DELTA OIL & GAS INC - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - DELTA OIL & GAS INC	Financial_Report.xls
EX-31.1 - EXHIBIT311 - DELTA OIL & GAS INC	exhibit311.htm
EX-10.1 - EXHIBIT101 - DELTA OIL & GAS INC	exhibit101.htm
EX-32.1 - EXHIBIT321 - DELTA OIL & GAS INC	exhibit321.htm
EX-32.1 - EXHIBIT312 - DELTA OIL & GAS INC	exhibit312.htm

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 September 30, 2012

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 November 10, 2012
Common Stock, $0.001 par value		14,693,241

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.	14

Item 4.	Controls and Procedures.	14
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings.	16

Item 1A.	Risk Factors.	16

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	16

Item 3.	Defaults Upon Senior Securities.	16

Item 4.	Mine Safety Disclosures.	16

Item 5.	Other Information.	16

Item 6.	Exhibits.	16

	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 three and nine months ended September 30, 2012 are as follows:

F-1	Unaudited Consolidated Balance Sheet as of September 30, 2012 and December 31, 2011 (audited);

F-2	Unaudited Consolidated Statements of Operations for the three and nine months ended September 30, 2012 and 2011;

F-3	Unaudited Consolidated Statements of Cash Flows for the nine months ended September 30, 2012 and 2011; 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 September 30, 2012 are not necessarily indicative of the results that can be expected for the full year.

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Table of Contents

DELTA OIL & GAS, INC.

Consolidated Balance Sheets
(Stated in U.S. Dollars)

	September 30,			December 31,
	2012			2011
ASSETS	(Unaudited)			(Audited)

Current
Cash and cash equivalents	$	77,265		$	258,228
Restricted cash		53			10,662
Accounts receivable		98,223			192,117
Prepaid expenses		8,544			8,402

		184,085			469,409

Natural Gas And Oil Properties
Proved property		1,137,461			1,137,012
Unproved property		508,508			595,102

		1,645,969			1,732,114

Property, Plant And Equipment (Net)		-			251

TOTAL ASSETS	$	1,830,054		$	2,201,774

LIABILITIES AND STOCKHOLDERS' EQUITY

LIABILITIES

Current
Accounts payable and accrued liabilities	$	46,329		$	182,080
Project cost advanced received		12,547			18,742
Promissory note payable		20,342			-
Due to related party		-			45

		79,218			200,867
Long Term
Asset retirement obligation		18,058			16,567

TOTAL LIABILITIES		97,276			217,434

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;
14,693,241 and 14,157,107 shares issued and
outstanding, respectively		14,693			14,157
Additional paid-in capital		7,467,492			7,297,901

Accumulative Other Comprehensive Income		142,827			144,965

Accumulated Deficit		(5,892,234	)		(5,472,683	)

TOTAL STOCKHOLDERS' EQUITY		1,732,778			1,984,340

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,830,054		$	2,201,774


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 Income /(Loss)
(Stated in U.S. Dollars)
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Revenue

Natural gas and oil sales	$	127,517		$	219,471		$	375,292		$	1,035,063

		127,517			219,471			375,292			1,035,063
Costs And Expenses

Natural gas and oil operating costs		36,815			38,432			110,920			153,329
General and administrative		170,805			76,668			573,584			471,145
Accretion		497			574			1,491			1,721
Depreciation and depletion		48,682			103,006			108,254			388,169

		256,800			218,680			794,250			1,014,364

Net Operating Income/(Loss)		(129,283	)		791			(418,958	)		20,699

Other Income And Expense
Interest income		-			-			36			4
Interest expense		(347	)		-			(629	)		-

		(347	)		-			(593	)		4

Net Income/(Loss) Before Other Comprehensive Loss	$	(129,630	)	$	791		$	(419,551	)	$	20,703

Other Comprehensive Income/(Loss)

Foreign currency translation		(2,403	)		(45,140	)		(2,138	)		(39,192	)

Comprehensive Income/(Loss) For The Periods	$	(132,033	)	$	(44,349	)	$	(421,689	)	$	(18,489	)


Basic And Diluted Loss Per Common Share

Basic	$	(0.01	)	$	0.00		$	(0.03	)	$	0.00
Diluted	$	(0.01	)	$	0.00		$	(0.03	)	$	0.00

Weighted Average Number Of Common Shares Outstanding

Basic		14,562,341			14,157,107			14,390,617			14,136,228
Diluted		14,562,341			14,237,477			14,390,617			14,338,545


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)

	Nine Months Ended
	September 30,
	2012			2011
Cash Flows From Operating Activities:

Net income/(loss) for the periods	$	(419,551	)	$	20,703

Adjustments to reconcile net loss to net cash
used in operating activities:
Accretion		1,491			1,721
Depreciation and depletion		108,254			388,169
Stock-based compensation expense		113,161			41,346
Shares issued for services		30,000			42,000

Changes in operating assets and liabilities:
Accounts receivable		93,894			73,196
Accounts payable and accrued liabilities		(135,751	)		190,439
Restricted cash		10,609			(8,807	)
Project cost advance received		(6,195	)		17,132
Due to related party		(45	)		(22,849	)
Prepaid expenses		(142	)		1,413

Net Cash (Used)/Generated In Operating Activities		(204,275	)		744,463

Cash Flows From Investing Activities:

Sale proceeds of natural gas and oil working interests		300,000			15,731
Investment in natural gas and oil working interests		(294,892	)		(762,810	)

Net Cash (Used)/Generated In Investing Activities		5,108			(747,079	)

Cash Flows From Financing Activities:

Promissory note payable		20,342			-

Net Cash Generated in Financing Activities		20,342			-

Net Decrease In Cash And Cash Equivalents		(178,825	)		(2,616	)

Effect of Foreign Currency Adjustments on Cash		(2,138	)		(39,192	)

Cash And Cash Equivalents at Beginning of the Periods		258,228			525,128

Cash And Cash Equivalents at End of the Periods	$	77,265		$	483,320

Supplemental Disclosures of Non-Cash, Investing and Financing Activities

300.000 shares issued to the President, CFO and CEO as part of their	$	30,000		$	42,000
compensation package



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

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Table of Contents

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Stated in U.S. Dollars)

1. BASIS OF PRESENTATION

The unaudited consolidated financial statements as of September 30, 2012 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, 2011 audited consolidated financial statements and notes thereto. The results of the operations for the nine months ended September 30, 2012 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 $5,892,234 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 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

September 30, 2012

(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%, 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.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(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 September 30, 2012 and 2011, 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 and second 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 three 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. Deposits are insured up to $101,710, the amount that may be subject to credit risk for the nine months ended September 30, 2012 is $nil.

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

September 30, 2012

(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) Other Equipment

Computer equipment is stated at cost. Provision for depreciation on computer equipment is calculated using the straight-line method over the 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, and 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 period. 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 the period ended September 30, 2012, the conversion of options for the calculation of diluted earnings per share would be considered anti-dilutive. For the period ended September 30, 2011, the dilutive effect of outstanding options and warrants and their equivalents is reflected in diluted earnings per share by application of the treasury stock method. The table below presents the computation of basic and diluted earnings per share for the nine months ended September 30, 2012 and 2011:

	September 30, 2012			September 30, 2011
Basic earnings per share computation:
Income (Loss) from continuing operations and net income (loss)	$	(419,551	)	$	20,703
Basic shares outstanding		14,390,617			14,136,228
Basic earnings (loss) per share	$	(0.03	)	$	0.00

Diluted earnings per share computation:
Income (Loss) from continuing operations	$	(419,551	)	$	20,703
Basic shares outstanding		14,390,617			14,136,228
Incremental shares from assumed conversions:
Stock options		-			202,317
Diluted shares outstanding		14,390,617			14,338,545
Diluted earnings (loss) per share	$	(0.03	)	$	0.00

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Stated in U.S. Dollars)

3. SIGNIFICANT ACCOUNTING POLICIES (continued)

o) 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.

p) 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 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.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Stated in U.S. Dollars)

3. SIGNIFICANT ACCOUNTING POLICIES (continued)

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.

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. NATURAL GAS AND OIL PROPERTIES

a) Proved Properties

Properties	December 31, 2011		Additions		Disposals			Transfer from unproved properties		Depletion for the period			September 30, 2012

USA properties	$	1,137,012	$	114,245	$	(5,793	)	$	-	$	(108,003	)	$	1,137,461

a) Proved Properties – Descriptions

Properties in U.S.A.

i. Oklahoma, USA

2006-3 Drilling Program

In April 2007, the Company entered into the 2006-3 Drilling Program for a buy-in cost of $113,700 which will provide 12.5% Before Casing Point (“BCP”) working interest and After Casing Point (“ACP”) working interest of 10%. In September 2007, Wolf #1-7 was abandoned. Its cost amounting to $70,495 was moved to the proven cost pool for depletion. In October 2007, Ruggles #1-15 was also abandoned and the cost of $84,506 was moved to the proven cost pool for depletion.

In the 2006-3 Drilling Program, Elizabeth #1-25 was plugged and abandoned on February 7, 2008. Its cost amounting to $127,421 was moved to the proven cost pool for depletion. Plaster #1-11 and Dale #1-15 started producing in January and February 2008, respectively. Total cost of $205,064 was moved to the proven cost pool. Loretta #1-22 was plugged and abandoned in 2009; its cost amounting to $139,334 was moved to the proved cost pool.

The working interest of Plaster #1-1 was sold on April 2011, the net proceeds was $7,603.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Stated in U.S. Dollars)

4. NATURAL GAS AND OIL PROPERTIES (continued)

a) Proved Properties – Descriptions (continued)

2007-1 Drilling Program

In September 2007, the Company entered into the 2007-1 Drilling Program for a buy-in cost of $77,100 which will provide 25% Before Casing Point (“BCP”) working interest and 20% After Casing Point (“ACP”) working interest.

In the 2007-1 Drilling Program, Pollack #1-35 was plugged and abandoned on January 19, 2008. Its cost amounted to $152,101 was moved to the proven cost pool for depletion. Hulsey #1-8 started producing in February 2008; the cost of $200,382 was moved to the proven cost pool. River #1-28 started producing in June 2008; the cost of $169,159 was moved to the proven cost pool. Hulsey #2-8 started producing in January 2009; its cost amounted to $139,674 was moved to the proven cost pool for depletion.

2009-1 Drilling Program

On July 27, 2009, the Company entered into the 2009-1 Drilling Program for five wells which will provide 5.714286% Before Casing Point (“BCP”) working interest and 5.00% After Casing Point (“ACP”) working interest. The Company’s buy-in costs for each well is $2,625. During the three months to September 2009, the Company had paid buy-in, estimated drilling and completion costs for three wells, Saddle #1-28, Saddle #2-28 and Saddle #3-28. Saddle #1-28 and Saddle #2-28 started producing in November 2009 and Saddle #3-28 in December 2009, the total cost amounted to $96,633 was moved to the proven cost pool for depletion.

2009-3 Drilling Program - 4 Wells

On August 7, 2009, the Company entered into an agreement with Ranken Energy to participate in a four well drilling program in Garvin County, Oklahoma (the “2009-3 Drilling Program”). The Company 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, the Company will be responsible for our proportionate share of the drilling and completion costs. During the year ended December 31, 2009, the Company paid additional drilling costs in the amount of $115,017. Jackson #1-18 started producing in January 2010, the total cost amounted to $62,956 was moved to the proven cost pool for depletion. Brewer #1-20 was plugged and abandoned on June 2, 2010. Its cost amounted to $64,922 was moved to the proven cost pool for depletion. Miss Gracie #1-18 started producing in March 2010, the total cost amounted to $71,368 was moved to the proven cost pool for depletion. Waunice # 1-36 started production in June 2010 and was plugged and abandoned on September 23, 2010. Its cost amounted to $44,939 was moved to the proven cost pool for depletion. On August 18, 2011, the Company plugged and abandoned Jackson #1-18.

Joe Murray Farm #1-18

Joe Murray Farm #1-18 started producing in August 2010, the total cost amounted to $44,571 was moved to the proven cost pool for depletion.

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, the cost amounting to $304,479 was moved to the proven cost pool for depletion. During August 2011, the second exploration well, Donner#2, commenced production and the cost of $417,041 was moved to the proven cost pool for depletion.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Stated in U.S. Dollars)

4. NATURAL GAS AND OIL PROPERTIES (continued)

iii. California #1-1 - Lonestar Prospect, California, USA

On September 1, 2010, the Company entered into an agreement for the joint exploration and development of the Lonestar Prospect located in California, USA. The Company has a 25% working interest in the initial Prospect Test Well, California 1-1.

In November 2010, California 1-1 started producing. The cost amounting to $329,804 was moved to the proven cost pool for depletion.

The working interest of California 1-1 was sold on December 1, 2011, the net proceeds were$31,250.

b) Unproved Properties

Properties	December 31, 2011		Addition		Disposals			Transfer to proved properties		September 30, 2012

USA properties	$	595,102	$	213,406	$	(300,000	)	$	-	$	508,508

c) Costs not being amortized

The following table sets forth a summary of oil and gas property costs not being amortized at September 30, 2012, 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.

	Total		2012			2011		2010			2009 and Prior

Property acquisition costs and transfer to proved property pool	$	-		-			-		(37,775	)		37,775
Exploration and development	$	508,508		(86,594	)		406,335		(258,345	)		447,112
Capitalized interest	$	-		-								-
Total	$	508,508		(86,594	)		406,335		(296,120	)		484,887

Properties in U.S.A.

i. King City, California, USA

On May 25, 2009, the Company entered into a Farm-out agreement with Sunset Exploration (“Sunset”) to participate in 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 7, 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%, and in all additional wells drilled in the AMI. The purchaser is subsequently responsible for 25% of the completion costs. Following the sale, the Company will revert back to its 40% working interest in the SBV 2-32 well.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Stated in U.S. Dollars)

4. NATURAL GAS AND OIL PROPERTIES (continued)

ii. Texas Prospect, Texas, USA

The first exploration well, Donner #1, started producing in August 2010, the cost amounted to $304,479 was moved to the proven cost pool for depletion. Donner #2 started producing in August 2011, the cost amounted to $417,041 was moved to the proven cost pool for depletion.

iii. 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 $0.11 per share and its pro-rata share of drilling costs, which amount $49,460. The Company has also paid its pro-rata share of $42,000 for two re-completions.

5. 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

September 30, 2012

(Stated in U.S. Dollars)

6. CURRENT LIABILITIES

The Company received $12,547 as of September 30, 2012 (December 31, 2011 - $18,742) from Hillcrest Resources Ltd., as its share in the Texas project. The Company will expend these funds for drilling the first and second exploration wells.

7. 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 September 30, 2012 and December 31, 2011, 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

The information below reflects the change in the asset retirement obligations during the period ended September 30, 2012 and year ended December 31, 2011:

	September 30 2012		December 31 2011

Balance, beginning of the year	$	16,567	$	19,121
Liabilities assumed		-		-
Revisions		-		(4,849	)
Accretion expense		1,491		2,295
Balance, end of the period	$	18,058	$	16,567

8. SHARE CAPITAL

i. Common Stock

On January 19, 2011, the Company granted 300,000 common shares to the Officers of the Company as part of their compensation package. The price of the share as of January 19, 2011 was $0.14.

On February 22, 2012, the Company granted 300,000 common shares to the Officers of the Company as part of their compensation packages for 2012, and issued 300,000 common shares for 2011 which were granted in 2011. The price per the share was $0.14.

On August 20, 2012, the Company issued 236,134 common shares to Progas Energy Services, Inc. as payment of the drilling costs of the first well located in Jim Wells County, Texas. The price of the share as of August 20, 2012 was $0.11.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Stated in U.S. Dollars)

8. SHARE CAPITAL (continued)

Preferred Stock

The Company did not issue any preferred stock during the period ended September 30, 2012 (December 31, 2011 - Nil).

ii. Stock Options

On June 1, 2012, the Company granted 400,000 stock options with an exercise price of $0.08 per share to a Company engaged in investor relations. 200,000 stock options will vest immediately and the remaining 200,000 stock options will vest on September 1, 2012.

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 $113,161 for the period ended September 30, 2012 and $82,693 for the year ended December 31, 2011. The changes in stock options are as follows:

	Number			Weighted average exercise price

Balance outstanding, December 31, 2011		1,500,000		$	0.128
Granted		600,000			0.130
Granted		400,000			0.080
Expired		(100,000	)		0.150
Exercised		-			-
Balance outstanding, September 30, 2012		2,400,000		$	0.120

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:

	September 30, 2012			December 31, 2011

Risk-fee interest rate		1.15	%		1.95	%
Expected life of the option	5 year			5 year
Expected volatility		228	%		214	%
Expected dividend yield		-			-

The following table summarized information about the stock options outstanding as at September 30, 2012:

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

$0.120	800,000	0.17	800,000
$0.135	600,000	3.30	600,000
$0.130	600,000	4.47	600,000
$0.080	400,000	0.66	400,000

9. RELATED PARTIES

During the period ended September 30, 2012, the Company paid $202,095 (September 30, 2011 - $196,872) for consulting fees and $34,514 (September 30, 2011 - $27,578) for accounting services to Companies controlled by directors and officers of the Company. There was $nil (December 31, 2011 - $45) payable to directors and officers of the Company for the consulting fees and the reimbursement of expenses incurred on behalf of the Company. Amounts paid to related parties are based on exchange amounts agreed upon by those related parties.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Stated in U.S. Dollars)

9. RELATED PARTIES (continued)

On January 19, 2011, the Company issued 300,000 shares of common stock in consideration for services rendered to Officers of the Company. The price of the share as of January 19, 2011 was $0.14. The total cost of $42,000 was recorded in the compensation expense for shares granted and was included in the general and administration expense.

On January 19, 2011, the Company granted 600,000 stock options in consideration for services rendered to the directors and officers of the Company at a purchase price of $0.135 for 5 years. The price of the share on January 19, 2011 was $0.14. The total cost of $82,693 was recorded in the compensation expense for options granted and was included in the general and administration expense.

On March 21, 2012, the Company granted 600,000 stock options in consideration for services rendered to the directors and officers of the Company at a purchase price of $0.13 for 5 years. The price of the share on March 21, 2012 was $0.14. The total cost of $83,149 was recorded in the compensation expense for options granted and was included in the general and administration expense.

On February 22, 2012, the Company granted 300,000 shares of common stock in consideration for services rendered to Officers of the Company. The price of the shares as of the grant date was $0.14. The total cost of $42,000 was recorded in the compensation expense for shares granted and was included in the general and administration expense.

On July 23, 2012, the Company received promissory notes of CDN$20,000 from the officers of the Company.

	September 30, 2012		December 31,2011

Unsecured loan CDN$20,000, unconditionally promises to pay with accrued interest equal to the Bank of Montreal’s Prime Lending Rate plus 5.5% per annum.	$	20,342	$	-

The promissory notes are payable on demand. As of September 30, 2012, the accrued interest was $351.

10. 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.

11. CONTINGENCIES

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 September 30, 2012, we recognized $147,709 in revenue from the Joe Murray Farms well and $147,709 has not been recognized as revenue and is being escrowed pending the outcome of these proceedings.

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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, 2011, 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.

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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 reasonably 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.

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 we receive offers that 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 King City, California and Eastern Texas.

While our producing interests in South Central, Oklahoma contribute cash flow, these working interests of ours 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 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:

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	Net Revenue Distribution
	Before Payout	After Payout
Well #1	36%	20%
Well #2	36%	24%
Well #3	36%	24%

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.

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 Sept. 30, 2012		Three months ended Sept. 30, 2011		Nine months ended Sept. 30, 2012		Nine months ended Sept. 30, 2011

Donner #1	$	60,899	$	56,803	$	185,598	$	288,309

Donner #2	$	18,779	$	24,225	$	35,741	$	24,225

The reduction in revenue, for the nine months ended September 30, 2012, for Donner #1 was caused by a reduction in working interest from 36% to 20% as the after payout amount was achieved. The small increase in revenue for the 3 months ended September 30, 2012, for Donner #1 was due to an increase in commodity prices. The decrease in revenue for the three months ended September 30, 2012, for Donner #2 was due to the well being converted to a natural gas well from an oil producing well in the corresponding quarter. The Donner #2 well has begun production as a natural gas well during the second quarter of 2012.

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 is comprised of approximately 10,000 acres. We are 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 will be obligated to pay 40.0% of the costs of any future wells in 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. We were encouraged by the results which appear to be indicating the potential for significant hydrocarbon targets. The first exploration well was drilled in November 2011 at a cost of $608,084. The logs indicated potential pay zones and we are currently in the process of completing a test well with a view toward full production if the tests indicate an economic potential, which cannot be assured.

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On September 7, 2012, the Company entered into a farm-out agreement with MPG King City Project, L.P. (“MPG”), pursuant to which the Company received $300,000 in exchange for a 25% working interest in the SBV 2-32 well. MPG’s working interest will revert to a 20% working interest after Sunset pays a penalty of 400% as a result of Sunset’s election not to pay its requisite portion of the drilling costs related to the well. MPG also received a 20% working interest in all additional wells drilled in the area of mutual interest. MPG is subsequently responsible for 25% of the completion costs. Following the farm-out agreement, the Company will revert back to its 40% working interest in the SBV 2-32 well.

Lonestar Prospect, California, USA

On September 1, 2010, we entered into an agreement for the joint exploration and development of the Lonestar Prospect located in California, USA. We are obligated to pay 25% of the costs in order to earn a 20% working interest in the initial well, named internally as California #1-1. As at March 31, 2012, we expended an aggregate of $329,804 in drilling and completion costs for California #1-1. In November 2010, this well was fully logged and tested and a 9,000 foot wholly owned pipeline was installed. The well started production during November 2010, and the costs have been transferred to the proved costs pool for depletion.

The following represents the revenue from the California #1-1:

Well Name	Three months ended Sept. 30, 2012	Three months ended Sept. 30, 2011	Nine months ended Sept. 30, 2012	Nine months ended Sept. 30, 2011

Lonestar	$ni	$67,013	$nil	$379,383

We did not generate any revenue from the California #1-1 during the nine months ended September 30, 2012 due to our disposition of our working interest in the California #1-1 on December 1, 2011 for net proceeds of $31,500.

NON-CORE PROPERTIES

2009-3 Drilling Program - 4 Wells

On August 7, 2009, we entered into an agreement with Ranken Energy Corporation 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:

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Well Name	Three months ended, Sept. 30, 2012	Three months ended, Sept. 30, 2011	Nine months ended, Sept. 30, 2012	Nine months ended, Sept. 30, 2011

Jackson #1-18	$nil	$nil	$nil	$1,651
Miss Gracie #1-18	$24,231	$20,370	$40,413	$137,507
Joe Murray Farms	$6,888	$17,211	$39,510	$90,359

The decrease in revenues for Miss Gracie #1-18 and Joe Murray Farms was due to a reduction in production for the period as compared to the corresponding prior year. We have not generated any revenue from the Jackson #1-18 in 2012 because the well was plugged and abandoned in August 2011. Drilling and completion costs of $127,878 were moved to the proved properties pool for depletion.

Due to ongoing legal proceedings potentially impacting the Joe Murray Farms well, the revenue reported from the Joe Murray Farms well for the nine months ended September 30, 2012 and September 30, 2011 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 $147,709 in revenue from the Joe Murray Farms well and $147,709 is the other fifty percent amount as of September 30, 2012 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. Total revenue received from all three wells for the three months ended September 30, 2012 was $523 (September 30, 2011: $2,235). The decrease in revenue is due to the decline in reserves and the reduction in the price of natural gas. Total revenue received for the nine months ended September 30, 2012 was $6,169 (September 30, 2011: $17,334), the decrease was caused by a decline in reserves and the reduction in the price of natural gas.

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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.

Drilling of the third well in this drilling program (the “River #1”) was completed during the three months ended September 30, 2008. River #1 is currently in production and the total revenue received for the three months ended September 30, 2012 was $5,927 (September 30, 2011: $6,669), and for the nine months ended September 30, 2012, was $13,815 (September 30, 2011: $22,311). The decrease in revenue was caused by a decrease in natural gas prices and a reduction in production due to declining reserves.

Hulsey #1-8 started producing during the first quarter of 2008 and the total revenue received for the three months ended September 30, 2012 was $8,286 (September 30, 2011: $18,733), and for the nine months ended September 30, 2012 was $38,738 (September 30, 2011: $55,376). The decrease in revenue was caused by the decline in production and a decline in natural gas prices. However, subsequent to the quarter, the well has been re-worked which should result in higher production.

Hulsey #2-8 commenced production during the three months ended March 31, 2009 and produced $1,984 for the three months ended September 30, 2012 (September 30, 2011: $6,980) and for the nine months ended September 30, 2012 was $15,307 (September 30, 2011: $17,074). The decrease is due to a reduction in production from this well, however a re-work program was initiated after the quarter end which should result in an increase in production. Our proportionate costs associated with the Hulsey #2-8 well amounted to $139,674, which was moved to the proved properties cost pool for depletion.

2006-3 Drilling Program

On April 17, 2007, we entered into an agreement with Ranken Energy Corporation to participate in a six well drilling program in Garvin and Murray counties in Oklahoma (the “2006-3 drilling Program”). The leases secured and/or lands to be pooled for this drilling program total approximately 820 net acres. We agreed to take a 10% working interest in this program.

Three wells drilled (the “Wolf #1-7”, the “Loretta #1-22” and the “Ruggles #1-15”) were deemed by the operator to not be commercially viable and as such, were plugged and abandoned in September 2007.

Three other wells drilled (the “Elizabeth #1-25”, the “Plaster #1-1” and the “Dale #1 re-entry”) were deemed by the operator to be commercially viable and production casing was set in each. The Plaster #1 encountered hydrocarbon showings and produced natural gas commencing in January, 2008, but was sold in the second quarter of 2011 for net proceeds of $7,603. The Elizabeth #1-25 has been plugged and abandoned as of February 7, 2008.

Total revenue received from the Plaster #1 and Dale #1 wells for the three and nine months ended September 30, 2012 was $nil (September 30, 2011: $nil and the nine months ended September 30, 2011: $1,534). The Plaster #1well was sold in the second quarter of 2011 for net proceeds of $7,603, resulting in a loss on the sale of $8,128

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For the Three Months Ended September 31, 2012 and 2011

Revenues

We generated total revenue of $127,057 for the three months ended September 30, 2012, a decrease of 42% from revenues of $219,471 for the three months ended September 30, 2011. The decrease in revenues from natural gas and oil sales was due to the disposal in December 2011 of the California #1-1 well in the Lonestar Prospect, the reduction in production from our wells in Oklahoma and us achieving the payout amount for the Donner #1 well, which further reduced our working interest percentage, when compared to the corresponding period last year.

Costs and Expenses

We incurred costs and expenses in the amount of $256,800 for the three months ended September 30, 2012, a 17% increase from costs and expenses of $218,680 for three months ended September 30, 2011. The increase in costs was primarily attributable to an increase in general and administrative costs attributable to an increase in stock based compensation costs, which was partially offset by a reduction in depletion and depreciation charges and natural gas and oil operating costs.

Changes in our costs and expenses for the three months ended September 30, 2012, when compared the three months ended September 30, 2011, are described in more detail below:

Natural gas and oil operating costs for the three months ended September 30, 2012 decreased to $36,815 from $38,432 for the three months ended September 30, 2011, a decrease of 4%. The decrease in natural gas and oil operating costs was caused by the reduction in production and the disposal of the California #1-1 well in the Lonestar Prospect, which was partially offset by an increase in costs relating to the Oklahoma properties, when compared to the same period in the prior year.

General and administrative costs for the three months ended September 30, 2012 increased to $170,805 from $76,668 for the three months ended September 30, 2011, an increase of 123%. The increase was primarily caused by an increase in stock based compensation of $59,815, and an increase in audit and review fees together with an increase in professional fees regarding engineering reports, when compared to the previous period in the corresponding year. This was offset by a reduction in management fees.

Depreciation and depletion costs for the three months ended September 30, 2012 decreased to $48,682 from $103,006 for the three months ended September 30, 2011. The decrease was caused by a decrease in production as a proportion of our reserves from our natural gas and oil wells, in particular, our wells located in Texas and Oklahoma and from the disposal of California #1-1 well in the Lonestar Prospect.

Net Operating Loss

The net operating loss for the three months ended September 30, 2012 was $129,283, compared to a net operating income of $791 for the three months ended September 30, 2011, due to the factors described above.

Other Income and Expense

We reported other net expense of $347 for the three months ended September 30, 2012, as compared to other net expense of $nil for the three months ended September 30, 2011. Other expense was attributable to interest on a loan that was advanced to us by the directors of the Company. We reported other loss of $2,403 for the three months ended September 30, 2012 from the translation of foreign currency, as compared to other loss of $45,140 from the translation of foreign currency for the three months ended September 30, 2011.

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Comprehensive Loss for the period

As a result of the above, comprehensive loss for the three months ended September 30, 2012 was $132,033, compared to a comprehensive loss of $44,349 for the three months ended September 30, 2011.

For the Nine Months Ended September 30, 2012 and 2011

Revenues

We generated total revenue of $375,292 for the nine months ended September 30, 2012, a decrease of 64% from revenues of $1,035,063 for the nine months ended September 30, 2011. The decrease in revenues from natural gas and oil sales was due to the disposal in December 2011 of the California #1-1 well in the Lonestar Prospect, the reduction in production from our wells in Oklahoma and us achieving the payout amount for the Donner #1 well, which further reduced our working interest percentage, when compared to the corresponding period last year.

Costs and Expenses

We incurred costs and expenses in the amount of $794,250 for the nine months ended September 30, 2012, a 22% decrease from costs and expenses of $1,014,364 for nine months ended September 30, 2011. The decrease in costs was primarily attributable to reduced depletion and depreciation charges and natural gas and oil operating costs, which was partially offset by increases in general and administrative costs attributable to an increase in stock based compensation costs.

Changes in our costs and expenses for the nine months ended September 30, 2012, when compared the nine months ended September 30, 2011, are described in more detail below:

Natural gas and oil operating costs for the nine months ended September 30, 2012 decreased to $110,920 from $153,329 for the nine months ended September 30, 2011, a decrease of 28%. The decrease in natural gas and oil operating costs was caused by the reduction in production costs and a reduction in production costs related to the disposal of the California #1-1 well in the Lonestar Prospect when compared to the same period in the prior year.

General and administrative costs for the nine months ended September 30, 2012 increased to $573,584 from $471,145 for the nine months ended September 30, 2011, an increase of 22%. The increase was primarily caused by an increase in stock based compensation of $59,815, and an increase in audit and review fees together with an increase in professional fees regarding engineering reports, when compared to the previous period in the corresponding year. This was offset by a reduction in management fees.

Depreciation and depletion costs for the nine months ended September 30, 2012 decreased to $108,254 from $388,169. The decrease was caused by a decrease in production as a proportion of our reserves from our natural gas and oil wells, in particular, our wells located in Texas and Oklahoma and from the disposal of the California #1-1 well in the Lonestar Prospect.

Net Operating Income/(Loss)

The net operating loss for the nine months ended September 30, 2012 was $418,958, compared to a net operating income of $20,699 for the nine months ended September 30, 2011, due to the factors described above.

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Other Income and Expense

We reported other net expense of $593 for the nine months ended September 30, 2012, as compared to other net income of $4 for the nine months ended September 30, 2011. Other income was attributable to interest received on bank deposits, while other expense is attributable to interest on a loan that was advanced to us by the directors of the Company. We reported other expense of $2,138 for the nine months ended September 30, 2012 from the translation of foreign currency, as compared to other expense of $39,192 from the translation of foreign currency for the nine months ended September 30, 2011.

Comprehensive Income/(Loss) for the period

As a result of the above, comprehensive loss for the nine months ended September 30, 2012 was $421,689, compared to a comprehensive loss of $18,489 for the nine months ended September 30, 2011.

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 should not be indicative of future operations.

Summary of Quarterly Results on a Non-GAAP basis

Set forth below is a summary of our financial results for the eight most recently completed quarters, removing non-cash items. The following non-GAAP 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. Non-GAAP financial measures should not be considered in isolation from, or as a substitute for, financial information calculated in accordance with GAAP. Investors are encouraged to review the Financial Statements for information prepared in accordance with GAAP.

	Sept 30, 2012	Jun 30, 2012	Mar 31, 2012	Dec 31, 2011	Sept 30, 2011	Jun 30, 2011	Mar 31, 2011	Dec 31, 2010
	$	$	$	$	$	$	$	$
Revenue	127,517	121,057	126,718	190,158	219,471	405,068	410,524	358,700
Operating Costs	(256,800)	(306,444)	(231,007)	(278,931)	(217,855)	(323,601)	(471,283)	(1,280,437)
Non-cash items *	64,185	120,884	67,837	81,795	103,580	129,479	247,732	985,464
Net Income/(loss)	(65,098)	(65,503)	(36,452)	(6,978)	105,196	210,946	186,973	64,327

* 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.

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Liquidity and Capital Resources

As of September 30, 2012, we had total current assets of $184,085 and total current liabilities in the amount of $79,218. As a result, we had working capital of $104,867 as of September 30, 2012. As of September 30, 2012, we had a cash and cash equivalent balance of $77,265 (December 31, 2011: $258,228).

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 will not be sufficient to fund our continued operations at the current level for the next twelve months. As such, we anticipate we will require additional financing to fund our operations and proposed drilling activities for periods beyond September 30, 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 stock. We intend to seek additional funding in the form of equity financing from the sale of our common stock, but cannot provide any assurance that we will be able to raise sufficient funding from the sale of our common 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 used $183,933 in cash for the nine months to September 30, 2012, compared to $744,463 cash generated in operating activities for the nine months to September 30, 2011. Our negative cash flow for the nine months to September 30, 2012 was caused by a decrease in revenues earned and an increase in net comprehensive loss during such period which was partially offset by an overall reduction in cash expenses for the period. Our accounts payable as of September 30, 2012 decreased to $46,329, a decrease of $135,751 from $182,080 as of December 31, 2011.

Cash Used in Investing Activities

Cash flows generated from investing activities for the nine months to September 30, 2012 was $5,108, compared to $747,079 cash used in investing activities for the nine months to September 30, 2011. All cash used in investment activities during the nine months ended September 30, 2012 and 2011 related to investments in natural gas and oil working interests. The Company generated $300,000 from the partial sale of its King City prospect in September 2012. During the nine months ended September 30, 2011, we received $7,603 in sale proceeds from natural gas and oil working interests.

Cash from Financing Activities

There were no cash flows used by or generated from financing activities for the nine months ended September 30, 2012 and September 30, 2011.

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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.

Going Concern

As shown in the accompanying financial statements, we have incurred a net loss of $5,762,604 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 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, 2011. 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, 2011, 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.

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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 nine months ended September 30, 2012 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, 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, 2012, we recognized $147,709 in revenue from the Joe Murray Farms well and the other fifty percent of the revenues, which is $147,709, 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, 2011.

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

During the third quarter of 2012, we issued 236,134 restricted shares of our common stock to an oil and gas company in connection with an agreement to acquire a working interest in, and as payment of certain drilling costs related to, a property in Texas. See note 4(c)(iii) of the Financial Statements for more information. These shares were issued in a private transaction and issued in reliance of the exemption provided by Section 4(2) of the Securities Act of 1933, as amended.

Item 3. Defaults upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

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:	November 14, 2012

	By: /s/ Christopher Paton-Gay Christopher Paton-Gay Title: Chief Executive Officer and Director
Date:	November 14, 2012
	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 Quarter Ended September 30, 2012

Exhibit No.		Description

10.1		Farm-out Agreement, dated as of September 7, 2012, between Delta Oil & Gas, Inc. and MPG King City Project, L.P.

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.LAB *		XBRL Extension Labels Linkbase Document
101.PRE *		XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF *		XBRL Taxonomy Extension Definition 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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