DELTA OIL & GAS INC - FORM 10-Q

Attached files

file	filename
EX-10.2 - EX102 - DELTA OIL & GAS INC	ex102.htm
EX-31.1 - EX311 - DELTA OIL & GAS INC	ex311.htm
EX-32.1 - EX321 - DELTA OIL & GAS INC	ex321.htm
EX-10.1 - EX101 - DELTA OIL & GAS INC	ex101.htm
EX-31.2 - EX312 - DELTA OIL & GAS INC	ex312.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

x	Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

	For the quarterly period ended: September 30, 2009

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

	For the transition period ___________ to __________

	Commission File Number: 000-52001

Delta Oil & Gas, Inc.

(Exact name of registrant as specified in its charter)

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

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

(Address of principal executive offices)

866-355-3644

(Registrant’s telephone number, including area code)

_______________________________________________________________

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the issuer was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. xYes o No

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

Non-accelerated filer o Smaller reporting company x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes xNo

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 29, 2009
Common Stock, $0.001 par value		13,557,107

Table of Contents

	TABLE OF CONTENTS	Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements.	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	4
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	17
Item 4T.	Controls and Procedures.	18
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings.	19
Item 1A.	Risk Factors.	19
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	19
Item 3.	Defaults Upon Senior Securities.	19
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 -

Table of Contents

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

Our unaudited consolidated financial statements included in this Form 10-Q for the three and nine months ended September 30, 2009 are as follows:
F-1	Unaudited Consolidated Balance Sheet as of September 30, 2009 and September 30, 2008;
F-2	Unaudited Consolidated Statements of Operations for the three and nine months ended September 30, 2009 and 2008 and from inception on January 9, 2001 to September 30, 2009;
F-3	Unaudited Consolidated Statements of Cash Flows for the nine months ended September 30, 2009 and 2008 and from inception on January 9, 2001 to September 30, 2009;
F-4	Unaudited Consolidated Statement of Changes in Stockholders' Equity from inception on January 9, 2001 to September 30, 2009;
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, 2009 are not necessarily indicative of the results that can be expected for the full year.

- 3 -

Table of Contents

DELTA OIL & GAS, INC.
(A Development Stage Company)

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

	September 30,			December 31,
	2009			2008
ASSETS	(Unaudited)			(Audited)

Current
Cash and cash equivalents	$	465,686		$	980,562
Accounts receivable		48,694			65,614
Franchise tax prepaid		1,004			-
Prepaid expenses		109,286			11,193

		624,670			1,057,369

Natural Gas And Oil Properties
Proved property		1,171,458			892,096
Unproved property		706,937			630,376

		1,878,395			1,522,472

Capital Assets, Net		3,456			172

TOTAL ASSETS	$	2,506,521		$	2,580,013

LIABILITIES AND STOCKHOLDERS' EQUITY

LIABILITIES

Current
Accounts payable and accrued liabilities	$	29,356		$	26,553

Long Term
Asset retirement obligation		22,696			23,604

TOTAL LIABILITIES		52,052			50,157

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, 13,557,107 and 9,368,102 shares issued
and outstanding, respectively		13,557			9,368
Additional paid-in capital		6,971,313			6,088,272

Cumulative Other Comprehensive Income/(loss)		96,538			5,978

Deficit Accumulated During The Development Stage		(4,723,053	)		(3,573,762	)

		2,358,355			2,529,856

Noncontrolling Interest		96,114			-

TOTAL STOCKHOLDERS' EQUITY		2,454,469			2,529,856

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	2,506,521		$	2,580,013


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

F - 1

Table of Contents

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,
	2009			2008			2009			2008			2009
Revenue

Natural gas and oil sales	$	101,491		$	190,076		$	233,582		$	773,216		$	2,618,612
Gain on sale of natural gas and oil properties		-		$	719,146			142,481			719,146			2,271,087

		101,491			909,222			376,063			1,492,362			4,889,699
Costs And Expenses

Natural gas and oil operating costs		25,495			48,516			98,671			179,626			656,052
General and administrative		147,141			158,457			439,363			344,090			3,480,040
Accretion		815			3,354			2,363			10,062			9,768
Depreciation and depletion		5,739			39,820			31,443			200,767			1,470,401
Impairment of natural gas and oil properties		7,867			-			210,353			388,702			3,337,466
Loss on sale of natural gas and oil properties		-			-			750,305			-			750,305

		187,057			250,147			1,532,498			1,123,247			9,704,032

Net Operating Income (Loss)		(85,566	)		659,075			(1,156,435	)		369,115			(4,814,333	)

Other Income And (Expense)

Forgiveness of debt		-			-			-			-			39,933
Interest income		2,160			1,213			7,832			1,465			76,026
Interest expense		-			(1,598	)		-			(5,016	)		(5,016	)

		2,160			(385	)		7,832			(3,551	)		110,943

Income (Loss) Before Income Taxes		(83,406	)		658,690			(1,148,603	)		365,564			(4,703,390	)

Income taxes		-			-			5,205			-			24,180

Net Income (Loss)		(83,406	)		658,690			(1,153,808	)		365,564			(4,727,570	)

Less: Net loss attributable to the noncontrolling interest		196			-			4,517			-			4,517

Net Income (Loss) Attributable to Delta Oil and Gas, Inc.	$	(83,210	)	$	658,690		$	(1,149,291	)	$	365,564		$	(4,723,053	)

Basic And Diluted Loss Per Common Share	$	(0.00	)	$	0.01		$	(0.02	)	$	0.01

Weighted Average Number Of
Common Shares Outstanding		13,557,107			9,368,102			12,246,684			9,219,634


Consolidated Statement of Comprehensive Income/(Loss)

Comprehensive (Loss)

Net Loss	$	(83,406	)	$	658,690		$	(1,153,808	)	$	365,564		$	(4,727,570	)

Other Comprehensive Loss
Foreign Currency Translation		58,366			(7,412	)		90,560			(17,664	)		96,538

Comprehensive (Loss)	$	(25,040	)	$	651,278		$	(1,063,248	)	$	347,900		$	(4,631,032	)


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

F - 2

Table of Contents

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,
	2009			2008			2009
Cash Flows From Operating Activities:

Net loss for the period	$	(1,149,291	)	$	(217,194	)	$	(4,723,053	)

Adjustments to reconcile net loss to net cash
used in operating activities:
Accretion		2,363			11,993			9,768
Depreciation and depletion		31,443			365,971			1,470,401
Impairment of natural gas and oil properties		210,353			711,563			3,337,466
Loss on sale of natural gas and oil properties		750,305			-			750,305
Stock-based compensation expense		13,750			123,724			621,833
Shares issued to President & CEO for servicess rendered		30,000			26,500			516,500
Shares issued to CFO for services rendered		12,000			21,200			170,700
Shares issued to Investor Relations Services Inc for services rendered		-			-			40,800
Realized foreign exchange loss		90,560			(20,170	)		93,326
Net loss attributable to the noncontrolling interest		(4,517	)		-			(4,517	)
Gain on sale of natural gas and oil properties		(142,481	)		(719,146	)		(2,271,087	)

Changes in operating assets and liabilities:
GIC		-			236,112			-
Accounts receivable		16,920			(48,260	)		(48,694	)
Accounts payable and accrued liabilities		2,803			(115,176	)		(86,667	)
Due to related party		-			19,559			-
Franchise tax prepaid		(1,004	)		-			(1,004	)
Prepaid expenses		(98,093	)		(63,045	)		(109,286	)

Net Cash Generated/(Used) In Operating Activities		(234,889	)		333,631			(233,209	)

Cash Flows From Investing Activities:

Purchase of other equipment		(4,886	)		-			(9,369	)
Sale proceeds of natural gas and oil working interests		407,629			1,309,826			3,217,455
Investment in natural gas and oil working interests		(634,685	)		(729,402	)		(7,264,704	)

Net Cash Generated /(Used) In Investing Activities		(231,942	)		580,424			(4,056,618	)

Cash Flows From Financing Activities:

Registration of shares under Form S-4		-			(95,414	)		-
Share issue expenses		(48,045	)		-			(180,334	)
Proceeds from issuance of common stock		-			25,000			4,935,847

Net Cash Provided/(Used) By Financing Activities		(48,045	)		(70,414	)		4,755,513

Net Increase/(Decrease) In Cash And Cash Equivalents		(514,876	)		843,641			465,686

Cash And Cash Equivalents At Beginning Of Period
(Excess Of Deposits Over Checks Issued)		980,562			238,351			-

Cash And Cash Equivalents At End Of Period	$	465,686		$	1,081,992		$	465,686

Supplemental Disclosures Of Non-Cash Financing Activities
200,000 shares issued to the President & CEO as part of their	$	30,000		$	26,500		$	516,500
compensation package

80,000 shares issued to the CFO for services rendered	$	12,000		$	21,200		$	170,700

10,000 shares issued to Investor Relations Services Inc.,
for services rendered.	$	-		$	-		$	40,800

3,909,005 shares issued for the acquisition of Oil and Gas properties	$	879,526		$	-		$	879,526

Supplemental Disclosures Of Non-Cash Transactions
Income taxes paid	$	5,205		$	-		$	24,180

Investment in natural gas and oil working interests included in	$	-		$	-		$	116,023
accounts payable

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

F - 3

Table of Contents

DELTA OIL & GAS INC.
(A Development Stage Company)

Consolidated Statement Of Changes In Stockholders' Equity
Period From Inception, January 9, 2001, to September 30, 2009
(Stated in U.S. Dollars)
(Unaudited)

														DEFICIT
	COMMON STOCK													ACCUMULATED
	NUMBER							SHARE			SHARE			DURING THE			CUMULATIVE
	OF COMMON		PAR		ADDITIONAL			SUBSCRIPTIONS			SUBSCRIPTIONS			DEVELOPMENT			COMPREHENSIVE			NONCONTROLLING
	SHARES VALUE		VALUE		PAID-IN CAPITAL			RECEIVED			RECEIVABLE			STAGE			INCOME/(LOSS)			INTEREST			TOTAL

Shares issued for cash at $0.00018		2,750,000	$	2,750	$	(250	)	$	-		$	-		$	-		$	-		$	-		$	2,500

Shares issued for cash at $0.0036		5,500,000		5,500		94,500			-			-			-			-			-			100,000

Shares issued for cash at $0.045		9,350		9		2,116			-			-			-			-			-			2,125

Net (loss) for the period ended		-		-		-			-			-			(184,407	)		-			-			(184,407	)

Balance, December 31, 2001		8,259,350		8,259		96,366			-			-			(184,407	)		-			-			(79,782	)

Net (loss) for the year		-		-		-			-			-			(62,760	)		-			-			(62,760	)

Balance, December 31, 2002		8,259,350		8,259		96,366			-			-			(247,167	)		-			-			(142,542	)

Net (loss) for the year		-		-		-			-			-			(24,423	)		-			-			(24,423	)

Balance, December 31, 2003		8,259,350		8,259		96,366			-			-			(271,590	)		-			-			(166,965	)

Share subscriptions received		-		-		-			160,000			-			-			-			-			160,000

Net (loss) for the year		-		-		-			-			-			(31,574	)		-			-			(31,574	)

Balance, December 31, 2004		8,259,350		8,259		96,366			160,000			-			(303,164	)		-			-			(38,539	)

Units issued for cash at $1.00, net of share issuance cost		496,797		497		2,483,228			(160,000	)		-			-			-			-			2,323,725

Options exercised for cash at $0.8		49,000		49		195,951			-			(16,000	)		-			-			-			180,000

Stock-based compensation		-		-		370,267			-			-			-			-			-			370,267

Net (loss) for the year		-		-		-			-			-			(570,050	)		-			-			(570,050	)

Balance, December 31, 2005		8,805,147		8,805		3,145,812			-			(16,000	)		(873,214	)		-			-			2,265,403

Subscriptions receivable		-		-		-			-			16,000			-			-			-			16,000

Options exercised for cash at $0.8		61,000		61		243,939			-			-			-			-			-			244,000

Options exercised for cash at $1.00		2,500		3		12,498			-			-			-			-			-			12,501

Shares issued for cash at $2.75,		145,455		145		1,849,850			-			-			-			-			-			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		9,014,102		9,014		5,447,818			-			-			(1,107,977	)		-			-			4,348,855

Options exercised for cash at $0.75		12,000		12		44,988			-			-			-			-			-			45,000

Shares issued to President & CEO as part of his compensation package at $0.92		100,000		100		459,900			-			-			-			-			-			460,000

Shares issued to Investor Relations Services, Inc. as part of the agreement		12,000		12		40,788			-			-			-			-			-			40,800

Shares issued to CFO for services rendered		50,000		50		137,450			-			-			-			-			-			137,500

Stock-based compensation		-		-		42,097			-			-			-			-			-			42,097

Comprehensive Income/(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		9,188,102		9,188		6,173,041			-			-			(3,357,936	)		187,348			-			3,011,641

Shares issued to President & CEO & CFO as part of their compensation package at $0.053		180,000		180		47,520			-			-			-			-			-			47,700

Registration of shares under Form S-4		-		-		(132,289	)		-			-			-			-			-			(132,289	)

Comprehensive Income/(Loss):
Cumulative translation adjustment		-		-		-			-			-			-			(181,370	)		-			(181,370	)
Net loss for the year		-		-		-			-			-			(215,826	)		-			-			(215,826	)
Comprehensive loss																								(397,196	)

Balance, December 31, 2008		9,368,102		9,368		6,088,272			-			-			(3,573,762	)		5,978			-			2,529,856

Shares issued for acquisition of oil & gas		3,909,005		3,909		875,616			-			-			-			-			-			879,525
properties
Registration of shares under Form S-4		-		-		(48,045	)		-			-			-			-			-			(48,045	)

Noncontrolling interest in subsidiary		-		-		-			-			-			-			-			100,631			100,631

Shares issued to President, CEO & CFO as part of his compensation package at $0.03		280,000		280		41,720			-			-			-			-			-			42,000

Options issued to CEO		-		-		13,750			-			-			-			-			-			13,750

Comprehensive Income/(Loss):
Cumulative translation adjustment		-		-		-			-			-			-			90,560			-			90,560
Net loss for the period		-		-		-			-			-			(1,149,291	)		-			(4,517	)		(1,153,808	)
Comprehensive loss																								(1,063,248	)

Balance, September 30, 2009		13,557,107	$	13,557	$	6,971,313		$	-		$	-		$	(4,723,053	)	$	96,538		$	96,114		$	2,454,469


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

F - 4

Table of Contents

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Stated in U.S. Dollars)

1. BASIS OF PRESENTATION

The unaudited consolidated financial statements as of September 30, 2009 included herein have been prepared without audit pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with United States generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. It is suggested that these consolidated financial statements be read in conjunction with the December 31, 2008 audited financial statements and notes thereto. The results of the operations for the nine months ended September 30, 2009 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.

The Company is subject to several categories of risk associated with its development stage activities. Natural gas and oil exploration and production is a speculative business, and involves a high degree of risk. Among the factors that have a direct bearing on the Company’s prospects are uncertainties inherent in estimating natural gas and oil reserves, future hydrocarbon production, and cash flows, particularly with respect to wells that have not been fully tested and with wells having limited production histories; access to additional capital; changes in the price of natural gas and oil; availability and cost of services and equipment; and the presence of competitors with greater financial resources and capacity.

The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial costs from environmental accidents or events for which the Company may be currently liable. In addition, the Company’s oil and gas business makes it vulnerable to changes in prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on current oil and gas prices and estimated reserves. Price declines reduce the estimated quantity of proved reserves and increase annual depletion expense (which is based on proved reserves).

b)	Business acquisition

On March 26, 2009, the Company acquired 80.31% of The Stallion Group (“Stallion”), a Nevada corporation, whose principal business is in the identification, acquisition and exploration of oil and gas properties. To fund the acquisition of the Common Stock, the Company issued 3,909,005 shares of common stock and paid $46,908 in cash to the holders of the Stallion’s common stock that was tendered for a value of $0.04. Each common share of Stallion was exchangeable for 0.333333 of the Company’s common shares and $0.0008 in cash. As of March 26, 2009, the Company owned 58,635,139 shares of Common Stock, which represents approximately 80.31% of the shares of Common Stock issued and outstanding. Following is a summary of purchase price allocation:

F - 5

Table of Contents

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Stated in U.S. Dollars)

2. OPERATIONS (continued)

b)	Business acquisition (continued)

	March 26, 2009
Purchase price:
Share consideration – issued 3,909,005 common shares at $0.225 per share	$	879,526
Cash payment - $0.0008 for 58,653,139 common shares		46,908
Fair value of Non-Controlling Interests		100,631
Total	$	1,027,065
Represented By: Net assets purchased		(45,399	)
Increase in Oil and Gas Properties		(970,535	)
Net Assets attributable to Non-Controlling Interests		(11,131	)
	$Nil

Purchase Price Allocation:
Share capital	$	3,495,046
Accumulated deficit		(3,452,287	)
Cumulative translation adjustment		13,771
Total	$	56,530
Investment in Subsidiary – 80.31%	$	45,399
Non-Controlling Interest – 19.69%	$	11,131

As the acquisition was completed on March 26, 2009, the net loss of $18,422 of Stallion was included in the consolidated financial statements as of September 30, 2009.

The following table summarizes the net assets acquired upon the acquisition of The Stallion Group:

Cash & cash Equivalents	$	565
Accounts receivable		13,712
Prepaid Expenses		3,001
Natural gas and oil properties		194,670
Capital Assets, Net Total Assets		4,190
	$	216,138

Current Liabilities	$	(144,144	)
Asset Retirement Obligation Total Net Assets Total Net Assets purchased – 80.31%		(15,464	)
	$	56,530

	$	45,399

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 $4,723,053 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.

F - 6

Table of Contents

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Stated in U.S. Dollars)

2. OPERATIONS (continued)

c) Going Concern

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.

3. SIGNIFICANT ACCOUNTING POLICIES

a)	Basis of Consolidation

The consolidated financial statements are presented in accordance with accounting principles generally accepted in the United States and include the financial statements of the Company and its wholly-owned subsidiaries, Delta Oil & Gas (Canada) Inc. and 80.31% of The Stallion Group. All significant inter-company balances and transactions have been eliminated.

b)	Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved natural gas and oil reserve quantities and the related present value of estimated future net cash flows there from.

c)	Natural Gas and Oil Properties

The Company accounts for its oil and gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (“SEC”). Accordingly, all costs associated with the acquisition of properties and exploration with the intent of finding proved oil and gas reserves contribute to the discovery of proved reserves, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. All general corporate costs are expensed as incurred. In general, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded. Amortization of evaluated oil and gas properties is computed on the units of production method based on all proved reserves on a country-by-country basis. The net capitalized costs of evaluated oil and gas properties (full cost ceiling limitation) are not to exceed their related estimated future net revenues from proved reserves discounted at 10%, and the lower of cost or estimated fair value of unproved properties, net of tax considerations. These properties are included in the amortization pool immediately upon the determination that the well is dry.

Unproved properties consist of lease acquisition costs and costs on wells currently being drilled on the properties. The recorded costs of the investment in unproved properties are not amortized until proved reserves associated with the projects can be determined or until they are impaired. Unevaluated oil and gas properties are assessed at least annually for impairment either individually or on an aggregate basis.

F - 7

Table of Contents

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Stated in U.S. Dollars)

3. SIGNIFICANT ACCOUNTING POLICIES (continued)

d)	Asset Retirement Obligations

The Company has adopted “Accounting for Asset Retirement Obligations” of the FASB Accounting Standards Codification, which requires that asset retirement obligations (“ARO”) associated with the retirement of a tangible long-lived asset, including natural gas and oil properties, be recognized as liabilities in the period in which it is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated assets. The cost of tangible long-lived assets, including the initially recognized ARO, is depleted, such that the cost of the ARO is recognized over the useful life of the assets. The ARO is recorded at fair value, and accretion expense is recognized over time as the discounted cash flows are accreted to the expected settlement value. The fair value of the ARO is measured using expected future cash flow, discounted at the Company’s credit-adjusted risk-free interest rate.

e)	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)	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, 2009 and 2008, 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) Concentration of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents and accounts receivable. The Company maintains cash at one financial institution. The Company periodically evaluates the credit worthiness of financial institutions, and maintains cash accounts only in large high quality financial institutions, thereby minimizing exposure for deposits in excess of federally insured amounts. The Company believes credit risk associated with cash and cash equivalents to be minimal. Deposits are insured up to $93,397, the amount that may be subject to credit risk for the nine months ended September 30, 2009 is $372,289.

The Company has recorded trade accounts receivable from the business operations. Management periodically evaluates the collectability of the trade receivables and believes that the Company’s receivables are fully collectable and that the risk of loss is minimal.

F - 8

Table of Contents

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Stated in U.S. Dollars)

3. SIGNIFICANT ACCOUNTING POLICIES (continued)

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.

j)	Environmental Protection and Reclamation Costs (Continued)

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.

k)	Foreign Currency Translation

United States funds are considered the Company’s functional currency. Transaction amounts denominated in foreign currencies are translated into their United States dollar equivalents at exchange rates prevailing at the transaction date. Monetary assets and liabilities are adjusted at each balance sheet date to reflect exchange rates prevailing at that date, and non-monetary assets and liabilities are translated at the historical rate of exchange. Gains and losses arising from restatement of foreign currency monetary assets and liabilities at each year-end are included in other comprehensive income.

l)	Other Equipment

Computer equipment is stated at cost. Provision for depreciation on computer equipment is calculated using the straight-line method over the estimated useful life of three years.

m)	Impairment of Long-Lived Assets

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

n)	Loss Per Share

In February 1997, as required by the “Earnings Per Share” Topic of the FASB Accounting Standards Codification, basic and diluted earnings per share are to be presented. Basic earnings per share is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding in the period. Diluted earnings per share takes into consideration common shares outstanding (computed under basic earnings per share) and potentially dilutive common shares.

F - 9

Table of Contents

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Stated in U.S. Dollars)

3. SIGNIFICANT ACCOUNTING POLICIES (continued)

o)	Income Taxes

The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax bases of assets and liabilities, and their reported amounts in the financial statements, and (ii) operating loss and tax credit carry-forwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period.

p)	Financial Instruments

The Company’s financial instruments consist of cash and cash equivalent, accounts receivable, accounts payable and accrued liabilities.

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.

q) Comprehensive Loss

Reporting Comprehensive Income Topic of the FASB Accounting Standards Codification establishes standards for the reporting and display of comprehensive loss and its components in the financial statements. The Company is disclosing this information on its Consolidated Statements of Changes in Stockholders’ Equity and Consolidated Statement of Operations.

r) Stock-Based Compensation

The Company records stock-based compensation in accordance with Share-Based Payments of the FASB Accounting Standards Codification, which requires the measurement and recognition of compensation expense based on estimated fair values for all share-based awards made to employees and directors, including stock options.

Shared Based Payments requires companies to estimate the fair value of share-based awards on the date of grant using an option-pricing model. The Company uses the Black-Scholes option-pricing model as its method of determining fair value. This model is affected by the Company’s stock price as well as assumptions regarding a number of subjective variables. These subjective variables include, but are not limited to the Company’s expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise behaviors. The value of the portion of the award that is ultimately expected to vest is recognized as an expense in the statement of operations over the requisite service period.

All transactions in which goods or services are the consideration received for the issuance of equity instruments are accounted for based on the fair value of the consideration received or the fair value of the equity instrument issued, whichever is more reliably measurable.

F - 10

Table of Contents

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Stated in U.S. Dollars)

4. NATURAL GAS AND OIL PROPERTIES

a)	Proved Properties

Properties	December 31, 2008		Additions		Disposals			Depletion for the period			Impairment			September 30, 2009
USA properties	$	866,781	$	1,319,587	$	(808,861	)	$	(22,670	)	$	(202,486	)	$	1,152,351

Canada properties		25,315		16,554		(7,725	)		(7,170	)		(7,867	)		19,107

Total	$	892,096	$	1,336,141	$	(816,586	)	$	(29,840	)	$	(210,353	)	$	1,171,458

Properties in U.S.A.

i.	Oklahoma, USA

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.

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. Hulsey #2-8 started producing in January 2009; its cost amounted to $139,674 was moved to the proven cost pool for depletion.

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.

F - 11

Table of Contents

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Stated in U.S. Dollars)

4.	NATURAL GAS AND OIL PROPERTIES (Continued)

Proved Properties - Descriptions

Properties in U.S.A.

ii.	Palmetto Point Prospect, Mississippi, USA (Continued)

During the year ended 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. These wells were found to be proved in December 2008.

On October 10, 2007, the Company elected to participate in the drilling of PP F-12 and PP F-12-3 in Mississippi operated by Griffin & Griffin Exploration. The Company’s 10% of the estimated drilling costs was $88,783. PP F-12 started production 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.

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.

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

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.

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

F - 12

Table of Contents

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Stated in U.S. Dollars)

NATURAL GAS AND OIL PROPERTIES (Continued)

Proved Properties - Descriptions

Properties in U.S.A.

v.	Willows Gas Field, California, U.S.A

Through the Company’s subsidiary, Stallion, the Company acquired a well working interest in California, U.S.A. On October 15, 2007, Stallion agreed to participate in the drilling program to be conducted by Production Specialties Company (“PSC”). Stallion shall pay for the initial test well, 12.5% of 100% of all costs and expenses of drilling, completing, testing and equipping the Wilson Creek #1-27, to earn 6.25% working interest. As of September 30, 2009, Stallion has expended $195,971 for the costs of Wilson Creek #1-27 and $60,000 for 3D seismic in the prospect area. Wilson Creek #1-27 started producing gas from April 2008. The well has been temporarily shut in pending an increase in natural gas commodity prices.

Properties in Canada

vi.

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. The well, HZ 1C2-23 was drilled in September 2008 also started production from November 2008. As at September 30, 2009, the Company had advanced $338,967 as its share of the costs in this Agreement.

On June 1, 2009, the Company sold 2.5% of its 7.5% Working Interest for CAD$250,000.

vii. 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 had 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.

viii. 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.

ix. Strachan Prospect, Alberta, Canada

In September 2005, the Company entered into a participation and farm-out 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%. 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.

F - 13

Table of Contents

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Stated in U.S. Dollars)

4.	NATURAL GAS AND OIL PROPERTIES (Continued)

b) Unproved Properties

Properties	December 31, 2008		Addition		Disposals			Transfer to proved properties			September 30, 2009
USA properties	$	430,311	$	374,715	$	(154,671	)	$	(139,673	)	$	510,682
Canada properties		200,065		60,156		(63,966	)		-			196,255
Total	$	630,376	$	434,871		(218,637	)	$	(139,673	)	$	706,937

Unproved Properties - Descriptions

Properties in U.S.A.

Oklahoma, USA

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. 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. Hulsey #2-8 started producing in January 2009; its cost amounted to $139,674 was moved to the proven cost pool for depletion.

On July 27, 2009, the Company entered into the 2009-1 Drilling Program for five wells which will provide 5.714286% Before Casing Point (“BCP”) working interest and 5.00% After Casing Point (“ACP”) working interest. The Company’s buy-in costs for each well is $2,625. During the three months to September 2009, the Company had paid buy-in, estimated drilling and completion costs for three wells; Saddle #1-18, Saddle #2-18 and Saddle #3-18. The total of the costs were $90,217.

In August 2009, the Company entered into the 2009-3 Drilling Program for a total buy-in cost of $37,775 which will provide 6.25% Before Casing Point (“BCP”) working interest and 5.00% After Casing Point (“ACP”) working interest. During the three months to September 2009, the Company paid estimated drilling costs of $78,090.

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.

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

F - 14

Table of Contents

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Stated in U.S. Dollars)

4.	NATURAL GAS AND OIL PROPERTIES (continued)

Unproved Properties - Descriptions

Properties in U.S.A.

iii.

King City, California, USA

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

iv.

Texas Prospect, Texas, USA

On July 15, 2009, the Company successfully obtained the leases on certain lands in Texas, USA. These leases will provide the Company with the ability to drill up to 3 exploration wells. The costs of the leases were $169,566.

Properties in Canada

iv.

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 March 31, 2009, the Company had expended $162,996 of the well 3B9-23/3A11. In March 2009, the Company joined the drilling of a new well, 2 HZ 3B9 LEG. In June 2009, the Company joined the drilling of a new well, HZ 1B1-23/3B8, and paid CAD$49,826 for 5% working interest.

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.

F - 15

Table of Contents

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Stated in U.S. Dollars)

5.	NATURAL GAS AND OIL EXPLORATION RISK (continued)

b) Distribution Risk

The Company is dependent on the operator to market any oil production from its wells and any subsequent production which may be received from other wells which may be successfully drilled on the Prospect. It relies on the operator’s ability and expertise in the industry to successfully market the same. Prices at which the operator sells gas/oil both in intrastate and interstate commerce will be subject to the availability of pipe lines, demand and other factors beyond the control of the operator. The Company and the operator believe any oil produced can be readily sold to a number of buyers.

c)	Credit Risk

A substantial portion of the Company’s accounts receivable is with joint venture partners in the oil and gas industry and is subject to normal industry credit risks.

d)	Foreign Operations Risk

The Company is exposed to foreign currency fluctuations, political risks, price controls and varying forms of fiscal regimes or changes thereto which may impair its ability to conduct profitable operations as it operates internationally and holds foreign denominated cash and other assets.

6.	ASSET RETIREMENT OBLIGATIONS

The Company follows the Accounting for Asset Retirement Obligations Topic of the FASB Accounting Standards Codification. This addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It also requires recognition of the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. As of September 30, 2009 and December 31, 2008, the Company recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with Asset Retirement Obligations of the FASB Accounting Standards Codification . The liability for the fair value of an asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production. The Company amortizes the amount added to the oil and gas properties and recognizes accretion expense in connection with the discounted liability over the remaining life of the respective well. The estimated liability is based on historical experience in plugging and abandoning wells, estimated useful lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements. The liability is a discounted liability using a credit-adjusted risk-free rate of 12%.

Revisions to the liability could occur due to changes in plugging and abandonment costs, well useful lives or if federal or state regulators enact new guidance on the plugging and abandonment of wells.

The information below reflects the change in the asset retirement obligations during the nine months period ended September 30, 2009 and year ended December 31, 2008:

	September 30, 2009			December 31, 2008
Balance, beginning of the period	$	23,604		$	111,803
Liabilities assumed		-			8,898
Revisions		(3,271	)		(99,626	)
Accretion expense		2,363			2,529
Balance, end of the period	$	22,696		$	23,604

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Table of Contents

Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Stated in U.S. Dollars)

7.	SHARE CAPITAL

On September 25, 2009, the Company’s shareholders voted for a 1 for 5 reverse split. On October 21, 2009 the Company changed its Articles of Incorporation to reflect the 1 for 5 reverse share split. The Company’s financial statements reflect the changes in its share capital retroactively and prospectively. Hence the Company’s outstanding warrants and options have been adjusted accordingly.

Common Stock

On January 11, 2006, the Company issued 15,000 common shares for exercise of stock options at $4.00 per share.

On January 24, 2006, the Company issued 46,000 common shares for exercise of stock options at $4.00 per share.

On January 25, 2006, the Company issued 2,500 common shares for exercise of stock options at $5.00 per share.

On April 25, 2006, the Company issued 145,455 common shares pursuant to a private placement at $13.75 per share.

On January 23, 2007, the Company issued 12,000 common shares for exercise of stock options at $3.75 per share.

On March 1, 2007, the Company issued 100,000 common shares to the President and CEO as part of his compensation package. The price of the share as of March 1, 2007 was $4.60.

On May 1, 2007, the Company issued 12,000 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 $6.40.

On July 8, 2007, the Company issued 50,000 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 $2.75. It was the average of the share price of July 6 and July 9, 2007.

On August 13, 2008, the Company issued 180,000 common shares to the Officers of the Company as part of their compensation package. The price of the share as of August 13, 2008 was $0.265.

On March 26, 2009, the Company issued 3,909,005 common shares for the acquisition of 80.31% for oil and gas properties.

On April 6, 2009, the Company issued 280,000 common shares to the Officers of the Company as part of their compensation package. The price of the share as of April 6, 2009 was $0.15.

Preferred Stock

The Company did not issue any preferred stock during the nine months period ended September 30, 2009 (December 31, 2008 - Nil).

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Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Stated in U.S. Dollars)

7.	SHARE CAPITAL (continued)

ii.

Stock Options

Compensation expense related to incentive stock options granted is recorded at their fair value as calculated by the Black-Scholes option pricing model. Compensation expense of $13,750 was recorded during the nine months ended September 30, 2009 (September 30, 2008 – 123,724) related to options granted during the nine months ended September 30, 2009 and 2008. The changes in stock options are as follows:

	NUMBER	WEIGHTED AVERAGE EXERCISE PRICE
Balance outstanding, December 31, 2008 Granted Expired Exercised Balance outstanding, September 30, 2009	48,000 100,000 (48,000) -	$ 3.75 0.15 - -
	100,000	$ 0.15

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

	September 30, 2009			September 30, 2008
Risk-fee interest rate		1.00	%		0.00	%
Expected life of the option	3 years			0 year
Expected volatility		199.13	%		0.00	%
Expected dividend yield		-			-

The following table summarized information about the stock options outstanding as at September 30, 2009:

Options outstanding			Options exercisable
Exercise price	Number of shares	Remaining contractual life (years)	Number of shares
$0.15	100,000	2.52	100,000

iii.

Common Stock Share Purchase Warrants

As at September 30, 2009, share purchase warrants outstanding for the purchase of common shares as follows:

Warrants outstanding

Exercise price	Number of shares	Expiry date
$ 7.50	497,997	February 1, 2010

No warrants were issued during the nine months period ended September 30, 2009.

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Delta Oil & Gas, Inc.

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Stated in U.S. Dollars)

8.	RELATED PARTIES

During the nine months period ended September 30, 2009, the Company paid $146,243 (September 30, 2008 - $129,564) for consulting fees and $27,578 (September 30, 2008 - $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 April 3, 2009, the Company issued 280,000 shares of common stock in consideration for services rendered to Officers of the Company. The price of the share as of April 3, 2009 was $0.15. The total cost of $42,000 was recorded in the compensation expense for shares granted and was included in the general and administration expense.

On April 3, 2009, the Company granted 100,000 stock options in consideration for services rendered to the Officer of the Company. The price of the share as of April 3, 2009 was $0.15. The total cost of $13,750 was recorded in the compensation expense for options 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.

9.	SUBSEQUENT EVENTS

On October 21st, 2009, the Company filed its Articles of Amendment to the Articles of Incorporation of the Company in order to affect a 1-for-5 reverse stock split of all the issued and outstanding shares of common stock of the Company. The Company’s shares of common stock will trade on the OTC Bulletin Board under the symbol “DLTA” at the start of trading on Tuesday, 27th October 2009.

As a result of the reverse stock split, every five (5) shares of the Company issued and outstanding common stock will be combined into one (1) share of common stock. The reverse stock split will not change the number of authorized shares of the Company’s common stock. Following the reverse stock split, the Company expects to have approximately 13,557,107 shares of common stock outstanding. The reverse stock split will affect all shares of the Company’s common stock, including common stock underlying stock options and warrants outstanding immediately prior to the effective time of the reverse stock split.

The financial statements have been prepared to reflect the reverse stock split as the shareholders approved the reverse split on September 25, 2009.

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

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

Although forward-looking statements in this Quarterly Report on Form 10-Q reflect the good faith judgment of our management, such statements can only be based on facts and factors currently known by us. Consequently, forward-looking statements are inherently subject to risks and uncertainties and actual results and outcomes may differ materially from the results and outcomes discussed in or anticipated by the forward-looking statements. We caution the reader that numerous important factors, including those factors discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008, 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.

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Business of Delta Oil

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 King City, California; Southern Saskatchewan, Canada; and South Central, Oklahoma. As a result of our acquisition of a controlling interest in The Stallion Group, a Nevada corporation, which is discussed below, we expanded our property interests to include acreage in the North Sacramento Valley, California.

Reverse Stock Split

On October 21, 2009, we filed Articles of Amendment to our Articles of Incorporation in order to effect a 1-for-5 reverse stock split of all of our issued and outstanding shares of common stock. Our shares of common stock are now quoted on the OTC Bulletin Board under the symbol "DLTA".

As a result of the reverse stock split, every five (5) shares of our issued and outstanding common stock will be combined into one (1) share of common stock. The reverse stock split will not change the number of authorized shares of our common stock.

No fractional shares were issued in connection with the reverse stock split. If, as a result of the reverse stock split, a stockholder would have otherwise held a fractional share, the number of shares to be received by such stockholder was rounded up to the next whole number.

Following the effectiveness of the reverse stock split, we had approximately 13,557,107 shares of common stock outstanding. The reverse stock split affected all shares of the our common stock, including common stock underlying stock options and warrants that are outstanding immediately prior to the effective time of the reverse stock split.

Additional information about the reverse stock split is available in the our definitive proxy statement filed with the Securities and Exchange Commission on August 10, 2009.

Acquisition of Controlling Interest in the Stallion Group

On October 7, 2008, we announced the commencement of our offer to purchase (the “Offer”) all of the outstanding common shares of The Stallion Group, a Nevada corporation (the “Stallion Group”), in exchange for 0.333333 shares of our common stock and $0.0008 in cash per share of the Stallion Group, upon the terms and subject to the conditions set forth in the prospectus accompanying the Offer.

The Offer expired on March 26, 2009 and thereafter we notified the depository to take and pay for all of the shares of the Stallion Group that were validly tendered in connection with our previously-announced Offer. The depository advised us that, as of the expiration of the Offer, 58,635,139 shares of the Stallion Group common stock had been validly tendered, representing 80.31% of the issued and outstanding common shares of the Stallion Group.

All validly tendered common shares of the Stallion Group were accepted for payment in accordance with the terms of the Offer, pursuant to which each validly tendered common share of the Stallion Group was exchanged for 0.333333 of a share of our common stock and $0.0008 in cash.

Based on the number of common shares validly tendered in the Offer and the exchange ratio set forth above, we issued 3,909,005 shares of our common stock and paid $46,908 in cash pursuant to the Offer.

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Hillspring Prospect

On November 26, 2004, through our wholly-owned Canadian subsidiary, Delta Oil & Gas (Canada), Inc., we entered into an agreement (the "Agreement") with Win Energy Corporation, ("Win Energy"), an Alberta based oil & gas exploration company, in order to acquire an interest in leases owned by Win Energy. On or about January 25, 2005, we paid Win Energy $414,766 in exchange for a 10% working interest in one section of land (640 acres) in Hillspring located approximately 90 miles south of Calgary, Alberta in the Southern Alberta Foothills belt. During the three months ended March 31, 2009, management reassessed its participation in this project and determined to abandon this project due to concerns regarding its profitability. We did not incur any costs in connection with our abandonment of this project and do not anticipate incurring any future costs.

Strachan Prospect

On September 23, 2005, we entered into the Farmout Agreement with Odin Capital Inc. (“Odin Capital”), a Calgary, Alberta corporation. A former member of our board of directors, Mr. Philipchuk, maintains a 50% ownership interest in Odin Capital. Odin Capital 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:

1.	in the Spacing Unit for the Earning Well:
(a)		a 2.0% interest in the petroleum and natural gas below the base of the Mannville, excluding natural gas in the Leduc formation; and
(b)		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;
2.	a 1.6% interest in the rights below the base of the Shunda formation in Section 10, Township 38, Range 9W5M; and
3.	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.

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 we committed to perform a full testing program. During the three months ended March 31, 2008, testing showed that no economic hydrocarbons were present, the well was abandoned and 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 10% gross working and revenue interest in a ten-well drilling program (the “Drilling

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Program”) to be undertaken by Griffin & Griffin Exploration L.L.C. (“Griffin Exploration”), 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 Exploration on February 24, 2006.

The initial Drilling Program on ten wells on the acquired property interest was completed by Griffin Exploration. On August 4, 2006, we paid $70,000 to Griffin Exploration in exchange for our participation in an additional two well program, which has also been completed. The prospect area owned or controlled by Griffin Exploration on which the wells were drilled is comprised of approximately 1,273 acres in Palmetto Point, Mississippi. Twelve wells had been drilled resulting in seven producing wells. We anticipated that three additional wells would be producing subsequent to being 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.

In October 2007, as part of Palmetto Point 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 to commence oil production.

Effective February 1, 2009, we disposed of our interests in the Palmetto Point Prospect - 12 Wells Phase - I project described above. These interests were disposed of together with the interests in the Palmetto Point Prospect – 50 Wells Phase II project described below.

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 Exploration 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 acquired, through our acquisition of a controlling interest of the Stallion Group in March 2009, an additional interest in this same drilling program. Pursuant to the agreement entered into by the Stallion Group with Griffin Exploration on August 2, 2006, the Stallion Group agreed to pay 30% of all prospect fees, mineral leases, surface leases, and drilling and completion costs to earn a net 19.2% share of all production zones to the base of a geological formation referred to as the Frio formation and 17.25%

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of all production to the base of a geological formation referred to as the Wilcox formation. The Stallion Group’s cost during the quarter ending September 30, 2006 amounted to $300,000. During the fourth quarter of fiscal 2006, the Stallion Group made additional payments of $600,000 that were employed in the further development of prospects on lands in Mississippi and Louisiana in accordance with the terms of the operating agreement. As a result of our acquisition of a controlling interest of the Stallion Group in March 2009 pursuant to our tender offer, we became obligated to pay 40% of all prospect fees, mineral leases, surface leases, and drilling and completion costs to earn a net 27.2% share of all production zones to the base of a geological formation referred to as the Frio formation and 24.75% of all production to the base of a geological formation referred to as the Wilcox formation

Neither we nor the Stallion Group incurred any additional payments other than drilling costs for these prospects in 2008 or 2007.

Effective February 1, 2009, we disposed of all of our interests in the Palmetto Point Prospect - 50 Wells Phase - II project described above, including those previously held by the Stallion Group. These interests were disposed of together with the interests in the Palmetto Point Prospect – 12 Wells Phase I for consideration of $200,367 plus a monthly payment of $500 for each monthly period that these wells are in production up to a maximum of forty-eight months.

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 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 of December 31, 2007 were $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. In December 2008, a second well was drilled and completed, which started production in January 2009.

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.

Total revenue received from these wells for the three months ended September 30, 2009 was $49,554, as compared to $33,406 for the three months ended September 30, 2008. Total revenue

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received from these wells for the nine months ended September 30, 2009 was $126,670, as compared to $88,921 for the nine months ended September 30, 2008. The increase in revenue was caused by the addition of a new successful well which started production in January 2009; however, this was partially offset by the disposal of 2.5% of our interest in the Wordsworth Prospect for $214,961, which was effective on June 1, 2009, thereby reducing our interest from 7.5% to 5.0%.

We will continue to hold a 5.0% working interest in our existing wells on the Wordsworth Prospect and any future wells which we elect to participate on the Wordsworth Prospect. On November 2, 2009 we announced the completion and production of a third well at the location 2A2-23-7-3W2. The total cost of this well was CDN$67,253. The well has started production and we began receiving royalties from this well during November 2009.

Owl Creek Prospect

On June 1, 2006, we entered into an assignment agreement with Brinx Resources, Ltd., (“Brinx Resources”), a Nevada oil & gas exploration company, in order to acquire a working interest in lands and leases owned by Brinx Resources in Oklahoma. 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 and McClain counties in Oklahoma and we refer to the lands as the “Owl Creek Prospect.”

Pursuant to the terms of the assignment agreement with Brinx Resources, 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 and was paid. Initially, the Powell #2 began flowing oil and natural gas under its own pressure without the assistance of a pump. In July 2008, the Company disposed of its holdings in Powell #2 and the surrounding area for aggregate consideration of $760,438.

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. In July 2008, the Company disposed of its holdings in Isbill #2-36 and the surrounding area for aggregate consideration of $549,388.

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 $1,067,447. We decided to dispose of the property based on the declining rates of production experienced by the operator and the reasonable offer for both wells and the surrounding lands of 1,120 acres.

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2006-3 Drilling Program

On April 17, 2007, we entered into an agreement with Ranken Energy Corporation (“Ranken Energy”) to participate in a five well drilling program in Garvin and Murray counties in Oklahoma (the “2006-3 drilling Program”). The leases secured and/or lands to be pooled for this drilling program total approximately 820 net acres. We agreed to take a 10% working interest in this program. To date, we have paid Ranken the sum of $514,619.

Three wells drilled (the "Wolf #1-7", the "Loretta #1-22" and the “Ruggles #1-15") were deemed by the operator to not be commercially viable and as such, were plugged and abandoned in September 2007. The proportionate costs associated with these abandoned wells amounted to $244,989, which were moved to the proved properties cost pool for depletion.

Three other wells drilled (the “Elizabeth #1-25”, the “Plaster #1-1” and the “Dale #1 re-entry”) were deemed by the operator to be commercially viable and production casing was set in each. The Elizabeth #1-25 located in the Meridian Prospect cost $99,129, the Plaster #1-1 located in the Plaster Prospect cost $116,581, and re-entry into the Dale #1 located in the Dale Prospect cost $18,150, all of which was paid August and September , 2007. Subsequent to the completion of these wells, two remain economically viable at this time. The Plaster #1 encountered hydrocarbon showings and 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 as of February 7, 2008.

Total revenue received from these wells for the three months ended September 30, 2009 was $1,821, as compared to $638 for the three months ended September 30, 2008. Total revenue received from these wells for the nine months ended September 30, 2009 was $4,707, as compared to $46,430 for the nine months ended September 30, 2008. The reduction in revenue was caused by a suspension of production in the Dale #1 and a decline in oil prices in the reporting period ended September 30, 2009, as compared to the reporting period ended September 30, 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 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 since February 2008.

Hulsey #1-8 started producing during the first quarter of 2008 and the total revenue received from the Hulsey #1-8 for the three months ended September 30, 2009 was $30,609, as compared to $38,273 for the three months ended September 30, 2008. The total revenue received from the Hulsey #1-8 for the nine months ended September 30, 2009 was $46,498, as compared to $57,178 for the nine months ended September 30, 2008. The significant decrease in revenue received from the Hulsey #1-8 is attributable to a decline in hydrocarbons recovered from the well and the reduction in natural gas and oil commodity prices.

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Drilling of the third well in this drilling program (the “River #1”) was completed during the three months ended September 30, 2008 and generated revenue for the three and nine month period ended September 30, 2008 of $75,231. The total revenue received from the River #1 for the three months ended September 30, 2009 was $11,842 and $33,148 for the nine months ended September 30, 2009. The decrease in revenue was caused by a significant reduction in natural gas prices.

Hulsey #2-8 commenced production during the three months ended March 31, 2009 and produced $5,764 in oil revenues for the three months ended September 30, 2009 and $14,020 for the nine months ended September 30, 2009. Our proportionate costs associated with the Hulsey #2-8 well amounted to $139,674, which was moved to the proved properties cost pool for depletion.

2009-1 Drilling Program - 5 Wells

On July 27, 2009, we entered into an agreement with Ranken Energy to participate in a five well drilling program in Garvin County, Oklahoma (the “2009-1 Drilling Program”). We have agreed to take a 5.0% working interest in the 2009-1 Drilling Program in exchange for our payment of a total of $13,125 in buy-in costs, which equates to $2,625 in buy-in costs for each well, plus our proportionate shares of the drilling and completion costs. During the three months ended September 30, 2009, we paid estimated drilling and completion costs of $90,217 for three wells, which we refer to as Saddle #1-18, Saddle #2-18 and Saddle #3-18. The 2009-1 Drilling Program has already commenced and we currently anticipate that we will have the results prior to the end of the fiscal year.

2009-3 Drilling Program - 4 Wells

On August 7, 2009, we entered into an agreement with Ranken Energy to participate in a four well drilling program in Garvin County, Oklahoma (the “2009-3 Drilling Program”). We purchased a 6.25% working interest before casing point and 5.0% working interest after casing point in the 2009-3 Drilling Program for $37,775. In addition to the total buy-in cost of $37,775, we will be responsible for our proportionate share of the drilling and completion costs. During the three months to September 2009, we paid the total buy-in cost of $37,775 and advanced estimated drilling costs in the amount of $78,090.

Willows Gas Field

On February 15, 2008, the Stallion Group entered into a farm out agreement with Production Specialties Company (“Production Specialties”) for participation in a natural gas prospect area located in the North Sacramento Valley, California. The Stallion Group participated in the drilling of the first well (“Wilson Creek #1-27”) on the prospect area and encountered a number of prospective pay zones. Testing was completed and stabilized flow rates exceeded a combined 1.5 million cubic feet per day of sweet high quality gas. Thereafter, the Wilson Creek #1-27 was connected to a nearby pipeline and begun producing natural gas in April 2008.

On October 15, 2007, the Stallion Group drilled its first prospect well, paying 12.5% of the costs of the first well to earn a 6.25% working interest. Thereafter, the Stallion Group will pay 6.25% of the costs of future wells to earn 6.25% working interest. As of September 30, 2009, $195,971 was expended for the costs of the Wilson Creek #1-27 and $60,000 was expended for 3D seismic in the prospect area. In light of the current natural gas commodity prices, we reviewed the future economic viability of this well during the prior reporting period ended June 30, 2009 and decided to suspend production until further notice in order to determine whether production of this well will be profitable.

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King City, California

On May 25, 2009, we entered into a farm-out agreement with Sunset Exploration (“Sunset”), a California corporation, to participate in the drilling and exploration of lands located in Monterey County, California. The prospect area where the drilling and exploration will take place is comprised of approximately 10,000 acres. We are obligated to pay 66.67% of the costs of the initial test well up to casing point, in order to earn a 40.0% working interest. Thereafter, we will be obligated to pay 40.0% of the costs of any future wells which we elect to participate in order to earn a 40.0% working interest. We paid Sunset $100,000 as an advance towards the permitting and processing of lands and the costs of a gravity survey and a 2D seismic program. We commenced a gravity survey and 2D seismic program in August 2009. Following receipt of the results from the gravity survey and 2D seismic program, the Company has decided to pursue further 2D seismic analysis in order to identify viable hydrocarbon targets for its first test well..

Texas Prospect

On July 15, 2009, we entered into an assignment agreement with Mr. Barry Lasker (the “Assignor”) and was assigned all of Assignor’s rights and obligations under two oil, gas and liquid hydrocarbon lease agreements, each dated March 26, 2009 (the “Leases”) covering an aggregate area of approximately 243 acres in Newton County, Texas (the “Texas Prospect”). The assignment of the Leases and the assumption of the Assignor’s rights and obligations under the Leases is conditioned upon the written consent of each lessor, which has not yet been received. We are attempting to secure the consent of each lessor to the Assignor’s assignment of the Leases to us and anticipate that we will be successful in securing such approvals.

We are also in the process of negotiating a definitive agreement with the Assignor whereby it is contemplated that the Assignor will participate with us in the drilling of 3 exploration wells on the Texas Prospect on terms that have not been specified. In connection with the assignment of the Leases to us and with the expectation that we will secure the written consent of each lessor and successfully negotiate a definitive agreement with the Assignor, we have advanced lease costs of $169,566 to the Assignor relating to the Texas Prospect during the reporting period.

For the Three and Nine Months Ended September 30, 2009 and 2008

Revenues

We generated total revenue of $101,491 for the three months ended September 30, 2009, a decrease from revenues of $909,222 for the three months ended September 30, 2008. Our revenues generated during the three months ended September 30, 2009 were entirely attributable to natural gas and oil sales. Whereas during the three months ended September 30, 2008, we generated revenue of $190,076 from natural gas and oil sales and $719,146 from a gain on the disposition of our interest in the Owl Creek Prospect. The 47% decrease in revenues from natural gas and oil sales for the three months ended September 30, 2009, when compared to the three months ended September 30, 2008, was attributable a decline in natural gas and oil prices and the lack of revenues from the Owl Creek Prospect that was disposed of during the three months ended September 30, 2008.

We generated total revenue of $376,063 for the nine months ended September 30, 2009, a decrease from revenues of $1,492,362 for the nine months ended September 30, 2008. The decrease in revenues for the nine months ended September 30, 2009, when compared to the nine months ended September 30, 2008, was attributable a decline in natural gas and oil prices, the lack of revenues from the Owl Creek Prospect that was disposed of during the three months ended September 30, 2008 and lower gains reported from the disposition of natural gas and oil properties. Revenue generated from natural gas

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and oil sales was $233,582 for the nine months ended September 30, 2009, a decrease of approximately 70% from $773,216 for the nine months ended September 30, 2008. The decrease in revenues from natural gas and oil sales for the nine months ended September 30, 2009, when compared to the nine months ended September 30, 2008, was attributable a decline in natural gas and oil prices and the lack of revenues from the Owl Creek Prospect that was disposed of in July 2008. We reported a gain of $142,481on the sale of natural gas and oil properties during the nine months ended September 30, 2009 relating to our disposition of 2.5% of our interest in the Wordsworth Prospect and a gain of $719,146 on the sale of natural gas and oil properties during the nine months ended September 30, 2008 relating to our disposition of our interest in the Owl Creek Prospect.

Costs and Expenses

We incurred costs and expenses in the amount of $187,057 for the three months ended September 30, 2009, a 25% decrease from costs and expenses of $250,147 for three months ended September 30, 2008. The decrease in costs was attributable to a reduction in natural gas and oil operating costs and a reduction in the depreciation and depletion costs. Both items were caused by the sale of our interests in the Owl Creek Prospect during the three months ended September 30, 2008. The decrease in costs and expenses for the three months ended September 30, 2009, when compared the three months ended September 30, 2008, is primarily attributable to the following factors:

General and administrative costs for the three months ended September 30, 2009 decreased to $147,141 from $158,457 for the three months ended September 30, 2008, a decrease of 7%. The decrease was caused as by a reduction in insurance and investor relations expenses; however, this was partially offset by the inclusion of costs associated with an increase in personnel resulting from our acquisition of a majority interest in the Stallion Group, an increase in stock based compensation and an increase in audit and accounting fees.

Natural gas and oil operating costs for the three months ended September 30, 2009 decreased to $25,495 from $48,516 for the three months ended September 30, 2009, a decrease of 47%. The reduction in operating expenses was caused by the sale of our interests in the Owl Creek Prospect during the three months ended September 30, 2008.

Depreciation and depletion costs for the three months ended September 30, 2009 decreased to $5,739 from $39,820. The decrease was caused by the sale of our interests in the Owl Creek Prospect during the three months ended September 30, 2009. This resulted in a reduction in production which resulted in a reduced depletion charge.

We incurred costs and expenses in the amount of $ $1,532,498 for the nine months ended September 30, 2009, a 36% increase from costs and expenses of $1,123,247 for nine months ended September 30, 2008. The increase in costs and expenses for the nine months ended September 30, 2009, when compared the nine months ended September 30, 2008, is primarily attributable to a loss on sale of natural gas and oil properties we experienced for the nine months ended September 30, 2009 of $750,305 from the disposal of Palmetto Point Prospect 12 Wells Phase - I and 50 wells – Phase II projects.

Changes in other costs and expenses line items for the nine months ended September 30, 2009, when compared the nine months ended September 30, 2008, is primarily attributable to the following factors:

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General and administrative costs for the nine months ended September 30, 2009 increased to $439,363 from $344,090 for the nine months ended September 30, 2008, an increase of 28%. The increases in general and administration costs were caused by increases in foreign exchange losses increasing to $90,560, from a foreign exchange gains of $20,170 for the nine months ended September 30, 2008, resulting from the strengthening of the Canadian dollar against the U.S. dollar, an increase in personnel resulting from our acquisition of a majority interest in the Stallion Group and an increase in audit and accounting fees. This was partially offset 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 nine months ended September 30, 2009 was $55,750, as compared to $171,424 for the nine months ended September 30, 2008.

Natural gas and oil operating costs for the nine months ended September 30, 2009 decreased to $98,671 from $179,626 for the nine months ended September 30, 2008, a decrease of 45%. The decrease in natural gas and oil operating costs is attributable to lower costs resulting from disposal of our interests in the Owl Creek Prospect in July 2008, the Palmetto Point Prospect 12 Wells Phase - I and 50 wells – Phase II projects during the three months ended March 31, 2009 and our disposition of 2.5% of our interest in the Wordsworth Prospect on June 1, 2009.

Depreciation and depletion expense for the nine months ended September 30, 2009 decreased to $31,443 from $200,767 for the nine months ended September 30, 2008, a decrease of 84%. The decrease in depreciation and depletion expense is attributable to the disposal of our interests in the Owl Creek Prospect and Palmetto Point Prospect 12 Wells Phase - I and 50 wells – Phase II projects, which was partially offset by additional uneconomic wells that were moved to the proved property pool for depletion; and

Impairment of natural gas and oil properties expense for the nine months ended September 30, 2009 decreased to $210,353 from $388,702 for the nine months ended September 30, 2008, an decrease of 46%. The decrease in impairment of natural gas and oil properties expense for the nine months ended September 30, 2009, as compared to the nine months ended September 30, 2008, is attributable to a decline in natural gas and oil prices, which adversely impacts the third party valuation of our properties resulting in a reduction in carrying value of reserves.

Net Operating Loss

The net operating loss for the three months ended September 30, 2009 was $85,566, compared to a net operating profit of $659,075 for the three months ended September 30, 2008 due to the factors described above. The net operating loss for the nine months ended September 30, 2009 was $1,156,435, compared to a net operating profit of $369,115 for the nine months ended September 30, 2008 due to the factors described above.

Other Income and Expense

We reported other net income of $2,160 for the three months ended September 30, 2009, as compared to other expense of $385 in the three months ended September 30, 2008. We reported other net income of $7,832 for the nine months ended September 30, 2009, as compared to other expense of $3,551 in the nine months ended September 30, 2008. Other income was attributable to interest received on bank deposits.

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Net Loss

As a result of the above, net loss for the three months ended September 30, 2009 was $83,210, compared to a net profit of $658,690 for the three months ended September 30, 2008 and net loss for the nine months ended September 30, 2009 was $1,149,291, compared to a net profit of $365,564 for the nine months ended September 30, 2008.

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, 2009, we had total current assets of $624,670 and total current liabilities in the amount of $29,356. As a result, we had working capital of $595,314 as of September 30, 2009.

The revenue we currently generate from natural gas and oil sales does not exceed our operating expenses. As such, we anticipate that 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, 2009. During the nine months September 30, 2009, we received $-0- from financing activities involving loan issuances, as compared to $25,000 during the nine months ended September 30, 2008. We incurred expenses of $48,045 from a Form S-4 registration of shares in connection with the Offer to acquire shares of the Stallion Group, for the nine months September 30, 2009, compared to $95,414 for the nine months September 30, 2008.

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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Cash Used in Operating Activities

Operating activities used $234,889 in cash for the nine months September 30, 2009, compared to $333,631 in cash generated from operating activities for the nine months ended September 30, 2008. Our negative cash flow for the nine months September 30, 2009 was caused by a decline in revenues earned during such period.

Cash Used in / Provided by Investing Activities

Cash flows used by investing activities for the nine months ended September 30, 2009 was $231,942, compared to $580,424 cash generated by investing activities for the nine months ended September 30, 2008. All cash used in investment activities during the nine months ended September 30, 2009 and 2008 related to investments in natural gas and oil working interests. The increase in net cash used was caused by the Company’s investment in oil and gas properties which was partially offset by the sale of 2.5% of it’s interest in the Wordsworth prospect.

Cash from Financing Activities

Cash flows used by financing activities for the nine months September 30, 2009 primarily consisted of $48,045 related to the cost of registration of shares under the Form S-4 in relation to the Offer to acquire shares of the Stallion Group, compared to $70,414 in cash provided from financing activities for the nine months ended September 30, 2008.

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 $4,723,053 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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Oil and Gas Joint Ventures

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

Natural Gas and Oil Properties

We account for our oil and gas producing activities using the full cost method of accounting as prescribed by the FASB Accounting Standards Codifications. Accordingly, all costs associated with the acquisition of properties and exploration with the intent of finding proved oil and gas reserves contribute to the discovery of proved reserves, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. All general corporate costs are expensed as incurred. In general, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded. Amortization of evaluated oil and gas properties is computed on the units of production method based on all proved reserves on a country-by-country basis. Unevaluated oil and gas properties are assessed at least annually for impairment either individually or on an aggregate basis. The net capitalized costs of evaluated oil and gas properties (full cost ceiling limitation) are not to exceed their related estimated future net revenues from proved reserves discounted at 10%, and the lower of cost or estimated fair value of unproved properties, net of tax considerations. These properties are included in the amortization pool immediately upon the determination that the well is dry.

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 June 30, 2009 and 2008, we had no overproduced imbalances.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

(Not Applicable).

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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, 2009. This evaluation was carried out under the supervision and with the participation of our Chief Executive Officer, Mr. Christopher Paton-Gay, and our Chief Financial Officer, Mr. Kulwant Sandher. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2009, our disclosure controls and procedures are effective.

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

Limitations on the Effectiveness of Internal Controls

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

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal controls over financial reporting during the quarter ended September 30, 2009 that have materially affected or are reasonably likely to materially affect such controls.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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.

None.

Item 3. Defaults upon Senior Securities.

None.

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

We held our Annual Meeting of Shareholders on September 25, 2009. The director nominees named below were each elected to a term expiring at the 2010 Annual Meeting of Shareholders by the indicated votes cast for and withheld with respect to each nominee.

Name of Nominee	For	Withheld
Christopher Paton-Gay	37,088,756	1,739,669
Douglas N. Bolen	37,028,694	1,799,731
Kulwant Sandher	37,071,053	1,757,372

All of the other proposals, as set forth in our proxy statement for the 2009 Annual Meeting of Shareholders, were approved by our shareholders as follows:

	For	Against	Abstain
Approval of a reverse stock split of all our issued and outstanding common stock on a one-for-five basis.	34,163,061	4,371,563	293,801
Ratification of the selection of STS Partners LLP., Chartered Accountants to serve as our independent registered public accounting firm for 2009.	37,877,438	636,594	314,393

Item 5. Other Information.

None.

Item 6. Exhibits.

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

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SIGNATURES

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

	Delta Oil & Gas, Inc.

Date:	November 20, 2009

	By: /s/ Christopher Paton-Gay Christopher Paton-Gay Title: Chief Executive Officer and Director
Date:	November 20, 2009
	By: /s/ Kulwant Sandher Kulwant Sandher Title: Chief Financial Officer and Director

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DELTA OIL & GAS, INC.

(the “Registrant”)

(Commission File No. 000-52001)

Exhibit Index

Quarterly Report on Form 10-Q

for the Quarter Ended September 30, 2009

Exhibit No.	Description	Incorporated Herein by Reference to	Filed Herewith
3.1	Articles of Amendment to the Articles of Incorporation of Delta Oil & Gas, Inc.	Exhibit 3.1 of Form 8-K filed on October 26, 2009
10.1	Assignment of Oil, Gas & Liquid Hydrocarbon Leases dated July 15, 2009 relating to the Texas Prospect		X
10.2	Letter Agreement by and between Delta and Ranken Energy Corporation dated August 7, 2009.		X
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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