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, 2015, 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 strategy
is to focus on the exploration, exploitation and development of our major oil plays – the Niobrara, Permian and Pennsylvanian
in Goshen County, Wyoming and the Bakken in Williams County, North Dakota. In March 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 consist 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 will
be operated by us, however there are a number of non-operated wells also included in this package. We have been approved as operator
of record by the Montana Board of Oil and Gas Conservation effective May 1, 2016 for the locations in Montana. We are still waiting
on approval from the North Dakota Industrial Commission for locations in North Dakota. We expect to receive this by June 1, 2016.
Our net oil production was 41,927 barrels
of oil for the quarter ended March 31, 2016 (excluding the impact of acquired production), compared to 63,750 barrels of oil for
the quarter ended March 31, 2015. The decrease in oil production was due to the natural decline in production witnessed in
Bakken wells.
Our net gas production was 92,399 Mcf for
the quarter ended March 31, 2016, compared to 75,615 Mcf for the quarter ended March 31, 2015. The increase in gas production is
due to gas capture facilities being built on more well locations over the prior 12 months.
Our net oil production was 154,156 barrels
of oil for the nine months ended March 31, 2016 compared to 142,272 barrels of oil for the nine months ended March 31, 2015. The
increase in oil production is due to new wells commencing production in our North Stockyard project during the year ended June
30, 2015.
Our net gas production was 271,469 Mcf
for the nine months ended March 31, 2016, compared to 159,466 Mcf for the nine months ended March 31, 2015.
For the three months ended March 31, 2016
and March 31, 2015, we reported a net loss of $1.3 million and a net loss of $1.9 million, respectively. The loss in the current
period reflects a $0.9 million in depletion, amortization and impairment while the loss in the prior period reflects
a $2.2 million depletion, amortization and impairment expenditure. See “Results of Operations” below.
For the nine months ended March 31, 2016 and March 31, 2015, we reported a net loss of $18.1 million and a net loss of $15.5
million, respectively. The loss in the current period reflects a $4.2 million in exploration expenditure and impairment expense
of $9.9 million while the loss in the prior period reflects a $3.6 million of impairment expenditure and $11.6 million in
write off of previously capitalized exploration expenditure. 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 and Nine Months Ended March 31, 2016 and Current Activities
Acquisition: Producing Properties
Foreman Butte Project, McKenzie County,
North Dakota
Mississippian Madison Formation, Williston
Basin
Samson 87% Operated Average Working
Interest
On March 31
st
, we closed on
the acquisition of 51,305 net acres of oil and gas leases, producing oil and gas wells, currently shut-in wells and associated
facilities in North Dakota and Montana for a cash price of $16.0 million. The properties produced approximately 720 BOPD from 41
net producing wells, based on pre-acquisition data. Netherland Sewell & Associates have estimated that the properties contain
Proved Reserves of 8.5 million barrels of oil with a Net Present Value of $84.9 million as at October 1
st
, 2015, the
effective date of the transaction.
The 51,305 net acres of petroleum leases
that were acquired include the right to exploit hydrocarbons down to the top of the Bakken Formation. For a portion of the leases,
we are also acquiring the rights to the deeper geologic section below the Bakken pool. The properties have been in production for
several years and represent production from various geologic horizons above the Bakken Formation, including the Ratcliffe and Mission
Canyon intervals of the Mississippian Madison Formation which provide conventional oil and gas accumulations in this region. The
properties have largely been developed using 640 acre horizontal wells or 40 acre vertical wells. With the current lower oil service
costs, we envisages development of the acquired PUD locations by using longer laterals, infilling the historical 640 acre wells
or developing 40 acre infills adjacent to existing or known production.
Our immediate focus, however, will be on
the 18 wells in the PDNP category, since we expect that these wells can be bought back on line with minimal capital expenditure
of $500,000. If certain wells are not brought back on line in a timely fashion we may face plugging liabilities for these wells
earlier than we currently have planned. We also sees additional upside using an acid-based stimulation of the existing PDP and
PDNP wells in light of the reservoir’s calcium carbonate-based architecture. No stimulation of these reservoirs has ever
been undertaken but this style of stimulation treatment has resulted in a 4-10 times uplift in production rates in other wells
in the region, thought there can be no guarantee that we will achieve the same level of success.
We are still finalizing our acquisition
accounting for this project. This will be completed prior to the finalization of the June 30, 2016 10-K.
Undeveloped Properties: Exploration
Activities
Hawk Springs Project, Goshen County,
Wyoming
Permo-Penn Project, Northern D-J Basin
Samson 37.5% working interest
We have two contiguous areas in the Hawk
Springs Project. One of the areas is a joint venture with a private company and is subject to a joint venture with Halliburton
Energy Services, Inc.
The Bluff Prospect was drilled in June
2014 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. Various oil shows were observed in
the Cretaceous, Jurassic, Permian, and Pennsylvanian intervals while drilling. The Permian target zone (from 7738 feet to 7756
feet) exhibited excellent porosity (29% density porosity). Detailed analysis of the Permian target zone proved that it was the
source of the nitrogen gas that was seen while drilling the well. The presence of nitrogen in the Permian target zone validates
the trap in the Bluff prospect and has the potential to host an oil leg below the gas cap. This data led the partners to make the
decision to complete the Permian target sand.
The Permian target sand was flow tested
at a rate of 8 MMcf/D on a 21/64 inch choke during a 40 hour flow test and then shut-in for a 10 day build-up using down-hole gauges.
The buildup data has determined that the original reservoir pressure within the 9500 foot sand is 3,459 pounds per square inch.
A chromatographic analysis of the gas samples indicated that the majority of the gas was composed of nitrogen (97.5%), with some
helium (0.15%), carbon dioxide (0.15%), and the rest hydrocarbons (2.2%). A pressure transient analysis has confirmed that the
9500 foot sand is highly permeable and also identified a movable fluid boundary (oil or water) downdip of the well. Isotope Geochemistry
analysis of the gas samples, has identified the source of the nitrogen, which is from a post-mature organic kerogen in the black
shales of the Pennsylvanian section. The hydrocarbons in the samples are mixed thermogenic post mature gases generated in the wet
gas/condensate window. All of the gathered evidence supports the theory that the fluid below the gas cap is likely to be oil. The
gas-fluid interface has been identified through the integration of the pressure transient test data with newly processed inverted
seismic data.
We concluded our extended flow test on
the Bluff #1-11 well. The Permian Hartville sand (from 7738 feet-7756 feet) produced 1.2 BCF of nitrogen gas during a 100 day flow
test. The goals of the test were to determine the reservoir drive mechanism and the type of fluid (oil or water, which was identified
from the pressure transient analysis and seismic inversion data) beneath the nitrogen gas cap. From the pressure transient analysis
data, we forecasted that it would take another year and half before the water or oil leg could be seen at the well. The gas/fluid
contact moved 180 feet over the 100 day flow test period and would have to move another 420 feet to eventually reach the wellbore.
Due to this lack of movement, we have continued to shut the well in to monitor the pressure build-up which can hopefully determine
if there is any continuing fluid movement in the reservoir. We would expect to observe the pressure again during the quarter ended
June 30, 2016. If the pressure builds back up to the original bottom hole pressure, we may be able to determine that the drive
mechanism is an active water drive at which point it may be worth opening the well up again to flow and look for an oil leg. If
the bottom hole reservoir pressures remain low after the build-up, the Permian Hartville zone will be abandoned and additional
recompletions will occur in the uphole zones where other hydrocarbon shows were observed.
Following the continued degradation in
the oil price, $1.4 million, representing all current costs associated with this well were written off during the quarter ended
December 31, 2015. The review of the pressure buildup is expected to be completed by mid-year 2016 however additional costs are
not expected to be incurred with respect to this well unless a sustained recovery in the oil price is observed.
Spirit of America US34 #2-29 well
Samson 100% Working Interest
In an effort to establish continuous production
from the Muddy Formation, the tubing in the SOA 1-29 well was perforated 120 feet above the packer in September 2015 in order to
establish tubing and casing annulus communication. Two feet of perforations (7650 feet -7652 feet) were shot with four shots per
foot (eight shots fired in all). During October 2015, the well underwent a swabbing operation to remove a full column of fluid
from the wellbore to allow the well to flow freely. Subsequent to this operation, the well failed to produce economic quantities
of hydrocarbons and no further work is planned with respect to this well bore. $0.2 million in expense was written off to dry hole
costs in relation to this well during the quarter ended September 30, 2015. Additional costs of $0.2 million were incurred during
the quarter ended December 31, 2015 and have been written off to dry hole expense.
South Prairie Project, North Dakota
Mississippian Mission Canyon Formation, Williston Basin
Samson 25% working interest
Samson has a 25% working interest in 25,590
net acres located on the eastern flank of the Williston Basin in North Dakota. The first well of the project, the Matson #3-1 well
was drilled and determined to be a dry hole and was plugged and abandoned in the prior year
In June 2015, we elected to participate
in our proportionate 25% working interest in 900 net acres in the Birch prospect. The target zone is the Wayne zone of the Mississippian
Mission Canyon Formation to be found at an expected depth of 4,800 feet, measured depth. We participated at our proportionate
25% working interest in the drilling of the Badger #1 well in Section 29 of Township 157N, Range 81W in Ward County, North Dakota.
The well was drilled to a depth of 4,900 feet in 7 days for the total cost of approximately $350,000 (our share is approximately
$90,000). The prospect was identified as a 375 acre 4-way structural closure on the South Prairie 3-D seismic survey. Approximately
30 feet of structural closure relief was interpreted. The targeted porosity zone of the Mississippian Mission Canyon Formation
was found at a depth of 4,774 feet MD, which was 55 feet structurally high to the offsetting
Anschutz
Helseth #1 well and 36 feet high to the offsetting Apache Corporation’s Ward Estate #1-29 well proving the existence of the
4-way structural closure. However, low resistivity readings, a lack of oil shows, and calculated high water saturations (>80%)
indicate the targeted reservoir is non-productive. Hence, the decision was made to plug and abandon the well.
This well was drilled in
October 2015 and $0.1 million in costs was expensed to dry hole costs during the quarter ended December 31, 2015.
Cane Creek Project, Grand & San
Juan Counties, Utah
Pennsylvanian Paradox Formation, Paradox
Basin
Samson 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 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. In November 2015,
we paid an extension fee of $40,000 in order to extend the option period to December 2016. Subsequently, the MMDA has been finalized
and is awaiting signature by both parties. Upon entering into the MMDA, SITLA is obligated to deliver oil and gas leases covering
our project area at cost of $75 per acre to us.
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. The 3-D seismic is currently being designed to image these natural fractures. The seismic
shoot was surveyed and permitted this past summer. We believe this project has the potential to provide very robust economics in
a low priced oil environment using the evidence obtained from a nearby
competitor well that has
produced 802,967 BO in just over two years.
Developed Properties: Drilling
Activities
North Stockyard Oilfield, Williams County,
North Dakota
Mississippian Bakken Formation, Williston
Basin
Bakken & Three Forks infill wells
Samson ~25-30% working interest
On January 1, 2013, we and the operator
group negotiated a non-cash acreage swap for the Middle Bakken/First Bench of the Three Forks (MB/TF), whereby we traded certain
interests in our undeveloped acres in the Southern Tier for these parties’ undeveloped acres in the Northern Tier. As a result
of this acreage swap we owned 64% and 57%, respectively, in the two overlapping 1,280 acre spacing units located in the Northern
Tier. Our net production from current producing wells was not affected. In August 2013, we divested half our equity position in
the undeveloped acreage in the North Stockyard project to Slawson Exploration Company Inc. (“Slawson”) for $5.562 million
in cash and other consideration while retaining our full interest in the currently producing wells in the North Stockyard field.
Slawson is now the operator of the Northern Tier acreage.
Due to high hydrogen sulphide content in
the well, the Harstad well was plugged and abandoned during the current quarter ended September 30, 2015.
We have 22 wells in this field with all
wells currently producing.
Rainbow Project, Williams County, North
Dakota
Mississippian Bakken Formation, Williston Basin
Samson 23% and 52% working interest
In 2013, we acquired 656 acres in a 1,255
acre drilling unit and 294 acres in a 1,280 acre drilling unit. Both drilling units are located in the Rainbow Project, Williams
County, North Dakota. The Rainbow Project is located in Sections 17, 18, 19 and 20 in T158N R99W.
Samson acquired the net acres in the Rainbow
Project from the vendor as part of an acreage trade and is obligated provide a $1 million carry (10% of expected costs to drill
and complete the first well) to the vendor, for the first development well to be drilled in the Rainbow Project.
Samson has assessed the project based on
offset well data and believes that the project will support 16 wells, 8 in the middle Bakken and 8 in the first bench of the Three
Forks. These wells would be expected to be configured as north-south orientated 10,000 foot horizontals.
In the western drilling unit of the acquired
acreage, Samson holds a 52% working interest. In the eastern drilling unit, Samson’s interest is 23%. Continental Resources
has been designated as Operator, due to their larger working interest.
The first well in this project area, the
Gladys 1-20H well (23% working interest), was drilled and completed in January 2014. During the quarter the Gladys 1-20H well produced
11,858 barrels of oil (gross). Samson has no further drilling planned in this project area until there is a sustained recovery
in the oil prices.
Developed Properties: Production
Activities
North Stockyard Oilfield, Williams
County, North Dakota
Mississippian Bakken Formation, Williston
Basin
Samson various working interests
We have twenty three producing wells in
the North Stockyard Field. Currently all wells are producing. These wells are located in Williams County, North Dakota, in Township
154N Range 99W.
They produce 93% of our total oil production
and 84% of our total gas production for the March 2016 quarter.
Results of Operations
For the three months ended March 31, 2016,
we reported a net loss of $1.3 million compared to a net loss of $1.9 million for the same period in 2015.
For the nine months ended March 31, 2016
we reported a net loss of $18.1 million compared to a net loss of $15.5 million for the same period in 2015.
The following tables sets forth selected
operating data for the three months ended:
|
|
Three months ended
|
|
|
|
31-Mar-16
|
|
|
31-Mar-15
|
|
|
31-Dec-15
|
|
Production Volume
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls)
|
|
|
41,927
|
|
|
|
63,750
|
|
|
|
51,888
|
|
Natural gas (Mcf)
|
|
|
92,399
|
|
|
|
71,188
|
|
|
|
93,332
|
|
BOE (Barrels of oil equivalent - based on one barrel of oil to six Mcf of natural gas)
|
|
|
57,327
|
|
|
|
75,615
|
|
|
|
67,443
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Oil ($/Bbls)
|
|
$
|
22.91
|
|
|
$
|
37.62
|
|
|
$
|
36.58
|
|
Impact of settled derivative instruments
|
|
$
|
13.78
|
|
|
$
|
9.69
|
|
|
$
|
1.74
|
|
Derivative adjusted price
|
|
$
|
36.69
|
|
|
$
|
47.31
|
|
|
$
|
38.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Gas ($/Mcf)
|
|
$
|
1.69
|
|
|
$
|
3.71
|
|
|
$
|
2.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expense per BOE:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
8.58
|
|
|
$
|
12.97
|
|
|
$
|
12.38
|
|
Production and property taxes
|
|
$
|
2.96
|
|
|
$
|
4.30
|
|
|
$
|
4.16
|
|
Depletion, depreciation and amortization
|
|
$
|
13.80
|
|
|
$
|
21.94
|
|
|
$
|
20.75
|
|
General and administrative expense
|
|
$
|
15.74
|
|
|
$
|
15.23
|
|
|
$
|
13.52
|
|
|
|
Nine months ended
|
|
|
|
31-Mar-16
|
|
|
31-Mar-15
|
|
Production Volume
|
|
|
|
|
|
|
|
|
Oil (Bbls)
|
|
|
154,156
|
|
|
|
142,272
|
|
Natural gas (Mcf)
|
|
|
271,469
|
|
|
|
159,466
|
|
BOE
|
|
|
199,401
|
|
|
|
168,850
|
|
|
|
|
|
|
|
|
|
|
Sales Price
|
|
|
|
|
|
|
|
|
Realized Oil ($/Bbls)
|
|
$
|
34.26
|
|
|
$
|
55.80
|
|
Impact of settled derivative instruments
|
|
$
|
4.46
|
|
|
$
|
7.63
|
|
|
|
$
|
38.72
|
|
|
$
|
63.43
|
|
|
|
|
|
|
|
|
|
|
Realized Gas ($/Mcf)
|
|
$
|
2.15
|
|
|
$
|
4.19
|
|
|
|
|
|
|
|
|
|
|
Expense per BOE:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
13.76
|
|
|
$
|
19.38
|
|
Production and property taxes
|
|
$
|
3.76
|
|
|
$
|
5.96
|
|
Depletion, depreciation and amortization
|
|
$
|
18.43
|
|
|
$
|
22.11
|
|
General and administrative expense
|
|
$
|
14.42
|
|
|
$
|
21.46
|
|
The following table sets forth results
of operations for the following periods:
|
|
Three months ended
|
|
|
3Q16 to 3Q15
|
|
|
Three months ended
|
|
|
3Q16 to 2Q16
|
|
|
|
31-Mar-16
|
|
|
31-Mar-15
|
|
|
change
|
|
|
31-Dec-15
|
|
|
Change
|
|
Oil sales
|
|
$
|
960,705
|
|
|
$
|
2,398,226
|
|
|
$
|
(1,437,521
|
)
|
|
$
|
1,898,240
|
|
|
$
|
(937,535
|
)
|
Gas sales
|
|
|
156,333
|
|
|
|
263,823
|
|
|
|
(107,490
|
)
|
|
|
210,212
|
|
|
|
(53,879
|
)
|
Other liquids
|
|
|
9,580
|
|
|
|
-
|
|
|
|
9,580
|
|
|
|
27,201
|
|
|
|
(17,621
|
)
|
Interest income
|
|
|
255
|
|
|
|
6,365
|
|
|
|
(6,110
|
)
|
|
|
667
|
|
|
|
(412
|
)
|
Gain on derivative instruments
|
|
|
-
|
|
|
|
371,852
|
|
|
|
(371,852
|
)
|
|
|
200,017
|
|
|
|
(200,017
|
)
|
Other
|
|
|
879,330
|
|
|
|
1,297
|
|
|
|
878,033
|
|
|
|
265
|
|
|
|
879,065
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
(661,394
|
)
|
|
|
(1,306,117
|
)
|
|
|
644,723
|
|
|
|
(1,102,441
|
)
|
|
|
441,047
|
|
Depletion, depreciation and amortization
|
|
|
(791,104
|
)
|
|
|
(1,658,784
|
)
|
|
|
867,680
|
|
|
|
(1,399,511
|
)
|
|
|
608,407
|
|
Impairment
|
|
|
(49,126
|
)
|
|
|
(543,820
|
)
|
|
|
494,694
|
|
|
|
(9,682,965
|
)
|
|
|
9,633,839
|
|
Abandonment expense
|
|
|
-
|
|
|
|
(11,868
|
)
|
|
|
11,868
|
|
|
|
-
|
|
|
|
-
|
|
Exploration and evaluation expenditure
|
|
|
(21,399
|
)
|
|
|
(93,041
|
)
|
|
|
71,642
|
|
|
|
(3,699,651
|
)
|
|
|
3,678,252
|
|
Accretion of asset retirement obligations
|
|
|
(15,353
|
)
|
|
|
(9,186
|
)
|
|
|
(6,167
|
)
|
|
|
(15,116
|
)
|
|
|
(237
|
)
|
Interest expense
|
|
|
(207,650
|
)
|
|
|
(176,415
|
)
|
|
|
(31,235
|
)
|
|
|
(196,357
|
)
|
|
|
(11,293
|
)
|
Loss on derivative instruments
|
|
|
(358,514
|
)
|
|
|
-
|
|
|
|
(358,514
|
)
|
|
|
(196,357
|
)
|
|
|
(162,157
|
)
|
Amortization of borrowing costs
|
|
|
(35,485
|
)
|
|
|
(35,063
|
)
|
|
|
(422
|
)
|
|
|
(35,486
|
)
|
|
|
1
|
|
Acquisition costs
|
|
|
(215,853
|
)
|
|
|
-
|
|
|
|
(215,853
|
)
|
|
|
-
|
|
|
|
(215,853
|
)
|
General and administrative
|
|
|
(902,455
|
)
|
|
|
(1,151,294
|
)
|
|
|
248,839
|
|
|
|
(911,925
|
)
|
|
|
9,470
|
|
Net loss
|
|
$
|
(1,252,130
|
)
|
|
$
|
(1,944,025
|
)
|
|
$
|
691,895
|
|
|
$
|
(14,903,207
|
)
|
|
$
|
13,651,077
|
|
Comparison of Quarter Ended March 31,
2016 to Quarter Ended March 31, 2015 and for the nine months ended March 31, 2016 and nine months ended March 31, 2015.
The completion of the acquisition of
the Foreman Butte project has not had any material impact on the results for the quarter or the nine months ended March 31, 2016
as the transaction was closed on March 31, 2016. We anticipate filing a Form 8-K for this transaction prior to June 15, 2016.
Oil and gas revenues
Oil revenues decreased from $2.4 million
for the three months ended March 31, 2015 to $1.0 million for the three months ended March 31, 2016, as a result of the decrease
in the oil price and a decrease in oil production. Oil production decreased from 63,750 barrels for the three months ended March
31, 2015 to 41,927 for the three months ended March 31, 2016 due to natural decline associated with our wells, the majority of
which are Bakken producers, which traditionally have a high decline rate in the first few years post drilling. The realized oil
price also decreased from $37.62 per Bbl for the three months ended March 31, 2015 to $22.91 per Bbl (excluding the impact of derivatives)
for the three months ended March 31, 2016 following a decrease in global oil prices.
Oil revenues decreased from $7.9 million
for the nine months ended March 31, 2015 to $5.3 million for the nine months ended March 31, 2016, as a result of the decrease
in the oil price. Oil production increased slightly from 142,272 barrels for the nine months ended March 31, 2015 to 154,159 for
the nine months ended March 31, 2016. The slight increase in production is due to the impact of the development of our North Stockyard
field which was completed during the year ended June 30, 2015. The realized oil price decreased significantly from $55.8 per Bbl
for the nine months ended March 31, 2015 to $34.26 per Bbl (excluding the impact of derivatives) for the nine months ended March
31, 2016 following a decrease in global oil prices.
Gas revenues decreased from $0.3 million
for the three months ended March 31, 2015 to $0.2 million for the three months ended March 31, 2016. This decrease is due to a
decrease in the realized gas price which has offset an increase in production for the three month period. Production increased
from 71,188 Mcf for the quarter ended March 31, 2015 to 92,399 Mcf for the quarter ended March 31, 2016. The increase in production
was due to the operators of our North Stockyard field being able to capture and sell a greater percentage of gas production following
the installation of certain infrastructure improvements. The increase in production was offset by a decrease in the realized gas
price which decreased from $3.71 per Mcf for the quarter ended December 31, 2014 to $1.69 per Mcf for the quarter ended March 31,
2016 due to a general decrease in the price of natural gas.
Gas revenues decreased slightly from $0.7
million for the nine months ended March 31, 2015 to $0.6 million for the nine months ended March 31, 2016. Production increased
significantly from 159,466 Mcf for the nine months ended March 31, 2015 to 271,469 Mcf for the nine months ended March 31, 2016.
The increase in production was due to the operators of our North Stockyard field being able to capture and sell a greater percentage
of gas production following the installation of certain infrastructure improvements. The increase in production was offset by a
decrease in the realized gas price which decreased from $4.19 per Mcf for the nine months ended March 31, 2015 to $2.15 per Mcf
for the nine ended March 31, 2016 due to a general decrease in the price of natural gas.
Exploration expense
Exploration expenditures decreased slightly
from $0.1 million for the quarter ended March 31, 2015, to $21,399 for the quarter ended March 31, 2016. Exploration costs in both
periods relate to general exploration work and delay rentals payable to keep exploration leases alive. With the continued deterioration
in the oil price, exploration expenditure has been significantly reduced. Leases have been let go as they expire or delay rentals
not made causing the leases to expire.
Exploration expenditures decreased from
$11.5 million for the nine months ended March 31, 2015, to $4.2 million for the nine months ended March 31, 2016. $0.1 million
of the expenditure relates to the Badger well, drilled in our South Prairie prospect in North Dakota. This well was drilled in
October 2015 and failed to produce hydrocarbons, therefore the costs associated with the well have been expensed in the quarter
ended December 31, 2015. The remaining expenditure relates to costs written off associated with our Hawk Springs project in Goshen
County, Wyoming.
Expenditure in the prior period relates
previously capitalized exploration expenditure written off, primarily in relation to the Roosevelt project in Montana and the South
Prairie project in North Dakota.
Impairment expense
During the three months ended March 31,
2016 we recognized $0.05 million in impairment expense compared to $0.5 million during the quarter ended March 31, 2015. The impairment
recognized in the current quarter primarily relates to our Gladys well in the Rainbow field and is driven by the sustained decrease
in the oil price seen in the past year. The impairment during the quarter ended March 31, 2015 relates additional asset retirement
obligation recognized following the decreasing oil price.
During the nine months ended March 31,
2016 we recognized $10.0 million in impairment expense compared to $3.6 million in the nine months ended March 31, 2015. The impairment
in the current period primarily relates to the impact of the falling oil price on the realized oil price for our production primarily
from our North Stockyard field. The impairment in the prior period relates to our Rainbow field in North Dakota.
Abandonment expense
Abandonment expense decreased from $0.01
million for the three months ended March 31, 2015 to $nil for the three months ended March 31, 2016.
Abandonment expense decreased from $0.2
million for the nine months ended March 31, 2015 to $nil for the nine months ended March 31, 2016.
Lease operating expense
Lease operating expenses (LOE) decreased
from $1.3 million for the quarter ended March 31, 2015, to $0.7 million for the quarter ended March 31, 2016. Costs per BOE have
decreased from $12.97 for the quarter ended March 31, 2015 to $8.58 for the quarter ended March 31, 2016. Followed the continued
deterioration in the oil price, a renewed focus on cost control has been implemented by the operators of our most significant wells,
which are located in the North Stockyard Project in North Dakota.
Lease operating expenses decreased from
$4.3 million for the nine months ended March 31, 2015, to $3.5 million for the nine months ended March 31, 2016. The slight increase
in production has been offset by a decrease in LOE per barrel. Costs per BOE have decreased significantly from $19.38 for the nine
months ended March 31, 2015 to $13.76 for the nine months ended March 31, 2016.
Depletion, depreciation and amortization
expense
Depletion, depreciation and amortization
expense decreased from $1.7 million for the quarter ended March 31, 2015 to $0.8 million for the quarter ended March 31, 2016.
The decrease in depletion is a result of the decrease in the production and a decrease in the depletion base, following the significant
impairment expense recorded during the prior quarter. The per BOE cost decreased from $21.94 for the three months ended March 31,
2015 to $13.78 for the three months ended March 31, 2016.
Depletion, depreciation and amortization
expense remained consistent at $3.7 million for the nine months ended March 31, 2015 and 2016. An increase in production was offset
by a decrease in the cost per BOE from $22.11 for the nine months ended March 31, 2015 to $18.42 for the nine months ended March
31, 2016.
General and administrative expense
General and administrative expense decreased
from $1.2 million for the quarter ended March 31, 2015 to $0.9 million for the quarter ended March 31, 2016. We have been actively
trying to reduce our general and administrative costs in recent periods. Salaries were reduced by 15% for all employees effective
September 1, 2015. We also reduced our staffing levels in light of the continued weakness in the global oil market. The decrease
in general and administrative costs was offset by a decrease in production so that the per BOE costs increased slightly from $15.23
for the quarter ended March 31, 2015 to $15.74 for the quarter ended March 31, 2016.
General and administrative expense also
decreased from $3.6 million for the nine months ended March 31, 2015 to $2.9 million for the nine months ended March 31, 2016.
As a result of lower expense and increased production, general and administrative costs on a per BOE basis decreased from $21.46
for the nine months ended March 31, 2015 to $14.42 per BOE for the nine months ended March 31, 2016.
Cash Flows
The table below shows cash flows for the
following periods:
|
|
Nine months ended
|
|
|
|
31-Mar-16
|
|
|
31-Mar-15
|
|
Cash provided by operating activities
|
|
$
|
623,853
|
|
|
$
|
1,022,324
|
|
Cash used in investing activities
|
|
|
(2,389,717
|
)
|
|
|
(17,812,128
|
)
|
Cash provided by financing activities
|
|
|
301,975
|
|
|
|
12,872,190
|
|
Cash provided by operations decreased from
a net inflow of $1.0 million for the nine months ended March 31, 2015, to a net inflow of $0.6 million for the nine months ended
March 31, 2016. Cash receipts from customers decreased from $9.4 million for nine months ended March 31, 2015 to $8.5 million for
the nine months ended March 31, 2016, due to a decrease in the realized oil price despite an increase in production. Payments to
suppliers and employees also decreased from $8.8 million for the nine months ended March 31, 2015 to $7.4 million for the nine
months ended March 31, 2016 following continued cost saving initiatives with respect to lease operating expenses and administrative
costs.
Cash used in investing activities decreased
from $17.8 million for the nine months ended March 31, 2015 to $2.4 million of cash used for the nine months ended March 31, 2016.
The cash outflow for the prior period related to ongoing drilling activities in our North Stockyard project in North Dakota. The
cash outflow in the current period relates to continued work in our North Stockyard field, though no new wells were drilled in
this period. It also includes the $0.5 million non-refundable deposit paid to the seller
in relation to our Foreman Butte
Acquisition. The remaining cash purchase price for this acquisition was paid on April 1, 2016, and the promissory note issued to
the seller is due April 1, 2017.
Cash provided by financing activities decreased
from a cash inflow of $9.3 million for the nine months ended March 31, 2015 to $0.3 million for the nine months ended March 31,
2016. Cash inflow for the current period is $0.3 million in proceeds from borrowings from our credit facility. Cash inflow in the
prior period is a result of the drawdown of borrowings from our credit facility with our primary lender.
All options outstanding as at March 31,
2016 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 and we anticipate this will be our primary use of capital during fiscal
2016.
Following the closing of our Foreman Butte
Acquisition, our current budget for exploration, exploitation and development capital expenditures in fiscal 2016 is $3.5 million,
of which we incurred approximately $2.3 million during the first nine months of the fiscal year. These expenditures were funded
through our current cash on hand and cash generated from oil sales. We have additional workovers planned in our Foreman Butte Project
following its acquisition.
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 is due April 1, 2017 and has a 10% interest rate. We are required under the amended credit
agreement to repay Mutual of Omaha $10 million by June 30, 2016. As a result of the amendment of the credit facility, the interest
rate has been increased to 6% plus the 90 day LIBOR or approximately 6.5% from 1 April 2016 onwards. The amendment to our credit
facility also requires us to comply with additional restrictions, which are described below.
The borrowing base under our credit facility
may be increased (up to the credit facility maximum of $50.0 million) 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 period, once a year. The facility matures January
28, 2017.
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 (described below); (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; (6) paying down
at least $10 million of the credit facility by June 30, 2016; 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.
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 5.75 for the quarter ended March 30, 2016 through to September 30, 2016 reducing to 4.00 by September 30, 2017
|
|
·
|
Senior leverage ratio of no greater than
4.25 to 1 for the quarter ended June 30, 2016 reducing to 3.75 for the quarter ending December 31, 2016 and thereafter
|
|
·
|
Interest coverage ratio minimum of between
2.5 and 1.0
|
For
the quarter ended March 31, 2015 we were in breach of our Debt to EBITDAX covenant. Our primary lender has given us a waiver with
respect to this breach for this quarter only. We were in compliance with all other covenants.
We were in compliance with all of our covenants
for the quarter ended June 30, 2015.
As at September 30, 2015 we were in breach
of our Debt to EBITDAX and interest coverage ratio covenants. We received a waiver from our primary lender with respect to these
covenants for this quarter only.
As at December 31, 2015 we were in breach
of our Debt to EBITDAX and interest coverage ratio covenants. We received a waiver from our primary lender with respect to these
covenants for this quarter only.
As at March 31, 2016 we were in breach
of our Debt to EBITDAX and interest coverage ratio covenants. We have requested a waiver from our primary lender with respect to
these covenants for this quarter only.
The credit facility in the current period has been presented
as a current liability. In previous periods (prior to the quarter ended September 30, 2015) the facility was presented as a non-current
liability. Due to the continuing weakness in the global oil price, there is doubt as to whether or not we will be able to meet
our future debt covenants. We are working with the bank to renegotiate our facility and extend its term. We will continue to ask
for waivers on a quarterly basis as necessary; however there can be no guarantee they will be granted. If we do not receive a waiver
from the lender, and if we fail to cure any such noncompliance during the applicable cure period, the due date of our debt could
be accelerated by the lender. In addition, failure to comply with any of the covenants under our credit facility could adversely
affect our ability to fund ongoing operations.
The funds drawn from our credit facility
were used to fund drilling in our North Stockyard project in North Dakota and more recently, to partially fund the Foreman Butte
acquisition.
Uncertainties relating to our capital resources
and requirements include the effects of results from 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, 2016, and the allocation of those expenditures, are dependent on a variety of
factors, including the availability of capital resources to fund the 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 sources of liquidity during the
nine months ended March, 31, 2016 was cash on hand and cash flow from operations. We also drew down the remaining $301,000 from
our primary lender in December 2015. This drawdown in part funded our non-refundable $500,000 deposit for our Foreman Butte Acquisition.
During the current quarter we closed on our Foreman Butte Acquisition with funding provided by our primary lender under our credit
facility and through seller financing. Although the acquisition closed on March 31, 2016 the cash payment was not made until April
1, 2016.
During the prior three 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 March 31, 2016
decreased from June 30, 2015 largely due to payments for drilling and fracturing activities in our North Stockyard project in North
Dakota, a deposit of $500,000 paid for our Foreman Butte Acquisition, cash collateral of $350,000 provided for state and federal
bonds in order for us to continue operating oil and gas properties and lower oil and gas revenues due to lower commodity prices.
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 Haliburton 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 unevaluated properties. See the risk factors in our Annual Report on Form 10-K for the fiscal year ended June 30,
2015 including “Drilling results in emerging plays, such as our Hawk Springs and Roosevelt Projects, are subject to heightened
risks.” and “Inadequate liquidity could materially and adversely affect our business operations.” See also Part
II, Item 1A of this report below.
Looking Ahead
We plan to focus on the following objectives
in the coming 12 months:
|
·
|
Continued focus on cost savings and efficiency
across all aspects of the Company including lease operating costs and general and administrative costs
|
|
·
|
Continued focus on strengthening the balance
sheet through an appropriate injection of capital
|
|
·
|
The successful integration of the properties
and assets acquired in the Foreman Butte Acquisition, and the review and workover of such assets;
|
|
·
|
The continued appraisal of our Cane Creek
project in the Paradox basin in Utah; and
|
|
·
|
The continued search and appraisal of
new development and exploration projects that add value to our current portfolio at lower oil prices
|
|
·
|
Capital raising activities to satisfy
our obligations to repay $10 million under our amended credit facility by June 30, 2016 and to raise an additional $5 million of
equity by September 30, 2016
|
|
·
|
Repayment of the $4 million promissory
note issued to the seller in the Foreman Butte Acquisition
|
|
·
|
Maintaining compliance with NYSE MKT listing
standards
|
Our ability to meet these objectives will
depend on our ability to raise additional capital to fund the planned development programs.