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EX-31.1 - EXHIBIT 31.1 - Samson Oil & Gas LTDv440046_ex31-1.htm
EX-31.2 - EXHIBIT 31.2 - Samson Oil & Gas LTDv440046_ex31-2.htm
EX-32.1 - EXHIBIT 32.1 - Samson Oil & Gas LTDv440046_ex32-1.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended March 31, 2016

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission File Number: 001-33578

 

Samson Oil & Gas Limited

(Exact Name of Registrant as Specified in its Charter)

 

Australia N/A
(State or Other Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification No.)

 

Level 16, AMP Building,

140 St Georges Terrace

Perth, Western Australia 6000

 
(Address Of Principal Executive Offices) (Zip Code)

 

 

+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 x      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.

 

Large accelerated filer ¨ Accelerated filer     ¨
     
Non-accelerated filer ¨ Smaller reporting company     x

 

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 3,215,854,701 ordinary shares outstanding as of May 13, 2016.

 

 

 

 

SAMSON OIL & GAS LIMITED

FORM 10-Q

QUARTER ENDED March 31, 2016

 

TABLE OF CONTENTS

 

    Page
     
Part I — Financial Information 4
     
Item 1. Financial Statements (unaudited) 4
   
  Consolidated Balance Sheets, March 31, 2016 and June 30, 2015 4
   
  Consolidated Statement of Operations and Comprehensive Income (Loss) for the three months ended March 31, 2016 and 2015 and nine months ended March 31, 2016 and 2015 5
   
  Consolidated Statement of Changes in Stockholders’ Equity/(Deficit) for the nine months ended March, 2016 6
   
  Consolidated Statement of Cash Flows for the nine months ended March 31, 2016 and 2015 7
   
  Notes to  Consolidated Financial Statements (unaudited) 8
     
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operation 15
     
Item 3. Quantitative and Qualitative Disclosures About Market Risk 24
     
Item 4. Controls and Procedures 24
   
Part II   — Other Information 25
     
Item 1. Legal Proceedings 25
     
Item 1A. Risk Factors 25
     
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 26
     
Item 3. Defaults Upon Senior Securities 26
     
Item 4. Mine Safety Disclosures 26
     
Item 5. Other Information 27
     
Item 6. Exhibits 27
     
Signatures 28

 

 

 

 

FORWARD-LOOKING STATEMENTS

 

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:

 

our future financial position, including cash flow, debt levels and anticipated liquidity;

 

the timing, effects and success of our exploration and development activities;

 

uncertainties in the estimation of proved reserves and in the projection of future rates of production;

 

timing, amount, and marketability of production;

 

third party operational curtailment, processing plant or pipeline capacity constraints beyond our control;

 

our ability to acquire and dispose of oil and gas properties at favorable prices;

 

our ability to market, develop and produce new properties;

 

declines in the values of our properties that may result in write-downs;

 

effectiveness of management strategies and decisions;

 

oil and natural gas prices and demand;

 

unanticipated recovery or production problems, including cratering, explosions, fires;

 

the strength and financial resources of our competitors;

 

our entrance into transactions in commodity derivative instruments;

 

climatic conditions; and

 

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 the forward–looking statements made in this report.

 

  3

 

 

Part I — Financial Information

 

Item 1.   Financial Statements.

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

   31-Mar-16   30-Jun-15 
ASSETS          
CURRENT ASSETS          
Cash and cash equivalents  $532,552   $2,062,720 
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively   2,021,448    3,645,223 
Prepayments   143,143    372,079 
Restricted cash - bonding   350,000    - 
Oil inventory   425,925    - 
Fair value of derivative instrument   -    159,216 
Total current assets   3,473,068    6,239,238 
PROPERTY, PLANT AND EQUIPMENT, AT COST          
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment of $57,715,498 and $44,273,976 at March 31, 2016 and June 30, 2015, respectively   34,662,416    29,715,540 
Other property and equipment, net of accumulated depreciation and amortization of $574,676 and $553,428 at March 31, 2016 and June 30, 2015, respectively   125,231    248,521 
Net property, plant and equipment   34,787,647    29,964,061 
OTHER NON CURRENT ASSETS          
Fair value of derivative instrument   -    101,269 
Undeveloped capitalized acreage   -    2,491,422 
Capitalized exploration expense   220,703    1,388,798 
Other   298,069    342,069 
TOTAL ASSETS  $38,779,487   $40,526,857 
           
LIABILITIES AND STOCKHOLDERS’ (DEFICIT)/ EQUITY          
CURRENT LIABILITIES          
Accounts payable  $1,253,716   $1,678,915 
Accruals   707,395    1,999,344 
Fair value of derivative instruments   27,691    - 
Vendor facility   4,000,000      
Credit facility   30,500,000    - 
Provision for annual leave   195,416    219,414 
Total current liabilities   36,684,218    3,897,673 
NON CURRENT LIABILITIES          
Asset retirement obligations   3,361,590    1,263,674 
Fair value of derivative instruments   185,148    - 
Credit facility   -    18,699,000 
TOTAL LIABILITIES   40,230,956    23,860,347 
STOCKHOLDERS’ (DEFICIT)/EQUITY – nil par value          
2,837,834,301 (equivalent to 14,189,172 ADR’s) and 2,837,782,022 (equivalent to 14,188,910 ADR’s) ordinary shares issued and outstanding at March 31, 2016 and June 30, 2015, respectively   104,492,749    104,491,774 
Accumulated other comprehensive income   930,439    996,256 
Accumulated deficit   (106,874,657)   (88,821,520)
Total stockholders’ (deficit)/equity   (1,451,469)   16,666,510 
TOTAL LIABILITIES AND STOCKHOLDERS’(DEFICIT)/ EQUITY  $38,779,487   $40,526,857 

 

 

See accompanying Notes to Consolidated Financial Statements.

 

  4

 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

 

   Three months ended   Nine months ended 
                 
   31-Mar-16   31-Mar-15   31-Mar-16   31-Mar-15 
REVENUES AND OTHER INCOME:                    
Oil sales  $960,705   $2,398,226   $5,281,528   $7,939,471 
Gas sales   156,333    263,823    583,292    667,826 
Other liquids   9,580    -    38,127    - 
Interest income   255    6,365    2,457    25,888 
Gain on derivative instruments   -    371,852    214,055    3,459,558 
Other   879,330    1,297    897,232    8,068 
 TOTAL REVENUE AND OTHER INCOME   2,006,203    3,041,563    7,016,691    12,100,811 
                     
EXPENSES:                    
Lease operating expense   (661,394)   (1,306,117)   (3,492,564)   (4,278,234)
Depletion, depreciation and amortization   (791,104)   (1,658,784)   (3,674,347)   (3,732,464)
Impairment expense   (49,126)   (543,820)   (9,852,113)   (3,604,504)
Abandonment expense   -    (11,868)   -    (226,671)
Exploration and evaluation expenditure   (21,399)   (93,041)   (4,214,118)   (11,558,997)
Accretion of asset retirement obligations   (15,353)   (9,186)   (45,357)   (25,527)
Amortization of borrowing costs   (35,485)   (35,063)   (106,457)   (100,195)
Interest expense   (207,650)   (176,415)   (594,046)   (407,700)
Loss on  derivative instruments   (358,514)   -    -    - 
Acquisition costs   (215,853)   -    (215,853)   - 
General and administrative   (902,455)   (1,151,294)   (2,874,973)   (3,623,366)
TOTAL EXPENSES   (3,258,333)   (4,985,588)   (25,069,828)   (27,557,658)
                     
Loss from operations   (1,252,130)   (1,944,025)   (18,053,137)   (15,456,847)
Income tax benefit   -    -    -    - 
Net loss   (1,252,130)   (1,944,025)   (18,053,137)   (15,456,847)
OTHER COMPREHENSIVE GAIN (LOSS)                    
Foreign currency translation gain/(loss)   (1,653)   (88,059)   (65,817)   (314,458)
Total comprehensive loss for the period  $(1,253,783)  $(2,032,084)  $(18,118,954)  $(15,771,305)
                     
Net loss per ordinary share from operations:                    
Basic – cents per share   (0.04)   (0.07)   (0.64)   (0.54)
Diluted – cents per share   (0.04)   (0.07)   (0.64)   (0.54)
                     
Weighted average ordinary shares outstanding:                    
Basic   2,837,834,301    2,837,782,022    2,837,830,689    2,837,775,738 
Diluted   2,837,834,301    2,837,782,022    2,837,830,689    2,837,775,738 

 

 

See accompanying Notes to Consolidated Financial Statements.

  

  5

 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ (DEFICIT)/EQUITY

(Unaudited)

 

         Accumulated    
          Other   Total 
   Ordinary   (Accumulated
   Comprehensive   Stockholders 
   Shares   Deficit)   Income   Deficit 
Balance at June 30, 2015  $104,491,774   $(88,821,520)  $996,256   $16,666,510 
Net loss   -    (18,053,137)   -    (18,053,137)
Foreign currency translation loss, net of tax of $nil   -    -    (65,817)   (65,817)
Total comprehensive loss for the period   -    (18,053,137)   (65,817)   (18,118,954)
Exercise of options   1,475    -    -    1,475 
Cost associated with issue of equity   (500)   -    -    (500)
Balance at March 31, 2016  $104,492,749   $(106,874,657)  $930,439   $(1,451,469)

 

 

See accompanying Notes to Consolidated Financial Statements.

 

  6

 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

   Nine months ended 
   31-Mar-16   31-Mar-15 
Cash flows provided by operating activities          
Receipts from customers  $8,482,172   $9,403,571 
Payments to suppliers & employees   (7,345,116)   (8,815,489)
Interest received   2,444    25,719 
Proceeds from derivative instruments   437,380    846,916 
Interest paid   (603,027)   (331,258)
Payments for bonding   (350,000)   - 
State income taxes paid   -    (107,135)
Net cash flows provided by operating activities   623,853    1,022,324 
Cash flows used in investing activities          
Payments for plant & equipment   -    (20,249)
Payments for exploration and evaluation   (578,105)   (1,803,402)
Payments for oil and gas properties   (1,811,612)   (15,988,477)
Net cash flows used in investing activities   (2,389,717)   (17,812,128)
Cash flows provided by financing activities          
Proceeds from the exercise of options   1,475    880 
Proceeds from borrowings   301,000    13,000,000 
Borrowing costs   -    (83,690)
Share issuance costs   (500)   (45,000)
Net cash flows provided by financing activities   301,975    12,872,190 
Net (decrease) in cash and cash equivalents   (1,463,889)   (3,917,614)
Cash and cash equivalents at the beginning of the fiscal period   2,062,720    6,846,394 
Effects of exchange rate changes on cash and cash equivalents   (66,279)   (325,387)
Cash and cash equivalents at end of fiscal period  $532,552   $2,603,393 

 

 

See accompanying Notes to Consolidated Financial Statements

 

  7

 

 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

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 normal and recurring by nature, in the opinion of management, necessary for fair statement of 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, 2015. The year-end Consolidated Balance Sheet presented herein was derived from audited Consolidated Financial Statements, but does not include all disclosures required by GAAP.

 

It is suggested that these financial statements be read in conjunction with the financial statements and the notes thereto included in the Company’s latest annual report (“Form 10-K”).

 

Accruals.   Accrued liabilities at March 31, 2016 and June 30, 2015 consist primarily of estimates for goods and services received but not yet invoiced.

 

Prepayments. Prepayments at March 31, 2016 and June 30, 2015 include insurance premiums and other subscription costs paid in advance for the year.

 

Prepayments at June 30, 2015 also included cash advanced to the operators of our South Prairie exploration project for a future exploration well and insurance premiums paid in advance for the year. The exploration well was drilled in October 2015 and was a dry hole. Costs were expensed as incurred.

 

Comparatives. Changes have been made to the classification of certain prior period comparatives in order to remain consistent with the current period presentation. These changes have had no material impact on the financial statements.

 

Recent Accounting Standards

 

In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements –Going Concern (“ASU 2014-15”). The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for fiscal years ending after December 15, 2016 and annual and interim periods thereafter. This standard is not expected to have an impact on the Company’s consolidated financial statements and we are currently assessing the expected impact on footnote disclosures.

 

2. Income Taxes

 

The Company has cumulative net operating losses (“NOLs”) 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 NOLs if there has been a change in ownership as described in Internal Revenue Code Section 382.  The Company’s prior year NOLs are limited by IRC Section 382.

 

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 benefits 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.

 

  8

 

 

3. Earnings Per Share

 

Basic earnings (loss) per share is calculated by dividing net earnings (loss) attributable to ordinary shares 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 ordinary shares (which in Samson’s case consists of unexercised stock options). In the event of a net loss, however no potential ordinary shares are included in the calculation of shares outstanding since the impact would be anti-dilutive.  

 

The following table details the weighted average dilutive and anti-dilutive securities outstanding, which consist of transferable options to purchase ordinary shares which are tradeable on the ASX (“options”), for the periods presented:

 

   Three months ended   Nine months ended 
   31-Mar-16   31-Mar-15   31-Mar-16   31-Mar-15 
Dilutive   -    -    -    - 
Anti–dilutive   320,615,486    324,643,740    322,400,133    367,910,312 

 

The following tables set forth the calculation of basic and diluted loss per share:

 

   Three months ended   Nine months ended 
   31-Mar-16   31-Mar-15   31-Mar-16   31-Mar-15 
Net income (loss)  $(1,252,130)   (1,944,025)  $(18,053,137)   (15,456,847)
                     
Basic weighted average ordinary shares outstanding   2,837,834,301    2,837,782,022    2,837,830,689    2,837,775,738 
Basic earnings per ordinary share – cents per share   (0.04)   (0.07)   (0.64)   (0.54)
Diluted earnings per ordinary share – cents per share   (0.04)   (0.07)   (0.64)   (0.54)

 

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 those obligations. 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 liabilities settled in the nine months to March 31, 2015 relate to work performed to plug and abandon three wells in our Greens Canyon prospect in Wyoming. These wells were drilled 10 years ago and did not produce economic quantities of hydrocarbons. The liabilities settled in the nine months ended March 31, 2016 relates to the plugging of one well in our North Stockyard property, the Harstad. This well’s performance was sub-optimal and experienced high levels of hydrogen sulphide. The additions in the current quarter are a result of the Foreman Butte acquisition completed on March 31, 2016.

 

The amount recorded as a current liability in the current period, relates to work expected to be performed in our Hawk Springs project in Wyoming prior to December 31, 2016.

 

The following table summarizes the activities for the Company’s asset retirement obligations for the nine months ended March 31, 2016 and 2015:

 

   Nine months ended 
   31-Mar-16   31-Mar-15 
Asset retirement obligations at beginning of period  $1,810,674   $1,775,792 
Liabilities incurred or acquired   1,868,273    719,920 
Liabilities settled   (46,322)   (710,561)
Disposition of properties   -    - 
Accretion expense   45,357    25,527 
Asset retirement obligations at end of period   3,677,982    1,810,678 
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)   (316,392)   (135,429)
Long-term asset retirement obligations  $3,361,590   $1,675,249 

 

  9

 

 

5. 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:

 

  · Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

 

  · Level 2—Pricing inputs are other than quoted prices in active markets included in level 1, but are either directly or indirectly observable as of the reported date and for substantially the full term of the instrument. Inputs may include quoted prices for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies.

 

  · Level 3—Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

 

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, 2016 and June 30, 2015.

 

   Carrying value at March 31, 2016   Level 1   Level 2   Level 3   Netting (1)   Fair Value at March 31, 2016 
Current Assets:                              
Cash and cash equivalents  $532,552   $532,552   $-   $-   $-   $532,552 
Derivative Instruments   -    -    551,556    -    (551,556)   - 
                               
Non Current Assets                              
Derivative Instruments   -    -    446,923         (446,923)   - 
                               
Current Liabilities                              
Derivative instruments   27,691    -    579,247    -    (551,556)   27,691 
                               
Non Current Liabilities                              
Derivative Instruments   185,148    -    632,071         (446,923)   185,148 

 

  10

 

 

   Carrying value at June 30, 2015   Level 1   Level 2   Level 3   Netting (1)   Fair Value at June 30, 2015 
Current Assets:                              
Cash and cash equivalents  $2,062,720   $2,062,720   $-   $-   $-   $2,062,720 
Derivative Instruments   159,216    -    379,540    -    (220,324)   159,216 
                               
Non Current Assets                              
Derivative Instruments   101,269    -    298,703    -    (197,434)   101,269 
                               
Current Liabilities                              
Derivative instruments   -    -    220,324    -    (220,324)   - 
                               
Non Current Liabilities                              
Derivative Instruments   -    -    197,434    -    (197,434)   - 

 

(1)Netting In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.

 

The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above:

 

Level 1 Fair value Measurements

Fair Value of Financial Instruments.   The Company’s financial instruments consist primarily of cash and cash equivalents, restricted cash, accounts receivable and payable and derivatives (discussed below). The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short–term maturities.

 

Level 2 Fair Measurements

Derivative Contracts. The Company’s derivative contracts consist of oil collars and oil call options. The fair value of these contracts are based on inputs that are either readily available in the public market, such as oil future prices or inputs that can be corroborated from active markets. Fair value is determined through the use of a discounted cash model using applicable inputs discussed above.

 

Other fair value measurements

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.

 

Some oil and gas properties are stated at fair value as at March 31, 2016. As a result of the significant decline in oil prices experienced in recent months, the carrying value of oil and gas properties was reviewed and subject to impairment costs of $9.6 million for the nine months ended March 31, 2016 relating to our North Stockyard field due to the continued decrease in the oil price.

 

6. Commitments and Contingencies

 

The Company has no 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 such matters will not materially affect our results of operations or cash flows.

 

From time to time, we are involved in various legal proceedings through the ordinary course of business. While the ultimate outcome is not known, management believes that any resolution will not materially impact the financial statements.

 

Halliburton Dispute

 

In March 2016, we settled our outstanding dispute with Halliburton. Under the settlement Halliburton agreed to pay Samson $725,000 and release Samson from its obligation to pay Haliburton $170,000 in revenue relating to its interest in the Defender well in Wyoming. Samson also agreed to forgive $18,000 in unpaid joint interest billings. The impact of these transactions was recognized in other income. This settlement ends this dispute.

 

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7. 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:

 

§the period for which Samson has the right to explore;

 

§planned and budgeted future exploration expenditure;

 

§activities incurred during the year; and

 

§activities planned for future periods.

  

If, after having capitalized expenditures under our policy, we conclude that we are unlikely to recover the expenditures through future exploitation, then the relevant capitalized amount will be written off to expense.

 

As of March 31, 2016 we had capitalized exploration expenditures of $0.2 million. This amount primarily relates to costs incurred in connection with our Cane Creek project in Utah.

 

During the nine months ended March 31, 2016 we have written off $4.1 million in capitalized exploration expenditure, of which $1.3 million related to our Bluff well in our Hawk Springs project. This well has been shut in to observe pressure build up in the well bore. We have not yet determined our final course of action with respect to this well bore, however given the current oil price environment its unlikely that we will commit any further funds to this well in the near term, therefore all costs capitalized associated with this well have been written off. We also wrote off $2.4 million in previously capitalized expenditure in relation to leasehold costs for our Hawk Springs project. In past periods we had written off this leasehold costs as the associated acreage expired. Following the continued deterioration in the oil price, we are not currently committing any funds to further exploration on this leasehold and thus the decision was made to expense all previously capitalized expenditures. The remaining $0.4 million in costs written off relates to costs capitalized with respect to activities on our Spirit of America 1 and Spirit of America 11 wells in our Hawk Springs project in Goshen County, Wyoming. Work performed on these wells failed to demonstrate that hydrocarbons existed in economic quantities.

 

Exploration or divestment activities are continuing in all exploration areas. The outcome of these activities remains uncertain and may result in write offs in future periods if the related efforts prove unsuccessful.

 

8.  Share Capital

 

Issue of Share Capital 

During the nine months ended March 31, 2016, 52,279 options with an exercise price of 3.8 cents (Australian) per ordinary share were exercised for net proceeds of $1,475.

 

During the nine months ended March 31, 2015 24,025 options with an exercise price of 3.8 cents (Australian) per ordinary share were exercised for net proceeds of $880.

 

All options exercised were issued in a public rights offering conducted in June 2013.

 

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9. Cash Flow Statement

 

Reconciliation of loss after tax to the net cash flows from operations:

 

   Nine months ended 
   31-Mar-16   31-Mar-15 
           
Net loss after tax  $(18,053,137)  $(15,456,847)
Depletion, depreciation and amortization   3,674,347    3,732,464 
Accretion of asset retirement obligation   45,357    25,527 
Impairment expense   9,852,113    3,604,504 
Exploration and evaluation expenditure   4,214,118    11,558,997 
Amortization borrowing costs   106,457    100,195 
Abandonment expense   -    226,671 
Non cash (gain)/loss on derivative instruments   473,324    (2,374,018)
Acquistion costs   215,853    - 
           
Changes in assets and liabilities:          
           
Decrease in receivables   1,623,775    2,480,349 
Increase/(decrease) in provision for annual leave   (23,998)   6,310 
(Decrease)/Increase in payables   (1,504,356)   (2,881,828)
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES  $623,853   $1,022,324 

  

10. Credit Facility

 

   Nine months ended 
   31-Mar-16   31-Mar-15 
Credit facility at beginning of period  $18,699,000   $6,000,000 
Cash advanced under facility  $301,000    13,000,000 
Cash committed to be advanced under facility   11,500,000      
Repayments   -    - 
Credit facility at end of period (1)  $30,500,000   $19,000,000 
         - 
Funds available for drawdown under the facility  $-    - 

 

(1)The credit facility in the current period has been presented as a current liability. In previous periods (prior to the quarter ended September 30, 2015) the facility was presented as a non-current liability. Due to the continuing weakness in the global oil price, there is doubt as to whether or not we will be able to meet our future debt covenants. We are working with the bank to renegotiate our facility and extend the term of the facility, we will continue to ask for waivers on a quarterly basis as necessary; however there can be no guarantee they will be granted.

 

In January 2014, we entered into a $25.0 million credit facility with our primary lender, Mutual of Omaha Bank, with an initial borrowing base of $8.0 million, which was increased to $15.5 million in June 2014. In November 2014, the borrowing base was increased to $19.0 million which was fully drawn down as of December 31, 2015. In March 2016, the facility was extended to $30.5 million to partly fund the Foreman Butte acquisition. As a result of this amendment to the facility agreement, the following changes were made to the original facility agreement:

 

·The addition of more restrictive financial covenants (including the debt to EBITDA ratio and the minimum liquidity requirement);
·Increases in the interest rate and unused facility fee;
·The addition of a minimum hedging requirement of 75% of forecasted production;
·A requirement to reduce our general and administrative costs from $6 million per year to $3 million per year;
·A requirement to raise $5 million in equity on or before September 30, 2016;
·A requirement to pay down at least $10 million of the loan by June 30, 2016; and
·The addition of a monthly cash flow sweep whereby 50% of cash operating income will be used to repay outstanding borrowings under the Credit Agreement.

 

The current borrowing base is fully drawn and unless the borrowing base is increased or we pay down outstanding borrowings, we are unable to borrow additional amounts under this facility.

 

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The borrowing base under our credit facility may be increased, (up to the credit facility maximum of $50.0 million) or decreased depending on the value of our reserves. Borrowing base redeterminations are performed by the lender every six months based on our June and December reserve reports. We also have the ability to request a borrowing base redetermination at another period, once a year. The facility matures January 28, 2017. The interest rate is LIBOR plus 3.75% or approximately 4.02% for the quarter March 31, 2016. This increased to LIBOR plus 6% following the extension in the facility.

 

The credit facility includes the following covenants, tested on a quarterly basis:

·Current ratio greater than 1
·Debt to EBITDAX (annualized) ratio no greater than 5.75 for the quarter ended March 30, 2016 through to September 30, 2016 reducing to 4.00 by September 30, 2017
·Senior leverage ratio of no greater than 4.25 to 1 for the quarter ended June 30, 2016 reducing to 3.75 for the quarter ending December 31, 2016 and thereafter
·Interest coverage ratio minimum of between 2.5 and 1.0

 

As at March 31, 2015 we were in breach of our debt to EBIDTAX covenant. We received a waiver from our primary lender with respect to this breach for this quarter only. We were in compliance with all other covenants.

 

We were in compliance with all of our covenants as at June 30, 2015.

 

As at September 30, 2015 we were in breach of our Debt to EBITDAX and interest coverage ratio covenants. We received a waiver from our primary lender with respect to these covenants for this quarter only.

 

As at December 31, 2015 we were in breach of our Debt to EBITDAX and interest coverage ratio covenants. We received a waiver from our primary lender with respect to these covenants for this quarter only.

 

As at March 31, 2016 we were in breach of our Debt to EBITDAX and interest coverage ratio covenants. We have requested a waiver from our primary lender with respect to these covenants for this quarter only.

 

If the current pricing environment does not improve it will difficult to maintain compliance with covenants based our current debt levels. If we are not in compliance with the financial covenants in the credit facility, or if we do not receive a waiver from the lender, and if we fail to cure any such noncompliance during the applicable cure period, the due date of our debt could be accelerated by the lender. In addition, failure to comply with any of the covenants under our credit facility could adversely affect our ability to fund ongoing operations.

 

We incurred $0.6 million in borrowing costs (including legal fees and bank fees) in connection with the establishment of this facility which have been deferred and are being amortized over the life of the facility.

 

11. Derivatives

 

The Company has not designated any of its derivative contracts as hedges for accounting purposes. The Company records all derivative contracts at fair value. Changes in derivative contracts are recognized in earnings. Changes in settlements and valuation gains and losses are included in loss/(gain) on derivative instruments in the Statement of Operations. These contracts are settled on a monthly basis. Derivative assets and liabilities arising from the Company’s derivative contracts with the same counterparty that provide for net settlement are reported on a net basis in the Balance Sheet.

 

The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil. The Company seeks to manage this risk through the use of commodity derivative contracts These derivative contracts allow the Company to limit its exposure to commodity price volatility on a portion of its forecasted oil sales. At December 31, 2015, the Company’s commodity derivative contracts consisted of collars and fixed price swaps, which are described below:

 

CollarCollars contain a fixed floor price (put) and fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from the either party.

 

Fixed price swapThe Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

 

All of the Company’s derivative contracts are with the same counterparty (a large multinational oil company) and are shown on a net basis on the Balance Sheet. The Company’s counterparty has entered into an inter-creditor agreement with the Company’s primary lender, and as such, no additional collateral is required by the counterparty.

 

During the quarter ended March 31, 2016 we recognized $358,514 in loss on derivative instruments in the Statement of Operations.

 

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During the quarter ended March 31, 2016 we closed out our previous hedge positions and added new hedges. We added collars and fixed swaps for both oil and gas for the two year period from April 2016 to May 2018, in line with the requirements of our amended credit facility with Mutual of Omaha Bank. A portion of these hedges had deferred premiums associated with them. These deferred premiums are included in the mark to mark value of our hedges recorded in the Balance Sheet.

 

At March 31, 2016 the Company’s open derivative contracts consisted of the following:

 

Collars                      
Product  Start Date  End Date  Volume   Floor   Ceiling   Deferred Premium 
WTI  1-May-16  30-Apr-18   147,462    41.50    63.00    (506,242)
Henry Hub  1-May-16  31-Oct-16   192,029    1.90    2.40    - 
Henry Hub  1-Nov-16  31-Mar-17   134,088    2.60    3.35    (17,431)
Henry Hub  1-Apr-17  31-Oct-17   167,682    2.40    2.91    - 
Henry Hub  1-Nov-17  30-Apr-18   127,030    2.80    3.60    (24,135)
                         (547,808)

 

Costless Swaps                      
                       
Product  Start  End  Volume (BO)   Swap         
WTI  1-May-16  31-Dec-16   113,925    41.20           
WTI  1-Jan-17  31-Dec-17   141,255    44.09           
WTI  1-Jan-18  30-Apr-18   39,720    45.55           

 

Oil Price Collars - WTI  Volumes (Bbls)   Sub Floor US$   Floor US$   Ceiling US$ 
April 2016   3,000    -    67.50    82.50 
April 2016   2,250    40.00    55.00    80.00 

 

12. Subsequent Events

 

Although the acquisition of the Foreman Butte project was completed on March 31, 2016, the settlement of the payment to the vendor and the drawdown of the additional debt under our credit facility did not occur until April 1, 2016. The impact of this acquisition has been included in the financial statements as at March 31, 2016 based on our preliminary acquisition accounting. We are still reviewing this accounting and expect to make changes to this in the Form 10-K for the 12 months ended June 30, 2016. The acquisition had a $16 million purchase price, subject to customary adjustments. On December 31, 2015 we paid a deposit of $0.5 million for this acquisition to the vendor. The remaining purchase price was funded through an extension to our current credit facility of $11.5 million and a further $4.0 million in vendor financing. Further details with the respect to our credit facility can be found in Note 10. The vendor financing of $4.0 million accrues 10% interest and is payable prior to March 31, 2017. We expect to file a Form 8-K with respect to this transaction prior to June 15, 2016.

 

As announced in a Form 8-K filed on April 12, 2016 we issued 378,020,400 ordinary shares at $0.0037 per ordinary share to raise gross proceeds of $1,398,675.

 

Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

The following is management’s discussion and analysis of certain significant factors that have affected aspects of our financial position and the results of operations during the periods included in the accompanying Condensed Financial Statements. You should read this in conjunction with the discussion under “Management's Discussion and Analysis of Financial Condition and Results of Operations” and the audited Financial Statements for the year ended June 30, 2015, included in our Annual Report on Form 10-K and the Consolidated Financial Statements included elsewhere herein.

 

Throughout this report, a barrel of oil or Bbl means a stock tank barrel (“STB”) and a thousand cubic feet of gas or Mcf means a thousand standard cubic feet of gas (“Mscf”).

 

Overview

 

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties.  Our strategy is to focus on the exploration, exploitation and development of our major oil plays – the Niobrara, Permian and Pennsylvanian in Goshen County, Wyoming and the Bakken in Williams County, North Dakota.   In March we closed on an acquisition (the “Foreman Butte Acquisition”) of certain assets located in North Dakota and Montana, which we refer to as the “Foreman Butte Project,” for a purchase price of $16 million. The acquired assets consist of producing oil and gas wells, shut in wells and associated facilities. The wells are located in the Madison and Ratcliffe formations. The majority of these wells will be operated by us, however there are a number of non-operated wells also included in this package. We have been approved as operator of record by the Montana Board of Oil and Gas Conservation effective May 1, 2016 for the locations in Montana. We are still waiting on approval from the North Dakota Industrial Commission for locations in North Dakota. We expect to receive this by June 1, 2016.

 

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Our net oil production was 41,927 barrels of oil for the quarter ended March 31, 2016 (excluding the impact of acquired production), compared to 63,750 barrels of oil for the quarter ended March 31, 2015.  The decrease in oil production was due to the natural decline in production witnessed in Bakken wells.

 

Our net gas production was 92,399 Mcf for the quarter ended March 31, 2016, compared to 75,615 Mcf for the quarter ended March 31, 2015. The increase in gas production is due to gas capture facilities being built on more well locations over the prior 12 months.

 

Our net oil production was 154,156 barrels of oil for the nine months ended March 31, 2016 compared to 142,272 barrels of oil for the nine months ended March 31, 2015. The increase in oil production is due to new wells commencing production in our North Stockyard project during the year ended June 30, 2015.

 

Our net gas production was 271,469 Mcf for the nine months ended March 31, 2016, compared to 159,466 Mcf for the nine months ended March 31, 2015.

 

For the three months ended March 31, 2016 and March 31, 2015, we reported a net loss of $1.3 million and a net loss of $1.9 million, respectively. The loss in the current period reflects a $0.9 million in depletion, amortization and impairment while the loss in the prior period reflects a $2.2 million depletion, amortization and impairment expenditure. See “Results of Operations” below.

 

For the nine months ended March 31, 2016 and March 31, 2015, we reported a net loss of $18.1 million and a net loss of $15.5 million, respectively. The loss in the current period reflects a $4.2 million in exploration expenditure and impairment expense of $9.9 million while the loss in the prior period reflects a $3.6 million of impairment expenditure and $11.6 million in write off of previously capitalized exploration expenditure. See “Results of Operations” below.

 

In the execution of our strategy, our management is principally focused on economically developing additional reserves of oil and on maximizing production levels through exploration, exploitation and development activities on a cost-effective basis.

 

Notable Activities and Status of Material Properties during the Quarter and Nine Months Ended March 31, 2016 and Current Activities

 

Acquisition: Producing Properties

Foreman Butte Project, McKenzie County, North Dakota

Mississippian Madison Formation, Williston Basin

Samson 87% Operated Average Working Interest

On March 31st, we closed on the acquisition of 51,305 net acres of oil and gas leases, producing oil and gas wells, currently shut-in wells and associated facilities in North Dakota and Montana for a cash price of $16.0 million. The properties produced approximately 720 BOPD from 41 net producing wells, based on pre-acquisition data. Netherland Sewell & Associates have estimated that the properties contain Proved Reserves of 8.5 million barrels of oil with a Net Present Value of $84.9 million as at October 1st, 2015, the effective date of the transaction.

 

The 51,305 net acres of petroleum leases that were acquired include the right to exploit hydrocarbons down to the top of the Bakken Formation. For a portion of the leases, we are also acquiring the rights to the deeper geologic section below the Bakken pool. The properties have been in production for several years and represent production from various geologic horizons above the Bakken Formation, including the Ratcliffe and Mission Canyon intervals of the Mississippian Madison Formation which provide conventional oil and gas accumulations in this region. The properties have largely been developed using 640 acre horizontal wells or 40 acre vertical wells. With the current lower oil service costs, we envisages development of the acquired PUD locations by using longer laterals, infilling the historical 640 acre wells or developing 40 acre infills adjacent to existing or known production.

 

Our immediate focus, however, will be on the 18 wells in the PDNP category, since we expect that these wells can be bought back on line with minimal capital expenditure of $500,000. If certain wells are not brought back on line in a timely fashion we may face plugging liabilities for these wells earlier than we currently have planned. We also sees additional upside using an acid-based stimulation of the existing PDP and PDNP wells in light of the reservoir’s calcium carbonate-based architecture. No stimulation of these reservoirs has ever been undertaken but this style of stimulation treatment has resulted in a 4-10 times uplift in production rates in other wells in the region, thought there can be no guarantee that we will achieve the same level of success.

 

We are still finalizing our acquisition accounting for this project. This will be completed prior to the finalization of the June 30, 2016 10-K.

 

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Undeveloped Properties: Exploration Activities

 

Hawk Springs Project, Goshen County, Wyoming

Permo-Penn Project, Northern D-J Basin

Samson 37.5% working interest

 

We have two contiguous areas in the Hawk Springs Project. One of the areas is a joint venture with a private company and is subject to a joint venture with Halliburton Energy Services, Inc.

 

The Bluff Prospect was drilled in June 2014 to test multiple targets in the Permian and Pennsylvanian sections in a 4-way structural trapping configuration. The Bluff #1-11 well reached a total depth of 8,900 feet after intersecting the pre-Cambrian basement. Various oil shows were observed in the Cretaceous, Jurassic, Permian, and Pennsylvanian intervals while drilling. The Permian target zone (from 7738 feet to 7756 feet) exhibited excellent porosity (29% density porosity). Detailed analysis of the Permian target zone proved that it was the source of the nitrogen gas that was seen while drilling the well. The presence of nitrogen in the Permian target zone validates the trap in the Bluff prospect and has the potential to host an oil leg below the gas cap. This data led the partners to make the decision to complete the Permian target sand.

 

The Permian target sand was flow tested at a rate of 8 MMcf/D on a 21/64 inch choke during a 40 hour flow test and then shut-in for a 10 day build-up using down-hole gauges. The buildup data has determined that the original reservoir pressure within the 9500 foot sand is 3,459 pounds per square inch. A chromatographic analysis of the gas samples indicated that the majority of the gas was composed of nitrogen (97.5%), with some helium (0.15%), carbon dioxide (0.15%), and the rest hydrocarbons (2.2%). A pressure transient analysis has confirmed that the 9500 foot sand is highly permeable and also identified a movable fluid boundary (oil or water) downdip of the well. Isotope Geochemistry analysis of the gas samples, has identified the source of the nitrogen, which is from a post-mature organic kerogen in the black shales of the Pennsylvanian section. The hydrocarbons in the samples are mixed thermogenic post mature gases generated in the wet gas/condensate window. All of the gathered evidence supports the theory that the fluid below the gas cap is likely to be oil. The gas-fluid interface has been identified through the integration of the pressure transient test data with newly processed inverted seismic data.

 

We concluded our extended flow test on the Bluff #1-11 well. The Permian Hartville sand (from 7738 feet-7756 feet) produced 1.2 BCF of nitrogen gas during a 100 day flow test. The goals of the test were to determine the reservoir drive mechanism and the type of fluid (oil or water, which was identified from the pressure transient analysis and seismic inversion data) beneath the nitrogen gas cap. From the pressure transient analysis data, we forecasted that it would take another year and half before the water or oil leg could be seen at the well. The gas/fluid contact moved 180 feet over the 100 day flow test period and would have to move another 420 feet to eventually reach the wellbore. Due to this lack of movement, we have continued to shut the well in to monitor the pressure build-up which can hopefully determine if there is any continuing fluid movement in the reservoir. We would expect to observe the pressure again during the quarter ended June 30, 2016. If the pressure builds back up to the original bottom hole pressure, we may be able to determine that the drive mechanism is an active water drive at which point it may be worth opening the well up again to flow and look for an oil leg. If the bottom hole reservoir pressures remain low after the build-up, the Permian Hartville zone will be abandoned and additional recompletions will occur in the uphole zones where other hydrocarbon shows were observed.

 

Following the continued degradation in the oil price, $1.4 million, representing all current costs associated with this well were written off during the quarter ended December 31, 2015. The review of the pressure buildup is expected to be completed by mid-year 2016 however additional costs are not expected to be incurred with respect to this well unless a sustained recovery in the oil price is observed.

 

Spirit of America US34 #2-29 well

Samson 100% Working Interest

In an effort to establish continuous production from the Muddy Formation, the tubing in the SOA 1-29 well was perforated 120 feet above the packer in September 2015 in order to establish tubing and casing annulus communication. Two feet of perforations (7650 feet -7652 feet) were shot with four shots per foot (eight shots fired in all). During October 2015, the well underwent a swabbing operation to remove a full column of fluid from the wellbore to allow the well to flow freely. Subsequent to this operation, the well failed to produce economic quantities of hydrocarbons and no further work is planned with respect to this well bore. $0.2 million in expense was written off to dry hole costs in relation to this well during the quarter ended September 30, 2015. Additional costs of $0.2 million were incurred during the quarter ended December 31, 2015 and have been written off to dry hole expense.

 

South Prairie Project, North Dakota

Mississippian Mission Canyon Formation, Williston Basin

Samson 25% working interest

 

Samson has a 25% working interest in 25,590 net acres located on the eastern flank of the Williston Basin in North Dakota. The first well of the project, the Matson #3-1 well was drilled and determined to be a dry hole and was plugged and abandoned in the prior year

 

In June 2015, we elected to participate in our proportionate 25% working interest in 900 net acres in the Birch prospect. The target zone is the Wayne zone of the Mississippian Mission Canyon Formation to be found at an expected depth of 4,800 feet, measured depth.  We participated at our proportionate 25% working interest in the drilling of the Badger #1 well in Section 29 of Township 157N, Range 81W in Ward County, North Dakota. The well was drilled to a depth of 4,900 feet in 7 days for the total cost of approximately $350,000 (our share is approximately $90,000). The prospect was identified as a 375 acre 4-way structural closure on the South Prairie 3-D seismic survey. Approximately 30 feet of structural closure relief was interpreted. The targeted porosity zone of the Mississippian Mission Canyon Formation was found at a depth of 4,774 feet MD, which was 55 feet structurally high to the offsetting Anschutz Helseth #1 well and 36 feet high to the offsetting Apache Corporation’s Ward Estate #1-29 well proving the existence of the 4-way structural closure. However, low resistivity readings, a lack of oil shows, and calculated high water saturations (>80%) indicate the targeted reservoir is non-productive. Hence, the decision was made to plug and abandon the well.

 

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This well was drilled in October 2015 and $0.1 million in costs was expensed to dry hole costs during the quarter ended December 31, 2015.

 

Cane Creek Project, Grand & San Juan Counties, Utah

Pennsylvanian Paradox Formation, Paradox Basin

Samson 100% Working Interest

 

On November 5, 2014, we entered into an Other Business Arrangement (“OBA”) with the Utah School and Institutional Trust Lands Administration (“SITLA”) covering approximately 8,080 gross/net acres located in Grand and San Juan Counties, Utah, all of which are administered by SITLA. We were granted an option period for two years in order to enter into a Multiple Mineral Development Agreement (“MMDA”) with another company who hold leases to extract potash in an acreage position situated within our project area. In November 2015, we paid an extension fee of $40,000 in order to extend the option period to December 2016. Subsequently, the MMDA has been finalized and is awaiting signature by both parties. Upon entering into the MMDA, SITLA is obligated to deliver oil and gas leases covering our project area at cost of $75 per acre to us.

 

This acreage is located in the heart of the Cane Creek Clastic Play of the Paradox Formation along the Cane Creek anticline. The primary drilling objective is the overpressured and oil saturated Cane Creek Clastic interval. Keys to the play to date include positioning along the axis of the Cane Creek anticline and exposure to open natural fractures. The 3-D seismic is currently being designed to image these natural fractures. The seismic shoot was surveyed and permitted this past summer. We believe this project has the potential to provide very robust economics in a low priced oil environment using the evidence obtained from a nearby competitor well that has produced 802,967 BO in just over two years.

 

Developed Properties: Drilling Activities

 

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Bakken & Three Forks infill wells

Samson ~25-30% working interest

 

On January 1, 2013, we and the operator group negotiated a non-cash acreage swap for the Middle Bakken/First Bench of the Three Forks (MB/TF), whereby we traded certain interests in our undeveloped acres in the Southern Tier for these parties’ undeveloped acres in the Northern Tier. As a result of this acreage swap we owned 64% and 57%, respectively, in the two overlapping 1,280 acre spacing units located in the Northern Tier. Our net production from current producing wells was not affected. In August 2013, we divested half our equity position in the undeveloped acreage in the North Stockyard project to Slawson Exploration Company Inc. (“Slawson”) for $5.562 million in cash and other consideration while retaining our full interest in the currently producing wells in the North Stockyard field. Slawson is now the operator of the Northern Tier acreage.

 

Due to high hydrogen sulphide content in the well, the Harstad well was plugged and abandoned during the current quarter ended September 30, 2015.

 

We have 22 wells in this field with all wells currently producing.

 

Rainbow Project, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson 23% and 52% working interest

 

In 2013, we acquired 656 acres in a 1,255 acre drilling unit and 294 acres in a 1,280 acre drilling unit. Both drilling units are located in the Rainbow Project, Williams County, North Dakota. The Rainbow Project is located in Sections 17, 18, 19 and 20 in T158N R99W.

 

Samson acquired the net acres in the Rainbow Project from the vendor as part of an acreage trade and is obligated provide a $1 million carry (10% of expected costs to drill and complete the first well) to the vendor, for the first development well to be drilled in the Rainbow Project.

 

Samson has assessed the project based on offset well data and believes that the project will support 16 wells, 8 in the middle Bakken and 8 in the first bench of the Three Forks. These wells would be expected to be configured as north-south orientated 10,000 foot horizontals.

 

In the western drilling unit of the acquired acreage, Samson holds a 52% working interest. In the eastern drilling unit, Samson’s interest is 23%. Continental Resources has been designated as Operator, due to their larger working interest.

 

The first well in this project area, the Gladys 1-20H well (23% working interest), was drilled and completed in January 2014. During the quarter the Gladys 1-20H well produced 11,858 barrels of oil (gross). Samson has no further drilling planned in this project area until there is a sustained recovery in the oil prices.

 

  18

 

 

Developed Properties: Production Activities

 

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson various working interests

 

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

 

They produce 93% of our total oil production and 84% of our total gas production for the March 2016 quarter.

 

Results of Operations

 

For the three months ended March 31, 2016, we reported a net loss of $1.3 million compared to a net loss of $1.9 million for the same period in 2015.

 

For the nine months ended March 31, 2016 we reported a net loss of $18.1 million compared to a net loss of $15.5 million for the same period in 2015.

 

 

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

 

   Three months ended 
   31-Mar-16   31-Mar-15   31-Dec-15 
Production Volume               
Oil (Bbls)   41,927    63,750    51,888 
Natural gas (Mcf)   92,399    71,188    93,332 
BOE (Barrels of oil equivalent - based on one barrel of oil to six Mcf of natural gas)   57,327    75,615    67,443 
                
Sales Price               
 Realized Oil ($/Bbls)  $22.91   $37.62   $36.58 
Impact of settled derivative instruments  $13.78   $9.69   $1.74 
Derivative adjusted price  $36.69   $47.31   $38.32 
                
Realized Gas ($/Mcf)  $1.69   $3.71   $2.25 
                
Expense per BOE:               
Lease operating expenses  $8.58   $12.97   $12.38 
Production and property taxes  $2.96   $4.30   $4.16 
Depletion, depreciation and amortization  $13.80   $21.94   $20.75 
General and administrative expense  $15.74   $15.23   $13.52 

 

 

   Nine months ended 
   31-Mar-16   31-Mar-15 
Production Volume          
Oil (Bbls)   154,156    142,272 
Natural gas (Mcf)   271,469    159,466 
BOE   199,401    168,850 
           
Sales Price          
Realized Oil ($/Bbls)  $34.26   $55.80 
Impact of settled derivative instruments  $4.46   $7.63 
   $38.72   $63.43 
           
Realized Gas ($/Mcf)  $2.15   $4.19 
           
Expense per BOE:          
Lease operating expenses  $13.76   $19.38 
Production and property taxes  $3.76   $5.96 
Depletion, depreciation and amortization  $18.43   $22.11 
General and administrative expense  $14.42   $21.46 

 

  19

 

 

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

 

   Three months ended   3Q16 to 3Q15   Three months ended   3Q16 to 2Q16 
   31-Mar-16   31-Mar-15   change   31-Dec-15   Change 
Oil sales  $960,705   $2,398,226   $(1,437,521)  $1,898,240   $(937,535)
Gas sales   156,333    263,823    (107,490)   210,212    (53,879)
Other liquids   9,580    -    9,580    27,201    (17,621)
Interest income   255    6,365    (6,110)   667    (412)
Gain on derivative instruments   -    371,852    (371,852)   200,017    (200,017)
Other   879,330    1,297    878,033    265    879,065 
                          
Lease operating expense   (661,394)   (1,306,117)   644,723    (1,102,441)   441,047 
Depletion, depreciation and amortization   (791,104)   (1,658,784)   867,680    (1,399,511)   608,407 
Impairment   (49,126)   (543,820)   494,694    (9,682,965)   9,633,839 
Abandonment expense   -    (11,868)   11,868    -    - 
Exploration and evaluation expenditure   (21,399)   (93,041)   71,642    (3,699,651)   3,678,252 
Accretion of asset retirement obligations   (15,353)   (9,186)   (6,167)   (15,116)   (237)
Interest expense   (207,650)   (176,415)   (31,235)   (196,357)   (11,293)
Loss on  derivative instruments   (358,514)   -    (358,514)   (196,357)   (162,157)
Amortization of borrowing costs   (35,485)   (35,063)   (422)   (35,486)   1 
Acquisition costs   (215,853)   -    (215,853)   -    (215,853)
General and administrative   (902,455)   (1,151,294)   248,839    (911,925)   9,470 
Net loss  $(1,252,130)  $(1,944,025)  $691,895   $(14,903,207)  $13,651,077 

 

Comparison of Quarter Ended March 31, 2016 to Quarter Ended March 31, 2015 and for the nine months ended March 31, 2016 and nine months ended March 31, 2015.

 

The completion of the acquisition of the Foreman Butte project has not had any material impact on the results for the quarter or the nine months ended March 31, 2016 as the transaction was closed on March 31, 2016. We anticipate filing a Form 8-K for this transaction prior to June 15, 2016.

 

Oil and gas revenues

 

Oil revenues decreased from $2.4 million for the three months ended March 31, 2015 to $1.0 million for the three months ended March 31, 2016, as a result of the decrease in the oil price and a decrease in oil production. Oil production decreased from 63,750 barrels for the three months ended March 31, 2015 to 41,927 for the three months ended March 31, 2016 due to natural decline associated with our wells, the majority of which are Bakken producers, which traditionally have a high decline rate in the first few years post drilling. The realized oil price also decreased from $37.62 per Bbl for the three months ended March 31, 2015 to $22.91 per Bbl (excluding the impact of derivatives) for the three months ended March 31, 2016 following a decrease in global oil prices.

 

Oil revenues decreased from $7.9 million for the nine months ended March 31, 2015 to $5.3 million for the nine months ended March 31, 2016, as a result of the decrease in the oil price. Oil production increased slightly from 142,272 barrels for the nine months ended March 31, 2015 to 154,159 for the nine months ended March 31, 2016. The slight increase in production is due to the impact of the development of our North Stockyard field which was completed during the year ended June 30, 2015. The realized oil price decreased significantly from $55.8 per Bbl for the nine months ended March 31, 2015 to $34.26 per Bbl (excluding the impact of derivatives) for the nine months ended March 31, 2016 following a decrease in global oil prices.

 

  20

 

 

Gas revenues decreased from $0.3 million for the three months ended March 31, 2015 to $0.2 million for the three months ended March 31, 2016. This decrease is due to a decrease in the realized gas price which has offset an increase in production for the three month period. Production increased from 71,188 Mcf for the quarter ended March 31, 2015 to 92,399 Mcf for the quarter ended March 31, 2016. The increase in production was due to the operators of our North Stockyard field being able to capture and sell a greater percentage of gas production following the installation of certain infrastructure improvements. The increase in production was offset by a decrease in the realized gas price which decreased from $3.71 per Mcf for the quarter ended December 31, 2014 to $1.69 per Mcf for the quarter ended March 31, 2016 due to a general decrease in the price of natural gas.

 

Gas revenues decreased slightly from $0.7 million for the nine months ended March 31, 2015 to $0.6 million for the nine months ended March 31, 2016. Production increased significantly from 159,466 Mcf for the nine months ended March 31, 2015 to 271,469 Mcf for the nine months ended March 31, 2016. The increase in production was due to the operators of our North Stockyard field being able to capture and sell a greater percentage of gas production following the installation of certain infrastructure improvements. The increase in production was offset by a decrease in the realized gas price which decreased from $4.19 per Mcf for the nine months ended March 31, 2015 to $2.15 per Mcf for the nine ended March 31, 2016 due to a general decrease in the price of natural gas.

 

Exploration expense

 

Exploration expenditures decreased slightly from $0.1 million for the quarter ended March 31, 2015, to $21,399 for the quarter ended March 31, 2016. Exploration costs in both periods relate to general exploration work and delay rentals payable to keep exploration leases alive. With the continued deterioration in the oil price, exploration expenditure has been significantly reduced. Leases have been let go as they expire or delay rentals not made causing the leases to expire.

 

Exploration expenditures decreased from $11.5 million for the nine months ended March 31, 2015, to $4.2 million for the nine months ended March 31, 2016. $0.1 million of the expenditure relates to the Badger well, drilled in our South Prairie prospect in North Dakota. This well was drilled in October 2015 and failed to produce hydrocarbons, therefore the costs associated with the well have been expensed in the quarter ended December 31, 2015. The remaining expenditure relates to costs written off associated with our Hawk Springs project in Goshen County, Wyoming.

 

Expenditure in the prior period relates previously capitalized exploration expenditure written off, primarily in relation to the Roosevelt project in Montana and the South Prairie project in North Dakota.

 

Impairment expense

 

During the three months ended March 31, 2016 we recognized $0.05 million in impairment expense compared to $0.5 million during the quarter ended March 31, 2015. The impairment recognized in the current quarter primarily relates to our Gladys well in the Rainbow field and is driven by the sustained decrease in the oil price seen in the past year. The impairment during the quarter ended March 31, 2015 relates additional asset retirement obligation recognized following the decreasing oil price.

 

During the nine months ended March 31, 2016 we recognized $10.0 million in impairment expense compared to $3.6 million in the nine months ended March 31, 2015. The impairment in the current period primarily relates to the impact of the falling oil price on the realized oil price for our production primarily from our North Stockyard field. The impairment in the prior period relates to our Rainbow field in North Dakota.

 

Abandonment expense

 

Abandonment expense decreased from $0.01 million for the three months ended March 31, 2015 to $nil for the three months ended March 31, 2016.

 

Abandonment expense decreased from $0.2 million for the nine months ended March 31, 2015 to $nil for the nine months ended March 31, 2016.

 

Lease operating expense

 

Lease operating expenses (LOE) decreased from $1.3 million for the quarter ended March 31, 2015, to $0.7 million for the quarter ended March 31, 2016. Costs per BOE have decreased from $12.97 for the quarter ended March 31, 2015 to $8.58 for the quarter ended March 31, 2016. Followed the continued deterioration in the oil price, a renewed focus on cost control has been implemented by the operators of our most significant wells, which are located in the North Stockyard Project in North Dakota.

 

Lease operating expenses decreased from $4.3 million for the nine months ended March 31, 2015, to $3.5 million for the nine months ended March 31, 2016. The slight increase in production has been offset by a decrease in LOE per barrel. Costs per BOE have decreased significantly from $19.38 for the nine months ended March 31, 2015 to $13.76 for the nine months ended March 31, 2016.

 

  21

 

 

Depletion, depreciation and amortization expense

 

Depletion, depreciation and amortization expense decreased from $1.7 million for the quarter ended March 31, 2015 to $0.8 million for the quarter ended March 31, 2016. The decrease in depletion is a result of the decrease in the production and a decrease in the depletion base, following the significant impairment expense recorded during the prior quarter. The per BOE cost decreased from $21.94 for the three months ended March 31, 2015 to $13.78 for the three months ended March 31, 2016.

 

Depletion, depreciation and amortization expense remained consistent at $3.7 million for the nine months ended March 31, 2015 and 2016. An increase in production was offset by a decrease in the cost per BOE from $22.11 for the nine months ended March 31, 2015 to $18.42 for the nine months ended March 31, 2016.

 

General and administrative expense

 

General and administrative expense decreased from $1.2 million for the quarter ended March 31, 2015 to $0.9 million for the quarter ended March 31, 2016. We have been actively trying to reduce our general and administrative costs in recent periods. Salaries were reduced by 15% for all employees effective September 1, 2015. We also reduced our staffing levels in light of the continued weakness in the global oil market. The decrease in general and administrative costs was offset by a decrease in production so that the per BOE costs increased slightly from $15.23 for the quarter ended March 31, 2015 to $15.74 for the quarter ended March 31, 2016.

 

General and administrative expense also decreased from $3.6 million for the nine months ended March 31, 2015 to $2.9 million for the nine months ended March 31, 2016. As a result of lower expense and increased production, general and administrative costs on a per BOE basis decreased from $21.46 for the nine months ended March 31, 2015 to $14.42 per BOE for the nine months ended March 31, 2016.

 

Cash Flows

 

The table below shows cash flows for the following periods: 

 

   Nine months ended 
   31-Mar-16   31-Mar-15 
Cash provided by operating activities  $623,853   $1,022,324 
Cash used in investing activities   (2,389,717)   (17,812,128)
Cash provided by financing activities   301,975    12,872,190 

 

Cash provided by operations decreased from a net inflow of $1.0 million for the nine months ended March 31, 2015, to a net inflow of $0.6 million for the nine months ended March 31, 2016. Cash receipts from customers decreased from $9.4 million for nine months ended March 31, 2015 to $8.5 million for the nine months ended March 31, 2016, due to a decrease in the realized oil price despite an increase in production. Payments to suppliers and employees also decreased from $8.8 million for the nine months ended March 31, 2015 to $7.4 million for the nine months ended March 31, 2016 following continued cost saving initiatives with respect to lease operating expenses and administrative costs.

 

Cash used in investing activities decreased from $17.8 million for the nine months ended March 31, 2015 to $2.4 million of cash used for the nine months ended March 31, 2016. The cash outflow for the prior period related to ongoing drilling activities in our North Stockyard project in North Dakota. The cash outflow in the current period relates to continued work in our North Stockyard field, though no new wells were drilled in this period. It also includes the $0.5 million non-refundable deposit paid to the seller in relation to our Foreman Butte Acquisition. The remaining cash purchase price for this acquisition was paid on April 1, 2016, and the promissory note issued to the seller is due April 1, 2017.

 

Cash provided by financing activities decreased from a cash inflow of $9.3 million for the nine months ended March 31, 2015 to $0.3 million for the nine months ended March 31, 2016. Cash inflow for the current period is $0.3 million in proceeds from borrowings from our credit facility. Cash inflow in the prior period is a result of the drawdown of borrowings from our credit facility with our primary lender.

 

All options outstanding as at March 31, 2016 are currently out of the money.

Liquidity, Capital Resources and Capital Expenditures

 

Our primary use of capital has been acquiring, developing and exploring oil and natural gas properties and we anticipate this will be our primary use of capital during fiscal 2016.  

 

Following the closing of our Foreman Butte Acquisition, our current budget for exploration, exploitation and development capital expenditures in fiscal 2016 is $3.5 million, of which we incurred approximately $2.3 million during the first nine months of the fiscal year. These expenditures were funded through our current cash on hand and cash generated from oil sales. We have additional workovers planned in our Foreman Butte Project following its acquisition.

 

  22

 

 

In January 2014, we entered into a $25.0 million credit facility with our primary lender, Mutual of Omaha Bank, with an initial borrowing base of $8.0 million, which was increased to $15.5 million in June 2014. In November 2014, the borrowing base was increased to $19.0 million, which was fully drawn prior to the closing of the Foreman Butte Acquisition. In March 2016, our credit facility was amended to increase the borrowing base to $30.5 million to partially fund the Foreman Butte Acquisition. An additional $4 million in financing was also provided by the seller. This promissory note is due April 1, 2017 and has a 10% interest rate. We are required under the amended credit agreement to repay Mutual of Omaha $10 million by June 30, 2016. As a result of the amendment of the credit facility, the interest rate has been increased to 6% plus the 90 day LIBOR or approximately 6.5% from 1 April 2016 onwards. The amendment to our credit facility also requires us to comply with additional restrictions, which are described below.

 

The borrowing base under our credit facility may be increased (up to the credit facility maximum of $50.0 million) or decreased in the future depending on the value of our reserves. Borrowing base redeterminations are performed by the lender every six months based on our June and December reserve reports. We also have the ability to request a borrowing base redetermination at another period, once a year. The facility matures January 28, 2017.

 

As a condition to providing financing for our Foreman Butte Acquisition, our primary lender required us to amend our credit agreement to include materially more restrictive terms. These new terms include: (1) more restrictive financial covenants (described below); (2) increases in the interest rate and unused facility fees; (3) a minimum hedging requirement of 75% of our forecasted production; (4) reducing annual G&A expenses from $6 million to $3 million; (5) raising an additional $5 million in equity on or before September 30, 2016; (6) paying down at least $10 million of the credit facility by June 30, 2016; and (7) a monthly cash flow sweep of 50% of our cash operating income. These amendments could make it materially more difficult to operate our business, and there can be no assurance that we will be able to remain in compliance with these covenants, particularly in the current oil price environment.

 

The credit facility includes the following covenants, tested on a quarterly basis:

·Current ratio greater than 1
·Debt to EBITDAX (annualized) ratio no greater than 5.75 for the quarter ended March 30, 2016 through to September 30, 2016 reducing to 4.00 by September 30, 2017
·Senior leverage ratio of no greater than 4.25 to 1 for the quarter ended June 30, 2016 reducing to 3.75 for the quarter ending December 31, 2016 and thereafter
·Interest coverage ratio minimum of between 2.5 and 1.0

 

For the quarter ended March 31, 2015 we were in breach of our Debt to EBITDAX covenant. Our primary lender has given us a waiver with respect to this breach for this quarter only. We were in compliance with all other covenants.

 

We were in compliance with all of our covenants for the quarter ended June 30, 2015.

 

As at September 30, 2015 we were in breach of our Debt to EBITDAX and interest coverage ratio covenants. We received a waiver from our primary lender with respect to these covenants for this quarter only.

 

As at December 31, 2015 we were in breach of our Debt to EBITDAX and interest coverage ratio covenants. We received a waiver from our primary lender with respect to these covenants for this quarter only.

 

As at March 31, 2016 we were in breach of our Debt to EBITDAX and interest coverage ratio covenants. We have requested a waiver from our primary lender with respect to these covenants for this quarter only.

 

The credit facility in the current period has been presented as a current liability. In previous periods (prior to the quarter ended September 30, 2015) the facility was presented as a non-current liability. Due to the continuing weakness in the global oil price, there is doubt as to whether or not we will be able to meet our future debt covenants. We are working with the bank to renegotiate our facility and extend its term. We will continue to ask for waivers on a quarterly basis as necessary; however there can be no guarantee they will be granted. If we do not receive a waiver from the lender, and if we fail to cure any such noncompliance during the applicable cure period, the due date of our debt could be accelerated by the lender. In addition, failure to comply with any of the covenants under our credit facility could adversely affect our ability to fund ongoing operations.

 

The funds drawn from our credit facility were used to fund drilling in our North Stockyard project in North Dakota and more recently, to partially fund the Foreman Butte acquisition.

 

Uncertainties relating to our capital resources and requirements include the effects of results from our exploration and drilling program and changes in oil and natural gas prices, either of which could lead us to accelerate or decelerate exploration and drilling activities. The aggregate levels of capital expenditures for our fiscal year ending June 30, 2016, and the allocation of those expenditures, are dependent on a variety of factors, including the availability of capital resources to fund the expenditures and changes in our business assessments as to where our capital can be most profitably employed. Accordingly, the actual levels of capital resources and expenditures and the allocation of those expenditures may vary materially from our estimates.

 

  23

 

 

We are continually monitoring the capital resources available to us to meet our future financial obligations, planned capital expenditure activities and liquidity.  Our future success in growing our proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring such additional productive reserves.

 

Our main sources of liquidity during the nine months ended March, 31, 2016 was cash on hand and cash flow from operations. We also drew down the remaining $301,000 from our primary lender in December 2015. This drawdown in part funded our non-refundable $500,000 deposit for our Foreman Butte Acquisition. During the current quarter we closed on our Foreman Butte Acquisition with funding provided by our primary lender under our credit facility and through seller financing. Although the acquisition closed on March 31, 2016 the cash payment was not made until April 1, 2016.

 

During the prior three fiscal years, our three main sources of liquidity were (i) borrowings under our credit facility, (ii) equity issued to raise $21.4 million and (iii) our tax refund of $5.6 million from the Internal Revenue Service, received in February 2013. During the years prior to the fiscal year ended June 30, 2012, our primary sources of liquidity were the sale of acreage and other oil and gas assets.

 

Our cash position as of March 31, 2016 decreased from June 30, 2015 largely due to payments for drilling and fracturing activities in our North Stockyard project in North Dakota, a deposit of $500,000 paid for our Foreman Butte Acquisition, cash collateral of $350,000 provided for state and federal bonds in order for us to continue operating oil and gas properties and lower oil and gas revenues due to lower commodity prices.

 

In April 2016, we issued 378,020,400 ordinary shares at $0.0037 per ordinary share to raise gross proceeds of $1,398,675.

 

In April 2016, we also received cash of $725,000 from Haliburton following the settlement of our legal dispute with them.

 

If future production rates are less than anticipated, and/or the oil price continues to deteriorate for an extended period, the value of our position in affected areas will decline, our results of operations, financial condition and liquidity will be adversely impacted and we could incur material write-downs of unevaluated properties. See the risk factors in our Annual Report on Form 10-K for the fiscal year ended June 30, 2015 including “Drilling results in emerging plays, such as our Hawk Springs and Roosevelt Projects, are subject to heightened risks.” and “Inadequate liquidity could materially and adversely affect our business operations.” See also Part II, Item 1A of this report below.

 

Looking Ahead

 

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

 

·Continued focus on cost savings and efficiency across all aspects of the Company including lease operating costs and general and administrative costs
·Continued focus on strengthening the balance sheet through an appropriate injection of capital
·The successful integration of the properties and assets acquired in the Foreman Butte Acquisition, and the review and workover of such assets;
·The continued appraisal of our Cane Creek project in the Paradox basin in Utah; and
·The continued search and appraisal of new development and exploration projects that add value to our current portfolio at lower oil prices
·Capital raising activities to satisfy our obligations to repay $10 million under our amended credit facility by June 30, 2016 and to raise an additional $5 million of equity by September 30, 2016
·Repayment of the $4 million promissory note issued to the seller in the Foreman Butte Acquisition
·Maintaining compliance with NYSE MKT listing standards

 

 

Our ability to meet these objectives will depend on our ability to raise additional capital to fund the planned development programs.

 

Item 3.   Quantitative and Qualitative Disclosures About Market Risk.

 

Not applicable.

 

Item 4.    Controls and Procedures.

 

As of March 31, 2016, 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, 2016, 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.  

 

  24

 

 

There were no changes in our internal control over financial reporting that occurred during the three months ended March 31, 2016, 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

 

Item 1.    Legal Proceedings.

 

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.

 

Halliburton Dispute

 

In March 2016 we settled our outstanding dispute with Halliburton. Under the settlement Haliburton agreed to pay Samson $725,000 and release Samson from its obligation to pay Haliburton $170,000 in revenue relating to its interest in the Defender well in Wyoming. Samson also agreed to forgive $18,000 in unpaid joint interest billings. The impact of these transactions was recognized in other income. This settlement ends this dispute.

 

Item 1A.   Risk Factors.

 

In addition to the risks described above and 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, 2015.  The risks disclosed herein and in our Annual Report on Form 10-K could materially affect our business, financial condition or future results.  The risks described herein and 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.

 

Inadequate liquidity could materially and adversely affect our business operations.

 

We have significant outstanding indebtedness under our credit facility with our primary lender. As of December 31, 2015, we had drawn $19 million of the $19 million borrowing base under our credit facility. Effective upon the closing of the Foreman Butte Acquisition, our primary lender agreed to amend our credit facility to increase our borrowing based to $30.5 million. We used all of the additional $11.5 million of the increased borrowing base to finance the Foreman Butte Acquisition, and we are currently unable to borrow additional amounts under the credit facility. The amendment to our credit facility also requires us to comply with additional restrictions, which are described below.

 

In addition to amounts outstanding under our credit facility, the seller in the Foreman Butte Acquisition financed an additional $4 million of the purchase price through a secured promissory note issued at closing. The Note has a 12-month term and bears interest at 10%. The Note is secured by a second-lien mortgage and security interest in substantially all of the acquired assets.

 

Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend upon our future operating performance and financial condition as well as our ability to refinance our current indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control.  We cannot assure you that our business will generate sufficient cash flows from operations, or that future borrowings will be available to us under our credit facility or otherwise, in an amount sufficient to fund our liquidity needs. In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems, and we might be required to seek additional debt or equity financing or to dispose of material assets or operations to meet our debt service and other obligations.  We cannot assure you that we would be able to raise capital through debt or equity financings on terms acceptable to us or at all, or that we could consummate dispositions of assets or operations for fair market value, in a timely manner or at all.  Furthermore, any proceeds that we could realize from any financings or dispositions may not be adequate to meet our debt service or other obligations then due.

 

Recent amendments to our credit agreement with our primary lender impose additional restrictions on our ability to operate our business and require us to meet additional financial and operational requirements.

 

As a condition to providing financing for our Foreman Butte Acquisition, our primary lender required us to amend our credit agreement to include materially more restrictive terms. These new terms include: (1) more restrictive financial covenants (including the debt-to-EBITDA ratio and minimum liquidity requirements); (2) increases in the interest rate and unused facility fees; (3) a minimum hedging requirement of 75% of our forecasted production; (4) reducing annual G&A expenses from $6 million to $3 million; (5) raising an additional $5 million in equity on or before September 30, 2016; (6) paying down at least $10 million of the credit facility by June 30, 2016; and (7) a monthly cash flow sweep of 50% of our cash operating income. These amendments could make it materially more difficult to operate our business, and there can be no assurance that we will be able to remain in compliance with these covenants, particularly in the current oil price environment.

 

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Our Foreman Butte Acquisition is subject to uncertainties, such as our ability to evaluate recoverable reserves and potential liabilities associated with the assets being acquired, and our ability to successfully integrate such assets with our current business.

 

The success of the Foreman Butte Acquisition depends upon our ability to assess a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues and potential environmental and other liabilities. Our assessment of such factors is based on production reports, engineering studies, geophysical and geological analyses and seismic and other information, the results of which are inexact and inherently uncertain. Though the assessments we conducted were generally consistent with industry practices, we may not have fully assessed all of the deficiencies and capabilities of the acquired properties. The success of the Foreman Butte Acquisition also depends on our ability to integrate the assets being acquired with our current business and to operate such assets for a profit. If we are not successful in achieving these objectives, the anticipated economic, operational and other benefits and synergies of the Foreman Butte Acquisition may not be realized fully or at all, which could result in substantial costs and delays or other operational, technical or financial problems. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce or eliminate the anticipated benefits of the acquisition.

 

A substantial number of the wells acquired in the Foreman Butte Acquisition are not currently producing or are shut-in.

 

Approximately 65 wells that we acquired in the Foreman Butte Acquisition are not currently producing or are shut-in. If we are unable to return these wells to production within 12 months, the North Dakota Industrial Commission (“NDIC”) may require us to permanently plug and abandon them. In addition, certain of the acquired wells were previously subject to a gas gathering agreement with ONEOK Rockies Midstream, LLC that was terminated on February 29, 2016. The seller in the Foreman Butte Acquisition entered into a thirty-day temporary agreement that expired on March 31, 2016, and we are in the process of negotiating a new long term gas gathering agreement for these wells. If we are unable to successfully negotiate a new gas gathering agreement or obtain an extension of the temporary gas gathering agreement, we will be forced to flare gas produced from certain of the acquired wells, which, in turn, may require us to shut-in part or all of these wells in order to comply with applicable NDIC anti-flaring regulations.

 

Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds.

 

Not applicable

 

Item 3.    Defaults Upon Senior Securities.

 

Not applicable.

 

Item 4.    Mine Safety Disclosures.

 

Not applicable.

 

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Item 5.    Other Information.

 

Not applicable.

 

Item 6.    Exhibits.

 

Exhibit No.   Title of Exhibit
     

31.1

 

Certification of the Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

     
31.2   Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
     
32.1   Certifications of the Principal Executive Officer and Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
     

101.INS

 

XBRL Instance Document

101.SCH   XBRL Taxonomy Extension Schema Document
101.CAL   XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF   XBRL Taxonomy Extension Definition Linkbase Document
101.LAB   XBRL Taxonomy Extension Label Linkbase Document
101.PRE   XBRL Taxonomy Extension Presentation Linkbase Document
     
    *Furnished herewith

 

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Signatures

 

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.

 

  SAMSON OIL & GAS LIMITED
   
Date:  May 16, 2016 By: /s/ Terry Barr
    Terence M. Barr
    Managing Director, President and Chief Executive Officer (Principal Executive Officer)
   
Date: May 16, 2016 By: /s/ Robyn Lamont
    Robyn Lamont
    Chief Financial Officer (Principal Financial Officer)

 

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