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SSN > SEC Filings for SSN > Form 10-Q on 9-Nov-2012All Recent SEC Filings

Show all filings for SAMSON OIL & GAS LTD | Request a Trial to NEW EDGAR Online Pro

Form 10-Q for SAMSON OIL & GAS LTD


9-Nov-2012

Quarterly Report


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, 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 18,882 barrels of oil for the quarter ended September 30, 2012 compared to 24,601 barrels of oil for the quarter ended September 30, 2011. Our net gas production was 41,091 Mcf for the quarter ended September 30, 2012 compared to 59,246 Mcf for the quarter ended September 30, 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 and in a manner consistent with preserving adequate liquidity and financial flexibility.

Notable Activities during the Quarter Ended September 30, 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 has been producing an unusually high concentration of paraffin and asphaltene (11.74%). We have, following consultation with industry experts, designed a chemical treatment program to maintain these compounds in solution. This treatment program will require a change to the bottom hole configuration of the well, so a workover rig is scheduled to arrive on location in November to run this completion. Prior to the paraffin and asphaltene plugging, the well had established a consistent production rate of approximately 75 BOPD while maintaining a high fluid level in the wellbore. The go-forward plan is to increase the pump rate to lower the fluid level and thus increase the production rate.

Two stages of a three stage completion have taken place on the Spirit of America US34 #2-29 Permo-Penn exploration well. Most recently, Frac Stage #3 took place, which included 7 feet of log pay from 9247feet to-9254 feet, 7 feet of log pay from 9225 feet to 9232 feet, and 8 feet of log pay from 9167 feet to 9175 feet. The stimulation included 37,000 pounds of proppant. The initial shut-in pressure (ISIP) after fracking measured 4,238 psi. After 45 minutes the pressure bled down to 4163 psi and 70 bbls were flowed back before the well was shut-in with 3761 psi of pressure. During flowback operations 177 bbls of fluid was recovered before the wellbore plugged with salt. A coil tubing unit was used to drill out the salt plugs, however hot water was subsequently required to clear the plugs, and the plugging is consistent as the salt is precipitating out of the formation water as a result of a pressure drop and temperature cooling. This can be treated with an appropriate salt inhibitor to prevent the salt from precipitating out of the water. To date approximately 253 bbls of load water have been recovered out of approximately 1600 bbls that were pumped into the well. A workover rig will be required to remove the tubing and reset the retrievable bridge plug and packer in order to attempt to make a completion in the best zone, the 9300 foot sand (Frac Stage #2). This final frac stage is scheduled to occur in the coming quarter following this workover operation. To date approximately $7.0 million has been capitalized to this well and is carried in Capitalized Exploration Expenditure on the Balance Sheet, including $2.0 million during the current quarter.

Samson has mapped numerous similar prospects within its 3-D seismic area that will allow for follow-up to this well. The next such prospect is the Bluff Federal #1-12 well, which is 2,000 feet shallower than the Spirit of America well and is located within a 4-way structural closure. Samson currently expects to have a 50% working interest in the Bluff Federal well, although this has not been finalized.

Samson has 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 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. Samson's 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. Approximately 3,425 barrels of oil have been produced through September, 2012. The well is currently being worked over for mechanical repairs but should be back on production during November 2012.

Samson's second Bakken appraisal (exploratory) well, the Gretel II 12 KA 3, was drilled in January 2012 and fracture stimulated in March 2012. It appears that this well was drilled on the north side of the Brockton Fault zone, which is believed to be the western edge of the continuous Bakken oil. The Gretel II has produced oil, but with a high water cut. This well is currently shut-in and awaiting mechanical repairs. Although Australia II and Gretel II may be productive in the future, we do not believe that we will recover our costs associated with drilling them.

We currently have a third permitted exploratory well in this project - the Prairie Falcon. The drilling location of this well is south of the Brockton Fault zone and is north of the Abercrombie 1-10H well, an existing well which had an initial production of 630 BOPD. We are waiting on the results of two other nearby wells, which should help define the productive extension of the Elm Coulee Bakken fairway onto the Fort Peck Indian Reservation. If economic results are obtained from these offsetting wells, we plan to move ahead with the drilling of the Prairie Falcon well. We are currently looking for a joint venture participant for the drilling of the Prairie Falcon well and the continuing development of our leasehold on the Fort Peck Indian Reservation.

Drilling Program

Hawk Springs Project, Goshen County, Wyoming

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

Bluff Federal #1-12

Samson will most likely have a 50% Working Interest, based on current expectations and leasehold positions

A better understanding of the Permian section has been achieved from the well data obtained in the Spirit of America US34 #2-29 well that has allowed us to high-grade the Bluff Federal prospect, which is currently being prepared to be drilled next year. From that data, several of the upper Permian zones calculate to be hydrocarbon bearing whereas the deepest zone, the 9500' sand, calculates to contain formation water or is "wet". The SOA #2 prospect depended on the 9500' sand to be stratigraphically trapped (i.e. a sand pinch-out). The fact that this zone appears to be wet most likely means the sand does not pinch-out or trap at this particular prospect as the seismic data would indicate, but instead persists over a much larger area, requiring a structural closure to trap hydrocarbons in the reservoir. This 9500' sand has also been mapped as a four-way dip structural closure just a few miles away and more than 2,000' shallower at the Bluff Federal prospect.

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson various Working Interests

We anticipate undertaking a transaction by which we will swap our equity in the undrilled acreage in the southern three sections of this holding for the same amount of acreage in the northern three sections. Our equity in the current production will be unaffected by this transaction. The swap is aimed at allowing us to be or name the operator of the northern three sections and thereby develop the considerable potential in a timely manner. Based on current industry practice and evidenced by offset production, we believe that it is economically feasible to drill both the Bakken Formation and the underlying Three Forks Formation at a 160 acre density. Accordingly, we have identified ten infill development wells that can be drilled between the existing Bakken wells, four in the Bakken formation and six in the Three Forks Formation. The wells would be drilled from pads that would accommodate multiple well heads. The infill development drilling is tentatively planned to commence in the first quarter of 2013.

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.

1. The Harstad #1-15H well (34.5% working interest) was down for 33 days during the quarter due to pump rod failure and as a result averaged 19 BOPD for the quarter from the Mississippian Bluell Formation. After the workover, the well has been averaging 35 BOPD. The well has cumulative gross production of 99 MSTB and 82 MMcf.

2. The Leonard #1-23H well (10% working interest, 37.5% after non-consent penalty) was down for 44 days during the quarter for multiple workovers. As a result, the well averaged 25 BOPD and 33 Mcf/D during the quarter. After the workover, the well has been averaging 51 BOPD and 62 Mcfd. To date, the Leonard #1-23H well has produced approximately 99 MSTB and 102 MMcf.

3. The Gene #1-22H well (30.6% working interest) produced at an average daily rate of 110 BOPD and 90 Mcf/D during the quarter. The cumulative production to date is approximately 131 MSTB and 144 MMcf.

4. The Gary #1-24H (37% working interest) well was down for 13 days during the quarter due to pump rod failure. As a result, the well averaged 80 BOPD and 122 Mcf/D during the quarter. The cumulative production to date is approximately 129 MSTB and 210 MMcf.

5. The Rodney #1-14H (27% working interest) well produced at an average daily rate of 97 BOPD and 183 Mcf/D during the quarter. The cumulative production to date is approximately 96 MSTB and 132 MMcf.

6. Earl #1-13H (32% working interest) well was down for 33 days during the quarter due to tubing failure and as a result produced at an average daily rate of 140 BOPD and 222 Mcf/D during the quarter. Cumulative production to date is approximately 145 MSTB and 200 MMcf.

7. The Everett #1-15H (26% working interest) well was the sixth Bakken well drilled in the North Stockyard Field. The Everett well produced at an average daily rate of 170 BOPD and 244 Mcf/D during the quarter. Cumulative production to date is approximately 70 MSTB and 96 MMcf.

Sabretooth Gas Field, Brazoria County Texas

Oligocene Vicksburg Formation, Gulf Coast Basin

Samson 9.375% Working Interest

Production for the Davis Bintliff #1 well has held steady at an average rate of
2.6 MMcf/D and 28 BOPD for the quarter. The well has continued to be choked-back from a 10/64" choke (where it was making 4.3 Mmcf/D) to an 8/64" choke (where it is now making 2.6 Mmcf/D) due to depressed gas prices. Cumulative production to date is approximately 5 Bscf and 59 MBO.

Abercrombie 1-10H well, Richland County, Montana

Mississippian Bakken Formation,Williston Basin

Samson 0.75% working interest

The Abercrombie #1-10H (SSN 0.75% W.I.) well has produced a cumulative 29,000 barrels of oil while producing at an average rate of approximately 160 BOPD and 310 Mcf/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 well has been fracked and is now on production. It is producing at an average rate of approximately 138 BOPD and 15 Mcf/D during the quarter.

Looking Ahead

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

The continued appraisal and development, subject to the results of the appraisal operations, 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.

Results of Operations

In the first quarter of the year ending June 30, 2013, we reported a net loss of ($0.9) 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
                                                   30-Sep-12       30-Sep-11
Production Volume
Oil (Bbls)                                             18,882          24,601
Natural gas (Mcf)                                      41,091          59,246
BOE                                                    25,731          34,475

Oil Price per Bbl Produced (in dollars):
Realized price                                     $    76.61     $     85.20
Realized commodity derivative gain (loss)                   -               -
Net realized price                                 $    76.61     $     85.20

Natural Gas Price per Mcf Produced (in dollars):
Realized price                                     $     3.55     $      5.23
Realized commodity derivative gain (loss)                   -     $      0.62
Net realized price                                 $     3.55     $      5.85

Expense per BOE (in dollars):
Lease operating expenses                           $    25.56     $      9.58
Production and property taxes                      $     6.00     $      8.59
Depletion, depreciation and amortization           $    22.05     $     21.27
General and administrative expense                 $    57.63     $     55.10

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

                                                    Three months ended
                                                31-Mar-12        31-Mar-11        1Q11 to 1Q12 change
Oil sales                                      $  1,446,537     $  2,176,436     $            (729,899 )
Gas sales                                           145,764          310,176                  (164,412 )
Other liquids                                         4,457            5,666                    (1,209 )
Interest income                                      71,640          113,806                   (42,166 )
Other                                                    12           19,157                   (19,145 )
                                                                                                     -
Lease operating expense                            (811,989 )       (626,797 )                (185,192 )
Depletion, depreciation and amortization           (590,767 )       (733,309 )                 142,542
Exploration and evaluation expenditure             (361,944 )       (107,956 )                (253,988 )
Accretion of asset retirement obligations           (13,434 )         (5,434 )                  (8,000 )
General and administrative                       (1,482,812 )     (1,899,581 )                 416,769
Income tax (provision)/ benefit                     668,998          188,178                   480,820
Net (loss)                                     $   (923,538 )   $   (559,658 )   $            (363,880 )

Three Months Comparison of Quarter Ended September 30, 2012 to Quarter Ended September 30, 2012

Oil and gas revenues

Oil revenues decreased from $2.1 million for the three months ended September 30, 2011 to $1.4 million for the three months ended September 30, 2012 as a result of a decrease in our oil production, coupled with a decrease in the realized price. Oil production decreased slightly from 24,601 barrels for the quarter ended September 30, 2011 to 18,882 barrels for the quarter ended September 30, 2012. Our realized oil price decreased from $85.20 for the quarter ended September 30, 2011 to $76.61 for the quarter ended September 30, 2012.

Gas revenues also decreased from $0.3 million for the quarter ended September 2011 to $0.14 million for the quarter ended September 30,2012 due a combination of a decrease in production volume and realized gas price. Production decreased by 13%, while the realized gas price decreased from $5.85 for the quarter ended September 30, 2011 to $3.55 for the quarter ended September 2012.

Exploration expense

Exploration expenditure increased from $0.1 million for the quarter ended September 30, 2011 to $0.36 million for the quarter ended September 30, 2012 primarily as a result of writing off $0.26 million in additional expenditure on our Australia II and Gretel II wells in our Roosevelt Project in Montana.

We currently have approximately $7.0 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 future events.

Lease operating expense

Lease operating expenses increased from $0.6 million for the quarter ended September 30, 2011 to $0.8 million for the quarter ended September 30, 2012. This is largely due to increased lease operating expense in our North Stockyard field as a result of the high salt water content.

Depletion, depreciation and amortization expense

Depletion, depreciation and amortization expense decreased from $0.7 million for the quarter ended September 30, 2011 to $0.6 million for the quarter ended September 30, 2012. Depreciation, depletion and amortization expense per BOE remained consistent at $21.27 for the quarter ended September 30, 2011 compared to $22.05 for the quarter ended September 30, 2012.

General and administrative expense

General and administrative expense decreased slightly from $1.9 million for the quarter ended September 30, 2011 to $1.5 million for the quarter ended September 30, 2012. Included within general and administrative expense is $0.7 million of employee benefits (including share based payments) for the current quarter compared with $1.1 million for the prior quarter. This decrease is due to lower share based payments expense and lower employee bonus accruals. Other general and administrative costs including but not limited to legal fees, audit fees, investor relations and travel remained consistent at $0.75 million for the quarter ended September 30, 2011 and $0.8 million for the quarter ended September 30, 2012.

Income tax (expense)/benefit

Income tax benefit increased from a benefit of $0.2 million for the quarter ended September 30, 2011 to a benefit of $0.67 million for quarter ended September 30, 2012. The tax benefit recognized in the current year is a result of a portion of this year's operating losses being carried back to the income tax expense recognized in the year ended June 30, 2011.

Cash Flows



The table below shows cash flows for the three month period ended:



                                                       Three months ended
                                                   30-Sep-12        30-Sep-11
Cash provided by/(used in) operating activities   $   (161,325 )   $    123,781
Cash (used in)/provided by investing activities     (8,754,657 )     (4,335,408 )
Cash provided by/(used in) financing activities        444,272          290,581

Cash provided by operations increased from an inflow of $0.12 million for the three months ended September 30, 2011 to cash outflow ($0.16) million for the three months ended September 30, 2012. Payments to suppliers and employees decreased significantly from $2.7 million for the three months ended September 30, 2011 to $1.9 million for three months ended September 30, 2012, as a result of decreasing general and administration costs.

Cash used in investing activities increase from cash outflow of $4.3 million for the three months ended September 30, 2011 to a cash outflow of $8.7 million for the three months ended September 30, 2012. The cash outflow for both three month periods ended September 30, 2012 and 2011 is as a result of drilling/exploration activities being conducted in our Hawk Springs and Roosevelt projects.

Cash provided by financing activities increased from a cash inflow of $0.3 million for the three months ended September 30, 2011 to cash inflow of $0.4 million for the three months ended September 30, 2012. Cash inflow for both of the three month periods is a result of the exercise of options during the respective period.

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 the fiscal year ending June 30, 2013 as well. Our current budget for exploration, exploitation and development capital expenditures in fiscal year ending June 30, 2013 is $9 million, of which we incurred approximately $5 million during the first quarter of the fiscal year. The remaining expenditure relates to:

the completion of the Spirit of America II well,

the salt water disposal well in our North Stockyard project as well as at least two development wells in this project and

the initial well in our South Prairie Project in North Dakota.

We also have a rig commitment, expected to commence in December 2012, the total commitment over 18 months is $14.2 million.

We expect to fund our fiscal year 2013 capital expenditures with cash on hand and cash flow from operations, and there is also a possibility we will conduct an equity capital raising or debt financing. In addition, there is a possibility that we will pursue one or more significant acquisitions that require equity or debt financing. However, there is no guarantee that we will be able to fund all of the planned expenditure from our existing working capital or be able to raise the funds through the equity or debt markets.

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 fiscal year ending June 30, 2013, 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 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.

Currently our two main sources of liquidity are cash on hand, which was $10.5 million at September 30, 2012, and cash flow from operations. There is also a possibility that during the fiscal year ending June 30, 2013 we will conduct a equity capital raise or debt financing. During the past two fiscal years, our two main sources of liquidity were (i) approximately $73.2 million cash received from the sale of 24,166 acres in Goshen County, Wyoming to Chesapeake Energy Corporation and (ii) $6.3 million received from the sale of our interests in the Jonah and Lookout Wash fields. Both sales occurred during the fiscal year ended June 30, 2011. During the recent years prior to the fiscal year ended June 30, 2011, our primary sources of liquidity were (i) equity sales and (ii) a loan facility with Macquarie Bank Limited, which we repaid in full on May 30, 2011.

Our cash on hand position has decreased from the same period in the previously year largely due to exploration expenditures which have not produced meaningful cash flow to date from production results. In particular, both of the two Roosevelt project wells drilled in the fiscal year ended June 30, 2012 have so far failed to deliver positive results and one well in the Hawk Springs project well was also drilled unsuccessfully. If future drilling success rates or production are less than anticipated, 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, 2012 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."

During the quarter ended September 30, 2012, 27,983,189 1.5 Australian cent (A$0.015) warrants were exercised for net proceeds of $ 0.4 million to us. The warrants exercised were issued in a public rights offering conducted in October 2009 and expire December 31, 2012.

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