Item
1 and 2. Business and Properties
Samson Oil & Gas Limited (“we”,
“Samson” or the “Company”) is a company limited by shares, incorporated on April 6, 1979, under the
laws of Australia. Our principal business is the exploration and development of oil and natural gas properties in the
United States.
Recent activities
On April 9, 2019, Samson Oil and Gas,
USA, Inc., our wholly owned subsidiary, entered into a credit agreement (“Credit Agreement”) with AEP I FINCO LLC
(“Lender”) providing for a $33.5 million term loan. The Company used the proceeds of the Credit Agreement to retire
the Company’s previous credit facility of $23.9 million with Mutual of Omaha Bank, repay outstanding creditors, royalty
and working interest owners and provide working capital to pursue its infill development drilling program. In conjunction with
the closing of the Credit Agreement, the Company paid $1.4 million in deferred borrowing costs.
The Credit Agreement is secured by certain
of the Company’s oil and gas properties and has a 5-year term with a maturity date on April 9, 2024. Interest on the Credit
Facility accrues at a rate equal to LIBOR plus a margin of 10.5% and is payable on the last day of each interest period. Under
the terms of the Credit Agreement, the Company is subject to certain covenants and obligations, as described in Note 8 to the
Consolidated Financial Statements. At June 30, 2019, we were in violation of certain financial covenants. We have, therefore,
classified the total amount outstanding under our debt facility of $33.5 million as a current liability and fully amortized the
$1.4 million of deferred borrowing costs as a charge to finance expense in our statement of operations.
The infill development drilling program
is designed to drill horizontal laterals from the existing well bores. The ability to drill out of an existing wellbore has made
the economics of these development wells attractive, given the ability to use surface facilities associated with the existing
well. Over the next nine months, we expect to drill a total of eight lateral wells within the Home Run Field (the “Home
Run Field Drill Program”), which is the largest (by area) of the oil fields in Samson’s portfolio. The Company has
in its portfolio a total of 26 Contingent resource locations that management expects will provide an excellent growth platform.
The Credit Agreement is expected to provide sufficient working capital to initiate and maintain the planned development drilling
program. Due to our recent breaches of the Credit Agreement, however, the Lender may declare an event of default and foreclose
on some or all of our assets and/or accelerate the full amount of the $33.5 million loan plus all accrued and unpaid interest,
prepayment penalties, fees and other lender costs and expenses, depleting our working capital such that we would be unable to
maintain the planned development drilling program.
Going concern
We do not generate adequate revenue to
satisfy our current operations, we have negative cash flows from operations, and we have incurred significant net operating losses
during the years ended June 30, 2019, and 2018, which raise substantial doubt about our ability to continue as a going concern.
We are also in breach of several of our covenants under the Credit Agreement, resulting in our borrowings payable of $33.5 million
being classified as current liabilities.
Accordingly, our financial statements
have been prepared on the going concern basis, which contemplates the continuity of normal business activities and the realization
of assets and settlement of liabilities in the normal course of business. We are currently negotiating with a prospective party
a transaction to divest all of our oil and gas assets, which we believe, if successful, will result in proceeds not less than
our obligations under the Credit Agreement and to our vendors. We are also currently negotiating with the Lender in an effort
to obtain a waiver for our breach of the Credit Agreement.
Our ability to continue as a going
concern is dependent on our re-negotiation of the Credit Agreement, our ability to sell our assets, development of our
Foreman Butte property, and our ability to reduce costs or raise further capital. There can be no assurances that we will
successfully obtain a waiver from the Lender, successfully divest our assets, or increase our cash flows from operations.
Given our current financial situation we may be forced to accept terms on these transactions that are less favorable than
would be otherwise available.
Prior Transactions
In March 2016, we acquired the Foreman
Butte Project, comprised of a number of producing and non-producing, operated and non-operated properties in the Ratcliffe and
Madison formations in North Dakota and Montana. The purchase price was $16.0 million (before post-closing settlement adjustments)
and following a review of the fair market value of the assets and liabilities on the closing date of the transaction, we recorded
a bargain purchase gain of $10.7 million. This acquisition was financed through an extension in our credit facility with Mutual
of Omaha Bank of $11.5 million and a $4.0 million promissory note provided to the seller of the assets. This note was repaid in
May 2017 through a term note facility from Mutual of Omaha Bank.
On June 30, 2016, we signed a purchase
and sale agreement for the sale of our North Stockyard project in North Dakota. The sale price was $15.0 million and closed on
October 31, 2016, of which $11.5 million of the total proceeds from this transaction were used to pay down our credit facility
with Mutual of Omaha Bank. The remaining proceeds were used to rebalance our hedge book, following the sale of a portion of our
production, and for working capital.
In May 2017, we closed on the sale of
our State GC assets in New Mexico. The sale price of $1.2 million was applied to pay down our facility with Mutual of Omaha Bank.
In June 2017, Samson and Mutual of Omaha Bank agreed to extend both the $4 million term loan and our $19.5 million reserve base
facility until October 2018. The previous maturity date was October 31, 2017.
In June 2018, we signed a purchase and
sale agreement for the sale of the majority of our working interest in the Foreman Butte project in Montana and North Dakota for
$40 million. This sale was expected to close on October 15, 2018 however the buyer failed to close. We terminated the purchase
and sale agreement with the buyer and engaged PLS Energy Advisors Group to remarket the asset. A non-refundable $1 million deposit
placed into escrow by the buyer was released to us.
Business Strategy
Our business strategy is to acquire, explore
and develop oil, natural gas and natural gas liquids ("NGL's") in the United States, primarily with a focus in Montana
and North Dakota. Our long-term strategy is to seek to deliver net asset value per share growth to our investors via attractive
investments within the oil and gas industry. In the event we are able to obtain sufficient additional capital we expect to seek
properties that offer profit potential from overlooked and by-passed reserves of oil and natural gas, which may include shut-in
wells, in-field development, stripper wells, and re-completion and re-working projects.
Production and Reserves Estimates
Production Activities
Average net barrel of oil equivalent (“BOE”)
production per day (“BOEPD”) for the fiscal year ended June 30, 2019, was 629 BOEPD, an increase of 112 BOEPD or 21.5%
compared to the same period in the prior year. Current 30 day production rate (as of August 31, 2019), is averaging 1,101 BOPD
(on a gross Operated basis) and approximately 780 BOPD net to Samson. This increase is due to bringing wells back online through
a series of workovers.
Prior 12-month net sales volumes by quarter:
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Q3
2018
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Q4
2018
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Q1
2019
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|
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Q2
2019
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|
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Total
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|
OIL,
BBL
|
|
|
54,779
|
|
|
|
63,618
|
|
|
|
46,258
|
|
|
|
59,135
|
|
|
|
223,790
|
|
GAS,
MCF
|
|
|
11,941
|
|
|
|
10,583
|
|
|
|
5,213
|
|
|
|
7,882
|
|
|
|
35,619
|
|
BOE
|
|
|
56,769
|
|
|
|
65,381
|
|
|
|
47,127
|
|
|
|
60,449
|
|
|
|
229,726
|
|
BOEPD
|
|
|
617
|
|
|
|
711
|
|
|
|
524
|
|
|
|
664
|
|
|
|
629
|
|
We have an interest in the following joint
operations whose principal activities are oil and gas exploration and production.
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Working Interest
Held
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Project/Property Name
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|
|
|
%
|
|
|
%
|
|
Exploration
|
|
Location
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|
2019
|
|
|
2018
|
|
Roosevelt *
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|
United States of America
|
|
|
66.00
|
|
|
|
66.00
|
|
* leases
expired or wells plugged and abandoned
Production
|
|
|
|
|
|
|
|
|
|
|
Big Hand
|
|
United States of America
|
|
|
4.00
|
|
|
|
4.00
|
|
Bird Canyon
|
|
United States of America
|
|
|
16.00
|
|
|
|
16.00
|
|
Jalmat
|
|
United States of America
|
|
|
60.00
|
|
|
|
60.00
|
|
LA Ward
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|
United States of America
|
|
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3.00
|
|
|
|
3.00
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|
Neta
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United States of America
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13.00
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|
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13.00
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Powder River Basin
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United States of America
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|
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18.00
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|
|
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18.00
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|
Scribner
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United States of America
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|
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28.00
|
|
|
|
28.00
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|
Wagensen
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United States of America
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|
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8.00
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|
|
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8.00
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Foreman Butte
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United States of America
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|
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1-100
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1-100
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Reserve Analysis
The Company’s estimated total net
proved reserves of oil and natural gas as of June 30, 2019, and the present values of estimated future net revenues attributable
to those reserves as of those dates, are presented in the following tables. All of our reserves are located in the United States.
The estimates quoted for June 2019, are based on, and fairly represent, information and supporting documentation prepared by an
employee of Netherland Sewell & Associates Inc, an independent petroleum engineering consulting firm. Netherland, Sewell &
Associates, Inc. and its employees and its registered petroleum engineers have no interest in Samson and performed those services
at their standard rates. Netherland, Sewell & Associates, Inc.’s estimates were based on a review of geologic, economic,
ownership, and engineering data provided to them by us.
In accordance with SEC regulations, no
price or cost escalation or reduction was considered. The technical persons at Netherland, Sewell & Associates, Inc. responsible
for preparing our reserve estimate meet the requirements regarding qualifications, independence, objectivity, and confidentiality
set forth in the standards pertaining to the estimating and auditing of oil and gas reserves information promulgated by the Society
of Petroleum Engineers.
In substance, the Netherland, Sewell &
Associates, Inc. report used estimates of oil and gas reserves based upon standard petroleum engineering methods which include
production data, decline curve analysis, volumetric calculations, pressure history, analogy, various correlations and technical
factors. Information for this purpose was obtained from owners of interests in the areas involved, state regulatory agencies,
commercial services, outside operators and files of Netherland, Sewell & Associates, Inc.
Management has established, and is responsible
for, internal controls designed to provide reasonable assurance that the estimates of Proved Reserves are computed and reported
in accordance with SEC rules and regulations as well as with established industry practices. Our officers, executives and geologists
have experience evaluating reserves on a well by well basis and on a company wide basis. Prior to generation of the annual reserves,
management and staff prepare an internal reserve study and then meet with Netherland, Sewell & Associates, Inc. to review
properties and discuss assumptions used in our internal study and the calculation of reserves. Management reviews all information
submitted to Netherland, Sewell & Associates, Inc. to ensure the accuracy of the data. Management also reviews the final report
from Netherland, Sewell & Associates, Inc. and discusses any differences from Management expectations with them.
The reserve estimates are reported to
the Board of Directors, at least annually. Our Board members have experience in reviewing and understanding reserve estimates.
The following tables summarize our proved
oil and natural gas reserves at June 30, 2019, using SEC regulations and our contingent resources at June 30, 2019:
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As
at 30 June 2019
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Reserves
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NET
OIL
MBBLS
|
|
|
NET
GAS
MMCF
|
|
|
NET
BOE
MBBLS
|
|
|
NPV
10
MILLION
|
|
PDP
|
|
|
2,930
|
|
|
|
915
|
|
|
|
3,083
|
|
|
$
|
47.6
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|
Contingent Resources *
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|
NET
OIL
MBBLS
|
|
|
NET
GAS
MMCF
|
|
|
NET
BOE
MBBLS
|
|
|
NPV
10
MILLION
|
|
1C - Non-producing
|
|
|
102
|
|
|
|
141
|
|
|
|
126
|
|
|
$
|
1.4
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|
1C - Undeveloped
|
|
|
2,682
|
|
|
|
2,236
|
|
|
|
3,055
|
|
|
$
|
44.8
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|
Total contingent resources
|
|
|
2,784
|
|
|
|
2,377
|
|
|
|
3,181
|
|
|
$
|
46.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total proved plus contingent
resources
|
|
|
5,714
|
|
|
|
3,292
|
|
|
|
6,264
|
|
|
$
|
93.8
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|
* Contingent Resources are potentially recoverable volumes
associated with a development plan that targets discovered volumes but is not (yet) commercial, as defined below.
To be considered as “commercial”,
there must be a firm intention to proceed with the project in a reasonable time frame (typically 5 years), and such intention
must be based upon all of the following criteria:
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·
|
A reasonable
assessment of the future economics of the development project meeting defined investment
and operating criteria;
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·
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A reasonable
expectation that there will be a market for all or at least the expected sales quantities
of production required to justify development;
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|
·
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Evidence
that the necessary production and transportation facilities are available or can be made
available; and
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·
|
Evidence
that legal, contractual, environmental and other social and economic concerns will allow
for the actual implementation of the recovery project being evaluated.
|
Given our current financial condition
there is no assurance that we will have the necessary financial resources available to meet the defined investment and operating
criteria, noted above, in order to execute the development plan necessary to categorize the Contingent resources as proven reserves.
Notes to Reserves and Resources Estimates
NET BOE MBBLS is thousand barrels of oil
equivalent
BOE is calculated using a heating value
of gas and converted as 1 BOE equals 6 MCF
PDP is Proved Developed Producing Reserves
1C – Non-Producing is Contingent
Developed Non-Producing Resources
1C - Undeveloped is Contingent Undeveloped
Resources
NPV10 is Net Present Value
at 10% discount rate
The oil price after basis adjustments
used in our June 30, 2019 reserve study for oil was $55.68 per Bbl and for natural gas was $3.89 per Mcf. The assumed prices used
in calculating the estimated future net revenue attributable to proved reserves do not necessarily reflect actual market prices
for oil production sold after June 30, 2019. There can be no assurance that all of the estimated proved reserves will be produced
and sold at the assumed prices. Accordingly, the foregoing prices should not be interpreted as a prediction of future prices.
The following reserve estimate using the NYMEX and Henry Hub
strip prices are as follows:
As of June 30, 2019
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Reserve category
|
|
Net
Oil
MBBLS
|
|
|
Net
Gas
MMCF
|
|
|
Net
BOE
MBBLS
|
|
|
NPV
10
$
MILLION
|
|
Proved
Developed Producing
|
|
|
2,788
|
|
|
|
856
|
|
|
|
2,930
|
|
|
$
|
37.93
|
|
Notes to Reserves Estimates
NET BOE MBBLS is thousand barrels of oil
equivalent
BOE is calculated using a heating value
of gas and converted as 1 BOE equals 6 MCF
PDP is Proved Developed Producing Reserves
NPV10 is Net Present Value
at 10% discount rate
The commodity prices used in this estimate are as follows:
|
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Oil Price $/Bbl
|
|
|
Gas Price
($/MMBTU)
|
|
December 31, 2019
|
|
|
52.27
|
|
|
|
3.24
|
|
December 31, 2020
|
|
|
50.46
|
|
|
|
3.41
|
|
December 31, 2021
|
|
|
48.41
|
|
|
|
3.45
|
|
December 31, 2022
|
|
|
47.81
|
|
|
|
3.47
|
|
December 31, 2023
|
|
|
47.90
|
|
|
|
3.54
|
|
Thereafter
|
|
|
48.32
|
|
|
|
3.64
|
|
Reporting and Financials
We became required to file our periodic
reports to the SEC as a U.S. domestic issuer as of July 1, 2011. Since we remain an Australian corporation, however, we are still
considered to be a domestic company in Australia as well. As a result, we are required to report our financial results
in the U.S. using U.S. Generally Accepted Accounting Principles (“U.S. GAAP”) and in Australia using International
Financial Reporting Standards (“IFRS”).
We publish our consolidated financial
statements, both U.S. GAAP and IFRS, in U.S. dollars. In this annual report, unless otherwise specified, all dollar
amounts are expressed in U.S. dollars, and references to “dollars,” “$” or “US$” are to United
States dollars. All references to “A$” are to Australian dollars.
Our registered office is located at Level
8, 99 St Georges Terrace, Perth, Western Australia 6000 and our telephone number at that office is +61 8-9486-4036. Our principal
office in the United States is located at 1331 17th Street, Suite 710, Denver, Colorado 80202 and our telephone number
at that office is +1 303-295-0344. Our website is www.samsonoilandgas.com.
Marketing, Major Customers and Delivery Commitments
Markets for oil and natural gas are volatile
and are subject to wide fluctuations depending on numerous factors beyond our control, including seasonality, economic conditions,
foreign imports, political conditions in other energy producing countries, OPEC market actions, and domestic government regulations
and policies. Substantially all of our production is sold pursuant to agreements with pricing based on prevailing commodity prices,
subject to adjustment for regional differentials and similar factors. These contracts are generally set up on a month to month
basis and can be cancelled at any time by either party giving 30 days’ notice. We had no material delivery commitments as
of the date of this report.
Regulatory Environment
Our oil and gas exploration, production,
and related operations are subject to numerous and frequently changing federal, state, tribal and local laws and regulations governing
the discharge of materials into the environment or otherwise relating to environmental protection. These regulations relate to,
among other things, environmental and land-use matters, conservation, safety, pipeline use, drilling and spacing of wells, well
stimulation, transportation, and forced pooling and protection of correlative rights among interest owners. Environmental laws
and regulations may require the acquisition of certain permits prior to or in connection with our activities and operations. In
addition, they may restrict or prohibit the types, quantities, and concentration of substances that can be released into the environment,
including releases from drilling and production operations, and restrict or prohibit drilling or other operations that could impact
wetlands, endangered or threatened species or other protected areas or natural resources. Following is a summary of some key statutory
and regulatory programs that affect our operations.
Regulation of Oil and Gas
Certain regulations may govern the location
of wells, the method of drilling and casing wells, the rates of production or “allowables,” the surface use and restoration
of properties upon which wells are drilled, and the notification of surface owners and other third parties. Certain 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. We also are subject to various laws and regulations pertaining to Native American tribal surface ownership, Native
American oil and gas leases and other exploration agreements, fees, taxes, or other burdens, obligations, and issues unique to
oil and gas ownership and operations within Native American reservations.
Environmental and Land Use Regulation
A wide variety of environmental and land-use
regulations apply to companies engaged in the production and sale of oil and natural gas. These regulations have been changed
frequently in the past and, in general, these changes have imposed more stringent requirements that increase operating costs and/or
require capital expenditures to remain in compliance. Failure to comply with these requirements can result in civil and/or criminal
penalties and liability for non-compliance, clean-up costs and other environmental and natural resource damages. It also is possible
that unanticipated developments or changes in the law could require us to make environmental expenditures significantly greater
than those we currently expect.
Discharges to Waters. The
Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and comparable state statutes impose
restrictions and controls on the discharge of “pollutants,” which include dredge and fill material, produced waters,
various oil and natural gas wastes, including drilling fluids, drill cuttings, and other substances. Discharge of such pollutants
into wetlands, onshore (streams, rivers, etc.), coastal and offshore waters without appropriate permits is prohibited. These controls
generally have become more stringent over time, and it is possible that additional restrictions will be imposed in the future.
Violation of the Clean Water Act and similar state regulatory programs can result in civil, criminal and administrative penalties
for the unauthorized discharges of pollutants. Violations also put operators at risk of citizen lawsuits under the Clean Water
Act, seeking both enforcement of the Clean Water Act’s provisions and civil penalties and litigation costs. Operators may
also face substantial liability for the costs of removal or remediation associated with improper discharges of pollutants.
The Clean Water Act also regulates stormwater
discharges from industrial properties and construction sites, and requires permits and the implementation of site-specific Stormwater
Pollution Prevention Plans (“SWPPPs”), best management practices, training, and periodic monitoring of covered activities.
Certain operations also are required to develop and implement Spill Prevention, Control, and Countermeasure (“SPCC”)
plans, and in some circumstances, facility response plans to address potential oil and produced water spills. Certain exemptions
from some Clean Water Act requirements were created or broadened pursuant to the Energy Policy Act of 2005.
The Oil Pollution Act (“OPA”)
of 1990 places strict liability for oil spills on the "responsible party," which it defines for onshore facilities as
the owner or operator of a facility or pipeline. Strict liability means liability without fault. The OPA provides for the recovery
of cleanup and removal costs, and also recognizes as recoverable damages the loss of profits or impairment of earning capacity
due to the injury to natural resources caused by an oil spill. Further, a federal, state, foreign government, or Indian tribe
trustee may recover damages for injury to natural resources, including the reasonable cost of assessing the damage. Finally, federal
and state governments may also recover damages for the loss of taxes, royalties, rents, fees, or profits brought about by injury
to property or natural resources. We may be subject to strict liability under OPA for all or part of the costs of cleaning up
oil spills from our facilities and for natural resource damages. We have not, to our knowledge, been identified as a responsible
party under OPA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect
to their operation of those properties.
Safe Drinking Water Act – Regulation
of Hydraulic Fracturing. The federal Safe Drinking Water Act, or the “SDWA”, is the main federal law that authorizes
the United States Environmental Protection Agency (“EPA”) to set standards for drinking water quality and oversee
the states, localities, and water suppliers who implement those standards. The Underground Injection Control (UIC) Program under
the SDWA is responsible for regulating the construction, operation, permitting, and closure of injection wells that place fluids
underground. The Energy Policy Act of 2005 currently excludes hydraulic fracturing from regulation by the SDWA. Hydraulic fracturing
is a process that creates a fracture extending from a well bore into a low-permeability rock formation to enable oil or natural
gas to move more easily to a production well. Hydraulic fractures typically are created through the injection of water, sand and
chemicals into the rock formation.
The United States Congress has on multiple
occasions considered, and may in the future consider, legislation such as the Fracturing Responsibility and Awareness of Chemicals
Act, or the FRAC Act, to amend the SDWA to repeal this exemption. However, Congress has not taken any significant action on such
legislation. A version of the FRAC Act was introduced in 2017 but remains in the first stages of the legislative process. If enacted
as currently proposed, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass
hydraulic fracturing activities. Such a provision could require hydraulic fracturing operations to meet permitting and financial
assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations,
including disclosure of chemicals used in the fracturing process, and meet plugging and abandonment requirements. The FRAC Act’s
proposal to require the reporting and public disclosure of chemicals used in the fracturing process could 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. It is not possible to predict whether a future session of Congress
may act further on hydraulic fracturing legislation. Such legislation, if adopted, could establish additional regulation and permitting
requirements at the federal level.
In addition, in March 2010, at the request
of the U.S. Congress, EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that
hydraulic fracturing may have on drinking water resources. A progress report was released in December 2012. In May 2014, the EPA
indicated that as a first step, it would convene a stakeholder process to develop an approach to obtain information on chemical
substances and mixtures used in hydraulic fracturing. To gather information to inform EPA's proposal, the EPA issued an advance
notice of proposed rulemaking (ANPR) and initiated a public participation process to seek comment on the information that should
be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanism for obtaining this information.
EPA issued a draft report in June 2015, concluding that, although hydraulic fracturing activities have the potential to impact
drinking water resources through water withdrawals, spills, fracturing directly into such resources, underground migration of
liquids and gases, and inadequate treatment and discharge of wastewater, EPA did not find evidence that these mechanisms have
led to widespread, systemic impacts on drinking water resources in the United States. EPA finalized the report in December 2016,
after considering public comments on the draft report. The key findings remain largely unchanged from the draft report, although
EPA noted in the final report that data gaps and uncertainties limited EPA’s ability to fully assess the potential impacts
on drinking water resources locally and nationally.
Hydraulic fracturing currently is regulated
primarily at the state level. Colorado, Wyoming, Montana, North Dakota, Texas, and New Mexico recently enacted rules to regulate
certain aspects of hydraulic fracturing. These regulations generally require companies to disclose the chemicals used in hydraulic
fracturing operations, as well as the concentrations of those chemicals, on a well-by-well basis, either prior to or following
well completion, depending on which state’s regulations apply.
Air Emissions. Our operations
are subject to local, state and federal regulations governing emissions of air pollutants. Major sources of air pollutants are
subject to more stringent, federally based permitting requirements. Producing wells, natural gas plants and electric generating
facilities all emit volatile organic compounds (“VOCs”) and nitrous oxides in their normal operation. Civil
and administrative enforcement actions for failure to comply strictly with air pollution regulations or permits generally are
resolved by payment of monetary fines, performance of mitigation projects to offset excess emissions and the correction of any
identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation
of certain sources of emissions.
In April 2012, EPA issued regulations
specifically applicable to the oil and gas industry that among other things, requires operators to capture 95 percent of the VOC
emissions from natural gas wells that are hydraulically fractured. The reduction in VOC emissions is accomplished primarily through
the use of “reduced emissions completion” methods to capture natural gas that would otherwise escape into the air
or be combusted. EPA also issued regulations that set requirements for VOC emissions from several types of equipment, including
storage tanks, compressors, dehydrators, valves and connectors. In June 2016, EPA issued additional regulations specific to the
oil and gas industry adding methane standards for equipment and processes covered by the 2012 regulations. The 2016 final
regulations also add leak detection and repair (LDAR) requirements for equipment such as valves, connectors, pressure relief valves,
open-ended lines, access doors, flanges, crank case vents, pump seals or diaphragms, closed vent systems, compressors, separators,
dehydrators, thief hatches on storage tanks, and sweetening units at gas processing plants. On April 19, 2017, EPA announced its
intent to administratively reconsider the methane rules, staying a June 3, 2017 effective date for certain provisions—such
as the LDAR provisions—for 90 days. Environmental groups filed a petition to stop the administrative stay in the D.C. Circuit,
and on July 3, 2017, the D.C. Circuit granted relief for the petitioners, which had the impact of making the previously-stayed
rules effective. And on September 12, 2018, EPA proposed revisions to its 2016 methane regulations and sought comment on additional
areas for possible revision as part of its previously noted reconsideration of those rules. While EPA continues to reconsider
aspects of the methane rule, it will remain effective. These new and revised regulations, or the adoption of any other laws
or regulations restricting or reducing these emissions, will increase our operating costs.
Another regulatory development that may
impact our operations is EPA’s notice of finding and determination that emissions of carbon dioxide, methane, and other
greenhouse gases (“GHGs”) present an endangerment to human health and the environment. In response to that finding,
EPA has implemented GHG-related reporting, monitoring, and recordkeeping rules for petroleum and natural gas systems, among other
industries, and developed a Climate Action Plan, including a Methane Strategy which formed the basis for methane regulations issued
in June 2016. However, the Executive Office report calling for the Climate Action Plan and Methane Strategy was rescinded by President
Donald Trump by Executive Order 13,783, and the June 2016 methane regulations, though currently effective, are the subject of
proposed and possible further reconsideration and revision, as noted above. EPA has also solicited comment on a proposed two-year
stay of those methane rules. Those methane regulations remain in effect until possible revision or repeal by separate EPA rulemaking
in the future, which action is also likely to be challenged in the courts. While the U.S. Congress has considered, and may in
the future again consider, “cap and trade” legislation that would establish an economy-wide cap on emissions of GHGs
in the United States and could require major sources of GHG emissions to obtain GHG emission “allowances” to continue
their operations, the current administration’s decision to withdraw from the Paris Climate accords, announced on June 1,
2017, among other factors, makes passage of such legislation less likely in the near term. Any laws or regulations that
may be adopted to restrict or reduce emissions of GHGs would be likely to increase our operating costs and could also have an
adverse effect on demand for our production.
Waste Disposal. We
currently own or lease a number of properties that have been used for production of oil and natural gas for many years. Although
we believe the prior owners and/or operators of those properties generally utilized operating and disposal practices that met
applicable standards in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under
the properties we currently own or lease. State and federal laws applicable to oil and natural gas wastes have become more stringent
over time. Under new and existing laws, we could be required to remediate property, including groundwater, containing or impacted
by previously disposed wastes (including wastes disposed of or released by prior owners or operators) or to perform remedial well-plugging
operations to prevent future, or mitigate existing, contamination.
We may generate wastes, including “solid”
wastes and “hazardous” wastes that are subject to the federal Resource Conservation and Recovery Act, as amended (“RCRA”),
and comparable state statutes, although certain oil and natural gas exploration and production (“E&P”) wastes
currently are excluded from regulation as hazardous wastes under RCRA. On May 4, 2016, several environmental groups filed a declaratory
judgment action in federal district court for the District of Columbia seeking to compel the EPA to review the exemption of E&P
wastes under RCRA. The groups had previously filed a Notice of Intent (“NOI”) to Sue EPA in August 2015 for failure
to act on a 2010 petition to review the E&P RCRA exemption. In late December 2016, EPA entered into a consent decree with
the environmental groups and agreed to reconsider the Agency’s current treatment of E&P wastes. The District Court approved
the consent decree, binding EPA to a court-imposed timeline for determining how oil and gas wastes should be regulated under RCRA.
In April 2019, EPA concluded that it would not revise federal regulations on E&P waste management under the RCPA at this time.
This decision received criticism from environmental groups and both the federal government and state governments will likely continue
to receive pressure to further regulate E&P waste. If E&P waste becomes regulated as hazardous waste, then generators,
transporters, and owners/operators of disposal and treatment facilities will be subject to RCRA regulations at significant increased
cost. Thus, it is possible that certain wastes generated by our oil and natural gas operations that currently are excluded from
regulation as hazardous wastes may in the future be designated as hazardous wastes, and may therefore become subject to more rigorous
and costly management, disposal and clean-up requirements. State and federal oil and natural gas regulations also provide guidelines
for the storage and disposal of solid wastes resulting from the production of oil and natural gas, both onshore and offshore.
Superfund. Under the Comprehensive
Environmental Response, Compensation, and Liability Act of 1980, as amended, also known as CERCLA or the Superfund law, and similar
state laws, responsibility for the entire cost of cleaning up a contaminated site, as well as natural resource damages, can be
imposed upon current or former site owners or operators and any party who releases or threatens to release one or more designated
“hazardous substances” at the site, regardless of whether the original activities that led to the contamination were
lawful at the time of disposal. This is known as strict liability, meaning liability without fault. CERCLA also authorizes EPA
and, in some cases, third parties, to take actions in response to releases of hazardous substances into the environment and to
seek to recover from the potentially responsible parties the costs of such response actions. Although CERCLA generally excludes
petroleum from the definition of hazardous substances, in the course of our operations we may have generated and may generate
other wastes that fall within CERCLA’s definition of hazardous substances. We also may be an owner or operator of facilities
at which hazardous substances have been released by previous owners or operators. We may be subject to joint and several liability
as well as strict liability under CERCLA for all or part of the costs of cleaning up facilities at which such substances have
been released and for natural resource damages. Joint and several liability is liability that may be apportioned either among
two or more parties or to only one or a few select members of a group, making each party individually responsible for the entire
obligation. In some situations, we could be exposed to liability for clean-up costs and other damages as a result of conduct that
was lawful at the time it occurred or for the conduct of third parties at, or prior operators of, properties we have acquired.
This includes, in some circumstances, operators of properties in which we have an interest and parties that provide transportation
services for us. If exposed to joint and several liability, we could be responsible for more than our share of costs for remediating
a particular site, and potentially for the entire obligation, even where other parties were involved in the activity giving rise
to the liability. We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware
of any prior owners or operators of our properties that have been so identified with respect to their ownership or operation of
those properties.
BLM Venting and Flaring Proposed Rule.
On January 22, 2016 the Department of Interior’s Bureau of Land Management (BLM) released a proposed BLM Waste Prevention,
Production Subject to Royalties, and Resource Conservation proposed rule. Comment on the proposed rule closed on April 22, 2016,
and BLM issued its final rule on November 18, 2016. Petitions for judicial review of the rule were filed by industry groups and,
as a result, BLM postponed compliance dates for certain sections of the rule pending judicial review. The 2016 rule was designed
to replace the BLM's notice to lessees, NTL-4A, on venting and flaring at oil and gas facilities producing on federal and tribal
lands by dealing with provisions related to venting and flaring of oil and natural gas, leak detection, storage tanks, pneumatic
controllers and pumps, well maintenance and unloading, drilling and completions, and royalties. On September 18, 2018, however,
the BLM substantially revised its 2016 Waste Prevention Rule, which had also been the subject of multiple court challenges but
had become effective at certain points in the interim due to various court rulings. The 2018 rule essentially reverts the agency’s
regulation of venting and flaring to what existed before the 2016 Waste Prevention Rule was promulgated.
Potentially Material Costs Associated
with Environmental Regulation of Our Oil and Natural Gas Operations
Significant potential costs relating to
environmental and land-use regulations associated with our existing properties and operations include those relating to: (i) plugging
and abandonment of facilities; (ii) clean-up costs and damages due to spills or other releases; and (iii) penalties
imposed for spills, releases or non-compliance with applicable laws and regulations. As is customary in the oil and natural gas
industry, we typically have contractually assumed, and may assume in the future, obligations relating to plugging and abandonment,
clean-up and other environmental costs in connection with our acquisition of operating interests in fields, and these costs can
be significant.
Plugging and Abandonment Costs
Our operations are subject to stringent
abandonment and closure requirements imposed by the various regulatory bodies including the BLM and State agencies.
As described in our financial statements,
we have estimated the present value of our aggregate asset retirement obligations to be $3.6 million as of June 30, 2019. This
figure reflects the expected future costs associated with site reclamation, facilities dismantlement and plugging and abandonment
of wells. The discount rates used to calculate the present value varied depending on the estimated timing of the obligation, but
typically ranged between 4% and 13 %. Actual costs may differ from our estimates. Our financial statements do not reflect any
liabilities relating to other environmental obligations.
Competition
The oil and natural gas business is highly
competitive in the search for and acquisition of additional reserves and in the sale of oil and natural gas. Our competitors consist
of major and intermediate sized integrated oil and natural gas companies, independent oil and natural gas companies and individual
producers and operators. The principal competitive factors in the acquisition of undeveloped oil and gas leases include the availability
and quality of staff and data necessary to identify, investigate and purchase such leases, and the financial resources necessary
to acquire and develop such leases. Many of our competitors have substantially greater financial resources, and more fully developed
staffs and facilities than ours. In addition, the producing, processing and marketing of natural gas and crude oil are affected
by a number of factors that are beyond our control, the effect of which cannot be accurately predicted. See “Item 1A.
Risk Factors.” Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs
that allow us to remain competitive.
Employees
At October 15, 2019, we had 5 full-time
employees in Denver, Colorado, U.S.
Available Information
We are subject to the informational requirements
of the Securities Exchange Act of 1934 (the “Exchange Act”). We therefore file periodic reports, proxy
statements and other information with the Securities and Exchange Commission (the “SEC”). Such reports may be obtained
by visiting the Public Reference Room of the SEC at 100 F Street, NE, Washington, D.C. 20549, or by calling the SEC at 800-SEC-0330. In
addition, the SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information.
Financial and other information can also
be accessed on the investor section of our website at www.samsonoilandgas.com. We make available, free of charge, copies
of our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports
filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after filing
such material electronically or otherwise furnishing it to the SEC. Information on our website is not incorporated into this Form
10-K or our other securities filings and is not a part of them.
Our business, operating or financial
condition could be harmed due to any of the following risk factors. Accordingly, investors should carefully consider
these risks in making a decision as to whether to purchase, sell or hold our securities. In addition, investors should
note that the risks described below are not the only risks facing the Company. Additional risks not presently known
to us, or risks that do not seem significant today, may also impair our business operations in the future. When determining whether
to invest in our securities, you should also refer to the other information contained in this Annual Report on Form 10-K, including
our consolidated financial statements and the related notes, and in our other filings with the SEC. As an Australian
company, the rights of our shareholders may differ from the rights typically offered to shareholders of a company incorporated
in the United States.
Risks Related to Our Business, Operations and Industry
We are in breach of our Credit Agreement
and the terms governing our indebtedness may limit our ability to execute capital spending or to respond to other initiatives
or opportunities as they may arise.
As of the filing of this Form 10-K, we
are in breach of several of our financial covenants under the Credit Agreement. Due to our breach of certain financial covenants
under the Credit Agreement, the Lender may declare all amounts and obligations of the Company due and payable immediately. We
are currently negotiating a waiver from our Lender for this breach. As of the filing of this Form 10-K, we have not received a
waiver, and, as such, we have classified the total amount of outstanding debt of $33.5 million as a current liability and we expensed
$1.4 million of deferred loan fees that were recorded as a debt discount. If we do not succeed in renegotiating the Credit Agreement
or acquire sufficient funds to repay the Lender, the Lender could declare an event of default and foreclose on some or all of
our assets and/or accelerate the full amount of the $33.5 million loan plus all accrued and unpaid interest, prepayment penalties,
fees and other lender costs and expenses. In any of these scenarios we may be forced to cease operations or seek bankruptcy protection,
in which event our shareholders could lose their entire investment.
Even if we are successful in renegotiating
our Credit Agreement, it is unlikely that we would obtain substantially better terms than under the existing Credit Agreement.
Under the terms of our Credit Agreement, we are subject to very stringent financial covenants and obligations. Any decline in
cash flow from our oil and natural gas reserves, if continued for any extended period, would very likely result in us having to
make mandatory payments to pay down amounts owed to a level that is in compliance with the Credit Agreement. A required repayment
of the Credit Agreement could be significant. Additionally, the terms of the Credit Agreement restrict our ability to incur additional
debt, which limits our ability to obtain additional funding.
The Credit Agreement contains covenants
and other restrictions that are highly unfavorable to us, including those customary for oil and gas credit facilities, such as
limitations on debt, liens, dividends, voluntary redemptions of debt, investments, and asset sales. The Credit Agreement requires
us to maintain compliance with certain financial tests and financial covenants. If future debt financing is not available to us
when required as a result of limited access to the credit markets or otherwise, or is not available on acceptable terms, we may
be unable to invest needed capital for our continuing drilling and exploration activities, take advantage of business opportunities,
respond to competitive pressures or refinance maturing debt. In addition, we may be forced to sell some of our assets on an untimely
basis or under unfavorable terms. Any of these results could have a material adverse effect on our operating results and financial
condition.
We are subject to a pending administrative
action brought by the Commission under North Dakota Century Code Chapters 38-08 and 28-32 (“NDIC”), which could result
in us having to pay a substantial fee.
On September 4, 2019, the Company received
an administrative action brought by the Commission under North Dakota Century Code Chapters 38-08 and 28-32 (“NDIC). The
notice makes claim to the status of certain shut-in wells and other location items operated by Samson. Samson submitted its formal
response in September 2019 and has met with the NDIC concerning this matter and has presented the Company’s plan to address
the administrative action. No final resolution or settlement has been entered into as of the filing of this report and the Company
cannot reasonably estimate the amount of any potential penalties or fees that may be assessed against the Company. Any amount
assessed against the Company is likely to be significant and, once assessed, could cause the Lender to declare an event of default
and foreclose on some or all of our assets and/or accelerate the full amount of the $33.5 million loan plus all accrued and unpaid
interest, prepayment penalties, fees and other lender costs and expenses. In any of these scenarios we may be forced to cease
operations or seek bankruptcy protection, in which event our shareholders could lose their entire investment.
Our Credit Agreement is subject
to variable rates of interest which could negatively impact us.
Borrowings under our Credit Agreement
are at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations
on the variable rate indebtedness would increase even though the amount borrowed remained the same, and the Company’s income
and cash flows would decrease.
Our auditors and management have
expressed substantial doubt about our ability to continue as a going concern.
As disclosed in the financial statements,
we incurred a net loss of $7.2 million for the year ended June 30, 2019. As of that date, our total current liabilities of $43.3
million exceed our total current assets of $4.8 million. Additionally, we are in violation of our debt covenant and have suffered
recurring losses from operations. We believe these circumstances raise substantial doubt about our ability to continue as a going
concern.
If we are not able to generate the funds
needed to cover our ongoing expenses, then we may be forced to cease operations or seek bankruptcy protection, in which event
our shareholders could lose their entire investment.
Declines in oil or gas prices have
and will materially adversely affect our Revenues.
Our financial condition and results of
operations depend in large part upon the prices of oil and natural gas and the costs of finding, acquiring, developing and producing
reserves. As seen in recent years, prices for oil and natural gas are subject to extreme fluctuations in response to changes in
supply, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide political
instability (especially in the Middle East and other oil producing regions), the foreign supply of oil and gas, the price of foreign
imports, the level of drilling activity, the level of consumer product demand, government regulations and taxes, the price and
availability of alternative fuels, speculating activities in the commodities markets, and the overall economic environment. Our
operations are substantially adversely impacted as oil prices decline. Lower prices dramatically affect revenues from drilling
operations. Drilling of new wells, development of leases and acquisitions of new properties are also adversely affected and limited.
As a result, our potential revenues from operations as well as the proved reserves may substantially decrease from levels achieved
during periods when oil prices were much higher. There can be no assurances as to the future prices of oil or gas. A substantial
or extended decline in oil or gas prices would have a material adverse effect on our financial position, results of operations,
quantities of oil and gas that may be economically produced, and access to capital. Oil and natural gas prices have historically
been and are likely to continue to be volatile.
This volatility makes it difficult to
estimate with precision the value of producing properties in acquisitions and to budget and project the return on exploration
and development projects involving our oil and gas properties. In addition, unusually volatile prices often disrupt the market
for oil and gas properties, as buyers and sellers have more difficulty agreeing on the purchase price of properties.
Our ongoing infill development drilling
program is critical to our future success
We have embarked on an infill development
drilling program at the Gonzales location in the Home Run Field. The drilling program is designed to drill two horizontal laterals
from the existing well bore. The existing development consists of a single 5,300 ft. lateral drilled with a single 640-acre spacing
unit. The two new well bores will be directionally drilled to access the balance of the 640-acre spacing unit. The ability to
drill out of an existing wellbore made the economics of these developmental wells more attractive due to the ability to use existing
surface facilities associated with the existing well. While we believe that these two lateral wells are likely to be completed
and achieve commercial levels of production, oil drilling of any kind carries numerous risks and uncertainties that cannot be
disregarded.
We plan to drill a total of 8 similar
lateral wells to the Gonzales wells within the next 12 months. We have identified a total of 26 Contingent resource locations
for future drilling. While we believe that our recent refinancing will provide sufficient working capital to initiate the development
drilling program, our ability to drill subsequent wells will depend upon the success of our earlier developmental drilling and
the additional capital available to us as a result of that success. There can be no assurance that the earlier developmental drilling
will achieve the success needed to complete the entire planned drilling program. Additionally, if the lender declares an event
of default due to our current violations of the Credit Agreement and forecloses on some or all of our assets and/or accelerate
the full amount of the $33.5 million loan plus all accrued and unpaid interest, prepayment penalties, fees and other lender costs
and expenses, we may be forced to cease our drilling program and/or sell our Gonzales location. If we cease our drilling program,
we may be forced to cease all operations or seek bankruptcy protection, in which event our shareholders could lose their entire
investment.
Reserve estimates are imprecise
and subject to revision.
Estimates of oil and natural gas reserves
are projections based on available geologic, geophysical, production and engineering data. There are uncertainties inherent
in the manner of producing, and the interpretation of, this data as well as in the projection of future rates of production and
the timing of development expenditures. Estimates of economically recoverable oil and natural gas reserves and future net cash
flows necessarily depend upon a number of factors including:
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the quality and quantity of available
data;
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the interpretation of that data;
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our ability to access the capital required
to develop proved undeveloped locations;
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the accuracy of various mandated economic
assumptions; and
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the judgment of the engineers preparing
the estimate.
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Actual future production, natural gas
and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil
reserves will likely vary from our estimates. Any significant variance could materially affect the quantities and value of our
reserves. Our reserves may also be susceptible to drainage by operators on adjacent properties. We are required to adjust
our estimates of proved reserves to reflect production history, results of exploration and development and prevailing gas and
oil prices. These reserve reports are necessarily imprecise and may significantly vary depending on the judgment of
the reservoir engineering consulting firm.
Investors should not construe the present
value of future net cash flows as the current market value of the estimated oil and natural gas reserves attributable to our properties. The
estimated discounted future net cash flows from proved reserves are based on the
average of the sales price on the first day of each month in the applicable year, with costs determined as of the date of the
estimate, in accordance with applicable regulations, even though actual future prices and costs may be materially higher
or lower. As a result of significant recent declines in commodity
prices, such average sales prices are significantly in excess of more recent prices. Unless commodity prices or reserves increase,
the estimated discounted future net cash flows from our proved reserves would generally be expected to decrease as additional
months with lower commodity sales prices will be included in this calculation in the future. Factors that will affect actual
future net cash flows include:
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the amount and timing of actual production;
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the price for which that oil and gas production
can be sold;
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supply and demand for oil and natural
gas;
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curtailments or increases in consumption
by natural gas and oil purchasers; and
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changes in government regulations or taxation.
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As a result of these and other factors,
we will be required to periodically reassess the amount of our reserves, which reassessment may require us to recognize a write–down
of our oil and gas properties, as occurred at June 30, 2016 and June 30, 2015. We have not recorded any write downs of our oil
and gas properties for the years ended June 30, 2019 and 2018.
Additionally, in recent years, there has
been increased debate and disagreement over the classification of reserves, with particular focus on proved undeveloped reserves.
The interpretation of SEC rules regarding the classification of reserves and their applicability in different situations remain
unclear in many respects. Changing interpretations of the classification standards of reserves or disagreements with our interpretations
could cause us to write-down reserves.
Unless reserves are replaced as
they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition
and results of operations.
Producing oil and reservoirs are generally
characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of
decline will change if production from existing wells declines in a different manner than we estimated. The rate can change due
to other circumstances as well. Our future reserves and production and, therefore, our cash flows and income, are highly dependent
on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable
reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production
at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations.
Our development and exploration
operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which
could lead to a loss of properties and a decline in our production, profitability and reserves.
Our industry is capital intensive. We
expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production
and acquisition of crude oil and natural gas reserves. To date, we have financed capital expenditures primarily with cash generated
by operations, capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing
similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including:
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the amount of crude oil and natural gas we are able to produce from
existing wells;
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our ability to acquire, locate and produce new reserves;
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the prices at which crude oil and natural gas are sold; and
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the costs to produce crude oil and natural gas.
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If our revenues decrease as a result of
lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources would increase.
If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. Our Credit
Agreement restricts our ability to incur additional debt. If we raise funds through the incurrence of debt, the risks we face
with respect to our indebtedness would increase and we would incur additional interest expense. There can be no assurance as to
the availability or terms of any additional financing. Our inability to obtain additional financing, or sufficient financing on
favorable terms, would adversely affect our financial condition and profitability. We have, in the past, funded a portion of our
capital expenditures with proceeds from the sale of our properties, such as the sale of a portion of the North Stockyard properties
to Slawson Exploration Company in August 2013. More recent sales of properties have been used to repay debt or provide working
capital.
Petroleum exploration, drilling
and development involve substantial business risks.
The business of exploring for and developing
oil and gas properties involves a high degree of business and financial risk, and thus a substantial risk of investment loss that
even a combination of experience, knowledge and careful evaluation may not be able to overcome. In addition, oil and gas drilling
and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond
our control. These factors include:
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unexpected drilling conditions;
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unexpected geological formations including
abnormal pressure or irregularities in formations;
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equipment failures or accidents;
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adverse changes in prices;
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ability to fund capital necessary to develop
exploration properties and producing properties;
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shortages in experienced labor; and
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shortages or delays in the delivery of
equipment, including equipment needed for drilling, fracture stimulating and completing wells.
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Acquisition and completion decisions generally
are based on subjective judgments and assumptions that are speculative. It is impossible to predict with certainty the production
potential of a particular property or well. Furthermore, the successful completion of a well does not ensure a profitable return
on the investment. A variety of geological, operational, or market–related factors, including, but not limited to, unusual
or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution
and other environmental risks, shortages or delays in the viability of drilling rigs and the delivery of equipment, loss of circulation
of drilling fluids or other conditions may substantially delay or prevent completion of any well or otherwise prevent a property
or well from being profitable. A productive well may become uneconomic if water or other substances are encountered that impair
or prevent the production of oil or natural gas from the well.
If our access to markets for our
oil and gas production is restricted, it could negatively impact our production, our income and ultimately our ability to retain
our leases. Our ability to sell oil and natural gas and receive market prices for our oil and natural gas may be adversely affected
by pipeline and gathering system capacity constraints.
Market
conditions or the unavailability of satisfactory transportation arrangements may hinder our access to oil and gas markets or delay
our production. The availability of a ready market for our oil and gas production depends on a number of factors, including the
demand for and supply of oil and gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market
our production depends in part on the availability and capacity of gathering systems, pipelines and processing facilities owned
and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. Our
productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other
means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or gas may have
several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a
lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended
time, possibly causing us to lose a lease due to lack of production. We currently own an interest in several wells that
are capable of producing but may have their production curtailed from time to time at some point in the future pending gas sales
contract negotiations, as well as construction of gas gathering systems, pipelines, and processing facilities.
A significant portion of our producing
properties are located in geographic areas that are vulnerable to extreme seasonal weather, as well as additional environmental
regulation and production constraints.
A significant portion of our operating
properties are located in the Rocky Mountain region. As a result, the success of our operations and our profitability
may be disproportionately exposed to the impact of adverse conditions unique to that region. Such conditions can include
extreme seasonal weather, which could limit our ability to access our properties or otherwise delay or curtail our operations. Also,
there could be delays or interruptions of production from existing or planned new wells by significant governmental regulation,
transportation capacity constraints, curtailment of production, interruption of transportation, or fluctuations in prices of oil
and natural gas produced from the wells in the region.
In addition, some of the properties that
we may develop for production are located on federal lands where drilling and other related activities cannot be conducted during
certain times of the year due to environmental considerations. This could adversely affect our ability to operate in those
areas and may intensify competition during certain times for drilling rigs, oil field equipment, services, supplies and qualified
personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay
our operations and materially increase our operating and capital costs, particularly if our exploration or development activities
on federal lands, or our production from federal lands increases.
Our business involves significant
operating risks that could adversely affect our production and could be expensive to remedy. We do not have insurance to cover
all of the risks that we may face.
Our operations are subject to all the
risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural
gas wells, including:
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cratering and explosions;
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pipe failures and ruptures;
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pipeline accidents and failures;
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mechanical and operational problems that
affect production;
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formations with abnormal pressures;
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uncontrollable flows of oil, natural gas,
brine or well fluids;
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releases of contaminants into the environment;
and
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failure of subcontractors to perform or
supply goods or services or personnel shortages.
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These industry operating risks can result
in injury or loss of life, severe damage to or destruction of property, damage to natural resources and equipment, pollution or
other environmental damage, clean–up responsibilities, regulatory investigation and penalties, and suspension of operations,
any of which could result in substantial losses. In addition, maintenance activities undertaken to reduce operational risks can
be costly and can require exploration, exploitation and development operations to be curtailed while those activities are being
completed. We may also be subject to damage claims by other oil and gas companies.
We do not maintain insurance in amounts
that cover all of the losses to which we may be subject, and some risks, such as pollution and environmental risks, are not generally
fully insurable. Our insurance policies and contractual rights to indemnity may not adequately cover our losses, and we do
not have access to insurance coverage or rights to indemnity for all risks. If a significant accident or other event occurs and
is not fully covered by insurance or contractual indemnity, it could adversely affect our financial position and results of operations.
Other business risks also include the
risk of cyber security breaches. If management’s systems for protecting against cyber security risk prove not to be sufficient,
the company could be adversely affected such as by having its business systems compromised, its proprietary information altered,
lost or stolen, or its business operations disrupted.
Competition in the oil and natural
gas industry is intense, which may adversely affect our ability to succeed.
The oil and natural gas industry is highly
competitive, and we compete with other companies that are significantly larger and have greater resources. Many of these
companies not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and
other products on a regional, national or worldwide basis. These companies may be able to pay higher prices for productive
oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties
and prospects than our financial or human resources permit. In addition, these competitors may have a greater ability to
continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may also
be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can. 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 this highly competitive environment.
We may not be able to keep pace
with technological developments in our industry.
The oil and gas industry is characterized
by rapid and significant technological advancements and introductions of new products and services using new technologies. As
others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us
to implement those new technologies at substantial cost. In addition, other oil and gas companies may have greater financial,
technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement
new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on
a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete
or if we are unable to use the most advanced commercially available technology, our business, financial condition and results
of operations could be materially adversely affected.
We are subject to complex environmental
federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.
Our exploration, development, and production
operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations
have increased the costs to plan, design, drill, install, operate and reclaim oil and natural gas wells and related production
facilities. Under these laws and regulations, we also could be held liable for personal injuries, property damage, clean-up costs,
and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of operations
and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased
in recent years, and environmental organizations have opposed, with some success, certain drilling projects.
The environmental laws and regulations
to which we are subject:
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require applying for and receiving permits before drilling
commences;
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restrict the types, quantities
and concentration of substances that can be released into the environment in connection
with drilling and production activities;
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limit or prohibit drilling activities on certain lands
lying within wilderness, wetlands, and other protected or sensitive areas; and
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impose substantial liabilities for unpermitted releases
and emissions resulting from our operations.
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If any of our operations require federal
permits or otherwise involve a “major federal action” that significantly impacts the environment, we may be required
to prepare an environmental impact statement (“EIS”) pursuant to the National Environmental Policy Act to obtain the
federal permits necessary to proceed with the development of certain oil and gas properties. There can be no assurance that we
will obtain all necessary permits and, if obtained, that the costs associated with completing the EIS and obtaining such permits
will not exceed those that previously had been estimated. It is possible that the costs and delays associated with compliance
with such requirements could cause us to delay or abandon the further development of certain properties.
Changes in environmental laws and regulations
occur frequently, and any changes that result in more stringent or costly waste handling, emission controls, storage, transportation,
disposal or cleanup requirements could require us to make significant expenditures to maintain compliance and may otherwise have
a material adverse effect on our earnings, results of operations, competitive position or financial condition. For example, because
of its potential effect on ground water, seismic activity, and local communities, hydraulic fracturing and associated water disposal
currently are the subject of regulatory scrutiny, negative press, and proposed legislative changes, particularly at the state
and local level. Hydraulic fracturing is a process that creates a fracture extending from a well bore into a low-permeability
rock formation to enable oil or natural gas to move more easily to a production well. Hydraulic fractures typically are created
through the injection of water, sand and chemicals into the rock formation. Legislative and regulatory efforts to further regulate
this process may render permitting and compliance requirements more stringent for hydraulic fracturing, which may limit or prohibit
use of the process. While none of our properties are expected to be subject to any such changes, there is no assurance that this
will remain the case.
President Donald Trump’s election
and inauguration in January 2017 has resulted in uncertainty with respect to the future environmental regulation of the oil and
natural gas industry. This uncertainty may affect how the oil and gas industry is regulated, and could also increase the level
of public interest in environmental protection and safety concerns and may result in new or different pressures being exerted.
For example, President Donald Trump issued Executive Order 13,783 (March 28, 2017) entitled “Promoting Energy Independence
and Economic Growth.” The stated goal is to “suspend, revise, or rescind [regulations] that unduly burden the development
of domestic energy resources beyond the degree necessary to protect the public interest.” This Executive Order identified
a number of Obama-era Clean Air Act and Clean Water Act regulations for reconsideration by the EPA. Public interest groups may
increase their use of litigation as a means to require more stringent regulation of the oil and natural gas industry. As noted,
there may be heightened litigation regarding any revision or rescission of these rules, resulting in uncertainty for the regulated
community.
Over the years, we have owned or leased
numerous properties for oil and gas activities upon which petroleum hydrocarbons or other materials may have been released by
us or predecessor property owners or lessees who were not under our control. Under applicable environmental laws and regulations,
including CERCLA, RCRA and analogous state laws, we could be held strictly liable for the removal or remediation of any such previously
released contaminants at such locations, in some cases regardless of whether we were responsible for the release or whether the
operations were compliant with applicable regulations or standard practice within the industry at the time they were performed.
Our operations also are subject to wildlife-protection
laws and regulations such as the Migratory Bird Treaty Act (MBTA). For example, some oil companies have been charged under the
MBTA with killing migratory birds that have died in reserve pits in North Dakota, where we conduct operations. Reserve pits are
used during oil and gas drilling operations and can pose an attractive nuisance to migratory birds. During the cleanup phase of
a reserve pit, North Dakota requires companies to cover the pit with a net if it is open for more than 90 days to reduce the risk
of bird mortality.
The federal Clean Water Act and analogous
state laws impose strict controls against the unpermitted discharge of pollutants and fill material, including spills and leaks
of crude oil and other substances from our operations. The Clean Water Act also requires approval and/or permits prior to construction,
where construction will disturb wetlands or other waters of the U.S. The Clean Water Act also regulates storm water run-off from
crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control,
and Countermeasure ("SPCC") plan requirements of the Clean Water Act dictate use of appropriate secondary containment
loadout controls, piping controls, berms, and other measures to help prevent the contamination of navigable waters in the event
of a petroleum hydrocarbon spill, rupture, or leak, and that these measures be included in a written SPCC plan that is updated
periodically.
The BLM had issued a final rule regulating
hydraulic fracturing in 2015 (the “HF Rule”), and though never effective due to numerous court challenges, the HF
Rule was rescinded by final rule of BLM published in the Federal Register December 28, 2017. That rescission was effected as part
of President Trump’s goal to reduce the burden of federal regulations that hinder economic growth and energy development,
and Department of Interior Secretarial Order No. 3349, “Promoting Energy Independence and Economic Growth.”
Additionally, BLM also published a final
rule on September 18, 2018, substantially revising its 2016 Waste Prevention Rule, which was also the subject of multiple court
challenges, and had become effective at certain points in the interim due to various court rulings. The final rule essentially
reverts the agency’s regulation of venting and flaring to what existed before the 2016 Waste Prevention Rule was promulgated.
Despite the noted BLM rescissions and
revisions of prior hydraulic fracturing regulations at the federal level, EPA in 2014 and 2017 issued technical permitting guidance
under the SDWA for the underground injection of liquids from hydraulically fractured (and other) wells where diesel fuels are
used which guidance remains the agency’s current policy. Although Samson does not use diesel fuel in its hydraulic fracturing
activities, continued EPA adherence to this guidance may create duplicative federal and state requirements in certain jurisdictions
where Samson operates.
In April 2012, EPA issued regulations
specifically applicable to the oil and gas industry that among other things, requires operators to capture 95 percent of the VOC
emissions from natural gas wells that are hydraulically fractured. The reduction in VOC emissions is accomplished primarily through
the use of “reduced emissions completion” methods to capture natural gas that would otherwise escape into the air
or be combusted. EPA also issued regulations that set requirements for VOC emissions from several types of equipment, including
storage tanks, compressors, dehydrators, valves and connectors. In June 2016, EPA issued additional regulations specific to the
oil and gas industry adding methane standards for equipment and processes covered by the 2012 regulations. The 2016 final
regulations also add leak detection and repair (LDAR) requirements for equipment such as valves, connectors, pressure relief valves,
open-ended lines, access doors, flanges, crank case vents, pump seals or diaphragms, closed vent systems, compressors, separators,
dehydrators, thief hatches on storage tanks, and sweetening units at gas processing plants. On April 19, 2017, EPA announced its
intent to administratively reconsider the methane rules, staying a June 3, 2017 effective date for certain provisions—such
as the LDAR provisions—for 90 days. Environmental groups filed a petition to stop the administrative stay in the D.C. Circuit,
and on July 3, 2017, the D.C. Circuit granted relief for the petitioners, which had the impact of making the previously-stayed
rules effective. And on September 12, 2018, EPA proposed revisions to its 2016 methane regulations and sought comment on additional
areas for possible revision as part of its previously noted reconsideration of those rules. While EPA continues to reconsider
aspects of the methane rule, it will remain effective. These new and revised regulations, or the adoption of any other laws
or regulations restricting or reducing these emissions, will increase our operating costs.
Another regulatory development that may
impact our operations is EPA’s notice of finding and determination that emissions of carbon dioxide, methane, and other
GHGs present an endangerment to human health and the environment. In response to that finding, EPA has implemented GHG-related
reporting, monitoring, and recordkeeping rules for petroleum and natural gas systems, among other industries, and developed a
Climate Action Plan, including a Methane Strategy which formed the basis for methane regulations issued in June 2016. However,
the Executive Office report calling for the Climate Action Plan and Methane Strategy was rescinded by President Trump by Executive
Order 13,783, and the June 2016 methane regulations, though currently effective, are the subject of proposed and possible further
reconsideration and revision, as noted above. EPA has also solicited comment on a proposed two-year stay of those methane rules.
Those methane regulations remain in effect until possible revision or repeal by separate EPA rulemaking in the future, which action
is also likely to be challenged in the courts. While the U.S. Congress has considered, and may in the future again consider, “cap
and trade” legislation that would establish an economy-wide cap on emissions of GHGs in the United States and could require
major sources of GHG emissions to obtain GHG emission “allowances” to continue their operations, the current administration’s
decision to withdraw from the Paris Climate accords, announced on June 1, 2017, among other factors, makes passage of such legislation
less likely in the near term. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would
be likely to increase our operating costs and could also have an adverse effect on demand for our production.
Finally, another federal regulation affecting
hydraulic fracturing activities is the Occupational Safety and Health Administration’s (OSHA) final rule on Occupational
Exposure to Respirable Crystalline Silica, which includes specific requirements applicable to hydraulic fracturing operations
in the oil and gas industry published on March 25, 2016. Hydraulic fracturing operations in the oil and gas industry are regulated
under OSHA’s “general industry” regulations. The final silica rule establishes a new permissible exposure limit
(PEL) of 50 micrograms of respirable crystalline silica per cubic meter of air (50 µg/m3) as an 8-hour, time-weighted average
in all industries covered by the rule. The rule also includes other employee-protection provisions, such as requirements for exposure
assessment, methods for controlling exposure, respiratory protection, medical surveillance, hazard communication, and recordkeeping.
Implementation of this rule could increase operating costs. The final rule took effect on June 23, 2016, after which industries
have one to five years to comply with most requirements.
We depend on key members of our management team.
The loss of key members of our management
team could reduce our competitiveness and prospects for future success. We do not have any “key man” insurance policies
for our Chief Executive Officer; or any other executive. Our exploratory drilling success and the success of other activities
integral to our operations will depend, in part, on our ability to attract and retain experienced management professionals. Competition
for these professionals is extremely intense.
Instability in the global financial
system may have impacts on our liquidity and financial condition that we currently cannot predict.
Instability in the global financial system
may have a material impact on our liquidity and our financial condition. We previously relied upon access to both our revolving
credit facility and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by the cash
flow from operations or other sources. Our ability to access the capital markets or borrow money may be restricted or made more
expensive at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react
to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future.
The economic situation could have an impact on our lenders or customers, causing them to fail to meet their obligations to us,
and on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments.
Also, market conditions, including with respect to commodity prices such as for oil and gas, could have an impact on our oil and
gas derivative instruments if our counterparties are unable to perform their obligations or seek bankruptcy protection. Additionally,
challenges in the economy have led and could further lead to reductions in the demand for oil and gas, or further reductions in
the prices of oil and gas, or both, which could have a negative impact on our financial position, results of operations and cash
flows.
Failure to adequately protect critical
data and technology systems could materially affect our operations.
Information technology solution failures,
network disruptions and breaches of data security could disrupt our operations by causing delays or cancellation of customer orders,
impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee
or our information, or damage to our reputation. There can be no assurance that a system failure or data security breach will
not have a material adverse effect on our financial condition, results of operations or cash flows.
Risks Related to Our Securities
Currency fluctuations may adversely
affect the price of our American Depository Shares (“ADSs”) relative to the price of our ordinary shares.
The price of our ordinary shares is quoted
in Australian dollars and the price of our ADSs is quoted in U.S. dollars. Movements in the Australian dollar/U.S.
dollar exchange rate may adversely affect the U.S. dollar price of our ADSs and the U.S. dollar equivalent of the price of our
ordinary shares. During the year ended June 30, 2019, the Australian dollar has, as a general trend, maintained its value against
the U.S. dollar, but remains volatile. As the Australian dollar weakens against the U.S. dollar, the U.S. dollar price of
the ADSs could decline correspondingly, even if the price of our ordinary shares in Australian dollars increases or remains unchanged.
In the unlikely event that dividends are payable, we will likely calculate and pay any cash dividends in Australian dollars and,
as a result, exchange rate movements will affect the U.S. dollar amount of any dividends holders of our ADSs will receive from
The Bank of New York Mellon, our depositary. While we would ordinarily expect such variances to be adjusted by inter-market arbitrage
activity that accounts for the differences in currency values, there can be no assurance that such activity will in fact be an
efficient offset to this risk.
The prices of our ordinary shares
and ADSs have been and will likely continue to be volatile.
Trading in our ordinary shares is currently
suspended on the ASX. The trading prices of our ordinary shares on the ASX and of our ADSs on the OTCQB have been volatile and
will likely to continue to be volatile (in the case of our ordinary shares, assuming the resumption of trading on the ASX). Other
natural resource companies have experienced similar volatility for their shares, leading us to expect that the results of exploration
activities, the price of oil and natural gas, future operating results, market conditions for natural resource shares in general,
and other factors beyond our control, could have a significant adverse or positive impact on the market price of our ordinary
shares and ADSs. We also believe that this volatility creates opportunities for arbitrage trading between the ASX and OTCQB markets.
While we recognize that arbitrage trading is an appropriate market mechanism to eliminate the differences between different trading
markets resulting from the combination of volatile stock prices and inter-market inefficiencies, some of our shareholders may
not be in a position to take advantage of the potential profits available to arbitrageurs in such cases.
Our ADSs may be deemed a “penny
stock,” which makes it more difficult for our investors to sell their shares.
As a result of our delisting from the
NYSE American our ADSs may now be subject to the “penny stock” rules adopted under Section 15(g) of the Exchange Act.
The penny stock rules generally apply to companies whose common stock is not listed on a national securities exchange and trades
at less than $5.00 per share, other than companies that have had average revenue of at least $6,000,000 for the last three years
or that have net tangible assets worth of at least $2,000,000 if the company has been operating for three or more years. These
rules require, among other things, that brokers who trade penny stock to persons other than “established customers”
complete certain documentation, make suitability inquiries of investors and provide investors with certain information concerning
trading in the security, including a risk disclosure document and quote information under certain circumstances. Many brokers
have decided not to trade penny stocks because of the requirements of the penny stock rules and, as a result, the number of broker-dealers
willing to act as market makers in such securities is limited. If we remain subject to the penny stock rules for any significant
period, it could have an adverse effect on the market, if any, for our securities. If our securities are subject to the penny
stock rules, investors will find it more difficult to dispose of our securities. If we identify a viable buyer and sell Foreman
Butte Project, we will likely have net tangible assets in excess of $2,000,000 and would therefore no longer be subject to the
penny stock rules.
We may issue shares of blank check
preferred stock in the future that may adversely impact rights of holders of our ordinary shares and ADSs.
Our corporate constitution authorizes
us to issue an unlimited amount of “blank check” preferred stock. Accordingly, our board of directors will have
the authority to fix and determine the relative rights and preferences of preferred shares, as well as the authority to issue
such shares, without further shareholder approval. As a result, our board of directors could authorize the issuance of a
series of preferred stock that would grant to holders preferred rights to our assets upon liquidation, the right to receive dividends
before dividends are declared to holders of our common stock, and the right to the redemption of such preferred shares, together
with a premium, prior to the redemption of the common stock. To the extent that we do issue such additional shares of preferred
stock, the rights of ordinary share and ADS holders could be impaired thereby, including, without limitation, dilution of their
ownership interests in us. In addition, shares of preferred stock could be issued with terms calculated to delay or prevent
a change in control or make removal of management more difficult, which may not be in the interest of holders of ordinary shares
or ADSs.
Our ADSs are required to trade on
the over-the-counter market and therefore selling the ADS could be more difficult.
As our ADSs on the over-the-counter market,
selling them may be difficult due to reduced trading volume, transaction delays, and reduced security analyst coverage. In addition,
as the ADSs have been delisted from the NYSE American, additional regulatory burdens are imposed upon broker-dealers that may
discourage them from effecting transactions in such securities, as discussed in greater detail below, further limiting the liquidity
of the ADSs. These factors could result in lower prices and larger spreads in the bid and ask prices for our securities. The delisting
from the NYSE American exchange and continued or further declines in our share price could also greatly impair our ability to
raise additional necessary capital through equity or debt financing and could significantly increase the ownership dilution to
shareholders caused by our issuing equity in financing or other transactions. Any such limitations on our ability to raise debt
and equity capital could prevent us from making future investments and satisfying maturing debt commitments.
We report as a U.S. domestic issuer,
which means increased compliance costs notwithstanding continued eligibility for certain NYSE American rule waivers.
On July 1, 2011, we commenced reporting
as a U.S. domestic issuer instead of as a “foreign private issuer” as we had in prior years. Accordingly, we are now
required to comply with the reporting and other requirements imposed by U.S. securities laws on U.S. domestic issuers, which are
more extensive than those applicable to foreign private issuers. We are also required to prepare financial statements in accordance
with U.S. GAAP in addition to our financial statements prepared in accordance with IFRS pursuant to ASX requirements. Generating
two separate sets of financial statements is a substantial burden that imposes significant administrative and accounting costs
on us. As a result of becoming a U.S. domestic issuer, the legal, accounting, regulatory and compliance costs to us under U.S.
securities laws are significantly higher than those that were incurred by us as a foreign private issuer.
We do not expect to pay dividends
in the foreseeable future. As a result, holders of our ordinary shares and ADSs must rely on appreciation for any return on their
investment.
We do not anticipate paying cash dividends
on our ordinary shares in the foreseeable future. Accordingly, holders of our ordinary shares and ADSs will have to rely on capital
appreciation, if any, to earn a return on their investment in our ordinary shares.
The trading prices of our ADSs may be adversely affected
by short selling.
“Short selling” is the sale
of a security that the seller does not own, including a sale that is completed by the seller’s delivery of a “borrowed”
security (i.e. the short seller’s promise to deliver the security). Short sellers make a short sale because
they believe that they will be able to buy the stock at a lower price than their sales price. Significant amounts of short selling,
or the perception that a significant amount of short sales could occur, could depress the market price of our ADSs. The
price decline could be exacerbated if sufficient “naked short selling” occurs, which is the practice by which
short sellers place short sell orders for shares without first borrowing the shares to be sold, or without having first adequately
located such shares and arranged for a firm contract to borrow such shares prior to the delivery date set to close the sale.
The result is an artificial deluge into the market of shares for sale – shares that the seller does not own and has not
even borrowed. Although there are regulations in the United States designed to address abusive short selling, the regulations
may not be adequately structured or enforced.
We may be deemed to be a passive
foreign investment company (a “PFIC”) for U.S. federal income tax purposes. If we are or we become a PFIC,
it could have adverse tax consequences to holders of our ordinary shares or ADSs.
Potential investors in our ordinary shares
or ADSs should consider the risk that we could be now, or could in the future become, a PFIC for U.S. federal income tax purposes.
We do not believe that we were a PFIC for the taxable year ended June 30, 2018, and do not expect to be a PFIC in the foreseeable
future. However, the tests for determining PFIC status depend upon a number of factors, some of which are beyond our control and
subject to uncertainties, and accordingly we cannot be certain of our PFIC status for the current, or any other, taxable year.
We do not undertake an obligation to determine our PFIC status, or to advise investors in our securities as to our PFIC status,
for any taxable year.
If we were to be a PFIC for any year,
holders of our ordinary shares or ADSs who are U.S. persons for U.S. federal income tax purposes (“U.S. holders”)
whose holding period for such ordinary shares or ADSs includes part of a year in which we are a PFIC generally will be subject
to a special, highly adverse, tax regime imposed on “excess distributions” made by us. This regime will
continue to apply irrespective of whether we are still a PFIC in the year an “excess distribution” is made or received.
“Excess distributions” for this purpose would include certain distributions received on our ordinary shares or ADSs. In
addition, gains by a U.S. holder on a sale or other transfer of our ordinary shares or ADSs (including certain transfers that
would otherwise be tax-free) would be treated in the same manner as excess distributions. Under the PFIC rules, excess
distributions (including gains treated as excess distributions) would be allocated ratably to each day in the U.S. holder’s
holding period of the ordinary shares or ADSs with respect to which the excess distribution is made or received. The portion of
any excess distributions allocated to the current year or prior years before the first day of the first taxable year beginning
after December 31, 1986, in which we became a PFIC would be includible by the U.S. holder as ordinary income in the current year. The
portion of any excess distributions allocated to prior taxable years in which we were a PFIC would be taxed to such U.S. holder
at the highest marginal rate applicable to ordinary income for each such year (regardless of the U.S. holder’s actual marginal
rate for that year and without reduction by any losses or loss carryforwards), and any such tax owing would be subject to interest
charges. In addition, dividends received from us will not be “qualified dividend income” if we are a PFIC
in the year of payment, or were a PFIC in the year preceding the year of payment, and will be subject to taxation at ordinary
income rates.
In certain cases, U.S. holders may make
elections to mitigate the adverse tax rules that apply to PFICs (the “mark-to-market” and “qualified electing
fund” or “QEF” elections), but these elections may also accelerate the recognition of taxable income and could
result in the recognition of ordinary income. We have never received a request from a holder of our ordinary shares or ADSs
for the annual information required to make a QEF election and we have not decided whether we would provide such information if
such a request were to be received. Additional adverse tax rules would apply to U.S. holders for any year in which
we are a PFIC and own or dispose of shares in another corporation that is itself a PFIC. Special adverse rules that impact certain
estate planning goals could apply to our ordinary shares or ADSs if we are a PFIC.
The market price of our ordinary
shares and ADSs could be adversely affected by sales of substantial amounts of shares in the public markets or the issuance of
additional shares in the future, including in connection with acquisitions.
Sales of a substantial number of our ordinary
shares in the public market, either directly or indirectly as the sale of ADSs, or the perception that such sales may occur, could
cause the market price of our ordinary shares (and ADSs) to decline. In addition, the sale of these shares in the public market,
or the possibility of such sales, could impair our ability to raise capital through the sale of additional shares or other securities.
As of June 30, 2019, subject to meeting the vesting requirements we had outstanding options to purchase an aggregate of approximately
314,500,000 of our ordinary shares granted to certain of our directors, officers and employees. These option holders, subject
to compliance with applicable securities laws, are permitted to sell shares they own or acquire upon the exercise of options in
the public market. The exercise prices of the options are between A$0.0055 and A$0.07 per share, and the options expire around
November 2026. The exercise of such options could have similarly adverse consequences on the trading prices for our shares.
For further details on our outstanding
options, see “Note 9 – Share-Based Payments” in the Notes to our Consolidated Financial Statements.
In addition, in the future, we may issue
ordinary shares or ADSs including in connection with acquisitions of assets or businesses. If we use our shares for this purpose,
the issuances could have a dilutive effect on the market value of our ordinary shares, depending on market conditions at the time
of an acquisition, the price we pay, the value of the business or assets acquired, our success in exploiting the properties or
integrating the businesses we acquire and other factors.
Our ADS holders are not shareholders
and do not have shareholder rights.
The Bank of New York Mellon, as depositary,
executes and delivers our ADSs on our behalf. Each ADS is represented by a certificate evidencing a specific number of ADSs. Our
ADS holders are not required to be treated as shareholders and do not have the rights of shareholders. The depositary is
the holder of the ordinary shares underlying our ADSs. Holders of our ADSs have ADS holder rights. A deposit agreement among us,
the depositary and our ADS holders sets out ADS holder rights as well as the rights and obligations of the depositary. New York
law governs the deposit agreement and the ADSs.
Our ADS holders do not have the right
to receive notices of general meetings or to attend and vote at our general meetings of shareholders. Our practice is to give
ADS holders notices of general meetings and to enable them to vote at our general meetings of shareholders, but we are not obligated
to continue to do so. Our ADS holders may instruct the depositary to vote the ordinary shares underlying their ADSs,
but only when we ask the depositary to ask for their instructions. Although our practice is to have the depositary
ask for the instructions of ADS holders, we are not obligated to do so, and if we do not, our ADS holders would not be able to
exercise their right to vote. ADS holders can exercise their right to vote the ordinary shares underlying their ADSs
by withdrawing the ordinary shares. It is possible, however, that our ADS holders would not know about the meeting enough in advance
to withdraw the ordinary shares.
When we do ask the depositary to seek
our ADS holders’ instructions, the depositary notifies our ADS holders of the upcoming vote and arranges to deliver our
voting materials and form of notice to them. The depositary then tries, as far as practicable, subject to Australian law and the
provisions of the depositary agreement, to vote the ordinary shares as our ADS holders instruct. The depositary does not vote
or attempt to exercise the right to vote other than in accordance with the instructions of the ADS holders. We cannot assure our
ADS holders that they will receive the voting materials in time to ensure that they can instruct the depositary to vote their
shares. In addition, there may be other circumstances in which our ADS holders may not be able to exercise voting rights.
Similarly, while our ADS holders would
generally receive the same dividends or other distributions as holders of our ordinary shares, their rights are not identical. Dividends
and other distributions payable with respect to our ordinary shares generally will be paid directly to those holders. By
contrast, any dividends or distributions payable with respect to ordinary shares that are held as ADSs will be paid to the depositary,
which has agreed to pay to our ADS holders the cash dividends or other distributions it or the custodian receives on shares or
other deposited securities, after deducting its fees and expenses. Our ADS holders will receive these distributions in proportion
to the number of ordinary shares their ADSs represent. In addition, while it is unlikely, there may be circumstances in which
the depositary may not pay to our ADS holders the same amounts distributed by us as a dividend or distribution, such as when it
is unlawful or impractical to do so. See the next risk factor below.
There are circumstances where it
may be unlawful or impractical to make distributions to the holders of our ADSs.
Our depositary, The Bank of New York Mellon,
has agreed to pay to our ADS holders the cash dividends or other distributions it or the custodian receives on shares or other
deposited securities, after deducting its fees and expenses. Our ADS holders will receive these distributions in proportion to
the number of ordinary shares their ADSs represent.
In the case of a cash dividend, the depositary
will convert any cash dividend or other cash distribution we pay on the ordinary shares into U.S. dollars if it can do so on a
reasonable basis and can transfer the U.S. dollars to the United States. In the unlikely event that it is not possible
to convert a cash dividend or distribution into U.S. dollars, then the deposit agreement with the depositary allows the depositary
to distribute foreign currency only to those ADS holders to whom it is possible to do so. There is also a risk that,
if a distribution is payable by us in Australian dollars, the depositary may hold some or all of the foreign currency for a short
period of time rather than immediately converting it for the account of the ADS holders. Because the depositary
will not invest the foreign currency, will not be liable for any interest on the unpaid distribution or for any fluctuation in
the exchange rates during a time when the depositary has not converted the foreign currency, our ADS holders could lose some of
the value of the distribution.
The depositary may determine that it is
unlawful or impractical to convert foreign currency to U.S. dollars or to make a distribution to ADS holders that is made to the
holders of ordinary shares. This means that, under rare circumstances, our ADS holders may not receive the same distributions
we make to the holders of our ordinary shares or receive the same value for their ADSs if it is illegal or impractical for us
to or the depositary to do so.
There may be difficulty in effecting
service of legal process and enforcing judgments against us and our directors and management.
We are a public company limited by shares,
registered and operating under the Australian Corporations Act 2001. Two of our four directors reside outside the United States.
Substantially all of the assets of those persons are located outside the U.S. As a result, it may not be possible to effect service
on such persons in the U.S. or to enforce, in foreign courts, judgments against such persons obtained in U.S. courts and predicated
on the civil liability provisions of the federal securities laws of the U.S. There is doubt as to the enforceability in the Commonwealth
of Australia, in original actions or in actions for enforcement of judgments of U.S. courts, of civil liabilities predicated solely
upon federal or state securities laws of the U.S., especially in the case of enforcement of judgments of U.S. courts where the
defendant has not been properly served in Australia.