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, 2012, included in our Annual Report on Form 10-K and the Consolidated Financial Statements included elsewhere herein.

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 and Roosevelt County, Montana. We are in the early stages of our first Niobrara shale project - Hawk Springs - and also of our Montana Bakken shale project - the Roosevelt project.

Our net oil production was 17,744 barrels of oil for the quarter ended December 31, 2012 compared to 18,580 barrels of oil for the quarter ended December 31, 2011. Our net gas production was 51,587 Mcf for the quarter ended December 31, 2012 compared to 58,487 Mcf for the quarter ended December 31, 2011.

Our net oil production was 36,626 barrels of oil for the six months ended December 31, 2012 compared to 43,516 barrels of oil for the six months ended December 31, 2011. Our net gas production was 92,678 Mcf for the six months ended December 31, 2012 compared to 117,669 Mcf for the six months ended December 31, 2011.

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. Our execution of that strategy today, however, is dependent on our ability to raise additional capital to fund any new exploration and development drilling.

Notable Activities and Status of Properties during the Quarter Ended December 31, 2012 and Current Activities

Undeveloped Properties: Exploration Activities

Hawk Springs Project, Goshen County, Wyoming

Cretaceous Niobrara Formation & Permo-Penn Project, Northern D-J Basin

Samson 37.5% to 100% Working Interest

Production to date from the Niobrara Formation in the Defender US33 #2-29H well in Goshen County, WY has been sporadic due to the chemistry of the Niobrara oil, which had been producing an unusually high concentration of paraffin and asphaltene (11.74%). After a successful workover during the current quarter, the well had produced 691 barrels of oil over a 38 day period, however the well was offline for the majority of the quarter due to a pump failure. Further analysis of the hydraulic fracture treatment shows that the effective frac length was extremely limited and because of this the well is on a timer and pumps for only a few hours a day.

The limited frac length and the lack of un-stimulated permeability offers an opportunity to design a suitable additional stimulation treatment. A chemical injection program, run during the quarter has alleviated the paraffin and asphaltene problems.

The Spirit of America US34 #2-29 (the SOA #2) intersected two excellent quality Permian age reservoirs, the 9,300 ft. sand, which appears to be oil saturated and the 9,500 ft. sand which is water saturated. Integrating the well data to the 3-D seismic shows that an amplitude anomaly (lithology/porosity indicator) is associated with the 9500' sand indicating a thick and porous reservoir exists everywhere the amplitude is mapped. After further examination of the 3D seismic and additional work performed during the quarter, it has been established that the likely reason for the lack of oil saturation in the 9500' sand is that a leak point can be established by a fortuitous juxtaposition of another porous reservoir across a fault that intersects the amplitude anomaly. As this arrangement in the SOA prospect is unique in the project area, Samson believes that the prospectivity of the remaining two dozen prospects in the project has been re-established since these prospects are not affected by any recognized faulting.

To date approximately $7.2 million has been capitalized in relation to the SOA #2 and carried in Capitalized Exploration Expenditure on the Balance Sheet, including $0.2 million during the quarter ended December 31, 2012. One more stage of the well remains to be fraced prior to the final determination of the outcome of this well. Depending on the results of the final frac of this well, it is possible that some or all of the costs currently deferred in relation to this well will have to be written off to the Income Statement. The final frac of the SOA #2 has not yet been scheduled, however, and we therefore have not established the time frame in which the SOA #2 will be completed.

As a result of this analysis, the strategy is to pursue a farmout to enable two prospects to be drilled: Bluff Federal, which relies on a four way dip closure and American Eagle, which is an amplitude anomaly unaffected by the faulting seen in the SOA#2 well.

Samson has two contiguous areas in the Hawk Springs Project. One of the areas is a joint venture with a private company and the other is subject to a joint venture with a Halliburton company.

Roosevelt Project, Roosevelt County, Montana

Mississippian Bakken Formation,Williston Basin

Samson 100% working interest in Australia II & Gretel II wells, 66.7% in any subsequent drilling, depending on the drilling location

We have an interest in approximately 45,000 gross acres (30,000 net acres) in the Roosevelt Project with Fort Peck Energy Co. ("FPEC") having the remaining 15,000 net acres.

Our first Bakken appraisal (exploratory) well in the Roosevelt project area on the Ft. Peck Indian Reservation, the Australia II 12 KA 6 well, was drilled in December 2011. 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. Cumulative oil production for the well is 5,497 stock tank barrels ("STB").

During the quarter parted sucker rods were successfully repaired and the well was returned to production on October 25th. The well produced 810 barrels of oil over a thirteen day period before the pump stopped working because of a scale accumulation due to the high mineral content of the formation water. The pump was replaced and the well produced 402 STB however it has been off line since December 8th due to a further mechanical failure and is currently awaiting repairs. The initial drilling costs of $13.1 million were expensed to the Statement of Operations during the year ended June 30, 2012. In addition $0.1 million of costs have been expensed to the Statement of Operations through December 31, 2012 as exploration expenditure.

Our second Bakken well, Gretel II, was drilled in January 2012 and fracture stimulated in March 2012. This well was drilled on the north side of the Brockton Fault zone, which may define the western edge of the continuous Bakken oil accumulation. The Gretel II has produced oil, but with a high water cut. The toe end of the lateral portion of the Gretel well was plugged back to a depth of 14,002 feet to minimize water production from the faults that were encountered beyond this depth.

The plug back was mechanically successful and the water production was reduced; however the oil rate has not increased and production for the well remains at around 1 to 3 BOPD. The well will be pumped for a further two months after which it may be converted to a water disposal well unless an economic oil rate is established. The initial drilling costs of $11.6 million were expensed to the Statement of Operations during the year ended June 30, 2012. In addition $0.22 million of costs have been expensed to the Statement of Operations through December 31, 2012 as exploration expenditure.

We also currently have a 1280-acre approved spacing order for a third exploratory well in this project: named Prairie Falcon. The drilling location of this well is south of the Brockton Fault zone and is north of the Abercrombie 1-10H well, which had initial production of 630 BOPD. We are monitoring the production rate from the Abercrombie well and waiting on the results of two offset wells, the Custer 1-7H well (SSN 2.2% WI) which is about to spud and another well yet to be named and drilled. These latter two wells will help define a productive extension to the Elm Coulee Bakken fairway. Any further exploration or development of our Roosevelt Project in the fiscal year ending June 30, 2013, will depend upon our success in obtaining additional capital and our results of operations.

Drilling Program

Hawk Springs Project, Goshen County, Wyoming

Wildcat (Exploratory) Permo-Penn Hartville Formation, Northern D-J Basin

Bluff Federal #1-12

American Eagle US 21#1

Samson is presently anticipating having a 47% carried interest after a farmout of the project

As noted above we are in the process of marketing a farmout of our Hawk Springs project in an effort to have two prospects tested; however there is no guarantee we will be able to farmout the Hawk Springs project.

The Bluff Federal prospect will test a four-way dip structural closure just a few miles away from the Spirit of America US34 #2-29 well (SOA #2) and more than 2000' shallower in depth. The excellent reservoir properties and oil shows seen in the SOA #2 well has allowed us to high-grade the Bluff Federal prospect.

We would also like to test the American Eagle US21 prospect. This prospect is an amplitude anomaly associated with the excellent reservoir quality rock observed in the SOA #2 well.

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Bakken & Three Forks infill wells

Samson ~60% Working Interest

We and the Operator group have negotiated an acreage swap for the Middle Bakken/First Bench of the Three Forks (MB/TF), whereby we will acquire these parties' undeveloped acres in the Northern Tier and will divest undeveloped acres in the Southern Tier. Following the swap, we will own 64% and 57%, respectively, in the two overlapping 1,280 acre spacing units located in the Northern Tier. We will be the Operator for the entire Northern Tier. Our net production from current producing wells is not affected.

The formal agreement documenting the swap has been completed between us and the Operator. We are waiting on the remaining working interest owners to complete the paper-work in order to finalize the agreement. We have identified 14 infill development wells that can be drilled between the existing Bakken wells and in the Three Forks Formation with 160 acre spacing. The North Dakota Industrial Commission has approved the spacing order for these wells and the first four drilling permits have been received.

An initial 8 infill development wells are planned to be drilled from two pads utilizing the skiddable platform available on Frontier Rig 24. The development wells are designed as 6,300 foot horizontals in either the Middle Bakken or the First Bench of the Three Forks. The wells will be "batched" drilled, which is expected to result in considerable cost savings. However our ability to complete this development plan is contingent on the completion of a planned debt financing or another capital raising program.

Developed Properties: Production Activities

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson various Working Interests

We have seven producing wells in the North Stockyard Field. These wells are located in Williams County, North Dakota, in Township 154N Range 99W.

The Harstad #1-15H well (34.5% working interest) was down for 6 days during the quarter due to weather/storm related issues and as a result averaged 34.1 BOPD for the quarter from the Mississippian Bluell Formation. The well has cumulative gross production of 102 MSTB and 82 MMscf.

The Leonard #1-23H well (10% working interest, 37.5% after non-consent penalty) was down for 12 days during the quarter for a workover. The well averaged 40.7 BOPD and 51.6 Mscf/D during the quarter. To date, the Leonard #1-23H well has produced approximately 102 MSTB and 105 MMscf.

The Gene #1-22H well (30.6% working interest) was down for approximately 38 days during the quarter for a workover. The well produced at an average daily rate of 56 BOPD and 40 Mscf/D during the quarter. The cumulative production to date is approximately 134 MSTB and 147 MMscf.

The Gary #1-24H (37% working interest) well was down for 3 days during the quarter due to an electrical failure. The well averaged 96 BOPD and 178 Mscf/D during the quarter. The cumulative production to date is approximately 136 MSTB and 226 MMscf.

The Rodney #1-14H (27% working interest) was down for one day during the quarter. The well produced at an average daily rate of 84 BOPD and 171 Mscf/D during the quarter. The cumulative production to date is approximately 102 MSTB and 145 MMscf.

The Earl #1-13H (32% working interest) well was down for 19 days during the quarter due to surface equipment failure and as a result produced at an average daily rate of 166 BOPD and 293 Mscf/D. Cumulative production to date is approximately 161 MSTB and 230 MMscf.

The Everett #1-15H (26% working interest) well was the sixth Bakken well drilled in the North Stockyard Oilfield. The Everett well produced at an average daily rate of 133 BOPD and 217 Mscf/D during the quarter. Cumulative production to date is approximately 76 MSTB and 109 MMscf.

Sabretooth Gas Field, Brazoria County Texas

Oligocene Vicksburg Formation, Gulf Coast Basin

Samson 9.375% Working Interest

Production for the Davis Bintliff #1 well was increased on October 3rd due to a strengthening of the gas price. The average rate increased to 3.9 MMscf/D and 41 BOPD for the quarter. Cumulative production to date is approximately 5.3 Bscf and 62 MSTB.

Abercrombie 1-10H well, Richland County, Montana

Mississippian Bakken Formation,Williston Basin

Samson 2.82% working interest

The Abercrombie #1-10H well has produced a cumulative 29,000 barrels of oil while producing at an average rate of approximately 92 BOPD and 300 Mscf/D during the quarter.

Riva Ridge 6-7-33-56H well, Sheridan County, Montana

Mississippian Bakken Formation,Williston Basin

Samson 0.76% working interest

The Riva Ridge 6-7-33-56H (SSN 0.76% W.I.) is producing at an average rate of approximately 61 BOPD and 42 Mscf/D during the quarter.

The Riva Ridge II (SSN 0.76% W.I.) has been drilled and is currently being completed in the Three Forks Formation.

Looking Ahead

We plan to focus on two main objectives in the coming 12 months:

· The continued appraisal and development, likely through a farmout of our Hawk Springs and Roosevelt projects, including multiple conventional targets in the Permian and Pennsylvanian formations on our acreage in Goshen County, Wyoming and Roosevelt County, Montana respectively.

· The continued development of our North Stockyard project in Williams County, North Dakota.

Our ability to meet these objectives will be materially affected by our ability to raise additional capital to fund the planned development programs.

Results of Operations

In the quarter ended December 31, 2012, we reported a net gain of $0.04 million after an income tax benefit of $1.4 million.

For the six months ended December 31, 2012 we reported a net loss of ($0.89) million after an income tax benefit of $2.0 million, which can be attributed to lease operating expenses, depletion and depreciation and other costs exceeding our revenue.

Operating data

The following table sets forth selected operating data for the three months ended:

                                                                 Three months ended
                                                      31-Dec-12       31-Dec-11       30-Sep-12
Production Volume
Oil (Bbls)                                                17,744          18,580          18,882
Natural gas (Mcf)                                         51,587          58,487          41,091
BOE                                                       26,342          28,327          25,731

Oil Price per Bbl Produced (in dollars):
Realized price                                       $     82.13     $     89.66     $     76.61

Natural Gas Price per Mcf Produced (in dollars):
Realized price                                       $      4.24     $      4.49     $      3.55

Expense per BOE (in dollars):
Lease operating expenses                             $     32.10     $      8.07     $     25.56
Production and property taxes                        $      7.44     $      8.01     $      6.00
Depletion, depreciation and amortization             $     18.02     $     21.22     $     22.05
General and administrative expense                   $     50.73     $     73.29     $     57.63

The following table sets forth selected operating data for the six months ended:

                                                    31-Dec-12      31-Dec-11
Production Volume
Oil (Bbls)                                              36,626         43,516
Natural gas (Mcf)                                       92,678        117,669
BOE                                                     52,072         63,128

Oil Price per Bbl Produced (in dollars):
Realized price                                     $     79.28     $    88.30

Natural Gas Price per Mcf Produced (in dollars):
Realized price                                     $      3.94     $     4.87

Expense per BOE (in dollars):
Lease operating expenses                           $     28.87     $     8.85
Production and property taxes                      $      6.73     $     8.28
Depletion, depreciation and amortization           $     20.01     $    20.89
General and administrative expense                 $     54.14     $    62.76

The following table sets forth results of operations for the following periods:

                                                 Three months ended
                                             31-Dec-12        31-Dec-11        2Q12 to 2Q11 change       30-Sep-12        2Q12 to 1Q12 Change
Oil sales                                   $  1,457,238     $  1,666,006     $            (208,768 )   $  1,446,537     $              10,701
Gas sales                                        218,885          263,087                   (44,202 )        145,764                    73,121
Other liquids                                          -            2,255                    (2,255 )          4,457                    (4,457 )
Interest income                                   55,139           85,431                   (30,292 )         71,640                   (16,501 )
Other                                            111,469            1,979                   109,490               12                   111,457
                                                                                                  -                                          -
Lease operating expense                       (1,041,761 )       (455,495 )                (586,266 )       (811,989 )                (229,772 )
Depletion, depreciation and amortization        (498,851 )       (619,713 )                 120,862         (590,767 )                  91,916
Exploration and evaluation expenditure           (39,006 )     (4,619,278 )               4,580,272         (361,944 )                 322,938
Accretion of asset retirement obligations        (13,675 )         (5,559 )                  (8,116 )        (13,434 )                    (241 )
General and administrative                    (1,336,332 )     (2,076,296 )                 739,964       (1,482,812 )                 146,480
Income tax (provision)/ benefit                1,366,938          693,385                   673,553          668,998                   697,940
Net (loss)                                  $    280,044     $ (5,064,198 )   $           5,344,242     $   (923,538 )   $           1,203,582

The following table sets forth results of operations for the following periods:

                                                           Six months ended
                                                      31-Dec-12        31-Dec-11        2Q12 to 2Q11 change
Oil sales                                            $  2,903,775     $  3,842,442     $            (938,667 )
Gas sales                                                 364,907          573,263                  (208,356 )
Other liquids                                               4,199            7,921                    (3,722 )
Interest income                                           126,779          199,237                   (72,458 )
Other                                                     111,481           21,136                    90,345
                                                                                                           -
Lease operating expense                                (1,853,750 )     (1,082,292 )                (771,458 )
Depletion, depreciation and amortization               (1,089,618 )     (1,353,022 )                 263,404
Exploration and evaluation expenditure                   (400,950 )     (4,740,828 )               4,339,878
Accretion of asset retirement obligations                 (27,109 )        (10,993 )                 (16,116 )
General and administrative                             (2,819,114 )     (3,962,282 )               1,143,168
Income tax (provision)/ benefit                         2,035,936          881,563                 1,154,373
Net income (loss)                                    $   (643,464 )   $ (5,623,855 )   $           4,980,391

Three Months Comparison of Quarter Ended September 30, 2012 to Quarter Ended September 30, 2012 and six months comparison of the period ended December 31, 2012 to the period ended December 31, 2011.

Oil and gas revenues

Oil revenues decreased slightly from $1.66 million for the three months ended December 31, 2011 to $1.46 million for the three months ended December 31, 2012 as a result of a decrease in our oil production, coupled with a decrease in the realized price. Oil production decreased slightly from 18,580 barrels for the quarter ended December 31, 2011 to 17,744 barrels for the quarter ended December 31, 2012. Our realized oil price decreased from $89.66 for the quarter ended December 31, 2011 to $82.13 for the quarter ended December 31, 2012.

Oil revenues also decreased from $3.84 million for the six months ended December 31, 2011 to $2.90 million for the six months ended December 31, 2012 as a result of a decrease in our oil production, coupled with a decrease in the realized price. Oil production decreased from 43,516 barrels for the six months ended December 31, 2011 to 36,626 barrels for the six months ended December 31, 2012. Our realized oil price decreased from $88.30 for the six months ended December 31, 2011 to $79.28 for the six months ended December 31, 2012.

Gas revenues also decreased slightly from $0.26 million for the quarter ended December 2011 to $0.22 million for the quarter ended December 31, 2012 due a combination of a decrease in production volume and realized gas price. Production decreased by 12%, while the realized gas price decreased from $4.49 for the quarter ended December 31, 2011 to $4.25 for the quarter ended December 31, 2012.

Gas revenues also decreased from $0.57 million for the six months ended December 2011 to $0.36 million for the six months ended December 31, 2012 due a combination of a decrease in production volume and realized gas price. Production decreased by 21%, while the realized gas price decreased from $4.87 for the six months ended December 31, 2011 to $3.94 for the six months ended December 31, 2012.

Exploration expense

Exploration expenditure decreased significantly from $4.6 million for the quarter ended December 31, 2011 to $0.04 million for the quarter ended December 31, 2012 primarily as a result of writing off $4.5 million in expenditure related to the drilling of the Spirit of America I well during the quarter ended December 31, 2011. This well experienced numerous mechanical and operational difficulties and ultimately failed to reach its target.

Exploration expenditure decreased significantly from $4.7 million for the six months ended December 31, 2011 to $0.4 million for the six months ended December 31, 2012 primarily as a result of writing off $4.5 million in expenditure related to the drilling of the Spirit of America I well during the six months ended December 31, 2011. This well experienced numerous mechanical and operational difficulties and ultimately failed to reach its target. During the six months ended December 31, 2012 the exploration expenditure relates to expenses incurred on our Australia II and Gretel II leases as well as other general exploration expenditure.

We currently have approximately $7.2 million capitalized in exploration expense on the balance sheet in relation to the Spirit of America II well. While this well is still being completed, depending on the outcome of it, it is possible that we will need to recognize impairment expense in relation to this expenditure. The magnitude of impairment expense, if any, is not yet known and will depend on the results after the completion of the well.

Lease operating expense

Lease operating expenses increased from $0.46 million for the quarter ended December 31, 2011 to $1.04 million for the quarter ended December 31, 2012. This is largely due to increased lease operating expense in our North Stockyard field as a result of the high salt water content as well as lease operating costs being incurred in the Roosevelt Field in relation to our Australia II and Gretel II wells. The Gretel II well in particular produces a significant amount of water which, the disposal of which leads to increased lease operating costs.

Lease operating expenses increased from $1.08 million for the six months ended December 31, 2011 to $1.85 million for the six months ended December 31, 2012. This is largely due to increased lease operating expense in our North Stockyard field as a result of the high salt water content as well as lease operating costs being incurred in the Roosevelt Field in relation to our Australia II and Gretel II wells. The Gretel II well in particular produces a significant amount of water which, the disposal of which leads to increased lease operating costs.

Depletion, depreciation and amortization expense

Depletion, depreciation and amortization expense decreased from $0.62 million for the quarter ended December 30, 2011 to $0.5 million for the quarter ended December 31, 2012. This decrease is due to a decrease in production. Depreciation, depletion and amortization expense per BOE decreased from $21.22 for the quarter ended December 31, 2011 compared to $18.02 for the quarter ended December 31, 2012.

Depletion, depreciation and amortization expense decreased from $1.35 million for the six months ended December 31, 2011 to $1.09 million for the six months ended December 31, 2012. This decrease is due to a decrease in production. Depreciation, depletion and amortization expense per BOE remained consistent at $20.89 for the six months ended December 31, 2011 compared to $20.01 for the six months ended December 31, 2012.

Impairment expense

Impairment expense increased from $nil for the quarter and six months ended December 30, 2011 to $0.24 million for the same periods ended December 31, 2012. The majority of impairment recognised is in relation to two wells drilled in our . . .