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.
In 2016, we underwent two transformative
transactions. In March 2016, we closed on the acquisition of the Foreman Butte project, which included 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 million and closed on October
31, 2016. $11.5 million of the proceeds from this transaction was 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 current 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 $19.45 million reserve
base facility until October 2018. The previous maturity date was October 31, 2017.
We engaged Netherland, Sewell and Associates,
Inc (“Netherland Sewell”) to prepare our proved oil and gas reserve estimates and the future net revenue to be derived
from our properties. Netherland Sewell is an independent petroleum engineering consulting firm that has provided consulting
services throughout the world for over 75 years. Netherland Sewell’s estimates were prepared by the use of standard geological
and engineering methods generally accepted by the petroleum industry. Reserve volumes and values were determined under
the method prescribed by the SEC, which requires the application of the 12-month average price for natural gas and oil calculated
as the un-weighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period to the
end of the reporting period and year-end costs. The proved reserve estimates represent our net revenue interest in our properties. When
preparing our reserve estimates, Netherland Sewell did not independently verify the accuracy and completeness of information and
data furnished by us with respect to property interests, production from such properties, current costs of operation and development,
current prices for production agreements relating to current and future operations and sale of production, and various other information
and data.
According to a reserve report prepared
by Netherland Sewell we had proved oil and gas reserves valued at approximately $65.3 million (before taxes) based on a present
value calculation with 10% discounting rate. This present value as of June 30, 2017, utilizes an adjusted realized pricing of $43.64
per Bbl for oil and $1.01 per Mcf for natural gas. As of June 30, 2017, 90% of our proved reserves were oil and 55% was proved
developed producing, 3% were proved non producing and 42% was proved undeveloped.
Our business strategy is to create a competitive
and sustainable rate of return to shareholders by exploring for, acquiring and developing oil and natural gas resources in the
United States. Our primary financial goal is to develop profitably our oil properties while maintaining a strong balance
sheet, and specifically to focus on the exploration, exploitation and development of our major oil project – the Foreman
Butte project in Montana and North Dakota.
We became required to file our periodic
reports to the SEC as a U.S. domestic issuer as of July 1, 2011. Since we remain an Australian corporation, however, we are still
considered to be a domestic company in Australia as well. As a result, we are required to report our financial results
in the U.S. using U.S. Generally Accepted Accounting Principles (“U.S. GAAP”) and in Australia using International
Financial Reporting Standards (“IFRS”).
We publish our consolidated financial statements,
both U.S. GAAP and IFRS, in U.S. dollars. In this annual report, unless otherwise specified, all dollar amounts are
expressed in U.S. dollars, and references to “dollars,” “$” or “US$” are to United States dollars. All
references to “A$” are to Australian dollars.
Our registered office is located at Level
16, AMP Building, 140 St Georges Terrace, Perth, Western Australia 6000 and our telephone number at that office is +61 8-9220-9830.
Our principal office in the United States is located at 1331 17
th
Street, Suite 710 Denver, Colorado 80202 and our telephone
number at that office is +1 303-295-0344. Our website is www.samsonoilandgas.com.
Preparation of Reserves Estimates
Our fiscal year-end petroleum reserves
report was prepared by Netherland Sewell in the current year. The reports were based upon its review of the property interests
being appraised, production from such properties, current costs of operation and development, current prices for production, agreements
relating to current and future operations and sales of production, geoscience and engineering data, and other information we provide
to the firm. The information we provided was reviewed by knowledgeable officers, employees and consultants to the Company, including
the Chief Executive Officer, in order to ensure accuracy and completeness of the data prior to its submission to Netherland Sewell.
Upon analysis and evaluation of data provided,
Netherland Sewell issues a preliminary appraisal report of our reserves. The preliminary appraisal report and changes in our reserves
are reviewed by our consulting reserves engineer and our Chief Executive Officer for completeness of the data presented, reasonableness
of the results obtained and compliance with the reserves definitions in Regulation S-X. Once all questions have been addressed,
Netherland Sewell issues the final appraisal report, reflecting its conclusions.
The technical persons primarily responsible
for preparing the estimates presented meet the requirements regarding qualifications, independence, objectivity and confidentiality
set forth in the SPE Standards. Ben Johnson, a licensed professional engineer in the state of Texas, has been practicing consulting
petroleum engineering at Netherland Sewell since 2007 and has 2 years of prior industry experience. John G. Hattner, a licensed
professional geoscientist in the state of Texas, has been practicing consulting petroleum geoscience at Netherland Sewell since
1991 and has over 11 years of prior industry experience.
Internally, the Chief Executive Officer,
Terry Barr, is responsible for overseeing the preparation of the Company’s reserves report and working with Netherland Sewell
on its final report. The CEO is a petroleum geologist who holds an associateship in applied geology and has over 40 years of relevant
experience in the oil and gas industry.
The reserve estimates are reported to the
Board of Directors, at least annually. Our Board members have experience in reviewing and understanding reserve estimates.
Estimated Proved Reserves
The information set forth below regarding
our oil and gas reserves for the fiscal years ended June 30, 2017 and 2016 was prepared by Netherland Sewell.
Proved oil and gas reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., costs
as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements,
but not on escalations based upon future conditions. Proved reserves are categorized as either developed or undeveloped.
The following table summarizes certain
information concerning our reserves and production in fiscal years ended June 30, 2017 and 2016:
|
|
2017
|
|
|
2016
|
|
|
|
Oil
(MBbls)
|
|
|
Gas
(Mcf)
|
|
|
Total
(MBOE)
|
|
|
Oil
(MBbls)
|
|
|
Gas
(Mcf)
|
|
|
Total
(MBOE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
9,982
|
|
|
|
8,593
|
|
|
|
11,415
|
|
|
|
1,285
|
|
|
|
1,183
|
|
|
|
1,483
|
|
Revisions of previous
quantity estimates
|
|
|
(2,851
|
)
|
|
|
(2,474
|
)
|
|
|
(3,263
|
)
|
|
|
2,597
|
|
|
|
2,662
|
|
|
|
3,041
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Sale of reserves in
place
|
|
|
(1,475
|
)
|
|
|
(2,396
|
)
|
|
|
(1,874
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Acquisitions
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
6,340
|
|
|
|
5,317
|
|
|
|
7,226
|
|
Production
|
|
|
(297
|
)
|
|
|
(158
|
)
|
|
|
(323
|
)
|
|
|
(240
|
)
|
|
|
(569
|
)
|
|
|
(335
|
)
|
End of year
|
|
|
5,359
|
|
|
|
3,565
|
|
|
|
5,955
|
|
|
|
9,982
|
|
|
|
8,593
|
|
|
|
11,415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
3,020
|
|
|
|
1,575
|
|
|
|
3,284
|
|
|
|
3,724
|
|
|
|
3,092
|
|
|
|
4,240
|
|
Proved developed non
producing
|
|
|
134
|
|
|
|
224
|
|
|
|
171
|
|
|
|
970
|
|
|
|
1,800
|
|
|
|
1,270
|
|
Proved
undeveloped reserves
|
|
|
2,205
|
|
|
|
1,766
|
|
|
|
2,499
|
|
|
|
5,288
|
|
|
|
3,701
|
|
|
|
5,905
|
|
Total
proved reserves
|
|
|
5,359
|
|
|
|
3,565
|
|
|
|
5,954
|
|
|
|
9,982
|
|
|
|
8,593
|
|
|
|
11,415
|
|
Revisions of previous quantity estimates
The positive revisions recorded for the year ended June 30,
2016 relate to the increase in reserves associated with the Foreman Butte project acquisition. Subsequent to taking over operatorship
of the project, we employed a number of workover rigs to return previously down wells to production. Many of these wells had no
PDP value at acquisition date and therefore were not included in the acquired reserves value.
The downward revision recorded in the current year relates to
our current drilling plan for our PUD locations. In the prior year, we anticipated drilling them as new 10,000 foot lateral horizontal
wells. Upon further technical review, we now plan to drill the PUD wells as 5,000 foot laterals out of an existing well bore. The
shortening of the lateral length lead to a decrease in the volume of reserves associated with these PUDs.
Acquisition
The acquisition of reserves in the
fiscal year ended June 30, 2016 consists of proved reserves associated with the Foreman Butte acquisition. This acquisition
added 2.1 MMBOE in proved developed producing reserves, 1.4 MMBOE in proved developed non producing reserves and 3.7 MMBOE in
proved undeveloped reserves on the acquisition date of March 31, 2016.
Sales of Reserves in Place
The sale of reserves in place during the fiscal year ended June
30, 2017 consists of proved reserves (net of production prior to sale) in the North Stockyard field in North Dakota and the State
GC field in New Mexico. All reserves were proved developed producing.
Proved Developed Producing Reserves
In March 2016, we closed on an acquisition of proved reserves,
the Foreman Butte project. This project contributed 4.2 MMBOE on June 30, 2016. Following the acquisition, we commenced a workover
program to return previously shut in wells to production. This program accounted for the increase in reserves from March 31, 2016
to June 30, 2016.
At June 30, 2017 our proved developed producing reserves primarily
relate to producing wells in our Foreman Butte project area in North Dakota and Montana.
Proved Developed Not Producing (PDNP)
PDNP reserves are those estimated proved
reserves expected to recovered from existing wells where there is a requirement to achieve a workover to re-establish production
As of June 30, 2016, the PDNP reserves were 1.3 MMBOE. Following
the acquisition, we commenced a workover program to return previously shut in wells to production.
As of June 30, 2017, the PDNP reserves were 171 MBOE, this primarily
relates to wells that require a workover to commence production again. This work will be performed as capital allows.
Proved Undeveloped Reserves
Proved undeveloped reserves (PUD) are those
reserves expected to be recovered from new wells on undeveloped acreage.
As of June 30, 2016, the PUD reserves were
5.9 MMBOE. At acquisition date, the reserves included 12 PUD locations.
During the year ended June 30, 2017 through
further technical review, we changed our plan with respect to the drilling the PUDs. This reduced the reserves volumes associated
with the PUDs but did not change the reserve value associated with the PUDs due to a decrease in the estimated drilling costs.
We currently have the permits to drill 4 PUDs and have commenced sourcing the appropriate rig and other contractors and equipment
required. We are in the process of refinancing our current credit facility which, if we are successful, will allow us to commence
drilling our PUDs.
While we did not convert any PUDs during
the year ended June 30, 2017, we have made considerable progress on their development through the increased technical review and
the determination of the most efficient and cost effective way to drill them.
Production, Prices, Costs and Balance Sheet Information
Production
During the years ended June 30, 2017
and 2016, we produced 298,517 and 240,424 barrels of oil, respectively. During the years ended June 30, 2017 and
2016 we produced 147,765 and 569,008 Mcf of gas, respectively.
For the year ended June 30, 2017 and June
30, 2016 we had one Field (as such term is used within the meaning of applicable regulations of the SEC – See Glossary of
Technical Terms) that contains more than 15% of our total proved reserves, namely our interests in the Foreman Butte field in North
Dakota, which is part of our Foreman Butte project in North Dakota and Montana.
The following tables disclose our oil and
gas production volume, revenue and expenses from the Foreman Butte field for the fiscal year ended June 30, 2017 and 2016:
|
|
2017
Foreman Butte
Field
|
|
Oil volume – Bbls
|
|
|
253,168
|
|
Revenue – $
|
|
|
10,697,487
|
|
Average Price per barrel – $
|
|
|
42.25
|
|
Gas volume – Mcf
|
|
|
52,281
|
|
Revenue – $
|
|
|
176,407
|
|
Average price per Mcf – $
|
|
|
3.37
|
|
Per unit production and lease operation costs per BOE – $
|
|
$
|
31.12
|
|
This includes $4.69 per BOE of work over
costs and $3.50 per BOE in production taxes. We have further reduced lease operating expense in the second half of the year following
us becoming operator of the field.
|
|
2016
Foreman Butte
Field
|
|
Oil volume – Bbls
|
|
|
4,396
|
|
Revenue – $
|
|
$
|
171,138
|
|
Average Price per barrel – $
|
|
$
|
38.93
|
|
Gas volume – Mcf
|
|
|
-
|
|
Revenue – $
|
|
|
-
|
|
Average price per Mcf – $
|
|
|
-
|
|
Per unit production and lease operation costs per BOE – $
|
|
$
|
44.50
|
|
* We took over operatorship of this field which was acquired
within the larger Foreman Butte acquisition on June 2, 2016; therefore the costs associated with this field reflect the structure
of the previous operator.
Prices and Costs
The average sale price (excluding the impact
of derivative instruments) we achieved for oil during the years ended June 30, 2017 and June 30, 2016 was $42.15 and
$34.27 per barrel, respectively.
The average sale price we achieved for
gas during the years ended June 30, 2017 and June 30, 2016 was $2.95 and $1.25 per Mcf, respectively.
The average production costs
(excluding production taxes) per barrel of oil equivalent was $29.12 for the year ended June 30, 2017 and $12.95 for the year
ended June 30, 2016.
Drilling Activity
|
|
Year Ended June 30
|
|
|
|
2017
|
|
|
2016
|
|
Net productive exploratory wells drilled
|
|
|
Nil
|
|
|
|
Nil
|
|
Net dry exploratory wells drilled
|
|
|
Nil
|
|
|
|
0.25
|
|
Net productive development wells drilled
|
|
|
Nil
|
|
|
|
Nil
|
|
Net dry development wells drilled
|
|
|
Nil
|
|
|
|
Nil
|
|
The exploratory wells drilled in the previous
year were both drilled in our South Prairie project in North Dakota.
Present Drilling Activity
As of September 28, 2017, we were not
participating in the process of drilling or completing any wells (including wells temporarily suspended).
For a discussion of our present development
activity, see “Description of Properties—Exploration / Undeveloped Properties” in “Item 1 and 2. Business
and Properties” and “Recent Developments”, “2016 and 2017 Capital Expenditures” and “Estimated
2018 Capital Expenditures” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results
of Operations”.
Oil and Natural Gas Wells and Acreage
As at September 28, 2017, our wells and
acreage were as follows:
Gross productive oil wells
|
|
|
169
|
|
Net productive oil wells
|
|
|
117
|
|
Gross productive gas wells
|
|
|
4
|
|
Net productive gas wells
|
|
|
1
|
|
Wells with multiple completions
|
|
|
0
|
|
Gross Developed Acres
|
|
|
47,902
|
|
Net Developed Acres
|
|
|
40,164
|
|
Gross Undeveloped Acres
|
|
|
2,736
|
|
Net Undeveloped Acres
|
|
|
1,318
|
|
All of our acreage positions are located
in the continental United States, with the majority located in North Dakota and Montana. We have extensive leases with
a variety of remaining lease terms varying from 3 months to four years. 95% of our net developed acres are held by production. In
some cases we have the ability to extend the lease term.
Standardized Measure of Discounted Future
Net Cash Flows
Future hydrocarbon sales and production
and development costs have been estimated using a 12-month average price for the commodity prices for June 30, 2017 and June 30,
2016 and costs in effect at the end of the periods indicated. The 12-month historical average of the first of the month prices
used for natural gas for June 30, 2017 and June 30, 2016 were $3.01 and $0.37 per Mcf, respectively. The 12-month historical
average of the first of the month prices used for oil for June 30, 2017 and June 30, 2016 were $48.95 and $37.12 per barrel of
oil, respectively. Future cash flows were reduced by estimated future development, abandonment and production costs
based on period–end costs. No deductions were made for general overhead, depletion, depreciation and amortization
or any indirect costs. All cash flows are discounted at 10%.
Changes in demand for hydrocarbons, inflation
and other factors make such estimates inherently imprecise and subject to substantial revisions. This table should not
be construed to be an estimate of current market value of the proved reserves attributable to Samson.
The following table shows the estimated
standardized measure of discounted future net cash flows relating to proved reserves (in US$’000’s):
|
|
As at June 30,
|
|
|
|
2017
|
|
|
2016
|
|
Future cash inflows
|
|
$
|
237,490
|
|
|
$
|
373,740
|
|
Future production costs
|
|
|
(91,920
|
)
|
|
|
(184,691
|
)
|
Future development costs
|
|
|
(13,367
|
)
|
|
|
(50,752
|
)
|
Future income taxes
|
|
|
-
|
|
|
|
0
|
|
Future net cashflows
|
|
|
132,203
|
|
|
|
138,297
|
|
10 % discount
|
|
|
(66,941
|
)
|
|
|
(71,550
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows relating to proved reserves
|
|
$
|
65,262
|
|
|
$
|
66,747
|
|
The principal sources of changes in the
standardized measure of discounted future net cash flows during the periods ended June 30, 2017 and June 30, 2016 are
as follows (in $’000’s):
|
|
Fiscal Year Ended June 30
|
|
|
|
2017
|
|
|
2016
|
|
Beginning of year
|
|
$
|
66,747
|
|
|
$
|
34,253
|
|
Sales of oil and gas produced during the period, net of production costs
|
|
|
(3,122
|
)
|
|
|
(3,575
|
)
|
Net changes in prices and production costs
|
|
|
1,601
|
|
|
|
(15,705
|
)
|
Previously estimated development costs incurred during the period
|
|
|
-
|
|
|
|
-
|
|
Changes in estimates of future development costs
|
|
|
22,929
|
|
|
|
(14,545
|
)
|
Extensions and discoveries
|
|
|
-
|
|
|
|
-
|
|
Revisions of previous quantity estimates and other
|
|
|
(21,078
|
)
|
|
|
18,074
|
|
Sale of reserves in place
|
|
|
(10,445
|
)
|
|
|
-
|
|
Purchase of reserves in place
|
|
|
-
|
|
|
|
41,564
|
|
Change in future income taxes
|
|
|
-
|
|
|
|
-
|
|
Accretion of discount
|
|
|
6,675
|
|
|
|
3,452
|
|
Other
|
|
|
1,955
|
|
|
|
3,229
|
|
Balance at end of year
|
|
$
|
65,262
|
|
|
$
|
66,747
|
|
The impact of income taxes has not been
included in the current year as the net operating losses and the tax basis of the assets exceed the future cash flows.
Description of Properties
Production information is shown net to
our interests. Our net revenue interest is included in the total amount.
Developed Properties
Foreman Butte Project – Williston
Basin, North Dakota and Montana
Various working interests
In March 2016, we closed on the acquisition
of the Foreman Butte project. This project includes a number of producing and non producing, operated and non operated wells in
the Ratcliffe and Madison formations in Montana and North Dakota.
This project consists of 131 wells (both
operated and non operated) across a number of fields in Montana and North Dakota. The wells are conventional wells drilled as early
as 1980 to as recently as 2010.
In September 2017, we received
approval for a water flood pilot project for the Home Run Field utilizing an existing wellbore which is located on the flank
of the field and which is non-productive. This well, the Mays 1-20H has been tested and readied for injected water following
the approval from the North Dakota Industrial Commission. We expect to commence injection in October 2017. The water flood is
being used to add pressure to the reservoir which we believe should enhance the recovery of oil. The well performance in the
offsetting wells will be monitored to establish the viability of the flood. The water being used is produced formation water
so that there is no chemical compatibility issues, in essence the water is being returned to the reservoir from which it
originated. Initially this water will be trucked to the injector from the existing producing wells but will ultimately be
pipelined.
The Home Run Field (aka as the Foreman
Butte Field) is the largest area oil field in our portfolio. It was developed on a 640 acre spacing pattern and our engineering
and geologic analyses have determined that only 3.2% of the original oil in place has been recovered to date. Given that oil fields
typically recover up to around 20% of their oil in place there would appear to be significant un-developed oil to be recovered
from this field.
This has been confirmed through the use
of a 3 dimensional numerical simulation of the reservoir volume, and the expected production curve for these wells has been developed
from the resulting numerical model.
The current reservoir pressure has also
been established using a field wide fluid level study, and the initial development wells will be located in areas of demonstrated
higher pressure.
Assuming the completion of our debt
refinance, we are planning to drill our first development well. The first lateral will test the Ratcliffe Formation of the
Mississippian Madison Group. The lateral in the Ratcliffe Formation will help define the pressure depletion radius from the
existing producing wellbores which will ultimately determine the number of PUDs (proven undeveloped drilling locations) we
can drill in this reservoir.
Currently we have 20 Ratcliffe PUD
locations identified. The second lateral will test an undeveloped reservoir in the Mission Canyon Formation of the
Mississippian Madison Group. This lateral could prove up a new oil field with the potential for many additional well
locations (up to 20 vertical wells or 8 drill-out laterals) although we can make no assurances of the results of this testing. A
3,500 acre 4-way structural closure has been mapped from an abundance of existing well control in the area.
These PUDS meet the definition of PUDS
per the SPE PRMS guidelines and SEC definitions and have been risked accordingly.
During the year ended June 30, 2017, the
Foreman Butte Project area produced 253,168 barrels of oil.
North Stockyard Project – Williston
Basin, North Dakota
On June 30, 2016 we entered into a purchase
and sale agreement to sell our North Stockyard property for $15 million. This transaction closed on October 31, 2016.
State GC Oil and Gas Field, New Mexico
The State GC Oil and Gas Field, located
in Lea County, New Mexico, was discovered in 1980 and covers approximately 600 acres. The field is operated by Legacy
Resources.
The State GC# 1 well was drilled in 1980
and has been productive since that time.
This project was sold for $1.2 million
on April 30, 2017.
Davis Bintliff #1 Well (Sabretooth Prospect),
Brazoria County, Texas
12.5% Working Interest before payout,
9.375% Working Interest after payout
This well is operated by Davis Holdings.
The Davis Bintliff #1 well was completed at the end of October 2008.
During the year, this well encountered
operational issues and was plugged and abandoned.
Exploration / Undeveloped Properties
Hawk Springs Project, Goshen County,
Wyoming
37.5% -100% working interest
Spirit of America US 34 #2-29 (Spirit
of America II)
100% working interest
The Spirit of America I replacement well,
Spirit of America II, was drilled to a total depth of 10,634 feet using a conservative drilling approach to penetrate the troublesome
salt section along with heavy weight, oil based mud. Numerous operational difficulties were encountered and the well failed to
produce economic quantities of hydrocarbons. $7.3 million in costs associated to drill this well, were written off to the Statement
of Operations in the year ended June 30, 2013.
In July 2015, a workover rig was moved
to the location to test the Dakota formation from 8,054 feet to 8,064 feet. This formation was found to be water saturated and
no hydrocarbons were noted. All costs associated with this well have been written off to the Income Statement during the year ended
June 30, 2016.
This well was plugged in October 2016.
Defender US 33 #2-29H
37.5% working interest
This well commenced production in February 2012 and has experienced
numerous operational and pumping issues. In July 2012, the well was cleaned out and resumed pumping. In June 2015, the well was
struck by lightning which affected the electronic controllers associated with the well. These controllers have yet to be repaired
due to the well’s low productivity rate.
There was no production from this well
during the year ended June 30, 2016. This well was plugged in October 2016.
Bluff 1-11 (25% working interest)
During the year ended June 30, 2014 we
drilled the Bluff Prospect to test multiple targets in the Permian and Pennsylvanian sections in a 4-way structural trapping configuration.
The Bluff #1-11 well reached a total depth of 8,900 feet after intersecting the pre-Cambrian basement on June 13, 2014.
To date, this well has failed to produce
economic quantities of hydrocarbons and all costs associated with drilling it have been written off the Statement of Operations.
The well is yet to be plugged as we are waiting on testing the upper canyon spring zone with a perforation and swab test. This
operation is expected to cost $20,000, net to us. This operation is not currently planned.
Roosevelt Project, Roosevelt County,
Montana
100% Working Interest
Australia II
100% working interest
In December 2011, we drilled Australia
II in the Roosevelt Project, our first appraisal (exploratory) well in this project area. This well was drilled to a total measured
depth of 14,972 feet with the horizontal lateral remaining within the target zone for the entire lateral length. Oil and gas shows
were returned during the drilling of this well and approximately 3,425 barrels of oil were produced. This well was being pumped,
and although this well is productive, we do not presently believe that we will be able to recover our costs associated with drilling
it. We expensed $13.1 million of previously capitalized exploration expenditure in the Statement of Operations as deferred exploration
expenditure written off, which represents 100% of the costs incurred to June 30, 2012.
In July 2014, we replaced the pump on the
Australia II well and production from this well has recommenced production. During July 2014, the well averaged 100 barrels of
oil per day. Following the continued decline in the oil price, this well was shut in from January 2015 to August 2016. It has no
reserves associated with it at June 30, 2016.
This well was put back on production in
August 2016 and produced at an average rate of 66 BOEPD.
Rainbow Project, Williams County, North
Dakota
Mississippian Bakken Formation, Williston Basin
23% -52% working interest
During the year ended June 30, 2013, we
acquired, in two tranches, a net 950 acres in two 1,280 acre drilling units located in the Rainbow Project, Williams County, North
Dakota. The Rainbow Project is located in Sections 17, 18, 19 and 20 in T158N R99W.
The acquisition involved an acreage trade
by the parties and a future carry of the vendor by us in the initial drilling program on the Rainbow Project. We transferred 160
net acres from our 1,200 acre undeveloped acreage holding in North Stockyard and the vendor will fund its share (between 7.5% and
8.5%) of the North Stockyard initial infill program. We have acquired 950 net acres in the Rainbow Project from the vendor for
this acreage trade and have paid $1 million to the vendor, in lieu of a carry as we did not spud a well within the desired time
frame. $0.6 million of this payment was made prior to June 30, 2015 with the remaining $0.4 million paid subsequent to year end.
In the western drilling unit of the acquired
acreage, we hold a 52.21% working interest. In the eastern drilling unit, our interest is 23%.
Our first Rainbow well, Gladys 1-20, drilled
by Continental Resources, spud on June 28, 2014 and was drilled to a total depth of 19,994 feet. The well is 1,280 acre lateral
(approximately 10,000 feet) in the middle member of the Bakken formation. The well produced 4,302 net barrels of oil during the
year ended June 30, 2017.
There has been no further drilling activity
on this lease during the year ended June 30, 2017 and 652 acres have expired.
Cane Creek Project, Grand & San
Juan Counties, Utah
Pennsylvanian Paradox Formation, Paradox
Basin
100% working interest
On November 5, 2014, we entered into an
Other Business Arrangement (“OBA”) with the Utah School and Institutional Trust Lands Administration (“SITLA”)
covering approximately 8,080 gross/net acres located in Grand and San Juan Counties, Utah, all of which are administered by SITLA.
We were granted an option period for two years, expiring November 30
th
, 2016 in order to enter into a Multiple Mineral
Development Agreement (“MMDA”) with another company who hold leases to extract potash in an acreage position situated
within our project area. Upon entering into the MMDA, SITLA is obligated to deliver oil and gas leases covering our project area
at a cost of $75 per acre to us. The MMDA has been finalized though it has not yet been executed. We are currently in the process
of seeking farm out partners to move this project forward. We paid an additional option fee in November 2016 to extend our option
to November 30
th
, 2017.
This acreage is located in the heart of
the Cane Creek Clastic Play of the Paradox Formation along the Cane Creek anticline. The primary drilling objective is the overpressured
and oil saturated Cane Creek Clastic interval. Keys to the play to date include positioning along the axis of the Cane Creek anticline
and exposure to open natural fractures. A 3-D seismic is currently being designed to image these natural fractures. This project
displays very robust economics in a low priced oil environment using the evidence obtained from a nearby competitor well. Initial
production rates from a well drilled by a competitor are around 1,500 BOPD and decline rates are very modest, as experienced by
competitor wells in the area. We have not drilled a well in this area to date.
Risk and Insurance Program
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 the risk of well blowouts, oil spills and other adverse events. We could be held responsible for injuries suffered by
third parties, contamination, property damage or other losses resulting from these types of events. In addition, we have generally
agreed to indemnify our drilling rig contractors against certain of these types of losses. Because of these risks, we maintain
insurance against some, but not all, of the potential risks affecting our operations and in coverage amounts and deductible levels
that we believe to be economic. Our insurance program is designed to provide us with what we believe to be an economically appropriate
level of financial protection from significant unfavorable losses resulting from damages to, or the loss of, physical assets or
loss of human life or liability claims of third parties, attributed to certain assets and including such occurrences as well blowouts
and resulting oil spills. We regularly review our risks of loss and the cost and availability of insurance and consider the need
to revise our insurance program accordingly. Our insurance coverage includes deductibles which must be met prior to recovery. Additionally,
our insurance is subject to exclusions and limitations and there is no assurance that such coverage will adequately protect us
against liability from all potential consequences and damages.
In general, our current insurance policies covering a
blowout or other insurable incident resulting in damage to one of our oil and gas wells provide up to $20 million of well
control, pollution cleanup and consequential damages coverage and $11 million of third party liability coverage for additional
pollution cleanup and consequential damages, which also covers personal injury and death.
If a well blowout, spill or similar event
occurs that is not covered by insurance or not fully protected by insured limits, we would be responsible for the costs, which
could have a material adverse impact on our financial condition, results of operations and cash flows.
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 September
26, 2017.
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 generate volatile organic compounds (“VOCs”) and nitrous oxides. 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 correction of any identified deficiencies. Alternatively, regulatory agencies
could require us to forego construction, modification or operation of certain air-emission sources.
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 volatile organic
compounds (“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” or “green completion” methods
to capture natural gas that would otherwise escape into the air. EPA also issued regulations that set requirements for VOC emissions
from several types of equipment, including storage tanks, compressors, dehydrators, and valves. 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. Petitioners 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. While EPA reconsiders the methane rule, it will remain effective. These new 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 Trump by Executive Order 13,783,
and the June 2016 methane regulations, though currently effective, are slated for review and possible revision or repeal by EPA.
A brief EPA administrative stay of certain portions of the methane regulations was vacated by the D.C. Circuit Court of Appeals
in July 2017, but EPA has 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 would require most 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, makes that 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 to Sue (“NOI”)
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. EPA has until March 2019 to make its determination. 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 rule is 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. It deals 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. We are evaluating the economic implications of complying
with this rule, but the rule could potentially lead to plugging and abandoning some of our existing oil and gas locations on federal
and tribal lands.
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 Note 5 to our financial
statements, we have estimated the present value of our aggregate asset retirement obligations to be $3.5 million as of June 30,
2017. 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 September 9, 2017, we had 12 employees,
including 2 part time employees. The 2 part time employees are located in Perth, Western Australia and are involved in facilitating
the administration of the Company. 9 employees are located in Denver, Colorado and 1 is located in North Dakota and works
specifically on our Foreman Butte project in North Dakota and Montana.
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 depend on successful exploration,
development and acquisitions to maintain reserves and revenue in the future.
In general, the volume of production from
natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our
future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves
that are economically feasible and in developing existing proved reserves. To the extent that cash flow from operations
is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment
to maintain or expand our asset base of natural gas and oil reserves would be impaired.
Inadequate liquidity could materially
and adversely affect our business operations.
We have significant outstanding indebtedness
under our credit facility with Mutual of Omaha Bank. As of June 30, 2017, we had drawn $23.5 million of the $24 million borrowing
base under our credit facility. This facility is due for repayment in October 2018.
Our ability to pay interest and principal
on our indebtedness and to satisfy our other obligations will depend upon our future operating performance and financial condition
as well as our ability to refinance our current indebtedness, which will be affected by prevailing economic conditions and financial,
business and other factors, many of which are beyond our control. We cannot assure you that our business will generate sufficient
cash flows from operations, or that future borrowings will be available to us under our credit facility or otherwise, in an amount
sufficient to fund our liquidity needs. In the absence of adequate cash from operations and other available capital resources,
we could face substantial liquidity problems, and we might be required to seek additional debt or equity financing or to dispose
of material assets or operations to meet our debt service and other obligations. We cannot assure you that we would be able
to raise capital through debt or equity financings on terms acceptable to us or at all, or that we could consummate dispositions
of assets or operations for fair market value, in a timely manner or at all. Furthermore, any proceeds that we could realize
from any financings or dispositions may not be adequate to meet our debt service or other obligations then due.
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 $2.7 million and had net cash outflows from operating activities of $2.6 million
for the year ended June 30, 2017. As at that date, our total current liabilities of $29.1 million exceed our total current assets
of $2.4 million. Additionally, we are in violation of our debt covenants and have suffered recurring losses from operations. We
believe these circumstances raise substantial doubt about the our ability to continue as a going concern.
Our ability to continue
as a going concern is dependent on the re-negotiation or replacement of our primary debt facility, the sale of some of our assets,
raising additional capital or some combination thereof. If we are not able to generate the funds needed to cover our ongoing expenses,
then we may be forced to cease operations, in which event our shareholders could lose their entire investment.
Recent amendments to our credit agreement
with our primary lender impose additional restrictions on our ability to operate our business and require us to meet additional
financial and operational requirements.
As a condition to providing financing for
our Foreman Butte acquisition, our primary lender required us to amend our credit agreement to include materially more restrictive
terms. These new terms include: (1) more restrictive financial covenants (including the debt-to-EBITDA ratio and minimum liquidity
requirements); (2) increases in the interest rate and unused facility fees; (3) a minimum hedging requirement of 75% of our forecasted
production; (4) reducing annual G&A expenses from $6 million to $3 million; (5) raising an additional $5 million in equity
on or before September 30, 2016 (which was extended to November 15, 2016 and was achieved through the sale of the North Stockyard
assets); (6) paying down at least $10 million of the credit facility by June 30, 2016 (which date was subsequently extended to
October 31, 2016 and which condition was achieved, as discussed above); and (7) a monthly cash flow sweep of 50% of our cash operating
income. These amendments could make it materially more difficult to operate our business, and there can be no assurance that we
will be able to remain in compliance with these covenants, particularly in the current oil price environment. As at June 30, 2017
we were in breach of earnings and liquidity covenants with respect to the facility and are expected to breach these covenants for
the quarter ending September 30, 2017. There is no assurance that our primary lender will not declare a default and seek immediate
repayment of the entire debt borrowed under the facility because of these breaches.
Our Foreman Butte acquisition is
subject to uncertainties, such as our ability to evaluate recoverable reserves and potential liabilities associated with the assets
being acquired, and our ability to successfully integrate such assets with our current business.
The success of the Foreman Butte acquisition
depends on a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential,
future commodity prices, operating costs, title issues and potential environmental and other liabilities. Our assessment of such
factors is based on production reports, engineering studies, geophysical and geological analyses and seismic and other information,
the results of which are inexact and inherently uncertain. Though the assessments we conducted were generally consistent with industry
practices, we may not have fully assessed all of the deficiencies and capabilities of the acquired properties. The success of the
Foreman Butte acquisition also depends on our ability to integrate the assets being acquired with our current business and to operate
such assets for a profit. If we are not successful in achieving these objectives, the anticipated economic, operational and other
benefits and synergies of the Foreman Butte acquisition may not be realized fully or at all, which could result in substantial
costs and delays or other operational, technical or financial problems. In addition, the actual integration may result in additional
and unforeseen expenses, which could reduce or eliminate the anticipated benefits of the acquisition.
We recorded a significant impairment
on the carrying value of our oil and gas assets during the fiscal year ended June 30, 2016 and 2015, and may record additional
impairments in the future.
We recognized impairment expense of $11.0
million for the twelve months ended June 30, 2016, in addition to the impairment expense of $21.5 million we recognized for the
twelve months ended June 30, 2015 of $21.5 million. The impairment expense recognized in both years is primarily in relation to
our former North Stockyard project as a direct result of the significant fall in the oil price. Subsequent adverse changes in oil
and gas prices or drilling results may result in us being unable to recover the carrying value of our long-lived assets, and make
it appropriate to recognize more impairments in future periods. Such impairments could materially and adversely affect our results
of operations. For the fiscal year ended June 30, 2017, we recorded $0.2 million in impairments in relation to our oil inventory.
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
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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.
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.
Any significant reduction in our borrowing base under our
credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund
our operations, and we may not have sufficient funds to repay borrowings under our credit facility if required as a result of a
borrowing base redetermination.
In January 2014, we entered into a $25
million credit facility agreement with Mutual of Omaha Bank. In November 2014 this facility was increased to $50
million. The current borrowing base is $24 million and we were drawn to $23.5 million as at June 30, 2017. We intend
to continue borrowing under our credit facility in the future as is allowable. The borrowing base is subject to periodic
redetermination and is based in part on oil and natural gas prices and the value of properties owned, which could be reduced
in the case of asset disposition. A negative adjustment could also occur if the estimates of future prices used by the banks
in calculating the borrowing base are significantly lower than those used in the last redetermination, including as a result
of a decline in oil prices or an expectation that existing low prices will continue. Any significant reduction in our
borrowing base as a result of such redeterminations or otherwise may negatively impact our liquidity and our ability to fund
our operations. Further, if the outstanding borrowings under our revolving credit facility were to exceed the borrowing base
as a result of such redetermination, we would be required to repay indebtedness in excess of the newly established borrowing
base, or we might need to further secure the debt with additional collateral. Our ability to meet any debt obligations in the
future depends on our future performance.
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 or the borrowing base
under our revolving credit facility decreases 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. 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 has
been used to repay debt or provide working capital. We are currently in the process of refinancing our current debt facility
in order to provide the required working capital to commence our PUD drilling, and we can provide no assurances about the
outcome of the refinancing efforts.
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.
Oil and natural gas prices are extremely
volatile, and decreases in prices have in the past, and could in the future, adversely affect our profitability, financial condition,
cash flows, access to capital and ability to grow.
Our revenues, profitability and future rate
of growth depend principally upon the market prices of oil and natural gas, which fluctuate widely. The markets for these commodities
are unpredictable and even relatively modest drops in prices can significantly affect our financial results and impede our growth.
Sustained declines in oil and gas prices may adversely affect our financial condition, liquidity and results of operations.
Recently,
oil prices have declined significantly. We are particularly dependent on the production and sale of oil and this recent commodity
price decline has had, and may continue to have, an adverse effect on us. Further volatility in oil and gas prices or a continued
prolonged period of low oil or gas prices may materially adversely affect our financial position, liquidity (including our borrowing
capacity under our revolving credit facility), ability to finance planned capital expenditures and results of operations.
It
is impossible to predict future oil and gas price movements with certainty. Prices for oil and gas are subject to wide fluctuation
in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional
factors beyond our control.
Factors that can cause market prices of oil and natural gas to fluctuate include:
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national and international financial market conditions;
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uncertainty in capital and commodities markets;
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the level of consumer product demand;
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U.S. and foreign governmental regulations;
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the price and availability of alternative fuels;
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political and economic conditions in oil producing countries, particularly those in the Middle East, including actions by the Organization of Petroleum Exporting Countries;
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the foreign supply of oil and natural gas;
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the price of oil and gas imports, consumer preferences; and
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overall U.S. and foreign economic conditions.
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At various times, excess domestic and imported
supplies have depressed oil and gas prices. Additionally, the location of our producing wells may limit our ability to take advantage
of spikes in regional demand and resulting increases in price. While increased demand would normally be expected to increase the
prices we receive for our oil and natural gas, other factors, such as the recent sharp downturn in worldwide economic activity,
may dampen or even reverse any such positive impact on prices.
The profitability of wells are generally reduced
or eliminated as commodity prices decline. In addition, certain wells that are profitable may not meet our internal return targets.
Recent price declines have caused us to significantly reduce our new exploration and development activity which may adversely affect
our results of operations, cash flows and our business.
Lower oil and natural gas prices may not only
decrease our revenues, but also may reduce the amount of oil and natural gas that we can produce economically. Such a reduction
may result in substantial downward adjustments to our estimated proved reserves and require write–downs of our properties.
If this occurs, or if our development costs increase, our production data factors change or our exploration results do not meet
expectations, accounting rules may require us to write down the carrying value of our oil and natural gas properties to fair value,
as a non–cash charge to earnings.
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 we intend
to 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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well blowouts;
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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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casing collapses;
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fires;
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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 abandon 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:
1. require
applying for and receiving permits before drilling commences;
2. restrict
the types, quantities and concentration of substances that can be released into the environment in connection with drilling and
production activities;
3. limit
or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; and
4. impose
substantial liabilities for pollution resulting from our operations.
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 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 currently is the subject
of regulatory scrutiny, negative press, and 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 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 regulatory environment affecting 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 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 continue to exert pressure on the oil and natural gas
industry. As noted, there may be heightened litigation regarding any revision or rescission for 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 standard in 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, oil companies have been charged with killing migratory
birds in North Dakota, where we conduct operations. Reserve pits are used during oil and gas drilling operations. 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. The maximum
penalty for each conviction under the MBTA is two years in prison and a $250,000 fine.
The federal Clean Water Act and analogous state
laws impose strict controls against the discharge of pollutants and fill material, including spills and leaks of crude oil and
other substances. 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")
requirements of the Clean Water Act require 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,
which can increase operating costs
The EPA has also issued permitting guidance
under the SDWA for the underground injection of liquids from hydraulically fractured (and other) wells where diesel is used. Depending
upon how it is implemented, this guidance may create duplicative requirements in certain areas, further slow the permitting process
in certain areas, increase the costs of operations, and result in expanded regulation of hydraulic fracturing activities by the
EPA and could therefore even adversely affect companies, such as Samson, that do not use diesel fuel in hydraulic fracturing activities.
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 volatile organic
compounds (“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” (REC) or “green completion”
methods to capture natural gas that would otherwise escape into the air. EPA also issued regulations that set requirements for
VOC emissions from several types of equipment, including storage tanks, compressors, dehydrators, and valves. 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, and made these standards also applicable to oil wells that are hydraulically fractured. 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. Petitioners 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. While EPA reconsiders the methane rule, it will remain effective. The State of North Dakota and EPA Region VIII have
also pursued enforcement against other North Dakota operators related to failure to properly design, operate, and maintain atmospheric
storage tanks in compliance with North Dakota state regulations and Tribal FIP regulations. It is possible that these existing
air regulations, recent enforcement initiatives, 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 standards regulations issued in June 2016. EPA also intends to conduct future rulemaking to make appropriate
revisions to the Prevention of Significant Deterioration and Operating Permit rules under the Clean Air Act. 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 slated for review and possible
repeal by the EPA. Moreover, 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 would require most sources
of GHG emissions to obtain GHG emission “allowances” to continue their operations. 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.
The Occupational Safety and Health Act promotes
workplace safety by, among other things, providing for the development and enforcement of mandatory occupational safety and health
standards. These standards apply to employers, including oil and gas operators and service companies, and are developed and enforced
by the Occupational Safety and Health Administration (OSHA). On March 25, 2016, OSHA released its final rule on Occupational Exposure
to Respirable Crystalline Silica, which includes specific requirements applicable to hydraulic fracturing operations in the oil
and gas industry. 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 rely 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 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, 2017, the Australian dollar has, as a general trend, maintained its value against the U.S.
dollar, though the exchange rate 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.
The trading prices of our ordinary shares on
the ASX and of our ADSs on the NYSE American (formerly NYSE MKT) have been, and likely will continue to be, volatile. 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 NYSE American 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.
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.
NYSE American has taken actions toward
delisting our ADSs, including suspending trading in our common stock.
On September 14, 2017, we received a letter
from the NYSE American (the “Exchange”) stating that the Company’s American Depositary Shares (“ADS”)
are no longer suitable for listing on the Exchange. The Exchange commenced delisting proceedings pursuant to Section 1003(a)(iii)
and Section 1009 of the NYSE American Company Guide because the Company failed to meet the stockholders’ equity requirement
of $6,000,000 at the end of the maximum permitted 18-month compliance plan period ending September 14, 2017.
The Company has a right to request a
review of the Exchange’s delisting determination by the Listing Qualifications Panel. On September 20, 2017, we
submitted a request for a review of such delisting determination. As of September 28, 2017, a hearing date has not been
scheduled. If the Listing Qualifications Panel concurs with the determination of the NYSE American staff to delist the ADSs,
our ADSs will be delisted from the Exchange.
If the NYSE American delists our ADSs,
investors may face material adverse consequences.
Upon a delisting of our ADSs by the NYSE
American, investors may face material adverse consequences, including, but not limited to, a lack of trading market for our
securities, reduced liquidity, decreased analyst coverage of our securities, and an inability for us to obtain additional
financing to fund our operations. In addition, delisting from the Exchange might negatively impact our reputation and, as a
consequence, our business. Also, as long as we are not listed on a national exchange we may not use Form S-3 registration
statements for most offerings, which may impair our ability to raise funds, may limit the type of offerings we could undertake, and could increase the expenses of any offering.
If our ADS are required to trade on the
over-the-counter market, selling the ADS could be more difficult.
If the ADSs are delisted from the Exchange,
they may trade in the over-the-counter market. If our ADSs were to trade on the over-the-counter market, selling the ADSs could
be more difficult because smaller quantities of shares would likely be bought and sold, transactions could be delayed, and any
security analysts’ coverage of us may be reduced. In addition, if the ADSs are delisted, 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. Such delisting from the 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.
Even though Samson is now a “domestic
issuer” for SEC reporting requirements, we remain a “foreign based entity” for purposes of Section 110 of the
NYSE American Company Guide. This permits us to apply to the NYSE American to have certain of its listing criteria relaxed and
receive exemptions from rules applicable to corporations incorporated in the United States. We currently are relying on one Section
110 exemption received in connection with our stock option plan, and is described in more detail in “Item 5—Market
for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Market Information.”
While we have no current plans to seek additional Section 110 relief from NYSE American, there can be no assurance that we will
not do so in the future.
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, 2017, 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, 2017, subject to meeting the vesting requirements, we had outstanding
options to purchase an aggregate of approximately 324,000,000 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. In addition, as of June 30, 2017, we had
warrants outstanding which may be exercised by warrant holders for 87,033,246 ordinary shares. The exercise prices of the
warrants and options is between 0.55 and 3.8 cents per share (Australian), and the warrants and options expire between
November 2017 and November 2026. The exercise of such warrants could have similarly adverse consequences on the trading
prices for our shares.
For further details on our outstanding
options and warrants, see “Note 10 – 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. However it is possible 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.