DELTA OIL & GAS INC - FORM 10-Q

Attached files

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EX-31.2 - EXHIBIT312 - DELTA OIL & GAS INC	exhibit312.htm
EX-31.1 - EXHIBIT311 - DELTA OIL & GAS INC	exhibit311.htm
EX-32.1 - EXHIBIT321 - DELTA OIL & GAS INC	exhibit321.htm
EXCEL - IDEA: XBRL DOCUMENT - DELTA OIL & GAS INC	Financial_Report.xls

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, 2011

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. ý Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ý 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 ¨ Accelerated filer ¨

Non-accelerated filer ¨ Smaller reporting company ý

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes ý 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 13, 2011
Common Stock, $0.001 par value		14,157,107

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.	16

Item 4.	Controls and Procedures.	16
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings.	17

Item 1A.	Risk Factors.	17

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	17

Item 3.	Defaults Upon Senior Securities.	17

Item 4.	(Removed and Reserved).	17

Item 5.	Other Information.	17

Item 6.	Exhibits.	17

	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, 2011 are as follows:
F-1	Unaudited Consolidated Balance Sheet as of September 30, 2011 and December 31, 2010 (audited);

F-2	Unaudited Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and 2010;

F-3	Unaudited Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010; 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, 2011 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,
	2011			2010
ASSETS	(Unaudited)			(Audited)

Current
Cash and cash equivalents	$	483,320		$	525,128
Restricted cash		17,177			8,370
Accounts receivable		179,393			252,589
Prepaid expenses		7,155			8,568

		687,045			794,655

Natural Gas And Oil Properties
Proved property		1,196,710			1,099,016
Unproved property		449,342			188,767

		1,646,052			1,287,783

Property, Plant and Equipment (net)		383			797

TOTAL ASSETS	$	2,333,480		$	2,083,235

LIABILITIES AND STOCKHOLDERS' EQUITY

LIABILITIES

Current
Accounts payable and accrued liabilities	$	290,842		$	100,403
Project cost advanced received		22,556			5,424
Due to related party		-			22,849

		313,398			128,676
Long Term
Asset retirement obligation		19,787			19,121

TOTAL LIABILITIES		333,185			147,797

STOCKHOLDERS' EQUITY

Share Capital
Preferred Shares, 25,000,000 shares authorized of $0.001
par value of which none have been issued
Common stock, 100,000,000 shares authorized of $0.001
par value, 14,157,107 and 13,857,107 shares issued
and outstanding, respectively		14,157			13,857
Additional paid-in capital		7,256,554			7,173,508

Accumulative Other Comprehensive Income		115,118			154,310

Accumulated Deficit		(5,385,534	)		(5,406,237	)

TOTAL STOCKHOLDERS' EQUITY		2,000,295			1,935,438

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	2,333,480		$	2,083,235


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

F - 1

Table of Contents

DELTA OIL & GAS, INC.

Consolidated Statements Of Operations
(Stated in U.S. Dollars)
(Unaudited)

	THREE MONTHS ENDED					NINE MONTHS ENDED
	September 30,					September 30,
	2011			2010		2011			2010
Revenue

Natural gas and oil sales	$	219,471		$	175,020	$	1,035,063		$	506,771
Gain on sale of natural gas and oil properties		-			518,874		-			518,874


		219,471			693,894		1,035,063			1,025,645
Costs And Expenses

Natural gas and oil operating costs		38,432			33,391		153,329			114,953
General and administrative		75,843			123,715		469,520			453,009
Accretion		574			645		1,721			1,934
Depreciation and depletion		103,006			36,656		388,169			76,291


		217,855			194,407		1,012,739			646,187

Net Operating Income/(Loss)		1,616			499,487		22,324			379,458

Other Income
Interest income		-			-		4			192

		-			-		4			192

Income/(Loss) Before Income Taxes		1,616			499,487		22,328			379,650

Income taxes		825			-		1,625			3,177

Net Income/(Loss)		791			499,487		20,703			376,473

Less: Net income/(loss) attributable to
the noncontrolling interest		-			92		-			404

Net Income/(Loss) Attributable to Delta Oil & Gas, Inc.	$	791		$	499,395	$	20,703		$	376,069

Basic And Diluted Income/(Loss) Per Common Share
Basic	$	0.00		$	0.04	$	0.00		$	0.03
Diluted	$	0.00		$	0.04	$	0.00		$	0.03

Weighted Average Number Of Common Shares Outstanding
Basic		14,157,107			13,857,107		14,136,228			13,783,481
Diluted		14,237,477			13,857,107		14,338,545			13,783,481

Consolidated Statement of Comprehensive Income/(Loss)

Comprehensive Income/(Loss)

Net Income/(Loss)	$	791		$	499,487	$	20,703		$	376,473

Other Comprehensive Income/(Loss)
Foreign Currency Translation		(45,140	)		32,517		(39,192	)		38,799

Comprehensive Income/(Loss)	$	(44,349	)	$	532,004	$	(18,489	)	$	415,272


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,
	2011			2010
Cash Flows From Operating Activities:

Net income/(loss) for the period	$	20,703		$	376,069

Adjustments to reconcile net loss to net cash
used in operating activities:
Accretion		1,721			1,934
Depreciation and depletion		388,169			76,291
Stock-based compensation expense		41,346			-
Shares issued to President & CEO for servicess rendered		28,000			39,000
Shares issued to CFO for services rendered		14,000			19,500
Net income attributable to the noncontrolling interest		-			404
Gain on sale of natural gas and oil properties		-			(518,874	)

Changes in operating assets and liabilities:
Accounts receivable		73,196			(42,943	)
Accounts payable and accrued liabilities		190,439			79,628
Project cost advance received		17,132			4,402
Due to related party		(22,849	)		519
Franchise tax prepaid		-			1,004
Prepaid expenses		1,413			(2,472	)
Advancement for oil and gas exploration costs		-			49,898

Net Cash Generated In Operating Activities		753,270			84,360

Cash Flows From Investing Activities:

Sale proceeds of natural gas and oil working interests		15,731			705,949
Investment in natural gas and oil working interests		(762,810	)		(664,701	)

Net Cash Used/Generated In Investing Activities		(747,079	)		41,248

Cash Flows From Financing Activities:

Restricted cash		(8,807	)		(23,465	)

Net Cash Used By Financing Activities		(8,807	)		(23,465	)

Net (Decrease)/Increased In Cash And Cash Equivalents		(2,616	)		102,143

Effect of foreign currency adjustments on cash		(39,192	)		38,799

Cash And Cash Equivalents At Beginning Of Period
(Excess Of Deposits Over Checks Issued)		525,128			446,808

Cash And Cash Equivalents at end of Period	$	483,320		$	587,750


Supplemental Disclosures Of Non-Cash, Investing and Financing Activities

200,000 shares issued to the President & CEO as part of their	$	28,000		$	39,000
compensation package

100,000 shares issued to the CFO for services rendered	$	14,000		$	19,500

Supplemental Disclosures
Income taxes paid	$	1,625		$	3,177


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, 2011

(Stated in U.S. Dollars)

1. BASIS OF PRESENTATION

The consolidated financial statements as of September 30, 2011 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, 2010 audited consolidated financial statements and notes thereto. The results of the operations for the nine months ended September 30, 2011 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. Prior to the current fiscal year, the Company was designated as a development stage enterprise.

The Company is subject to several categories of risk associated with its development stage activities. 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 $5,385,534 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, 2011

(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, 2011

(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, 2011 and 2010, 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 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 well that is being drilled at this location.

i) Concentration of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents and accounts receivable. The Company maintains cash at two financial institutions. The Company periodically evaluates the credit worthiness of financial institutions, and maintains cash accounts only in large high quality financial institutions, thereby minimizing exposure for deposits in excess of federally insured amounts. The Company believes credit risk associated with cash and cash equivalents to be minimal. Deposits are insured up to $95,400. The amount that may be subject to credit risk for the nine months ended September 30, 2011 is $387,920.

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, 2011

(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, an evaluation of recoverability would be performed. If an evaluation is required, the estimated future undiscounted cash flows associated with the asset would be compared to the asset’s carrying amount to determine if a write-down to market value or discounted cash flow value is required. Impairment of oil and gas properties is evaluated subject to the full cost ceiling as described under Natural Gas and Oil 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.

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, 2011 and 2010:

	September 30, 2011		September 30, 2010
Basic earnings per share computation:
Income (Loss) from continuing operations and net Income (loss)	$	20,703	$	376,069
Basic shares outstanding		14,136,228		13,783,481
Basic earnings (loss) per share	$	0.00	$	0.03

Diluted earnings per share computation:
Income (Loss) from continuing operations	$	20,703	$	376,069
Basic shares outstanding		14,136,228		13,783,481
Incremental shares from assumed conversions:
Stock options		202,317		-
Diluted shares outstanding		14,338,545		13,783,481
Diluted earnings (loss) per share	$	0.00	$	0.03

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(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 equivalents, accounts receivable, franchise tax prepaid, accounts payable and accrued liabilities and project cost advanced 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.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(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, 2010				Additions				Disposals				Transfer from unproved properties				Depletion for the period				September 30, 2011
USA properties		$	1,099,016			$	65,374			$	(16,787	)		$	436,861			$	(387,754	)		$	1,196,710

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 costs of $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 amounted 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 of $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, 2011

(Stated in U.S. Dollars)

4. NATURAL GAS AND OIL PROPERTIES (continued)

a) Proved Properties – Descriptions

Properties in U.S.A.

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 of $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 of $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 of $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 of $115,017. Jackson #1-18 started producing in January 2010, the total cost of $62,956 was moved to the proven cost pool for depletion. Brewer #1-20 was plugged and abandoned on June 2, 2010. Its costs of $64,922 was moved to the proven cost pool for depletion. Miss Gracie #1-18 started producing in March 2010, the total costs of $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 of $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 of $44,571 was moved to the proven cost pool for depletion.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Stated in U.S. Dollars)

4. NATURAL GAS AND OIL PROPERTIES (continued)

a) Proved Properties - Descriptions

Properties in U.S.A

i. Palmetto Point Prospect, Mississippi, USA

On February 21, 2006, the Company entered into an agreement (the “Agreement”) with 0743608 B.C. Ltd., (“Assignor”) a British Columbia, Canada based oil and gas exploration company, in order to accept an assignment of the Assignor’s ten percent (10%) gross working and revenue interest in a ten-well drilling program (the “Drilling Program”) to be undertaken by Griffin & Griffin Exploration L.L.C., (“Griffin”) a Mississippi based exploration company. Under the terms of the Agreement, the Company paid the Assignor $425,000 as payment for the assignment of the Assignor’s 10% gross working and revenue interest in the Drilling Program. The Company also entered into a joint Operating Agreement directly with Griffin on February 24, 2006.

The Drilling Program on the acquired property interests was initiated by Griffin in May 2006 and was substantially completed by Griffin by December 31, 2006. The prospect area owned or controlled by Griffin on which the ten wells were drilled, is comprised of approximately 1,273 acres in Palmetto Point, Mississippi.

During the year ended December 31, 2007, eight wells were found to be proved wells, and two wells, PP F-7 and PP F-121 were abandoned due to no apparent gas or oil shows present. The costs of abandon properties were added to the capitalized cost in determination of the depletion expense.

On August 4, 2006, the Company elected to participate in additional two wells program in Mississippi owned by Griffin & Griffin Exploration and paid $70,000. These wells were found to be proved in December 2008.

On October 10, 2007, the Company elected to participate in the drilling of PP F-12 and PP F-12-3 in Mississippi operated by Griffin & Griffin Exploration. The Company’s 10% of the estimated drilling costs was $88,783. PP F-12 started production in October 2007, and PP F-12-3 started production in November 2007. An additional AFE in the amount of $36,498 for work over’s on the PP F-12, PP F-12-3 was paid on January 31, 2008.

On January 11, 2008, the Company paid $11,030 for PP F-41 salt water disposal well.

ii. Mississippi II, Mississippi, USA

In August 2006, the Company entered into a joint venture agreement with Griffin & Griffin Exploration, LLC to acquire an interest in a drilling program comprised of up to 50 natural gas and/or oil wells. The area in which the wells are to be drilled is comprised of approximately 300,000 gross acres of land located between Southwest Mississippi and North East Louisiana. The wells are targeting the Frio and Wilcox Geological formations. The Company has agreed to pay 10% of all prospect fees, mineral leases, surface leases and drilling and completion costs to earn a net 8% share of all production zones to the base of the Frio formation and 7.5% of all production to the base of the Wilcox formation. In January 2007, the well CMR USA 39-14 was found to be proved. The cost of $35,126 was added to the proven cost pool. Dixon#1 was abandoned in January 2007, its costs of $40,605 was moved to the proven cost pool for depletion. Randall#1 was abandoned in June 2007, its costs of $26,918 was moved to the proven cost pool for depletion. BR F-24 was abandoned and its costs of $41,999 was moved to the proven cost pool for depletion. Faust #1, USA 1-37 and BR F-33 were found to be proven and the total cost of $129,360 was added to the proven cost pool.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Stated in U.S. Dollars)

4. NATURAL GAS AND OIL PROPERTIES (continued)

a) Proved Properties - Descriptions

Properties in U.S.A

ii. Mississippi II, Mississippi, USA (continued)

In connection with the acquisition of Stallion, the Company acquired an additional 30% of the drilling programs.

iii. Mississippi III, Mississippi, USA

During August to December 2007, five additional wells, PP F-90, PP F-100, PP F-111, PP F-6A, and PP F-83 were drilled in the area. These wells were abandoned due to modest gas shows and a total drilling cost of $110,729 was added to the capitalized costs in determination of depletion expense.

On April 3, 2009, the Company sold its Working Interest in the Mississippi project and the surrounding lands for $200,367 plus a monthly $500 payment for 48 months of production.

iv. Willows Gas Field, California, U.S.AT

Through the Company’s subsidiary, Stallion, the Company acquired a well working interest in California, U.S.A. On October 15, 2007, Stallion agreed to participate in the drilling program to be conducted by Production Specialties Company (“PSC”). Stallion shall pay for the initial test well, 12.5% of 100% of all costs and expenses of drilling, completing, testing and equipping the Wilson Creek #1-27, to earn 6.25% working interest. As of December 31, 2009, Stallion has expended $195,971 for the costs of Wilson Creek #1-27 and $60,000 for 3D seismic in the prospect area. Wilson Creek #1-27 started producing gas from April 2008. On December 10, 2010, it was sold to the Company for $9,982.

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

vi. 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, Morrow 1-7 started producing, the costs of $329,804 was moved to the proven cost pool for depletion.

b) Unproved Properties

Properties		December 31, 2010				Addition				Transfer to proved properties				September 30, 2011
USA properties		$	188,767			$	697,436			$	(436,861	)		$	449,342

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Stated in U.S. Dollars)

4. NATURAL GAS AND OIL PROPERTIES (continued)

c) Costs not being amortized

The following table sets forth a summary of oil and gas property costs not being amortized at September 30, 2011, 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		2011		2010			2009			2008 and Prior
Property acquisition costs and transfer to proved property pool	$	-		-		(37,775	)		17,900			19,875
Exploration and development	$	449,342		260,575		(258,345	)		(163,389	)		610,501
Capitalized interest	$	-							-			-
Total	$	449,342		260,575		(296,120	)		(145,489	)		630,376

Properties in U.S.A.

i. Mississippi II, Mississippi, USA

In August, 2006, the Company entered into a joint venture agreement with Griffin & Griffin Exploration, LLC. to acquire an interest in a drilling program comprised of up to 50 natural gas and/or oil wells. The area in which the wells are to be drilled is comprised of approximately 300,000 gross acres of land located between Southwest Mississippi and North East Louisiana. The wells are targeting the Frio and Wilcox Geological formations. The Company has agreed to pay 10% of all prospect fees, mineral leases, and surface leases and drilling and completion costs to earn a net 8% share of all production zones to the base of the Frio formation and 7.5% of all production to the base of the Wilcox formation.

On April 3, 2009, the Company sold its Working Interest in the Mississippi project and the surrounding lands for $200,367 and $500 per month for 48 months of production.

ii. King City, California, USA

On May 25, 2009, the Company entered into a Farm-out agreement with Sunset Exploration (“Sunset”) to participate in a drilling and exploration of lands located in California, USA. The Company paid $100,000 to Sunset towards the permitting and processing of lands and the costs of a gravity survey and a 2D seismic program. The Company shall pay 66.67% pro rata share of 100% of all costs associated in the initial test well. If the test well is capable of producing hydrocarbons, then the Company shall pay its working interest pro rata share of all completion costs. The Company’s working interest is 40% of 100% in the Area of Mutual Interest.

iii. Texas Prospect, Texas, USA

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

(Stated in U.S. Dollars)

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.

6. CURRENT LIABILITIES

The Company received $22,556 as of September 30, 2011 from Hillcrest Resources Ltd., as its share in the Texas project. The Company will expend these funds for drilling the third exploration hole.

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, 2011 and December 31, 2010, 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

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Stated in U.S. Dollars)

7. ASSET RETIREMENT OBLIGATIONS (continued)

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 wells.

The information below reflects the change in the asset retirement obligations during the nine months ended September 30, 2011 and December 31, 2010:

	September 30, 2011			December 31, 2010
Balance, beginning of period	$	19,121		$	21,487
Liabilities assumed		-			5,160
Revisions		(1,055	)		(9,645	)
Accretion expense		1,721			2,118
Balance, end of period	$	19,787		$	19,121

8. SHARE CAPITAL

i. Common Stock

On March 8, 2010, the Company issued 300,000 common shares to the Officers of the Company as part of their compensation package. The price per share as of March 8, 2010 was $0.195.

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

Preferred Stock

The Company did not issue any preferred stock during the nine months ended September 30, 2011 (December 31, 2010 - Nil).

ii. Stock Options

Compensation expense related to incentive stock options granted is recorded at fair value as calculated using the Black-Scholes option pricing model. Compensation expense was $41,346 for the nine months ended September 30, 2011 and nil for the year ended December 31, 2010. The changes in stock options are as follows:

	Number		Weighted average exercise price
Balance outstanding, December 31, 2010		900,000	$	0.120
Granted		600,000	$	0.135
Expired		-		-
Exercised		-		-
Balance outstanding, September 30, 2011		1,500,000	$	0.128

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Stated in U.S. Dollars)

8. SHARE CAPITAL (continued)

ii. Stock Options (continued)

The weighted average assumptions used in calculating the fair value of stock options granted and vested using the Black-Scholes option pricing model are as follows:

	September 30, 2011			December 31, 2010
Risk-fee interest rate		1.95	%		-
Expected life of the option	5 year				-
Expected volatility		214	%		-
Expected dividend yield		-			-

The following table summarizes information about the stock options outstanding as at September 30, 2011:

Options outstanding			Options exercisable
Exercise price	Number of shares	Remaining contractual life (years)	Number of shares
$0.150	100,000	0.52	100,000
$0.120	800,000	1.17	800,000
$0.135	600,000	4.31	300,000

9. RELATED PARTIES

During the period ended September 30, 2011, the Company paid $253,152 (September 30, 2010 - $196,872) for consulting fees and $33,363 (September 30, 2010 - $27,578) for accounting services to Companies controlled by directors and officers of the Company. Amounts paid to related parties are based on exchange amounts agreed upon by those related parties.

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 per share as of January 19, 2011 was $0.14. The total cost of $42,000 was recorded in compensation expense for shares granted and was included in 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 per share as of January 19, 2011 was $0.14. The total cost of $41,346 was recorded in compensation expense for options granted and was included in general and administration expense.

10. COMMITMENT AND CONTRACTURAL OBLIGATIONS

For Kings City Farm-out Modification, the Company shall be responsible for 40% (i.e. $8,000) of additional expense on seismic survey.

The Company contracted with its executive officers to pay each of the executive officers $85,632 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.

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Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Stated in U.S. Dollars)

11. CONTINGENCIES

In September 2010, two lawsuits were filed in the District Court of Garvin County in the State of Oklahoma by Harold Hamm (“Hamm”) against certain defendants (“Defendants”) and consolidated together alleging, among other things, that Hamm owns an interest in two oil and gas leases in Garvin County and is entitled to a 50% participatory interest. We were not named as a party in these legal proceedings, but Hamm’s allegations include that he is entitled to a 50% participatory interest in the Joe Murray Farms well drilled as part of the 2009-3 Drilling Program, which we purchased a 6.25% working interest before casing point and 5.0% working interest after casing point. The Defendants and the Company believe that there is no merit to Hamm’s allegations. In connection with these proceedings, the Defendants were ordered in January 2011 to escrow fifty percent (50%) of the revenues generated within the subject area pending the outcome of these proceedings. For this reason, fifty percent (50%) of the revenues we are entitled to that have been generated by production from the Joe Murray Farms well is being escrowed and there is no assurance that we will be able to recover these proceeds. As of September 30, 2011, we recognized $90,359 in revenue from the Joe Murray Farms well and $90,359 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, 2010, 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 far as possible, the inherent risk of oil and gas exploration. We seek to create value and reduce risks through the acquisition and development of property interests in areas that have:

·	Significant undeveloped reserves;

·	Close proximity to developed markets for oil and natural gas;

·	Existing infrastructure or the ability to install our own infrastructure of oil and natural gas 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 offers fall within range of what management believes are their true values.

Historically, Delta has taken small working interest positions in multiple and diverse projects. Under our new Core / Non-core strategy, Delta 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 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; Northern California and Eastern Texas. As a result of our acquisition in March 2009 of a controlling interest in The Stallion Group, a Nevada corporation, we acquired property interests which include acreage in the North Sacramento Valley, California.

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

CORE PROPERTIES

Texas Prospect

On July 15, 2009, we entered into an assignment agreement with Mr. Barry Lasker (the “Assignor”) and were assigned all of Assignor’s rights and obligations under two oil, gas and liquid hydrocarbon lease agreements, each dated March 26, 2009 (the “Leases”) covering an aggregate area of approximately 243 acres in Newton County, Texas (the “Texas Prospect”). These Leases provide us with the ability to drill up to 3 exploration wells. The costs of the leases were $169,566. In December 2009, we sold a sixty (60%) percent interest in the Leases to Hillcrest Resources Ltd. (“Hillcrest”) and received $111,424. As September 30, 2011, the costs of the leases were $74,018.

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Following our disposition of a 60% interest in the Leases to Hillcrest, we are responsible for 40% of all costs allocated to the Leases, drilling and completion of up to 3 exploration wells. The Company has 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 of approximately 25%, according to the following table:

	Net Revenue Distribution
	Before Payout	After Payout
Well #1	36%	20%
Well #2	36%	24%
Well #3	36%	28%

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.

The Company paid its 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 well was completed and the well went into production during the quarter ended September 30, 2010. On August 4, 2011, the Company successfully drilled and completed the second well (Donner #2). The following represents the revenue from the drilling program:

Well Name	Three months ended September 30, 2011		Three months ended September 30, 2010		Nine months ended September 30, 2011		Nine months ended September 30, 2010
Donner #1	$	56,803	$	35,138	$	288,309	$	35,138

Donner #2	$	24,225	$nil		$	24,225	$nil

The significant reduction in revenue for Donner #1 was due to a reduction in the Net Revenue Distribution from 36% to 20% resulting from the well reaching Payout. Payout refers to the return of our initial investment in the well and the costs of operating the well until Payout has been achieved.

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 is 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 September 30, 2010, the Company had expended $222,125 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 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 drilling program:

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Well Name		Three months ended Sept. 30, 2011				Three months ended Sept. 30, 2010		Nine months ended Sept. 30, 2011				Nine months ended Sept. 30, 201
Lonestar		$	67,013		$	nil		$	379,383		$	nil

The significant reduction in revenue from the previous quarter was caused by a reduction in production due to a decline in reserves.

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 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. Delta and its Partners are now working on setting the location for our first exploratory well. We have agreed that we will permit a 2-3 well drilling program around the exploratory well and that we will commence drilling our first exploration well as soon as well licenses and drilling permits have been issued.

NON-CORE PROPERTIES

2009-3 Drilling Program - 4 Wells

On August 7, 2009, we entered into an agreement with Ranken Energy to participate in a four well drilling program in Garvin County, Oklahoma (the “2009-3 Drilling Program”). We purchased a 6.25% working interest before casing point and 5.0% working interest after casing point in the 2009-3 Drilling Program for $37,775. In addition to the total buy-in cost, we are responsible for our proportionate share of the drilling and completion costs. During the year ended December 31, 2009, we paid additional drilling costs in the amount of $78,090. 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, the Company 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, 2011		Three months ended, Sept. 30, 2010		Nine months ended, Sept. 30, 2011		Nine months ended, Sept. 30, 2010
Jackson #1-18	$	nil	$	18,323	$	1,651	$	39,243
Miss Gracie #1-18	$	20,370	$	48,507	$	137,507	$	126,946
Joe Murray Farms	$	17,211	$	17,303	$	90,359	$	17,303

The increase in revenues from Miss Gracie and Joe Murray Farms for the nine months ended September 30, 2011, as compared to the same period in the prior year, was due to wells not being in production for both periods during the corresponding prior year and for the same length of time. The decrease in revenue for Jackson was due to the depletion in hydrocarbon reserves. 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 three and nine months ended 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.

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 landowner exercising an option to increase its working interest causing a proportional reduction to all working interests held in this drilling program.

During the year ended December 31, 2009, we paid estimated drilling and completion costs of $72,175 for three wells which we refer to as Saddle #1-18, Saddle #2-18 and Saddle #3-18. The first three wells in this drilling program 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, 2011 was $2,235 (September 30, 2010: $14,106); the decrease was caused by a decrease in commodity prices and production; and for the nine months ended September 30, 2011 was $17,334 (September 30, 2010: $33,179). The decrease in revenue for the nine months ended September 30, 2011, as compared to the nine month ended September 30, 2010, was primarily attributable to the decline in reserves and commodity prices.

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”). We purchased a 20% working interest in the 2007-1 Drilling Program for $77,100. 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, 2011 was $6,669 (September 30, 2010: $5,918), and for the nine months ended September 30, 2011, was $22,311 (September 30, 2010: $30,900); the decrease in revenue was primarily attributable to a decrease in production due to declining reserves.

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Hulsey #1-8 started producing during the first quarter of 2008 and the total revenue received for the three months ended September 30, 2011 was $18,733 (September 30, 2010: $14,333) and for the nine months ended September 30, 2011 was $55,376 (September 30, 2010: $54,387). The increase in revenue was caused by an increase in production.

Hulsey #2-8 commenced production during the three months ended March 31, 2009 and produced $6,980 for the three months ended September 30, 2011 (September 30, 2010: $7,817) and for the nine months ended September 30, 2011 was $17,074 (September 30, 2010: $14,220). The increase for the nine months ended September 30, 2011, as compared to the nine months ended September 30, 2010, was caused by 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 (“Ranken Energy”) 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. To date, we have paid the sum of $514,619.

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. The proportionate costs associated with these abandoned wells amounted to $244,989, which were moved to the proved properties cost pool for depletion.

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 Elizabeth #1-25 located in the Meridian Prospect cost $99,129, the Plaster #1-1 located in the Plaster Prospect cost $116,581, and re-entry into the Dale #1 located in the Dale Prospect cost $18,150, all of which was paid August and September, 2007. Subsequent to the completion of these wells, two remain economically viable at this time. The Plaster #1 encountered hydrocarbon showings and produced natural gas commencing in January, 2008. The Dale #1 re-entry has been producing in the range of 2 to 3 barrels of oil per day. 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 months ended September 30, 2011was $nil (September 30, 2010: $1,624) and for the nine months ended September 30, 2011 was $1,534 (June 30, 2010: $5,643). The Plaster #1 well was sold in the second quarter of 2011 for net proceeds of $7,603, resulting in a loss on the sale of $8,128.

The operator, Ranken Energy, is reviewing the productivity levels from these wells and may propose the drilling of additional wells in the Dale Prospect and the Crazy Horse Prospect. We anticipate that we would participate in these wells to the same extent as in the original drilling program, which is a 10% working interest.

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Wordsworth Prospect

On April 10, 2006, we entered into a farm-out, option and participation letter agreement (“FOP Agreement”) where we acquired a 15% working interest in certain leasehold interests located in southeast Saskatchewan, Canada referred to as the Wordsworth area for the purchase price of $152,724. We were responsible for our proportionate share of the costs associated with drilling, testing, and completing the first test well on the property. In exchange for us paying our proportionate share of the costs associated with drilling, testing, and completing the first test well on the property, we earned a 15% working interest before payout and a 7.5% working interest after payout on the Wordsworth prospect. Payout refers to the return of our initial investment in the property. In addition, we also acquired an option to participate and acquire a working interest in a vertical test well drilled to 1200 meters to test the Mississippian (Alida) formation in LSD 13 of section 24, township 7, range 3 W2.

During June 2006, the first well was drilled to a horizontal depth of 2033 meters in the Wordsworth prospect. The initial drilling of this well and subsequent testing revealed that this well contained oil reserves suitable for commercial production. In June 2006, this initial well began producing as an oil well.

A second horizontal well was drilled in May 2007 at a cost of $198,152. Initial logs indicated hydrocarbon showings in an oil-bearing zone estimated to be approximately 770 feet in the horizontal section. However, due to the high water content in fluid removed from this well, the operator determined that it was not commercially productive and it was plugged and abandoned. In April 2008, the operator recommended re-entering the second horizontal well with a view to drilling horizontally in a different direction starting at the base of the vertical portion of that well. We elected to participate in this re-entry on the same terms and conditions as the previous wells. This well was drilled at a cost of $33,812. No economic hydrocarbons were found and this well was plugged and abandoned.

On November 2, 2009, we announced the completion and production of a third well at the location 2A2-23-7-3W2. The total cost of this well was CDN$67,253. The well started production and we began receiving royalties from this well during November 2009.

On July 1, 2010, we entered into a Purchase and Sale Agreement (the “Agreement”) with Petrex Energy Ltd. (“Petrex”) whereby Petrex agreed to purchase our remaining 5% working interest in the Wordsworth prospect and our right to participate in future wells in the Wordsworth prospect for CDN $757,500, inclusive of 5% GST on Tangibles, which equates to US $704,490; this resulted in a gain on sale of future revenues of $518,874.

Willows Gas Field

On February 15, 2007, Stallion, our majority-owned subsidiary, entered into a Farm Out Agreement with Production Specialties Company (“Production Specialties”) for participation in a natural gas prospect area located in the North Sacramento Valley, California. On October 15, 2007, Stallion drilled its first prospect well paying 12.5% of the costs of the first well to earn a 6.25% working interest. For subsequent wells, Stallion will pay 6.25% of the costs of future wells to earn 6.25% working interest. Stallion participated in the drilling of the first well (“Wilson Creek #1-27”) on the prospect area and encountered a number of prospective pay zones. Testing was completed and stabilized flow rates exceeded a combined 1.5 million cubic feet per day of sweet high quality gas. Thereafter, the Wilson Creek #1-27 was connected to a nearby pipeline and begun producing natural gas in April 2008. Total costs for the Wilson Creek #1-27 well in the end year ended December 31, 2009 was $255,971. During 2009 and in light of the lower natural gas commodity prices, we reviewed the future economic viability of this well and decided to suspend production until further notice in order to determine whether production of this well will be profitable. During the quarter ended March 31, 2010, we decided to resume production on this well due to an increase in commodity prices, but ceased production during February 2010, due to the limited economic viability of the Wilson Creek #1-27 well. The revenue for the Wilson Creek #1-27 well for the three and nine months ended September 30, 2011 was $nil. The decrease was caused by the Company’s decision to cease production from this well attributable to a reduction in reserves.

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For the Three Months Ended September 30, 2011 and 2010

Revenues

We generated revenue of $219,471 from natural gas and oil sales for the three months ended September 30, 2011, an increase of 25% from revenues from natural gas and oil sales of $175,020 for the three months ended September 30, 2010. All revenue generated during the three months ended September 30, 2011 was attributable to natural gas and oil sales. We generated total revenue of $693,894 during the three months ended September 30, 2010, which is inclusive of a gain on sale of natural gas and oil properties of $518,874.

The increase in revenues from natural gas and oil sales was due to an in increase in revenue from a number of new producing wells when compared to the corresponding period last year, particularly in our California, and Texas areas of interest. This was partially offset by a reduction in revenue from the Company’s non-core properties. The increase is also attributed to an increase in the price of natural gas and oil when compared to the corresponding period last year.

Costs and Expenses

We incurred costs and expenses in the amount of $217,855 for the three months ended September 30, 2011, a 12% increase from costs and expenses of $194,407 for three months ended September 30, 2010. The increase in costs was primarily attributable depletion and depreciation charges.

Changes in our costs and expenses for the three months ended September 30, 2011, when compared the three months ended September 30, 2010, are described below:

Natural gas and oil operating costs for the three months ended September 30, 2011 increased to $38,432 from $33,391 for the three months ended September 30, 2010, an increase of 15%. The increase in natural gas and oil operating costs was caused by the increase in production and an increase in the number of producing wells when compared to the same period in the prior year.

General and administrative costs for the three months ended September 30, 2011 decreased to $75,843 from $123,715 for the three months ended September 30, 2010, a decrease of 39%. The decrease was caused by a gain on foreign exchange and a reduction in stock based compensation as compared to the previous period in the corresponding year, which was partially offset by an increase in management fees.

Depreciation and depletion costs for the three months ended September 30, 2011 increased to $103,006 from $36,656. The increase was caused by an increase in production as a proportion of the Company’s reserves, from our natural gas and oil wells, in particular, our wells located in California, Texas and Oklahoma.

Net Operating Income

The net operating income for the three months ended September 30, 2011 was $1,616, compared to a net operating income of $499,487 for the three months ended September 30, 2010 due to the factors described above, which included a $518,874 the gain on sale of natural gas and oil properties.

Other Income and Expense

We reported other net income of $nil for the three months ended September 30, 2011 and 2010.

Net Income Attributable to Delta Oil and Gas Inc.

As a result of the above, net income for the three months ended September 30, 2011 was $791, compared to a net income of $499,395 for the three months ended September 30, 2010.

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For the Nine Months Ended September 30, 2011 and 2010

Revenues

We generated revenue of $1,035,063 from natural gas and oil sales for the nine months ended September 30, 2011, an increase of 104% from revenues of $506,771 from natural gas and oil sales for the nine months ended September 30, 2010. All revenue generated during the nine months ended September 30, 2011 was attributable to natural gas and oil sales. We generated total revenue of $1,025,645 during the nine months ended September 30, 2010, which is inclusive of a gain on sale of natural gas and oil properties of $518,874.

The increase in revenues from natural gas and oil sales was due to an in increase in revenue from a number of new producing wells when compared to the corresponding period last year, particularly in our California, Texas and Oklahoma areas of interest. This was partially offset by a reduction in revenue from the Company’s non-core properties. The increase is also attributed to an increase in the price of natural gas and oil when compared to the corresponding period last year.

Costs and Expenses

We incurred costs and expenses in the amount of $1,012,739 for the nine months ended September 30, 2011, a 57% increase from costs and expenses of $646,187 for nine months ended September 30, 2010. The significant increase in costs was primarily attributable to increased depletion and depreciation charges and natural gas and oil operating costs.

Changes in our costs and expenses for the nine months ended September 30, 2011, when compared the nine months ended September 30, 2010, are described below:

Natural gas and oil operating costs for the nine months ended September 30, 2011 increased to $153,329 from $114,953 for the nine months ended September 30, 2010, an increase of 33%. The increase in natural gas and oil operating costs was caused by the increase in production and an increase in the number of producing wells when compared to the same period in the prior year.

General and administrative costs for the nine months ended September 30, 2011 increased to $469,520 from $453,009 for the nine months ended September 30, 2010, an increase of 4%. The slight increase was caused by an increase in stock based compensation of $83,346, which was partially offset by a decrease in realized foreign exchange losses as compared to the previous period in the corresponding year.

Depreciation and depletion costs for the nine months ended September 30, 2011 increased to $388,169 from $76,291. The increase was caused by an increase in production as a proportion of the Company’s reserves, from our natural gas and oil wells, in particular, our wells located in California, Texas and Oklahoma.

Net Operating Income/(Loss)

The net operating income for the nine months ended September 30, 2011 was $22,324, compared to a net operating income of $379,458 for the nine months ended September 30, 2010 due to the factors described above, which included a $518,874 the gain on sale of natural gas and oil properties.

Other Income and Expense

We reported other net income of $4 for the nine months ended September 30, 2011, as compared to other net income of $192 in the nine months ended September 30, 2010. Other income was attributable to interest received on bank deposits.

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Net Income/(Loss) Attributable to Delta Oil and Gas Inc.

As a result of the above, net income for the nine months ended September 30, 2011 was $20,703, compared to net income of $376,069 for the nine months ended September 30, 2010.

There are material events and uncertainties which could cause our reported financial information to not to 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 the Company’s financial results for the eight most recently completed quarters, removing non-cash items. The following information is presented for informational purposes only; the net income/(loss) totals below do not match the Financial Statements due to the removal of non-cash items.

	Sept 30, 2011	Jun 30, 2011	Mar 31, 2011	Dec 31, 2010	Sept 30, 2010	Jun 30, 2010	Mar 31, 2010	Dec 31, 2009
	$	$	$	$	$	$	$	$
Revenue	219,471	405,068	410,524	358,700	693,894	206,319	125,432	135,054
Operating Costs	(217,855)	(323,601)	(471,283)	(1,280,437)	(194,407)	(201,940)	(249,840)	(1,338,180)
Non-cash items *	103,580	129,479	247,732	985,464	-	-	-	1,124,869
Net Income/(loss)	105,196	210,946	186,973	64,327	499,395	1,695	(124,408)	(78,257)

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

Liquidity and Capital Resources

As of September 30, 2011, we had total current assets of $687,045 and total current liabilities in the amount of $313,398. As a result, we had working capital of $373,647 as of September 30, 2011.

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The revenue we generated from natural gas and oil sales for the nine months ended September 30, 2011 marginally exceeded our operating expenses over the same period. As such, we anticipate that we may require additional financing activities including issuance of our equity or debt securities to fund our operations and proposed drilling activities beyond the next twelve months.

We will require additional funds to expand our acquisition, exploration and production of natural oil and gas properties. Our management also anticipates that the current cash on hand may not be sufficient to fund our continued operations at the current level for the next twelve months. Additional capital will be required to effectively expand our operations through the acquisition and drilling of new prospects and to implement our overall business strategy. It is uncertain whether we will be able to obtain financing when sought or obtain it on terms acceptable to us. We can provide no assurance that we will be able to secure any financing. If we are unable to obtain additional financing when sought, the full implementation of our ability to expand our operations will be impaired and may be forced to cease operations, liquidate assets, seek additional capital on less favourable terms and/or pursue other remedial measures. Any additional equity financing may involve substantial dilution to our then existing shareholders.

Cash Generated/(Used) in Operating Activities

Operating activities generated $753,270 in cash for the nine months September 30, 2011, compared to $84,360 cash generated in operating activities for the nine months September 30, 2011. Our positive cash flow for the nine months September 30, 2011 was primarily attributable to an depreciation and depletion expense of $388,169 during the reporting period and an increase in accounts payable of $190,439 over the reporting period.

Cash Flows From Investing Activities

Cash flows used in investing activities for the nine months September 30, 2011 was $747,079, compared to $41,248 cash generated from investing activities for the nine months September 30, 2010. During the nine months September 30, 2011, we invested $762,810 in natural gas and oil working interests, but received $15,731 in proceeds from the sale of natural gas and oil working interests. All cash used in investment activities during nine months September 30, 2010 related to investments in natural gas and oil working interests.

Cash from Financing Activities

Cash flows used by financing activities the nine months September 30, 2011 were $8,807, as compared to of $23,465, for the nine months September 30, 2010. Cash flows used by financing activities relating to restricted cash held for drilling activities for the second exploration well in the Company’s Texas Prospect

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

We have incurred a net loss of $5,385,534 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.

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Critical Accounting Policies

In December 2001, the SEC requested that all registrants list their most “critical accounting polices” in the Management Discussion and Analysis. The SEC indicated that a “critical accounting policy” is one which is both important to the portrayal of a company’s financial condition and results, and requires management’s most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain. We believe that the following accounting policies fit this definition.

Oil and Gas Joint Ventures

All exploration and production activities are conducted jointly with others and, accordingly, the accounts reflect only our proportionate interest in such activities.

Natural Gas and Oil Properties

We account for our oil and gas producing activities using the full cost method of accounting as prescribed by the FASB Accounting Standards Codifications. 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. Unevaluated oil and gas properties are assessed at least annually for impairment either individually or on an aggregate 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.

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 we share an undivided interest with other producers are recognized based on the actual volumes sold by us during the period. Gas imbalances occur when our actual sales differ from its entitlement under existing working interests. We record a liability for gas imbalances when we have sold more than our 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. At September 30, 2011 and 2010, we had no overproduced imbalances.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk.

(Not Applicable).

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

We carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of September 30, 2011. This evaluation was carried out under the supervision and with the participation of our Chief Executive Officer, Mr. Christopher Paton-Gay, and our Chief Financial Officer, Mr. Kulwant Sandher. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2011, our disclosure controls and procedures are effective.

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act are recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in our reports filed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

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 quarter ended September 30, 2011 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

During the three months ended September 30, 2011, there have been no material developments in the legal proceedings discussed in our Quarterly Report on Form 10-Q for the period ended March 31, 2011.

Item 1A. Risk Factors.

(Not Applicable).

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

During to the reporting period, we issued to three consultants in exchange for services rendered options to purchase an aggregate of 600,000 shares of our common stock at an exercise price of $0.135 exercisable for a period of 5 years. These options 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. We did not engage in any general solicitation or advertising.

Item 3. Defaults upon Senior Securities.

None.

Item 4. (Removed and Reserved).

Item 5. Other Information.

None.

Item 6. Exhibits.

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

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SIGNATURES

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

	Delta Oil & Gas, Inc.

Date:	November 14, 2011

	By: /s/ Christopher Paton-Gay Christopher Paton-Gay Title: Chief Executive Officer and Director
Date:	November 14, 2011
	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 June 30, 2011

Exhibit No.		Description
31.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

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

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

101.INS *		XBRL Instance Document

101.SCH *		XBRL Taxonomy Extension Schema Document

101.CAL *		XBRL Taxonomy Extension Calculation Linkbase Document

101 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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