UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 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 June 30, 2014

o	Transition Report pursuant to 13 or 15(d) of the Securities Exchange Act of 1934

	For the transition period ____________ to __________

	Commission File Number: 000-52001

Delta Oil & Gas, Inc.

(Exact name of registrant as specified in its charter)

Colorado	91-2102350
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Suite 604 – 700 West Pender Street, Vancouver, British Columbia, Canada V6C 1G8

(Address of principal executive offices)

866-355-3644

(Registrant’s telephone number, including area code)

_______________________________________________________________

(Former name, former address and former fiscal year, if changed since last report)

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 issuer was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. xYes o 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). x Yes ¨ 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,” “non-accelerated filer,” and “a smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer o

Non-accelerated filer o Smaller reporting company x

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Class		Outstanding at August 12, 2014

Common Stock, $0.001 par value		15,193,241

Table of Contents

	TABLE OF CONTENTS	Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements.	3

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	4

Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	11

Item 4.	Controls and Procedures.	11
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings.	12

Item 1A.	Risk Factors.	12

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	12

Item 3.	Defaults Upon Senior Securities.	12

Item 4.	(Removed and Reserved).	12

Item 5.	Other Information.	12

Item 6.	Exhibits.	12

	Signatures
	Exhibits
	Certifications

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Table of Contents

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

Our unaudited consolidated financial statements included in this Form 10-Q for the six months ended June 30, 2014 are as follows:

F-1	Unaudited Consolidated Balance Sheet as of June 30, 2014 and December 31, 2013 (audited);

F-2	Unaudited Consolidated Statements of Operations and Comprehensive Loss for the three and six months and ended June 30, 2014 and 2013;

F-3	Unaudited Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013; and

F-4	Notes to Unaudited Consolidated Financial Statements.

These unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and the SEC instructions to Form 10-Q. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. Operating results for the interim period ended June 30, 2014 are not necessarily indicative of the results that can be expected for the full year.

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DELTA OIL & GAS, INC.
Consolidated Balance Sheets
(Stated in U.S. Dollars)

	June 30,			December 31,
	2014			2013
	(Unaudited)			(Audited)
ASSETS

Current
Cash and cash equivalents	$	43,681		$	142,647
Restricted cash		9,047			391,073
Accounts receivable		57,693			32,984
Prepaid expenses		7,674			1,026

		118,095			567,730

Natural Gas And Oil Properties
Proved property		344,371			347,318
Unproved property		84,587			160,738

		428,958			508,056

Property, Plant And Equipment (Net)		-			-

TOTAL ASSETS	$	547,053		$	1,075,786

LIABILITIES AND STOCKHOLDERS' EQUITY

LIABILITIES

Current
Accounts payable and accrued liabilities	$	62,244		$	56,587
Project cost advanced received		9,633			242,551
Promissory note payable		-			18,804
Security loans		231,611			155,000

		303,488			472,942
Long Term
Asset retirement obligation		31,674			29,881

TOTAL LIABILITIES		335,162			502,823

STOCKHOLDERS' EQUITY

Share Capital
Preferred Shares, $0.001 par value; authorized 25,000,000;
none issued
Common Shares, $0.001 par value; authorized 100,000,000;
15,193,241 shares issued and
outstanding, respectively		15,193			15,193
Additional paid-in capital		7,580,783			7,580,783

Accumulative Other Comprehensive Income		140,238			141,386

Accumulated Deficit		(7,524,323	)		(7,164,399	)

TOTAL STOCKHOLDERS' EQUITY		211,891			572,963

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	547,053		$	1,075,786


The accompanying notes are an integral part of these consolidated financial statements

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DELTA OIL & GAS, INC.
Consolidated Statements Of Operations and Comprehensive Loss
(Stated in U.S. Dollars)
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Revenue

Natural gas and oil sales	$	144,305		$	145,173		$	219,750		$	291,884

		144,305			145,173			219,750			291,884
Costs And Expenses

Natural gas and oil operating costs		27,534			27,041			48,349			50,530
General and administrative		112,531			169,666			238,688			379,635
Accretion		896			843			1,793			1,686
Depreciation and depletion		125,080			60,883			280,526			127,969

		266,041			258,433			569,356			559,820

Net Operating Loss		(121,736	)		(113,260	)		(349,606	)		(267,936	)

Other Income And Expense
Interest income		-			-			-			14
Interest expense		(5,433	)		(439	)		(10,318	)		(879	)

		(5,433	)		(439	)		(10,318	)		(865	)

Net Loss Before Other Comprehensive Loss	$	(127,169	)	$	(113,699	)	$	(359,924	)	$	(268,801	)

Other Comprehensive Income/(Loss)

Foreign currency translation		2,682			317			(1,148	)		(868	)

Comprehensive Loss For The Peiods	$	(124,487	)	$	(113,382	)	$	(361,072	)	$	(269,669	)


Basic And Diluted Loss Per Common Share

Basic	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	(0.02	)
Diluted	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	(0.02	)

Weighted Average Number Of Common Shares Outstanding

Basic		15,193,241			15,158,077			15,193,241			15,028,048
Diluted		15,193,241			15,158,077			15,193,241			15,028,048


The accompanying notes are an integral part of these consolidated financial statements

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DELTA OIL & GAS, INC.
Consolidated Statements Of Cash Flows
(Stated in U.S. Dollars)
(Unaudited)

	Six Months Ended
	June 30,
	2014			2013
Cash Flows From Operating Activities:

Net loss for the periods	$	(359,924	)	$	(268,801	)

Adjustments to reconcile net loss to net cash
used in operating activities:
Accretion		1,793			1,686
Depreciation and depletion		280,526			127,969
Stock-based compensation expense		-			51,837
Shares issued for services		-			25,500
Changes in operating assets and liabilities:
Accounts receivable		(24,709	)		9,582
Accounts payable and accrued liabilities		5,657			38,922
Restricted cash		382,026			-
Project cost advance received		(232,918	)		-
Prepaid expenses		(6,648	)		732

Net Cash Generated/(Used) In Operating Activities		45,803			(12,573	)

Cash Flows From Investing Activities:

Sale proceeds of natural gas and oil working interests		100,000			-
Investment in natural gas and oil working interests		(301,428	)		(11,888	)

Net Cash Used In Investing Activities		(201,428	)		(11,888	)

Cash Flows From Financing Activities:

Proceeds from issuance of common shares		-			16,000
Payment on promissory note		(18,804	)		(1,086	)
Proceeds from security loan		76,611			-

Net Cash Generated in Financing Activities		57,807			14,914

Net Decrease In Cash And Cash Equivalents		(97,818	)		(9,547	)

Effect of Foreign Currency Adjustments on Cash		(1,148	)		(868	)

Cash And Cash Equivalents at Beginning of the Periods		142,647			35,507

Cash And Cash Equivalents at End of the Periods	$	43,681		$	25,092

Supplemental Disclosures of Non-Cash, Investing and Financing Activities

300,000 shares issued to the President, CFO and CEO as part of their	$	-		$	25,500
compensation package

The accompanying notes are an integral part of these consolidated financial statements

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Stated in U.S. Dollars)

1. BASIS OF PRESENTATION

The unaudited consolidated financial statements as of June 30, 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 six months ended June 30, 2014 are not indicative of the results that may be expected for the year.

2. OPERATIONS

a) Organization

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).

b) Going Concern

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 $7,524,323 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.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 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.

b) Use of Estimates

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%, plus 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.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Stated in U.S. Dollars)

3. SIGNIFICANT ACCOUNTING POLICIES (continued)

f) Revenue Recognition

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 has 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 June 30, 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 is 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.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 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).

l)	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 a discounted cash flow value is required. Impairment of oil and gas properties is evaluated subject to the full cost ceiling as described under Natural Gas and Oil Properties in Financial Statements.

m)	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 six months ended June 30, 2014 and 2013:

	June 30, 2014			June 30, 2013

Basic and Diluted earnings per share computation:
Loss from continuing operations and net loss	$	(359,924	)	$	(268,801	)
Weighted Average Basic shares outstanding		15,193,241			15,028,048
Basic and Diluted loss per share	$	(0.02	)	$	(0.02	)

n)	Income Taxes

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.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Stated in U.S. Dollars)

3. SIGNIFICANT ACCOUNTING POLICIES (continued)

o)	Financial Instruments

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, accrued liabilities, project cost advance received, and security loan.

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.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 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			June 30, 2014

USA properties	$	347,318	$	37,763	$	(100,000	)	$	339,816	$	(280,526	)	$	344,371

a) Proved Properties – Descriptions

Properties in U.S.A.

i. Oklahoma, USA

Joe Murray Farm #1-18

Joe Murray Farm #1-18 started producing in August 2010. At June 30, 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 June 30, 2014, the total cost of Donner #1 was $327,687. During August 2011, the second exploration well, Donner#2, commenced production. At June 30, 2014, the total cost of Donner #2 was $507,806.

In March 2014, the third exploration well, Donner #4, commenced production and the cost of $331,067 was moved to the proved cost pool for depletion.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 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			June 30, 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 June 30, 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.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Stated in U.S. Dollars)

5. NATURAL GAS AND OIL PROPERTIES (continued)

Properties in U.S.A.

	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.

c)	Credit Risk

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.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Stated in U.S. Dollars)

7. CURRENT LIABILITIES

The Company received $9,633 as of June 30, 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, Donner 2 and Donner 4. 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, $66,667 received in February 2014 and $41,533 received in May 2014 less payout.

The table below reflects the change in the security loans during the six months ended June 30, 2014 and year ended December 31, 2013:

	June 30, 2014			December 31, 2013

Balance, beginning of the period	$	155,000		$	-
Loan received		108,200			155,000
Payout		(41,781	)		-
Interest accrued		10,192			-
Balance, end of the period	$	231,611		$	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 $221,419 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 June 30, 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 lives of the respective well.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Stated in U.S. Dollars)

9. ASSET RETIREMENT OBLIGATIONS (continued)

The information below reflects the change in the asset retirement obligations during the six months ended June 30, 2014 and year ended December 31, 2013:

	June 30, 2014		December 31, 2013

Balance, beginning of the period	$	29,881	$	28,115
Liabilities assumed		-		-
Revisions		-		(1,607	)
Accretion expense		1,793		3,373
Balance, end of the period	$	31,674	$	29,881

10. SHARE CAPITAL

i. Common Stock

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 period ended June 30, 2014 (December 31, 2013 - Nil).

ii. Stock Options

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 by the Black-Scholes option pricing model. Compensation expense was $ nil for the period ended June 30, 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, June 30, 2014		2,000,000	$	0.107

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 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:

	June 30, 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 June 30, 2014:

Options outstanding			Options exercisable
Exercise price	Number of shares	Remaining contractual life (years)	Number of shares

$0.135	600,000	1.55	600,000
$0.130	600,000	2.72	600,000
$0.085	400,000	3.61	400,000
$0.050	400,000	3.67	400,000

11. RELATED PARTIES

During the period ended June 30, 2014, the Company paid $136,853 (2013 - $132,874) for consulting fees and $21,017 (2013- $22,692) 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 June 30, 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 - $51,837) was recorded in the compensation expense for options granted and was included in the general and administration expense.

During the period ended June 30, 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 the general and administrative expense (2013 – 300,000 shares at $0.085 and $25,500).

On July 23, 2012, the Company executed a promissory note of CAD$20,000 in favor of the officers of the Company.

	June 30, 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.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 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, 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 June 30, 2014, we recognized $167,063 in revenue from the Joe Murray Farms well and $167,063 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.

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

This Quarterly Report on Form 10-Q contains forward-looking statements regarding our business, financial condition, results of operations and prospects. Words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” “estimates” and similar expressions or variations of such words are intended to identify forward-looking statements, but are not deemed to represent an all-inclusive means of identifying forward-looking statements as denoted in this Quarterly Report on Form 10-Q. Additionally, statements concerning future matters are forward-looking statements.

Although forward-looking statements in this Quarterly Report on Form 10-Q reflect the good faith judgment of our management, such statements can only be based on facts and factors currently known by us. Consequently, forward-looking statements are inherently subject to risks and uncertainties and actual results and outcomes may differ materially from the results and outcomes discussed in or anticipated by the forward-looking statements. We caution the reader that numerous important factors, including those factors discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013, which are incorporated herein by reference, could affect our actual results and could cause our actual consolidated results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, the Company. Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this Quarterly Report on Form 10-Q. We file reports with the Securities and Exchange Commission (the “SEC” or “Commission”). We make available on our website under “Investors/SEC Filings,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file such materials with or furnish them to the SEC. Our website address is www.deltaoilandgas.com. You can also read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. You can obtain additional information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.

We undertake no obligation to revise or update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this Quarterly Report on Form 10-Q. Readers are urged to carefully review and consider the various disclosures made throughout the entirety of this Quarterly Report, which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operations and prospects.

As used in this Quarterly Report, the terms the “Company,” “we,” “us,” “our,” “Delta” and “Delta Oil” mean Delta Oil & Gas, Inc. and our subsidiaries unless otherwise indicated.

Business of Delta Oil

We were incorporated under the laws of the State of Colorado on January 9, 2001 under the name Delta Oil & Gas, Inc.

We are engaged in the acquisition, development and production of oil and natural gas properties in North America. We seek to acquire and develop properties with undeveloped reserves that are economically attractive to us. We will employ expertise in geological and geophysical areas to mitigate, as far as possible, the inherent risk of oil and gas exploration. We seek to create value and reduce risks through the acquisition and development of property interests in areas that:

·	have significant undeveloped reserves;

·	are in close proximity to developed markets for oil and natural gas;

·	have existing infrastructure or the ability to install our own infrastructure of oil and natural gas; and pipelines and production platforms.

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During the first and second quarters of 2010, management engaged in a detailed strategic review of all of our development lands, exploratory lands and working interest partners held at that time. The outcome of these reviews lead to an internal declaration of core and non-core properties. Those properties within the “Core” were to receive priority focus for development and expansion and those in the “Non-Core” grouping were to be considered as low priority for development and considered for divestment should offers fall within range of what management believes are their true values.

Historically, we have taken small working interest positions in multiple and diverse projects. Under our new Core / Non-Core strategy, we will generally focus on larger working interest relationships in substantive project areas and move to strategically explore and develop those projects. We believe that this core strategy will enable us to develop Delta Oil and Gas to the next level in its growth towards becoming a more significant oil and natural gas producing entity.

Our current focus is on the exploration of our Core land portfolio comprised of working interests in acreage in Eastern Texas.

Our producing interests in South Central, Oklahoma contribute strong cash flow, but because our working interests fall below management’s threshold for participating working interest percentages and with little or no opportunity to increase these percentages, this portfolio of lands has been designated as Non-Core.

CORE PROPERTIES

Texas Prospect

On July 15, 2009, we entered into an assignment agreement with Mr. Barry Lasker (the “Assignor”) and were assigned all of Assignor’s rights and obligations under two oil, gas and liquid hydrocarbon lease agreements, each dated March 26, 2009 (the “Leases”) covering an aggregate area of approximately 243 acres in Newton County, Texas (the “Texas Prospect”). These Leases provide us with the ability to drill up to 3 exploration wells.

Following our disposition of a 60% interest in the Leases to Hillcrest Resources Ltd. (‘Hillcrest”) in December 2009, we are responsible for 40% of all costs allocated to the Leases, drilling and completion of up to 3 exploration wells. We have drilled and completed the first two exploration holes. Once the 3 exploration wells are drilled, completed and production commences, if at all, we will receive a percentage distribution of net revenue, after deduction of all applicable expenses and royalties, according to the following table:

	Net Revenue Distribution
	Before Payout	After Payout

Well #1	36%	20%
Well #2	32%	18%
Well #3	32%	18%

Under the terms of the Leases, we have the ability to participate in additional wells drilled in the Texas Prospect. In the event that we elect to participate, we will negotiate with Hillcrest our respective levels of participation in additional wells. Our percentage of the costs and net revenue distribution, both before and after payout, associated with each additional well will be proportional to our level of participation.

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We paid our proportionate share of the drilling and completion costs during the quarter ended June 30, 2010. On June 4, 2010, the first well (the “Donner #1”) was successfully drilled and encountered hydrocarbons. The Donner #1 was completed and went into production during the quarter ended September 30, 2010. On August 4, 2011, we successfully drilled and completed the second well (the “Donner #2”). The following represents the revenue from the drilling program:

Well Name	Three months ended June 30, 2014		Three months ended June 30, 2013		Six months ended June 30, 2014		Six months ended June 30, 2013

Donner #1	$	56,261	$	66,158	$	109,199	$	127,293
Donner #2	$	31,549	$	37,405	$	44,815	$	72,887
Donner #4	$	47,752	Nil		$	49,233	Nil

The decrease in revenue for Donner #1 was caused by a reduction in production due to maintenance issues. The decrease in revenues for Donner #2 was due reduction in the reserve life of the well. Subsequent to the six months June 30, 2014, Donner #2 has become uneconomic to continue as a natural gas well due to water issues; therefore, the Company and its partners have decided to perforate an additional zone up dip from the natural gas producing zone. Donner #4 commenced production during March 2014.

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 at an initial cost of $0.15 per share and its pro-rata share of drilling costs, which was $49,460. The Company has also paid its pro-rata share of $42,000 for two re-completions.

The first four wells in this field have shown oil stains in at least one zone per well. The Company’s first well, Laughlin Kibby #1, commenced production during the first quarter ended March 31, 2014. The following represents the revenue from this drilling program;

Well Name	Three months ended June 30, 2014		Three months ended June 30, 2013	Six months ended June 30, 2014		Six months ended June 30, 2013

Kibby #1	$	3,510	$nil	$	10,054	$nil

The increase in revenue for the three and six months ended June 30, 2014 when compared to the three and six months ended June 30, 2013, was caused by the well not being in production during the corresponding period in the prior year.

King City, California

On May 25, 2009, we entered into a farm-out agreement with Sunset Exploration (“Sunset”), a California corporation, to participate in the drilling and exploration of lands located in Monterey County, California. The prospect area where the drilling and exploration will take place was comprised of approximately 10,000 acres. We were obligated to pay 66.67% of the costs of the initial test well up to casing point, in order to earn a 40.0% working interest. Thereafter, we were obligated to pay 40.0% of the costs of any future wells which we elect to participate in order to earn a 40.0% working interest. We paid Sunset $100,000 as an advance towards the permitting and processing of lands and the costs of a gravity survey and a 2D seismic program.

We completed a gravity survey and 2D seismic program in 2010 and extensively reviewed the data provided from the program. The first exploration well was drilled in November 2011 at a cost of $608,084. The logs indicated potential pay zones and we completed a test well with a view toward full production if the tests indicate an economic potential, which cannot be assured. During the quarter ended March 31, 2013, testing results indicated that there were no economic hydrocarbons, hence the well was abandoned. Total costs of $363,231 were moved to the proven cost pool for depletion. The Company has no further interest in the King City lands.

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NON-CORE PROPERTIES

2009-3 Drilling Program - 4 Wells

On August 7, 2009, we entered into an agreement with Ranken Energy to participate in a four well drilling program in Garvin County, Oklahoma (the “2009-3 Drilling Program”). We purchased a 6.25% working interest before casing point and 5.0% working interest after casing point in the 2009-3 Drilling Program for $37,775. In addition to the total buy-in cost, we are responsible for our proportionate share of the drilling and completion costs. The first well (the “Jackson #1-18”) started production during the quarter ending March 31, 2010, the second well (the “Miss Gracie #1-18”) started production during the quarter ending June 30, 2010 and the third well (“Joe Murray Farms”) started production during the quarter ended September 30, 2010. On August 18, 2011, we plugged and abandoned Jackson #1-18 due to the well being uneconomic. The following represents the revenues from this drilling program:

Well Name	Three months ended, June 30, 2014	Three months ended June 30, 2013	Six months ended, June 30, 2014	Six months ended June 30, 2013

Miss Gracie #1-18	$nil	$4,104	$nil	$14,151

Joe Murray Farms	$5,233	$5,125	$6,450	$9,275

The decrease in revenues for Joe Murray Farms was due to a reduction in production for the period as compared to the corresponding prior year caused by maintenance issues and reserve depletion. The Company sold its working interest in Miss Gracie at the end of the last fiscal year. Due to ongoing legal proceedings potentially impacting the Joe Murray Farms well, the revenue reported from the Joe Murray Farms well for the six months ending June 30, 2014 and June 30, 2013 reflects fifty percent (50%) of the total revenues generated from production and the remaining fifty percent (50%) is being escrowed pending the outcome of these proceedings and has not been recognized as revenue. We have recognized an aggregate of $167,063 in revenue from the Joe Murray Farms well and $167,063 is the amount as of June 30, 2014 that is being escrowed pending the outcome of these proceedings and has not been recognized as revenue.

2009-1 Drilling Program - 5 Wells

On July 27, 2009, we entered into an agreement with Ranken Energy to participate in a five well drilling program in Garvin County, Oklahoma (the “2009-1 Drilling Program”). We initially acquired a 5.0% working interest in the 2009-1 Drilling Program in exchange for our payment of a total of $13,125 in buy-in costs, which equates to $2,625 in buy-in costs for each well, plus our proportionate share of the drilling and completion costs. During the fourth quarter of 2009, our working interest in the 2009-1 Drilling Program was reduced to 3.75%. The reduction in our working interest was attributable to the land owner exercising an option to increase its working interest causing a proportional reduction to all working interests held in this drilling program.

We refer to the first three wells in this drilling program as Saddle #1-18, Saddle #2-18 and Saddle #3-18. These wells started to produce hydrocarbons during the quarter ending March 31, 2010. During December 2013, the Company sold its working interests in the all of the Saddle wells. Total revenue received from all three wells for the three and six months ending June 30, 2014 was $nil (June 30, 2013: $3,044).

2007-1 Drilling Program - 3 Wells

On September 10, 2007, we entered into an agreement with Ranken Energy to participate in a four well drilling program in Garvin County, Oklahoma (the “2007-1 Drilling Program”). Drilling of the first and second wells (the “Pollock #1-35” and the “Hulsey #1”) was completed in the N.E. Anitoch Prospect and the Washington Creek Prospect respectively. The Pollock #1-35 did not prove to be commercially viable.

During December 2013, the Company sold its working interests in River #1, Hulsey #1-8 and Hulsey #2-8, hence no revenue was produced for the three months ended March 31, 2014. The following represents the revenues from this drilling program.

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Well Name	Three months ended, June 30, 2014	Three months ended, June 30, 2013		Six months ended June 30, 2014	Six months ended June 30, 2014

River #1	$nil	$	2,841	$nil	$	5,447
Hulsey #1	$nil	$	12,413	$nil	$	31,045
Hulsey #2	$nil	$	11,703	$nil	$	24,126

For the Three Months Ended June 30, 2014 and 2013

Revenues

We generated total revenue of $144,305 for the three months ended June 30, 2014, a slight decrease from revenues of $145,173 for the three months ended June 30, 2013. The decrease in revenues from natural gas and oil sales was due to the sale of wells located in Oklahoma when compared to the corresponding period last year, which was offset by the addition of new production from the Texas prospect.

Costs and Expenses

We incurred costs and expenses in the amount of $266,041 for the three months ended June 30, 2014, compared to costs and expenses of $258,433 for three months ended June 30, 2013. The increase in costs was primarily attributable to depletion and depreciation expenses.

Other changes in our costs and expenses for the three months ended June 30, 2014, when compared to the three months ended June 30, 2013, are described below:

Natural gas and oil operating costs for the three months ended June 30, 2014 remained the same at $27,534 from $27,041 for the three months ended June 30, 2013. The Company sold its wells in Oklahoma resulting in the reduction in operating costs during the period when compared to the corresponding year, however this was offset by an increase in operating costs from the addition of new wells in the Texas prospect.

General and administrative costs for the three months ended June 30, 2014 decreased to $112,531 from $169,666 for the three months ended June 30, 2013, a decrease of 34%. The decrease was primarily caused by a decrease in stock based compensation from $14,711 for the quarter ended June 30, 2013 to $nil for the quarter ended June 30, 2014, since no stock options were issued during the period. Legal and professional expenses decreased by $25,728 for the three months ending June 30, 2014 when compared to the corresponding year. Finally, investor relations expense for the three months ending June 30, 2014 was $504 as compared to $9,816 for the three months ending June 30, 2013. The reduction was caused by the company not embarking on investor relation activities for the three months ending June 30, 2014.

Depreciation and depletion costs for the three months ended June 30, 2014 increased significantly to $125,080 from $60,883 for the three months ended June 30, 2013. The increase was caused by the reduction in reserves as evaluated by the third party reserve engineer and the transfer of abandoned projects to the proved property depletion pool.

Net Operating Loss

The net operating loss for the three months ended June 30, 2014 was $121,736, compared to a net operating loss of $113,260 for the three months ended June 30, 2013, due to the factors described above.

Other Income and Expense

We reported other expense of $5,433 for the three months ended June 30, 2014 compared to $439 for the three months ended June 30, 2013. Other expense was interest charged on a secured loan as described in Note 8 in the financial statements for the six months ended June 30, 2014.

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Comprehensive Loss for the period

As a result of the above, comprehensive loss for the three months ended June 30, 2014 was $124,487, compared to a comprehensive loss of $113,382 for the three months ended June 30, 2013.

For the Six Months Ended June 30, 2014 and 2013

Revenues

We generated total revenue of $219,750 for the six months ended June 30, 2014, a 25% decrease from revenues of $291,884 for the six months ended June 30, 2013. The decrease in revenues from natural gas and oil sales was due to the sale of wells located in Oklahoma when compared to the corresponding period last year, which was offset by the addition of new production from the Texas prospect.

Costs and Expenses

We incurred costs and expenses in the amount of $569,356 for the six months ended June 30, 2014, compared to costs and expenses of $559,820 for six months ended June 30, 2013. The increase in costs was primarily attributable to depletion and depreciation expenses.

Other changes in our costs and expenses for the six months ended June 30, 2014, when compared to the six months ended June 30, 2013, are described below:

Natural gas and oil operating costs for the six months ended June 30, 2014 remained the same at $48,349 from $50,350 for the six months ended June 30, 2013. The Company sold its wells in Oklahoma resulting in the reduction in operating costs during the period when compared to the corresponding year, however this was offset by an increase in operating costs from the addition of new wells in the Texas prospect.

General and administrative costs for the six months ended June 30, 2014 decreased to $238,688 from $379,635 for the six months ended June 30, 2013, a decrease of 37%. The decrease was primarily caused by a decrease in stock based compensation from $77,337 for the six ended June 30, 2013 to $nil for the six ended June 30, 2014, since no stock options were issued during the period. Legal and professional expenses decreased by $45,576 for the six months ending June 30, 2014 when compared to the corresponding year. Finally, investor relations expense for the six months ending June 30, 2014 decreased by $15,312 when compared to the corresponding period in the previous year. The reduction was caused by the company not embarking on investor relation activities for the three months ending June 30, 2014.

Depreciation and depletion costs for the six months ended June 30, 2014 increased significantly to $280,526 from $127,969 for the six months ended June 30, 2013. The increase was caused by the reduction in reserves as evaluated by the third party reserve engineer and the transfer of abandoned projects to the proved property depletion pool.

Net Operating Loss

The net operating loss for the six months ended June 30, 2014 was $349,606, compared to a net operating loss of $267,936 for the six months ended June 30, 2013, due to the factors described above.

Other Income and Expense

We reported other expense of $10,318 for the six months ended June 30, 2014 compared to $879 for the six months ended June 30, 2013. Other expense was interest charged on a secured loan as described in Note 8 in the financial statements for the six months ended June 30, 2014.

Comprehensive Loss for the period

As a result of the above, comprehensive loss for the six months ended June 30, 2014 was $361,072, compared to a comprehensive loss of $269,669 for the six months ended June 30, 2013.

There are material events and uncertainties which could cause our reported financial information to not be indicative of future operating results or financial condition. Our inability to successfully identify, execute or effectively integrate future acquisitions may negatively affect our results of operations. The success of any acquisition depends on a number of factors beyond our control, including the ability to estimate accurately the recoverable volumes of reserves, rates of future production and future net revenues attainable from the reserves and to assess possible environmental liabilities. Drilling for oil and natural gas may also involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. Our ability to achieve our target results are also dependent upon the current and future market prices for crude oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost. We do not operate the properties in which we have an interest and we have limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our returns on capital in drilling or acquisition activities and our targeted production growth rate. As a result, our historical results may not be indicative of future operations.

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Summary of Quarterly Results on a Non-GAAP basis

Set forth below is a summary of the Company’s financial results for the eight most recently completed quarters, removing non-cash items. The following information is presented for informational purposes only; the net income/(loss) totals below do not match the Financial Statements due to the removal of non-cash items.

	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sept. 30, 2013	Jun 30, 2013	Mar 31, 2013	Dec 31, 2012	Sept 30, 2012
	$	$	$	$	$	$	$	$
Revenue	144,305	75,445	85,866	107,297	145,173	146,711	153,699	127,517
Operating Costs	(266,041)	(303,315)	(950,650)	(184,305)	(258,433)	(301,387)	(213,943)	(256,800)
Non-cash items *	125,976	156,343	801,278	52,213	74,751	130,555	68,625	64,185
Net Operating Income/(loss)	4,240	(71,527)	(63,506)	(24,795)	(38,509)	(24,121)	8,381	(65,098)

*Non-cash items are those items that are related to stock based compensation, depletion and depreciation, impairment charges or losses on sale of investments and accretion costs.

Liquidity and Capital Resources

As of June 30, 2014, we had total current assets of $118,095 and total current liabilities in the amount of $303,488. As a result, we had a working capital deficit of $185,393 as of June 30, 2014, compared to working capital of $94,788 as at December 31, 2013. The reduction in working capital is directly attributable to the net operating loss incurred for the six months ending June 30, 2014, and the secured loan of $231,611.

The revenue we currently generate from natural gas and oil sales does not exceed our operating expenses. Our management anticipates that the current cash on hand may not be sufficient to fund our continued operations at the current level for the next twelve months. As such, we may require additional financing to fund our operations and proposed drilling activities for the year ended December 31, 2013. We will also require additional funds to expand our acquisition, exploration and production of natural oil and gas properties. We will require additional significant capital to fund the development of our existing proved undeveloped reserves and to effectively expand our operations through the acquisition and drilling of new prospects and to implement our overall business strategy. We believe that debt financing will not be an alternative for funding as we have limited tangible assets to secure any debt financing. We anticipate that additional funding will be in the form of equity financing from the sale of our common or preferred stock. We intend to seek additional funding in the form of equity financing from the sale of our common or preferred stock, but cannot provide any assurance that we will be able to raise sufficient funding from the sale of our common preferred stock to fund our operations and acquisition of new prospects. If we are unable to obtain additional financing, we will experience liquidity problems and management expects that we will need to curtail operations, liquidate assets, seek additional capital on less favorable terms and/or pursue other remedial measures. Any additional equity financing may involve substantial dilution to our then existing shareholders.

Cash Generated/(Used) in Operating Activities

Operating activities generated a $45,803 increase in cash for the six months ending June 30, 2014, compared to $(12,573) cash used in operating activities for the six months ending June 30, 2013. Our increase in net cash generated for the six months ending June 30, 2014 was caused by an increase in accounts payable and increase in restricted cash, which was offset by a decrease in the Company’s revenues. Our accounts payable as of June 30, 2014 increased to $62,244, an increase of $5,657 from $56,587 as of December 31, 2013.

Cash Generated in Investing Activities

Cash flows used in investing activities for the six months ending June 30, 2014 was $201,428, compared to $11,888 cash used in investing activities for the six months ending June 30, 2013. All cash used in investment activities during the six months ending June 30, 2014 and 2013 related to investments in natural gas and oil working interests. The Company 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.

Cash from Financing Activities

The Company received $76,611as net loan proceeds as described in Note 8 of the financial statements for the six months ending June 30, 2014 and paid a promissory note of $18,804 during the six months ending June 30, 2014.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet debt nor did we have any transactions, arrangements, obligations (including contingent obligations) or other relationships with any unconsolidated entities or other persons that may have material current or future effect on financial conditions, changes in the financial conditions, results of operations, liquidity, capital expenditures, capital resources, or significant components of revenue or expenses.

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Going Concern

As shown in the accompanying financial statements, we have incurred a cumulative net loss of $7,524,323 since inception. To achieve profitable operations, we require additional capital for obtaining producing oil and gas properties through either the purchase of producing wells or successful exploration activity. We believe that we will be able to obtain sufficient funding to meet our business objectives, including anticipated cash needs for working capital and are currently evaluating several financing options. However, there can be no assurances offered in this regard. As a result of the foregoing, there exists substantial doubt about our ability to continue as a going concern.

Critical Accounting Policies

Our consolidated financial statements have been prepared in conformity with Generally Accepted Accounting Principles (GAAP). For a full discussion of our accounting policies as required by GAAP, refer to our Annual Report on Form 10-K for the year ended December 31, 2013. We consider certain accounting policies to be critical to an understanding of our condensed consolidated financial statements because their application requires significant judgment and reliance on estimations of matters that are inherently uncertain. The specific risks related to these critical accounting policies are unchanged at the date of this report and are described in detail in our Annual Report on Form 10-K.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

(Not Applicable).

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this report. Based on such evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, the Company’s disclosure controls and procedures are not effective in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act. This conclusion is based primarily on the material weakness in internal control over financial reporting which was disclosed in our Annual Report on Form 10-K for the year ended December 31, 2013, where management identified material weaknesses based on the size of our company and the fact that we have only one financial expert on our management team and no audit committee.

Limitations on the Effectiveness of Internal Controls

Our management does not expect that our disclosure controls and procedures or our internal control over financial reporting will necessarily prevent all fraud and material error. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving our objectives and our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the internal control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, control may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal controls over financial reporting during the six months ending June 30, 2014 that have materially affected or are reasonably likely to materially affect such controls.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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 June 30, 2014, we recognized $167,063 in cumulative revenue from the Joe Murray Farms well and an additional $167,063 has not been recognized as revenue and is being escrowed pending the outcome of these proceedings.

Item 1A. Risk Factors.

In addition to the risks and uncertainties discussed herein, particularly those discussed in the “Safe Harbor” Cautionary Statement and the other sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part I, Item 2, see the risk factors set forth in Part I, Item 1A of our annual report on Form 10-K for the fiscal year ended December 31, 2013.

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

None

Item 3. Defaults upon Senior Securities.

None.

Item 4. (Removed and Reserved).

Item 5. Other Information.

None.

Item 6. Exhibits.

See the Exhibit Index following the signatures page of this report, which is incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Delta Oil & Gas, Inc.

Date:	August 12, 2014



	By: /s/ Christopher Paton-Gay Christopher Paton-Gay Title: Chief Executive Officer and Director
Date:	August 12, 2014



	By: /s/ Kulwant Sandher Kulwant Sandher Title: Chief Financial Officer and Director

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DELTA OIL & GAS, INC.

(the “Registrant”)

(Commission File No. 000-52001)

Exhibit Index

Quarterly Report on Form 10-Q

for the Six Ended June 30, 2014

Exhibit No.		Description

31.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1		Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS †		XBRL Instance Document

101.SCH †		XBRL Taxonomy Extension Schema Document

101.CAL †		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF †		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB †		XBRL Extension Labels Linkbase Document

101.PRE †		XBRL Taxonomy Extension Presentation Linkbase Document

† In accordance with SEC rules, this interactive data file is deemed “furnished” and not “filed” for purposes of Sections 11 or 12 of the Securities Act of 1933 and Section 18 of the Securities and Exchange Act of 1934, and otherwise is not subject to liability under those sections or acts.

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DELTA OIL & GAS INC 10-Q