March 31, 2014
(Stated in U.S. Dollars)
1. BASIS OF PRESENTATION
The unaudited consolidated financial statements as of March 31, 2014 included herein have been prepared without audit pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with United States generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. It is suggested that these consolidated financial statements be read in conjunction with the December 31, 2013 audited consolidated financial statements and notes thereto. The results of the operations for the three months ended March 31, 2014 are not indicative of the results that may be expected for the year.
2. OPERATIONS
Delta Oil & Gas, Inc. (“the Company”) was incorporated as a Colorado corporation on January 9, 2001.
The Company is an independent natural gas and oil company engaged in the exploration, development, and acquisition of natural gas and oil properties in the United States and Canada. The Company’s entry into the natural gas and oil business began on February 8, 2001.
Natural gas and oil exploration and production is a speculative business, and involves a high degree of risk. Among the factors that have a direct bearing on the Company’s prospects are uncertainties inherent in estimating natural gas and oil reserves, future hydrocarbon production, and cash flows, particularly with respect to wells that have not been fully tested and with wells having limited production histories; access to additional capital; changes in the price of natural gas and oil; availability and cost of services and equipment; and the presence of competitors with greater financial resources and capacity.
The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial costs from environmental accidents or events for which the Company may be currently liable. In addition, the Company’s oil and gas business makes it vulnerable to changes in prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on current oil and gas prices and estimated probable reserves. Price declines reduce the estimated quantity of proved and probable reserves and increase annual depletion expense (which is based on proved and probable reserves).
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern.
As shown in the accompanying consolidated financial statements, the Company has incurred a net loss of $7,397,154 since inception. To achieve profitable operations, the Company requires additional capital for obtaining producing oil and gas properties through either the purchase of producing wells or successful exploration activity. Management believes that sufficient funding will be available to meet its business objectives including anticipated cash needs for working capital and is currently evaluating several financing options. However, there can be no assurance that the Company will be able to obtain sufficient funds to continue the development of its properties and, if successful, to commence the sale of its projects under development. As a result of the foregoing, there exists substantial doubt about the Company’s ability to continue as a going concern. These consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
Delta Oil & Gas, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2014
(Stated in U.S. Dollars)
3. SIGNIFICANT ACCOUNTING POLICIES
a)
Basis of Consolidation
The consolidated financial statements are presented in accordance with accounting principles generally accepted in the United States and include the financial statements of the Company and its wholly-owned subsidiary, Delta Oil & Gas (Canada) Inc. All significant inter-company balances and transactions have been eliminated.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved natural gas and oil reserve quantities and the related present value of estimated future net cash flows there from.
c)
Natural Gas and Oil Properties
The Company accounts for its oil and gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (“SEC”). Accordingly, all costs associated with the acquisition of properties and exploration with the intent of finding proved oil and gas reserves contribute to the discovery of proved reserves, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. All general corporate costs are expensed as incurred. In general, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded. Amortization of evaluated oil and gas properties is computed on the units of production method based on all proved reserves on a country-by-country basis. The net capitalized costs of evaluated oil and gas properties (full cost ceiling limitation) are not to exceed their related estimated future net revenues from proved reserves discounted at 10%, and the lower of cost or estimated fair value of unproved properties, net of tax considerations. These properties are included in the amortization pool immediately upon the determination that the well is dry.
Unproved properties consist of lease acquisition costs and costs on wells currently being drilled on the properties. The recorded costs of the investment in unproved properties are not amortized until proved reserves associated with the projects can be determined or until they are impaired. Unevaluated oil and gas properties are assessed at least annually for impairment either individually or on an aggregate basis.
d)
Asset Retirement Obligations
The Company has adopted “Accounting for Asset Retirement Obligations” of the FASB Accounting Standards Codification, which requires that asset retirement obligations (“ARO”) associated with the retirement of a tangible long-lived asset, including natural gas and oil properties, be recognized as liabilities in the period in which it is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated assets. The cost of tangible long-lived assets, including the initially recognized ARO, is depleted, such that the cost of the ARO is recognized over the useful life of the assets. The ARO is recorded at fair value, and accretion expense is recognized over time as the discounted cash flows are accreted to the expected settlement value. The fair value of the ARO is measured using expected future cash flow discounted at the Company’s credit-adjusted risk-free interest rate.
e)
Oil and Gas Joint Ventures
All exploration and production activities are conducted jointly with others and, accordingly, the accounts reflect only the Company’s proportionate interest in such activities.
Delta Oil & Gas, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2014
(Stated in U.S. Dollars)
3. SIGNIFICANT ACCOUNTING POLICIES (continued)
Revenue from sales of crude oil, natural gas and refined petroleum products are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customers. Title transfers for crude oil, natural gas and bulk refined products generally occur at pipeline custody points or when a tanker lifting have occurred. Revenues from the production of oil and natural gas properties in which the Company shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period. Gas imbalances occur when the Company’s actual sales differ from its entitlement under existing working interests. The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that the partners can recoup their share of production from the field. As at March 31, 2014 and 2013, the Company had no overproduced imbalances.
g)
Cash and Cash Equivalent
Cash consists of cash on deposit with high quality major financial institutions, and to date, the Company has not experienced losses on any of its balances. The carrying amounts approximated fair market value due to the liquidity of these deposits. For purposes of the balance sheet and statements of cash flows, the Company considers all highly liquid instruments with maturity of three months or less at the time of issuance to be cash equivalents.
h) Restricted Cash
Restricted cash consists of funds deposited in a trust account for the Texas Prospect, which can only be used for drilling and completion costs associated with the first, second, third and fourth well that are being drilled at this location.
i) Concentration of Credit Risk
Financial instruments which potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents and accounts receivable. The Company maintains cash at two financial institutions. The Company periodically evaluates the credit worthiness of financial institutions, and maintains cash accounts only in large high quality financial institutions, thereby minimizing exposure for deposits in excess of federally insured amounts. The Company believes credit risk associated with cash and cash equivalents to be minimal.
The Company has recorded trade accounts receivable from the business operations. Management periodically evaluates the collectability of the trade receivables and believes that the Company’s receivables are fully collectable and that the risk of loss is minimal.
j) Environmental Protection and Reclamation Costs
The operations of the Company have been, and may in the future be affected from time to time in varying degrees by changes in environmental regulations, including those for future removal and site restorations costs. Both the likelihood of new regulations and their overall effect upon the Company may vary from region to region and are not predictable.
The Company’s policy is to meet or, if possible, surpass standards set by relevant legislation, by application of technically proven and economically feasible measures. Environmental expenditures that relate to ongoing environmental and reclamation programs will be charged against statements of operations as incurred or capitalized and amortized depending upon their future economic benefits. The Company does not currently anticipate any material capital expenditures for environmental control facilities because all property holdings are at early stages of exploration. Therefore, estimated future removal and site restoration costs are presently considered minimal.
Delta Oil & Gas, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2014
(Stated in U.S. Dollars)
3. SIGNIFICANT ACCOUNTING POLICIES (continued)
k)
Foreign Currency Translation
United States funds are considered the Company’s functional currency. Transaction amounts denominated in foreign currencies are translated into their United States dollar equivalents at exchange rates prevailing at the transaction date. Monetary assets and liabilities are adjusted at each balance sheet date to reflect exchange rates prevailing at that date, and non-monetary assets and liabilities are translated at the historical rate of exchange. Gains and losses arising from restatement of foreign currency monetary assets and liabilities at each year-end are included in other comprehensive income/(loss).
Computer equipment is stated at cost. Provision for depreciation on computer equipment is calculated using the straight-line method over an estimated useful life of three years.
m)
Impairment of Long-Lived Assets
In the event that facts and circumstances indicate that the costs of long-lived assets, other than oil and gas properties, may be impaired, an evaluation of recoverability would be performed. If an evaluation is required, the estimated future undiscounted cash flows associated with the asset would be compared to the asset’s carrying amount to determine if a write-down to market value or discounted cash flow value is required. Impairment of oil and gas properties is evaluated subject to the full cost ceiling as described under Natural Oil and Gas Properties.
n)
Income/Loss Per Share
As required by the “Earnings Per Share” Topic of the FASB Accounting Standards Codification, basic and diluted earnings per share are to be presented. Basic earnings per share is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding in the year. Diluted earnings per share takes into consideration common shares outstanding (computed under basic earnings per share) and potentially dilutive common shares.
As the company is reporting net loss in both years, the conversion of options for the calculation of diluted earnings per share would be considered anti-dilutive. The table below presents the computation of basic and diluted earnings per share for the three months ended March 31, 2014 and 2013:
|
|
|
March 31, 2014
|
|
|
March 31, 2013
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted earnings per share computation:
|
|
|
|
|
|
|
|
Loss from continuing operations and net loss
|
|
$
|
(236,585
|
)
|
|
$
|
(155,102
|
)
|
|
Weighted Average Basic shares outstanding
|
|
|
15,193,241
|
|
|
|
14,896,575
|
|
|
Basic and Diluted loss per share
|
|
$
|
(0.02
|
)
|
|
$
|
(0.01
|
)
|
The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax bases of assets and liabilities, and their reported amounts in the financial statements, and (ii) operating loss and tax credit carry forwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period.
Delta Oil & Gas, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2014
(Stated in U.S. Dollars)
3. SIGNIFICANT ACCOUNTING POLICIES (continued)
The FASB Accounting Standards Codification
Financial Instruments requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The standard establishes a fair value hierarchy based on the level of independent, objective evidence surrounding the inputs used to measure fair value. A financial instrument’s categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The standard prioritizes the inputs into three levels that may be used to measure fair value:
Level 1
Level 1 applies to assets or liabilities for which there are quoted prices in active markets for identical assets or liabilities.
Level 2
Level 2 applies to assets or liabilities for which there are inputs other than quoted prices that are observable for the asset or liability such as quoted prices for similar assets or liabilities in active markets; quoted prices for identical assets or liabilities in markets with insufficient volume or infrequent transactions (less active markets); or model-derived valuations in which significant inputs are observable or can be derived principally from, or corroborated by, observable market data.
Level 3
Level 3 applies to assets or liabilities for which there are unobservable inputs to the valuation methodology that are significant to the measurement of the fair value of the assets or liabilities.
The Company’s financial instruments consist of cash and cash equivalent, accounts receivable, prepaid expenses, accounts payable and accrued liabilities and project cost advance received.
It is management’s opinion that the Company is not exposed to significant interest or credit risks arising from these financial instruments. The fair value of these financial instruments is approximate to their carrying values.
q) Comprehensive Loss
Reporting Comprehensive Income Topic of the FASB Accounting Standards Codification establishes standards for the reporting and display of comprehensive loss and its components in the financial statements. The Company is disclosing this information on its Consolidated Statement of Operations and Comprehensive Income.
r) Stock-Based Compensation
The Company records stock-based compensation in accordance with Share-Based Payments of the FASB Accounting Standards Codification, which requires the measurement and recognition of compensation expense based on estimated fair values for all share-based awards made to employees and directors, including stock options.
Shared Based Payments requires companies to estimate the fair value of share-based awards on the date of grant using an option-pricing model. The Company uses the Black-Scholes option-pricing model as its method of determining fair value. This model is affected by the Company’s stock price as well as assumptions regarding a number of subjective variables. These subjective variables include, but are not limited to the Company’s expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise behaviors. The value of the portion of the award that is ultimately expected to vest is recognized as an expense in the statement of operations over the requisite service period.
Delta Oil & Gas, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2014
(Stated in U.S. Dollars)
3. SIGNIFICANT ACCOUNTING POLICIES (continued)
r) Stock-Based Compensation (continued)
All transactions in which goods or services are the consideration received for the issuance of equity instruments are accounted for based on the fair value of the consideration received or the fair value of the equity instrument issued, whichever is more reliably measurable.
4. RECENT ACCOUNTING PRONOUNCEMENTS
On February 5, 2013, the FASB issued ASU 2013-02, which requires entities to disclose the following additional information about items reclassified out of accumulated other comprehensive income (AOCI): (1) changes in AOCI balances by component, (2) significant items reclassified out of AOCI by component either on the face of the income statement or as a separate footnote to the financial statements. For public entities, the ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2012. The adoption of this ASU did not have a material impact on the financial statements.
5. NATURAL GAS AND OIL PROPERTIES
a) Proved Properties
|
Properties
|
|
December 31, 2013
|
|
|
Additions
|
|
|
Disposals
|
|
|
Transfer
from unproved
properties
|
|
|
Depletion
for the period
|
|
|
March 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USA properties
|
|
$
|
347,318
|
|
|
$
|
3,943
|
|
|
$
|
(100,000
|
)
|
|
$
|
339,816
|
|
|
$
|
(155,446
|
)
|
|
$
|
435,631
|
|
a) Proved Properties – Descriptions
Properties in U.S.A.
Joe Murray Farm #1-18
Joe Murray Farm #1-18 started producing in August 2010. At March 31, 2014, the total cost of Joe Murray Farm #1-18 was $67,091. The interests are located in Garvin County, Oklahoma.
ii. Texas Prospect, Texas, USA
On July 15, 2009, the Company successfully obtained the leases on certain lands in Texas, USA. These leases will provide the Company with the ability to drill up to 3 exploration wells. In December 2009, the Company desired to convey a sixty (60%) percent interest in the leases to Hillcrest Resources Ltd and received $111,424 in December 2009.
In August 2010, the first exploration well, Donner #1, started producing. At March 31, 2014, the total cost of Donner #1 was $327,687. During August 2011, the second exploration well, Donner#2, commenced production. At March 31, 2014, the total cost of Donner #2 was $507,530.
In March 2014, the third exploration well, Donner #4, commenced production and the cost of $297,522 was moved to the proved cost pool for depletion.
Delta Oil & Gas, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2014
(Stated in U.S. Dollars)
5. NATURAL GAS AND OIL PROPERTIES (continued)
a)
Proved Properties – Descriptions (continued)
ii. Texas Prospect, Texas, USA (continued)
In conjunction with the secured loan (Note 8), the lender was granted an option to purchase ten percent after payout of the secured loan in and to the Company’s interest in Donner 1, 2 and 4. On March 11, 2014, the option was exercised and $100,000 was received.
iii. King City, California, USA
On May 25, 2009, the Company entered into a Farm-out agreement with Sunset Exploration (“Sunset”) to participate in a drilling and exploration of lands located in California, USA. The Company paid $100,000 to Sunset towards the permitting and processing of lands and the costs of a gravity survey and a 2D seismic program. The Company shall pay 66.67% pro rata share of 100% of all costs associated in the initial test well. If the test well is capable of producing hydrocarbons, then the Company shall pay its working interest pro rata share of all completion costs. The Company’s working interest is 40% of 100% in the Area of Mutual Interest.
On September 2012, the Company received the amount of $300,000 for a 25% working interest in the SBV 2-32 well, which will revert to a 20% working interest after the Sunset penalty payout of 400% as a result of Sunset’s election not to pay its requisite portion of the completion costs related to the well. The purchaser also received a 20% working interest in all additional wells drilled in the area of mutual interest and is subsequently responsible for 25% of the completion costs.
During March 2013, the property was abandoned and the cost of $363,231 was moved to the proven cost pool for depletion.
iv. Premont Northwest Field, USA
On August 20, 2012, the Company acquired its 10% working interest in the Garcia #3 and the continuing development rights in the field with an agreement with Progas Energy Services LLC, a Texas Oil & Gas Company (“Progas”) to jointly develop, the field located in Jim Wells County, Texas, known as the Premont Northwest Field. The Company acquired these interests through the issuance to Progas of 236,134 common shares valued at $35,420 and its pro-rata share of drilling costs, which amount to $49,460. The Company has also paid its pro-rata share of $42,000 for two re-completions.
The well, Laughlin Kibby #1, commenced production October 2013. The cost of $42,293 was moved to the proven cost pool for depletion.
b) Unproved Properties
|
Properties
|
December 31, 2013
|
|
Addition
|
|
Disposals
|
|
Transfer
to proved
properties
|
|
|
March 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USA properties
|
|
$
|
160,738
|
|
|
$
|
263,665
|
|
|
$
|
-
|
|
|
$
|
(339,816
|
)
|
|
$
|
84,587
|
|
c)
Costs not being amortized
The following table sets forth a summary of oil and gas property costs not being amortized at March 31, 2014, by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The majority of the evaluation activities are expected to be completed within five to ten years.
Delta Oil & Gas, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2014
(Stated in U.S. Dollars)
5. NATURAL GAS AND OIL PROPERTIES (continued)
|
|
|
|
Total
|
|
|
2014
|
|
|
2013
|
|
|
2012
|
|
|
2011
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition costs and transfer to proved property pool
|
|
|
$
|
(703,047
|
)
|
|
|
(339,816
|
)
|
|
|
(363,231
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and development
|
|
|
$
|
787,634
|
|
|
|
263,665
|
|
|
|
6,670
|
|
|
|
(77,803
|
)
|
|
|
406,335
|
|
|
|
188,767
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized interest
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
$
|
84,587
|
|
|
|
(76,151
|
)
|
|
|
(356,561
|
)
|
|
|
(77,803
|
)
|
|
|
406,335
|
|
|
|
188,767
|
|
6.
NATURAL GAS AND OIL EXPLORATION RISK
a)
Exploration Risk
The Company’s future financial condition and results of operations will depend upon prices received for its natural gas and oil production and the cost of finding, acquiring, developing and producing reserves. Substantially all of its production is sold under various terms and arrangements at prevailing market prices. Prices for natural gas and oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond its control. Other factors that have a direct bearing on the Company’s prospects are uncertainties inherent in estimating natural gas and oil reserves and future hydrocarbon production and cash flows, particularly with respect to wells that have not been fully tested and with wells having limited production histories; access to additional capital; changes in the price of natural gas and oil; availability and cost of services and equipment; and the presence of competitors with greater financial resources and capacity.
b) Distribution Risk
The Company is dependent on the operator to market any oil production from its wells and any subsequent production which may be received from other wells which may be successfully drilled on the Prospect. It relies on the operator’s ability and expertise in the industry to successfully market the same. Prices at which the operator sells gas/oil both in intrastate and interstate commerce will be subject to the availability of pipe lines, demand and other factors beyond the control of the operator. The Company and the operator believe any oil produced can be readily sold to a number of buyers.
A substantial portion of the Company’s accounts receivable is with joint venture partners in the oil and gas industry and is subject to normal industry credit risks.
d)
Foreign Operations Risk
The Company is exposed to foreign currency fluctuations, political risks, price controls and varying forms of fiscal regimes or changes thereto which may impair its ability to conduct profitable operations as it operates internationally and holds foreign denominated cash and other assets.
Delta Oil & Gas, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2014
(Stated in U.S. Dollars)
7. CURRENT LIABILITIES
The Company received $91,392 as of March 31, 2014 (December 31, 2013 - $242,551) from Hillcrest Resources Ltd., as its share in the Texas project. The Company will expend these funds for drilling future exploration wells.
8. SECURITY LOANS
On December 16, 2013 the Company obtained a loan, from an investment group, restricted for the further development of Texas properties in which they hold a participation agreement. The loan is secured by an assignment of thirty percent of the revenues earned by the Company before payout of the loan and ten percent of revenues earned after payout of the loan from Donner 1 and Donner 2. The funds are to be used exclusively for the development of Donner 4. The loan carries an interest rate of ten percent on total proceeds of $221,667 with $155,000 received in 2013 and $66,667 received in February 2014 less payout.
The table below reflects the change in the security loans during the three months ended March 31, 2014 and year ended December 31, 2013:
|
|
|
March 31,
2014
|
|
|
December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of the period
|
|
$
|
155,000
|
|
|
$
|
-
|
|
|
Loan received
|
|
|
66,667
|
|
|
|
155,000
|
|
|
Payout
|
|
|
(15,273
|
)
|
|
|
-
|
|
|
Interest accrued
|
|
|
4,760
|
|
|
|
-
|
|
|
Balance, end of the period
|
|
$
|
211,154
|
|
|
$
|
155,000
|
|
Payout is defined as the point when buyers have received payments, net of operating expenses, from the buyer’s interest in the assets totaling $221,667 with interest calculated on the outstanding balance, at the rate of 10% per annum, and paid or accrued on a monthly basis.
9.
ASSET RETIREMENT OBLIGATIONS
The Company follows the Accounting for Asset Retirement Obligations Topic of the FASB Accounting standards Codification. This addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It also requires recognition of the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. As of March 31, 2014 and December 31, 2013, the Company recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with Asset retirement Obligations of the FASB Accounting Standards Codification. The liability for the fair value of an asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production. The Company amortizes the amount added to the oil and gas properties and recognizes accretion expense in connection with the discounted liability over the remaining life of the respective well. The estimated liability is based on historical experience in plugging and abandoning wells, estimated useful lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements. The liability is a discounted liability using a credit-adjusted risk-free rate of 12%.
Revisions to the liability could occur due to changes in plugging and abandonment costs, well useful lives or if federal or state regulators enact new guidance on the plugging and abandonment of wells.
The Company amortizes the amount added to oil and gas properties and recognizes accretion expense in connection with the discounted liability over the remaining useful life of the respective well.
Delta Oil & Gas, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2014
(Stated in U.S. Dollars)
9.
ASSET RETIREMENT OBLIGATIONS (continued)
The information below reflects the change in the asset retirement obligations during the three months ended March 31, 2014 and year ended December 31, 2013:
|
|
|
March 31,
2014
|
|
|
December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of the period
|
|
$
|
29,881
|
|
|
$
|
28,115
|
|
|
Liabilities assumed
|
|
|
-
|
|
|
|
-
|
|
|
Revisions
|
|
|
-
|
|
|
|
(1,607
|
)
|
|
Accretion expense
|
|
|
897
|
|
|
|
3,373
|
|
|
Balance, end of the period
|
|
$
|
30,778
|
|
|
$
|
29,881
|
|
10. SHARE CAPITAL
On February 6, 2013, the Company granted 300,000 common shares to the Officers of the Company as part of their compensation package for 2013. The price per share was $0.085.
On March 7, 2013, the Company issued 100,000 common shares pursuant to the exercise of 100,000 options at $0.08 per share for total proceeds of $8,000.
On May 2, 2013, the Company issued 100,000 common shares pursuant to the exercise of 100,000 options at $0.08 per share for total proceeds of $8,000.
Preferred Stock
The Company did not issue any preferred stock during the three month period ended March 31, 2014 (December 31, 2013 - Nil).
On February 6, 2013, the Company granted 400,000 stock options with an exercise price of $0.085 per share to the Officers of the Company as part of their compensation package.
On May 8, 2013, the Company granted 400,000 stock options with an exercise price of $0.05 per share to the Officers of the Company as part of their compensation package.
Compensation expense related to incentive stock options granted is recorded at their fair value as calculated using the Black-Scholes option pricing model. Compensation expense was $ nil for the period ended March 31, 2014 and $51,837 for the year ended December 31, 2013. The changes in stock options are as follows:
|
|
|
Number
|
|
|
Weighted average
exercise price
|
|
|
|
|
|
|
|
|
|
|
Balance outstanding, December 31, 2013
|
|
|
2,000,000
|
|
|
$
|
0.107
|
|
|
Granted
|
|
|
-
|
|
|
|
-
|
|
|
Exercised
|
|
|
-
|
|
|
|
-
|
|
|
Expired
|
|
|
-
|
|
|
|
-
|
|
|
Balance outstanding, March 31, 2014
|
|
|
2,000,000
|
|
|
$
|
0.107
|
|
Delta Oil & Gas, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2014
(Stated in U.S. Dollars)
10. SHARE CAPITAL (continued)
The weighted average assumptions used in calculating the fair value of stock options granted and vested using the Black-Scholes option pricing model are as follows:
|
|
|
March 31, 2014
|
|
|
December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
Risk-fee interest rate
|
|
|
-
|
|
|
|
0.075 - 0.84
|
%
|
|
Expected life of the option
|
|
|
-
|
|
|
5 years
|
|
|
Expected volatility
|
|
|
-
|
|
|
|
260 - 278
|
%
|
|
Expected dividend yield
|
|
|
-
|
|
|
|
-
|
|
The following table summarized information about the stock options outstanding as at March 31, 2014:
|
Options outstanding
|
|
Options exercisable
|
|
Exercise price
|
|
Number of shares
|
|
Remaining
contractual
life (years)
|
|
Number
of shares
|
|
|
|
|
|
|
|
|
|
$0.135
|
|
600,000
|
|
1.80
|
|
600,000
|
|
$0.130
|
|
600,000
|
|
2.97
|
|
600,000
|
|
$0.085
|
|
400,000
|
|
3.85
|
|
400,000
|
|
$0.050
|
|
400,000
|
|
3.91
|
|
400,000
|
11.
RELATED PARTIES
During the period ended March 31, 2014, the Company paid $68,898 (2013 - $66,926) for consulting fees and $10,443 (2013- $11,431) for accounting services to Companies controlled by directors and officers of the Company. Amounts paid to related parties are based on exchange amounts agreed upon by those related parties.
During the period ended March 31, 2014, the Company did not grant any stock options in consideration for services rendered to the directors and officers of the Company (2013 – 400,000 stock options). The total cost of $nil (2013 - $35,626) was recorded in the compensation expense for options granted and was included in the general and administration expense.
During the period ended March 31, 2014, the Company did not grant any common stock in consideration for services rendered to Officers of the Company. The total cost of $nil was recorded in the compensation expense for shares granted and was included in general and administration expense (2013 – 300,000 shares at $0.085 and $42,000).
On July 23, 2012, the Company received a promissory note of CAD$20,000 from the officers of the Company.
|
|
|
March 31,
2014
|
|
|
December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured loan CAD$20,000, unconditionally promises to pay
with accrued interest equal to the Bank of Montreal’s Prime
Lending Rate plus 5.5% per annum.
|
|
$
|
-
|
|
|
$
|
18,804
|
|
On January 27, 2014, the promissory notes of CAD$20,000 and the accrued interest of CAD$2,737 was paid back to the Directors of the Company.
Delta Oil & Gas, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2014
(Stated in U.S. Dollars)
12.
COMMITMENT AND CONTRACTURAL OBLIGATIONS
The Company contracted with its executive officers to pay each of the executive officers CAD$90,000 per year and issue 100,000 common shares of the Company on the anniversary of the executive agreement. The agreement automatically renews after one year for a further 12 months.
13. CONTINGENCIES
In September 2010, two lawsuits were filed in the District Court of Garvin County in the State of Oklahoma by Harold Hamm (“Hamm”) against certain defendants (“Defendants”) and consolidated together alleging, among other things, that Hamm owns an interest in two oil and gas leases in Garvin County and is entitled to a 50% participatory interest. We were not named as a party in these legal proceedings, but Hamm’s allegations include that he is entitled to a 50% participatory interest in the Joe Murray Farms well drilled as part of the 2009-3 Drilling Program, in which we purchased a 6.25% working interest before casing point and 5.0% working interest after casing point. The Defendants and the Company believe that there is no merit to Hamm’s allegations. In connection with these proceedings, the Defendants were ordered in January 2011 to escrow fifty percent (50%) of the revenues generated within the subject area pending the outcome of these proceedings. For this reason, fifty percent (50%) of the revenues we are entitled to that have been generated by production from the Joe Murray Farms well is being escrowed and there is no assurance that we will be able to recover these proceeds. As of March 31, 2014, we recognized $161,829 in revenue from the Joe Murray Farms well and $161,829 has not been recognized as revenue and is being escrowed pending the outcome of these proceedings.
On October 1, 2013, the Company committed $50,000 of its escrow funds to the settlement provided that the balance of the Company’s escrow funds are returned to the Company upon achieving a settlements.
