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 December
31, 2014
OR
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 |
Commission File Number: 001-33578
Samson Oil & Gas Limited
(Exact Name of Registrant as Specified in
its Charter)
Australia |
N/A |
(State or Other Jurisdiction of Incorporation or Organization) |
(I.R.S. Employer Identification No.) |
|
|
Level 16, AMP Building,
140 St Georges Terrace
Perth, Western Australia 6000 |
|
(Address Of Principal Executive Offices) |
(Zip Code) |
+61 8 9220 9830
(Registrant’s Telephone Number, Including
Area Code)
Indicate
by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No
Indicate
by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive
Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the
preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark whether the registrant
is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions
of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2
of the Exchange Act.
Large accelerated filer |
¨ |
Accelerated filer x |
|
|
|
Non-accelerated filer |
¨ |
Smaller reporting company ¨ |
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 2,837,782,022 ordinary shares
outstanding as of February 6, 2015.
SAMSON OIL & GAS LIMITED
FORM 10-Q
QUARTER ENDED DECEMBER 31, 2014
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, our ability to and methods by which we may raise additional capital, production and future operating results.
In this quarterly report, the use of words
such as “anticipate,” “continue,” “estimate,” “expect,” “likely,” “may,”
“will,” “project,” “should,” “believe” and similar expressions are intended to
identify uncertainties. While we believe that the expectations reflected in those forward–looking statements are reasonable,
we cannot assure you that these expectations will prove to be correct. Our actual results could differ materially from those anticipated
in these forward–looking statements. The differences between actual results and those predicted by the forward–looking
statements could be material. Forward-looking statements are based upon our expectations relating to, among other things:
| · | our future financial position, including cash flow, anticipated liquidity,
outcome of capital raising efforts, and debt levels; |
| · | the timing, effects and success of our exploration and development
activities; |
| · | our ability to find, acquire, market, develop and produce new properties
and dispose of properties; |
| · | 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; |
| · | declines in the values of our properties that may result in write-downs; |
| · | effectiveness of management strategies and decisions; |
| · | the strength and financial resources of our competitors; |
| · | oil and natural gas prices and demand; |
| · | our entrance into transactions in commodity derivative instruments; |
| · | the receipt of governmental permits and other approvals relating to
our operations; |
| · | unanticipated recovery or production problems, including cratering,
explosions, fires; and |
| · | uncontrollable flows of oil, gas or well fluids. |
Many of these factors are beyond our ability
to control or predict. Neither these factors nor those included in the “Risk Factors” section of this quarterly report
represent a complete list of the factors that may affect us. We do not undertake to update the forward–looking
statements made in this report.
Part I — Financial Information
Item 1. Financial Statements.
SAMSON OIL & GAS LIMITED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| |
31-Dec-14 | | |
30-Jun-14 | |
ASSETS | |
| | | |
| | |
CURRENT ASSETS | |
| | | |
| | |
Cash and cash equivalents | |
$ | 3,881,138 | | |
$ | 6,846,394 | |
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively | |
| 3,401,145 | | |
| 5,533,516 | |
Prepayments | |
| 1,202,115 | | |
| 5,388,428 | |
Fair value of derivative instrument | |
| 1,949,350 | | |
| - | |
Short term deferred tax asset | |
| 84,946 | | |
| 84,946 | |
Total current assets | |
| 10,518,694 | | |
| 17,853,284 | |
PROPERTY, PLANT AND EQUIPMENT, AT COST | |
| | | |
| | |
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment of $21,079,958 and $21,219,361 at December 31, 2014 and June 30, 2014, respectively | |
| 46,866,724 | | |
| 34,430,793 | |
Other property and equipment, net of accumulated depreciation and amortization of $486,953 and $421,443 at December 31, 2014 and June 30, 2014, respectively | |
| 317,766 | | |
| 365,566 | |
Net property, plant and equipment | |
| 47,184,490 | | |
| 34,796,359 | |
OTHER NON CURRENT ASSETS | |
| | | |
| | |
Fair value of derivative instrument | |
| 256,940 | | |
| - | |
Undeveloped capitalized acreage | |
| 2,937,920 | | |
| 12,349,767 | |
Capitalized exploration expense | |
| 1,953,039 | | |
| 3,382,650 | |
Other | |
| 354,619 | | |
| 459,169 | |
TOTAL ASSETS | |
$ | 63,205,702 | | |
$ | 68,841,229 | |
| |
| | | |
| | |
LIABILITIES AND STOCKHOLDERS’ EQUITY | |
| | | |
| | |
CURRENT LIABILITIES | |
| | | |
| | |
Accounts payable | |
$ | 2,046,235 | | |
$ | 4,316,963 | |
Accruals | |
| 4,386,154 | | |
| 3,261,674 | |
Fair value of derivative instruments | |
| - | | |
| 284,376 | |
Provision for annual leave | |
| 211,229 | | |
| 230,311 | |
Total current liabilities | |
| 6,643,618 | | |
| 8,093,324 | |
NON CURRENT LIABILITIES | |
| | | |
| | |
Fair value of derivative instruments | |
| - | | |
| 128,998 | |
Asset retirement obligations | |
| 1,124,377 | | |
| 897,859 | |
Credit facility | |
| 15,500,000 | | |
| 6,000,000 | |
Deferred tax liability | |
| 84,946 | | |
| 84,946 | |
TOTAL LIABILITIES | |
| 23,352,941 | | |
| 15,205,127 | |
STOCKHOLDERS’ EQUITY – nil par value | |
| | | |
| | |
2,837,782,022 (equivalent to 141,889,101 ADR’s) and 2,837,756,933 (equivalent to 127,381,360 ADR’s) ordinary shares issued and outstanding at December 31, 2014 and June 30, 2014, respectively | |
| 104,491,774 | | |
| 104,535,894 | |
Accumulated other comprehensive income | |
| 1,075,697 | | |
| 1,302,096 | |
Accumulated deficit | |
| (65,714,710 | ) | |
| (52,201,888 | ) |
Total stockholders’ equity | |
| 39,852,761 | | |
| 53,636,102 | |
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | |
$ | 63,205,702 | | |
$ | 68,841,229 | |
See accompanying Notes to Consolidated Financial
Statements.
SAMSON OIL & GAS LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)
| |
Three months ended | | |
Six months ended | |
| |
31-Dec-14 | | |
31-Dec-13 | | |
31-Dec-14 | | |
31-Dec-13 | |
REVENUES AND OTHER INCOME: | |
| | | |
| | | |
| | | |
| | |
Oil sales | |
$ | 2,538,100 | | |
$ | 1,082,154 | | |
$ | 5,541,245 | | |
$ | 2,339,144 | |
Gas sales | |
| 148,953 | | |
| 202,658 | | |
| 404,003 | | |
| 344,604 | |
Other liquids | |
| - | | |
| 627 | | |
| - | | |
| 627 | |
Interest income | |
| 9,884 | | |
| 86,853 | | |
| 19,523 | | |
| 101,298 | |
Gain on derivative instruments | |
| 2,306,135 | | |
| - | | |
| 3,087,705 | | |
| - | |
Gain on sale of oil and gas properties | |
| - | | |
| - | | |
| - | | |
| 2,524,411 | |
Other | |
| 6,561 | | |
| 85 | | |
| 6,772 | | |
| 184 | |
TOTAL REVENUE AND OTHER INCOME | |
| 5,009,633 | | |
| 1,372,377 | | |
| 9,059,248 | | |
| 5,310,268 | |
| |
| | | |
| | | |
| | | |
| | |
EXPENSES: | |
| | | |
| | | |
| | | |
| | |
Lease operating expense | |
| (1,512,195 | ) | |
| (586,926 | ) | |
| (2,972,117 | ) | |
| (1,231,676 | ) |
Depletion, depreciation and amortization | |
| (1,118,619 | ) | |
| (417,723 | ) | |
| (2,073,680 | ) | |
| (881,805 | ) |
Impairment expense | |
| (3,027,288 | ) | |
| - | | |
| (3,060,684 | ) | |
| (83,121 | ) |
Abandonment expense | |
| (79,036 | ) | |
| - | | |
| (214,803 | ) | |
| - | |
Exploration and evaluation expenditure | |
| (362,540 | ) | |
| (51,669 | ) | |
| (11,465,956 | ) | |
| (319,374 | ) |
Accretion of asset retirement obligations | |
| (8,418 | ) | |
| (17,117 | ) | |
| (16,341 | ) | |
| (32,813 | ) |
Amortisation of borrowing costs | |
| (31,972 | ) | |
| - | | |
| (65,132 | ) | |
| - | |
Interest expense | |
| (147,343 | ) | |
| - | | |
| (231,285 | ) | |
| - | |
General and administrative | |
| (1,260,793 | ) | |
| (1,679,066 | ) | |
| (2,472,072 | ) | |
| (3,282,109 | ) |
TOTAL EXPENSES | |
| (7,548,204 | ) | |
| (2,752,501 | ) | |
| (22,572,070 | ) | |
| (5,830,898 | ) |
| |
| | | |
| | | |
| | | |
| | |
Loss from operations | |
| (2,538,571 | ) | |
| (1,380,124 | ) | |
| (13,512,822 | ) | |
| (520,630 | ) |
Income tax benefit | |
| - | | |
| - | | |
| - | | |
| - | |
Net loss | |
| (2,538,571 | ) | |
| (1,380,124 | ) | |
| (13,512,822 | ) | |
| (520,630 | ) |
OTHER COMPREHENSIVE GAIN (LOSS) | |
| | | |
| | | |
| | | |
| | |
Foreign currency translation loss | |
| (97,689 | ) | |
| (383,280 | ) | |
| (226,399 | ) | |
| (578,055 | ) |
Total comprehensive loss for the period | |
$ | (2,636,260 | ) | |
$ | (1,763,404 | ) | |
$ | (13,739,221 | ) | |
$ | (1,098,685 | ) |
| |
| | | |
| | | |
| | | |
| | |
Net loss per ordinary share from operations: | |
| | | |
| | | |
| | | |
| | |
Basic – cents per share | |
| (0.09 | ) | |
| (0.05 | ) | |
| (0.48 | ) | |
| (0.02 | ) |
Diluted – cents per share | |
| (0.09 | ) | |
| (0.05 | ) | |
| (0.48 | ) | |
| (0.02 | ) |
| |
| | | |
| | | |
| | | |
| | |
Weighted average ordinary shares outstanding: | |
| | | |
| | | |
| | | |
| | |
Basic | |
| 2,837,781,683 | | |
| 2,547,627,193 | | |
| 2,837,772,648 | | |
| 2,452,931,137 | |
Diluted | |
| 2,837,781,683 | | |
| 2,547,627,193 | | |
| 2,837,772,648 | | |
| 2,452,931,137 | |
See accompanying Notes to Consolidated Financial
Statements.
SAMSON OIL & GAS LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN
STOCKHOLDERS’ EQUITY
(Unaudited)
| |
| | |
| | |
Accumulated Other | | |
| |
| |
| | |
| | |
Other | | |
Total | |
| |
Ordinary | | |
| | |
Comprehensive | | |
Stockholders | |
| |
Shares | | |
(Accumulated Deficit) | | |
Income | | |
Equity | |
Balance at June 30, 2014 | |
$ | 104,535,894 | | |
$ | (52,201,888 | ) | |
$ | 1,302,096 | | |
$ | 53,636,102 | |
Net loss | |
| - | | |
| (13,512,822 | ) | |
| - | | |
| (13,512,822 | ) |
Foreign currency translation loss, net of tax of $nil | |
| - | | |
| - | | |
| (226,399 | ) | |
| (226,399 | ) |
Total comprehensive loss for the period | |
| - | | |
| (13,512,822 | ) | |
| (226,399 | ) | |
| (13,739,221 | ) |
Stock based compensation | |
| - | | |
| - | | |
| - | | |
| - | |
Exercise of options | |
| 880 | | |
| - | | |
| - | | |
| 880 | |
Share issuance costs | |
| (45,000 | ) | |
| - | | |
| - | | |
| (45,000 | ) |
Balance at December 31, 2014 | |
$ | 104,491,774 | | |
$ | (65,714,710 | ) | |
$ | 1,075,697 | | |
$ | 39,852,761 | |
See accompanying Notes to Consolidated Financial
Statements.
SAMSON OIL & GAS LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| |
Six months ended | |
| |
31-Dec-14 | | |
31-Dec-13 | |
Cash flows (used in)/provided by operating activities | |
| | | |
| | |
Receipts from customers | |
$ | 7,010,394 | | |
$ | 2,504,828 | |
Payments to suppliers & employees | |
| (6,349,789 | ) | |
| (4,207,411 | ) |
Interest received | |
| 19,499 | | |
| 102,019 | |
Proceeds from derivative instruments | |
| 228,837 | | |
| - | |
State income taxes paid | |
| (107,135 | ) | |
| - | |
Net cash flows provided by/(used in) operating activities | |
| 801,806 | | |
| (1,600,564 | ) |
Cash flows used in investing activities | |
| | | |
| | |
Proceeds from sale of oil and gas properties | |
| - | | |
| 3,547,409 | |
Payments for plant & equipment | |
| (21,427 | ) | |
| (25,041 | ) |
Payments for exploration and evaluation | |
| (1,399,142 | ) | |
| (240,945 | ) |
Payments for oil and gas properties | |
| (11,313,174 | ) | |
| (15,144,169 | ) |
Net cash flows used in investing activities | |
| (12,733,743 | ) | |
| (11,862,746 | ) |
Cash flows provided by financing activities | |
| | | |
| | |
Issuance of share capital | |
| - | | |
| 7,337,138 | |
Proceeds from the exercise of options | |
| 880 | | |
| 347 | |
Proceeds from borrowings | |
| 9,500,000 | | |
| - | |
Borrowing costs | |
| (83,690 | ) | |
| - | |
Interest paid | |
| (172,917 | ) | |
| - | |
Share issuance costs | |
| (45,000 | ) | |
| (561,239 | ) |
Net cash flows provided by financing activities | |
| 9,199,273 | | |
| 6,776,246 | |
Net decrease in cash and cash equivalents | |
| (2,732,664 | ) | |
| (6,687,064 | ) |
Cash and cash equivalents at the beginning of the fiscal period | |
| 6,846,394 | | |
| 13,170,627 | |
Effects of exchange rate changes on cash and cash equivalents | |
| (232,592 | ) | |
| (581,004 | ) |
Cash and cash equivalents at end of fiscal period | |
$ | 3,881,138 | | |
$ | 5,902,559 | |
See accompanying Notes to Consolidated Financial
Statements
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, 2014. 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 December 31, 2014 and June 30, 2014 consist primarily of estimates for goods and services received but not yet invoiced.
Prepayments. Prepayments at December
31, 2014 and June 30, 2014 consist primarily of cash advanced to the operators of our drilling projects for future drilling operations.
As at December 31, 2014, cash had been advanced to the operator of our North Stockyard infill development project for the drilling
and/or completion of four wells.
Recent Accounting Standards
There are no new accounting pronouncements
that have not been adopted by the Company as of December 31, 2014 that will have a material effect on the Company’s financial
statements.
2. Income Taxes
| |
Three months ended | | |
Six months ended | |
| |
31-Dec-14 | | |
31-Dec-13 | | |
31-Dec-14 | | |
31-Dec-13 | |
| |
| | |
| | |
| | |
| |
Income tax benefit | |
$ | - | | |
$ | - | | |
$ | - | | |
$ | - | |
Effective tax rate | |
| 0.00 | % | |
| 0.00 | % | |
| 0.00 | % | |
| 0.00 | % |
The Company has cumulative net operating
losses (“NOL”) 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.
In the tax year ended June 30, 2012, the
Company generated an NOL of $33 million which exceeded the amount of taxable income, after NOL, generated in the tax year ended
June 30, 2011. As a result, the NOL from June 30, 2012 was carried back to the year of June 30, 2011, generating a refund of tax
paid in that year. The Company’s remaining NOLs will be carried forward to offset future taxable income.
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.
3. Earnings Per Share
Basic earnings (loss) per share is calculated
by dividing net earnings (loss) attributable to ordinary shares by the weighted average number of shares outstanding for the period.
Under the treasury stock method, diluted earnings per share is calculated by dividing net earnings (loss) by the weighted average
number of shares outstanding including all potentially dilutive ordinary shares (which in Samson’s case consists of unexercised
stock options). In the event of a net loss, however no potential ordinary shares are included in the calculation of shares outstanding
since the impact would be anti-dilutive.
The following table details the weighted
average dilutive and anti-dilutive securities outstanding, which consist of options, for the periods presented:
| |
Three months ended | | |
Six months ended | |
| |
31-Dec-14 | | |
31-Dec-13 | | |
31-Dec-14 | | |
31-Dec-13 | |
Dilutive | |
| - | | |
| - | | |
| - | | |
| - | |
Anti–dilutive | |
| 389,168,104 | | |
| 300,885,050 | | |
| 389,177,139 | | |
| 261,058,802 | |
The following tables set forth the calculation
of basic and diluted loss per share:
| |
Three months ended | | |
Six months ended | |
| |
31-Dec-14 | | |
31-Dec-13 | | |
31-Dec-14 | | |
31-Dec-13 | |
Net income (loss) | |
$ | (2,538,571 | ) | |
| (1,380,124 | ) | |
$ | (13,512,822 | ) | |
| (520,630 | ) |
| |
| | | |
| | | |
| | | |
| | |
Basic weighted average ordinary shares outstanding | |
| 2,837,781,683 | | |
| 2,547,627,193 | | |
| 2,837,772,648 | | |
| 2,452,931,137 | |
Add: dilutive effect of stock options | |
| - | | |
| - | | |
| - | | |
| - | |
Add: bonus element for rights issue | |
| - | | |
| - | | |
| - | | |
| - | |
Diluted weighted average ordinary shares outstanding | |
| 2,837,781,683 | | |
| 2,547,627,193 | | |
| 2,837,772,648 | | |
| 2,452,931,137 | |
Basic earnings per ordinary share – cents per share | |
| (0.09 | ) | |
| (0.05 | ) | |
| (0.48 | ) | |
| (0.02 | ) |
Diluted earnings per ordinary share – cents per share | |
| (0.09 | ) | |
| (0.05 | ) | |
| (0.48 | ) | |
| (0.02 | ) |
4. Asset Retirement Obligations
The Company’s asset retirement obligations
primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing
and shut–in properties at the end of their productive lives in accordance with applicable state and federal laws. The Company
determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows
related to those obligations. The significant inputs used to calculate such liabilities include estimates of costs to be incurred,
the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability
is accreted to its present value each period and the capitalized asset retirement cost is depleted using the units–of–production
method.
The liabilities settled in the
six months to December 31, 2014 relate to work performed to plug and abandon three wells in our Greens Canyon
prospect in Wyoming. These wells were drilled 10 years ago and did not produce economic quantities of hydrocarbons.
The following table summarizes the activities
for the Company’s asset retirement obligations for the six months ended December 31, 2014 and 2013:
| |
Six months ended | |
| |
31-Dec-14 | | |
31-Dec-13 | |
Asset retirement obligations at beginning of period | |
$ | 1,775,792 | | |
$ | 868,589 | |
Liabilities incurred or acquired | |
| 42,805 | | |
| 154,735 | |
Liabilities settled | |
| (710,561 | ) | |
| (8,136 | ) |
Disposition of properties | |
| - | | |
| - | |
Accretion expense | |
| 16,341 | | |
| 32,813 | |
Asset retirement obligations at end of period | |
| 1,124,377 | | |
| 1,048,001 | |
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities) | |
| - | | |
| - | |
Long-term asset retirement obligations | |
$ | 1,124,377 | | |
$ | 1,048,001 | |
5. Equity Incentive Compensation
Stock-based compensation is measured at
the grant date based on the estimated fair value of the awards with the resulting amount recognized as compensation expense on
a straight-line basis over the requisite service period (usually the vesting period).
Total compensation cost recognized in the
Statements of Operations for the grants under the Company’s equity incentive compensation plans was $nil during the three
months ended December 31, 2014 and $80,989 during the three months ended December 31, 2013.
Total compensation cost recognized in the
Statements of Operations for the grants under the Company’s equity incentive compensation plans was $nil during the six months
ended December 31, 2014 and $86,244 during the six months ended December 31, 2013.
As of December 31, 2014, there was $nil
total unrecognized compensation cost related to outstanding stock options.
6. Sale of Oil and Gas Assets
In August 2013, we divested half our equity
position in the undeveloped acreage in the North Stockyard project to Slawson Exploration Company Inc. (“Slawson”)
for $5.562 million in cash and other consideration while retaining our full interest in the currently producing wells in the North
Stockyard field. $0.9 million of the cash portion of the purchase price was subject to the delivery of a useable well bore in Billabong.
While work is continuing on this well bore, it had to be suspended to permit other drilling operations to proceed on the same pad.
The Billabong workover was completed during the year ended June 30, 2014 and Slawson exercised its option to take over operation
of the Billabong well bore.
As a consequence of the transaction the
rig contract with Frontier was also terminated, with no penalty payment. Slawson is now the operator of the project going forward
for the development of the undeveloped acreage.
Along with the undeveloped acreage for
which a gain on sale was recognized in the Income Statement of $2.52 million, we have also transferred a 25% working interest in
Sail and Anchor well, which was drilled but not completed, at the time of sale, as well as a 25% working interest in the salt water
disposal well drilled in the prior year in the North Stockyard project for $2.92 million, recognized as a reimbursement in the
capitalized costs for these assets at the time of the transaction.
7. Fair Value Measurements
Fair value is defined as the price that
would be received in the sale of an asset or paid to transfer a liability in an orderly transaction between market participants
at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing
the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These
inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based
on the observability of those inputs. The FASB has established a fair value hierarchy that prioritizes the inputs used to measure
fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities
(level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).
The three levels of the fair value hierarchy
are as follows:
| · | 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
December 31, 2014 and June 30, 2013.
| |
Carrying value at December 31, 2014 | | |
Level 1 | | |
Level 2 | | |
Level 3 | | |
Netting (1) | | |
Fair Value at December 31, 2014 | |
Current Assets: | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Cash and cash equivalents | |
$ | 3,881,138 | | |
$ | 3,881,138 | | |
$ | - | | |
$ | - | | |
$ | - | | |
$ | 3,881,138 | |
Derivative Instruments | |
| 1,949,350 | | |
| - | | |
| 1,960,723 | | |
| - | | |
| (11,373 | ) | |
| 1,949,350 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Non Current Assets | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Derivative Instruments | |
| 256,940 | | |
| - | | |
| 722,491 | | |
| | | |
| (465,551 | ) | |
| 256,940 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| - | |
Current Liabilities | |
| | | |
| | | |
| | | |
| | | |
| | | |
| - | |
Derivative instruments | |
| - | | |
| - | | |
| 11,373 | | |
| - | | |
| (11,373 | ) | |
| - | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| - | |
Non Current Liabilities | |
| | | |
| | | |
| | | |
| | | |
| | | |
| - | |
Derivative Instruments | |
| - | | |
| - | | |
| 465,551 | | |
| | | |
| (465,551 | ) | |
| - | |
| |
Carrying value at June 30, 2014 | | |
Level 1 | | |
Level 2 | | |
Level 3 | | |
Netting (1) | | |
Fair Value at June 30, 2014 | |
Current Assets: | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Cash and cash equivalents | |
$ | 6,846,394 | | |
$ | 6,846,394 | | |
$ | - | | |
$ | - | | |
$ | - | | |
$ | 6,846,394 | |
Derivative Instruments | |
| - | | |
| - | | |
| 56,380 | | |
| - | | |
| (56,380 | ) | |
| - | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Non Current Assets | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Derivative Instruments | |
| - | | |
| - | | |
| 61,493 | | |
| - | | |
| (61,493 | ) | |
| - | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Current Liabilities | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Derivative instruments | |
| 284,376 | | |
| - | | |
| 340,756 | | |
| - | | |
| (56,380 | ) | |
| 284,376 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Non Current Liabilities | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Derivative Instruments | |
| 128,998 | | |
| - | | |
| 190,491 | | |
| - | | |
| (61,493 | ) | |
| 128,998 | |
| (1) | Netting In accordance with the Company’s standard practice, its commodity derivatives
are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated. |
The following methods and assumptions were
used to estimate the fair value of the assets and liabilities in the table above:
Level 1 Fair value Measurements
Fair Value of Financial Instruments.
The Company’s financial instruments consist primarily of cash and cash equivalents, restricted cash, accounts
receivable and payable and derivatives (discussed below). The carrying values of cash equivalents and accounts receivable and payable
are representative of their fair values due to their short–term maturities.
Level 2 Fair Measurements
Derivative Contracts. The
Company’s derivative contracts consist of oil collars and oil call options. The fair value of these contracts are based
on inputs that are either readily available in the public market, such as oil future prices or inputs that can be
corroborated from active markets. Fair value is determined through the use of a discounted cash model using applicable inputs
discussed above.
Other fair value measurements
Assets and Liabilities Measured at Fair
Value on a Nonrecurring Basis.
The Company also applies fair value accounting
guidance to measure non–financial assets and liabilities such as business acquisitions, proved oil and gas properties, and
asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances
and are not subject to recurring revaluations. These items are primarily valued using the present value of estimated future cash
inflows and/or outflows. Given the unobservable nature of these inputs, they are deemed to be Level 3.
Some oil and gas properties are stated
at fair value as at December 31, 2014. 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 $3.0 million. $2.7 million of this related to our
Rainbow property in North Dakota, while the remaining $0.3 million related to various small non-operated properties in Wyoming.
8. Commitments and Contingencies
The Company has no accrued environmental
liabilities for its sites, including sites in which governmental agencies have designated the Company as a potentially responsible
party, because it is not probable that a loss will be incurred and the minimum cost and/or amount of loss cannot be reasonably
estimated. However, due to uncertainties associated with environmental assessment and remediation activities, future expense to
remediate the currently identified sites, and sites identified in the future, if any, could be incurred. Management believes, based
upon current site assessments, that the ultimate resolution of any such matters will not materially affect our results of operations
or cash flows.
From time to time, we are involved in various
legal proceedings through the ordinary course of business. While the ultimate outcome is not known, management believes that any
resolution will not materially impact the financial statements.
Halliburton Dispute
Halliburton Energy Services, Inc., a co-participant
in the Company’s Hawk Springs project, has filed a complaint in Harris County, Texas District Court against Samson USA seeking
unpaid oil revenue attributable to its ownership interest in the Hawk Springs Project, which was approximately $126,000 as of June
5, 2013, and has since increased to approximately $168,000. Samson USA has answered the complaint and has filed counterclaims
against Halliburton arising out of Samson USA’s engagement of Halliburton’s Project Management group in May of 2011
to provide services in connection with its drilling program in Roosevelt County, Montana. In its counterclaims, Samson USA
claims approximately $336,000 from Halliburton on account of Halliburton’s refusal to pay an invoice for demobilization of
the drilling rig used in the Roosevelt project. Samson USA has also asked for a judicial accounting with respect to Halliburton’s
fees and expenses charged to Samson in connection with the Spirit of America well in Goshen County, Wyoming, and the Australia
II, well in Roosevelt County, Wyoming, because of Samson’s discovery of self-dealing and bill padding by Halliburton’s
onsite project manager there. Halliburton has not yet filed an answer to Samson’s counterclaims but the parties are
commencing discovery efforts in the lawsuit. While Samson believes that its counterclaims are meritorious and is confident
that Samson will obtain a net positive recovery from the lawsuit, there can be no assurance as to the ultimate outcome of this
litigation.
9. Capitalized Exploration Expense
We use the successful efforts method of
accounting for exploration and evaluation expenditure in respect of each area of interest. The application of this policy requires
management to make certain estimates and assumptions as to future events and circumstances, in particular the assessment of whether
economic quantities of reserves have been found. Any such estimates and assumptions may change as new information becomes
available.
Exploration and evaluation assets are assessed
for impairment when facts and circumstances indicate that the carrying amount of an exploration and evaluation asset may exceed
its recoverable amount. When assessing for impairment consideration is given to but not limited to the following:
| § | 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 December 31, 2014 we had capitalized
exploration expenditures of $2.3 million and undeveloped capitalized acreage expenditures of $2.9 million. This amount
primarily relates to costs incurred in connection with our Hawk Springs projects.
Our Hawk Springs project, in Goshen County,
Wyoming, includes $2.9 million in undeveloped capitalized acreage costs and $2.3 million in capitalized exploration expenditure.
The capitalized exploration expenditure includes costs associated with the acquisition of our North Platte 3D seismic data and
costs associated with the drilling of our Bluff Federal well in this project area. Operations are continuing on this well and it
is expected to be completed by March 31, 2015. Due to expired leases, $0.1 million has been written off with respect to this project
during the quarter ended September 30, 2014 and $0.2 million has been written off with respect to this project during the quarter
ended December 31, 2014.
Our Roosevelt project, in Roosevelt County,
Montana, includes $7.8 million in undeveloped capitalized acreage costs and $0.3 million in capitalized exploration expenditure.
The capitalized exploration expenditure consists of costs associated with well permitting; surface use agreements and other expenses
associated with drilling preparation activities. In December 2013, we entered into a seismic and drilling agreement with Momentus
Energy Corp, a Canadian exploration and development company based in Calgary. Momentus has committed to the acquisition of approximately
20 square miles of 3-D seismic data at no cost to us. Following the acquisition of the seismic data, Momentus has the option to
drill a horizontal Bakken well on our acreage at 100% cost to it. Upon Momentus drilling this well, it will have earned the right
to 50% of the test well and 50% of our acreage in the Roosevelt project.
The 3-D seismic survey has been shot, processed,
and interpreted. The agreement required Momentus to drill a Bakken horizontal by November 15, 2014, and as this did not occur negotiations
have proceeded and now Momentus has until March 15, 2015 to pay Samson $100,000 to extend the farm-out agreement to December 31,
2015. If Momentus fails to pay Samson $100,000 by March 15, 2015, the farm-out will terminate.
It is understood that the extension is
being requested as Momentus has failed to secure the funding to drill their earn-in well. Given the recent drop in oil prices,
the lack of certainty with respect to Momentus’s ability to drill their earn in well and the fact that at this point in time
we do not expect to spend any further funds on this project, the balance of $8.1 million capitalized with respect to this project
was written off to the Statement of Operations during the quarter ended September 30, 2014.
Our South Prairie project in Ward and Renville
counties, North Dakota, includes $1.6 million in undeveloped acreage costs and $0.9 million in capitalized exploration expenditure.
This expenditure relates to 3-D seismic acquisition costs. We are not the operator of this project. The joint venture is focusing
on developing three structural closure prospects (Pubco, Deering, and Birch) along the Prairie Salt edge in the South Prairie 3-D
project. The joint venture approved the drilling next of the Pubco Prospect, with the York 3-14 well, on the eastern edge of the
South Prairie 3-D seismic survey. This well was drilled during the quarter ended September 30, 2014 and found the primary target
to be water saturated. Given the lack of success from this project, we have written off the previously capitalized value of this
project of $2.5 million to the Statement of Operations during the quarter ended September 30, 2014.
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.
10. Issue of Share Capital
During the three months ended December
31, 2014, 1,064 Australian 3.8 cent options were exercised for net proceeds of $38.
During the six months ended December 31,
2014, 25,089 Australian 3.8 cent options were exercised for net proceeds of $880.
During the three months ended December
31, 2013 there were no issues of ordinary shares.
During the six months ended December 31,
2013 9,864 Australian 3.8 cent options were exercised for net proceeds of $347.
All options exercised were issued in a
public rights offering conducted in June 2013.
During the six months ended December 31,
2013, we issued 318,452,166 ordinary shares for 2.5 cents (Australian cents)/2.3 cents (United States cents) for proceeds of $7.3
million. The ordinary shares were issued to investors in the US and Australia. In conjunction with these issues we also issued
132,380,866 warrants with an exercise price of 3.8 cents (Australian) and expiry date of March 31, 2017.
11. Cash Flow Statement
Reconciliation of loss after tax to the
net cash flows from operations:
| |
Six months ended | |
| |
31-Dec-14 | | |
31-Dec-13 | |
Net loss after tax | |
$ | (13,512,822 | ) | |
$ | (520,630 | ) |
Depletion, depreciation and amortization | |
| 2,073,680 | | |
| 881,805 | |
Stock-based compensation | |
| - | | |
| 86,244 | |
Accretion of asset retirement obligation | |
| 16,341 | | |
| 32,813 | |
Impairment expense | |
| 3,060,684 | | |
| 83,121 | |
Exploration and evaluation expenditure | |
| 11,465,956 | | |
| 319,374 | |
Gain on sale of oil and gas properties | |
| - | | |
| (2,524,411 | ) |
Amortisation borrowing costs | |
| 65,132 | | |
| - | |
Abandonment expense | |
| 214,803 | | |
| - | |
Non cash gain on derivative instruments | |
| (2,619,664 | ) | |
| - | |
| |
| | | |
| | |
Changes in assets and liabilities: | |
| | | |
| | |
| |
| | | |
| | |
Decrease/(Increase) in receivables | |
| 2,132,371 | | |
| (179,360 | ) |
Decrease in income tax receivable/deferred tax asset | |
| - | | |
| - | |
Increase/(decrease) in provision for annual leave | |
| (19,082 | ) | |
| 38,851 | |
(Decrease)/Increase in payables | |
| (2,075,593 | ) | |
| 181,629 | |
NET CASH FLOWS PROVIDED BY/(USED IN) OPERATING ACTIVITIES | |
$ | 801,806 | | |
$ | (1,600,564 | ) |
12. Credit Facility
| |
Six months ended | |
| |
31-Dec-14 | | |
31-Dec-13 | |
Credit facility at beginning of period | |
$ | 6,000,000 | | |
$ | - | |
Cash advanced under facility | |
$ | 9,500,000 | | |
| - | |
Repayments | |
| - | | |
| - | |
Credit facility at end of period | |
$ | 15,500,000 | | |
$ | - | |
| |
| | | |
| - | |
Funds available for drawdown under the facility | |
$ | 3,500,000 | | |
| - | |
In January 2014, we entered into a $25.0
million credit facility with 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, of which $15.5 million has been drawn
down.
Additional increases in the borrowing base,
up to the credit facility maximum of $50.0 million, may be made available to us in the future depending on the value of our reserves.
Borrowing base redeterminations are performed by the lender every six months at June and December. We also have the ability to
request a borrowing base redetermination at another period, once a year. The facility matures January 28, 2017. The interest rate
is LIBOR plus 3.25% or approximately 3.48% for the quarter ended December 31, 2014.
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 3.5 |
| · | Interest coverage ratio minimum of between
2.5 and 1.0 |
The credit facility also includes an annual
cap on general and administrative expenditures of $6,000,000 per year to be tested for the first time for calendar year ended December
31, 2014 and each subsequent December 31 thereafter while the facility is in place.
As at December 31, 2014 we were in breach
of our debt to EBITDAX covenant. We have received a waiver from Mutual of Omaha with respect to this breach for this quarter only.
We were in compliance with all other covenants.
While we expect to be in compliance with
these covenants based on 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.
These funds, along with cash on hand and
cash flow from operations, will be used to fund drilling in our North Stockyard project in North Dakota. We expect to fund our
remaining capital expenditures for the fiscal year ending June 30, 2015 thereby, though we may obtain additional capital through
further drawdowns of our credit facility (if possible) or another capital raising program or asset sales.
We incurred $0.4 million in borrowing costs
(including legal fees and bank fees) which have been deferred and will be amortized over the life of the facility.
13. Derivatives
The Company has not designated any of its derivative contracts
as hedges for accounting purposes. The Company records all derivative contracts at fair value. Changes in derivative contracts
are recognized in earnings. Changes in settlements and valuation gains and losses are included in loss/(gain) on derivative instruments
in the Statement of Operations. These contracts are settled on a monthly basis. Derivative assets and liabilities arising from
the Company’s derivative contracts with the same counterparty that provide for net settlement are reported on a net basis
in the Balance Sheet.
The Company is exposed to commodity price risk, which
impacts the predictability of its cash flows from the sale of oil. The Company seeks to manage this risk through the use of
commodity derivative contracts These derivative contracts allow the Company to limit its exposure to commodity price
volatility on a portion of its forecasted oil sales. At December 31, 2014, 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 Mutual of Omaha Bank, the provider of the Company’s credit facility, as
such, no additional collateral is required by the counterparty.
During the quarter ended December 31, 2014 we recognized $2,306,135
gain on derivative instruments in the Statement of Operations.
We intend to increase our derivative portfolio as our production
increases in order to provide downside protection to our future production.
In October 2014, we entered into a deferred put spread arrangement
with respect to 36,600 barrels from production in 2016. These options have a floor of $82.50 (the Company receives $82.50 when
the market price settles between $67.20 and $82.50) and a sub floor of $67.50 (the Company receives the market price plus $15 for
any prices below $67.50) with a cost of $5.50 per barrel which is deferred until the settlement of the derivative instrument.
At December 31, 2014 the Company’s open derivative contracts
consisted of the following:
Oil Price Collars - WTI | |
Volumes (Bbls) | | |
Floor US$ | | |
Ceiling US$ | |
January 2015 - December 2015 | |
| 18,270 | | |
| 85.00 | | |
| 89.85 | |
January 2016 - February 2016 | |
| 2,788 | | |
| 85.00 | | |
| 89.85 | |
| |
| | | |
| | | |
| | |
Oil Price Swaps - WTI | |
Volumes (Bbls) | | |
Price US$ | | |
| |
January 2015 - December 2015 | |
| 18,270 | | |
| 105.00 | | |
| | |
January 2016 - February 2016 | |
| 2,788 | | |
| 105.00 | | |
| | |
| |
| | | |
| | | |
| | |
Oil Price Swaps - WTI | |
Volumes (Bbls) | | |
Avg Price US$ | | |
| | |
January 2015 - December 2015 | |
| 39,791 | | |
| 92.61 | | |
| | |
14. Subsequent Events
No events have occurred subsequent to December 31, 2014 that
would have an impact on our operations or the results of operations for the quarter ended December 31, 2014.
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, 2014, included in our Annual Report on Form 10-K and the Consolidated Financial
Statements included elsewhere herein.
Throughout this report, a barrel of oil
or Bbl means a stock tank barrel (“STB”) and a thousand cubic feet of gas or Mcf means a thousand standard cubic feet
of gas (“Mscf”).
Overview
We are an independent energy company primarily
engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Our strategy
is to focus on the exploration, exploitation and development of our major oil plays – the Niobrara, Permian and Pennsylvanian
in Goshen County, Wyoming and the Bakken in Williams County, North Dakota and Roosevelt County, Montana.
Our net oil production was 43,653 barrels
of oil for the quarter ended December 31, 2014, compared to 12,788 barrels of oil for the quarter ended December 31, 2013. The
increase in oil production was due to ten new wells commencing production in our North Stockyard project since December 2013. One
new well commenced production during the quarter ended September 30, 2014 with an additional nine commencing production during
the current quarter. Our net gas production was 39,043 Mcf for the quarter ended December 31, 2014, compared to 42,990 Mcf for
the quarter ended December 31, 2013. The decrease in gas production is a result of a decrease in production from our main gas well,
Sabretooth in Texas due to decreasing reservoir pressure, consistent with the production decline expected from this field. Gas
produced from the new wells in the North Stockyard project, with the exception of the Sail & Anchor and Blackdog wells, is
currently being flared while production facilities are being built and pipeline take away capacity is secured.
Our net oil production was 78,517 barrels
of oil for the six months ended December 31, 2014 compared to 25,424 barrels of oil for the six months ended December 31, 2013.
Our net gas production was 85,588 Mcf for the six months ended December 31, 2014 compared to 80,972 for the six months ended December
31, 2013. The increase in both oil and gas production is largely due to the eleven new wells that commenced production in our North
Stockyard project in North Dakota.
For the six months ended December 31, 2014
and December 31, 2013, we reported a net loss of $13.4 million and a net loss of $0.5 million, respectively. The loss in the current
period reflects a $11.0 million in write off of previously capitalized exploration expenditure and impairment expense of $3.0 million
while the loss in the prior period reflects a $2.5 million gain from the sale of oil and gas properties. 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 December 31, 2014 and Current Activities
Undeveloped Properties: Exploration
Activities
Hawk Springs Project, Goshen County,
Wyoming
Permo-Penn Project, Northern D-J Basin
Samson 37.5% working interest
We have two contiguous areas in the Hawk
Springs Project. One of the areas is a joint venture with a private company and is subject to a joint venture with Halliburton
Energy Services, Inc.
The Bluff Prospect was drilled in June
to test multiple targets in the Permian and Pennsylvanian sections in a 4-way structural trapping configuration. The Bluff #1-11
well reached a total depth of 8,900 feet after intersecting the pre-Cambrian basement on June 13th.
Various oil shows were observed in the
Cretaceous, Jurassic, Permian, and Pennsylvanian intervals while drilling. After running drill-pipe conveyed logging tools in the
deeper portion of the well below the intermediate casing, the Pennsylvanian zones, were deemed to be too thin and uneconomic to
produce. The Permian target zone (from 7738 to7756 feet) displayed excellent porosity (up to 29% density porosity). Further analysis
of the Permian target zone proves that it is the source of the nitrogen gas kicks. The presence of nitrogen in the Permian target
zone validates the trap in the Bluff prospect and has the potential to host an oil leg below the gas cap. This evidence led the
partners to make the decision to drill out the cement plug, set and cement a 5 inch liner 100 feet beneath the Permian target sand.
The Permian target sand was recently flow
tested at a rate of 8 MMcf/D on a 21/64 inch choke during a 40 hour flow test and then shut-in for a 10 day build-up using down-hole
gauges. The buildup data has determined that the original reservoir pressure within the 9500 foot sand is 3,459 psi. A chromatographic
analysis of the gas samples indicated that the majority of the gas was composed of nitrogen (97.5%), with some helium (0.15%),
carbon dioxide (0.15%), and the rest hydrocarbons (2.2%). A pressure transient analysis has confirmed that the 9500 foot sand is
highly permeable and also identified a movable fluid boundary (oil or water) downdip of the well. When the results are received
from the isotope geochemistry analysis of the gas samples, it may give us an understanding as to the whether the source of the
gas is organic or inorganic. If it is determined to be an organic source, it would be more likely that the fluid below the gas
cap is oil and thus a downdip well may be drilled to determine this. The gas-oil interface is currently being identified through
the integration of the pressure transient test data with newly processed inverted seismic data.
If it is determined to not drill the downdip
well, three zones in the Jurassic and Cretaceous sections, which are behind the intermediate casing, will subsequently be perforated
and flow-tested. Log pay was determined in the both the Dakota and Morrison Formations. Using a 60% water saturation as a cut-off
to determine oil productive zones, 23.5 feet of log pay was indicated in the Dakota (from 6,393 to 6,485 feet) and 3.5 feet in
the Morrison (from 6,605 to 6,625 feet). The Jurassic Canyon Springs Formation could also be productive. When comparing the Canyon
Springs reservoir characteristics in the Bluff well to analog producing fields in the southern Powder River Basin, there are similarities
between the two.
Roosevelt Project, Roosevelt County,
Montana
Mississippian Bakken Formation,
Williston Basin
Samson 100% working interest in Australia
II & Gretel II wells, 66.7% in any subsequent drilling, depending on the drilling location
We have an interest in approximately 45,000
gross acres (30,000 net acres) in the Roosevelt Project with Fort Peck Energy Co. (“FPEC”) having the remaining 15,000
net acres.
In December 2013, we entered into a seismic
and drilling agreement with Momentus Energy Corp, a Canadian exploration and development company based in Calgary. Momentus has
acquired approximately 20 squares of 3-D seismic data at no cost to us. Following the acquisition of the seismic data, Momentus
has the option to drill a horizontal Bakken well on our acreage at 100% its own cost. Upon Momentus drilling this well, it will
have earned the right to 50% of the test well and 50% of our acreage in the Roosevelt project. The program, consisting of 3-D seismic
acquisition and the cost of drilling the Bakken well, is valued at approximately $10 million.
The 3-D seismic survey has been shot, processed, and interpreted.
The agreement required Momentus to drill a Bakken horizontal by November 15, 2014, and as this did not occur negotiations have
proceeded and now Momentus has until March 15, 2015 to pay Samson $100,000 to extend the farm-out agreement to December 31, 2015.
If Momentus fails to pay Samson $100,000 by March 15, 2015, the farm-out will terminate.
The timing of the drilling of this well
has not been determined as of yet and some uncertainty exists with respect to Momentus ability to fund the earn-in well.
The two Bakken wells that were drilled
in 2011 and 2012 in the Roosevelt Project have proven to be uneconomic.
South Prairie Project, North Dakota
Mississippian Mission Canyon Formation, Williston Basin
Samson 25% working interest
Samson has a 25% working interest in 25,590 net acres located
on the eastern flank of the Williston Basin in North Dakota. The first well of the project, the Matson #3-1 well was drilled and
determined to be a dry hole and was plugged and abandoned in the prior year
Based on the technical analysis of this
result, the forward program will show a preference for structural closures that exist along the salt edge rather than those created
by dissolution events further interior to the salt edge. The joint venture is focusing on developing three structural closure prospects
(Pubco, Deering, and Birch) along the Prairie Salt edge in the South Prairie 3-D project.
Drilling has been completed on the York #3-9 well located in
T156N R82W S3 on the eastern flank of the Williston Basin, within the Pubco Prospect. Stephens Production Company drilled
the well to a total depth of 5,100 feet. The top of the Glenburn target zone of the Mississippian Mission Canyon Formation
was found as expected at a depth of 4,944 feet measured depth or 4,893 feet true vertical depth. The Glenburn was intersected
50 foot high to the two show wells originally thought to be near an oil-water contact, though the Glenburn was found to be wet,
and thus the well was plugged. One can conclude the reasoning for the wet Glenburn zone is that the 4-way structural trap
did not completely close on the eastern edge of the trap which coincides with edge of the 3-D seismic survey. The low-fold
data along the edges of 3-D seismic surveys are not always reliable and was one of the risks accounted for in the original assessment
of the Pubco prospect. Samson’s total cost for its 25% working interest in the York well was approximately $172,000.
Since this was the first test of three different Glenburn structural closures mapped along the Devonian Prairie Salt dissolution
edge, the remaining two prospects will be highly scrutinized by the Joint Venture to determine if they should still be drilled.
Although there are more prospects to be
drilled in this project area, the joint venture partners have no immediate plans to pursue any further exploration at this point
in time. Costs of $2.3 million with respect to seismic acquisition costs and acreage costs previously capitalized have been expensed
to the Statement of Operations this quarter.
Developed Properties: Drilling
Activities
North Stockyard Oilfield, Williams County,
North Dakota
Mississippian Bakken Formation, Williston
Basin
Bakken & Three Forks infill wells
Samson ~25-30% working interest
On January 1, 2013, we and the operator
group negotiated a non-cash acreage swap for the Middle Bakken/First Bench of the Three Forks (MB/TF), whereby we traded certain
interests in our undeveloped acres in the Southern Tier for these parties’ undeveloped acres in the Northern Tier. As a result
of this acreage swap we owned 64% and 57%, respectively, in the two overlapping 1,280 acre spacing units located in the Northern
Tier. Our net production from current producing wells was not affected. In August 2013, we divested half our equity position in
the undeveloped acreage in the North Stockyard project to Slawson Exploration Company Inc. (“Slawson”) for $5.562 million
in cash and other consideration while retaining our full interest in the currently producing wells in the North Stockyard field.
Slawson is now the operator of the Northern Tier acreage.
Nine Three Forks Formation wells have now
been drilled in the North Stockyard Oilfield. These wells were drilled as 8,000 foot laterals in a west-east orientation. Multistage
hydraulic fracturing operations have been completed on the Bootleg 4-14-15TFH, Bootleg 5-14-15TFH, Bootleg 6-14-15TFH, Bootleg
7-14-15TFH and Bootleg 8-14-15TFH wells during the quarter. In January of 2015, the Ironbank 6 & 7 wells were both fracture
stimulated.
The Billabong 2-13-14HBK well was successfully
worked over and the well is scheduled to be fracture stimulated this month.
Rainbow Project, Williams County, North
Dakota
Mississippian Bakken Formation, Williston Basin
Samson 23% and 52% working interest
In 2013, we acquired 656 acres in a 1,255
acre drilling unit and 294 acres in a 1,280 acre drilling unit. Both drilling units are located in the Rainbow Project, Williams
County, North Dakota. The Rainbow Project is located in Sections 17, 18, 19 and 20 in T158N R99W.
Samson acquired the net acres in the Rainbow
Project from the vendor as part of an acreage trade and is obligated provide a $1 million carry (10% of expected costs to drill
and complete the first well) to the vendor, for the first development well to be drilled in the Rainbow Project.
Samson has assessed the project based on
offset well data and believes that the project will support 16 wells, 8 in the middle Bakken and 8 in the first bench of the Three
Forks. These wells would be expected to be configured as north-south orientated 10,000 foot horizontals.
In the western drilling unit of the acquired
acreage, Samson holds a 52% working interest. In the eastern drilling unit, Samson’s interest is 23%. Continental Resources
has been designated as Operator, due to their larger working interest.
The first well in this project area, the
Gladys 1-20H well (23% working interest), has been drilled and completed. During the quarter the Gladys 1-20H well produced 24,390
barrels of oil (gross). This well is the first in the Rainbow project and is expected to support a drilling program of up to 14
wells, comprised of 8 wells in the middle Bakken and 6 in the Three Forks. Despite having an extensive drilling inventory in this
project, Samson has no further drilling planned until there is a sustained recovery in oil prices.
Developed Properties: Production
Activities
North Stockyard Oilfield, Williams
County, North Dakota
Mississippian Bakken Formation, Williston
Basin
Samson various working interests
We have seventeen producing wells in the
North Stockyard Field. These wells are located in Williams County, North Dakota, in Township 154N Range 99W.
The Harstad #1-15H well (34.5% working
interest) was shut in for 90 days during the quarter due to downhole problems and production activities on offset wells. Cumulative
gross production to December 31, 2014 was approximately 94 Mbbls.
The Leonard #1-23H well (10% working interest,
37.5% after non-consent penalty) was down for 12 days during the quarter due to an electrical malfunction. The well averaged
37 BOPD and 67 Mcf/D during the quarter. Cumulative gross production to December 31, 2014 was approximately 129 Mbbls and 142 MMcf.
The Gene #1-22H well (30.6% working interest)
was down for approximately 1 day during the quarter due to an electrical malfunction. The well produced at an average daily rate
of 60 BOPD and 108 Mcf/D during the quarter. Cumulative gross production to December 31, 2014 was approximately 182 Mbbls and 222
MMcf.
The Gary #1-24H (37% working interest)
well was down for for the entire quarter due to offset production activity. Cumulative gross production to December 31, 2014 was
approximately 180 Mbbls and 285 MMcf.
The Rodney #1-14H (27% working interest)
well was down for the entire quarter due to planned shut-in periods while completing the offset wells. Cumulative gross production
to December 31, 2014 was approximately 139 Mbbls and 195 MMcf.
The Earl #1-13H (32% working interest)
well was down for the entire quarter due to planned shut-in periods while completing the offset wells. Cumulative gross production
to September 30, 2014 was approximately 225 Mbbls and 327 MMcf.
The Everett #1-15H (26% working interest)
well was down for 24 days during the quarter due to planned shut in periods while completing the offset wells. The Everett well
produced at an average daily rate of 366 BOPD and 519 Mcf/D during the quarter. Cumulative gross production to December 31, 2014
was approximately 159 Mbbls and 211 MMcf.
The Sail & Anchor 4-13-14HBK well was
down for the entire quarter due to planned shut in periods while completing offset wells. Cumulative gross production to December
31, 2014 was approximately 55 Mbbls and 32 MMcf.
The Coopers 1-23-13HBK well was down for
64 days during the quarter due to planned shut in periods while completing offset wells. The well averaged 78 BOPD during the quarter.
Cumulative gross production to December 31, 2014 was 54 Mbbls.
The Little Creature 1- 15-14H well was
down for the entire quarter due to planned shut in periods while completing offset wells. Cumulative gross production to December
31, 2014 was 73 Mbbls.
The Tooheys 4-15-14HBK well was down for
58 days during the quarter due to planned shut in periods while completing offset wells. The well averaged 110 BOPD during the
quarter. Cumulative gross production to December 31, 2014 was 68 Mbbls
The Blackdog 3-13-14HBK well was down for
the entire quarter due to planned shut in periods while completing offset wells. Cumulative gross production to December 31, 2014
was 110 Mbbls and 77 MMcf.
The Matilda Bay 1-15HBK well (32.97% working interest) was down
for 29 days during the quarter due to planned shut in periods while completing offset wells. The well averaged 113 BOPD and 83
Mcf/D during the quarter. Cumulative gross production to December 31, 2014 was 110 Mbbls and 7 MMcf.
The Matilda Bay 2-15HBK well (32.97% working interest) was down
for 48 days during the quarter due to planned shut in periods while completing offset wells. The well averaged 46 BOPD and 119
Mcf/D during the quarter. Cumulative gross production to December 31, 2014 was 30 Mbbls and 3 MMcf.
The Bootleg 4-14-15TFH well was down for
19 days during the quarter due to Ironbank 6 & 7 operations. During the quarter it averaged 449 BOPD. Cumulative gross production
to December 31, 2014 was 55 Mbbls.
The Bootleg 5-14-15TFH well was down for
26 days during the quarter due to Ironbank 6 & 7 operations. During the quarter it averaged 411 BOPD. Cumulative gross production
to December 31, 2014 was 48 Mbbls.
The Bootleg 7-14-15TFH well was successfully
fracture stimulated during the quarter, however flowback operations have been delayed while offset activities continue on offset
wells.
The Bootleg 8-14-15TFH well was successfully
fracture stimulated during the quarter, however flowback operations have been delayed while offset activities continue on offset
wells.
Sabretooth Gas Field, Brazoria County
Texas
Oligocene Vicksburg Formation, Gulf
Coast Basin
Samson 9.375% working interest
Production for the Davis Bintliff #1 well
averaged 2.7 MMcf/d and 24 BOPD for the quarter. Cumulative production to December 31, 2014 is approximately 7.8 billion standard
cubic feet and 84.7 Mbbls.
All production amounts above indicate
gross production, rather than only the production attributable to our respective working interest for each well. See “Results
of Operations” below for the total production volumes attributed to Samson during the quarter.
Results of Operations
For the three months ended December 31,
2014, we reported a net loss of $2.5 million compared to a net loss of $1.4 million for the 2013 period.
For the six months ended December 31, 2014
we reported a net loss of $13.5 million compared to a net loss of $0.5 million for the 2013 period.
The following tables sets forth selected
operating data for the three months and six months ended respectively:
| |
Three months ended | |
| |
31-Dec-14 | | |
31-Dec-13 | | |
30-Sep-14 | |
Production Volume | |
| | | |
| | | |
| | |
Oil (Bbls) | |
| 43,653 | | |
| 12,788 | | |
| 35,613 | |
Natural gas (Mcf) | |
| 39,043 | | |
| 42,990 | | |
| 46,942 | |
BOE (based on one barrel of oil to six Mcf of natural gas) | |
| 50,160 | | |
| 19,953 | | |
| 43,437 | |
| |
| | | |
| | | |
| | |
Sales Price | |
| | | |
| | | |
| | |
Realised Oil ($/Bbls) | |
$ | 58.14 | | |
$ | 84.62 | | |
$ | 84.33 | |
Impact of settled derivative instruments | |
$ | 9.69 | | |
$ | 0.00 | | |
$ | 1.27 | |
Derivative adjusted price | |
$ | 67.83 | | |
$ | 84.62 | | |
$ | 85.60 | |
| |
| | | |
| | | |
| | |
Realised Gas ($/Mcf) | |
$ | 3.82 | | |
$ | 4.71 | | |
$ | 5.43 | |
| |
| | | |
| | | |
| | |
Expense per BOE: | |
| | | |
| | | |
| | |
Lease operating expenses | |
$ | 24.17 | | |
$ | 22.06 | | |
$ | 24.83 | |
Production and property taxes | |
$ | 5.97 | | |
$ | 7.35 | | |
$ | 8.78 | |
Depletion, depreciation and amortization | |
$ | 22.30 | | |
$ | 20.94 | | |
$ | 21.99 | |
General and administrative expense | |
$ | 25.14 | | |
$ | 84.15 | | |
$ | 27.89 | |
| |
Six months ended | |
| |
31-Dec-14 | | |
31-Dec-13 | |
Production Volume | |
| | | |
| | |
Oil (Bbls) | |
| 78,517 | | |
| 25,424 | |
Natural gas (Mcf) | |
| 85,588 | | |
| 80,972 | |
BOE | |
| 92,782 | | |
| 38,919 | |
| |
| | | |
| | |
Sales Price | |
| | | |
| | |
Realised Oil ($/Bbls) | |
$ | 70.57 | | |
$ | 92.01 | |
Impact of settled derivative instruments | |
$ | 5.96 | | |
$ | 0.00 | |
| |
$ | 76.53 | | |
$ | 92.01 | |
| |
| | | |
| | |
Gas ($/Mcf) | |
$ | 4.72 | | |
$ | 4.26 | |
| |
| | | |
| | |
Expense per BOE: | |
| | | |
| | |
Lease operating expenses | |
$ | 24.69 | | |
$ | 23.67 | |
Production and property taxes | |
$ | 7.34 | | |
$ | 7.98 | |
Depletion, depreciation and amortization | |
$ | 22.35 | | |
$ | 22.66 | |
General and administrative expense | |
$ | 26.64 | | |
$ | 84.33 | |
The following table sets forth results
of operations for the following periods:
| |
Three months ended | | |
Three months ended | |
| |
31-Dec-14 | | |
31-Dec-13 | | |
2Q15 to 2Q14 change | | |
30-Sep-14 | | |
2Q15 to 1Q15 Change | |
Oil sales | |
$ | 2,538,100 | | |
$ | 1,082,154 | | |
$ | 1,455,946 | | |
$ | 3,003,145 | | |
$ | (465,045 | ) |
Gas sales | |
| 148,953 | | |
| 202,658 | | |
| (53,705 | ) | |
| 255,050 | | |
| (106,097 | ) |
Other liquids | |
| - | | |
| 627 | | |
| (627 | ) | |
| - | | |
| - | |
Interest income | |
| 9,884 | | |
| 86,853 | | |
| (76,969 | ) | |
| 9,639 | | |
| 245 | |
Gain on derivative instruments | |
| 2,306,135 | | |
| - | | |
| 2,306,135 | | |
| 781,570 | | |
| 1,524,565 | |
Gain on sale of oil and gas properties | |
| - | | |
| - | | |
| - | | |
| - | | |
| - | |
Other | |
| 6,561 | | |
| 85 | | |
| 6,476 | | |
| 211 | | |
| 6,350 | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Lease operating expense | |
| (1,512,195 | ) | |
| (586,926 | ) | |
| (925,269 | ) | |
| (1,459,922 | ) | |
| (52,273 | ) |
Depletion, depreciation and amortization | |
| (1,118,619 | ) | |
| (417,723 | ) | |
| (700,896 | ) | |
| (955,061 | ) | |
| (163,558 | ) |
Impairment | |
| (3,027,288 | ) | |
| - | | |
| (3,027,288 | ) | |
| (33,396 | ) | |
| (2,993,892 | ) |
Abandonment expense | |
| (79,036 | ) | |
| - | | |
| (79,036 | ) | |
| (135,767 | ) | |
| 56,731 | |
Exploration and evaluation expenditure | |
| (362,540 | ) | |
| (51,669 | ) | |
| (310,871 | ) | |
| (11,103,416 | ) | |
| 10,740,876 | |
Accretion of asset retirement obligations | |
| (8,418 | ) | |
| (17,117 | ) | |
| 8,699 | | |
| (7,923 | ) | |
| (495 | ) |
Interest expense | |
| (147,343 | ) | |
| - | | |
| (147,343 | ) | |
| (33,160 | ) | |
| (114,183 | ) |
Amortisation of borrowing costs | |
| (31,972 | ) | |
| - | | |
| (31,972 | ) | |
| (83,942 | ) | |
| 51,970 | |
General and administrative | |
| (1,260,793 | ) | |
| (1,679,066 | ) | |
| 418,273 | | |
| (1,211,279 | ) | |
| (49,514 | ) |
Income tax benefit | |
| - | | |
| - | | |
| - | | |
| - | | |
| - | |
Net loss | |
$ | (2,538,571 | ) | |
$ | (1,380,124 | ) | |
$ | (1,158,447 | ) | |
$ | (10,974,251 | ) | |
$ | 8,435,680 | |
| |
Six months ended | | |
| |
| |
31-Dec-14 | | |
31-Dec-13 | | |
2Q15
to 2Q14 change | |
Oil sales | |
$ | 5,541,245 | | |
$ | 2,339,144 | | |
$ | 3,202,101 | |
Gas sales | |
| 404,003 | | |
| 344,604 | | |
| 59,399 | |
Other liquids | |
| - | | |
| 627 | | |
| (627 | ) |
Interest income | |
| 19,523 | | |
| 101,298 | | |
| (81,775 | ) |
Gain on derivative instruments | |
| 3,087,705 | | |
| - | | |
| 3,087,705 | |
Gain on sale of oil and gas properties | |
| - | | |
| 2,524,411 | | |
| (2,524,411 | ) |
Other | |
| 6,772 | | |
| 184 | | |
| 6,588 | |
| |
| | | |
| | | |
| - | |
Lease operating expense | |
| (2,972,117 | ) | |
| (1,231,676 | ) | |
| (1,740,441 | ) |
Depletion, depreciation and amortization | |
| (2,073,680 | ) | |
| (881,805 | ) | |
| (1,191,875 | ) |
Impairment | |
| (3,060,684 | ) | |
| (83,121 | ) | |
| (2,977,563 | ) |
Abandonment expense | |
| (214,803 | ) | |
| - | | |
| (214,803 | ) |
Exploration and evaluation expenditure | |
| (11,465,956 | ) | |
| (319,374 | ) | |
| (11,146,582 | ) |
Accretion of asset retirement obligations | |
| (16,341 | ) | |
| (32,813 | ) | |
| 16,472 | |
Interest expense | |
| (231,285 | ) | |
| - | | |
| (231,285 | ) |
Amortisation of borrowing costs | |
| (65,132 | ) | |
| - | | |
| (65,132 | ) |
General and administrative | |
| (2,472,072 | ) | |
| (3,282,109 | ) | |
| 810,037 | |
Income tax (provision)/ benefit | |
| - | | |
| - | | |
| - | |
Net loss | |
$ | (13,512,822 | ) | |
$ | (520,630 | ) | |
$ | (12,992,192 | ) |
Three Months Comparison of Quarter Ended
December 31, 2014 to Quarter Ended December 31, 2013 and Six Month Comparison of the Period Ended December 31, 2014 to the Period
Ended December 31, 2013.
Oil and gas revenues
Oil revenues increased from $1.1 million
for the three months ended December 31, 2013 to $2.5 million for the three months ended December 31, 2014, as a result of increased
production in our North Stockyard project following the commencement of production from ten new wells in this project area during
the period from January 1, 2014 to December 31, 2014. Oil production increased from 12,788 barrels for the three months ended December
31, 2013 to 43,653 for the three months ended December 31, 2014. The realized oil price decreased from $84.62 per Bbl for the three
months ended December 31, 2013 to $58.14 per Bbl (excluding the impact of derivatives) for the three months ended December 31,
2014 following a decrease in global oil prices.
Oil revenues increased from $2.3 million
for the six months ended December 31, 2013 to $5.5 million for the six months ended December 31, 2014, as a result of increased
production in our North Stockyard project following the commencement of production from ten new wells in this project area. Oil
production increased from 25,424 barrels for the six months ended December 31, 2013 to 78,517 for the six months ended December
31, 2014. The realized oil price decreased from $92.01 per Bbl for the six months ended December 31, 2013 to $70.57 per Bbl for
the six months ended December 31, 2014 following a decrease in global oil prices.
Gas revenues decreased from $0.2 million
for the three months ended December 31, 2013 to $0.1 million for the three months ended December 31, 2014. Production decreased
from 42,990 Mcf for the quarter ended December 31, 2013 to 39,043 Mcf for the quarter ended December 31, 2014. The realized gas
price also decreased slightly from $4.71 per Mcf for the quarter ended December 31, 2013 to $3.82 per Mcf for the quarter ended
December 31, 2014 due to a general decrease in the price of natural gas.
Gas revenues increased slightly from $0.3
million for the six months ended December 31, 2013 to $0.4 million for the six months ended December 31, 2014. Production increased
slightly from 80,972 Mcf for the six months ended December 31, 2013 to 85,588 Mcf for the six months ended December 31, 2014. The
realized gas price also increased from $4.26 per Mcf for the six months ended December 31, 2013 to $4.72 per Mcf for the six months
ended December 31, 2014 due to more liquids rich gas coming from our North Stockyard field.
Sale of oil and gas properties
In August 2013, we divested half of our
equity position in the undeveloped acreage in the North Stockyard project to Slawson Exploration Company Inc. for $5.562 million
in cash and other consideration while retaining our full interest in the currently producing wells in the North Stockyard field.
As a consequence of the transaction the rig contract with Frontier was also terminated, without penalty. Slawson is now the operator
of the project and responsible for the development of the remaining undeveloped acreage.
Along with the undeveloped acreage, we
also transferred a 25% working interest in the then drilled but not yet completed, at the time of the sale, Sail and Anchor well,
as well as a 25% working interest in the salt water disposal well and associated water handling facilities drilled in the prior
year in the North Stockyard project. A portion of the purchase price was subject to the delivery of a useable well bore in Billabong,
valued in the agreement at $0.9 million, which was delivered during the quarter ended June 30, 2014.
There were no such sales during the quarter
or six months ended December 31, 2014.
Exploration expense
Exploration expenditures increased from
$0.05 million for the quarter ended December 31, 2013, to $0.4 million for the quarter ended December 31, 2014. Expenditure in
the current period relates to $0.2 million of previously capitalized exploration acreage written off in relation to lease expirations
in our Hawk Springs project area. The remaining funds relate to general exploration expenditure on current and potential exploration
projects.
Exploration expenditure for the six months
ended December 31, 2014 increased to $11.5 million compared to $0.3 million for the six months ended December 31, 2013. $8.1 million
of exploration expenditure relates to previously capitalized exploration costs written off in relation to our Roosevelt project.
Part of this project has been farmed out to Momentus Energy and activities are continuing in this area, however given the recent
decline in oil prices and the exploratory nature of this project, we believe there is substantial doubt over Momentus’s ability
to drill its earn in well. $2.5 million of exploration expenditure relates to previously capitalized exploration costs written
off in relation to our South Prairie project. During the six months ended December 31, 2014, the York 3-9 well was drilled in this
project area at a cost of $0.2 million to us. The well was a dry hole and will be immediately plugged and abandoned. This was the
second dry hole in this project area and no further drilling is planned in the immediate future. $0.3 million was also written
off with respect to value of lease expirations in our Hawk Springs project area.
The expenditure in the prior period relates
to $0.2 million in dry hole costs in relation to the Matson well in the South Prairie project. This well was a dry hole.
Impairment expense
During the three months and six months
ended December 31, 2014 we recognized $3.1 million in impairment expense compared to nil and $0.1 million in the prior comparative
periods. $2.8 million relates to our Rainbow field in North Dakota, while the remaining $0.3 million relates to smaller fields
in Wyoming. The decrease in the value of these properties is a result of the decrease in the future expected oil price. The production
performance of these wells continues to meet expectations. Certain fields, subject to impairment, are carried at fair value at
December 31, 2014.
Abandonment expense
Abandonment expense increased from nil
in the quarter ended December 31, 2013 to $0.1 million during the quarter ended December 31, 2014. The cost in the current period
relate to additional costs associated with abandoning three wells in our Greens Canyon project area in Wyoming. Plugging and abandonment
activities commenced in July 2014 and have been completed. These wells were drilled over 10 years ago and were not economic.
Lease operating expense
Lease operating expenses increased from
$0.6 million for the quarter ended December 31 2013, to $1.5 million for the quarter ended December 31, 2014. The increase is due
to increased production. Costs per BOE increased slightly from $22.06 for the quarter ended December 31, 2013 to $24.17 for the
quarter ended December 31, 2014, excluding production taxes.
Lease operating expenses increased from
$1.2 million for the six months ended December 31 2013, to $3.0 million for the six months ended December 31, 2014. The increase
is due to increased production. Costs per BOE increased slightly from $23.67 for the six months ended December 31, 2013 to $24.69
for the six months ended December 31, 2014.
Depletion, depreciation and amortization
expense
Depletion, depreciation and amortization
expense increased from $0.4 million for the quarter ended December 31, 2013 to $1.1 million for the quarter ended December 31,
2014. The increase in depletion is primarily a result of the increase in the production. The per BOE cost increased slightly from
$20.94 for the three months ended December 31, 2013 to $22.30 for the three months ended December 31, 2014.
Depletion, depreciation and amortization
expense increased from $0.9 million for the six months ended December 31, 2013 to $2.1 million for the six months ended December
31, 2014. The increase in depletion is primarily a result of the increase in the production. The per BOE cost remained consistent
at $22.66 for the six months ended December 31, 2013 to $22.35 for the six months ended December 31, 2014.
General and administrative expense
General and administrative expense decreased
from $1.7 million for the quarter ended December 31, 2013 to $1.3 million for the three months ended December 31, 2014. We have
been actively trying to reduce our general and administrative costs in recent periods. A change in the use of professional service
providers has contributed to the decrease in the general and administrative costs from the prior period.
General and administrative expense decreased
from $3.3 million for the six months ended December 31, 2013 to $2.5 million for the six months ended December 31, 2014. We have
been actively trying to reduce our general and administrative costs in recent periods. A change in the use of professional service
providers has contributed to the decrease in the general and administrative costs from the prior period.
Cash Flows
The table below shows cash flows for the
following periods:
| |
Six months ended | |
| |
31-Dec-14 | | |
31-Dec-13 | |
Cash provided by/(used in) operating activities | |
$ | 801,806 | | |
$ | (1,600,564 | ) |
Cash used in investing activities | |
| (12,733,743 | ) | |
| (11,862,746 | ) |
Cash provided by financing activities | |
| 9,199,273 | | |
| 6,776,246 | |
Cash provided by/(used in) operations changed
from an outflow of $1.6 million for the six months ended December 30, 2013, to a net inflow of $0.8 million for the six months
ended December 31, 2014. Cash receipts from customers increased from $2.5 million for six months ended December 31, 2013 to $7.0
million for the six months ended December 31, 2014, due to an increase in production. Payments to suppliers and employees also
includes $1.0 million in payments made for abandonment operations during the six months ended December 31, 2014 which were not
incurred in prior periods.
Cash used in investing activities increased
from $11.9 million for the six months ended December 31, 2013 to $12.7 million of cash used for the six months ended December 31,
2014. The cash outflow for both periods relates to ongoing drilling activities in our North Stockyard project in North Dakota and
exploration expenditure drilling our Bluff well in the Hawk Springs project.
Cash provided by financing activities increased
from a cash inflow of $6.8 million for the six months ended December 31, 2013, to a cash inflow of $9.2 million for the six months
ended December 31, 2014. Cash inflow for the prior period was a result of the issue of 318,452,166 ordinary shares to raise $7.3
million before expenses. Cash inflow in the current period is a result of the drawdown of borrowings from our credit facility with
Mutual of Omaha.
All options outstanding as at December
31, 2014 are currently out of the money.
Liquidity, Capital Resources and Capital
Expenditures
Our primary use of capital has been acquiring,
developing and exploring oil and natural gas properties and we anticipate this will be our primary use of capital during fiscal
2015 as well.
Our current budget for exploration, exploitation
and development capital expenditures in fiscal 2015 is $18.4 million, of which we incurred approximately $11.8 million during
the first six months of the fiscal year. We were able to make these expenditures, which were required to participate in the drilling
and completion of the first five wells in our North Stockyard infill development program, by using the proceeds from our prior
registered direct offerings, our sale of development acreage to Slawson and drawdowns from our credit facility with Mutual of Omaha
Bank. The remaining $6.6 million in planned capital expenditures, relates to the drilling and completion of 2 additional wells
in our North Stockyard infill project and the payment for the Gladys well in our Rainbow project, also in North Dakota. Due to
the decrease in oil price, we do not have any additional development drilling planned for the immediate future. We are also continuing
to perform analysis work on our Bluff well in our Hawk Springs project.
In January 2014, we entered into a $25
million credit facility with Mutual of Omaha Bank. We drew down the remaining $4.5 million in borrowing base in October 2014. Additional
increases in the borrowing base, up to the credit facility maximum of $25 million may be made available to us in the future depending
on the value of our future reserves. Borrowing base redeterminations are performed by the lender every six months at June and December.
We also have the ability to request a borrowing base redetermination at another period, once a year.
In November 2014, we entered into the First
Amendment to the Company’s Credit Agreement with Mutual of Omaha Bank to increase the borrowing base of the reserve based
lending facility to $19 million, increase the maximum available under the facility to $50 million and decrease the interest rate.
The credit facility includes the following
covenants, which will be tested on a quarterly basis:
| · | Current ratio greater than 1 |
| · | Debt to EBITDAX (annualized) ratio no
greater than 3.5 |
| · | Interest coverage ratio minimum of 2.5
to 1.0 |
The credit facility also includes an annual
cap on general and administrative expenditures of $6,000,000 commencing the twelve months ended December 31, 2014.
For the quarter ended December 31, 2014
we were in breach of our Debt to EBITDAX covenant. Mutual of Omaha have given us a waiver with respect to this breach for the current
period only. We were in compliance with all other covenants.
While we expect to be in compliance with
these covenants based on 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.
The funds drawn from our credit facility
will be used to fund drilling in our North Stockyard project in North Dakota. We expect to fund our remaining capital expenditures
for fiscal 2015 with cash on hand, cash flow from operations, and drawdowns of our credit facility (to the extent available). We
may also elect, where we consider it reasonable and appropriate, to raise funds by the sale of selected assets.
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, 2015, 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 two main sources of liquidity during
the six months ended December 31, 2014 have been cash on hand, which was $3.8 million at December 31, 2014, cash flows from operations,
proceeds from our registered direct offering completed in August 2013, the sale of development acreage to Slawson and the new credit
facility entered into in January 2014. In April 2014, we issued 290,110,820 ordinary shares and 87,033,246 options to raise $5.4
million, before costs.
During the prior three fiscal years, our
three main sources of liquidity were (i) equity issued to raise $21.4 million and (ii) our tax refund of $5.6 million from the
Internal Revenue Service, received in February 2013. During the recent 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 December 31, 2014
decreased from December 31, 2013 largely due to payments for drilling and fracturing activities in our North Stockyard project
in North Dakota.
If future drilling success rates or production
are less than anticipated, the value of our position in affected areas will decline, our results of operations, financial condition
and liquidity will be adversely impacted and we could incur material write-downs of unevaluated properties. See the risk factors
in our Annual Report on Form 10-K for the fiscal year ended June 30, 2014 including “Drilling results in emerging plays,
such as our Hawk Springs and Roosevelt Projects, are subject to heightened risks.” and “Inadequate liquidity could
materially and adversely affect our business operations.” See also Part II, Item 1A of this report below.
Looking Ahead
We plan to focus on two main objectives
in the coming 12 months:
| · | The completion of our remaining two development
wells in one of our Bakken projects - the North Stockyard project in Williams County, North Dakota. |
| · | The continued appraisal and development
of our Hawk Springs project, including multiple conventional targets in the Permian and Pennsylvanian formations. |
Our ability to meet these objectives will
depend on our ability to raise additional capital to fund the planned development programs.
Item 3. Quantitative and Qualitative Disclosures
About Market Risk.
There were no material changes during the
six months ended December 31, 2014 to the disclosure made in our Annual Report on Form 10-K for the year ended June 30, 2014 regarding
this matter.
Item 4. Controls and Procedures.
As of December 31, 2014, 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 December 31, 2014, our disclosure controls and procedures were effective to ensure that the
information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in SEC rules and forms, and that information required to be disclosed
by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal
financial officer, as appropriate, to allow timely decisions regarding required disclosure.
There were no additional changes in our
internal control over financial reporting that occurred during the three months ended December 31 , 2014, that have materially
affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in
our internal control procedures from time to time in the future.
Part II — Other Information
Item 1. Legal Proceedings.
In the ordinary course of our business
we are named from time to time as a defendant in various legal proceedings. We maintain liability insurance and believe
that our coverage is reasonable in view of the legal risks to which our business ordinarily is subject.
Halliburton Dispute
Halliburton Energy Services, Inc., a co-participant
in the Company’s Hawk Springs project, has filed a complaint in Harris County, Texas District Court against Samson USA seeking
unpaid oil revenue attributable to its ownership interest in the Hawk Springs Project, which was approximately $126,000 as of June
5, 2013, and has since increased to approximately $164,000. Samson USA has answered the complaint and has filed counterclaims
against Halliburton arising out of Samson USA’s engagement of Halliburton’s Project Management group in May of 2011
to provide services in connection with its drilling program in Roosevelt County, Montana. In its counterclaims, Samson USA
claims approximately $336,000 from Halliburton on account of Halliburton’s refusal to pay an invoice for demobilization of
the drilling rig used in the Roosevelt project. Samson USA has also asked for a judicial accounting with respect to Halliburton’s
fees and expenses charged to Samson in connection with the Spirit of America well in Goshen County, Wyoming, and the Australia
II, well in Roosevelt County, Wyoming, because of Samson’s discovery of self-dealing and bill padding by Halliburton’s
onsite project manager there. Halliburton has not yet filed an answer to Samson’s counterclaims but the parties are
commencing discovery efforts in the lawsuit. While Samson believes that its counterclaims are meritorious and is confident
that Samson will obtain a net positive recovery from the lawsuit, there can be no assurance as to the ultimate outcome of this
litigation.
Item 1A. Risk Factors.
In addition to the other information set
forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in Part I, Item 1A. “Risk
Factors” in our Annual Report on Form 10-K for the fiscal year ended June 30, 2014. The risks disclosed in our
Annual Report on Form 10-K could materially affect our business, financial condition or future results. The risks described
in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently
known to us or that we currently deem to be immaterial may also materially adversely affect our business, financial condition or
operating results in the future.
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.
Item 5. Other Information.
Not applicable.
Item 6. Exhibits.
Exhibit No. |
|
Title of Exhibit |
|
|
|
10.1 |
|
First Amendment to the Term Loan Credit Agreement among Samson Oil and Gas USA, Inc. as a borrower, Samson Oil & Gas Limited and Samson Oil and Gas Montana, Inc. as guarantors and Mutual of Omaha Bank as lender and administrative agent. |
|
|
|
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 |
|
The following financial information from Samson Oil & Gas Limited’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2014 is formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheet, (ii) Consolidated Statements of Operations, (iii) Consolidated Statement of Changes in Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements. |
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: February 9, 2015 |
By: |
/s/ Terry Barr |
|
|
Terence M. Barr |
|
|
Managing Director, President and Chief Executive Officer (Principal Executive Officer) |
|
|
Date: February 9, 2015 |
By: |
/s/ Robyn Lamont |
|
|
Robyn Lamont |
|
|
Chief Financial Officer (Principal Financial Officer) |
Exhibit 10.1
FIRST AMENDMENT TO CREDIT AGREEMENT
THIS FIRST AMENDMENT TO CREDIT AGREEMENT
(the “First Amendment to Credit Agreement,” or this “Amendment”) is entered into
effective as of November 24, 2014, among SAMSON OIL AND GAS USA, INC., a Colorado corporation (“Borrower”),
and MUTUAL OF OMAHA BANK, as Administrative Agent and L/C Issuer (the “Administrative Agent”), and
the financial institutions executing this Amendment as Lenders.
RECITALS
A. Borrower,
the financial institutions signing as Lenders and Administrative Agent are parties to a Credit Agreement dated as of January 27,
2014 (the “Original Credit Agreement”).
B. The
parties desire to amend the Original Credit Agreement as hereinafter provided.
NOW, THEREFORE, in consideration of these
premises and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties
hereto agree as follows:
1. Same
Terms. All terms used herein which are defined in the Original Credit Agreement shall have the same meanings when used
herein, unless the context hereof otherwise requires or provides. In addition, (i) all references in the Loan Documents to the
“Agreement” shall mean the Original Credit Agreement, as amended by this Amendment, as the same shall hereafter be amended
from time to time, and (ii) all references in the Loan Documents to the “Loan Documents” shall mean the Loan Documents,
as amended by this Amendment, the Modification Papers, as the same shall hereafter be amended from time to time. In addition,
the following terms have the meanings set forth below:
“Effective Date”
means the date when (a) those Lenders comprising the Required Lenders have executed this Amendment, and (b) the conditions set
forth in Section 2 of this Amendment have been complied with to the satisfaction of the Administrative Agent, unless waived
in writing by the Administrative Agent.
“Authorization Certificate”:
See Section 2E.
“First Amendment to Mortgage”:
See Section 2B.
“Guarantor Confirmation Letter”:
See Section 2C.
“Modification Papers”
means this Amendment, the First Amendments to Mortgage, the Guarantor Confirmation Letters, the Security Agreement Confirmation
Letter, the Authorization Certificates, the No Material Adverse Change Certificate, and all of the other documents and agreements
executed in connection with the transactions contemplated by this Amendment.
“No Material Adverse Change Certificate”:
See Section 2F.
“Security Agreement Confirmation Letter”:
See Section 2D.
2. Conditions
Precedent. The obligations, agreements and waivers of Lenders as set forth in this Amendment are subject to the satisfaction
(in the opinion of Administrative Agent), unless waived in writing by Administrative Agent, of each of the following conditions
(and upon such satisfaction, this Amendment shall be deemed to be effective as of the Effective Date):
FIRST AMENDMENT TO CREDIT AGREEMENT– Page 1 |
A. First
Amendment to Credit Agreement. This Amendment shall be in full force and effect.
B. First
Amendment to Mortgage. Borrower shall have executed and delivered to Administrative Agent an amendment to the Oil and
Gas Mortgages (each a “First Amendment to Mortgage”), which shall be in form and substance satisfactory
to Administrative Agent.
C. Guarantor
Confirmation Letters. Each Guarantor shall have executed a letter in favor of Administrative Agent (each a “Guarantor
Confirmation Letter”) confirming that its Guaranty remains in full force and effect.
D. Security
Agreement Confirmation Letter. Borrower shall have executed a letter in favor of Administrative Agent (the “Security
Agreement Confirmation Letter”) confirming that the Security Agreement continues to secure all of the Obligations.
E. Authorization
Certificate. Borrower shall have delivered certificate appropriate Loan Parties (each an “Authorization Certificate”)
satisfactory in form and substance to Administrative Agent authorizing the execution, delivery and performance of the Modification
Papers to which it is a party.
F. Representations
and Warranties. Administrative Agent shall have received a certificate (the “No Material Adverse Change Certificate”)
to the effect that all representations and warranties contained herein or in the other Modification Papers or otherwise made in
writing in connection herewith or therewith shall be true and correct in all material respects (provided that any such representations
or warranties that are, by their terms, already qualified by reference to materiality shall be true and correct without regard
to such materiality standard) with the same force and effect as though such representations and warranties have been made on and
as of the Effective Date, or if made as of a specific date, as of such date.
G. Opinion
of Counsel. There shall have been delivered a favorable opinion of counsel of Borrower and each other Loan Party covering
such matters incident to the Modification Papers as Administrative Agent may reasonably request.
H. Borrowing
Base Increase Fee. Administrative Agent shall have received payment of a fee for the increase of the Borrowing Base described
below in the amount of $35,000.
I. Mortgage
and Title Coverage. (i) Borrower shall have mortgaged to Administrative Agent such additional oil and gas properties so
as to comply with the 80% mortgage coverage requirements required by Section 2.13(a) of the Original Credit Agreement, and (ii)
Borrower shall have provided Administrative Agent with title data acceptable to Administrative Agent so as to comply with the
80% title coverage requirements of Section 2.13(b) of the Original Credit Agreement.
J. Fees
and Expenses. Administrative Agent shall have received payment of all out-of-pocket fees and expenses (including reasonable
attorneys’ fees and expenses) incurred by Administrative Agent in connection with the preparation, negotiation and execution of
the Modification Papers.
FIRST AMENDMENT TO CREDIT AGREEMENT– Page 2 |
3. Amendments
to Original Credit Agreement. On the Effective Date, the Original Credit Agreement shall be deemed to be amended as follows:
(a) Clause
(b) of the definition of “Applicable Rate” in Section 1.01 of the Original Credit Agreement shall be amended to read
in its entirety as follows:
“(b) with
respect to Eurodollar Rate Loans and Letters of Credit, 3.25%; and”
(b) Section
8.07 of the Original Credit Agreement shall be amended to read in its entirety as follows:
“8.07. Limitation on
General and Administrative Expenses. Permit Borrower’s general and administrative expenses for the operation of all of
its oil and gas properties (either direct or payable to outside operators or agents) as determined in accordance with COPAS accounting
procedures, and all salaries, bonuses, withdrawals, distributions, consulting and professional fees other than expenses of Borrower’s
exploratory staff and other forms of compensation, and all other overhead, to exceed $6,000,000 per calendar year beginning with
the twelve months ended December 31, 2014 (for avoidance of doubt, expenses of Borrower’s exploratory staff are not subject
to this covenant) .”
(c) Schedule
2.01 attached to the original Credit Agreement is hereby replaced with Schedule 2.01 attached to this Amendment.
4. Increase
of Borrowing Base. On the Effective Date, the Borrowing Base is hereby increased from $15,500,000 to $19,000,000. The
Borrowing Base, as adjusted, will remain in effect until next adjusted but pursuant to the provisions of Article IV of
the Original Credit Agreement.
5. Certain
Representations. Borrower represents and warrants that, as of the Effective Date: (a) each Loan Party has full power and
authority to execute the Modification Papers to which it is a party and such Modification Papers constitute the legal, valid and
binding obligation of such Loan Party enforceable in accordance with their terms, except as enforceability may be limited by general
principles of equity and applicable bankruptcy, insolvency, reorganization, moratorium, and other similar laws affecting the enforcement
of creditors’ rights generally; and (b) no authorization, approval, consent or other action by, notice to, or filing with, any
governmental authority or other person is required for the execution, delivery and performance by each Loan Party thereof. In
addition, Borrower represents that after giving effect to this Amendment all representations and warranties contained in the Original
Credit Agreement and the other Loan Documents are true and correct in all material respects (provided that any such representations
or warranties that are, by their terms, are requalified by reference to materiality shall be true and correct without regard to
such materialty standard) on and as of the Effective Date as if made on and as of such date except to the extent that any such
representation or warranty expressly relates solely to an earlier date, in which case such representation or warranty is true
and correct in all material respects (or true and correct without regard to such materiality standard, as applicable) as of such
earlier date.
6. No
Further Amendments. Except as previously amended in writing or as amended hereby, the Original Credit Agreement shall
remain unchanged and all provisions shall remain fully effective between the parties.
FIRST AMENDMENT TO CREDIT AGREEMENT– Page 3 |
7. Acknowledgments
and Agreements. Borrower acknowledges that on the date hereof all outstanding Obligations are payable in accordance with
their terms, and Borrower waives any defense, offset, counterclaim or recoupment with respect thereto. Borrower, Administrative
Agent, L/C Issuer and each Lender do hereby adopt, ratify and confirm the Original Credit Agreement, as amended hereby,
and acknowledge and agree that the Original Credit Agreement, as amended hereby, is and remains in full force and effect. Borrower
acknowledges and agrees that its liabilities and obligations under the Original Credit Agreement, as amended hereby, and under
the other Loan Documents, are not impaired in any respect by this Amendment. Any breach of any representations, warranties and
covenants under this Amendment shall be Default or an Event of Default, as applicable, under the Original Credit Agreement.
8. Limitation
on Agreements. The modifications set forth herein are limited precisely as written and shall not be deemed (a) to be a
consent under or a waiver of or an amendment to any other term or condition in the Original Credit Agreement or any of the Loan
Documents, or (b) to prejudice any right or rights that Administrative Agent now has or may have in the future under or in connection
with the Original Credit Agreement and the other Loan Documents, each as amended hereby, or any of the other documents referred
to herein or therein. The Modification Papers shall constitute Loan Documents for all purposes.
9. Confirmation
of Security. Borrower hereby confirms and agrees that all of the Collateral Documents that presently secure the Obligations
shall continue to secure, in the same manner and to the same extent provided therein, the payment and performance of the Obligations
as described in the Original Credit Agreement as modified by this Amendment.
10. Counterparts.
This Amendment may be executed in any number of counterparts, each of which when executed and delivered shall be deemed an original,
but all of which constitute one instrument. In making proof of this Amendment, it shall not be necessary to produce or account
for more than one counterpart thereof signed by each of the parties hereto.
11. Incorporation
of Certain Provisions by Reference. The provisions of Section 11.15 of the Original Credit Agreement captioned “Governing
Law, Jurisdiction; Etc.” and Section 11.16 of the Original Credit Agreement captioned “Waiver of Right to Trial by
Jury” are incorporated herein by reference for all purposes.
12. Entirety,
Etc. This Amendment and the other Modification Papers and all of the other Loan Documents embody the entire agreement
between the parties. THIS AMENDMENT AND ALL OF THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY
NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN
ORAL AGREEMENTS AMONG THE PARTIES.
[This space
is left intentionally blank. Signature pages follow.]
FIRST AMENDMENT TO CREDIT AGREEMENT– Page 4 |
IN WITNESS
WHEREOF, the parties hereto have executed this Amendment to be effective as of the date and year first above written.
|
BORROWER |
|
|
|
SAMSON
OIL AND GAS USA, INC. |
|
|
|
By:
|
/s/
Terry Barr |
|
|
Terry Barr |
|
|
President, Treasurer and CEO |
FIRST AMENDMENT TO CREDIT AGREEMENT– Signature Page |
|
ADMINISTRATIVE
AGENT |
|
|
|
MUTUAL
OF OMAHA BANK,
as
Administrative Agent |
|
|
|
|
By:
|
/s/
Edward M. Fenk |
|
|
Edward M. Fenk |
|
|
Manager, Energy
Lending |
|
|
|
|
LENDER |
|
|
|
MUTUAL
OF OMAHA BANK |
|
|
|
|
By:
|
/s/
Edward M. Fenk |
|
|
Edward M. Fenk |
|
|
Manager, Energy
Lending |
FIRST AMENDMENT TO CREDIT AGREEMENT– Signature Page |
SCHEDULE 2.01
APPLICABLE PERCENTAGES, MAXIMUM CREDIT
AMOUNTS,
and ALLOCATIONS OF INITIAL BORROWING
BASE
| |
Applicable | | |
Maximum Credit | | |
Allocation of | |
Lender | |
Percentage | | |
Amount | | |
Borrowing Base | |
| |
| | |
| | |
| |
Mutual of Omaha Bank | |
| 100.000000000 | % | |
$ | 50,000,000 | | |
$ | 19,000,000 | |
| |
| | | |
| | | |
| | |
Total | |
| 100.000000000 | % | |
$ | 50,000,000 | | |
$ | 19,000,000 | |
SCHEDULE 2.01 – Solo Page |
EXHIBIT 31.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Terence M. Barr, certify that:
| 1. | I have reviewed this Quarterly Report on Form 10-Q of Samson Oil & Gas Limited; |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or
omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this
report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as
of, and for, the periods presented in this report; |
| 4. | The company’s other certifying officer and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have: |
| (a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
| (b) | Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
| (c) | Evaluated the effectiveness of the company’s disclosure controls and procedures and presented
in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and |
| (d) | Disclosed in this report any change in the company’s internal control over financial reporting
that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially
affect, the company’s internal control over financial reporting; and |
| 5. | The company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or
persons performing the equivalent functions): |
| (a) | All significant deficiencies and material weaknesses in the design or operation of internal control
over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize
and report financial information; and |
| (b) | Any fraud, whether or not material, that involves management or other employees who have a significant
role in the company’s internal control over financial reporting. |
/s/ Terry Barr |
|
Terence M. Barr |
|
Managing Director, President and Chief Executive Officer |
|
February 9, 2015 |
|
EXHIBIT 31.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Robyn Lamont, certify that:
| 1. | I have reviewed this Quarterly Report on Form 10-Q of Samson Oil & Gas Limited; |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or
omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this
report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as
of, and for, the periods presented in this report; |
| 4. | The company’s other certifying officer and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have: |
| (a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
| (b) | Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
| (c) | Evaluated the effectiveness of the company’s disclosure controls and procedures and presented
in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and |
| (d) | Disclosed in this report any change in the company’s internal control over financial reporting
that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially
affect, the company’s internal control over financial reporting; and |
| 5. | The company’s other certifying officer and I have disclosed, based on our most recent evaluation
of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board
of directors (or persons performing the equivalent functions): |
| (a) | All significant deficiencies and material weaknesses in the design or operation of internal control
over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize
and report financial information; and |
| (b) | Any fraud, whether or not material, that involves management or other employees who have a significant
role in the company’s internal control over financial reporting. |
/s/ Robyn Lamont |
|
Robyn Lamont |
|
Chief Financial Officer |
|
February 9, 2015 |
|
EXHIBIT 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY
ACT OF 2002
Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States
Code), the undersigned officers of Samson Oil & Gas Limited (the “Company”), do hereby certify, to such officer’s
knowledge, that:
(1) The
Quarterly Report on Form 10-Q for the quarter ended December 31, 2014 (the “Report”) fully complies with the requirements
of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The
information contained in the Report fairly presents, in all material respects, the financial condition and results of operations
of the Company.
/s/ Terry Barr |
|
Terence M. Barr |
|
President, Chief Executive Officer and Managing Director |
|
February 9, 2015 |
|
|
|
/s/ Robyn Lamont |
|
Robyn Lamont |
|
Chief Financial Officer |
|
February 9, 2015 |
|