UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2008
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from 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)		(IRS Employer Identification No.)

2600 144 4th Ave S.W., Calgary, Alberta, Canada T2P 3N4

(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 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 October 17, 2008
Common Stock, $0.001 par value	46,840,506

	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 .	17
Item 4T.	Controls and Procedures.	17
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings .	18
Item 1A.	Risk Factors.	18
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	18
Item 3.	Defaults Upon Senior Securities.	18
Item 4.	Submission of Matters to a Vote of Security Holders.	19
Item 5.	Other Information.	19
Item 6.	Exhibits.	19
Signatures
Exhibits
Certifications

- 2 -

 PART I - FINANCIAL INFORMATION

Item 1.       Financial Statements

Our unaudited consolidated financial statements included in this Form 10-Q are as follows:
F-1	Unaudited Consolidated Balance Sheet as of September 30, 2008.
F-2	Unaudited Consolidated Statements of Operations for the three and nine months ended September 30, 2008 and 2007 and from inception on January 9, 2001 to September 30, 2008.
F-3	Unaudited Consolidated Statements of Cash Flows for the nine months ended September 30, 2008 and 2007 and from inception on January 9, 2001 to September 30, 2008.
F-4	Unaudited Consolidated Statement of Changes in Stockholders' Equityfrom inception on January 9, 2001 to September 30, 2008.
F-5	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, 2008 are not necessarily indicative of the results that can be expected for the full year.

- 3 -

DELTA OIL & GAS, INC.
(A Development Stage Company)
Consolidated Balance Sheets
(Stated in U.S. Dollars)
(Audited)
	September 30,			December 31,
	2008			2007
ASSETS	(Unaudited)			(Audited)
Current
Cash and cash equivalents	$	1,072,012		$	71,115
GIC receivable		-			236,112
Accounts receivable		73,586			153,990
Franchise tax prepaid		6,912			6,912
Prepaid expenses		57,409			19,364
		1,209,919			487,493
Natural Gas And Oil Properties
Proved property		1,575,936			1,432,776
Unproved property		674,019			1,368,260
		2,249,955			2,801,036
Other Equipment
Computer equipment		4,483			4,483
Less: accumulated depreciation		(4,098	)		(3,351	)
		385			1,132
	$	3,460,259		$	3,289,661
LIABILITIES AND STOCKHOLDERS' EQUITY
LIABILITIES
Current
Accounts payable and accrued liabilities	$	26,566		$	166,217
Long Term
Asset retirement obligation		121,866			111,803
		148,432			278,020
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, 46,840,506 and 45,940,506 shares issued
and outstanding, respectively		46,841			45,941
Additional paid-in capital		6,087,674			6,136,288
Cumulative other comprehensive income		169,684			187,348
Deficit accumulated during the development stage		(2,992,372	)		(3,357,936	)
		3,311,827			3,011,641
	$	3,460,259		$	3,289,661
The accompanying notes are an integral part of these consolidated financial statements

F - 1

DELTA OIL & GAS, INC.
(A Development Stage Company)
Consolidated Statements of Operations
(Stated in U.S. Dollars)
(Unaudited)
													CUMULATIVE PERIOD
													FROM INCEPTION
													JANUARY 9, 2001
	THREE MONTHS ENDED						NINE MONTHS ENDED						TO
	SEPTEMBER 30,						SEPTEMBER 30,						SEPTEMBER 30,
	2008			2007			2008			2007			2008
Revenue
Natural gas and oil sales	$	190,076		$	230,483		$	773,216		$	638,126		$	2,298,154
Gain on sale of natural gas and oil properties		719,146			-			719,146			-			1,780,305
		909,222			230,483			1,492,362			638,126			4,078,459
Costs And Expenses
Natural gas and oil operating costs		48,516			44,040			179,626			127,301			514,738
General and administrative		158,457			163,918			344,090			1,075,260			3,127,215
Accretion		3,354			-			10,062			-			14,938
Depreciation and depletion		39,820			232,338			200,767			561,287			1,373,783
Impairment of natural gas and oil properties		-			-			388,702			40,589			2,002,167
Dry well costs written off		-			-			-			-			119,961
		250,147			440,296			1,123,247			1,804,437			7,152,802
Net Operating Income (Loss)		659,075			(209,813	)		369,115			(1,166,311	)		(3,074,343	)
Other Income and (Expense)
Forgiveness of debt		-			-			-			-			39,933
Interest income		1,213			9,364			1,465			32,563			62,634
Interest expense		(1,598	)		-			(5,016	)		-			(5,016	)
		(385	)		9,364			(3,551	)		32,563			97,551
Income (Loss) before income taxes	$	658,690		$	(200,449	)	$	365,564		$	(1,133,748	)	$	(2,976,792	)
Income taxes		-			6,109			-			10,270			15,580
Net Income (Loss)	$	658,690		$	(206,558	)	$	365,564		$	(1,144,018	)	$	(2,992,372	)
Basic And Diluted Income (Loss) Per Common Share	$	0.01		$	(0.00	)	$	0.01		$	(0.03	)
Weighted Average Number Of
Common Shares Outstanding		46,840,506			45,918,767			46,098,170			45,625,891
The accompanying notes are an integral part of these consolidated financial statements

F - 2

DELTA OIL & GAS, INC.
(A Development Stage Company)
Consolidated Statements of Cash Flows
(Stated in U.S. Dollars)
(Unaudited)
							CUMULATIVE PERIOD
							FROM INCEPTION
							JANUARY 9, 2001
	NINE MONTHS ENDED						TO
	SEPTEMBER 30,						SEPTEMBER 30,
	2008			2007			2008
Cash Flows From Operating Activities:
Net income (loss) for the period	$	365,564		$	(1,144,018	)	$	(2,992,372	)
Adjustments to reconcile net income (loss) to net cash
generated (used) in operating activities:
Gain on sale of natural gas and oil properties		(719,146	)		-			(1,780,305	)
Accretion		10,062			-			14,938
Depreciation and depletion		200,767			561,287			1,373,783
Impairment of natural gas and oil properties		388,702			40,589			2,002,167
Dry well costs written off		-			-			119,961
Stock-based compensation expense		-			134,754			608,083
Shares issued to President & CEO for servicess rendered		26,500			460,000			486,500
Shares issued to CFO for services rendered		21,200			44,843			158,700
Shares issued to Investor Relations Services Inc for services rendered		-			40,800			40,800
Realized foreign exchange loss		(17,664	)		-			166,472
Changes in operating assets and liabilities:
GIC		236,112			-			-
Accounts receivable		80,404			(47,832	)		(73,586	)
Accounts payable and accrued liabilities		(139,651	)		30,139			(89,457	)
Tax (Prepaid)		-			(6,912	)		(6,912	)
Prepaid expenses		(38,045	)		(17,908	)		(57,409	)
Net Cash Generated/(Used) in Operating Activities		414,805			95,742			(28,637	)
Cash Flows From (Used By) Investing Activities:
Purchase of other equipment		-			-			(4,483	)
Sale proceeds of natural gas and oil working interests		1,309,826			-			2,809,826
Investment in natural gas and oil working interests		(628,320	)		(1,208,094	)		(6,545,127	)
Net Cash Used in Investing Activities		681,506			(1,208,094	)		(3,739,784	)
Cash Flows From (Used By) Financing Activities:
Registration of shares under Form S-4		(95,414	)					(95,414	)
Proceeds from issuance of common stock		-			45,000			4,935,847
Net Cash Provided by (Used By) Financing Activities		(95,414	)		45,000			4,840,433
Net Increase/(Decrease) In Cash And Cash Equivalents		1,000,897			(1,067,352	)		1,072,012
Cash And Cash Equivalents At Beginning Of Period
(Excess Of Deposits  Over Checks Issued)		71,115			1,668,758			-
Cash And Cash Equivalents At End Of Period	$	1,072,012		$	601,406		$	1,072,012
Supplemental Disclosures of Non-Cash Financing Activities
500,000 shares issued to the President & CEO as part of his	$	26,500		$	460,000		$	486,500
compensation package
400,000 shares issued to the CFO for services rendered	$	21,200		$	137,500		$	158,700
60,000 shares issued to Investor Relations Services Inc., for
services rendered.	$	-		$	40,800		$	40,800
Supplemental Disclosures of Cash Flow Information
Interest paid	$	5,016			-		$	5,016
Income taxes for 2006	$	-		$	6,109		$	-
The accompanying notes are an integral part of these consolidated financial statements

F - 3

DELTA OIL & GAS INC.
(A Development Stage Company)
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
AND COMPREHENSIVE INCOME
PERIOD FROM INCEPTION, JANUARY 9, 2001, TO SEPTEMBER 30, 2008
(Stated in U.S. Dollars)
(Unaudited)
														DEFICIT
	COMMON STOCK													ACCUMULATED
	NUMBER							SHARE			SHARE			DURING THE			CUMULATIVE
	OF COMMON		PAR		ADDITIONAL			SUBSCRIPTIONS			SUBSCRIPTIONS			DEVELOPMENT			COMPREHENSIVE
	SHARES VALUE		VALUE		PAID-IN CAPITAL			RECEIVED			RECEIVABLE			STAGE			INCOME			TOTAL
Shares issued for cash at $0.00018		13,750,000	$	13,750	$	(11,250	)	$	-		$	-		$	-		$	-		$	2,500
Shares issued for cash at $0.0036		27,500,000		27,500		72,500			-			-			-			-			100,000
Shares issued for cash at $0.045		46,750		47		2,078			-			-			-			-			2,125
Net (loss) for the period ended		-		-		-			-			-			(184,407	)		-			(184,407	)
Balance, December 31, 2001		41,296,750		41,297		63,328			-			-			(184,407	)		-			(79,782	)
Net (loss) for the year		-		-		-			-			-			(62,760	)		-			(62,760	)
Balance, December 31, 2002		41,296,750		41,297		63,328			-			-			(247,167	)		-			(142,542	)
Net (loss) for the year		-		-		-			-			-			(24,423	)		-			(24,423	)
Balance, December 31, 2003		41,296,750		41,297		63,328			-			-			(271,590	)		-			(166,965	)
Share subscriptions received		-		-		-			160,000			-			-			-			160,000
Net (loss) for the year		-		-		-			-			-			(31,574	)		-			(31,574	)
Balance, December 31, 2004		41,296,750		41,297		63,328			160,000			-			(303,164	)		-			(38,539	)
Units issued for cash at $1.00,		2,483,985		2,484		2,481,241			(160,000	)		-			-			-			2,323,725
net of share issuance cost
Options exercised for cash at $0.8		245,000		245		195,755			-			(16,000	)		-			-			180,000
Stock-based compensation		-		-		370,267			-			-			-			-			370,267
Net (loss) for the year		-		-		-			-			-			(570,050	)		-			(570,050	)
Balance, December 31, 2005		44,025,735		44,026		3,110,591			-			(16,000	)		(873,214	)		-			2,265,403
Subscriptions receivable		-		-		-			-			16,000			-			-			16,000
Options exercised for cash at $0.8		305,000		305		243,695			-			-			-			-			244,000
Options exercised for cash at $1.00		12,500		13		12,488			-			-			-			-			12,501
Shares issued for cash at $2.75,		727,271		727		1,849,268			-			-			-			-			1,849,995
net of finders fee
Stock-based compensation		-		-		195,719			-			-			-			-			195,719
Net (loss) for the year		-		-		-			-			-			(234,763	)		-			(234,763	)
Balance, December 31, 2006		45,070,506		45,071		5,411,761			-			-			(1,107,977	)		-			4,348,855
Options exercised for cash at $0.75		60,000		60		44,940			-			-			-			-			45,000
Shares issued to President & CEO as		500,000		500		459,500			-			-			-			-			460,000
part of his compensation package at $0.92
Shares issued to Investor Relations		60,000		60		40,740			-			-			-			-			40,800
Services, Inc. as part of the agreement
Shares issued to CFO for services rendered		250,000		250		137,250			-			-			-			-			137,500
Stock-based compensation		-		-		42,097			-			-			-			-			42,097
Comprehensive (loss):
Cumulative translation adjustment		-		-		-			-			-			-			187,348			187,348
Net (loss) for the year		-		-		-			-			-			(2,249,959	)		-			(2,249,959	)
Comprehensive (loss)																					(2,062,611	)
Balance, December 31, 2007		45,940,506		45,941		6,136,288			-			-			(3,357,936	)		187,348			3,011,641
Shares issued to President & CEO & CFO as		900,000		900		46,800			-			-			-			-			47,700
part of their compensation package at $0.053
Registration of shares under Form S-4		-		-		(95,414	)		-			-			-			-			(95,414	)
Comprehensive income:
Cumulative translation adjustment		-		-		-			-			-			-			(17,664	)		(17,664	)
Net income for the period		-		-		-			-			-			365,564			-			365,564
Comprehensive income																					347,900
Balance, September 30, 2008		46,840,506	$	46,841	$	6,087,674		$	-		$	-		$	(2,992,372	)	$	169,684		$	3,311,827
The accompanying notes are an integral part of these consolidated financial statements

F - 4

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(Stated in U.S. Dollars)

1.            BASIS OF PRESENTATION
 

The unaudited consolidated financial statements as of September 30, 2008 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 adjustment (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, 2007 audited financial statements and notes thereto.  The results of the operations for the nine months ended September 30, 2008 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 a development stage, 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.

During the year ended December 31, 2004, the Company completed a forward stock split on the basis of 5 ½ common shares for every one previously held common share; common shares outstanding have been adjusted retroactively.

b)   Development Stage Activities

The Company is a development stage enterprise engaged in the exploration for and production of natural gas and oil in the United States and Canada.

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 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.

c)   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 $2,992,372 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.

F - 5

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(Stated in U.S. Dollars)

3.           SIGNIFICANT ACCOUNTING POLICIES

a)   Basis of Consolidation

The consolidated financial statements 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.  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.

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.

d)   Asset Retirement Obligations

The Company has adopted Statement of Financial Accounting Standards No. 143 (“SFAS 143”), “Accounting for Asset Retirement Obligations”, 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)   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.

F - 6

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(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. At September 30, 2008 and 2007, 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)  GIC Receivable

GIC Receivable is non-redeemable until October 9, 2008 and bears an interest rate of 2.1%.

i)   Environmental Protection and Reclamation Costs

The operations of the Company have been, and may be 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.

j)   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 period end are included in other comprehensive income.

k)   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.

F - 7

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(Stated in U.S. Dollars)

3. SIGNIFICANT ACCOUNTING POLICIES (Continued)

l)   Impairment of Long-Lived Assets

In the event that facts and circumstances indicate that the costs of long-lived assets, other than oil and gas properties, may be impaired, and evaluation of recoverability would be performed.  If an evaluation is required, the estimated future undiscounted cash flows associated with the asset would be compared to the asset’s carrying amount to determine if a write-down to market value or discounted cash flow value is required.  Impairment of oil and gas properties is evaluated subject to the full cost ceiling as described under Natural Oil and Gas Properties.

m)   Loss Per Share

In February 1997, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 128, “Earnings Per Share” (“SFAS 128”).  Under SFAS 128, 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.

n)   Income Taxes

The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax bases of assets and liabilities, and their reported amounts in the financial statements, and (ii) operating loss and tax credit carryforwards 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.

o)   Financial Instruments

The Company’s financial instruments consist of cash and cash equivalent, GIC receivable, accounts receivable, franchise tax prepaid, accounts payable, accrued liabilities and loan payable.

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 approximated to their carrying values.

o)      Comprehensive Loss

SFAS No. 130, “Reporting Comprehensive Income,” 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 Statements of Changes in Stockholders’ Equity.

p)      Stock-Based Compensation

The Company records stock-based compensation in accordance with SFAS 123(R), “Share-Based Payments,” 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. In March 2005, the Securities and Exchange Commission issued SAB 107 relating to SFAS 123(R). The Company applied the provisions of SAB 107 in its adoption of SFAS 123(R).

F - 8

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(Stated in U.S. Dollars)

3. SIGNIFICANT ACCOUNTING POLICIES (Continued)

p)   Stock-Based Compensation (Continued)

SFAS 123(R) 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, 2007		Addition		Depletion for the period			Impairment			September 30, 2008
USA properties	$	1,197,630	$	337,107	$	(137,621	)	$	-		$	1,397,116
Canada properties		235,146		394,774		(62,398	)		(388,702	)		178,820
Total	$	1,432,776	$	731,881	$	(200,019	)	$	(388,702	)	$	1,575,936

a) Proved Properties - Descriptions

Properties in U.S.A.

i.   Owl Creek Prospect, Oklahoma, USA

In June 2006, the Company entered into an agreement to accept the assignment of an undivided 20% working interest in a potential oil well known as the Powell#2 and an option to purchase a 20% interest in all future wells drilled on the land surrounding Powell#2.  In addition the Company has an option to participate in any lands of mutual interest that may be acquired in the future by the Owl Creek participating partners.  As of June 30, 2008, the cost to the Company for this assignment was $394,499.  On August 20, 2008, the Company assigned all of its interest in exchange for a cash amount of $760,438.

In July 2006, the Company also elected to participate in Isbill #1-36, which was abandoned during the year.  Its costs amounted to $80,738 was moved to the proven cost pool for depletion.

In January 2007, the Company elected to participate in Isbill #2-36 well.  The Company paid $187,559 for its 20% of working interest.  Isbill #2-36 started production from April 2007.  As of July 31, 2008, the Company expended $196,181 on Isbill #2-36.  On August 20, 2008, the Company assigned all o its interest in exchange for a cash amount of $549,388.

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 amount to $68,118 was moved to the proven cost pool for depletion.  In October 2007, Ruggles #1-15 was also abandoned and the cost of $84,328 was moved to the proven cost pool for depletion.

F - 9

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(Stated in U.S. Dollars)

4.            NATURAL GAS AND OIL PROPERTIES (Continued)

a) Proved Properties - Descriptions

Properties in U.S.A.

i.     Owl Creek Prospect, Oklahoma, USA (Continued)

In October 2007, the Company elected to participate in Powell #3-25 and paid $112,319 for the estimated drilling costs.  Powell #3-25 was abandoned on November 9, 2007.  Its costs amounted to $81,998 was moved to the proven cost pool for depletion.  The unused estimated drilling costs were applied to operating costs of other wells.

In the 2006-3 Drilling Program, Elizabeth #1-25 was plugged 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.

In the 2007-1 Drilling Program, Pollack #1-35 was plugged and abandoned on January 19, 2008.  Its cost amounted to $150,841 was moved to the proven cost pool for depletion.  Hulsey #1-8 started producing in February 2008; the cost of $161,039 was moved to the proven cost pool.  River #1-28 started producing in June 2008; the cost of $150.582 was moved to the proven cost pool.

 ii.    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.

As of 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.  As of December 31, 2007, both wells were found to be proved wells.

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 from October 2007, and PP F-12-3 started production from November 2007.  Additional AFE in the amount of $36,498 for workovers 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-41salt water disposal well.

F - 10

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(Stated in U.S. Dollars)

4.            NATURAL GAS AND OIL PROPERTIES (Continued)

a) Proved Properties - Descriptions

Properties in U.S.A.

iii.   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 amounted to $40,605 was moved to the proven cost pool for depletion.  Randall#1 was abandoned in June 2007, its costs amounted to $26,918 was moved to the proven cost pool for depletion.  BR F-24 was abandoned and its cost amounted to $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.

iv.    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.

Properties in Canada

v. Wordsworth Prospect, Saskatchewan, Canada

On April 10, 2006, the Company entered into an agreement (the “Agreement”) with Petrex Energy Ltd., for a participation and Farmout agreement where the Company will participate for 15% gross working interest before payout (BPO) and 7.5% gross working interest after pay out (APO) in a proposed four well horizontal drilling program in the Wordsworth area in Southeast Saskatchewan, Canada.  As at September 30, 2008, the Company had advanced $228,761 as its share of the costs in this Agreement.  Currently there is one producing well on this prospect.

vi.       Todd Creek, Alberta, Canada

In January 2005, the Company acquired a 20% working interest in 13.75 sections (8,800 acres) of land in Todd Creek, Alberta, Canada, at a cost of $597,263.  One of the well 13-28-9-2W5M has production since October 2006.

The Company paid $314,959 (CDN$352,376) on October 27, 2006 for well 13-33-8-2W5M.  It was abandoned and the cost was moved to the proved properties cost pool for depletion.  During the year ended of December 31, 2007, the remaining wells at Todd Creek were abandoned and the cost was moved to proven cost pool for depletion.

vii.       Hillspring, Alberta, Canada

In January 2005, the Company acquired a 10% working interest in 1 section (64 acres) of land in Hillspring, Alberta, Canada, at a cost of $414,766.   During the year ended of December 31, 2007, it was abandoned and the cost was moved to proven cost pool for depletion.

F - 11

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(Stated in U.S. Dollars)

4.     NATURAL GAS AND OIL PROPERTIES (Continued)

b)     Unproved Properties

Properties	December 31, 2007		Addition		Cost added to capitalized cost			September 30, 2008
USA properties	$	781,446	$	419,332	$	(805,977	)	$	394,801
Canada properties		586,814		81,066		(388,662	)		279,218
Total	$	1,368,260	$	500,398	$	(1,194,639	)	$	674,019

b) Unproved Properties - Descriptions

Properties in U.S.A.

i.     Owl Creek Prospect, Oklahoma, USA

In June 2006, the Company entered into an agreement to accept the assignment of an undivided 20% working interest in a potential oil well known as the Powell#2 and an option to purchase a 20% interest in all future wells drilled on the land surrounding Powell#2.  In addition the Company has an option to participate in any lands of mutual interest that may be acquired in the future by the Owl Creek participating partners.

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, 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.  On December 12, 2007, estimated drilling costs of $116,023 for Pollack #1-35 was accrued to the year end of December 31, 2007 and paid on January 14, 2008.

The Company also paid estimated completion cost of $56,734 for the well, Hulsey #1-8, on January 18, 2008; paid estimated drilling cost of $92,593 for the well, River #1-28, on February 12, 2008 and estimated completion costs of $63,111 on April 16, 2008.  During August to September 2008, the Company paid estimated drilling costs of $82,830 and estimated completion costs of $80,905 for the well, Hulsey #2-8.  All of the wells are for the 2007-1 Drilling Program.

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.

F - 12

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(Stated in U.S. Dollars)

4.            NATURAL GAS AND OIL PROPERTIES (Continued)

b)    Unproved Properties - Descriptions

Properties in Canada

iii. Wordsworth Prospect, Saskatchewan, Canada

In April 2007, the Company entered into an agreement (the “Agreement”) with Petrex Energy Ltd., for a participation and Farmout agreement where the Company will participate for 15% gross working interest before payout (BPO) and 7.5% gross working interest after pay out (APO) in a proposed four well horizontal drilling program in the Wordsworth area in Southeast Saskatchewan, Canada.  As at September 30, 2008, the Company had expended $162,996 of the well 3B9-23/3A11.  In March 2008, the Company joined the drilling of a new well, 2 HZ 3B9 LEG.  As at September 30, 2008, the Company had expended $37,070 on this well.  In September 2008, the Company joined the drilling of a new well, HZ 1C2-23 and paid a cash call of $79,152 (CAD$84,233).

iv.    Strachan Prospect, Alberta, Canada

In September 2005, the Company entered into a participation and farmout agreement with Odin Capital Inc. (“Odin”) where the Company will participate for 4% share of the costs of drilling a test well in certain lands located in the Leduc formation, Alberta, Canada.  In exchange for the participation costs, the Company will earn interests in certain petroleum and natural gas wells ranging from 1.289% to 4.0%.  As at December 31, 2007, the Company has advanced $388,662 as its share of the costs in the Leduc formation property.  The well was abandoned in the three month ended of March 31, 2008; the cost of $388,662 was moved to the proven cost pool for depletion.

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 Corporation’s accounts receivable is with joint venture partners in the oil and gas industry and is subject to normal industry credit risks.

F - 13

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(Stated in U.S. Dollars)

5.           NATURAL GAS AND OIL EXPLORATION RISK (Continued)

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.             NOTE PAYABLE

On February 12, 2008, the Company used a promissory note in exchange for proceeds of $90,000 from Venture Capital Asset Management.  The loan is unsecured and bears an interest rate of 10% per annum.  On September 3, 2008, the Company paid back the promissory note of $90,000 and the accrued interest of $5,016.

7.             ASSET RETIREMENT OBLIGATIONS

The ARO is calculated using the 5% value of proved properties as at December 31, 2007.  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 period ended September 30, 2008 and year ended December 31, 2007:

	September 30,		December 31,
	2008		2007
Balance, beginning of period	$	111,803	$	40,635
Liabilities assumed		-		66,292
Accretion expense		10,063		4,876
Balance, end of period	$	121,866	$	111,803

8.             SHARE CAPITAL

i. Common Stock

On January 11, 2006, the Company issued 75,000 common shares for exercise of stock options at $0.80 per share.

On January 24, 2006, the Company issued 230,000 common shares for exercise of stock options at $0.80 per share.

On January 25, 2006, the Company issued 12,500 common shares for exercise of stock options at $1.00 per share.

On April 25, 2006, the Company issued 727,271 common shares pursuant to a private placement at $2.75 per share.

On January 23, 2007, the Company issued 60,000 common shares for exercise of stock options at $0.75 per share.

F - 14

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(Stated in U.S. Dollars)

8.            SHARE CAPITAL (Continued)

On March 1, 2007, the Company issued 500,000 common shares to the President and CEO as part of his compensation package.  The price of the share as of March 1, 2007 was $0.92.

On May 1, 2007, the Company issued 60,000 common shares to Investor Relations Services, Inc. as part of the investor relation services and consulting agreement.  The price of the share as of May 1, 2007 was $0.68.

On July 8, 2007, the Company issued 250,000 common shares to its Chief Financial Officer as part of his services rendered and in lieu of cancellation of stock options.  The price of the share was $0.55.  It was the average of the share price of July 6 and July 9, 2007.

On August 13, 2008, the Company issued 500,000 common shares to the President and CEO and 400,000 common shares to the CFO as part of their compensation package.  The price of the share as of August 13, 2008 was $0.053.

Preferred Stock

The Company did not issue any preferred stock during the period ended September 30, 2008 (December 31, 2007 - $ Nil).

ii. Stock Options

Compensation expense related to stock options granted is recorded at their fair value as calculated by the Black-Scholes option pricing model.  Options exercised for the nine-month ended September 30, 2008 was nil (Year ended December 31, 2007 - $42,097, related to options granted during the year ended December 31, 2007).  The changes in stock options are as follows:

	Number	Weighted average exercise price
Balance outstanding, December 31, 2007 Granted Forfeited Exercised Balance outstanding, September 30, 2008	240,000               -  - -	$                      0.75                         -            - -
	240,000	$                      0.75

The weighted average assumptions used in calculating the fair value of stock options granted and vested during the year ended December 31, 2007 using the Black-Scholes option pricing model are as follows:

Risk-fee interest rate	3.77%
Expected life of the option	3 years
Expected volatility	69.03%
Expected dividend yield	-

The following table summarized information about the stock options outstanding as at September 30, 2008:

Options outstanding			Options exercisable
Exercise price	Number of shares	Remaining contractual life (years)	Number of shares
$ 0.75	240,000	0.47	240,000

F - 15

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(Stated in U.S. Dollars)

8. SHARE CAPITAL (Continued)

       iii. Common Stock Share Purchase Warrants

As at September 30, 2008, share purchase warrants outstanding for the purchase of common shares as follows:

Warrants outstanding              

Exercise price	Number of shares	Expiry date
$ 1.50       $ 3.00	2,483,985     727,271	February 1, 2010 April 30, 2009

9. RELATED PARTIES

During the nine-month period ended September 30, 2008, the Company paid $129,564 (September 30, 2007 - $81,596) for consulting fee and $30,919 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 August 13, 2008, the Company issued to Douglas Bolen 500,000 shares of common stock and Kulwant Sandher 400,000 shares of common stock in consideration for services rendered.  The price of the share as of August 13, 2008 was $0.053.  The total cost of $47,700 was recorded in the compensation expense for shares granted and was included in the general and administration expense.

On March 1, 2007, the Company issued to Douglas Bolen 500,000 shares of common stock in consideration for services rendered pursuant to the consulting agreement with Last Mountain Management, Inc. (“LMM”).  Douglas Bolen, Chief Executive Officer of the Company, is the sole shareholder, officer, and director of LMM. The price of the share as of March 1, 2007 was $0.92.  Total cost of $460,000 was included in the general and administration expense.

On July 8, 2007, the Company issued to Kulwant Sandher 250,000 shares of common stock in consideration for services rendered as Chief Financial Officer as well as in consideration for cancelling options previously granted.  The price of the share as of July 8, 2007 was $0.55.  The cost is $137,500, which was recorded in the compensation expense for shares granted and was included in the general and administration expense.

These shares were issued pursuant to Section 4(2) of the Securities Act of 1933, as amended.

10.           COMPARATIVE FIGURES

Certain comparative figures have been reclassified to conform to the financial statement presentation adopted in the current year.

11.           COMMITMENT AND CONTRACTURAL OBLIGATIONS

A lease agreement for the Vancouver, Canada office commenced June 1, 2008 and terminates on May 31, 2009.  The lease agreement provides a fixed rental fee of $1,425 per month plus additional charges for services supplied by the landlord or incurred on behalf of the Company in the previous month.

On March 1, 2005, the Company also rented an office in Calgary, Canada on a month to month basis for $295 per month.

F - 16

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(Stated in U.S. Dollars)

12.           SUBSEQUENT EVENT

On October 7, 2008, the Company announce that it has filed a Form S-4 with the Securities and Exchange Commission in order to register 27,168,832 of its common shares, which will form part of the consideration being offered to shareholders of The Stallion Group ("Stallion") in a proposed offer to acquire at least 80% of the shares of Stallion on a fully-diluted basis. Subject to the terms and conditions of the offer as contained in the Form S-4, it is anticipated that the consideration for each Stallion common share tendered in the offer and accepted would be 0.333 of a share of Delta common stock, and cash in the amount of $0.0008.

F - 17

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

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-KSB for the fiscal year ended December 31, 2007, 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, Delta Oil.  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 “we,” “us,” “our,” and “Delta Oil” mean Delta Oil & Gas, Inc. and our subsidiaries unless otherwise indicated.

- 4 -

Business of Issuer

We are an exploration company focused on developing North American oil and natural gas reserves.  Our current focus is on the exploration of our land portfolio comprised of working interests in acreage in Palmetto Point, Mississippi; Southern Saskatchewan, Canada; the Southern Alberta Foothills area in Canada; and South Central, Oklahoma.

Liberty Valance Well

On February 7, 2001, we acquired an 8.9% working interest in a production gas well called the Liberty Valance RD1 Gas Unit (the “Liberty Valance Well”), which is located in the Rancho Capay Gas Field in Glenn County, California.  We acquired the Liberty Valance Well for $90,000.

Based upon a reserve report, reserves in the Liberty Valance Well were estimated at 1,032 (MCF) on December 31, 2006, translating in an estimate of $123 for the standardized measure of discounted cash flows remaining from reserves as of December 31, 2006.  The operator of the Liberty Valance Well markets each non−operator's share of gas production from this well and deducts all royalty burdens and operating expenses prior to the distribution of revenues.  The Liberty Valance Well generated revenue of $2,870 during the year ended December 31, 2006.  On January 1, 2007, we sold our remaining interest in the Liberty Valance Well for forgiveness of abandonment costs associated with this well.

Todd Creek Prospect and Hillspring Prospect

On November 26, 2004, through our wholly-owned Canadian subsidiary, Delta Oil & Gas (Canada), Inc., we entered into two agreements (the "Agreements") with Win Energy Corporation, ("Win"), an Alberta based Oil & Gas Exploration Company, in order to acquire an interest in leases owned by Win.  On or about January 25, 2005, we paid Win the full purchase price set forth in the Agreements and acquired a 20% working interest in a property known as Todd Creek and a 10% working interest in a property known as Hillspring.  Both properties are located approximately 90 miles south of Calgary, Alberta in the Southern Alberta Foothills belt.

Todd Creek Prospect

On January 25, 2005, we acquired a 20% working interest in 13.75 sections of land (8,800 acres) in Todd Creek for the purchase price of $597,263 from Win.  Included in the acquisition was a test well that has been drilled and cased.  Under the terms of this agreement, Win has assumed all costs of drilling and completing or abandoning the test well up to gross costs of $1,330,000.  Thereafter, we will assume responsibility for 20% of all costs, risks, and expenses relating to the test well.  During the second quarter of 2007, we paid a cash call of $258,139 as our share of costs for the proposed drilling program.

During the second quarter of 2005, a well located in Todd Creek property was drilled to a specifically targeted depth.  This well is located in 13-28-9-2W5 in Alberta, Canada (the “13-28 well”) and it was evaluated and tested.  The operator encountered gas reservoirs and this well was tied into a newly constructed gas processing plant and production commenced in September 2006.  The revenue received from this well was $18,088 for the year ended December 31, 2007.

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Our monthly costs related to our interest in the 13-28 well exceeded the royalties we received and as a result, we abandoned our interest in this well in the fourth quarter of 2007.

In October 2006, we completed the drilling of a second well in the Todd Creek Prospect located in 13-33-8-2 in Alberta, Canada (the “13-33 well”) at a cost of $314,954.  Independent reserves reports we commissioned indicate that no economic hydrocarbons were present.  As a result, the 13-33 well was plugged and abandoned.

Hillspring Prospect

On January 25, 2005, we acquired a 10% working interest in one section of land (640 acres) in Hillspring for the purchase price of $414,766 from Win.  We previously had anticipated that a test well would have been drilled on our property interest during the second quarter of 2008, but no date has been scheduled at the present time.

Strachan Prospect

On September 23, 2005, we entered into the Farmout Agreement with Odin Capital Inc. (“Odin”), a Calgary, Alberta corporation.  A former member of our board of directors, Mr. Philipchuk, maintains a 50% ownership interest in Odin.  Odin had the right to acquire an oil and gas leasehold interests in certain lands located in Section 9, Township 38, Range 9, West of the 5th Meridian, Alberta, Canada (“Section 9”) upon incurring expenditures for drilling and testing on the property.  In exchange for us paying 4.0% of all costs associated with drilling, testing, and completing the test well on the property which we refer to as the Leduc formation test well, we will have earned:

(a)	In the Spacing Unit for the Earning Well:
(i)		a 2.0% interest in the petroleum and natural gas below the base of the Mannville, excluding natural gas in the Leduc formation; and
(ii)		a 4.0% interest in the natural gas in the Leduc formation before payout, subject to payment of the Overriding Royalty which is convertible upon payout at royalty owners option to 50% of our Interest; and
(b)	a 1.6% interest in the rights below the base of the Shunda formation in Section 10, Township 38, Range 9W5M.
(c)	a 1.289% interest in the rights below the base of the Shunda formation in Section 15 and 16, Township 38, Range 9W5M, down to the base of the deepest formation penetrated.

On October 6, 2005, drilling commenced on the Leduc formation test well.  Under the terms of the Farmout Agreement, we advanced 110% of the anticipated costs prior to drilling.  The total costs advanced by us prior to drilling were $347,431.  The well was drilled to the targeted depth of 13,650 feet.  During the three month period ended September 30, 2007, we paid additional drilling costs of $41,231 and have since incurred no additional drilling costs.

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Based on results indicating the presence of a potential gas well, the operator inserted casing into the total depth of the well in July 2006 and have committed to perform a full testing program.  During the three months ended March 31, 2008, testing showed that no economic hydrocarbons were present, thus the costs of $388,662 was transferred to the proven cost pool for depletion.

Palmetto Point Prospect - 12 Wells Phase - I

On February 21, 2006, we entered into an agreement with 0743608 B.C. Ltd., (“Assignor”), a British Columbia 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, we paid the Assignor $425,000 as payment for the assignment of the Assignor’s 10% gross working and revenue interest in the Drilling Program.  We also entered into a Joint Operating Agreement directly with Griffin on February 24, 2006.

The Initial Drilling Program on ten (10) wells on the acquired property interest was completed by Griffin.  On August 4, 2006, we paid $70,000 in exchange for our participation in an additional two well program, which has also been completed.  The prospect area owned or controlled by Griffin on which the wells were drilled is comprised of approximately 1,273 acres in Palmetto Point, Mississippi.  All twelve wells have been drilled and currently seven wells are producing, we anticipate that three wells will be producing and are currently waiting to be tied into the pipeline, and two wells were not commercially viable and were plugged and abandoned. We refer to this drilling program as Palmetto Point Phase I.  Total revenue received from these wells for the three months ended September 30, 2008 was $10,425, as compared with $21,990 in revenues for the three months ended September 30, 2007.  Total revenue received from these wells for the nine months ended September 30, 2008 was $35,842, as compared with $51,575 in revenues for the nine months ended September 30, 2007.  The decrease in revenue was caused by a temporary halt in production of these wells during the reporting period due to water contamination of these wells.  Remedial actions were taken by the installation of a salt water disposal well which was successful in eliminating the water contamination.  These wells have recommenced production and are currently producing.

In October 2007, as part of Phase I, we drilled a well (the "PP F-12") on the prospect.  Subsequent testing revealed that the PP F-12 well contained oil reserves suitable for commercial production.  The PP F-12 well began producing on October 2, 2007.   This well is situated in what is known as the Belmont Lake Oil Field.  Based on the positive results from the PP F-12 well, the operator suggested drilling an additional two development wells in the immediate vicinity in which we would participate.  In November 2007, we participated in the drilling of a step-out well from the PP F-12 (the “PP F-12 #2”).  This well was drilled to total depth, logged, tested and cased.   The PP F-12 #2 encountered approximately three feet of hydrocarbon showings and as such the operator recommended re-entering the well and directionally drilling on an angle toward the PP F-12.  Upon completion and testing of this re-entry (the “PP F-12 #2-3”), the operator encountered approximately 32 feet of hydrocarbon pay and the well was connected to a nearby pipeline and is currently producing oil.  Total revenue received from these

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two oil wells was $0 for the three months ended September 30, 2008 and $60,959 for the nine months ended September 30, 2008.  These two wells did not generate any revenue prior to 2008.  The revenue generated from these wells has been less than we anticipated as a result of a halt in production of these wells during the reporting period due to the flooding of the Mississippi basin where these wells are located.  We anticipate that these wells will recommence production during the quarter ended December 31, 2008.

Palmetto Point Prospect - 50 wells – Phase II

During the fiscal quarter ended September 30, 2006, we entered into a joint venture agreement to acquire an interest in a drilling program comprised of up to fifty natural gas and/or oil wells. The area in which the wells are being drilled is approximately 300,000 gross acres located between Southwest Mississippi and Northeastern Louisiana. Drilling commenced in September 2006.  The site of the first twenty wells is located within range to tie into existing pipeline infrastructure should the wells be suitable for commercial production.  The drilling program was conducted by Griffin in its capacity as operator.  We agreed to pay 10% of all prospect fees, mineral leases, surface leases, and drilling and completion costs to earn a net 8.0% share of all production zones to the base of a geological formation referred to as the Frio formation and 7.5% of all production to the base of a geological formation referred to as the Wilcox formation.  The cost during the quarter ending September 30, 2006 amounted to $100,000.  During the fourth quarter of fiscal 2006, we made additional payments of $300,000 that was employed in the further development of prospects on lands in Mississippi and Louisiana in accordance with the terms of the operating agreement.  We did not incur any additional payments other than drilling costs for these prospects in 2007.  We do not anticipate that we will incur any additional payments other than drilling costs for these prospects going forward.

We drilled seven wells, of which two have been abandoned (the Dixon #1 and the Randall #1).  Our costs attributable to these two abandoned wells was $67,523.  Of the successful four wells, the Redbug #1, Redbug #2 and the Buffalo River #1 began producing in the three months ended March 31, 2007 and the Faust #1, is awaiting connection to the nearby pipeline for production.  The revenue received from these wells for the three months ended September 30, 2008 was $22,028, as compared to $2,389 for the three months ended September 30, 2007.  The revenue received from these wells for the nine months ended September 30, 2008 was $73,837, compared to $9,066 for the nine months ended September 30, 2007.  The increase in revenue was caused by ongoing production for the entire nine month period ended September 30, 2008, as opposed to partial production commencing during the nine months ended September 30, 2007.

Wordsworth Prospect

On April 10, 2006, we entered into a farmout, 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 are 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

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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.  Our total costs as at December 31, 2007 was $222,649.

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.  The revenue received from this well for the three months ended September 30, 2008 was $33,406, as compared to $29,174 for the three months ended September 30, 2007.  The revenue received from this well for the nine months ended September 30, 2008 was $88,921, as compared to $104,118 for the nine months ended September 30, 2007.  The reduction in revenue was caused by the reduction in our working interest from 15% to 7.5% after payout and partially offset by an increase in commodity prices.  We do not expect the increase in commodity prices to continue for the remainder of the current fiscal year.

The 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.

Owl Creek Prospect

On June 1, 2006, we entered into an Assignment Agreement with Brinx Resources, Ltd., (“Brinx”), a Nevada Oil & Gas Exploration Company, in order to acquire a working interest in lands and leases owned by Brinx.  The purchase price of $300,000 for the assignment and options to acquire future interests has been paid in full.  We paid a further $68,987 for our proportion of costs associated with the completion of the first well.  The lands are located in Garvin & McClain Counties, Oklahoma and we refer to the lands as the “Owl Creek Prospect.”

Pursuant to the terms of the Assignment Agreement, we acquired a 20% working interest in an oil well drilled at the Owl Creek Prospect (the “Powell #2”).  The Powell #2 was drilled to total depth of 5,617 feet on May 18, 2006 and underwent testing.  Based upon the positive result of the testing of the Powell #2, this well was completed and commercial production commenced in August 2006.  Under the terms of the Assignment Agreement, we are responsible for our proportionate share of the costs of completion and tie-in for production of the Powell #2 which was $68,987.  Initially, the Powell #2 began flowing oil and natural gas under its own pressure

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without the assistance of a pump.  Revenue generated from the Powell #2 for the three months ended September 30, 2008 was $18,533, as compared to $129,567 for the three months ended September 30, 2007.  Revenue generated from the Powell #2 for the nine months ended September 30, 2008 was $173,577, as compared to $366,975 for the nine months ended September 30, 2007.  The reduction in revenue was caused by the Powell #2 being temporarily taken out of production in order to address maintenance issues and a reduction in oil production from the well.

As part of the Assignment Agreement, we were granted an option to earn a 20% working interest in any future wells drilled on the 1,120 acres of land, which make up the Owl Creek Prospect.  Lastly, we received an option to earn a 20% working interest in any future wells to be drilled on any land of mutual interest acquired by the Owl Creek participants in and around the same area.  The working interest in future wells is earned by paying 20% of the costs of drilling and completing each additional well.  Prior to drilling, we are provided an invoice for the anticipated costs of each proposed well and given the option to participate.

Based upon the positive results of the Powell #2, an additional well (the “Isbill #1-36”) was drilled and reached targeted depth in September 2006.  However, test results showed that the well was not commercially viable and it was plugged and abandoned in September 2006.  Costs of $80,738 were transferred to proved reserves and subsequently depleted in accordance with our accounting policy.

In January 2007, we commenced drilling of another well (the “Isbill #2-36”). Our 20% working interest in the Isbill #2-36 cost $157,437 for both drilling and completion.  The Isbill #2-36 was drilled to approximately 5,900 feet and encountered two potential pay zones and is a direct offset well to the Powell #2 which is currently producing.  The revenue received from the Isbill #2-36 for the three months ended September 30, 2008 was $0, as compared to $40,777 for the three months ended September 30, 2007.  The revenue received from the Isbill #2-36 for the nine months ended September 30, 2008 was $122,970, as compared to $80,585 for the nine months ended September 30, 2007.  We attribute the increased revenues from the Isbill #2-36 in the current reporting period to an increase in the price of a barrel of oil.  Our operator has experienced some maintenance difficulties in operating this well and this resulted in no revenue being generated from the Isbill #2-36 during the three months ended September 30, 2008.

In July 2008, we sold both the Powell #2 and Isbill #2-36 wells and all interest in the Owl Creek Prospect for gross proceeds of $1,309,826.  We realized a gain on sale of the property of $719,145.  We decided to dispose of the property based on the declining rates of production experienced by the operator and the reasonable offer for the both wells and the surrounding lands of 1,120 acres.

2006-3 Drilling Program

On April 17, 2007, we entered into an agreement with Ranken Energy Corporation to participate in a five well drilling program at Garvin and Murray Counties, 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.

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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.  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.  Subsequent to the completion of these wells, two remain economically viable at this time.  The Plaster #1 encountered hydrocarbon showings and is producing natural gas with amounts of associated oil as of 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.  Total revenue received from these wells for the three months ended September 30, 2008 was $638 and $46,430 for the nine months ended September 30, 2008.  These two wells did not generate any revenue prior to 2008.

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.

2007-1 Drilling Program - 3 Wells

On September 10, 2007, we entered into an agreement with Ranken Energy Corporation to participate in a three 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”) has been completed in the N.E. Anitoch Prospect and the Washington Creek Prospect respectively.  The Pollock #1-35 did not prove to be commercially viable but the Hulsey #1 has been producing in the range of 50 to 60 barrels of oil per day with approximately 50 Mcf of natural gas per day.  Drilling of the third well in this drilling program (the “River #1”) was completed during the three months ended September 30, 2008.  River #1 commenced production and the total revenue received for the three and nine month period ended September 30, 2008 was $75,231.  Hulsey #1-8 started producing during the first quarter of 2008 and the total revenue received for the three month period ended September 30, 2008 was $38,273.  The total revenue from this well for the nine month period ended September 30, 2008 was $95,451.

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Results of Operations for the three and nine months ended September 30, 2008 and 2007

Our gross revenue generated for the three months ended September 30, 2008 was $909,222, an increase of approximately 294% from revenues of $230,483 for the three months ended September 30, 2007.  Our gross revenue generated for the nine months ended September 30, 2008 was $1,492,362, an increase of approximately 134% from revenues of $638,126 for the nine months ended September 30, 2007.  The increase in gross revenue for the three and nine months ended September 30, 2008, when compared the three and nine months ended September 30, 2007, is attributable to the sale of our working interest in the Owl Creek Prospect during the three months ended September 30, 2008 for a gain of $719,146.

Revenue generated from natural gas and oil sales was $190,076 for the three months ended September 30, 2008, a decrease of approximately 18% from $230,483 for the three months ended September 30, 2007.  The decrease in revenue from natural gas and oil sales for the three months ended September 30, 2008, when compared the three months ended September 30, 2007, is primarily attributable to our wells in the Owl Creek Prospect not generating revenue for the entire three month period ended September 30, 2008 due to a temporary suspension of production in order to address maintenance issues and the sale of our working interest in the Owl Creek Prospect in July 2008.

Revenue generated from natural gas and oil sales was $773,216 for the nine months ended September 30, 2008, an increase of approximately 21% from $638,126 for the nine months ended September 30, 2007.  The increase in revenue from natural gas and oil sales for the nine months ended September 30, 2008, when compared the nine months ended September 30, 2007, is primarily attributable to revenues received from the additional wells from the Owl Creek and Palmetto prospects which started to produce revenue during the reporting period and an increase in commodity prices achieved on sales of hydrocarbons.

We incurred costs and expenses in the amount of $250,147 for the three months ended September 30, 2008, a 43% decrease from costs and expenses of $440,296 for the three months ended September 30, 2007.  We incurred costs and expenses in the amount of $1,123,247 for the nine months ended September 30, 2008, a 38% decrease from costs and expenses of $1,804,437 for the nine months ended September 30, 2008.

The decrease in costs and expenses for the three and nine months ended September 30, 2008, when compared the three and nine months ended September 30, 2007, is primarily attributable to the following factors:

·   General and administrative costs for the three months ended September 30, 2008 decreased to $158,457 from $163,918 for the three months ended September 30, 2007, a decreaseof 3%.  General and administrative costs for the nine months ended September 30, 2008 decreased to $344,090 from $1,075,260 for the nine months ended September 30, 2007, a decreaseof 68%.  The decrease in general and administrative costs was caused by a reduction in stock based compensation expense attributable to the issuances of stock options and shares of common stock.  Stock based compensation expense for the three months ended September 30, 2008 was $47,700 as compared to $53,477 for the three months ended September 30, 2007.  Stock based compensation expense for the nine months ended September 30, 2008 was $47,700, as compared to $680,397 for the nine months ended September 30, 2007.

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·   Natural gas and oil operating costs for the three months ended September 30, 2008 increased to $48,516 from $44,040 for the three months ended September 30, 2007, an increase of 10%.  Natural gas and oil operating costs for the nine months ended September 30, 2008 increased to $179,626 from $127,301 for the nine months ended September 30, 2007, an increase of 41%.  The increase in natural gas and oil operating costs is attributable to an increase in the number of producing wells in the three and nine months ended September 30, 2008, as compared to the same reporting periods in the prior year.

·   Depreciation and depletion expensefor the three months ended September 30, 2008 decreased to $39,820 from $232,338 for the three months ended September 30, 2007, a decrease of 83%.  Depreciation and depletion expensefor the nine months ended September 30, 2008 decreased to $200,767 from $561,287 for the nine months ended September 30, 2007, a decrease of 64%.  The decrease in depreciation and depletion expense is attributable to an increase in the estimated recoverable reserves and a reduction is uneconomic wells in the three and nine months ended September 30, 2008, as compared to the same reporting periods in the prior year; and

·   We recorded no impairment of natural gas and oil properties expense for the three months ended September 30, 2008 or 2007.  Impairment of natural gas and oil properties expense for the nine months ended September 30, 2008 increased to $388,702 from $40,589 for the nine months ended September 30, 2007, an increase of 858%.  The substantial increase in impairment of natural gas and oil properties expense for the nine months ended September 30, 2008, as compared to the nine months ended September 30, 2007, is attributable to the impairment of our working interests in Strachan, Alberta, Canada resulting from our evaluation that the costs associated with these prospects are highly unlikely to be recovered.

The net operating income for the three months ended September 30, 2008 was $659,075, compared to a net operating loss of $209,813 for the three months ended September 30, 2007.  The net operating income for the nine months ended September 30, 2008 was $369,115, compared to an operating net loss of $1,166,311 for the nine months ended September 30, 2007.

We reported other expenses of $385 for the three months ended September 30, 2008, as compared to other income of $9,364 in the three months ended September 30, 2007.  We reported other expenses of $3,551 for the nine months ended September 30, 2008 and other income of $32,563 for the nine months ended September 30, 2007.  Other expenses were attributable to interest expenses for a note payable which was paid in full during the reporting period.

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Net income for the quarter ended September 30, 2008 was $658,690, compared to a net loss of $206,558 for the quarter ended September 30, 2007. Net income for the nine months ended September 30, 2008 was $365,564, compared to a net loss of $1,114,018 for the nine months ended September 30, 2007.  Profitability during the three and nine months ended September 30, 2008 was attributable to an increase in revenues from new and existing wells, a reduction in operating expenses and the sale of the Owl Creek Prospect.

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.

Liquidity and Capital Resources

As of September 30, 2008, we had total current assets of $1,209,909 and total current liabilities in the amount of $26,566.  As a result, we had working capital of $1,183,353 as of September 30, 2008.

The revenue we currently generate from natural gas and oil sales does not exceed our operating expenses.  As such, we will require additional financing activities including issuance of our equity or debt securities to fund our operations and proposed drilling activities beyond the year ended December 31, 2008.  During the three months March 31, 2008, we received $90,000 from financing activities involving loan issuance.  We repaid this loan during the quarter ended September 30, 2008, including interest charges of $5,016.

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.  If we are unable to obtain additional financing, the full implementation of our ability to expand our operations will be impaired.  Any additional equity financing may involve substantial dilution to our then existing shareholders.

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Operating activities generated $414,805 in cash for the nine months ended September 30, 2008.  Our positive cash flow for the nine months ended September 30, 2008 was caused by the redemption of certain cash equivalents.

Cash flows provided by investing activities during the nine months ended September 30, 2008 was $681,506.  Our positive cash flow for the nine months ended September 30, 2008 was primarily caused by sale proceeds of natural gas and oil working interests in the amount of $1,309,826.

Cash flows provided by financing activities during the nine months ended September 30, 2008 primarily consisted of $95,414 related to the registration of shares under Form S-4.

The underlying drivers that resulted in material changes and the specific inflows and outflows of cash for the nine months ended September 30, 2008 are as follows:

·   Revenue received as a result of royalties from natural gas and oil producing properties;

·   Property acquisition costs; and

·   Sale of the Owl Creek 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

As shown in the accompanying financial statements, we have incurred a net loss of $2,992,372 since inception.  To achieve profitable operations, we require additional capital for obtaining producing oil and gas properties through either the purchase of producing wells or successful exploration activity.  We believe that we will be able to obtain sufficient funding to meet our business objectives, including anticipated cash needs for working capital and are currently evaluating several financing options.  However, there can be no assurances offered in this regard.  As a result of the foregoing, there exists substantial doubt about our ability to continue as a going concern.

Critical Accounting Policies

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.

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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 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.  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.

Unproved properties consist of lease acquisition costs and costs on well 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.

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, 2008 and 2007, we had no overproduced imbalances.

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Item 3.       Quantitative and Qualitative Disclosures About Market Risk

Not Applicable.

Item 4T.     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, 2008.  This evaluation was carried out under the supervision and with the participation of our Chief Executive Officer, Mr. Douglas Bolen, 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, 2008, 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.

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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, 2008 that have materially affected or are reasonably likely to materially affect such controls.

PART II – OTHER INFORMATION

Item 1.         Legal Proceedings

We are not a party to any pending legal proceeding.  We are not aware of any pending legal proceeding to which any of our officers, directors, or any beneficial holders of 5% or more of our voting securities are adverse to us or have a material interest adverse to us.

Item 1A.       Risk Factors

Not Applicable.

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

Other than as set forth below, we did not issue any securities without registration under the Securities Act during the reporting period.

On March 1, 2006, we entered into a consulting agreement with Last Mountain Management, Inc. (“LMM”) to provide consulting services to us (the “LMM Consulting Agreement”). Douglas Bolen, our Chief Executive Officer, is the sole shareholder, officer, and director of LMM.  Pursuant to the terms of the LMM Consulting Agreement, we issued to Mr. Bolen 500,000 shares of our common stock during the reporting period.  These shares were issued pursuant to Section 4(2).  We did not engage in any general solicitation or advertising.  The stock certificate was issued with the appropriate legends affixed to the restricted stock.

On January 1, 2008, we entered into a consulting agreement with Hurricane Corporate Services Ltd.  (“Hurricane”) to provide consulting services to us (the “Hurricane Consulting Agreement”). Kulwant Sandher, our Chief Financial Officer, is the sole shareholder, officer, and director of Hurricane.  Pursuant to the terms of the Hurricane Consulting Agreement, we issued to Mr. Sandher 400,000 shares of our common stock during the reporting period.  These shares were issued pursuant to Section 4(2).  We did not engage in any general solicitation or advertising.  The stock certificate was issued with the appropriate legends affixed to the restricted stock.

Item 3.       Defaults upon Senior Securities

None.

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Item 4.     Submission of Matters to a Vote of Security Holders

No matters have been submitted to our security holders for a vote, through the solicitation of proxies or otherwise, during the quarterly period ended September 30, 2008.

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 and 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 7, 2008
	By: /s/ Douglas Bolen                                                                                 Douglas Bolen Title:    Chief Executive Officer and Director
Date:	November 7, 2008
	By: /s/ Kulwant Sander             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

to

Quarterly Report on Form 10-Q

for the Quarter Ended September 30, 2008

Exhibit No.	Description	Filed Herewith
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	X
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	X
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	X

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