and equal employment opportunity. We do not believe that compliance
with these laws will have a material adverse effect on us.
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. These laws also
require the development of risk management plans for certain facilities to
prevent accidental releases of pollutants. We believe that we are in substantial
compliance with these applicable requirements and with other OSHA and comparable
requirements.
Competition
The oil and natural gas industry is intensely competitive, and we compete with
other companies that have greater resources. Many of these companies not only
explore for and produce oil and natural gas, but also carry on midstream and
refining operations and market petroleum and other products on a regional,
national or worldwide basis. These companies may be able to pay more for
productive oil and natural gas properties and exploratory prospects or to
define, evaluate, bid for and purchase a greater number of properties and
prospects than our financial or human resources permit. In addition, these
companies may have a greater ability to continue exploration activities during
periods of low oil and natural gas market prices. Our larger or more integrated
competitors may be able to absorb the burden of existing, and any changes to,
federal, state and local laws and regulations more easily than we can, which
would adversely affect our competitive position. Our ability to acquire
additional properties and to discover reserves in the future will be dependent
upon our ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. In addition, because we have
fewer financial and human resources than many companies in our industry, we may
be at a disadvantage in bidding for exploratory prospects and producing oil and
natural gas properties. Further, oil and natural gas compete with other forms of
energy available to customers, primarily based on price. These alternate forms
of energy include electricity, coal and fuel oils. Changes in the availability
or price of oil and natural gas or other forms of energy, as well as business
conditions, conservation, legislation, regulations and the ability to convert to
alternate fuels and other forms of energy may affect the demand for oil and
natural gas.
Office and Other Facilities
The Company leases its corporate headquarters in Plano, Texas. Reference detail
in Note 10 of the Consolidated Financial Statements regarding Lease Commitments.
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Employees
As of January 31, 2020, the Company had five full-time employees. We regularly
use independent contractors and consultants to perform various field-level tasks
as well as other required services. None of our employees are represented by a
labor union or covered by any collective bargaining agreement.
Research and Development Expenditures
None.
Reports to Security Holders
We file annual reports on Form 10-K, quarterly reports on Form 10-Q and current
reports on Form 8-K, proxy statements and other documents with the SEC under the
Exchange Act. The SEC maintains an Internet website that contains reports, proxy
and information statements, and other information regarding issuers, including
the Company, that file electronically with the SEC. The public can obtain any
document we file with the SEC at www.sec.gov.
PLAN OF OPERATION
Title to Properties
As is customary in the oil and natural gas industry, we initially conduct only a
cursory review of the title to our properties. When we determine that we will
conduct drilling operations on any properties, we conduct a thorough title
examination and perform curative work with respect to significant defects prior
to commencement of drilling operations. To the extent title opinions or other
investigations reflect title defects on those properties, we are typically
responsible for curing any title defects at our expense. We generally will not
commence drilling operations on a property until we have cured any material
title defects on such property. We have obtained title opinions on substantially
all of our producing properties and believe that we have satisfactory title to
our producing properties in accordance with standards generally accepted in the
oil and natural gas industry. Prior to completing an acquisition of producing
oil and natural gas leases, we perform title reviews on the most significant
leases and, depending on the materiality of properties, we may obtain a title
opinion, obtain an updated title review or opinion or review previously obtained
title opinions. Our oil and natural gas properties are subject to customary
royalty and other interests, liens for current taxes and other burdens which we
believe do not materially interfere with the use of or affect our carrying value
of the properties.
Oil and Gas Leases
The typical oil and natural gas lease agreement covering our acreage positions
in Pecos County, Texas, Lea County, New Mexico, and Mississippi provide for the
payment of royalties to the mineral owners for all oil and natural gas produced
from any wells drilled on the leased premises. The lessor royalties and other
leasehold burdens on our properties generally range from 20% to 25%, resulting
in a net revenue interest to the working interest owners generally ranging from
75% to 80%.
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RESULTS OF OPERATIONS
The following table presents selected financial and operational data for the six
months ended January 31, 2020 and 2019, respectively.
Six months ended January 31,
2020 2019 Change % Change
Revenue, oil and
gas sales $ 447,152 $ 225,828 $ 221,324 98.01 %
Number of BOE
sold 11,584 4,754 6,830 143.67 %
Average price
per BOE $ 38.60 $ 47.50 $ (8.90 ) -18.74 %
Net production
(BOE) 12,532 4,901 7,631 155.70 %
Average daily
net production
(BOE) 68.11 26.64 41.47 155.66 %
Three months ended January 31,
2020 2019 Change % Change
Revenue, oil and
gas sales $ 245,410 $ 95,803 $ 149,607 156.16 %
Number of BOE
sold 7,662 2,241 5,421 241.90 %
Average price
per BOE $ 32.03 $ 42.75 $ (10.72 ) -25.08 %
Net production
(BOE) 8,007 2,249 5,758 256.02 %
Average daily
net production
(BOE) 87.03 24.45 62.58 255.96 %
Oil and Gas Production and Revenue
Production Costs
Production costs increased $313,411 from $182,810 for the six months ended
January 31, 2019 to $496,221 for the six months ended January 31, 2020. This
increase for the comparable three-month period was attributable primarily to
increased reasonable and customary lease operating expenses.
Depletion, depreciation and amortization of asset retirement obligation
liability accretion ("DD&A")
Depletion of oil and gas properties is calculated under the units of production
method, following the full cost method of accounting. For the six month period
ended January 31, 2020, DD&A was $202,909 as compared to $151,389 for the six
month period ended January 31, 2019. The increase in DD&A of $51,520 for the
six-month comparable period was primarily due to the change in increased
production for the current period relative to the prior year and an increase in
the basis for DD&A calculation for property acquired.
General and Administrative Expenses
For the six months ended January 31, 2020, the Company's general and
administrative expenses were $2,142,449 compared to $2,101,599 for the
comparative six months ended January 31, 2019, an increase of $40,850.
Increase (decrease) in non-cash stock and warrant compensation $ (242,876 )
Increase (decrease) in consulting services expense
(25,347 )
Increase (decrease) in investor relations expense (66,632 )
Increase (decrease) in travel expense 12,201
Increase (decrease) in salaries, employee benefits and payroll taxes 11,126
Increase (decrease) in professional fees
243,962
Increase (decrease) in general corporate expenses 108,416
Total Decrease in General and Administrative Expenses $ 40,850
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For the three months ended January 31, 2020, the Company's general and
administrative expenses were $988,509 compared to $1,114,940 for the comparative
quarter ended January 31, 2019, a decrease of $126,431.
Detail of the changes in general and administrative expense is as follows:
Increase (decrease) in non cash stock and warrant compensation $ (168,237 )
Increase (decrease) in consulting
$ 99,122
Increase (decrease) in investor relations expense (3,419 )
Increase (decrease) in travel expense 15,501
Increase (decrease) in salaries, employee benefits and payroll taxes 99,313
Increase (decrease) in professional fees
64,696
Increase (decrease) in general corporate expenses (233,407 )
Total Increase in General and Administrative Expenses $ (126,431 )Liquidity and Capital Resources
The Company had a working capital deficit of $7,047,377 as of January 31 2020,
compared to a working capital deficit of $4,901,103 as of July 31, 2019. The
increase in the working capital deficit was primarily due to the net increase in
accounts payable, issuance of convertible notes payable, and the financing of
property acquisitions related to the New Mexico and Mississippi asset
acquisitions.
Detail of changes in cash flows for the six months ended January 31, 2020 and
2019 are as follows:
Increase
January 31, 2020 January 31, 2019 (Decrease)
Net cash from (used in)
operating activities $ 2,949,151 $ (272,945 ) $ 3,222,096
Net cash (used in)
investing activities $ (3,959,025 ) $ (527,053 ) $ (3,431,972 )
Net cash provided by
financing activities $ 952,744 $ 895,230 $ 57,514
The Company continues to seek sufficient capital to expand its drilling program.
The most cost-effective source of capital would be joint-ventured working
interest participation funds. A typical joint venture would involve 100% of the
drilling and completion funds being provided by such working interest
participants who would receive a negotiated working interest in the applicable
wells.
The Company's operating cash flow is dependent upon many factors, including
production levels, sales volume, oil and gas prices and other factors that may
be beyond its control.
Critical Accounting Policies and Recent Accounting Pronouncements
The Company has identified the policies below as critical to business operations
and the understanding of the Company's financial statements. The impact of these
policies and associated risks is discussed throughout Management's Discussion
and Analysis where such policies affect the Company's reported and expected
financial results.
Principles of Consolidation
The Company's consolidated financial statements include all its subsidiaries.
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The following table shows the wholly-owned subsidiaries of Amazing Energy Oil
and Gas, Co. which are engaged in the oil and gas business:
State of
Name of Subsidiary Incorporation Ownership Interest Principal Activity
Oil and gas exploration,
Amazing Energy, Inc. Nevada 100% development, and products
Ownership of oil and gas
Amazing Energy, LLC Texas 100% leases
Jilpetco, Inc. Texas 100% Operating company
Oil and gas exploration,
Amazing Energy MS LLC Mississippi 100% development, and products
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AMAZING ENERGY OIL AND GAS, CO. 
