Item 2. Management’s Discussion and Analysis
of Financial Condition and Results of Operations.
The following is management’s discussion
and analysis of certain significant factors that have affected aspects of our financial position and the results of operations
during the periods included in the accompanying Condensed Financial Statements. You should read this in conjunction with the discussion
under “Management's Discussion and Analysis of Financial Condition and Results of Operations” and the audited Financial
Statements for the year ended June 30, 2017, included in our Annual Report on Form 10-K and the Consolidated Financial
Statements included elsewhere herein.
Throughout this report, a barrel of oil
or “Bbl” means a stock tank barrel (“STB”) and a thousand cubic feet of gas or “Mcf” means
a thousand standard cubic feet of gas (“Mscf”).
Overview
We are an independent energy company primarily
engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Our principal business
is the exploration and development of oil and natural gas properties in the United States.
In March 2016 we closed on an acquisition
(the “Foreman Butte Acquisition”) of certain assets located in North Dakota and Montana, which we refer to as the “Foreman
Butte Project,” for a purchase price of $16 million. The acquired assets were comprised of producing oil and gas wells, shut
in wells and associated facilities. The wells are located in the Madison and Ratcliffe formations. The majority of these wells
are operated by us, however a number of non-operated wells were also included in this package. We continue to concentrate our efforts
on the operations of this field. Due to financial constraints we have not made substantial progress on the development of the PUD
drilling program in the Home Run field. Our development efforts are currently constrained by our lack of access to capital to fund
any development activities. We have four current drilling permits for our Home Run field and anticipate drilling our first PUD
well as soon as we obtain the necessary funding through a refinance of our credit facility or through the partial sale of our North
Dakota and Montana assets, through there can be no assurance this will be possible.
Fiscal quarter overview
Our net oil production was 50,846 barrels
of oil for the quarter ended December 31, 2017, compared to 76,784 barrels of oil for the quarter ended December 31, 2016. Production
was higher during the period ended December 31, 2016 due to increased production from a number of wells that were worked over towards
the end of June 2016 and into the first quarter of the 2017 fiscal year. Subsequent production has generally decreased in line
with the expected decline curves. In light of recent weakness and volatility in the oil price and our lack of access to capital,
we have discontinued workovers on marginally economical wells that continued to halt production during the period ended December
31, 2017. In addition, during the period ended December 31, 2017 production at two of our more significant wells was halted for
a period of time due to surface facility issues. In particular, the R Field did not produce for 16 days during the current quarter
and the Evans well was shut in for 13 days.
Our net gas production was 7,729 Mcf for
the quarter ended December 31, 2017, compared to 15,186 Mcf for the quarter ended December 31, 2016. Coupled with the decrease
in natural gas production following our North Stockyard sale, one of our significant gas wells, the Davis Bintliff well, has been
down since October 2016 while undergoing workover operations. These workover operations were not successful and, as a result, this
well was plugged and abandoned. Associated gas produced in the Foreman Butte project area is not as significant as it was in the
oil and gas properties previously owned by the Company, therefore the increased gas production from the acquisition has not offset
the decline from the sale.
Lease operating expenses (“LOE”)
decreased from $2.9 million for the quarter ended December 31, 2016, to $1.2 million for the quarter ended December 31, 2017 due
to lower production. Costs per BOE, excluding the impact of the workovers and production taxes were $18.91 a barrel. Costs have
decreased from $32.50 for the quarter ended December 31, 2016 due to decreased salt water disposal costs in our Foreman Butte project
area and shutting in wells that are uneconomic. The wells in the Foreman Butte project area are also older wells than those we
have previously owned and require additional fresh water and hot oil cleanouts which may increase operating costs of the wells.
We are continuing to review our lease operating expenses and will shut wells in that are not economic to produce in the current
oil pricing environment.
During the quarter ended December 31, 2017
we commenced our water flood project for the Home Run field and successfully injected 7,700 barrels of water. The waterflood project
utilizes an existing wellbore, the Mays 1-20H, which is located on the flank of the field and is uneconomic to produce for oil.
The water flood is being used to add pressure to the reservoir which is expected to enhance the recovery of oil as well as lower
salt water disposal costs although we can make no assurances as to whether it will be successful.
For the three months ended December 31,
2017 and December 31, 2016, we reported a net loss of $1.5 million and a net loss of $1.8 million, respectively. The loss in the
current period reflects $0.4 million in depletion and amortization, $0.9 million in loss on derivative instruments and $0.3 million
in exploration written off.
Fiscal year to date overview
Our net oil production was 104,644 barrels
of oil for the six months ended December 31, 2017 compared to 167,602 barrels of oil for the six months ended December 31, 2016.
Production has decreased as result of the sale of our North Stockyard property, which closed on October 29, 2016. Production has
also decreased due to our decision to discontinue workovers on marginally economical wells that ceased production during the six-month
period ended December 31, 2017 due to our lack of access to capital.
Our net gas production was 12,190 Mcf for
the six months ended December 31, 2017, compared to 59,565 Mcf for the six months ended December 31, 2016. As discussed above,
coupled with the decrease in natural gas production following our North Stockyard sale, one of our significant gas wells, the Davis
Bintliff well, has been down since October 2016 while undergoing workover operations. These workover operations were not successful
and, as a result, this well was plugged and abandoned. Associated gas produced in the Foreman Butte project area is not as significant
as it was in the oil and gas properties previously owned by the Company, therefore the increased gas production from the acquisition
has not offset the decline from the sale.
LOE decreased from $5.1 million for the
six months ending December 31, 2016 to $2.9 million for the six months ending December 31, 2017. Costs reduction is primarily due
to tighter cost controls enforced in the field including shutting in wells that are uneconomic to produce in the current climate.
Our ability to continue as a going concern
is dependent on the renegotiation of our finance facilities to permit additional development of our oil and gas properties or a
monetization of some or all of those properties. We are engaged in discussions with a non-bank lender with respect to refinancing
our current credit facility. We are engaged in discussions with a non-bank lender with respect to refinancing our current credit
facility. We have reached an agreement with Mutual of Omaha Bank which requires us to provide it, on or before March 31, 2018,
with (a) an executed purchase and sale agreement evidencing the sale of Samson and its subsidiaries or our respective businesses
and assets, or (b) a fully-executed letter of intent or other form of commitment letter from a credible lender or other third party
reflecting a proposed refinance or payment of Samson’s outstanding obligations. The sale or refinance must be completed by
May 31, 2018 under such circumstances that allows Mutual of Omaha Bank to be fully repaid. Should we fail to meet these deadlines,
Mutual of Omaha Bank may start foreclosure proceedings or seek alternative remedies to being repaid including the sale of the outstanding
loan. All covenant breaches are waived during the period the agreement is in place. We have engaged PLS, an energy advisory group
to market the assets. Based on our current financial position we may be required to accept terms less favorable than would otherwise
be available to us. There also can be no assurances that we will be successful in renegotiation or refinancing of our debt or our
efforts explore the sale of some or all of our assets. These factors indicate there is substantial doubt about our ability to continue
as a going concern.
See “Results of Operations”
below.
In the execution of our strategy, our management is principally
focused on economically developing additional reserves of oil and on maximizing production levels through exploration, exploitation
and development activities on a cost-effective basis.
Notable Activities and Status of Material
Properties during the Quarter Ended December 31, 2017 and Current Activities
Acquisition: Producing Properties
Foreman Butte Project, McKenzie County,
North Dakota
Mississippian Madison Formation, Williston
Basin
Samson 87% Operated Average Working
Interest
We averaged a gross 560 BOEPD from our
operated wells in the Foreman Butte Project this quarter. The production has reduced by 250 BOEPD from the previous quarter due
to capital constraints leading to a decrease in well workovers. Well recompletions and optimizations are scheduled to resume for
the upcoming quarter, using the workover rig we acquired through an exchange of unused pumping units.
During the quarter, we commenced our water
flood pilot project for the Home Run Field by successfully injecting over 7,700 barrels of water. The waterflood pilot project
utilizes an existing wellbore, the Mays 1-20H, which is located on the flank of the field and is non-economic to produce for oil.
The water flood is being used to add pressure to the reservoir which is expected to enhance the recovery of oil. The well performance
in the offsetting wells will be monitored to establish the viability of the flood. The water being used is produced formation water
so that there is no chemical compatibility issue. In essence the water is being returned to the reservoir from which it originated.
This water will be trucked to the injector from the existing producing wells. We anticipate this water flood will allow us to resume
production at certain wells that have been shut-in for the past 2 years. These shut-in wells were previously uneconomic to produce
due to high water disposal costs. We cannot make assurances regarding the success of the water flood operation.
The Home Run Field (also known as the Foreman
Butte Field) is the largest areal oil field in our portfolio. It was developed on a 640-acre spacing pattern and our engineering
and geologic analyses have determined that only 3.2% of the original oil in place has been recovered to date. Given that oil fields
can recover up to 20% of their oil in place, there would appear to be significant un-developed oil to be recovered from this field.
Accordingly, we are planning to drill our
first development well this year, should we be able to access the necessary capital to allow us to fund the drilling cost. The
first lateral will test the Ratcliffe Formation of the Mississippian Madison Group. Currently 26 Ratcliffe PUD (“proved undeveloped
drilling”) locations have been identified. The second lateral will test an undeveloped reservoir in the Mission Canyon Formation
of the Mississippian Madison Group. This lateral could prove up a new oil field with the potential for many additional well locations
(up to 20 vertical wells or 8 drill-out laterals, although we can make no assurances regarding the success of this lateral). A
3,500 acre 4-way structural closure has been mapped from an abundance of existing well control in the area. In 2004, the Banks
1-18H well was planned to be drilled as a dual lateral in both the Ratcliffe and Mission Canyon reservoirs. The Mission Canyon
lateral produced hundreds of barrels of oil while the lateral was being drilled. However, the well was completed as just a single
lateral in the Ratcliffe zone due to the operator being unable to remove a stuck whipstock that was set above the Mission Canyon
lateral in order to drill the Ratcliffe lateral. This stuck whipstock prevented the completion of the Mission Canyon lateral.
Several new PUDs in the Foreman Butte Project
were identified during the quarter. This has brought the total PUD count up to a total of 61 wells plus an additional 20 probable
locations within the Foreman Butte Project. Assuming we obtain financing to drill, this history makes the Company optimistic about
the prospects for the currently planned Mission Canyon lateral.
Undeveloped Properties: Exploration
Activities
Hawk Springs Project, Goshen County,
Wyoming
Permo-Penn Project, Northern D-J Basin
Samson 37.5% working interest
Following a delay due to bad weather in
the latter part of 2016, the recompletion of the Bluff #1-11 well has been further delayed due to our current focus on more capital
efficient projects in the Foreman Butte project area. The Jurassic Canyon Springs Formation will be perforated and flow tested
first. If this is unsuccessful, the Cretaceous Dakota Formation will subsequently be perforated and flow tested. This well will
be plugged and abandoned should these two operations be unsuccessful.
Cane Creek Project, Grand & San
Juan Counties, Utah
Pennsylvanian Paradox Formation, Paradox
Basin
Samson 100% Working Interest
Our option to lease 8,080 net acres with
Utah SITLA (Utah School and Institutional Trust Lands Administration) at a cost of $75 per acre expired on November 30, 2017, unexercised.
$0.3 million in undeveloped capitalized costs was written off in the three months ended December 31, 2017.
Developed Properties: Drilling
Activities
Rainbow Project, Williams County, North
Dakota
Mississippian Bakken Formation, Williston Basin
Samson 23% and 52% working interest
Kraken Operating, LLC, the operator of
the Gladys 1-20H well, has been producing this well at an average rate of 45 BOPD and 54 MCFPD during the quarter.
Results of Operations
For the three months ended December 31,
2017, we reported a net loss of $1.4 million compared to a net loss of $1.8 million for the same period in 2016.
For the six months ended December 31, 2017,
we reported a net loss of $3.2 million compared to a net loss of $2.4 million for the same period in 2016.
The following tables set forth selected
operating data for the three and six months ended:
|
|
Three months ended
|
|
|
|
31-Dec-17
|
|
|
31-Dec-16
|
|
Production Volume
|
|
|
|
|
|
|
|
|
Oil (Bbls)
|
|
|
50,846
|
|
|
|
76,784
|
|
Natural gas (Mcf)
|
|
|
7,279
|
|
|
|
15,186
|
|
BOE (Barrels of oil equivalent - based on one barrel of oil to six Mcf of natural gas)
|
|
|
52,059
|
|
|
|
79,315
|
|
|
|
|
|
|
|
|
|
|
Sales Price
|
|
|
|
|
|
|
|
|
Realized Oil ($/Bbls)
|
|
$
|
51.57
|
|
|
$
|
41.17
|
|
Impact of settled derivative instruments
|
|
$
|
(6.64
|
)
|
|
$
|
(8.93
|
)
|
Derivative adjusted price
|
|
$
|
44.92
|
|
|
$
|
32.24
|
|
|
|
|
|
|
|
|
|
|
Realized Gas ($/Mcf)
|
|
$
|
4.95
|
|
|
$
|
4.33
|
|
|
|
|
|
|
|
|
|
|
Expense per BOE:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
18.91
|
|
|
$
|
32.50
|
|
Production and property taxes
|
|
$
|
5.07
|
|
|
$
|
3.90
|
|
Depletion, depreciation and amortization
|
|
$
|
8.07
|
|
|
$
|
6.48
|
|
General and administrative expense
|
|
$
|
16.12
|
|
|
$
|
16.57
|
|
|
|
Six months ended
|
|
|
|
31-Dec-17
|
|
|
31-Dec-16
|
|
Production Volume
|
|
|
|
|
|
|
|
|
Oil (Bbls)
|
|
|
104,644
|
|
|
|
167,602
|
|
Natural gas (Mcf)
|
|
|
12,190
|
|
|
|
59,565
|
|
BOE
|
|
|
106,676
|
|
|
|
177,530
|
|
|
|
|
|
|
|
|
|
|
Sales Price
|
|
|
|
|
|
|
|
|
Realized Oil ($/Bbls)
|
|
$
|
49.75
|
|
|
$
|
40.26
|
|
Impact of settled derivative instruments
|
|
$
|
(4.45
|
)
|
|
$
|
(5.69
|
)
|
|
|
$
|
45.30
|
|
|
$
|
34.57
|
|
|
|
|
|
|
|
|
|
|
Realized Gas ($/Mcf)
|
|
$
|
7.00
|
|
|
$
|
3.50
|
|
|
|
|
|
|
|
|
|
|
Expense per BOE:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
22.94
|
|
|
$
|
24.81
|
|
Production and property taxes
|
|
$
|
4.25
|
|
|
$
|
3.70
|
|
Depletion, depreciation and amortization
|
|
$
|
8.42
|
|
|
$
|
5.82
|
|
General and administrative expense
|
|
$
|
20.61
|
|
|
$
|
13.89
|
|
The following table sets forth results
of operations for the following periods:
|
|
Three months ended
|
|
|
|
|
|
Three months ended
|
|
|
|
31-Dec-17
|
|
|
31-Dec-16
|
|
|
2Q17 to 2Q16
|
|
|
30-Sep-17
|
|
|
2Q17 to 1Q17
|
|
Oil sales
|
|
$
|
2,621,994
|
|
|
$
|
3,161,515
|
|
|
$
|
(539,521
|
)
|
|
$
|
2,584,521
|
|
|
$
|
37,473
|
|
Gas sales
|
|
|
36,033
|
|
|
|
65,752
|
|
|
|
(29,719
|
)
|
|
|
49,257
|
|
|
|
(13,224
|
)
|
Other liquids
|
|
|
1,601
|
|
|
|
11,540
|
|
|
|
(9,939
|
)
|
|
|
1,579
|
|
|
|
22
|
|
Interest income
|
|
|
54
|
|
|
|
161
|
|
|
|
(107
|
)
|
|
|
58
|
|
|
|
(4
|
)
|
Other
|
|
|
-
|
|
|
|
1,634,174
|
|
|
|
(1,634,174
|
)
|
|
|
178,658
|
|
|
|
(178,658
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
(1,249,052
|
)
|
|
|
(2,887,532
|
)
|
|
|
(1,638,480
|
)
|
|
|
(1,651,677
|
)
|
|
|
(402,625
|
)
|
Depletion, depreciation and amortization
|
|
|
(420,107
|
)
|
|
|
(514,049
|
)
|
|
|
(93,942
|
)
|
|
|
(478,058
|
)
|
|
|
(57,951
|
)
|
Abandonment
|
|
|
(25,820
|
)
|
|
|
-
|
|
|
|
25,820
|
|
|
|
(40,856
|
)
|
|
|
(15,036
|
)
|
Exploration and evaluation expenditure
|
|
|
(279,340
|
)
|
|
|
(18,490
|
)
|
|
|
260,850
|
|
|
|
(3,173
|
)
|
|
|
276,167
|
|
Accretion of asset retirement obligations
|
|
|
(79,715
|
)
|
|
|
(76,841
|
)
|
|
|
2,874
|
|
|
|
(80,171
|
)
|
|
|
(456
|
)
|
Interest expense
|
|
|
(331,184
|
)
|
|
|
(343,256
|
)
|
|
|
(12,072
|
)
|
|
|
(247,690
|
)
|
|
|
83,494
|
|
Loss on derivative instruments
|
|
|
(901,471
|
)
|
|
|
(1,488,504
|
)
|
|
|
(587,033
|
)
|
|
|
(667,395
|
)
|
|
|
234,076
|
|
Amortization of borrowing costs
|
|
|
(28,949
|
)
|
|
|
(66,849
|
)
|
|
|
(37,900
|
)
|
|
|
(28,950
|
)
|
|
|
(1
|
)
|
General and administrative
|
|
|
(839,282
|
)
|
|
|
(1,314,104
|
)
|
|
|
(474,822
|
)
|
|
|
(1,359,287
|
)
|
|
|
(520,005
|
)
|
Net loss
|
|
$
|
(1,495,238
|
)
|
|
$
|
(1,836,483
|
)
|
|
$
|
(341,245
|
)
|
|
$
|
(1,743,184
|
)
|
|
$
|
(247,946
|
)
|
Comparison of Quarter Ended December
31, 2017 to Quarter Ended December 31, 2016 and the six months ended December 31, 2017 to the six months ended December 31, 2016.
Oil and gas revenues
Oil revenues decreased from $3.2 million
for the three months ended December 31, 2016 to $2.6 million for the three months ended December 31, 2017, as a result of the decrease
in oil production. Oil production decreased from 76,784 barrels for the three months ended December 31, 2016 to 50,846 barrels
for the three months ended December 31, 2017. Production was higher during the period ended December 31, 2016, due to flush production
from a number of wells that were worked over towards the end of June 2016. Subsequent production has generally decreased in line
with the expected decline curves. In light of recent weakness and volatility in the oil price and our lack of access to capital,
we have discontinued workovers on marginally economical wells that stopped production during the period ended December 31, 2017.
In addition, during the period ended December 31, 2017, production at two of our more significant wells was halted for a period
of time due to surface facility issues. In particular, the R Field did not produce for 16 days during the current quarter and the
Evans well was shut in for 13 days.
The realized oil price increased from $41.17
per Bbl for the three months ended December 31, 2016 to $51.57 per Bbl (excluding the impact of derivatives) for the three months
ended December 31, 2017 following a recovery in the global oil price.
Gas revenues decreased from $0.1 million
for the three months ended December 31, 2016 to $0.05 million for the three months ended December 31, 2017. This decrease was due
to a decrease in production.
Oil revenues decreased from $6.7 million
for the six months ended December 31, 2016 to $5.2 million for the six months ended December 31, 2017, as a result of the decrease
in oil production. Oil production decreased from 167,602 barrels for the six months ended December 31, 2016 to 104,644 barrels
for the six months ended December 31, 2017. Production was higher during the period ended December 31, 2016, due to flush production
from a number of wells that were worked over towards the end of June 2016. Subsequent production has generally decreased in line
with the expected decline curves. In light of recent weakness and volatility in the oil price and our lack of access to capital,
we have discontinued workovers on marginally economical wells that stopped production during the period ended December 31, 2017.
In addition, during the period ended December 31, 2017, two of our more significant wells were shut in with surface facility issues.
In particular, the R Field did not produce for 44 days during the six months ended December 31, 2017 and the Evans well was shut
in for 21 days during the same period.
Gas revenues decreased from $0.2 million
for the six months ended December 31, 2016 to $0.1 million for the six months ended December 31, 2017. This decrease was due to
a decrease in production.
Sale of Assets
For the six months ended December 31, 2017
we recognized $0.2 million in profit on the sale of our working interest in a number of non operated wells in Wyoming. The wells
were sold for the value of the current accounts payable owed to the operator and the plugging liability.
During the six months ended December 31,
2016 we recognized $1.8 million in income from the sale of assets as result of the sale of our North Stockyard in North Dakota.
Exploration expense
Excluding deferred exploration costs written
off, exploration expenditures for the quarter and six months ended December 31, 2017 and December 31, 2016 were less than $20,000
for either quarter. $0.3 million in previously capitalized undeveloped acreage costs were written off during the three months ended
December 31, 2017 following the expiration of our option to lease acreage in the Cane Creek project area in Utah.
Impairment expense
We did not recognize any impairment expense during the three
months and six months ended December 31, 2017 or the three months and six months ended December 31, 2016.
Lease operating expense
Lease operating expenses (“LOE”)
decreased from $2.9 million for the quarter ended December 31, 2016, to $1.2 million for the quarter ended December 31, 2017 due
to lower production. Costs per BOE, excluding the impact of the workovers and production taxes were $18.91 a barrel. Costs have
decreased from $32.50 for the quarter ended December 31, 2016 due to decreased salt water disposal costs in our Foreman Butte project
area and shutting in wells that are uneconomic. The wells in the Foreman Butte project area are also older wells than those we
have previously owned and require additional fresh water and hot oil cleanouts which may increase operating costs of the wells.
We are continuing to review our lease operating expenses and will shut wells in that are not economic to produce in the current
oil pricing environment.
During the quarter ended December 31, 2017
we commenced our water flood project for the Home Run field and successfully injected 7,700 barrels of water. The waterflood project
utilizes an existing wellbore, the Mays 1-20H, which is located on the flank of the field and is uneconomic to produce for oil.
The water flood is being used to add pressure to the reservoir which is expected to enhance the recovery of oil as well as lower
salt water disposal costs although we can make no assurances as to whether it will be successful.
LOE decreased from $5.1 million for the
six months ending December 31, 2016 to $2.9 million for the six months ending December 31, 2017. Costs reduction is primarily due
to tighter cost controls enforced in the field including shutting in wells that are uneconomic to produce in the current climate.
Depletion, depreciation and amortization
expense
Depletion, depreciation and amortization
expense decreased slightly from $0.5 million for the quarter ended December 31, 2016 to $0.4 million for the quarter ended December
31, 2017. The decrease is due to a decrease in production.
Depletion, depreciation and amortization
expense decreased slightly from $1.0 million for the six months ended December 31, 2016 to $0.9 million for the six months ended
December 31, 2017. The decrease is due to a decrease in production.
General and administrative expense
General and administrative expense decreased
from $1.3 million for the quarter ended December 31, 2016 to $0.8 million for the quarter ended December 31, 2017. We have been
actively trying to reduce our general and administrative costs in recent periods. Effective October 1, 2017, all staff and directors
took 25% pay cuts in order to reduce salary costs. The cost of a number of consultants have also been reduced.
General and administrative expense decreased
from $2.5 million for the six months ended December 31, 2016 to $2.2 million for the six months ended December 31, 2017. This is
primarily due to the reduced salary costs following staff pay cuts and tighter cost control.
Cash Flows
The table below shows cash flows for the
following periods:
|
|
Six months ended
|
|
|
|
31-Dec-17
|
|
|
31-Dec-16
|
|
Cash used in operating activities
|
|
$
|
(66,034
|
)
|
|
$
|
(1,529,958
|
)
|
Cash (used in)/provided by investing activities
|
|
|
(170,161
|
)
|
|
|
12,029,347
|
|
Cash provided by/(used in) financing activities
|
|
|
450,000
|
|
|
|
(11,597,443
|
)
|
Cash used in operations decreased from
a net outflow of $1.5 million for the six months ended December 31, 2016, to a net outflow of $0.1 million for the six months ended
December 31, 2017. Cash receipts from customers decreased from $6.8 million for the six months ended December 31, 2016 to $6.1
million for the six months ended December 31, 2017, with an increase in price offset by a decrease in production. Payments to suppliers
and employees decreased from $6.6 million for the six months ended December 31, 2016 to $5.1 million for the six months ended December
31, 2017. Payments for derivative instruments decreased slightly from $0.7 million for the six months ended December 31, 2016 to
$0.5 million for the six months ended December 31, 2017. Interest expense decreased from $1.0 million for the six months ended
December 31, 2016 to $0.6 million for the six months ended December 31, 2017. An increase in interest rate was offset by a decrease
in the carrying value of the credit facility.
Cash used in investing activities decreased
from an inflow of $12.0 million for the six months ended December 31, 2016 (which included the sale of the North Stockyard project
for $14.0 million in cash proceeds) to an outflow of $0.2 million for the six months ended December 31, 2017 following a cessation
of significant activity in our Foreman Butte project, while we secure the additional capital needed to exploit the PUD locations
in this field.
Cash provided by financing activities increased
from a cash outflow of $11.6 million for the six months ended December 31, 2016 (including a repayment to Mutual of Omaha Bank)
to cash inflow of $0.5 million for the six months ended December 31, 2017, following the drawdown of funds under our Mutual of
Omaha Bank credit facility.
All options outstanding as at December
31, 2017 are currently out of the money.
Liquidity, Capital Resources and Capital
Expenditures
Our primary use of capital has been acquiring,
developing and exploring oil and natural gas properties. While we are planning for this to be our primary use of capital during
the remainder of fiscal 2017-2018, we cannot conduct any further development activities until we secure additional funding. There
can be no guarantee we will be able to secure this funding.
In January 2014, we entered into a $25.0
million credit facility with our primary lender, Mutual of Omaha Bank, with an initial borrowing base of $8.0 million, which was
increased to $15.5 million in June 2014. In November 2014, the borrowing base was increased to $19.0 million, which was fully drawn
prior to the closing of the Foreman Butte Acquisition. In March 2016, our credit facility was amended to increase the borrowing
base to $30.5 million to partially fund the Foreman Butte Acquisition. An additional $4 million in financing was also provided
by the seller. This promissory note was paid off in May 2017. We were required under the amended credit agreement to repay Mutual
of Omaha $10 million by June 30, 2016. This was ultimately increased to $11.5 million and extended to October 31, 2016. The pay
down was achieved through the sale of our North Stockyard property for $14.95 million on October 28, 2016 and was made on October
31, 2016.
In May 2017, Mutual of Omaha Bank agreed
to repay our outstanding promissory note to the seller of the Foreman Butte Acquisition through a term note in addition to our
current facility. This closed on May 5, 2017. Samson paid $0.45 million in interest from existing cash reserves, while Mutual of
Omaha Bank paid $4.0 million in principal.
As a result of this amendment to the credit
facility the interest changed from being based on LIBOR to the Wall Street Journal published Prime Rate (“Prime”).
The interest rate on the term loan is Prime plus 2.5% or approximately 6.5% and the credit facility is Prime plus 1.0% or 5%.
In June 2017, Samson and Mutual of Omaha
Bank agreed to extend both the $4 million term loan and our $19.45 million reserve base facility until October 2018. The previous
maturity date was October 31, 2017.
The current borrowing base is $24.0 million
and the balance of the drawn facility is $23.9 million.
The borrowing base under our credit facility
may be increased (up to the credit facility maximum of $50.0 million, which would require syndication of the loan) or decreased
in the future depending on the value of our reserves. Borrowing base redeterminations are performed by the lender every six months
based on our June and December reserve reports. We also have the ability to request a borrowing base redetermination at another
time, once a year. However, under the Agreement entered into between the Company and Mutual of Omaha Bank on February 9, 2018 (as
described below), the determination of the borrowing base as of October 31, 2017 has been postponed until March 31, 2018.
In March 2016, the facility was extended
to $30.5 million to partly fund the Foreman Butte Acquisition. As a result of this amendment to the facility agreement, the following
changes were made to the original facility agreement:
|
·
|
The addition of more restrictive financial
covenants (including the debt to EBITDA ratio and the minimum liquidity requirement);
|
|
·
|
Increases in the interest rate and unused
facility fee;
|
|
·
|
The addition of a minimum hedging requirement
of 75% of forecasted production;
|
|
·
|
A requirement to reduce our general and
administrative costs from $6 million per year to $3 million per year;
|
|
·
|
A requirement to raise $5 million in equity
on or before September 30, 2016, which deadline was extended and the condition was subsequently satisfied;
|
|
·
|
A requirement to pay down at least $10
million of the loan by June 30, 2016, which total was increased to $11.5 million and extended to October 31, 2016, and the condition
was satisfied on October 31, 2016; and
|
|
·
|
The addition of a monthly cash flow sweep
whereby 50% of cash operating income will be used to repay outstanding borrowings under the Credit Agreement. To date, $0.1 million
in repayments have been made under this covenant.
|
The credit facility includes the following
covenants, tested on a quarterly basis:
|
·
|
Current ratio greater than 1
|
|
·
|
Debt to EBITDAX (annualized) ratio no
greater than 4.00 for the quarter ended September 30, 2017 and thereafter
|
|
·
|
Senior leverage ratio of no greater than
3.75 for the quarter ending December 31, 2016 and thereafter
|
|
·
|
Interest coverage ratio minimum of between
2.5 and 1.0
|
As at December 31, 2017 we are in breach
of all four of these covenants.
On February 9, 2018 we entered into an
agreement (the “Agreement”) with Mutual of Omaha Bank. Under the Agreement we are required to provide Mutual of Omaha
Bank, on or before March 31, 2018, with either (a) an executed purchase and sale agreement evidencing the sale of Samson and its
subsidiaries or its respective businesses and assets, or (b) a fully-executed letter of intent or other form of commitment letter
from a credible lender or other financing source reflecting a proposed refinance or payment of Samson’s outstanding obligations.
Our credit facility has been recorded as a current liability
and is due for repayment October 2018. Upon termination of the Agreement, if we still do not meet the credit facility covenants,
the due date of our debt could be accelerated by the lender. In addition, in the interim, our continued failure to comply with
these covenants under our credit facility would adversely affect our ability to fund ongoing operations.
The funds drawn from our credit facility
were previously used to fund drilling in our North Stockyard project in North Dakota and, more recently, to partially fund the
Foreman Butte acquisition.
The uncertainties surrounding our capital
resources and requirements are further exacerbated by the variable results of our exploration and drilling program and changes
in oil and natural gas prices, either of which could lead us to accelerate or decelerate exploration and drilling activities. The
aggregate levels of capital expenditures for our fiscal year ending June 30, 2018, and the allocation of those expenditures, are
dependent on a variety of factors, including the availability of capital resources to fund those expenditures and changes in our
business assessments as to where our capital can be most profitably employed. Accordingly, the actual levels of capital resources
and expenditures and the allocation of those expenditures may vary materially from our estimates.
We are continually monitoring the capital
resources available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our
future success in growing our proved reserves and production will be highly dependent on capital resources available to us and
our success in finding or acquiring such additional productive reserves.
Our main source of liquidity during the
three months ended December 31, 2017 was cash on hand.
During the prior four fiscal years, our
three main sources of liquidity were (i) borrowings under our credit facility, (ii) equity issued to raise $21.4 million and (iii)
our tax refund of $5.6 million from the Internal Revenue Service, received in February 2013. During the years prior to the fiscal
year ended June 30, 2012, our primary sources of liquidity were the sale of acreage and other oil and gas assets.
Our cash position as of December 31, 2017
increased slightly from June 30, 2017 largely due an increase in our accounts payable balance.
In October 2016, we closed on the sale
of our North Stockyard project for $15.05 million. $11.5 million of the proceeds of the sale were used to pay down our credit facility
with Mutual of Omaha Bank. $0.2 million was used to close out a portion of our hedge positions to balance our hedge book following
the sale of production. The remaining $3.35 million, including the $1.0 million deposit paid in June 2016, was used for future
working capital
In April 2016, we issued 378,020,400 ordinary
shares at $0.0037 per ordinary share to raise gross proceeds of $1,398,675.
In April 2016, we also received cash of
$725,000 from Halliburton following the settlement of our legal dispute with them.
If future production rates are less than
anticipated, and/or the oil price continues to deteriorate for an extended period, the value of our position in affected areas
will decline, our results of operations, financial condition and liquidity will be adversely impacted and we could incur material
write-downs of oil and gas properties. Our ability to continue operations could also be adversely affected. See the risk factors
in our Annual Report on Form 10-K for the fiscal year ended June 30, 2017. See also Part II, Item 1A of this report below.
Off-Balance Sheet Arrangements
Since our inception, we have not engaged
in any off-balance sheet arrangements, including the use of structured finance, special purpose entities or variable interest entities.
Looking Ahead
We plan to focus on the following objectives
in the coming 12 months:
|
·
|
Achieving the sale of our business or
assets, or a refinancing of our debt, under the terms of the Agreement;
|
|
·
|
Continued focus on cost savings and efficiency
across all aspects of the Company, including lease operating costs and general and administrative costs;
|
|
·
|
Strengthening the balance sheet through
diligent capital management;
|
|
·
|
The successful integration of the properties
and assets acquired in the Foreman Butte Acquisition, and the review and workover of such assets as capital becomes available;
and
|
|
·
|
Renegotiation of our credit facility and
extend its term.
|
Our ability to meet these objectives, depends
on our success in raising additional capital to fund the planned development of our oil and gas properties.