Item 1 and 2.
|
Business and Properties
|
Samson Oil & Gas Limited (“we”,
“Samson” or the “Company”) is a company limited by shares, incorporated on April 6, 1979 under the
laws of Australia. Our principal business is the exploration and development of oil and natural gas properties in the
United States. During the year, 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 for the seller of the assets.
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 is $15 million, and the
purchaser has provided a deposit of $1 million. The transaction was initially scheduled to close on August 31, 2016. Under
the terms of the purchase and sale agreement, the purchaser could extend the closing date to September 30, 2016 through the
payment of $50,000. The purchaser exercised this option on August 31, 2016. The terms of the agreement allow another
extension to October 31, 2016 upon payment of an additional $50,000. We have been advised by the purchaser that they intend
to close October 20, 2016. We have received the $50,000 payment. If the transaction has not closed by October 31, 2016, the
agreement will be terminated. The $1 million deposit is not refundable unless environmental or title issues are identified by
the purchaser during their due diligence. This asset consists of 22 producing Bakken and Three Forks wells. The effective
date of the transaction is the day after the transaction closes. $11.5 million of the proceeds from this transaction will be
used to pay down our credit facility with Mutual of Omaha Bank. The remaining proceeds will be used to rebalance our hedge
book, following the sale of a portion of our production and for working capital.
Upon the closing of the North Stockyard
sale, the combination of that transaction with the Foreman Butte purchase would make a substantial contribution toward
improving our financial stability and restoring the loan to value ratio in our credit facility with Mutual of Omaha Bank.
We engaged Netherland, Sewell & 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 $66.5 million (before taxes) based on a present value calculation
with 10% discounting rate. This present value as of June 30, 2016, utilizes an adjusted realized pricing of $37.12 per Bbl for
oil and $0.37 per Mcf for natural gas. As of June 30, 2016, 87% of our proved reserves were oil and 37% was proved developed producing,
11% were proved non producing and 52% was proved undeveloped.
Our business strategy is to create a competitive
and sustainable rate of return to shareholders by exploring for, acquiring and developing oil and natural gas resources in the
United States. Our primary financial goal is to develop profitably our oil properties while maintaining a strong balance
sheet, and specifically to focus on the exploration, exploitation and development of our major oil project – the Foreman
Butte project in Montana and North Dakota.
We became required to file our periodic reports
to the SEC as a U.S. domestic issuer as of July 1, 2011. Since we remain an Australian corporation, however, we are still considered
to be a domestic company in Australia as well. As a result, we are required to report our financial results in the U.S.
using U.S. Generally Accepted Accounting Principles (“U.S. GAAP”) and in Australia using International Financial Reporting
Standards (“IFRS”).
We publish our consolidated financial statements,
both U.S. GAAP and IFRS, in U.S. dollars. In this annual report, unless otherwise specified, all dollar amounts are
expressed in U.S. dollars, and references to “dollars,” “$” 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. In prior years it has been completed by Ryder Scott
Company. The reports, as prepared by both independent reserve engineers were based upon their 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
in the current year and Ryder Scott in previous years.
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. Dan Smith, a licensed professional engineer in the state of Texas, has been practicing consulting
petroleum engineering at Netherland Sewell since 1980 and has over 7 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, 2016 was prepared by Netherland Sewell and June
30, 2015 was prepared by Ryder Scott Company L.P.
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, 2016 and 2015:
|
|
2016
|
|
|
2015
|
|
|
|
Oil
(MBbls)
|
|
|
Gas
(Mcf)
|
|
|
Total
(MBOE)
|
|
|
Oil
(MBbls)
|
|
|
Gas
(Mcf)
|
|
|
Total
(MBOE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
1,285
|
|
|
|
1,183
|
|
|
|
1,483
|
|
|
|
1,478
|
|
|
|
1,763
|
|
|
|
1,773
|
|
Revisions of previous quantity estimates
|
|
|
2,597
|
|
|
|
2,662
|
|
|
|
3,041
|
|
|
|
(376
|
)
|
|
|
(547
|
)
|
|
|
(467
|
)
|
Extensions and discoveries
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
414
|
|
|
|
193
|
|
|
|
446
|
|
Sale of reserves in place
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Acquisitions
|
|
|
6,340
|
|
|
|
5,317
|
|
|
|
7,226
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
(240
|
)
|
|
|
(569
|
)
|
|
|
(335
|
)
|
|
|
(231
|
)
|
|
|
(226
|
)
|
|
|
(269
|
)
|
End of year
|
|
|
9,982
|
|
|
|
8,593
|
|
|
|
11,415
|
|
|
|
1,285
|
|
|
|
1,183
|
|
|
|
1,483
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
3,724
|
|
|
|
3,092
|
|
|
|
4,240
|
|
|
|
1,285
|
|
|
|
1,183
|
|
|
|
1,483
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed non producing
|
|
|
970
|
|
|
|
1,800
|
|
|
|
1,270
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Proved undeveloped reserves
|
|
|
5,288
|
|
|
|
3,701
|
|
|
|
5,905
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Total proved reserves
|
|
|
9,982
|
|
|
|
8,593
|
|
|
|
11,415
|
|
|
|
1,285
|
|
|
|
1,183
|
|
|
|
1,483
|
|
Acquisition
The acquisition of reserves 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 acquisition date of Mach 31, 2016.
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 has accounted for the increase in reserves from March 31, 2016 to
June 30, 2016.
We have identified a further 29 wells that are economic to workover
in the current oil price environment. These wells are included in the proved non producing reserve category. The work to return
these wells to production is planned to be completed during the next year.
During the year ended June 30, 2015 we converted two proved undeveloped
locations to proved developed producing locations. We also drilled eight additional wells that are now categorized as PDP.
We have one well which was producing during the year ended June
30, 2015 but was classified as Proved Developed Producing Behind Pipe at June 30, 2015. It had estimated workover costs of $37,000
in order for it to commence production again. This work was completed during the first quarter of the current fiscal year.
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. We have identified a further
29 wells that are economic to workover in the current oil price environment. These wells are included in the proved non producing
reserve category. The work to return these wells to production is planned to be completed during the next year.
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. Following further technical review since the acquisition
date we have added 6 more PUD locations to the reserve value. We plan to drill these PUD wells within the next five years.
We did not convert any PUD locations during
the year ended June 30, 2016, as we had no PUD locations as at June 30, 2015.
During the year ended June 30, 2015 we successfully
drilled two PUD locations (with reserves of 141 MBbls at June 30, 2014) and converted them to PDP locations.
Production, Prices, Costs and Balance Sheet Information
Production
During the years ended June 30, 2016 and
2015, we produced 240,424 and 231,286 barrels of oil, respectively. During the years ended June 30, 2016 and 2015
we produced 569,008 and 226,707 Mcf of gas, respectively.
For the year ended 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 table discloses our oil and gas
production volume, revenue and expenses from the Foreman Butte field for the fiscal year ended June 30, 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.
For the year ended June 30, 2015
we had one Field (as such term is used within the meaning of applicable regulations of the SEC – See Glossary of
Technical Terms) that contained more than 15% of our total proved reserves, namely our interests in the North Stockyard project
in North Dakota.
The following table discloses our oil and gas
production volume, revenue and expenses from the North Stockyard field for the fiscal years ended June 30, 2015:
|
|
North Stockyard
|
|
Oil volume – Bbls
|
|
|
206,881
|
|
Revenue – $
|
|
$
|
11,021,976
|
|
Average Price per barrel – $
|
|
$
|
53.27
|
|
Gas volume – Mcf
|
|
|
127,660
|
|
Revenue – $
|
|
$
|
456,981
|
|
Average price per Mcf – $
|
|
$
|
3.58
|
|
Per unit production and lease operation costs per BOE – $*
|
|
$
|
22.70
|
|
Prices and Costs
The average sale price (excluding the impact
of derivative instruments) we achieved for oil during the years ended June 30, 2016 and June 30, 2015 was $34.27 and
$53.33 per barrel, respectively.
The average sale price we achieved for gas
during the years ended June 30, 2016 and June 30, 2015 was $1.25 and $3.68 per Mcf, respectively.
The average production costs (including lease
operating expenses, production taxes and handling expenses for oil and gas) per barrel of oil was $16.35 for the year ended June 30,
2016 and $22.91 for the year ended June 30, 2015.
Drilling Activity
|
|
Year Ended June 30
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Net productive exploratory wells drilled
|
|
|
Nil
|
|
|
|
Nil
|
|
|
|
Nil
|
|
Net dry exploratory wells drilled
|
|
|
0.25
|
|
|
|
0.25
|
|
|
|
Nil
|
|
Net productive development wells drilled
|
|
|
Nil
|
|
|
|
2.5
|
|
|
|
2.0
|
|
Net dry development wells drilled
|
|
|
Nil
|
|
|
|
Nil
|
|
|
|
Nil
|
|
Our productive development wells, drilled in
the previous years are all in our North Stockyard Project and are described below in “Description of Properties – North
Stockyard Project”.
The exploratory wells drilled in the current
year and the previous year were both drilled in our South Prairie project in North Dakota.
Present Drilling Activity
As of September 1, 2016, 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”, “2015 and 2016 Capital Expenditures” and “Estimated
2017 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 11, 2016, our wells and acreage
were as follows:
Gross productive oil wells
|
|
|
209
|
|
Net productive oil wells
|
|
|
107
|
|
Gross productive gas wells
|
|
|
5
|
|
Net productive gas wells
|
|
|
1
|
|
Wells with multiple completions
|
|
|
0
|
|
Gross Developed Acres
|
|
|
72,520
|
|
Net Developed Acres
|
|
|
53,246
|
|
Gross Undeveloped Acres
|
|
|
24,081
|
|
Net Undeveloped Acres
|
|
|
6,470
|
|
In March 2016, we closed on an acquisition,
our Foreman Butte project in Montana and North Dakota. This acquisition contributed 131 gross production oil wells and 94 net production
oil wells, to the total as of September 11, 2016.
All of our acreage positions are located in
the continental United States, with the majority located in Wyoming, 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, 2016 and June 30, 2015
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, 2016 and June 30, 2015 were $0.37 and $4.30 per Mcf, respectively. The 12-month historical average
of the first of the month prices used for oil for June 30, 2016 and June 30, 2015 were $37.12 and $59.64 per barrel of oil, respectively. Future
cash flows were reduced by estimated future development, abandonment and production costs based on period–end costs. No
deductions were made for general overhead, depletion, depreciation and amortization or any indirect costs. All cash
flows are discounted at 10%.
Changes in demand for hydrocarbons, inflation
and other factors make such estimates inherently imprecise and subject to substantial revisions. This table should not
be construed to be an estimate of current market value of the proved reserves attributable to Samson.
The following table shows the estimated standardized
measure of discounted future net cash flows relating to proved reserves (in US$’000’s):
|
|
As at June 30,
|
|
|
|
2016
|
|
|
2015
|
|
Future cash inflows
|
|
$
|
373,740
|
|
|
$
|
72,900
|
|
Future production costs
|
|
|
(184,691
|
)
|
|
|
(22,403
|
)
|
Future development costs
|
|
|
(50,752
|
)
|
|
|
(38
|
)
|
Future income taxes
|
|
|
-
|
|
|
|
0
|
|
Future net cashflows
|
|
|
138,297
|
|
|
|
50,459
|
|
10 % discount
|
|
|
(71,550
|
)
|
|
|
(16,206
|
)
|
Standardized measure of discounted future net cash flows relating to proved reserves
|
|
$
|
66,747
|
|
|
$
|
34,253
|
|
In March 2016, we closed the acquisition of
our Foreman Butte project. That project makes up $55.7 million in standardized measure of discounted future net cash flows relating
to proved reserves as disclosed in the table above.
On June 30, 2016 we signed a purchase and sale
agreement to sell our North Stockyard project. This project makes up $10.0 million in standardized measure of discounted further
net cash flows relating to proved reserves as disclosed in the table above. The sale price of this asset was $15 million. This
sale is expected to close on October 20, 2016. The effective date of the transaction is the day after the closing date.
During the year ended June 30, 2015, we drilled
and completed ten wells which are classified as PDP wells, two of which were classified as PUD locations at June 30, 2014.
The principal sources of changes in the standardized
measure of discounted future net cash flows during the periods ended June 30, 2016 and June 30, 2015 are as follows (in
$’000’s):
|
|
Fiscal Year Ended June 30
|
|
|
|
2016
|
|
|
2015
|
|
Beginning of year
|
|
$
|
34,253
|
|
|
$
|
42,593
|
|
|
|
|
|
|
|
|
|
|
Sales of oil and gas produced during the period, net of production costs
|
|
|
(3,575
|
)
|
|
|
(7,178
|
)
|
Net changes in prices and production costs
|
|
|
(15,705
|
)
|
|
|
(22,610
|
)
|
Previously estimated development costs incurred during the period
|
|
|
-
|
|
|
|
1,898
|
|
Changes in estimates of future development costs
|
|
|
(14,545
|
)
|
|
|
-
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
11,266
|
|
Revisions of previous quantity estimates and other
|
|
|
18,074
|
|
|
|
(6,197
|
)
|
Sale of reserves in place
|
|
|
-
|
|
|
|
-
|
|
Purchase of reserves in place
|
|
|
41,564
|
|
|
|
-
|
|
Change in future income taxes
|
|
|
-
|
|
|
|
11,809
|
|
Accretion of discount
|
|
|
3,452
|
|
|
|
5,440
|
|
Other
|
|
|
3,229
|
|
|
|
(2,768
|
)
|
Balance at end of year
|
|
$
|
66,747
|
|
|
$
|
34,253
|
|
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 cashflows.
Description of Properties
Production information is shown net to our
interests. Our net revenue interest is included in the total amount.
Reserve information is presented as the net
value to us and is the net present value discounted at 10%, based on the forward strip pricing as at June 30, 2016 as calculated
by Netherland Sewell.
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.
Following the acquisition, we commenced a workover
program to return previously shut in wells to production. This program consisted of working over 32 wells for an estimated cost
of $0.8 million.
Since the effective date of the acquisition,
the Foreman Butte Project area produced 47,928 barrels of oil.
At June 30, 2016, the Foreman Butte
project had net proved reserves of 9.8 MMBo and 8.0 MMcf. These reserves include 3.5 MMBOE in proved developed producing reserves,
1.6 MMBOE in proved non producing reserves and 6.0 MMBOE in proved undeveloped reserves.
North Stockyard Project – Williston
Basin, North Dakota
Various working interests
The Bakken formation gained significant prominence
after the United States Geological Survey (USGS) published an estimate in April 2008 stating that the unit could recover between
3.0 and 4.3 billion barrels of oil. The USGS estimated that the Bakken formation represents a “continuous”
oil accumulation and suggested that advances in completion technology have increased the estimated recovery potential by 25 times
since an earlier USGS study in 1995.
Together with our fellow working interest owners,
we have drilled twenty four wells in this field, fourteen in the Bakken Formation, eight in the Three Forks Formation, one in the
Mission Canyon formation and one in the second bench of the Three Forks Formation.
On June 30, 2016 we entered into a purchase
and sale agreement to sell our North Stockyard property for $15 million. This transaction is scheduled to close on October 20, 2016.
At June 30, 2016, the North Stockyard
project had net proved reserves of 0.8 MMBo and 1.3 MMcf.
State GC Oil and Gas Field, New Mexico
Average 32.2% Working Interest
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.
Average daily production during the year ended
June 30, 2016 from the State GC Oil and Gas Field was approximately 11
BOPD and 13 Mcf/d.
At June 30, 2016, the State GC Oil and
Gas Field had net proved reserves of 46,700 Bbls and 66,500 Mcf.
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.
Average daily producing during the year ended
June 30, 2016 from the Davis Bintliff #1 well was 1 BOPD and 108 Mcf/d
At June 30, 2016, the Davis Bintliff well
had net proved reserves of 1,900 Bbls and 222,100 Mcf.
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 is planned to be 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 is planned to be 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.
In October 2016, we plan to test the upper
canyon spring zone with a perforation and swab test. This operation is expected to cost $20,000, net to us. Should this operation
fail to produce economic quantities of hydrocarbons this well will be plugged immediately.
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.
Gretel II
100% working interest
We drilled our second appraisal (exploratory)
well in the Roosevelt Project, Gretel II, in January 2012 and fracture stimulated the well in March 2012. Based on the results,
it appears that this well was drilled on the north side of the Brockton Fault zone, which is believed to be the western edge of
the continuous Bakken oil formation. The Gretel II well is currently shut in, as it was mainly producing water, with just a 5%
oil cut. We do not believe that we will recover our costs associated with drilling it. We expensed $11.6 million of previously
capitalized exploration expenditure as deferred exploration expenditure, which represent 100% of the costs incurred to June 30,
2012. No further work was been performed on this well bore during the year ended June 30, 2015 or 2016.
This well has not produced during the year
ended June 30, 2016 and is expected to be plugged within the next two years.
In total, $24.7 million of previously capitalized
exploration expenditure has been expensed to the Statement of Operations as exploration expenditure written off in relation to
the drilling costs associated with these two wells during the year ended June 30, 2012.
During the year ended June 30, 2014, we entered into a seismic and
drilling agreement with Momentus Energy Corp (“Momentus”), a Canadian exploration and development company based in
Calgary, to further explore this project. Momentus shot and processed a 3D seismic survey over the acreage at no cost to us. They
were also required to drill a Bakken well in the project area. Due to the recent significant uncertainty in the oil markets, Momentus
declined to drill this well within the required time frame and thus the farm-out agreement is no longer valid.
As of June 30, 2015, we have elected to cease
all work in the Roosevelt Project and have started letting leases lapse through non- payment of delay rentals, in accordance with
the lease agreements. The remaining $8.1 million previously capitalized to the Balance Sheet with respect to this project was written
off to the Income Statement during the year ended June 30, 2015.
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 87,059 gross barrels of oil during
the year ended June 30, 2015. At June 30, 2016 the Gladys had reserves of 18,458 barrels of oil and 22,750 mcf of gas.
There has been no further drilling activity
on this lease during the year ended June 30, 2016 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.
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, 2016.
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 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, 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. They also can impose substantial liability for the costs of removal or remediation associated with 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 twice 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. If enacted, 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. The draft report has not yet been finalized but a FY2016 budget
request was made to fund a response to comments on the draft and to finalize the report.
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. 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 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. 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.
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 Environmental Protection Agency (“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. 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. 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. Strict liability means liability without fault, and
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, including,
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 22nd, 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 it is expected
to be issued in final form later this year. The proposed 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 $3.4 million as of June 30,
2016. 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, 2016, we had 11 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. 7 employees are located in Denver, Colorado and 2 are located in North Dakota and work
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, 2016, we had drawn $30.5 million of the
$30.5 million borrowing base under our credit facility. We were required to pay down our borrowing base by $10 million by
June 30, 2016 however on June 30, 2016 we received an extension to make this pay down by August 31, 2016. We received a
further extension to October 31, 2016 from Mutual of Omaha Bank following the extension in the anticipated closing date of
our sale of the North Stockyard field.
Under the purchase and sale agreement, the
purchaser of the North Stockyard field has the right to receive a further extension to the closing date to October 31, 2016 following
the payment of $50,000. The purchaser has exercised this right and we have received payment of $50,000. We have also received
an extension from Mutual of Omaha Bank with respect to paydown.
If the sale of the North Stockyard field fails
to close by October 31, 2016 we would need to examine other options to meet Mutual of Omaha’s paydown requirements, including
the sale of other assets, further capital raisings or a new credit facility with an alternative credit provider. This facility
may be more expensive and restrictive that our current facility.
In addition to amounts outstanding under our
credit facility, the seller in the Foreman Butte acquisition financed an additional $4 million of the purchase price through a
secured promissory note issued at closing. The note has a 12-month term and bears interest at 10%. The note is secured by a second-lien
mortgage and security interest in substantially all of the acquired assets.
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. As a result, there are uncertainties with respect to our liquidity, which uncertainty led our auditors
in Australia to note, in their report accompanying our fiscal 2016 annual report to the ASX, the existence of a material uncertainty
which may cast significant doubt about our ability to continue as a going concern.
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 date has been extended to November 15,
2016 (we raised $1.4 million in April 2016 towards this total and we expect Mutual of Omaha to apply the remaining proceeds
from the North Stockyard sale against this balance however there can be no guarantee they will agree to this); (6) paying
down at least $10 million of the credit facility by June 30, 2016 (which date has subsequently been extended, 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.
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 an impairment on the carrying
value of our oil and gas assets during the fiscal year ended June 30, 2016 and 2015, and may again in the future record additional
impairments.
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. The impairment expense recognized in both years is primarily in relation to our 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.
Emerging plays, such as our Hawk Springs
and Roosevelt Projects, are subject to heightened risks.
Part of our strategy through the years ended
June 30, 2013, 2014 and 2015 was to pursue acquisition, exploration and development activities in emerging plays such as our Hawk
Springs Project and Roosevelt Project. Our drilling results in these areas are more uncertain than drilling results in areas that
are developed and producing. Because emerging plays have limited or no production history, we have access to little if any past
drilling results in those areas to help predict the results of our own exploratory drilling. In addition, part of our strategy
to maximize recoveries from such new projects may involve the drilling of horizontal wells and/or using completion techniques that
have proven to be successful in other similar formations.
Given the continued decline in the oil price,
we do not intend to invest in our exploration plays in the near future. However, if the oil price recovers, we may determine it
is in the best interests of the company to resume exploration activities.
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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the ability of Samson to access the capital required to develop proved undeveloped locations;
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the accuracy of various mandated economic assumptions; and
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the judgment of the engineers preparing the estimate.
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Actual future production, natural gas and oil
prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves
will likely vary from our estimates. Any significant variance could materially affect the quantities and value of our reserves. Our
reserves may also be susceptible to drainage by operators on adjacent properties. We are required to adjust our estimates
of proved reserves to reflect production history, results of exploration and development and prevailing gas and oil prices.
These reserve reports are necessarily imprecise and may significantly vary depending on the judgment of the reservoir engineering
consulting firm.
Investors should not construe the present value
of future net cash flows as the current market value of the estimated oil and natural gas reserves attributable to our properties. The
estimated discounted future net cash flows from proved reserves are based on
the
average of the sales price on the first day of each month in the applicable year, with costs determined as of the date of the estimate
,
in accordance with applicable regulations, even though actual future prices and costs may be materially higher or lower.
As
a result of significant recent declines in commodity prices, such average sales prices are significantly in excess of more recent
prices. Unless commodity prices or reserves increase, the estimated discounted future net cash flows from our proved reserves would
generally be expected to decrease as additional months with lower commodity sales prices will be included in this calculation in
the future.
Factors that will affect actual future net cash flows include:
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the amount and timing of actual production;
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the price for which that oil and gas production can be sold;
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supply and demand for oil and natural gas;
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curtailments or increases in consumption by natural gas and oil purchasers; and
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changes in government regulations or taxation.
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As a result of these and other factors, we
will be required to periodically reassess the amount of our reserves, which reassessment may require us to recognize a write–down
of our oil and gas properties, as occurred at June 30, 2016 and June 30, 2015.
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 $30.5 million and we are drawn to $30.5 million as at June 30, 2016. 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 remain significantly
lower than those used in the last redetermination, including as a result of the recent decline in oil prices or an expectation
that such reduced 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 borrowing base will automatically
be reduced to $19 million on October 31, 2016 in accordance with an amendment to our credit agreement, following the extension
in the facility to partially fund the Foreman Butte acquisition and an agreement from Mutual of Omaha Bank with respect to the
sale of the North Stockyard properties. We currently expect the credit line to be paid down with $11.5 million of the total proceeds
from the close of the North Stockyard assets. However, there can be no assurance that this transaction will close or that we may
successfully pay down our credit line. We expect our next determination in October 2016 based our reserves as of June 30, 2016.
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.
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, 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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cratering and explosions;
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pipe failures and ruptures;
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pipeline accidents and failures;
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mechanical and operational problems that affect production;
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formations with abnormal pressures;
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uncontrollable flows of oil, natural gas, brine or well fluids;
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releases of contaminants into the environment; and
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failure of subcontractors to perform or supply goods or services or personnel shortages.
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These industry operating risks can result in
injury or loss of life, severe damage to or destruction of property, damage to natural resources and equipment, pollution or other
environmental damage, clean–up responsibilities, regulatory investigation and penalties, and suspension of operations, any
of which could result in substantial losses. In addition, maintenance activities undertaken to reduce operational risks can be
costly and can require exploration, exploitation and development operations to be curtailed while those activities are being completed.
We may also be subject to damage claims by other oil and gas companies.
We do not maintain insurance in amounts that
cover all of the losses to which we may be subject, and some risks, such as pollution and environmental risks, are not generally
fully insurable. Our insurance policies and contractual rights to indemnity may not adequately cover our losses, and we do
not have access to insurance coverage or rights to indemnity for all risks. If a significant accident or other event occurs and
is not fully covered by insurance or contractual indemnity, it could adversely affect our financial position and results of operations.
Other business risks also include the risk
of cyber security breaches. If management’s systems for protecting against cyber security risk prove not to be sufficient,
the company could be adversely affected such as by having its business systems compromised, its proprietary information altered,
lost or stolen, or its business operations disrupted.
Competition in the oil and natural gas
industry is intense, which may adversely affect our ability to succeed.
The oil and natural gas industry is highly
competitive, and we compete with other companies that are significantly larger and have greater resources. Many of these companies
not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products
on a regional, national or worldwide basis. These companies may be able to pay higher prices for productive oil and natural
gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects
than our financial or human resources permit. In addition, these competitors may have a greater ability to continue exploration
activities during periods of low oil and natural gas market prices. Our larger competitors may also be able to absorb the
burden of present and future federal, state, local and other laws and regulations more easily than we can. Our ability to
acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select
suitable properties and to consummate transactions in this highly competitive environment.
Intense competition in the oil and gas
industry requires us 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:
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require applying for and receiving permits before drilling
commences;
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restrict the types, quantities and concentration of substances that can be released into the environment
in connection with drilling and production activities;
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limit or prohibit drilling activities on certain lands
lying within wilderness, wetlands, and other protected areas; and
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impose substantial liabilities for pollution resulting
from our operations.
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If any of our operations require federal permits
or otherwise involve a “major federal action” that significantly impacts the environment, we may be required to prepare
an environmental impact statement (“EIS”) pursuant to the National Environmental Policy Act (“NEPA”) 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.
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 some of our 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.
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. 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 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.
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.
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, 2016, 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 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 MKT 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.
We report as a U.S. domestic issuer,
which means increased compliance costs notwithstanding continued eligibility for certain NYSE MKT 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 MKT Company Guide. This permits us to apply to the NYSE MKT 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 MKT, 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 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, 2016, 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, 2016, we had outstanding options to purchase an aggregate of approximately 4,000,000 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,
2016, we had warrants outstanding which may be exercised by warrant holders for 316,615,486 ordinary shares. The exercise prices
of the warrants and options are between A$0.033 and A$0.039 per share, and the warrants and options expire between March 2017 and
April 2018. 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 and one of our named executive officers
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.