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, 2017

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 an emerging growth company. See definition of “accelerated filer,” “large accelerated filer” and “emerging growth company” in Rule 12b-2 of the Exchange Act (Check one):

 

Large accelerated filer ¨   Accelerated filer ¨
     
Non-accelerated filer ¨   Smaller reporting company x
(Do not check if a smaller reporting company)    
    Emerging growth company ☐

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ¨ No x

 

There were 3,283,000,444 ordinary shares outstanding as of May 12, 2017.

 

 

 

 

 

Table of Contents

 

SAMSON OIL & GAS LIMITED

FORM 10-Q

QUARTER ENDED March 31, 2017

 

TABLE OF CONTENTS

 

    Page
     
Part I — Financial Information 3
     
Item 1. Financial Statements (unaudited) 4
   
  Consolidated Balance Sheets, March 31, 2017 and June 30, 2016 4
   
  Consolidated Statements of Operations and Comprehensive Income (Loss) for the three months ended March 31, 2017 and 2016 and for the nine months ended March 31, 2017 and 2016 5
   
  Consolidated Statements of Changes in Stockholders’ Equity/(Deficit) for the nine months ended March 31, 2017 6
   
  Consolidated Statements of Cash Flows for the nine months ended March 31, 2017 and 2016 7
   
  Notes to  Consolidated Financial Statements (unaudited) 8
     
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 17
     
Item 3. Quantitative and Qualitative Disclosures About Market Risk 26
     
Item 4. Controls and Procedures 26
   
Part II   — Other Information 26
     
Item 1. Legal Proceedings 26
     
Item 1A. Risk Factors 26
     
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

  

 

i

2  

 

 

Table of Contents

 

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, the terms of our credit facility, our ability to and methods by which we may raise additional capital, production and future operating results, and the objectives outlined under the section “Looking Ahead” below.

 

In this quarterly report, the use of words such as “anticipate,” “continue,” “could,” “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; and

 

• climatic conditions.

 

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, if any, 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-17     30-Jun-16  
ASSETS                
CURRENT ASSETS                
Cash and cash equivalents   $ 2,083,227     $ 2,654,812  
Accounts receivable     1,594,459       1,996,415  
Prepayments     305,270       183,305  
Oil inventory     219,288       463,768  
Oil and gas properties held for sale     -       13,768,865  
Total current assets     4,202,244       19,067,165  
PROPERTY, PLANT AND EQUIPMENT, AT COST                
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment of $16,426,241 and $15,049,015 at March 31, 2017 and June 30, 2016, respectively     31,394,105       31,522,323  
Other property and equipment, net of accumulated depreciation and amortization of $671,164 and $573,995 at March 31, 2017 and June 30, 2016, respectively     326,275       308,474  
Net property, plant and equipment     31,720,380       31,830,797  
OTHER NON CURRENT ASSETS                
Undeveloped capitalized acreage     271,078       220,703  
Restricted cash - bonding     450,000       450,000  
Other     270,109       474,325  
TOTAL ASSETS   $ 36,913,811     $ 52,042,990  
                 
LIABILITIES AND STOCKHOLDERS’ EQUITY                
CURRENT LIABILITIES                
Accounts payable   $ 4,418,775     $ 4,125,643  
Accruals     172,576       1,629,975  
Fair value of derivative instruments     1,262,277       1,671,653  
Promissory Note     4,400,000       4,046,428  
Credit facility     19,902,557       11,500,000  
Provision for annual leave     250,204       194,497  
Total current liabilities     30,406,389       23,168,196  
NON CURRENT LIABILITIES                
Asset retirement obligations     3,472,786       3,450,245  
Fair value of derivative instruments     160,721       1,233,076  
Credit facility     -       19,000,000  
TOTAL LIABILITIES     34,039,896       46,851,517  
STOCKHOLDERS’EQUITY – nil par value                
3,283,000,444 (equivalent to 16,415,002 ADR’s) and 3,215,854,701 (equivalent to 16,079,273 ADR’s) ordinary shares issued and outstanding at March 31, 2017 and June 30, 2016, respectively     106,174,704       105,719,184  
Accumulated other comprehensive income     877,907       927,718  
Accumulated deficit     (104,178,698 )     (101,455,429 )
Total stockholders’ equity     2,873,913       5,191,473  
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY   $ 36,913,809     $ 52,042,990  

 

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-17     31-Mar-16     31-Mar-17     31-Mar-16  
REVENUES AND OTHER INCOME:                                
Oil sales   $ 2,942,564     $ 960,705     $ 9,690,287     $ 5,281,528  
Gas sales     136,430       156,333       344,708       583,292  
Other liquids     9,987       9,580       36,560       38,127  
Interest income     75       255       352       2,457  
Gain on derivative instruments     1,424,590       -       379,442       214,055  
Other     (174,923 )     879,330       1,625,194       897,232  
 TOTAL REVENUE AND OTHER INCOME     4,338,723       2,006,203       12,076,543       7,016,691  
                                 
EXPENSES:                                
Lease operating expense     (1,986,860 )     (661,394 )     (7,563,746 )     (3,492,564 )
Depletion, depreciation and amortization     (404,893 )     (791,104 )     (1,492,214 )     (3,674,347 )
Impairment expense     -       (49,126 )     (244,480 )     (9,852,113 )
Exploration and evaluation expenditure     (12,360 )     (21,399 )     (36,905 )     (4,214,118 )
Accretion of asset retirement obligations     (79,320 )     (15,353 )     (235,381 )     (45,357 )
Amortization of borrowing costs     (66,849 )     (35,485 )     (200,547 )     (106,457 )
Interest expense     (309,143 )     (207,650 )     (1,275,791 )     (594,046 )
Loss on derivative instruments     -       (358,514 )     -       -  
Acquisition costs     -       (215,853 )     -       (215,853 )
General and administrative     (1,284,076 )     (902,455 )     (3,750,748 )     (2,874,973 )
TOTAL EXPENSES     (4,143,501 )     (3,258,333 )     (14,799,812 )     (25,069,828 )
                                 
Income (Loss) from operations     195,222       (1,252,130 )     (2,723,269 )     (18,053,137 )
Income tax benefit     -       -       -       -  
Net income (loss)     195,222       (1,252,130 )     (2,723,269 )     (18,053,137 )
OTHER COMPREHENSIVE LOSS                                
Foreign currency translation loss     (39,535 )     (1,653 )     (49,811 )     (65,817 )
Total comprehensive gain/(loss) for the period   $ 155,687     $ (1,253,783 )   $ (2,773,080 )   $ (18,118,954 )
                                 
Net loss per ordinary share from operations:                                
Basic – cents per share     0.01       (0.04 )     (0.08 )     (0.64 )
Diluted – cents per share     0.01       (0.04 )     (0.08 )     (0.64 )
                                 
Weighted average ordinary shares outstanding:                                
Basic     3,282,861,876       2,837,834,301       3,248,624,375       2,837,830,689  
Diluted     3,282,861,876       2,837,834,301       3,248,624,375       2,837,830,689  

 

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/(Loss)     Deficit  
Balance at June 30, 2016   $ 105,719,184     $ (101,455,429 )   $ 927,718     $ 5,191,473  
Net loss     -       (2,723,269 )     -       (2,723,269 )
Foreign currency translation loss, net of tax of nil     -       -       (49,811 )     (49,811 )
Total comprehensive loss for the period     -       (2,723,269 )     (49,811 )     (2,773,080 )
Shares issued     3,811                       3,811  
Share based payments     488,944       -       -       488,944  
Cost associated with issue of equity     (37,235 )     -       -       (37,235 )
Balance at March 31, 2017   $ 106,174,704     $ (104,178,698 )   $ 877,907     $ 2,873,913  

 

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-17     31-Mar-16  
Cash flows (used in)/provided by operating activities                
Receipts from customers   $ 11,065,372     $ 8,482,172  
Payments to suppliers & employees     (9,912,808 )     (7,345,116 )
Interest received     347       2,444  
(Payments on)/proceeds from derivative instruments     (1,102,289 )     437,380  
Interest paid     (1,501,096 )     (603,027 )
Payments for bonding     -       (350,000 )
Net cash flows (used in)/provided by operating activities     (1,450,474 )     623,853  
Cash flows provided by/(used in) investing activities                
Proceeds from sale of oil and gas properties     13,932,512       -  
Payments for plant & equipment     (114,296 )     -  
Payments for exploration and evaluation     (86,963 )     (578,105 )
Payments for oil and gas properties     (2,216,713 )     (1,811,612 )
Net cash flows provided by/(used in) investing activities     11,514,540       (2,389,717 )
Cash flows (used in)/provided by financing activities                
Proceeds from the exercise of options     3,811       1,475  
Proceeds from borrowings     1,000,000       301,000  
Repayment of borrowings     (11,597,443 )     -  
Share issuance costs     (37,235 )     (500 )
Net cash flows (used in)/provided by financing activities     (10,630,867 )     301,975  
Net (decrease) in cash and cash equivalents     (566,801 )     (1,463,889 )
Cash and cash equivalents at the beginning of the fiscal period     2,654,812       2,062,720  
Effects of exchange rate changes on cash and cash equivalents     (4,784 )     (66,279 )
Cash and cash equivalents at end of fiscal period   $ 2,083,227     $ 532,552  

 

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, 2016. 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 June 30, 2016 and March 31, 2017 consist primarily of estimates for goods and services received but not yet invoiced.

 

Prepayments. Prepayments at June 30, 2016 and March 31, 2017 include insurance premiums and other subscription costs paid in advance for the year.

 

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.

 

Liquidity

These financial statements have been prepared on the going concern basis, which contemplates the continuity of normal business activities and the realization of assets and settlement of liabilities in the normal course of business.

 

As disclosed in the financial statements, we incurred losses of $2.8 million for the nine months ended March 31, 2017 and had cash outflows from operations of $1.5 million. As at March 31, 2017 we had net current liabilities of $26.2 million. Our ability to continue as a going concern is dependent on the renegotiation of our finance facilities and/or a partial or full monetization of our assets.

 

We have commenced refinancing discussions with our current lender and have also commenced discussion with an investment banker representing non-bank financing. Based on our current financial position we may be required to accept terms less favorable than would otherwise be available to us.

  

On May 9, 2017 we signed a Purchase and Sale Agreement to sell our State GC assets for $1.2 million. This is expected to close on or about May 24, 2017. The funds will be used to reduce our outstanding debt with Mutual of Omaha Bank, however our borrowing base will not be lowered allowing these funds to be redrawn if required.

 

Recent Accounting Standards

 

In August 2014, the FASB issued Accounting Standards Update (“ASU”) 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.

 

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606), which amends the existing accounting standards for revenue recognition. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance in ASU 2014-09 is now effective for annual reporting periods beginning after December 15, 2017, including interim periods therein, as a result of the FASB's recent decision to defer the effective date by one year. We are currently evaluating the method of adoption and impact this standard will have on our consolidated financial statements and related disclosures.

 

8  

 

 

2. Restatement of Quarterly Information (unaudited)

 

The Company took over operatorship of the Foreman Butte field in May and June of 2016.  This change necessitated a review of our accounts payable procedures.  During the course of this review we noted that the design of one of processes was no sufficient to adequately capture all invoices in a timely fashion.  The impact of this is stated below.  We have since revised and redesigned our accounts payable procedures and controls. 

 

We have assessed the impact on the financial statements included in the 10Q for the quarter ended December 31, 2016 and have concluded that the impact of this misstatement was no sufficient to warrant a notice of non-reliance on the financial statements to be issued.

  

The impact of the restatement for the three months and six months ended December 31, 2016 is below.

 

    Three months ended
Dec 31, 2016 		          Six months ended
Dec 31, 2016 		       
    As previously reported     LOE Adjustment     As restated     As previously reported     LOE Adjustment     As restated  
Total Revenue and Other Income   $ 4,873,142     $ -     $ 4,873,142     $ 8,782,967     $ -     $ 8,782,967  
Total Expenses     (6,709,625 )     (516,040 )     (7,225,665 )     (11,131,997 )     (516,040 )     (11,648,037 )
Loss     (1,836,483 )     (516,040 )     (2,352,523 )     (2,349,030 )     (516,040 )     (2,865,070 )
Income tax expense     -       -       -       -       -       -  
Net loss     (1,836,483 )     (516,040 )     (2,352,523 )     (2,349,030 )     (516,040 )     (2,865,070 )
                                                 
Net loss per ordinary share from operations                                                
Basic - cents per share     (0.06 )     (0.01 )     (0.07 )     (0.07 )     (0.02 )     (0.09 )
Diluted - cents per share     (0.06 )     (0.01 )     (0.07 )     (0.07 )     (0.02 )     (0.09 )

 

3. 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.    

 

4. 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-17     31-Mar-16     31-Mar-17     31-Mar-16  
Dilutive     -       -       -       -  
Anti–dilutive     411,033,246       322,400,133       246,930,682       320,615,486  

 

9  

 

 

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

 

    Three months ended     Nine months ended  
    31-Mar-17     31-Mar-16     31-Mar-17     31-Mar-16  
Net income (loss)   $ 195,222     $ (1,252,130 )   $ (2,723,269 )   $ (18,053,137 )
                                 
Basic weighted average ordinary shares outstanding     3,282,861,876       2,837,834,301       3,248,624,375       2,837,830,689  
Basic earnings/(loss) per ordinary share – cents per share     0.01       (0.04 )     (0.08 )     (0.64 )
Diluted earnings/(loss) per ordinary share – cents per share     0.01       (0.04 )     (0.08 )     (0.64 )

  

5. 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.

 

Liabilities settled during the period relate to wells in our Hawk Springs project area in Goshen County, Wyoming which were plugged and abandoned during the period ended December 31, 2016. Disposition of properties relates to the sale of our North Stockyard project in North Dakota, which also closed during the quarter ended December 31, 2016.

 

The following table summarizes the activities for the Company’s asset retirement obligations for the nine months ended March 31, 2017 and 2016:

 

    Nine months ended  
    31-Mar-17     31-Mar-16  
Asset retirement obligations at beginning of period   $ 3,750,245     $ 1,810,674  
Liabilities incurred or acquired     -       1,868,273  
Liabilities settled     (134,721 )     (46,322 )
Disposition of properties     (378,119 )     -  
Accretion expense     235,381       45,357  
Asset retirement obligations at end of period     3,472,786       3,677,982  
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)     -       (316,392 )
Long-term asset retirement obligations   $ 3,472,786     $ 3,361,590  

 

6. 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).

 

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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, 2017 and June 30, 2016.

 

    Carrying value at March 31, 2017     Level 1     Level 2     Level 3     Netting (1)     Fair Value at March 31, 2017  
Current Assets:                                                
Cash and cash equivalents   $ 2,083,227     $ 2,083,227     $ -     $ -     $ -     $ 2,083,227  
Derivative Instruments     -       -       43,297       -       (43,297 )     -  
                                                 
Non Current Assets                                                
Derivative Instruments     -       -       418,824       -       (418,824 )     -  
                                                 
Current Liabilities                                                
Derivative instruments     1,262,277       -       1,305,574       -       (43,297 )     1,262,277  
                                                 
Non Current Liabilities                                                
Derivative Instruments     160,721       -       579,545       -       (418,824 )     160,721  
                                                 

 

    Carrying value at June 30, 2016     Level 1     Level 2     Level 3     Netting (1)     Fair Value at June 30, 2016  
Current Assets:                                                
Cash and cash equivalents   $ 2,654,812     $ 2,654,812     $ -     $ -     $ -     $ 2,654,812  
Derivative Instruments     -       -       136,727       -       (136,727 )     -  
                                                 
Non Current Assets                                                
Derivative Instruments     -       -       220,317       -       (220,317 )     -  
                                                 
Current Liabilities                                                
Derivative instruments     1,671,653       -       1,808,380       -       (136,727 )     1,671,653  
                                                 
Non Current Liabilities                                                
Derivative Instruments     1,233,076       -       1,453,393       -       (220,317 )     1,233,076  

 

(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.

 

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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 June 30, 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 $11 million for the twelve months ended June 30, 2016, the majority of which related to our North Stockyard field due to the sustained decrease in the oil price.

 

Following the sale of our North Stockyard property in October 2016, we closed out 42,300 barrels of oil hedges and 220,750 mcf of natural gas hedges at a cost of $169,182 to us, including $165,003 in deferred premiums.

 

7. 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.

 

8. 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, 2017 we had capitalized exploration expenditures of $271,078. This amount primarily relates to costs incurred in connection with our Cane Creek project in Utah.

 

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.

 

9.  Share Capital

 

Issue of Share Capital  

During the three months ended March 31, 2017, 140,143 options with an exercise price of AUD$ 0.038 per ordinary share were exercised for net proceeds of AUD$5,325/US$3,811. On March 31, 2017 229,442,097 unexercised options expired.

 

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During the nine months ended March 31, 2017 the company issued 67,005,600 ordinary shares to employees and Directors of the company. These shares were issued in lieu of cash salaries for employees and directors during the period from August 1, 2015 to August 31, 2016. The share price on the grant was US$0.0035 per ordinary share.

 

No shares were issued during the three months ended March 31, 2016.

 

During the nine months ended March 31, 2016, 52,279 options with an exercise price of AUD$ 0.038 per ordinary share were exercised for net proceeds of AUD$1,986/US$1,475.

 

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

 

Issue of Warrants

During the nine months ended March 31, 2017 the company issued 272,000,000 warrants at no cost to employees and Directors of the company. The warrants have an exercise price of AUD$0.0055 and an expiry date of November 17, 2026. The options vest on November 17, 2017. The have been valued at AUD$0.0038 using a binomial option pricing model. The company also issued 48,000,000 warrants to Australian based employees and directors of the Company. These warrants have an exercise price of AUD$0.007, vest on November 17, 2017 and expire on November 27, 2026. The expense related to both warrants grants will be recognized over the vesting period. To date share based payments of $0.2 million has been recognized. A further $0.8 million will be recognized prior to the options vesting date, assuming all employees and directors remain with the company.

 

10. Cash Flow Statement

 

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

 

    Nine months ended  
    31-Mar-17     31-Mar-16  
             
Net loss after tax   $ (2,723,269 )   $ (18,053,137 )
Depletion, depreciation and amortization     1,492,214       3,674,347  
Accretion of asset retirement obligation     235,381       45,357  
Impairment expense     244,480       9,852,113  
Exploration and evaluation expenditure     36,905       4,214,118  
Amortization borrowing costs     200,547       106,457  
Non cash (gain)/loss on derivative instruments     (1,481,731 )     473,324  
Acquisition costs     -       215,853  
Net gain from sale of assets     (1,625,194 )     -  
Share based payments     560,607       -  
                 
Changes in assets and liabilities:                
                 
Decrease in receivables     401,956       1,623,775  
Increase/(decrease) in provision for annual leave     55,707       (23,998 )
Increase/(decrease) in payables     1,151,923       (1,504,356 )
NET CASH FLOWS(USED IN)/PROVIDED BY OPERATING ACTIVITIES   $ (1,450,474 )   $ 623,853  

  

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11. Credit Facility

 

    Nine months ended  
    31-Mar-17     31-Mar-16  
Credit facility at beginning of period   $ 30,500,000     $ 18,699,000  
Cash advanced under facility     1,000,000       301,000  
Cash committed to be advanced under facility     -       11,500,000  
Repayments     (11,597,443 )     -  
Credit facility at end of period (1)   $ 19,902,557     $ 30,500,000  
                 
Funds available for drawdown under the facility     97,443       -  

 

(1) The credit facility is recognized as a current liability as the facility is currently due for repayment in October 2017.

 

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 (as defined below). 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 were required under the amended credit agreement to repay Mutual of Omaha $10 million by June 30, 2016. This was ultimately increased to $11.5 million and extended to October 31, 2016. The pay down was achieved through the sale of our North Stockyard property for $14.95 million on October 28, 2016 and was made on October 31, 2016.

 

In May 2017, Mutual of Omaha agreed to repay our outstanding promissory note through a term note in addition to our current facility. This closed on May 5, 2017. Samson paid $0.45 million in interest from existing cash reserves, while Mutual of Omaha paid $4.0 million in principal.

 

As a result of this amendment to the credit facility the interest changed from being based on LIBOR to the Wall Street Journal published Prime Rate (“Prime”). The interest rate on the term loan is Prime plus 2.5% or approximately 6.5% and the credit facility is Prime plus 1.0% or 5%. Both facilities will mature on October 31, 2017.

 

As of November 10, 2016 our borrowing base was increased to $20 million by Mutual of Omaha Bank, of which $19.9 million has been drawn down. The additional borrowing base capacity has no additional restrictions on it.

 

The borrowing base under our credit facility may be increased (up to the credit facility maximum of $50.0 million, which would require syndication of the loan) 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.

 

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 (this was extended to November 15, 2016 and then effective November 10, 2016 Mutual of Omaha agreed that this requirement had been met following the $1.4 million capital raise completed in April 2016 and by the application of retained funds from the North Stockyard sale);
· A requirement to pay down at least $10 million of the loan by June 30, 2016 (which was increased to $11.5 million and extended to October 31, 2016 in line with the closing of the North Stockyard sale) and we repaid $11.5 million on October 31, 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. $0.1 million has been repaid under this covenant.

 

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

 

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As at March 31, 2017 we were in breach of our spending cap with respect to the general and administrative expenses. We have requested a waiver of this covenant.

 

We were in compliance with all other covenants as at March 31, 2017.

 

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 also must continue to improve our operations to address our working capital deficit.

 

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.

  

12. 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 March 31, 2017, the Company’s commodity derivative contracts consisted of collars and fixed price swaps, which are described below:

 

Collar Collars 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 swap  The 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 nine months ended March 31, 2017 we recognized $379,442 in gain on derivative instruments in the Statement of Operations.

 

Following the sale of our North Stockyard property in October 2016, we closed out 42,300 barrels of oil hedges and 220,750 mcf of natural gas hedges at a cost of $169,182 to us, including $165,003 in deferred premiums.

 

At March 31, 2017 the Company’s open derivative contracts consisted of the following:

 

Collars            
             
Product Start Date End Date Volume (BO/Mmbtu) Floor Ceiling  
WTI 1-Apr-17 30-Apr-18  46,691 41.50 63.00  
WTI 1-May-18 31-Dec-18  107,800 45.00 56.00  
Henry Hub 1-Apr-17 31-Dec-17  91,850 2.40 2.91  
Henry Hub 1-Jan-18 30-Apr-18  64,774 2.80 3.60  
Henry Hub 1-May-18 31-Dec-18  80,850 2.65 2.90  
             
             
Costless Swaps            
Product Start End Volume (BO) Swap    
WTI 1-Apr-17 31-Dec-17  118,422  44.09    
WTI 1-Jan-18 30-Apr-18  39,720  45.55    

 

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13. Subsequent Events

 

On May 5, 2017, the Company, the Company’s primary lender, Mutual of Omaha Bank and certain affiliates of the Company, including Samson Oil and Gas USA, Inc. (“Samson USA”) and Samson Oil and Gas USA Montana, Inc., executed a Sixth Amendment to Credit Agreement, dated as of May 5, 2017 (the “Amendment”). Under the Amendment, the Company obtained a term loan in the amount of $4,000,000 (the “Term Loan”) in addition to the Company’s current $20 million revolving credit line. The Term Loan is evidenced by a promissory note (the “Term Note”) delivered by the Company in favor of Mutual of Omaha Bank for the balance of the Term Loan. The Company’s revolving credit line remains substantially unchanged, although the interest rate has been amended to the prime rate as reported in The Wall Street Journal (rather than LIBOR) plus 1%. The Term Loan has an interest rate of prime plus 2.5%. The Term Loan was used to pay off the $4,000,000 promissory note payable to the vendor of the Company’s Foreman Butte properties. Both the Term Loan and the Company’s $20 million revolving credit line will mature on October 31, 2017.

 

On May 9, 2017, Samson USA entered into an agreement for the sale of 100% of Samson USA’s interest in the State GC Oil and Gas Field in Lea County, New Mexico (the “Purchase Agreement”). The purchase price is $1.2 million, subject to certain adjustments provided in the Purchase Agreement. The sale is to be effective as of May 1, 2017 and closing is expected to occur on or about May 24, 2017. The Purchase Agreement contains certain termination rights for both Samson USA and the purchaser, including the right of either party to terminate if the aggregate reduction to the purchase price as a result of environmental and title defects exceeds 20% of the purchase price.

 

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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, 2016, 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 Madison Group reservoirs in the Williston Basin in Williams and McKenzie Counties, North Dakota, and Roosevelt County in Montana.   Our principal exploratory play is located in the Paradox Basin in Utah.

 

In March 2016 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.

 

Our net oil production was 64,632 barrels of oil for the quarter ended March 31, 2017, compared to 41,927 barrels of oil for the quarter ended March 31, 2016.  The decrease in oil production as a result of the sale of our North Stockyard property was more than offset by the increase in production as a result of the Foreman Butte Acquisition.

 

Our net gas production was 58,209 Mcf for the quarter ended March 31, 2017, compared to 92,399 Mcf for the quarter ended March 31, 2016. Coupled with the decrease in production following our North Stockyard sale, one of our significant gas wells has been down since October 2016 while undergoing workover operations. It appears these workover operations have not been successful and the operator is recommending that this well be plugged and abandoned. We do not have an expected timetable for this operation as yet. Associated gas produced in the Foreman Butte project area is not as significant as the oil production, therefore the acquisition has not offset decline from the sale.

 

Our net oil production was 230,756 barrels of oil for the nine months ended March 31, 2017 compared to 154,156 barrels of oil for the nine months ended March 31, 2016. Production has increased as a result of our acquisition of the Foreman Butte project and our subsequent workover activity in this project area. This activity offset the decrease in production as a result of the sale of the North Stockyard property, which closed on October 29, 2016.

 

Our net gas production was 93,526 Mcf of gas for the nine months ended March 31, 2017 compared to 271,469 Mcf of gas for the nine months ended March 31, 2016. Coupled with the decrease in production following our North Stockyard sale, one of our significant gas wells has been down since October 2016 while undergoing workover operations. It appears these workover operations have not been successful and the operator is recommending that this well be plugged and abandoned. We do not have an expected timetable for this operation as yet. Associated gas produced in the Foreman Butte project area is not as significant as the oil production, therefore the acquisition has not offset decline from the sale of the North Stockyard project area.

 

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For the three months ended March 31, 2017 and March 31, 2016, we reported a net gain of $0.2 million and a net loss of $1.3 million, respectively. The small gain in the current period reflects $0.4 million in depletion and amortization and $1.4 million in gain on derivative instruments while the loss in the prior period reflects a $0.8 million in depletion, amortization and impairment.

 

For the nine months ended March 31, 2017 and March 31, 2016, we reported a net loss of $2.7 million and a net loss of $18.1 million, respectively. The loss in the current period reflects $1.5 million in depletion and amortization while the loss in the prior period reflects a $4.3 million in exploration expenditure and impairment expense of $9.9 million.

 

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 Ended March 31, 2017 and Current Activities

 

Acquisition: Producing Properties

Foreman Butte Project, McKenzie County, North Dakota

Mississippian Madison Formation, Williston Basin

Samson 87% Operated Average Working Interest

 

We are continuing with our workover operations to return several shut-in wells back to production in the Foreman Butte Project. A fluid-level/production efficiency study has been completed on all the wells in the field to optimize well pump efficiency. We have discovered that many of the wells have sub-performing pump stroke lengths and/or improperly sized pumping units as evidenced from high-fluid levels located inside the wells. Concurrently, a number of wells with behind-pipe pay zones have been identified as recompletion candidates.

 

During the current quarter, we commenced the first of the identified recompletion targets. The Davidson #1, a vertical wellbore in Williams County, was perforated in the Ratcliffe zone of the Madison formation. The initial 24 hour production rate after perforating was 64 BOP. Additional recompletions and well optimizations are scheduled for the upcoming quarter that may add to the production from this project.

 

Additionally, two new horizontal laterals are currently being planned to be drilled out of the Maris 1-16H wellbore this spring. The first will test the Ratcliffe Formation of the Mississippian Madison Group. The second will test the Mission Canyon Formation of the Mississippian Madison Group. The lateral in the Ratcliffe Formation will help define the pressure depletion radius from the existing producing wellbores which will ultimately determine the number of PUD’s (proven undeveloped drilling locations) we can drill in this reservoir. Third-party pressure modelling of the Ratcliffe reservoir shows that relatively high reservoir pressure resides approximately 500 feet away from the Maris 1-16 surface location. It is estimated that this new lateral could produce at around 300 BOPD if the third-party pressure modelling proves to be correct. The second lateral in the Mission Canyon Formation will test an undeveloped reservoir that could prove up a new oil field with the potential for many additional well locations. These are expected to be drilled in the third quarter of calendar 2017.

 

Undeveloped Properties: Exploration Activities

 

Hawk Springs Project, Goshen County, Wyoming

Permo-Penn Project, Northern D-J Basin

Samson 37.5% working interest

 

Following a delay due to bad weather in the latter part of 2016, the recompletion of the Bluff #1-11 well has been further delayed due to our current focus on more capital efficient projects in the Foreman Butte project area. The Jurassic Canyon Springs Formation will be perforated and flow tested first. If this is unsuccessful, the Cretaceous Dakota Formation will subsequently be perforated and flow tested. This well will be plugged and abandoned should these two operations be unsuccessful.

 

Spirit of America US34 #2-29 well

Samson 100% Working Interest

This well was plugged and abandoned during the second quarter of fiscal 2017.

 

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. In November 2016, we paid a further extension fee of $40,000 to extend the option period to December 2017.

 

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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. While we can make no assurances, we believe this project has the potential to provide robust economics in a low priced oil environment using the evidence obtained from a nearby competitor well that has produced 802,967 barrels of oil(“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

 

The sale of this project area was completed on October 28, 2016. The project was sold for $14.95 million.

 

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, we hold a 52% working interest. In the eastern drilling unit, our 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 6,448 barrels of oil (gross). We have no further drilling planned in this project area until there is a sustained recovery in the oil prices, however six additional wells could be drilled in the 1,280 acre unit.

 

Results of Operations

 

For the three months ended March 31, 2017, we reported a net gain of $0.2 million compared to a net loss of $1.3 million for the same period in 2016.

 

For the nine months ended March 31, 2017, we reported a net loss of $2.7 million compared to a net loss of $18.1 million for the same period in 2016.

 

The following tables set forth selected operating data for the three months and nine months ended:

 

    Three months ended  
    31-Mar-17     31-Mar-16  
Production Volume                
Oil (Bbls)     64,632       41,927  
Natural gas (Mcf)     58,209       92,399  
BOE (Barrels of oil equivalent - based on one barrel of oil to six Mcf of natural gas)     74,334       57,327  
                 
Sales Price                
 Realized Oil ($/Bbls)   $ 45.53     $ 22.91  
Impact of settled derivative instruments   $ (2.29 )   $ 13.78  
Derivative adjusted price   $ 43.23     $ 36.69  
                 
Realized Gas ($/Mcf)   $ 2.34     $ 1.69  
                 
Expense per BOE:                
Lease operating expenses   $ 22.93     $ 8.58  
Production and property taxes   $ 3.80     $ 2.96  
Depletion, depreciation and amortization   $ 5.45     $ 13.80  
General and administrative expense   $ 17.27     $ 15.74  

 

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    Nine months ended  
    31-Mar-17     31-Mar-16  
Production Volume                
Oil (Bbls)     230,756       154,156  
Natural gas (Mcf)     93,526       271,469  
BOE     246,344       199,401  
                 
Sales Price                
Realized Oil ($/Bbls)   $ 41.99     $ 34.26  
Impact of settled derivative instruments   $ (4.78 )   $ 4.46  
    $ 37.21     $ 38.72  
                 
Realized Gas ($/Mcf)   $ 3.69     $ 2.15  
                 
Expense per BOE:                
Lease operating expenses   $ 26.89     $ 13.76  
Production and property taxes   $ 3.81     $ 3.76  
Depletion, depreciation and amortization   $ 6.06     $ 18.43  
General and administrative expense   $ 15.23     $ 14.42  

 

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

 

    Three months ended     3Q17 to 3Q16  
    31-Mar-17     31-Mar-16     change  
Oil sales   $ 2,942,564     $ 960,705     $ 1,981,859  
Gas sales     136,430       156,333       (19,903 )
Other liquids     9,987       9,580       407  
Interest income     75       255       (180 )
Gain on derivative instruments     1,424,590       -       1,424,590  
Other     (174,923 )     879,330       (1,054,253 )
                         
Lease operating expense     (1,986,860 )     (661,394 )     (1,325,466 )
Depletion, depreciation and amortization     (404,893 )     (791,104 )     386,211  
Impairment     -       (49,126 )     49,126  
Exploration and evaluation expenditure     (12,360 )     (21,399 )     9,039  
Accretion of asset retirement obligations     (79,320 )     (15,353 )     (63,967 )
Interest expense     (309,143 )     (207,650 )     (101,493 )
Loss on derivative instruments     -       (358,514 )     358,514  
Amortization of borrowing costs     (66,849 )     (35,485 )     (31,364 )
Acquisition costs     -       (215,853 )     215,853  
General and administrative     (1,284,076 )     (902,455 )     (381,621 )
Income tax benefit     -       -       -  
Net loss   $ 195,222     $ (1,252,130 )   $ 1,447,352  

 

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    Nine months ended     3Q17 to 3Q16  
    31-Mar-17     31-Mar-16     change  
Oil sales   $ 9,690,287     $ 5,281,528     $ 4,408,759  
Gas sales     344,708       583,292       (238,584 )
Other liquids     36,560       38,127       (1,567 )
Interest income     352       2,457       (2,105 )
Gain on derivative instruments     379,442       214,055       165,387  
Other     1,625,194       897,232       727,962  
                         
Lease operating expense     (7,563,746 )     (3,492,564 )     (4,071,182 )
Depletion, depreciation and amortization     (1,492,214 )     (3,674,347 )     2,182,133  
Impairment     (244,480 )     (9,852,113 )     9,607,633  
Exploration and evaluation expenditure     (36,905 )     (4,214,118 )     4,177,213  
Accretion of asset retirement obligations     (235,381 )     (45,357 )     (190,024 )
Interest expense     (1,275,791 )     (594,046 )     (681,745 )
Amortization of borrowing costs     (200,547 )     (106,457 )     (94,090 )
Acquistion costs     -       (215,853 )     215,853  
General and administrative     (3,750,748 )     (2,874,973 )     (875,775 )
Net loss   $ (2,723,269 )   $ (18,053,137 )   $ 15,329,868  

 

Comparison of Quarter Ended March 31, 2017 to Quarter Ended March 31, 2016 and for the nine months ended March 31, 2017 to the nine months ended March 31, 2016.

 

Oil and gas revenues

Oil revenues increased from $1.0 million for the three months ended March 31, 2016 to $2.9 million for the three months ended March 31, 2017, as a result of the increase in the oil price and an increase in oil production. Oil production increased from 41,927 barrels for the three months ended March 31, 2016 to 64,632 for the three months ended March 31, 2017. This increase was due to our Foreman Butte Acquisition which was completed in April 2016. This project added 64,049 barrels of oil to our production total for the three months ended March 31, 2017 compared to nil for the three months ended March 31, 2016. This increase was offset by the decrease in production associated with the sale of the North Stockyard project which was completed on October 29, 2016. The North Stockyard field contributed 92% of the revenue during the quarter ended March 31, 2016 compared to nil for the quarter ended March 31, 2017.

 

The realized oil price also increased from $22.91 per Bbl for the three months ended March 31, 2016 to $45.53 per Bbl (excluding the impact of derivatives) for the three months ended March 31, 2017 following a recovery in the global oil price.

 

Oil revenues increased from $5.3 million for the nine months ended March 31, 2016 to $9.7 million for the nine months ended March 31, 2017, as a result of the increase in the oil price and an increase in oil production. Oil production increased from 154,156 barrels for the nine months ended March 31, 2016 to 230,756 for the nine months ended March 31, 2017. This increase was due to our Foreman Butte Acquisition which was completed in April 2016. This increase was offset by the decrease in production associated with the sale of the North Stockyard project which was completed on October 29, 2016. The North Stockyard field contributed 90% of the oil revenue for the nine months ended March 31, 2016 compared to 13% for the nine months ended March 31, 2017.

 

The realized oil price also increased from $34.26 per Bbl for the nine months ended March 31, 2016 to $41.99 per Bbl (excluding the impact of derivatives) for the nine months ended March 31, 2017 following a recovery in the global oil price.

 

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Gas revenues decreased from $0.2 million for the three months ended March 31, 2016 to $0.1 million for the three months ended March 31, 2017. Due to the timing associated with receiving gas revenue checks, approximately $0.1 million of gas revenue recognized in the March 2017 quarter, related to production periods prior to January 2017. The production associated with this revenue was 49,104 MCF.

 

This decrease in the revenue recognised for the current quarter is due to a decrease in gas production which has offset an increase in the realized gas price. Production decreased from 92,399 Mcf for the quarter ended March 31, 2016 to 58,209 Mcf for the quarter ended March 31, 2017. The decrease in production was primarily due to the sale of the North Stockyard project area which was completed on October 29, 2016. The Foreman Butte Acquisition has not added significantly to the gas production as the wells in the acquisition area do not have a high gas content. The decrease in production was offset by an increase in the realized gas price from $1.69 per Mcf for the quarter ended March 31, 2016 to $2.34 per Mcf for the quarter ended March 31, 2017.

 

Gas revenues decreased from $0.6 million for the nine months ended March 31, 2016 to $0.3 million for the nine months ended March 31, 2017. This decrease is due to a decrease in gas production which has offset an increase in the realized gas price. Production decreased from 271,469 Mcf for the nine months ended March 31, 2016 to 93,526 Mcf for the nine months ended March 31, 2017. The decrease in production was primarily due to the sale of the North Stockyard project area which was completed on October 29, 2016. The Foreman Butte Acquisition has not added significantly to the gas production as the wells in the acquisition area do not have a high gas content. The decrease in production was offset by an increase in the realized gas price which increased slightly from $2.15 per Mcf for the nine months ended March 31, 2016 to $3.69 per Mcf for the nine months ended March 31, 2016.

 

Sale of Assets

For the three months ended March 31, 2017 we recognized $0.2 million in sale costs following the completion of the post settlement reconciliation with the purchasers of the North Stockyard property. These expenses related to invoices received after the settlement of the sale but relating to time periods prior to the effective date of the sale.

 

For the nine months ended March 31, 2017, we recognized $1.6 million in income from sale of assets as a result of the sale of our North Stockyard property. As at the sale date, the value of the property was $13.7 million and $0.3 million in asset retirement obligation. The sale value of the property was $14.95 million and we recognized $1.6 million in income from sale of assets after taking into account costs associated with the sale.

 

Exploration expense

 

Exploration expenditures for the quarter ended March 31, 2017 and March 31, 2016 were less than $22,000 for either quarter.

 

Exploration expenditures decreased from $4.2 million for the nine months ended March 31, 2016, to $0.04 million for the nine months ended March 31, 2017. Exploration costs in the current period relate to general exploration expense. Exploration costs in the prior period related to previously capitalized exploration expenditure written off in relation to our Hawk Springs project in Wyoming and wells drilled in this project area. With the continued weak oil price, exploration expenditure has been significantly reduced. Leases have been let go as they expire or delay rental payments not made causing the leases to expire.

 

Impairment expense

 

During the three months ended March 31, 2016 we recognized $0.05 million in impairment expense compared to nil million during the quarter ended March 31, 2017. The impairment expense recognized in the prior quarter relates primarily to our Rainbow field and was driven by the sustained decrease in the oil price witnessed during the first quarter of 2016 calendar year.

 

During the nine months ended March 31, 2016 we recognized $9.8 million in impairment expense compared with $0.2 million in impairment expense for the nine months ended March 31, 2017. The impairment recognized in the current period relates to a write down in the value of oil inventory held on the balance sheet related to our accounting policy of the holding inventory at the lower of cost or net realizable value. The impairment recognized in the prior period relates mainly to our North Stockyard property and was a result of the sustained decrease in the global oil price.

 

Lease operating expense

 

Lease operating expenses (“LOE”) increased from $0.8 million for the quarter ended March 31, 2016, to $2.0 million for the quarter ended March 31, 2017. Costs per BOE, excluding the impact of the workovers and production taxes were $16.56 a barrel. Costs have increased from $8.58 for the quarter ended March 31, 2016 due to increased salt water disposal costs in our Foreman Butte project area. The wells in the Foreman Butte project area are also older wells than those we have previously owned and require additional fresh water and hot oil cleanouts which increase in the operating costs of the wells. We are continuing to review our lease operating expenses and will shut wells in that are not economic to produce in the current oil pricing environment. We are also reviewing our salt water disposals options in order to ensure we are minimizing costs.

 

Lease operating expenses increased from $3.5 million for the nine months ended March, 2016 to $7.6 million for the nine months ended March 31, 2017 for similar reasons to those disclosed above for the three months ended March 31, 2017. Costs per BOE have increased from $13.76 for the nine months ended March 31, 2016 to $26.89 for the nine months ended March 31, 2017. Excluding the impact of workovers, LOE and production taxes for the period ended March 31, 2017 was $21.52 per BOE.

 

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Depletion, depreciation and amortization expense

 

Depletion, depreciation and amortization expense decreased from $0.8 million for the quarter ended March 31, 2016 to $0.4 million for the quarter ended March 31, 2017. The decrease in depletion is a result of the increase in the reserve base over which depletion is calculated following the Foreman Butte Acquisition. The per BOE cost decreased from $13.8 for the three months ended March 31, 2016 to $6.12 for the three months ended March 31, 2017.

 

Depletion, depreciation and amortization expense decreased from $3.7 million for the nine months ended March 31, 2016 to $1.5 million for the nine months ended March 31, 2017. The decrease in depletion is a result of the increase in the reserve base over which depletion is calculated following the Foreman Butte Acquisition. Depletion has not been charged on the North Stockyard assets, as is customary when assets are held for sale. The per BOE cost decreased from $18.43 for the nine months ended March 31, 2016 to $6.06 for the nine months ended March 31, 2017.

 

General and administrative expense

 

General and administrative expense, excluding share based payments of $0.3 million, increased slightly from $0.9 million for the quarter ended March 31, 2016 to $1.0 million for the quarter ended March 31, 2017. We have been actively trying to reduce our general and administrative costs in recent periods. The BOE costs decreased slightly, excluding share based payments, from $15.74 for the quarter ended March 31, 2016 to $14.50 for the quarter ended March 31, 2017.

 

General and administrative expense, excluding share based payments of $0.6 million, increased from $2.9 million for the nine months ended March 31, 2016 to $3.2 million for the nine months ended March 31, 2017. We have been actively trying to reduce our general and administrative costs in recent periods. The slight increase in general and administrative costs has been offset on a per BOE basis by increased production. The BOE costs decreased, excluding share based payments, from $14.42 for the nine months ended March 31, 2016 to $12.95 for the nine months ended March 31, 2017.

 

Cash Flows

 

The table below shows cash flows for the following periods: 

 

    Nine months ended  
    31-Mar-17     31-Mar-16  
Cash (used in)/provided by operating activities   $ (1,450,474 )   $ 623,853  
Cash provided by/(used in) investing activities     11,514,540       (2,389,717 )
Cash used in/(provided by) financing activities     (10,630,867 )     301,975  

 

Cash provided by operations decreased from a net inflow of $0.6 million for the nine months ended March 31, 2016, to a net outflow of ($1.5 million) for the nine months ended March 31, 2017. Cash receipts from customers increased from $8.5 million for the nine months ended March 31, 2016 to $11.1 million for the nine months ended March 31, 2017, due to an increase in production and an increase in the realized oil price. Payments to suppliers and employees also increased from $7.4 million for the nine months ended March 31, 2016 to $9.9 million for the nine months ended March 31, 2017 following increased workover activity in our Foreman Butte project area. Payments for derivative instruments and interest expense increased significantly in the nine months ended March 31, 2017 compared to the nine months ended March 31, 2016. Payments for derivative instruments increased due to an increase in the oil price compared to the price of derivative instruments. Interest expense increased due to the higher value of the credit facility held during the nine months ended March 31, 2017 following the closing of the Foreman Butte project.

 

Cash used in investing activities decreased from $2.4 million for the nine months ended March 31, 2016 to inflow of $11.5 million for the nine months ended March 31, 2017 following the receipt of proceeds from the sale of our North Stockyard project area. The cash outflow for the prior period related to ongoing activities in our North Stockyard project in North Dakota. The cash outflow in the current period relates to continued work in Foreman Butte field.

 

Cash provided by financing activities decreased from a cash inflow of $0.3 million for the nine months ended March 31, 2016 to cash out of ($10.6 million) for the nine months ended March 31, 2017. Cash inflow for the prior period related to proceeds from the exercise of options. Cash out flow in the current period relates to repayments borrowings with respect to our credit facility with Mutual of Omaha Bank

 

All options outstanding as at March 31, 2017 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 the remainder of fiscal 2017.  

 

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Following the closing of our Foreman Butte Acquisition, our current budget for exploration, exploitation and development capital expenditures in fiscal 2017 is $3.0 million, of which we incurred approximately $2.2 million during the first nine months of the fiscal year. These expenditures were funded through our current cash on hand, cash generated from oil sales, net proceeds from the sale of our North Stockyard project and a drawdown of $1.0 million from our Mutual of Omaha credit facility. We have additional workovers planned in our Foreman Butte Project during the course of the year.

 

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 was paid off in May 2017. We were required under the amended credit agreement to repay Mutual of Omaha $10 million by June 30, 2016. This was ultimately increased to $11.5 million and extended to October 31, 2016. The pay down was achieved through the sale of our North Stockyard property for $14.95 million on October 28, 2016 and was made on October 31, 2016.

 

In May 2017, Mutual of Omaha agreed to repay our outstanding promissory note to the seller of the Foreman Butte Acquisition through a term note in addition to our current facility. This closed on May 5, 2017. Samson paid $0.45 million in interest from existing cash reserves, while Mutual of Omaha paid $4.0 million in principal.

 

As a result of this amendment to the credit facility the interest changed from being based on LIBOR to the Wall Street Journal published Prime Rate

 

The interest rate on the term loan is Prime plus 2.5% or approximately 6.5% and the credit facility is Prime plus 1.0% or 5%. Both facilities will mature on October 31, 2017.

 

As of November 10, 2016 our borrowing base was increased to $20 million by Mutual of Omaha Bank, of which $19.9 million has been drawn down. The additional borrowing base capacity has no additional restrictions on it.

 

The borrowing base under our credit facility may be increased (up to the credit facility maximum of $50.0 million, which would require syndication of the loan) 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.

 

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 (this was extended to November 15, 2016 and then effective November 10, 2016, Mutual of Omaha agreed that this requirement had been met following the $1.4 million capital raise completed in April 2016 and by the application of retained funds from the North Stockyard sale);
· A requirement to pay down at least $10 million of the loan by June 30, 2016 (which was increased to $11.5 million and extended to October 31, 2016 in line with the closing of the North Stockyard sale) and we repaid $11.5 million on October 31, 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. $0.1 million in repayments have been made under this covenant.

 

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, 2017 we were in breach of our spending cap with respect to the general and administrative expenses. We have requested a waiver with respect to this covenant.

 

We were in compliance with all other covenants as at March 31, 2017.

 

Our credit facility of $20 million has been recorded as a current liability and is due for repayment October 2017. We are working with the bank to renegotiate our facility and extend its term. We believe we will meet the covenants in the future, however if we do not 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.

 

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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, 2017, and the allocation of those expenditures, are dependent on a variety of factors, including the availability of capital resources to fund the expenditures and changes in our business assessments as to where our capital can be most profitably employed. Accordingly, the actual levels of capital resources and expenditures and the allocation of those expenditures may vary materially from our estimates.

 

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

 

Our main sources of liquidity during the three months ended March 31, 2017 were cash on hand and a drawdown of $1.0 million from our Mutual of Omaha Bank credit facility.

 

During the prior four 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, 2017 decreased from June 30, 2016 largely due to payments for recompletion and workover activities in our Foreman Butte project in North Dakota and Montana, coupled with significant payments for our derivative instruments and higher interest payments.

 

In October 2016, we closed on the sale of our North Stockyard project for $15.05 million. $11.5 million of this has been used to pay down our credit facility with Mutual of Omaha Bank. $0.2 million was used to close out a portion of our hedge positions to balance our hedge book following the sale of production. The remaining $3.35 million, including the $1.0 million deposit paid in June 2016, will be used for future working capital.

 

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 Halliburton 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 oil and gas properties. See the risk factors in our Annual Report on Form 10-K for the fiscal year ended June 30, 2016. See also Part II, Item 1A of this report below.

 

Off-Balance Sheet Arrangements

 

Since our inception, we have not engaged in any off-balance sheet arrangements, including the use of structured finance, special purpose entities or variable interest entities.

 

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 strong capital management;
· 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;
· The continued search and appraisal of new development and exploration projects that add value to our current portfolio at lower oil prices;
· Renegotiate our credit facility and extend its term; and
· Regaining and 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.

 

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Item 3.   Quantitative and Qualitative Disclosures About Market Risk.

 

Not applicable.

 

Item 4.    Controls and Procedures.

 

Control weakness – Accounts Payable processing

The Company took over operatorship of the Foreman Butte field in May and June of 2016.  This change necessitated a review of our accounts payable procedures.  During the course of this review we noted that the design of one of processes was no sufficient to adequately capture all invoices in a timely fashion.  The impact of this is stated in Note 2.  As such, we have concluded that this control was not operating effectively for the quarter ended March 31, 2017. We have since revised and redesigned our accounts payable procedures and controls and will reassess the control design and effectiveness for the period ended June 30, 2017. 

 

As of March 31, 2017, 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, 2017, because of the deficiency note above, our disclosure controls and procedures were not 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.  

 

Other than disclosed above, there were no changes in our internal control over financial reporting that occurred during the three months ended March 31, 2017, 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. There are no material pending legal proceedings to which the Company is a party or of which our property is the subject.

 

Item 1A.   Risk Factors.

 

In addition to 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, 2016.  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.

 

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
     
10.1   Letter dated April 3, 2017 modifying payment terms of Secured Promissory Note dated March 31, 2016 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 7, 2017)
     
10.2+   Amended and Restated Employment Agreement, by and between Samson Oil and Gas USA and Terence Barr, dated January 1, 2011 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 26, 2017)
     
10.3+   Amended and Restated Employment Agreement, by and between Samson Oil and Gas USA and Robyn Lamont, dated January 1, 2017 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 26, 2017)
     
10.4+   Amended and Restated Employment Agreement, by and between Samson Oil and Gas USA and David Ninke, dated January 1, 2017 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 26, 2017)
     
10.5+   Employment Agreement, by and between Samson Oil and Gas USA and Mark Ulmer, dated April 1, 2016 (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 26, 2017)
     

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

101.SCH

101.CAL

101.DEF

101.LAB

101.PRE

 

XBRL Instance Document

XBRL Taxonomy Extension Schema Document

XBRL Taxonomy Extension Calculation Linkbase Document

XBRL Taxonomy Extension Definition Linkbase Document

XBRL Taxonomy Extension Label Linkbase Document

XBRL Taxonomy Extension Presentation Linkbase Document

 

*Furnished herewith

+ Management contract or compensatory plan or arrangement

  

27  

 

 

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 15, 2017 By: /s/ Terry Barr
    Terence M. Barr
    Managing Director, President and Chief Executive Officer (Principal Executive Officer)
   
Date:  May 15, 2017 By: /s/ Robyn Lamont
    Robyn Lamont
    Chief Financial Officer (Principal Financial Officer)

 

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