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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the quarterly period ended March 31, 2012
Commission File Number: 333-123711
Samson Oil & Gas Limited
(Exact Name of Registrant as Specified in its Charter)
+61 8 9220 9830
(Registrant’s Telephone Number, Including Area Code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes S No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
There were 1,761,535,827 ordinary shares outstanding as of May 7, 2012.
SAMSON OIL & GAS LIMITED
QUARTER ENDED MARCH 31, 2012
TABLE OF CONTENTS
Written forward–looking statements may appear in documents filed with the Securities and Exchange Commission (“SEC”), including this quarterly report, documents incorporated by reference, reports to shareholders and other communications.
The U.S. Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for forward–looking information to encourage companies to provide prospective information about themselves without fear of litigation so long as the information is identified as forward looking and is accompanied by meaningful cautionary statements identifying important factors that could cause actual results to differ materially from those projected in the information. Samson relies on this safe harbor in making forward–looking statements.
Forward–looking statements appear in a number of places in this quarterly report and include but are not limited to management’s comments regarding business strategy, exploration and development drilling prospects and activities at our oil and gas properties, oil and gas pipeline availability and capacity, natural gas and oil reserves and production, meeting our capital raising targets and following any use of proceeds plans, our ability to and methods by which we may raise additional capital, production and future operating results.
In this quarterly report, the use of words such as “anticipate,” “continue,” “estimate,” “expect,” “likely,” “may,” “will,” “project,” “should,” “believe” and similar expressions are intended to identify uncertainties. While we believe that the expectations reflected in those forward–looking statements are reasonable, we cannot assure you that these expectations will prove to be correct. Our actual results could differ materially from those anticipated in these forward–looking statements. The differences between actual results and those predicted by the forward-looking statements could be material. Forward-looking statements are based upon our expectations relating to, among other things:
Many of these factors are beyond our ability to control or predict. Neither these factors nor those included in the “Risk Factors” section of this quarterly report represent a complete list of the factors that may affect us. We do not undertake to update our forward–looking statements.
Part I — Financial Information
CONSOLIDATED BALANCE SHEETS
See accompanying Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
See accompanying Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying Notes to Consolidated Financial Statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Presentation
These Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial reporting. All adjustments which are, in the opinion of management, necessary to fairly state Samson Oil & Gas Limited’s (the Company) Consolidated Financial Statements have been included herein. Interim results are not necessarily indicative of expected annual results because of the impact of fluctuations in prices received for oil and natural gas, as well as other factors. In the course of preparing the Consolidated Financial Statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events, and, accordingly, actual results could differ from amounts previously established.
The Company’s Consolidated Financial Statements have been prepared on a basis consistent with the accounting principles and policies reflected in the Company’s audited financial statements as of and for the year ended June 30, 2011. The year-end Consolidated Balance Sheet presented herein was derived from audited Consolidated Financial Statements, but does not include all disclosures required by GAAP.
These Consolidated Financial Statements should be read in conjunction with our audited Consolidated Financial Statements included in our Annual Report on Form 10-K for the fiscal year ended June 30, 2011.
Accruals. The components of accrued liabilities for the periods ended March 31, 2012 and June 30, 2011 includes accruals based on estimated costs relating to goods and services provided yet not invoiced and an amount payable for Samson’s employee bonus plan.
Recent Accounting Standards
In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04 Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRSs. The ASU amends previously issued authoritative guidance and is effective for interim and annual periods beginning after December 15, 2011. The amendments change requirements for measuring fair value and disclosing information about those measurements. Additionally, the ASU clarifies the FASB’s intent regarding the application of existing fair value measurement requirements and changes certain principles or requirements for measuring fair value or disclosing information about its measurements. For many of the requirements, the FASB does not intend the amendments to change the application of the existing Fair Value Measurements guidance. This guidance will not have an impact on our financial position or results of operations.
In June 2011, the FASB issued ASU No. 2011-05 Presentation of Comprehensive Income. The ASU amends previously issued authoritative guidance and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. These amendments remove the option under current GAAP to present the components of other comprehensive income as part of the statements of changes in stockholder’s equity. The adoption of this guidance will not have an impact on our financial position or results of operations, but will require the Company to present the statements of comprehensive income separately from its statements of equity, as these statements are currently presented on a combined basis. This guidance will be adopted by Samson in the period beginning July 1, 2012.
In December 2011, the FASB issued ASU No. 2011-11 Disclosures about Offsetting Assets and Liabilities. The ASU requires additional disclosures about the impact of offsetting, or netting, on a company's financial position, and is effective for annual periods beginning on or after January 1, 2013 and interim periods within those annual periods, and retrospectively for all comparative periods presented. Under US GAAP, derivative assets and liabilities can be offset under certain conditions. The ASU requires disclosures showing both gross information and net information about instruments eligible for offset in the balance sheet. The Company is currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on the Company's financial position or results of operations.
2. Income Taxes
The Company has current year losses and available prior year cumulative net operating losses that may be carried forward to reduce taxable income in future years. The Tax Reform Act of 1986 contains provisions that limit the utilization of net operating loss carryforwards if there has been a change in ownership as described in Internal Revenue Code Section 382. The Company’s prior year losses are limited by IRC Section 382, however, current year losses are not subject to these limitations.
This current year operating loss will be carried back to offset tax paid in the June 30, 2011 year end. This will generate a current year benefit and income tax receivable for the tax expected to be refunded from the carry back claim
The tax for the period ending March 31, 2011 is current tax expense. This expense is the result of the sale of property that generated an extraordinary gain, when combined with the ordinary operating activity, was in excess of the net operating losses available to offset the net taxable income for the period. Deferred taxes for the period continue to be zero as there is a full valuation allowance on the remaining net deferred tax asset.
ASC Topic 740 requires that a valuation allowance be provided if it is more likely than not that some portion or all deferred tax assets will not be realized. The Company's ability to realize the benefit of its deferred tax assets will depend on the generation of future taxable income through profitable operations. Due to the Company's history of losses and the uncertainty of future profitable operations, the Company has recorded a full valuation allowance against its deferred tax assets
3. Earnings Per Share
Basic earnings (loss) per share is calculated by dividing net earnings (loss) attributable to common stock by the weighted average number of shares outstanding for the period. Under the treasury stock method, diluted earnings per share is calculated by dividing net earnings (loss) by the weighted average number of shares outstanding including all potentially dilutive common shares (unexercised stock options). In the event of a net loss, no potential common shares are included in the calculation of shares outstanding since the impact would be anti-dilutive. The Company's unexercised stock options do not contain rights to dividends. When the Company records a net loss, none of the loss is allocated to the unexercised stock options since the securities are not obligated to share in Company losses. Consequently, in periods of net loss, outstanding options will have no dilutive impact to the Company’s basic earnings per share.
The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and warrants, for the periods presented:
The following tables set forth the calculation of basic and diluted earnings per share for continuing and discontinued operations:
4. Asset Retirement Obligations
The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut–in properties at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted using the units–of–production method.
The following table summarizes the activities for the Company’s asset retirement obligations for the nine months ended March 31, 2012 and for the twelve months ended June 30, 2011:
Discount rates used to calculate the present value vary depending on the estimated timing of the obligation, but typically range between 4% and 9%.
5. Equity Incentive Compensation
Stock-based compensation is measured at the grant date based on the value of the awards, and the fair value is recognized on a straight-line basis over the requisite service period (usually the vesting period).
Total compensation cost recognized in the Statements of Operations for the grants under the Company’s equity incentive compensation plans was $125,722 and $496,888 during the three months ended March 31, 2012 and 2011 and $962,443 and $2,260,221 during the nine months ended March 31, 2012 and 2011.
The following table summarizes stock option activity for the nine months ended March 31, 2012:
In July 2011, 4,000,000 stock options were granted under the Samson Oil & Gas Limited Stock Option Plan to an employee of the Company. These options have an exercise price of 16.4 cents (Australian) and an expiry date of December 31, 2014. One third of these stock options vested on July 31, 2011. Another third will vest on July 31, 2012 with the remaining third vesting on July 31, 2013, provided the employee is still employed by the Company on those dates.
The fair value of each option granted was estimated using the Black-Scholes option pricing model. The following assumptions were used to compute the weighted average fair market value of options granted:
In November 2011, 4,000,000 options were granted under the Samson Oil and Gas Limited Stock Option to a non-executive Director of the Company. These options have an exercise price of 15.5 cents (Australian) and expiry date of October 31, 2015. These options vested immediately. The fair value of each option granted was estimated using the Black-Scholes option pricing model. The following assumptions were used to compute the weighted average fair market value of options granted:
As of March 31, 2012, there was $292,493 of total unrecognized compensation cost related to outstanding stock options. This cost is expected to be recognized over three years.
6. Hedging and Derivative Instruments
Commodity Derivative Agreements. The Company utilizes swap and collar option contracts to hedge the effect of price changes on a portion of its future oil production. The objective of the Company’s hedging activities and the use of derivative financial instruments is to achieve more predictable cash flows. While the use of these derivative instruments limits the downside risk of adverse price movements, they also may limit future revenues from favorable price movements.
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are with a single multinational bank with no history of default with the Company. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. No collateral has been provided in relation to the current contracts outstanding. Collateral may be required for future contracts.
The Company has elected not to apply hedge accounting to any of its derivative transactions and, consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income for those commodity derivatives that would qualify as cash flow hedges.
As of March 31, 2012, the Company has not entered into any derivative agreements in relation to its oil or gas production.
Following the sale of our interest in the Jonah and Lookout Wash properties our exposure to natural gas price fluctuations decreased significantly. On July 6, 2011, we closed out our remaining gas derivative positions. The termination of these positions resulted in Macquarie Bank Limited (the counter party to the hedges) paying us $36,500.
The components of commodity derivative losses (gains) in the Consolidated Statements of Operations are as follows:
7. Fair Value Measurements
Fair value is defined as the price that would be received in the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. The FASB has established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).
The three levels of the fair value hierarchy are as follows:
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of March 31, 2011 and June 30, 2011.
The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above:
Commodity Derivative Contracts. In previous periods, the Company’s commodity derivative instruments consisted of collar contracts for oil. The Company valued the derivative contracts using industry standard models, based on an income approach, which considers various assumptions including quoted forward prices and contractual prices for the underlying commodities, time value and volatility factors, as well as other relevant economic measures. Substantially all of the assumptions can be observed throughout the full term of the contracts, can be derived from observable data or are supportable by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the fair value hierarchy. As at March 31, 2012 the Company did not have any derivative instrument contracts in place.
Fair Value of Financial Instruments. The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable and payable and derivatives (discussed above). The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short–term maturities.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis. The Company also applies fair value accounting guidance to measure non–financial assets and liabilities such as business acquisitions, proved oil and gas properties, and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. These items are primarily valued using the present value of estimated future cash inflows and/or outflows. Given the unobservable nature of these inputs, they are deemed to be Level 3.
Fair value of assets and liabilities
The carrying value, fair value and level of fair value hierarchy of all financial assets and liabilities is included below:
8. Commitments and Contingencies
Leases –The Company has entered into lease agreements for office space in Denver, Colorado and Perth, Western Australia. As of June 30, 2011, future minimum lease payments under operating leases that have initial or remaining non–cancelable terms in excess of one year are $159,091 in 2012, $143,572 in 2013, $118,721 in 2014, $121,029 in 2015, $123,339, 2016 and $10,294 thereafter. Net rent expense incurred for office space was $59,705 for the three months ending March 31, 2012 and $37,095 for the three months ending March 31, 2011 and $165,010 for the nine months ending March 31, 2012 and $109,582 for the nine months ending March 31, 2011.
Rig commitments – The Company has entered into two drilling contracts with Frontier Drilling. The first, for Rig 24 is an 18 month contract, expected to commence August 1, 2012. The rig is a 1,500 horsepower, diesel electric rig equipped with a top drive. The rig is mounted on a box on box structure and capable of being skidded between wells on a single Eco Pad. The commitment over 18 months is approximately $14.2 million. The rig is a high quality rig and we have the right to sub-contract the rig to other parties should we not be able to utilize the rig for the full 18 months.
The second contract, for Rig 11 is a single well contract. This rig is currently being used to drill Spirit of America II in our Hawk Springs Project in Goshen County, Wyoming. The rig is a 1,000 horse-power, diesel electric rig equipped with a top drive. This well is expected to cost approximately $4 million, including the cost of the rig.
The Company has no material accrued environmental liabilities for its sites, including sites in which governmental agencies have designated the Company as a potentially responsible party, because it is not probable that a loss will be incurred and the minimum cost and/or amount of loss cannot be reasonably estimated. However, due to uncertainties associated with environmental assessment and remediation activities, future expense to remediate the currently identified sites, and sites identified in the future, if any, could be incurred. Management believes, based upon current site assessments, that the ultimate resolution of any matters will not result in material costs incurred.
There are no unrecorded contingent assets or liabilities in place for the Company at March 31, 2012 or June 30, 2011.
9. Capitalized Exploration Expense
We use the successful efforts method of accounting for exploration and evaluation expenditure in respect of each area of interest. The application of this policy requires management to make certain estimates and assumptions as to future events and circumstances, in particular the assessment of whether economic quantities of reserves have been found. Any such estimates and assumptions may change as new information becomes available.
Exploration and evaluation assets are assessed for impairment when facts and circumstances indicate that the carrying amount of an exploration and evaluation asset may exceed its recoverable amount. When assessing for impairment consideration is given to but not limited to the following:
If, after having capitalized expenditures under our policy, we conclude that we are unlikely to recover the expenditures through future exploitation or sale, then the relevant capitalized amount will be written off to the statement of operations.
Currently we have capitalized exploration expenditures of $22.6 million and undeveloped capitalized acreage of $9.7 million. This primarily relates to costs in relation to our Hawk Springs (including 3D seismic acquisition costs) and Roosevelt projects (including the drilling and permitting of exploration wells). The costs include acreage acquisition costs in both of Hawk Springs and Roosevelt project areas. During the nine months ended March 31, 2012 we drilled our first appraisal well in our Roosevelt Project, Australia II. This well has been fracture stimulated and production facilities are currently being built at the location. We have also incurred costs in relation to the permitting and location building of a number of other prospective well sites in the Roosevelt project area. Our second appraisal well in this project, Gretel II commenced drilling in January 2012 and was fracture stimulated in March 2012. Production facilities are also being constructed on this location.
During the prior quarter, we continued drilling our Spirit of America well in our Hawk Springs Project. Numerous operational difficulties were incurred during the drilling of this well and it ultimately failed to reach its target. Accordingly costs associated with this well have been written off from capitalized exploration expenditure to the Statement of Operations, in Exploration and Evaluation Expenditure in the amount of $4.9 million, including $0.4 million in the current quarter.
10. Issue of Share Capital
During the nine months ended March 31, 2012, 26,645,368 1.5 Australian cent warrants were exercised for net proceeds of $424,473 to us. The warrants were issued in public rights offering conducted in October 2009.
11. Cash Flow Statement
Reconciliation of the net profit/(loss) after tax to the net cash flows from 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, 2011, included in our Annual Report on Form 10-K and the Consolidated Financial Statements included elsewhere herein.
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 23,833 barrels of oil for the quarter ended March 31, 2012 compared to 12,501 barrels of oil for the quarter ended March 31, 2011. Our net production was 67,674 barrels for the nine months ended March 31, 2012 compared to 43,982 barrels of oil for the nine months ended March 31, 2011. Our net gas production was 60,475 Mcf for the quarter ended March 31, 2012 compared to 53,736 Mcf for the quarter ended March 31, 2011. Our net gas production was 176,484 Mcf for the nine months ended March 31, 2012 compared to 364,593 Mcf for the nine months ended March 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 and in a manner consistent with preserving adequate liquidity and financial flexibility.
Notable Activities During the Quarter Ended March 31, 2012 and Current Activities
Hawk Springs Project, Goshen County, Wyoming
We are continuing to evaluate production and core data from the Defender US33 #2-29H well to determine the validity for drilling a new Niobrara well, the Magic US38 #1-18H. Production to date has occurred from the traditional rod pump method which has been inefficient in handling gas and sand produced with the oil. A jet pump has been installed at the Defender well, this has been installed to alleviate gas locking and sanding issues that were experienced with the traditional sucker rod pump that has been on the well since inception. The core data has been analyzed and confirms that our Niobrara Formation exists well within the oil maturity window at our Defender well location as well as over the majority of Samson’s acreage position. This information along with our recent production is encouraging.
The initial Spirit of America well was drilled in the prior quarter and difficulties in drilling this well resulted in the well failing to reach our target depth. The Spirit of America replacement well, Spirit of America US34 #2-29, spud on May 1st and will test the Permian and Pennsylvanian age targets delineated from Samson’s North Platte 3-D seismic survey. We have mapped numerous similar prospects within this 3-D seismic area that we anticipate will lead to more drilling locations. We expect that a larger, more powerful top-drive rig combined with a heavy weighted oil-based mud and an intermediate casing string set over the salt and bubble gum shale section should enable us to reach these targets.
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 the Halliburton Joint Venture (HJV). Post completion of the Halliburton farmin, Samson will have a net 5,260 acres and outside of the HJV area Samson has a net 13,320 acres, amounting to total net acreage of 18,580 acres. Within the HJV area, Samson will remain Operator; however, Halliburton will be providing project management services along with regular oil field services to effect the drilling, completion and fracture stimulation of the wells drilled.
Roosevelt Project, Roosevelt County, Montana
Samson owns approximately 23,000 acres of leasehold (subject to a 33.4% back in) in the Roosevelt Project and retains the option to acquire additional acreage within the project area, which on a “most likely” case basis will result in Samson having a net acreage position of 31,000 acres after a back in has been exercised. During the quarter ended March 31, 2012 we purchased approximately 10,000 acres at an average cost of $175 per acre.
The first two initial wells, Australia II 12 KA 6 and Gretel II 12 KA 3, are 4,500 foot laterals in the middle Bakken Formation. The Australia II well was drilled in the 4th quarter of calendar year 2011 to a depth of 14,972 feet and the Gretel II well was drilled in January/February of 2012 to a depth of 15,555 feet.
Good gas and oil shows were recorded on the mudlogs while drilling through the Middle Member of the Bakken Formation in both wells. The Australia II and Gretel II wells have both been fracture-stimulated using a multi-stage, external casing packer completion technique. Approximately 600 barrels of oil were produced from the Australia II well during plug drill-out and flow-back operations before the well was shut-in while production facilities are being built.
A workover rig is currently drilling out the frac plugs on the Gretel II 12 KA 3 well. The well will subsequently be flowed back. Following the flow back, production facilities will be built on site, which is expected to occur during May and June.
If commercial production is established at Australia II 12 KA 6 or Gretel II 12 KA 3, a development program would commence and include the drilling of Australia III 12 KA 9 well (permitted), the Australia IV 12 KA 16 well (permitted and surface casing set), or a new location yet to be named.
Following 90 days of consistent production (defined as production in economic quantities for at least 20 days each month) from the two initial appraisal wells, Samson’s partner in the project area, Fort Peck Energy Company (FPEC), will have the option to back into a 33.34% position in the wells and land by reimbursing Samson’s acreage and drilling costs to the extent of that equity. In such an event, Samson will have a 66.66% working interest and a 53.34% net revenue interest.
FPEC is owned by North American Resource Partners (NARP) and the Assiniboine and Sioux Tribes. NARP is a portfolio company of Quantum Energy Partners, a private equity fund with substantial experience in energy transactions with Indian Nations. While Samson is not part of FPEC or NARP, the importance of having the Fort Peck Tribes as equity partners, albeit indirectly, was an important part of Samson’s decision to invest in the Roosevelt Project.
Hawk Springs Project, Goshen County, Wyoming
Cretaceous Niobrara Formation, Northern D-J Basin
Pending economic production results from the Defender well, a longer 9,000+ foot lateral in the Niobrara is currently being planned. We have recently requested a hearing at the Wyoming Oil and Gas Commission to allow for 1280 acre well spacing in order to drill such a well.
Hawk Springs Project, Goshen County, Wyoming
Wildcat (Exploratory) targets in the Permian & Pennsylvanian, Northern D-J Basin
Spirit of America US34 #1-29
Samson 100% Working Interest
The Spirit of America US34 #2-29 well spud on May 1st. This 11,000’ vertical well will test two targets in the Lower Permian and Pennsylvanian age rocks. The Company previously attempted to test these targets but was unsuccessful in doing so due to drilling difficulties in the Permian salt section. A larger, more powerful top-drive rig combined with a heavy weighted oil-based mud and an intermediate casing string set over the salt and bubble gum shale section should allow us to reach our targets.
North Stockyard Oilfield, Williams County, North Dakota
Mississippian Bakken Formation, Williston Basin
Samson various Working Interests
During the quarter, the North Dakota Industrial Commission approved the spacing order request for North Stockyard allowing for the drilling of four in-fill locations. We have received a proposal from the operator of this field to drill the first infill well in August 2012.
North Stockyard Oilfield, Williams County, North Dakota
Mississippian Bakken Formation, Williston Basin
Samson various Working Interests
Samson has seven producing wells in the North Stockyard Field. These wells are located in Williams County, North Dakota, in Township 154N Range
Sabretooth Gas Field, Brazoria County Texas
Oligocene Vicksburg Formation, Gulf Coast Basin
Samson 12.5% Working Interest
Production for the Davis Bintliff #1 well averaged 3.0 MMcf/D and 30 BOPD for the quarter. The well was 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) during the quarter due to depressed gas prices. Cumulative production to date is approximately 4.5 Bscf and 53 MBO.
We plan to focus on two main objectives in the coming 12 months:
Results of Operations
In the third quarter of the year ending June 30, 2012, we reported a net loss of ($0.5) million.
For the nine months ended March 31, 2012, we reported net loss of ($6.1) million and net cash from operations of $3.0 million.
The following table sets forth selected operating data (including the results of discontinued operations) for the three months ended:
The following table sets forth selected operating data (including the results of discontinued operations) for the nine months ended:
The following table sets forth results of operations, including total income from discontinued operations, for the three month periods ended:
The following table sets forth results of operations, including total income from discontinued operations, for the nine month periods ended:
Three Months and Nine Months Comparison of Quarter Ended March 31, 2012 to Quarter Ended March 31, 2011
Oil and gas revenues
Oil revenues increased from $1.2 million for the three months ended March 31, 2011 to $2.0 million for the three months ended March 31, 2012 primarily as a result of our increased focus on oil production. Oil production increased slightly from 12,501 barrels for the quarter ended March 31, 2011 to 23,833 barrels for the quarter ended March 31, 2012. Our realized oil price decreased from $93.59 for the quarter ended March 31, 2011 to $85.98 for the quarter ended March 31, 2012.
Oil revenues increased from $3.3 million for the nine months ended March 31, 2011 to $5.8 million for the nine months ended March 31, 2012. This increase is due to a 54% increase in sales volumes and a 14% increase in realized price for the nine months ended March 31, 2012 compared to the nine months ended March 31, 2011.
Gas revenues remained consistent at $0.2 million for the three months ended March 31, 2011 and $0.2 million for the three months ended March 31, 2012. Production increased by 12%, while revenues remained consistent due to a slight depreciation in the gas price from $4.52 for the quarter ended March 31, 2011 to $3.90 for the quarter ended March 31, 2012.
Gas revenues increased from $0.6 million for the nine months ended March 31, 2011 to $0.8 million for the nine months ended March 31, 2012. This increase is due a continuation in gas sales from our North Stockyard field, minimal gas sales were recognized from the North Stockyard field in the prior year and a 23% increase in realized price for the nine months ended March 31, 2012 compared to the nine months ended March 31, 2011.
Other revenues increased from $0.002 million for the nine months ended March 31, 2011 to $0.03million for the nine months ended March 31, 2012. The increase is due to the funds received from the close out of our gas hedging position in July 2011. Previously cash proceeds from derivative instruments were allocated to discontinued operations.
Sale of exploration acreage
Sale of exploration acreage decreased from $73.2 million for the nine months ended March 31, 2011 to $nil for the nine months ended March 31, 2012. The sale was one off sale and is not expected to be repeated again in the foreseeable future.
Exploration expenditure decreased from $0.7 million for the three months ended March 31, 2011 to $0.45 million for the three months ended March 31, 2012. Difficulties in drilling the Spirit of America well in our Hawk Springs project in Goshen County, Wyoming resulted in the well failing to reach our target depth and accordingly costs associated with this well have been written off from capitalized exploration expenditure to the Statement of Operations, Exploration and Evaluation Expenditure in the amount of $4.9 million, including $0.4 million in the current quarter. Other exploration expenditure in both quarters relates to delay rental payments that are most often made annually in order to maintain our lease hold position on non-producing leases.
Exploration expenditure increased from $1.7 million for the nine months ended March 31, 2011 to $5.2 million for the nine months ended March 31, 2012. As detailed above $4.9 million relates to costs associated with our Spirit of America well. Other exploration expenditure decreased as our main projects have reached a stage where more of the expenditure can be capitalized pending results of the exploration activities.
We currently have approximately $21.0 million capitalized in exploration expense on the balance sheet in relation to the Australia II and Gretel II wells. While these wells are still being completed, depending on the outcome of them and the timing of the completion, 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 $0.3 million for the quarter ended March 31, 2011 to $0.7 million for the quarter ended March 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.
Lease operating expenses increased from $1.0 million for the nine months ended March 31, 2011 to $1.8 million for the nine months ending March 31, 2012 as there was more well activity during the nine months ended March 31, 2012 compared to the number of wells online during the nine months ended March 31, 2011 and the increased cost of operations in North Stockyard as discussed above.
Depletion, depreciation and amortization expense
Depletion, depreciation and amortization expense increased from $0.4 million for the quarter ended March 31, 2011 to $0.7 million for the quarter ended March 31, 2012. Depreciation, depletion and amortization expense per BOE increased to $19.83 for the quarter ended March 31, 2012 compared to $18.63 for the quarter ended March 31, 2012.
Depletion, depreciation and amortization expense increased from $1.5 million for the nine months ended March 31, 2011 to $2.0 million for the same period ended March 31, 2012. This is a result of an increase in depletion expense per BOE for the period.
General and administrative expense
General and administrative expense increased slightly from $1.7 million for the quarter ended March 31, 2011 to $1.9 million for the quarter ended March 31, 2012. Included within general and administrative expense is $0.125 million of share based payments expense for the current quarter compared with $0.5 million for the prior quarter. The share based payments expense in the prior quarter relates to options granted to Directors that vested immediately, therefore all of the expense was recognized upon the grant date. $0.12 million of the share based payments expense in the current quarter relates to options granted to employees during the year ended June 30, 2011 that vest over a three year period and the expense is recognized over this period, resulting in a charge each quarter.
General and administrative costs decreased from $6.2 million for the nine months ended March 31, 2011 to $5.8 million for the nine months ended March 31, 2012.
Interest expense decreased from $0.207 million for the quarter ended March 31, 2011, to nil for the period ended March 31, 2012. We repaid our debt in full during the year ended June 30, 2011 thus no longer incur interest expense.
Interest expense decreased from $0.7 million for the nine months ended March 31, 2011 to nil for the nine months ended March 31, 2012. We repaid our debt in full during the year ended June 30, 2011 thus no longer incur interest expense.
Income tax (expense)/benefit
Income tax benefit increased from a benefit of $0.4 million for the quarter ended March 31, 2011 to a benefit of $0.83 million for quarter ended March 31, 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 prior year.
Income tax expense decreased from $14.7 million for the nine months ended March 31, 2011 to a benefit of $1.7 million for the nine months ended March 31, 2012. As noted above, the tax expense recognized in the prior year was as a result of the sale of exploration acreage during that period. This was a one-off sale and no similar sale was recorded in the current period. 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 prior year.
We recorded a gain from discontinued operations in the quarter ended March 31, 2011 of $2.4 million compared to nil in the current quarter. The discontinued operations related to our interest in the Jonah and Look Out Wash fields in Wyoming. We sold these properties during the year ended June 30, 2011 and do not have any discontinued operations for the quarter ended March 31, 2012.
We recorded a gain from discontinued operations in the nine months ended March 31, 2011 of $2.6 million compared to nil in the current quarter. The discontinued operations related to our interest in the Jonah and Look Out Wash fields in Wyoming. We sold these properties during the year ended June 30, 2011 and do not have any discontinued operations for the nine months ended March 31, 2012.
The table below shows cash flows, including those from discontinued operations, for the nine month period ended:
Cash provided by operations increased from an outflow of $7.7 million for the nine months ended March 31, 2011 to $3.0 million for the nine months ended March 31, 2012. The large cash outflow in the prior period was a result of income taxes paid of $7.0 million being paid. An income tax refund at $2.9 million was received during the current quarter.
Cash used in investing activities decreased from cash inflow of $72.0 for the nine months ended March 31, 2011 to a cash outflow of ($30.3 million) for the nine months ended March 31, 2012. The cash inflow in the prior period was primarily as a result of cash received from the sale of exploration acreage. The cash outflow for the nine months ended March 31, 2012 is as a result of drilling/exploration activities being conducted in our Hawk Springs and Roosevelt projects.
Cash provided by financing activities decreased from a cash inflow of $1.7 million for the nine months ended March 31, 2011 to a cash inflow of $0.4 million for the nine months ended March 31, 2012. The cash inflow in the nine months ended March 31, 2011 was a result of cash being received from a capital raising that was completed during July 2010. Cash provided by financing activities in the current quarter was a result of the exercise of 26,645,368 options with net proceeds of $424,473.
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, 2012 as well. Our current budget for exploration, exploitation and development capital expenditures in fiscal year ending June 30, 2012 is $35 million, of which we have incurred approximately $30 million during the first nine months of the fiscal year. The remaining expenditure relates to the completion of the production facilities on the Australia II and Gretel II wells, in our Roosevelt Project and the drilling and completion of the Spirit of America II well in our Hawk Springs project area. We increased our budget from the previous quarter due to unexpected additional expenditures on Australia II and Gretel II wells and the acquisition of additional acreage in our Roosevelt project.
We expect to fund our fiscal year 2012 capital expenditures primarily with cash flow from cash on hand and operations. Uncertainties relating to our capital resources and requirements include the effects of changes in oil and natural gas prices and results from our drilling program, either of which could lead us to accelerate or decelerate activities, including but not limited to our drilling, as well as the possibility that we will pursue one or more significant acquisitions that require debt or equity financing.
As we continue to grow, 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 proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional productive reserves.
Most recently, our main sources of liquidity have been (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.
During the quarter ended March 31, 2012, 8,072,977 1.5 Australian cent (A$0.015) warrants were exercised for net proceeds of $121,094 to us. The warrants exercised were issued in a public rights offering conducted in October 2009.
Debt obligations at March 31, 2012 decreased $9,597,426 to nil compared with the three months ended March 31, 2011, primarily due to the repayment in full of our loan facility with Macquarie Bank Limited in May 2011.
There were no material changes to the disclosure made in our Annual Report on Form 10-K for the year ended June 30, 2011 regarding this matter.
As of March 31, 2012, we have carried out an evaluation under the supervision of, and with the participation of, our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
Our Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2012, our disclosure controls and procedures were effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
There were no changes in our internal control over financial reporting that occurred during the three months ended March 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time in the future.
Part II — Other Information
In the ordinary course of our business we are named from time to time as a defendant in various legal proceedings. We maintain liability insurance and believe that our coverage is reasonable in view of the legal risks to which our business ordinarily is subject.
In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended June 30, 2011. The risks disclosed in our Annual Report on Form 10-K could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our business, financial condition or operating results in the future.
** Furnished herewith
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.