UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

Form 10-K

ý    ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2009

¨TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to _______.

Commission file number:  000-52001

Delta Oil & Gas, Inc.

(Exact name of registrant as specified in its charter)

Colorado	91-210350
(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)                    (Zip Code)
Registrant’s telephone, including area code:     (866) 355-3644

Securities registered under Section 12(b) of the Exchange Act:  None.

Securities registered under Section 12(g) of the Exchange Act:

Common Stock, $0.001 par value	Not Applicable
(Title of class)	(Name of each exchange on which registered)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  ¨  No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes  ¨  No ý

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 past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  ý  No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ¨

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” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨                                                                                                   Accelerated filer ¨

Non-accelerated filer   ¨ (Do not check if a smaller reporting company)                 Smaller reporting company ý

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

As of June 30, 2009, the aggregate market value of the Company’s common equity held by non-affiliates computed by reference to the closing price $0.03 was: 1,642,066

The number of shares of our common stock outstanding as of March 5, 2010 was: 13,557,107

FORM 10-K

DELTA OIL & GAS, INC.

DECEMBER 31, 2009

Table of Contents

	Page
PART I
Item 1.          Business.	5
Item 1A.       Risk Factors.	15
Item 1B.        Unresolved Staff Comments.	23
Item 2.           Properties.	23
Item 3.           Legal Proceedings.	29
Item 4.           Reserved.	29

PART II

Item 5.          Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	30
Item 6.          Selected Financial Data.	31
Item 7.          Management’s Discussion and Analysis of Financial Condition and Results of Operations.	32
Item 7A.       Quantitative and Qualitative Disclosures About Market Risk.	36
Item 8.          Financial Statements and Supplementary Data.	36
Item 9.          Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.	36
Item 9A.       Controls and Procedures.	37
Item 9B.        Other Information.	38

PART III

Item 10.         Directors, Executive Officers and Corporate Governance.	39
Item 11.         Executive Compensation.	41
Item 12.         Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	44
Item 13.         Certain Relationships and Related Transactions, and Director Independence.	45
Item 14.         Principal Accounting Fees and Services.		45

PART IV

Item 15.         Exhibits, Financial Statement Schedules.	46
Glossary
Signature Page
Exhibit Index

- 2 -

Cautionary Note Regarding Forward Looking Statements

This annual report contains forward-looking statements as that term is defined in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  In some cases, you can identify forward-looking statements by terminology such as “may,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential,” “continue,” “intends,” and other variations of these words or comparable words.  In addition, any statements that refer to expectations, projections or other characterizations of events, circumstances or trends and that do not relate to historical matters are forward-looking statements.  These forward-looking statements are based largely on our expectations or forecasts of future events, can be affected by inaccurate assumptions, and are subject to various business risks and known and unknown uncertainties, a number of which are beyond our control.  Therefore, actual results could differ materially from the forward-looking statements contained in this document, and readers are cautioned not to place undue reliance on such forward-looking statements.  These statements are only predictions and involve known and unknown risks, uncertainties and other factors, including the risks in the section entitled “Risk Factors” that may cause our or our industry’s actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by these forward-looking statements.

Important factors that may cause the actual results to differ from the forward-looking statements, projections or other expectations include, but are not limited to, the following:

·   changes in our business strategy;

·   the uncertainty of reserve estimates and timing of development expenditures;

·   access and availability of materials, equipment, supplies, labor and supervision, power and water;

·   results of current and future exploration activities;

·   results of pending and future feasibility studies;

·   accidents and labor disputes;

·   disappointing results from our exploration or development efforts;

·   failure to meet our revenue or profit goals or operating budget;

·   decline in demand for our common stock;

·   changes in general market conditions;

·   investor perception of our industry or our prospects;

·   technological changes in the oil and gas exploration industry, including technological innovations by competitors or in competing technologies;

·   the proximity of natural gas production to natural gas pipelines;

·   the availability of pipeline capacity;

·   the demand for oil and natural gas by utilities and other end users;

·   the availability of alternate fuel sources;

·   the effect of inclement weather, such as hurricanes;

·   changes in oil and gas exploration, processing and overhead costs;

·   unexpected changes in business and economic conditions;

·   changes in interest rates and currency exchange rates;

·   commodity price fluctuations, including changes in the worldwide price for oil and gas;

·   state and federal regulation of oil and natural gas marketing;

·   federal regulation of natural gas sold or transported in interstate commerce; and

·   local and community impacts and issues.

- 3 -

Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements.  You should not place undue reliance on these forward-looking statements, which speak only as of the date of this report.  Except as required by law, we do not undertake to update or revise any of the forward-looking statements to conform these statements to actual results, whether as a result of new information, future events or otherwise.

As used in this annual report, “Delta Oil & Gas,” “Delta”, the “Company,” “we,” “us,” or “our” refer to Delta Oil & Gas, Inc., unless otherwise indicated.

If you are not familiar with the oil and gas terms used in this report, please refer to the definitions of these terms under the caption “Glossary” at the end of Item 15 of this report.

- 4 -

PART I

ITEM 1.    BUSINESS.  

Business of Delta

We were incorporated under the laws of the State of Colorado on January 9, 2001 under the name Delta Oil & Gas, Inc.  We are engaged in the acquisition, exploration and development of North American oil and gas properties. Because oil and gas exploration and development requires significant capital and our assets and resources are limited, we participate in the oil and gas industry through the purchase of minority interests in either producing wells or oil and gas exploration and development projects.

Our current focus is on the exploration of our land portfolio comprised of working interests in acreage in King City, California; Southern Saskatchewan, Canada; South Central, Oklahoma; and Eastern, Texas.  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 and effected 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 were combined into one (1) share of common stock.  The reverse stock split did not change the number of authorized shares of our common stock.

No fractional shares were issued in connection with the reverse stock split and any fractional shares potentially issuable were 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 were 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 (“Stallion”), in exchange for 0.333333 shares of our common stock and $0.0008 in cash per share of Stallion, 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 Stallion 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 Stallion common stock had been validly tendered, representing 80.31% of the issued and outstanding common shares of Stallion.

All validly tendered common shares of Stallion were accepted for payment in accordance with the terms of the Offer, pursuant to which each validly tendered common share of Stallion 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 3,909,005sharesof our common stock and paid $46,908 in cash pursuant to the Offer.

- 5 -

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 year ended December 31, 2008, 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.  We agreed to pay 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.

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 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 refer to this drilling program as Palmetto Point Phase I.

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.  Total revenue received from the Palmetto Point Phase I producing wells for the year ended December 31, 2009 was $Nil, compared with $38,981in revenues for the year ended December 31, 2008.  The decrease in revenue was attributable to our disposition of these wells during fiscal 2009.

- 6 -

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% 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.

Seven wells had been drilled resulting in four producing wells.  We refer to this drilling program as Palmetto Point Phase II.

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.

Total revenue received from the Palmetto Point Phase II producing wells for the year ended December 31, 2009 was $Nil, compared with  $79,050 in revenues for the year ended December 31, 2008.  The decrease in revenue was attributable to our disposition of these wells during fiscal 2009.

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.

- 7 -

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

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

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

The revenue received from all wells in the Wordsworth prospectfor the year ended December 31, 2009 was $195,491 (2008: $104,989).  The increase in revenue was caused by the addition of a two new successful wells during the reporting period; however, this was partially offset by the disposal of 2.5% of our interest in the Wordsworth Prospect for $214,961, effective on June 1, 2009, thereby reducing our interest from 7.5% to 5%.

We will continue to hold a 5% working interest in our existing wells on the Wordsworth prospect and any future wells which we elect to participate.

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.

- 8 -

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.  In July 2008, we disposed of our 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.

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 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 the Plaster #1 and Dale #1 wells for the year ended December 31, 2009 was $7,920 (December 31, 2008: $46,923).  The reduction in revenue was caused by the suspension of production, the gradual decline in the reserves from these wells and the reduction in commodity prices when compared to the previous year.

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”) was completed in the N.E. Anitoch Prospect and the Washington Creek Prospect respectively.  The Pollock #1-35 did not prove to be commercially viable, 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.

Drilling of the third well in this drilling program (the “River #1”) was completed during the three months ended September 30, 2008.  River #1 commenced production and the total revenue received for the year ended December 31, 2009 was $47,468 (December 31, 2008: $79,897), the reduction was caused by a reduction in the commodity prices during the year.

Hulsey #1-8 started producing during the first quarter of 2008 and the total revenue received for the year ended December 31, 2009 was $66,212 (December 31, 2008: $111,498).  The reduction in revenue was caused by a reduction in commodity prices during the reporting period, together with a decline in production rates.

- 9 -

Hulsey #2-8 commenced production during the three months ended March 31, 2009 and produced $20,034 in oil revenues for the year ended December 31, 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 initially acquired a 5.0% working interest in the 2009-1 Drilling Program in exchange for our payment of a total of $13,125 in buy-in costs, which equates to $2,625 in buy-in costs for each well, plus our proportionate shares of the drilling and completion costs.  During the fourth quarter of 2009, our working interest in the 2009-1 Drilling Program was reduced to 3.75%.  The reduction in our working interest was attributable to the landowner exercising an option to increase its working interest causing in a proportional reduction to all working interests held in this drilling program.  During the year ended December 31, 2009, we paid estimated drilling and completion costs of $72,175for three wells which we refer to as Saddle #1-18, Saddle #2-18 and  Saddle #3-18.  The first two wells in this drilling program started to produce hydrocarbons in November and December 2009, resulting in revenue of $6,390 for the year ended December 31, 2009.

2009-3 Drilling Program - 4 Wells

On August 7, 2009, we entered into an agreement with Ranken Energy to participate in a four well drilling program in Garvin County, Oklahoma (the “2009-3 Drilling Program”).  We purchased a 6.25% working interest before casing point and 5.0% working interest after casing point in the 2009-3 Drilling Program for $37,775.  In addition to the total buy-in cost, we will be responsible for our proportionate share of the drilling and completion costs.  During the year ended December 31, 2009, we paid additional drilling costs in the amount of $78,090.  There has been no revenue generated during fiscal 2009; however, we anticipate that all four wells will begin production of hydrocarbons during the first quarter of 2010.

Willows Gas Field

On February 15, 2007, Stallion entered into a Farm Out Agreement with Production Specialties Company (“Production Specialties”) for participation in a natural gas prospect area located in the North Sacramento Valley, California.  On October 15, 2007, Stallion drilled its first prospect well paying 12.5% of the costs of the first well to earn a 6.25% working interest.  For subsequent wells, Stallion will pay 6.25% of the costs of future wells to earn 6.25% working interestStallion participated in the drilling of the first well (“Wilson Creek #1-27”)  on the prospect area and encountered a number of prospective pay zones.  Testing was completed and stabilized flow rates exceeded a combined 1.5 million cubic feet per day of sweet high quality gas.  Thereafter, the Wilson Creek #1-27 was connected to a nearby pipeline and begun producing natural gas in April 2008.  Total costs for the Wilson Creek #1-27 well in the end year ended December 31, 2009 was $255,971.  During the year and in light of the lower natural gas commodity prices, we reviewed the future economic viability of this well and decided to suspend production until further notice in order to determine whether production of this well will be profitable.  The total revenue received from the Wilson Creek #1-27 well for the year ended December 31, 2009 was $3,433 (December 31, 2008: $147,958).  The reduction in revenue was caused by a our decision to suspend production, a reduction in commodity prices during the reporting period and a decline in production rates attributable to a depletion in reserves.

King City, California

On May 25, 2009, we entered into a farm-out agreement with Sunset Exploration (“Sunset”), a California corporation, to participate in the drilling and exploration of lands located in Monterey County, California.  The prospect area where the drilling and exploration will take place is comprised of approximately 10,000 acres.  We are obligated to pay 66.67% of the costs of the initial test well up to casing point, in order to earn a 40.0% working interest.  Thereafter, we will be obligated to pay 40.0% of the costs of any future wells which we elect to participate in order to earn a 40.0% working interest.  We paid Sunset $100,000 as an advance towards the permitting and processing of lands and the costs of a gravity survey and a 2D seismic program. We commenced a gravity survey and 2D seismic program in August 2009.  Following receipt of the results from the gravity survey and 2D seismic program, we decided to pursue further 2D seismic analysis in order to identify viable hydrocarbon targets for its first test well, which we anticipate will be completed by December 31, 2010.

- 10 -

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”).  These Leases will provide us with the ability to drill up to 3 exploration wells.  The costs of the leases were $169,566.  In December 2009, we sold a sixty (60%) percent interest in the Leases to Hillcrest Resources Ltd. (“Hillcrest”) and received $111,424.  As at December 31, 2009, the costs of the leases were $74,018.  We hired an operator and will commence drilling of its first exploration well during the second quarter of 2010.

After disposition of a 60% interest in the Leases to Hillcrest, we will be responsible for 40% of all costs allocated to the Leases, drilling and completion of up to 3 exploration wells. We anticipate the dry hole costs to be approximately $442,000.  Once the 3 exploration wells are drilled, completed and production commences, if at all, we will receive a percentage distribution of net revenue, after deduction of all applicable expenses and royalties of approximately 25%, according to the following table:

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

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

Market for Our Products and Services

Each oil and gas working interest that we now own and those that we may later acquire a percentage of interest in will have an operator who will be responsible for marketing production.

The availability of a ready market for oil and gas and the prices of such oil and gas depend upon a number of factors which are beyond our control. These include, among other things:

•           the level of domestic production;

•           actions taken by foreign oil and gas producing nations;

•           the availability of pipelines with adequate capacity;

•           the availability and marketing of other competitive fuels;

•           fluctuating and seasonal demand for oil, gas and refined products; and

•           the extent of governmental regulation and taxation (under both present and future legislation) of

            the production, importation, refining, transportation, pricing, use and allocation of oil, gas, refined

            products and alternative fuels.

                In view of the many uncertainties affecting the supply and demand for crude oil, gas and refined petroleum products, it is not possible to predict accurately the prices or marketability of the gas and oil produced for sale.

- 11 -

In addition, the oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.  The price and availability of alternative energy sources could adversely affect our revenue.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state, local and tribal laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Patents, Licenses, Trademarks, Franchises, Concessions, Royalty Agreements, or Labor Contracts

We do not own, either legally or beneficially, any patent or trademark.

Research and Development

We did not incur any research and development expenditures in the fiscal years ended December 31, 2009 or 2008.

Existing and Probable Governmental Regulation

We monitor and comply with current government regulations that affect our activities, although our operations may be adversely affected by changes in government policy, regulations or taxation. There can be no assurance that we will be able to obtain all of the necessary licenses and permits that may be required to carry out our exploration and development programs. It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other natural gas and oil companies operating in the areas in which we operate.

United States Government Regulation

The United States federal government and various state and local governments have adopted laws and regulations regarding the protection of human health and the environment. These laws and regulations may require the acquisition of a permit by operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas, wetlands, or where pollution might cause serious harm, and impose substantial liabilities for pollution resulting from drilling operations, particularly with respect to operations in onshore and offshore waters or on submerged lands. These laws and regulations may increase the costs of drilling and operating wells. Because these laws and regulations change frequently, the costs of compliance with existing and future environmental regulations cannot be predicted with certainty.

The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the federal government. Production of any oil and gas by properties in which we have an interest will be affected to some degree by state regulations. States have statutory provisions regulating the production and sale of oil and gas, including provisions regarding deliverability. Such statutes and the regulations are generally intended to prevent waste of oil and gas and to protect correlative rights to produce oil and gas between owners of a common reservoir.

State regulatory authorities may also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or pro-ration unit.

- 12 -

Any exploration or production on Federal land will have to comply with the Federal Land Management Planning Act which has the effect generally of protecting the environment. Any exploration or production on private property whether owned or leased will have to comply with the Endangered Species Act and the Clean Water Act. The cost of complying with environmental concerns under any of these acts varies on a case by case basis. In many instances the cost can be prohibitive to development. Environmental costs associated with a particular project must be factored into the overall cost evaluation of whether to proceed with the project.

Environmental Regulation

Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution. The strict liability nature of such laws and regulations could impose liability upon us regardless of fault. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the “Superfund” law, generally imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance. Under CERCLA and comparable state statutes, such persons may be subject to strict joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  Governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

Canadian Government Regulation

The natural gas and oil industry is subject to extensive controls and regulations imposed by various levels of government. It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other natural gas and oil companies of similar size.

Pricing and Marketing Natural Gas

In Canada, the price of natural gas sold in interprovincial and international trade is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain criteria prescribed by the NEB and the Government of Canada. Natural gas exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m3/day) must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export license from the NEB and the issue of such a license requires the approval of the Governor in Council.

The government of Alberta also regulates the volume of natural gas that may be removed from the province for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.

- 13 -

Royalties and Incentives

                In addition to federal regulation, each province has legislation and regulations that govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of natural gas and oil production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.

Land Tenure

Crude natural gas and oil located in the western provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce natural gas and oil pursuant to leases, licenses and permits for varying terms from two years and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Natural gas and oil located in such provinces can also be privately owned and rights to explore for and produce such natural gas and oil are granted by lease on such terms and conditions as may be negotiated.

Compliance with Environmental Laws

We did not incur any costs in connection with the compliance with any federal, state, or local environmental laws. However, costs could occur at any time through industrial accident or in connection with a terrorist act or a new project. Costs could extend into the millions of dollars for which we could be totally liable. In the event of liability, we believe we would be entitled to contribution from other owners so that our percentage share of a particular project would be the percentage share of our liability on that project. However, other owners may not be willing or able to share in the cost of the liability. Even if liability is limited to our percentage share, any significant liability would wipe out our assets and resources.

Employees

We have no full-time employees at the present time.   Our executive officers do not devote their services full time to our operations.  

We engage contractors from time to time to consult with us on specific corporate affairs or to perform specific tasks in connection with our oil and gas operations.  As of December 31, 2009, we engaged approximately 3 contractors that provided work to us on a recurring basis, which includes Messrs. Paton-Gay, Bolen and Sandher.

- 14 -

ITEM 1A.      Risk Factors.

You should carefully consider the following risk factors in evaluating our business and us.  The factors listed below represent certain important factors that we believe could cause our business results to differ.  These factors are not intended to represent a complete list of the general or specific risks that may affect us.  It should be recognized that other risks may be significant, presently or in the future, and the risks set forth below may affect us to a greater extent than indicated.  If any of the following risks occur, our business, financial condition or results of operations could be materially and adversely affected.  You should also consider the other information included in this Annual Report and subsequent quarterly reports filed with the SEC.

Risk Factors

Risks Associated With Our Business

Operational Risks of Delta

Because we have experienced significant losses since inception, it is uncertain when, if ever, we will have significant operating income or cash flow from operations sufficient to sustain operations.

We suffered net losses since our inception, including net losses of $2,337,765 for the year ended December 31, 2009 and $215,826 for the year ended December 31, 2008. These losses are the result of an inadequate revenue stream to compensate for our operating and overhead costs. The volatility underlying the early stage nature of our business and our industry prevents us from accurately predicting future operating conditions and results, and we could continue to have losses. It is uncertain when, if ever, we will have significant operating income or cash flow from operations sufficient to sustain operations. If cash needs exceed available resources additional capital may not be available through public or private equity or debt financings. If we are unable to arrange new financing on terms that are acceptable to us or generate sufficient revenue from our prospects, we will be unable to continue in our current form and our business will fail.

If we are unable to obtain additional funding, we may be unable to expand our acquisition, exploration and production of natural oil and gas properties.

We will require additional funds to expand our acquisition, exploration and production of natural oil and gas properties. Our management anticipates that current cash on hand may be insufficient to fund our 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 implement our overall business strategy. There can be no assurance that financing will be available in amounts or on terms acceptable to us, if at all. The inability to obtain additional capital will restrict our ability to grow and may reduce our ability to continue to conduct current business operations. If we are unable to obtain additional financing when sought, we will be unable to acquire additional properties and may also be required to curtail our business plan. Any additional equity financing may involve substantial dilution to our then existing shareholders.

Because we cannot control activities on our properties, we may experience a reduction or forfeiture of our interests in some of our non-operated projects as a result of our potential failure to fund capital expenditure requirements.

We do not operate the properties in which we have a working 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

- 15 -

could materially adversely affect the realization of our returns on capital in drilling or acquisition activities and our targeted production growth rate. The success and timing of drilling, development and exploitation activities on properties operated by others depend on a number of factors that are beyond our control, including the operator’s expertise and financial resources, approval of other participants for drilling wells and utilization of technology. In addition, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.

If we are unable to successfully identify, execute or effectively integrate new prospects, our results of operations may be negatively affected.

Acquisitions of working interests in oil and gas properties have been an important element of our business, and we will continue to pursue acquisitions of new prospects in the future. In the last year, we have pursued and consummated the acquisition and drilling of new prospects that have provided us opportunities to grow our production and reserves.  Although we regularly engage in discussions with, and submit proposals to, acquisition candidates, suitable acquisitions may not be available in the future on reasonable terms. If we do identify an appropriate acquisition candidate, we may be unable to successfully negotiate the terms of an acquisition, finance the acquisition or, if the acquisition occurs, effectively integrate the acquired business into our existing business. Negotiations of potential acquisitions and the integration of acquired business operations may require a disproportionate amount of management’s attention and our resources. Even if we complete additional acquisitions, continued acquisition financing may not be available or available on reasonable terms, any new properties may not generate revenues comparable to our existing properties, the anticipated cost efficiencies or synergies may not be realized and these properties may not be integrated successfully or operated profitably. The success of any acquisition will depend on a number of factors, 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. Our inability to successfully identify, execute or effectively integrate future acquisitions may negatively affect our results of operations. Even though we perform a due diligence review (including a review of title and other records) of the properties we seek to acquire that we believe is consistent with industry practices, these reviews are inherently incomplete. Even an in-depth review of records and properties may not necessarily reveal existing or potential problems or permit us to become familiar enough with the properties to assess fully their deficiencies and potential. Even when problems are identified, we may assume certain environmental and other risks and liabilities in connection with the acquired properties. The discovery of any material liabilities associated with our acquisition of Stallion could harm our results of operations. In addition, acquisitions of working interests may require additional debt or equity financing, resulting in additional leverage or dilution of ownership.

Unless we replace our oil and gas reserves, our reserves and production will decline.

Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves.

Because our executive officers do not provide services on a full-time basis, they may not be able or willing to devote a sufficient amount of time to our business operations, causing our business to fail.

Our executive officers do not provide services to us on a full-time basis. We do not maintain key man life insurance policies for our executive officers. Currently, we do not have any employees other than our executive officers. If the demands of our business require the full business time of Messrs. Paton-Gay, Bolen, and Sandher, it is possible that Messrs. Paton-Gay, Bolen, and/or Sandher may not be able to devote sufficient time to the management of our business, as and when needed. If our management is unable to devote a sufficient amount of time to manage our operations, our business will fail.

- 16 -

If the employment of any of our executive officers is terminated for any reason, we may be required to make substantial severance payments and to repurchase any shares of common stock held by them, which could have a materially negative impact on our liquidity.

               In the event that the employment of any of our executive officers was terminated for any reason, our executive officers would be entitled, among other things, to receive a lump sum payment equal to 150% of their annual compensation then in effect, includingthe value of all stock awards that would have been received in the 18 months following termination, and to require us to purchase, for cash, any shares of our stock held by or due to them as of the date of termination.  The purchase of any such shares would be consummated thirty (30) days following the date of termination and the price to be paid by us would be based upon the average closing price per share of our common stock in the ten business days preceding the purchase date.  Any lump sum compensation payments to or the repurchase of shares held by one or more departing executive officers could have a materially negative impact on our cash available for operations and our liquidity.

Because our directors and officers may serve as directors or officers of other companies, they may have a conflict of interest in making decisions for our business.

Our directors and officers may serve as directors or officers of other companies or have significant shareholdings in other oil and gas companies and, to the extent that such other companies may participate in ventures in which we may participate, our directors and officers may have a conflict of interest in negotiating and concluding terms respecting the extent of such participation.  In the event that such a conflict of interest arises at a meeting of our directors, a director who has such a conflict will abstain from voting for or against the approval of such participation or such terms.  In determining whether or not we will participate in a particular program and the interest therein to be acquired by us, our directors will primarily consider the degree of risk to which we may be exposed and our financial position at that time.

Because our auditor has raised substantial doubt about our ability to continue as a going concern, our business has a high risk of failure.

As noted in our financial statements, we commenced operations 9 years ago. The audit report of STS Partners LLP, Chartered Accountants issued a going concern opinion and raised substantial doubt as to our continuance as a going concern. When an auditor issues a going concern opinion, the auditor has substantial doubt that the company will continue to operate indefinitely and not go out of business and liquidate its assets. This is a significant risk to investors who purchase shares of our common stock because there is an increased risk that we may not be able to generate and/or raise enough resources to remain operational for an indefinite period of time. The success of our business operations depends upon our ability to obtain additional capital for obtaining producing oil and gas properties through either the purchase of producing wells or successful exploration activity. We plan to seek additional financing through debt and/or equity financing arrangements to secure funding for our operations. There can be no assurance that such additional financing will be available to us on acceptable terms or at all. It is not possible at this time for us to predict with assurance the outcome of these matters. If we are not able to successfully complete the development of our business plan and attain sustainable profitable operations, then our business will fail.

Because we presently do not carry liability or title insurance on any of our properties and do not plan to secure any in the future, we are vulnerable to excessive potential claims and loss of title.

We do not maintain insurance against public liability, environmental risks or title on any of our properties. The possibility exists that title to existing properties or future prospective properties may be lost due to an omission in the claim of title. As a result, any claims against us may result in liabilities we will not be able to afford resulting in the failure of our business.

- 17 -

The laws of the State of Colorado and our Articles of Incorporation may protect our directors from certain types of lawsuits.

The laws of the State of Colorado provide that our directors will not be liable to us or our shareholders for monetary damages for all but certain types of conduct as directors of the company. Our articles of incorporation permit us to indemnify our directors and officers against all damages incurred in connection with our business to the fullest extent provided or allowed by law. The exculpation provisions may have the effect of preventing shareholders from recovering damages against our directors caused by their negligence, poor judgment or other circumstances. The indemnification provisions may require us to use our limited assets to defend our directors and officers against claims, including claims arising out of their negligence, poor judgment, or other circumstances.

Market Risks

Our stock price may be volatile and as a result you could lose all or part of your investment.

In addition to volatility associated with over the counter securities in general, the value of your investment could decline due to the impact of any of the following factors upon the market price of our common stock:

•           changes in the worldwide price for oil and gas;

•           disappointing results from our exploration or development efforts;

•           failure to meet our revenue or profit goals or operating budget;

•           decline in demand for our common stock;

•           downward revisions in securities analysts’ estimates or changes in general market conditions;

•           technological innovations by competitors or in competing technologies;

•           investor perception of our industry or our prospects; and

•           general economic trends.

In addition, stock markets generally have experienced extreme price and volume fluctuations and the market prices of securities generally have been highly volatile. These fluctuations are often unrelated to operating performance of a company and may adversely affect the market price of our common stock. As a result, investors may be unable to resell their shares at a fair price.

Intense competition in the oil and gas exploration and production segment could adversely affect our ability to acquire desirable properties prospective for oil and gas, as well as producing oil and gas properties.

The oil and gas industry is highly competitive. We compete with major integrated and independent oil and gas companies for the acquisition of desirable oil and gas properties and leases, for the equipment and services required to develop and operate properties, and in the marketing of oil and gas to end-users. Many competitors have financial and other resources that are substantially greater than ours, which could, in the future, make acquisitions of producing properties at economic prices difficult for us. In addition, many larger competitors may be better able to respond to factors that affect the demand for oil and natural gas production, such as changes in worldwide oil and natural gas prices and levels of production, the cost and availability of alternative fuels and the application of government regulations. We also face significant competition in attracting and retaining experienced, capable and technical personnel with experience in the oil and gas industry.

- 18 -

Numerous factors beyond our control could affect the marketability of oil and natural gas, so we may experience difficulty selling any oil and natural gas.

The availability of markets and the volatility of product prices are beyond our control and represent a significant risk. The marketability of our production depends upon the availability and capacity of natural gas gathering systems, pipelines and processing facilities. The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Our ability to generate revenue from oil and natural gas sales also depends on other factors beyond our control. These factors include:

•           the level of domestic production and imports of oil and natural gas;

•           the proximity of natural gas production to natural gas pipelines;

•           the availability of pipeline capacity;

•           the demand for oil and natural gas by utilities and other end users;

•           the availability of alternate fuel sources;

•           the effect of inclement weather, such as hurricanes;

•           state and federal regulation of oil and natural gas marketing; and

•           federal regulation of natural gas sold or transported in interstate commerce.

If these factors were to change dramatically, our ability to generate revenues from oil and natural gas sales or obtain favorable prices for our oil and natural gas could be adversely affected.

We have hurricane associated risks in connection with our properties in Texas.

In the event that commercially productive reservoirs are discovered in the wells that are to be drilled on our properties in Texas, these properties will be vulnerable to significant production curtailments resulting from hurricane damage to certain fields or, even in the event that producing fields are not damaged, production could be curtailed due to damage to facilities and equipment owned by oil and gas purchasers, or vendors and suppliers, because a portion of our oil and gas properties are located near coastal areas of the Texas.

Risks Relating to Our Business

Because exploration, development and drilling efforts are subject to many risks, the operation of our wells may not be profitable or achieve our targeted returns.

Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We seek to acquire working interests in properties which we believe will result in projects that will add value over time. However, we cannot guarantee that all of our prospects will result in viable projects or that we will not abandon these properties. Additionally, we cannot guarantee that any undeveloped acreage we have an interest in will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such acreage or wells. Drilling for oil and natural gas may 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 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.

- 19 -

Because our oil and natural gas reserve data is independently estimated, these estimates may still prove to be inaccurate.

Our reserve estimates generated for 2009 were compiled by, Harper & Associates, Mark E. Anderson and Chapman Petroleum Engineering independent consultants. In conducting their evaluations, the consultants evaluate our properties and independently develop proved reserve estimates.  There are numerous uncertainties and risks that are inherent in estimating quantities of oil and natural gas reserves and projecting future rates of production and timing of development expenditures as many factors are beyond our control. Many factors and assumptions are incorporated into these estimates including: expected reservoir characteristics based on geological, geophysical and engineering assessments;

• future production rates based on historical performance and expected future operating and investment activities;

• future oil and gas prices and quality and location differentials; and

• future development and operating costs.

Although we believe the independent consultant’s reserve estimates are reasonably based on the information available to them at the time they prepare their estimates, our actual results could vary materially from these estimated quantities of proved oil and natural gas reserves (in the aggregate and for a particular location), production, revenues, taxes and development and operating expenditures. In addition, these estimates of reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing oil and natural gas prices, operating and development costs and other factors.

Use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results drilling operations on our properties.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, drilling activities on our properties may not be successful or economical.

Because our business is subject to operating hazards, our business may be adversely affected by the occurrence of any such hazards.

Our operations are subject to risks inherent in the oil and natural gas industry, such as:

•           unexpected drilling conditions including blowouts and explosions;

•           uncontrollable flows of oil, natural gas or well fluids;

•           equipment failures, fires or accidents;

•           pollution and other environmental risks; and

•           shortages in experienced labor or shortages or delays in the delivery of equipment.

These risks could result in substantial losses to us from injury and loss of life, damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. Our operations are also subject to a variety of operating risks such as adverse weather conditions and more extensive governmental regulation. These regulations may, in certain circumstances, impose strict liability for pollution damage or result in the interruption or termination of operations.

- 20 -

Possible regulation related to global warming and climate change could have an adverse effect on our business, financial condition or results of operations and demand for natural gas and oil.

In June 2009, the United States House of Representatives passed the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill or ACESA. Further, on November 5, 2009, the United States Senate passed out of committee the Clean Energy Jobs and American Power Act, also known as the Boxer-Kerry Bill. These bills contain provisions that would establish a cap and trade system for restricting greenhouse gas emissions in the United States. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. Under such a system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The ultimate outcome of this federal legislative initiative remains uncertain.

In addition to pending climate legislation, the Environmental Protection Agency, or EPA, has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding could lead to regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. EPA has proposed such greenhouse gas regulations and may issue final rules this year.

In the courts, several decisions have been issued that could increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people and property.

Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and natural gas.

Risks Relating to our Common Stock

Trading on the over-the-counter bulletin board may be volatile and sporadic, which could depress the market price of our common stock and make it difficult for our stockholders to resell their shares.

Our common stock is quoted on the over-the-counter bulletin board service of the Financial Industry Regulatory Authority (the “OTCBB”).  Trading in stock quoted on the OTCBB is often thin and characterized by wide fluctuations in trading prices, due to many factors that may have little to do with our operations or business prospects.  This volatility could depress the market price of our common stock for reasons unrelated to operating performance.  Moreover, the OTCBB is not a stock exchange, and trading of securities on the OTCBB is often more sporadic than the trading of securities listed on a quotation system like Nasdaq or a stock exchange like Amex.  Accordingly, shareholders may have difficulty reselling any of the shares.

Because our common stock is quoted and traded on the OTCBB, short selling could increase the volatility of our stock price.

Short selling occurs when a person sells shares of stock which the person does not yet own and promises to buy stock in the future to cover the sale.  The general objective of the person selling the shares short is to make a profit by buying the shares later, at a lower price, to cover the sale.  Significant amounts of short selling, or the perception that a significant amount of short sales could occur, could depress the market price of our common stock. In contrast, purchases to cover a short position may have the effect of preventing or retarding a decline in the market price of our common stock, and together with the imposition of the penalty bid, may stabilize, maintain or otherwise affect the market price of our common stock.  As a result, the price of our common stock may be higher than the price that otherwise might exist in the open market.  If these activities are commenced, they may be discontinued at any time.  These transactions may be effected on the OTCBB or any other available markets or exchanges.  Such short selling if it were to occur could impact the value of our stock in an extreme and volatile manner to the detriment of our shareholders.

- 21 -

We may experience difficulties in the future in complying with Sarbanes-Oxley Section 404.

We are required to evaluate furnish a report by our management on our internal controls under Section 404 of the Sarbanes-Oxley Act of 2002.  Such report contains among other matters, an assessment of the effectiveness of our internal control over financial reporting as of the end of our fiscal year, including a statement as to whether or not our internal control over financial reporting is effective.

If we fail to maintain proper and effective internal controls in future periods, it could adversely affect our operating results, financial condition and our ability to run our business effectively and could cause investors to lose confidence in our financial reporting.

We have never paid dividends and have no plans to in the future.

Holders of shares of our common stock are entitled to receive such dividends as may be declared by our board of directors.  To date, we have paid no cash dividends on our shares of common stock and we do not expect to pay cash dividends on our common stock in the foreseeable future.  We intend to retain future earnings, if any, to provide funds for operation of our business.  Therefore, any return investors in our common stock will have to be in the form of appreciation, if any, in the market value of their shares of common stock.

We have additional securities available for issuance, which, if issued, could adversely affect the rights of the holders of our common stock.

Our Articles of Incorporation authorize the issuance of 100,000,000 shares of our common stock and 25,000,000 shares of preferred stock.  The common stock or preferred stock can be issued by our board of directors, without stockholder approval.  Any future issuances of our common stock would further dilute the percentage ownership of our common stock held by public stockholders.

If we issue shares of preferred stock with superior rights than our common stock, it could result in the decrease the value of our common stock and delay or prevent a change in control of us.

Our board of directors is authorized to issue up to 25,000,000 shares of preferred stock. Our board of directors has the power to establish the dividend rates, liquidation preferences, voting rights, redemption and conversion terms and privileges with respect to any series of preferred stock. The issuance of any shares of preferred stock having rights superior to those of the common stock may result in a decrease in the value or market price of the common stock. Holders of preferred stock may have the right to receive dividends, certain preferences in liquidation and conversion rights. The issuance of preferred stock could, under certain circumstances, have the effect of delaying, deferring or preventing a change in control of us without further vote or action by the stockholders and may adversely affect the voting and other rights of the holders of common stock.

Because the SEC imposes additional sales practice requirements on brokers who deal in our shares that are penny stocks, some brokers may be unwilling to trade them. This means that you may have difficulty in reselling your shares and may cause the price of the shares to decline.

Our stock is a penny stock. The Securities and Exchange Commission has adopted Rule 15g-9 which generally defines “penny stock” to be any equity security that has a market price (as defined) less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities are covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and “accredited investors”. The term “accredited investor” refers generally to institutions with assets in excess of $5,000,000 or individuals with a net worth in excess of $1,000,000 or annual income exceeding $200,000 or $300,000 jointly with their spouse. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC which provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny

- 22 -

stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer’s account. The bid and offer quotations and the broker-dealer and salesperson compensation information must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer’s confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities. We believe that the penny stock rules discourage investor interest in, and limit the marketability of, our common stock.

In addition to the “penny stock” rules promulgated by the Securities and Exchange Commission, FINRA has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative, low-priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low-priced securities will not be suitable for at least some customers. The FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock.

Indemnification of officers and directors.

Our articles of incorporation and the bylaws contain broad indemnification and liability limiting provisions regarding our officers, directors and employees, including the limitation of liability for certain violations of fiduciary duties.  Our stockholders therefore will have only limited recourse against such individuals.

ITEM 1B.UNRESOLVED STAFF COMMENTS.

None.

ITEM 2.         PROPERTIES.  

Description of Our Property

     Our principal executive offices are located at Suite 604, 700 West Pender Street, Vancouver, British Columbia, Canada V6C 1G8.  Our principle executive offices are provided to us at no cost by our Chief Financial Officer.

Proved Reserves Reporting

On December 31, 2008, the Securities and Exchange Commission, or the SEC, released a Final Rule, Modernization of Oil and Gas Reporting, approving revisions designed to modernize oil and gas reserve reporting requirements. The new reserve rules are effective for our financial statements for the year ended December 31, 2009 and our 2009 year-end proved reserve estimates. The most significant revisions to the reporting requirements include:

·   Commodity prices.  Economic producibility of reserves is now based on the unweighted, arithmetic average of the closing price on the first day of the month for the 12-month period prior to fiscal year end, unless prices are defined by contractual arrangements;

·   Undeveloped oil and gas reserves.  Reserves may be classified as “proved undeveloped” for undrilled areas beyond one offsetting drilling unit from a producing well if there is reasonable certainty that the quantities will be recovered;

- 23 -

·   Reliable technology.  The rules now permit the use of new technologies to establish the reasonable certainty of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes;

·   Unproved reserves.  Probable and possible reserves may be disclosed separately on a voluntary basis;

·   Preparation of reserves estimates.  Disclosure is required regarding the internal controls used to assure objectivity in the reserves estimation process and the qualifications of the technical person primarily responsible for preparing reserves estimates; and

·   Third party reports.  We are now required to file the report of any third party used to prepare or audit reserves our estimates.

We adopted the rules effective December 31, 2009, as required by the SEC.

Reported Reserves Table

The following table sets forth summary information regarding our estimated proved reserves at December 31, 2009, 2008 and 2007:

December 31,
	2009		2008		2007
	Oil (Bbls)	Gas (Mcf)	Gas (Mcf)	Oil (Bbls)	Gas (Mcf)	Oil (Bbls)
Proved Producing & Non-Producing Reserves (1)	41,230	116,940	209,173	53,355	166,660	74,894
Present value of proved reserves(2)	1,066,900		1,121,422		4,213,549
Standardized measure of discounted future net cash flows (3)	1,162,410		968,550		2,759,875

(1) Estimates of reserves as of year-end 2009 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2009, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2009. Estimates of reserves as of year-end 2008 and 2007 were prepared using constant prices and costs in accordance with previous guidelines of the SEC based on hydrocarbon prices received on a field-by-field basis as of December 31st of the applicable year. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

(2) Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on certain prevailing economic conditions. The estimated future production in our reserve reports dated December 31, 2009 is priced based on the 12-month un-weighted arithmetic average of the first-day-of-the month price for the period January through December 2009. The estimated future production in our reserve reports dated December 31, 2008 and 2007 is priced using constant year-end pricing.  PV-10 is a non-GAAP measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP.

- 24 -

(3) The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

The table below sets forth summary information regarding our estimated proved reserves for each country containing 15% or more of our proved reserves.  All estimated proved reserves in Canada are attributable to the Wordsworth Prospect in Saskatchewan and all estimated proved reserves in the United States are attributable to our properties in Garvin and Murray counties in Oklahoma that comprise the 2006-3, 2007-1, 2009-1 and 2009-3 drilling programs referenced above in "Item 1, Business."

	Reserves
Reserve Category	Oil & NGL’s (Bbls)	Natural Gas (Mcf)	Total (BOE)
PROVED
Developed:
USA	10,720	110,130	29,075
Canada	12,000	0	12,000
Total	22,720	110,130	41,075
Undeveloped:
USA	11,510	6,810	12,645
Canada	7,000	0	7,000
Total	18,510	6,810	19,645
TOTAL PROVED at December 31, 2009	41,230	116,940	60,720

Proved Undeveloped Reserves

As of December 31, 2009, we had 20,000 BOE (Barrels of Oil Equivalent) of proved undeveloped reserves, or PUDs.  As at December 31, 2009, we had approximately 35% of our PUD’s in Canada and 65% located in the USA.  Each of these PUD’s will be converted from undeveloped to developed as the wells begin production.   We anticipate that all of the PUD’s in the USA will be on production within the first two quarters of 2010; the remaining PUD’s in Canada will be developed within five years of December 31, 2009.

Internal Controls Over Preparation of Proved Reserve Estimates

Our policies regarding internal controls over reserve estimates requires reserves to be in compliance with the SEC definitions and guidance and for reserves to be prepared by an independent third party reserve engineering firm under the supervision of our management. Our management provides to our third party reserves engineers reserves estimate preparation material such as property interests, production, current costs of operation and development, current prices for production, geoscience and engineering data, and other information. This information is reviewed by other members of management to ensure accuracy and completeness of the data prior to submission to our third party reserve engineering firm.  During 2009 , we retained Harper & Associates, Inc., Mark E. Andersen and Chapman Petroleum Engineering as independent third-party reserve engineers, to prepare our estimates of proved reserves.  For more information about the evaluations performed by Harper & Associates, Inc., Mark E. Andersen, and Chapman Petroleum Engineering, see copies of their respective reports filed as exhibits to this Form 10-K.

- 25 -

Reserves Reported to Other Agencies

We did not file any reports during the year ended December 31, 2009 with any federal authority or agency other than the SEC with respect to our estimates of oil and natural gas reserves.

Production

The following table sets forth summary information regarding production by final product sold for the years ended December 31, 2009, 2008 and 2007:

Production Data	Year ended December 31,
	2009	2008	2007
Production -
Oil (Bbls)	5,775	3,377	11,514
Gas (Mcf)	12,279	28,559	33,394
Average Sales Price -
Oil (Bbls)	$56.00	$90.00	$64.00
Gas (Mcf)	$4.00	$6.00	$6.00
Average Production Costs per Mcf	$2.00	$3.29	$2.00

The table below sets forth summary information regarding production by final product for each country containing 15% or more of our proved reserves for the years ended December 31, 2009, 2008 and 2007.  All production in Canada is attributable to the Wordsworth Prospect in Saskatchewan and all production in the United States is attributable to our properties in Garvin and Murray counties in Oklahoma that comprise the 2006-3, 2007-1, 2009-1 and 2009-3 drilling programs referenced above in "Item 1, Business."

Production Data	Year Ended December 31
	2009		2008		2007
	USA	Canada	USA	Canada	USA	Canada
Production -
Oil (Bbls)	1,877	3,898	5,116	1,261	9,370	2,144
Gas (Mcf)	12,279	0	28,559	0	33,394	0
Average Sales Price -
Oil (Bbls)	$53.00	$58.00	$98.00	$88.00	$66.00	$61.00
Gas (Mcf)	$4.00	$0.00	$9.00	$0.00	$6.00	$0.00
Average Production Costs
Oil (Bbls)	$20.00	$14.00	$19.00	$40.00	$9.00	$9.00
Gas (Mcf)	$2.00	$0.00	$3.00	$0.00	$2.00	$0.00

Production costs may vary substantially among wells depending on the methods of recovery employed and other factors, but generally include severance taxes, administrative overhead, maintenance and repair, labor and utilities.  The reserves attributable to the Willows Gas Field in North Sacramento Valley, California were not material to our production in the United States and have not been itemized in the table above for this reason.

- 26 -

Productive Wells and Acreage

The following table shows our producing wells and acreage as of December 31, 2009:

	Producing Wells 3				Developed Acreage
	Oil		Gas
	Gross 1	Net 2	Gross 1	Net 2	Gross 1	Net 2
Saskatchewan, Canada (Wordsworth)	2	0.15	Nil	Nil	160	12
Garvin & Murray County, Oklahoma, USA  4	5	0.60	4	0.50	940	109
Willows Gas Filed, North Sacramento Valley, California, USA	0	0	0	0	300	18.75

1	A gross well or acre is a well or acre in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.
2	A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interest owned in gross wells or acres expressed as hole numbers and fractions thereof.
3	Productive wells are producing wells and wells capable of production.
4	Our properties in Garvin and Murray counties in Oklahoma consist of the 2006-3, 2007-1, 2009-1 and 2009-3 drilling programs referenced above in ‘Item 1, Business’.

Undeveloped Acreage

The following table set forth undeveloped acreage as of December 31, 2009:

	Undeveloped Acreage 1 as of December 31, 2009
	Gross	Net
Saskatchewan, Canada (Wordsworth)	4,800	24
Garvin & Murray County, Oklahoma, USA 2	1,660	301
King City, California, USA	10,000	4,000
Newton County, Texas, USA	243	97

1       2   "Undeveloped Acreage" includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial quantities of natural gas and oil regardless of whether the leasehold interest is classified as containing proved undeveloped reserves.   Our properties in Garvin and Murray counties in Oklahoma consist of the 2006-3, 2007-1, 2009-1 and 2009-3 drilling programs referenced above in ‘Item 1, Business’.

- 27 -

Drilling Activity

The following table sets forth information on our drilling activity for the last three years. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.

Geographical Area	Net Exploratory Wells Drilled		Net Development Wells Drilled
	Productive 1	Dry 2	Productive 1	Dry 2
Garvin, McClain & Murray Counties, Oklahoma 3
2009	0.45	0.20	0	0
2008	0.30	0.20	0	0
2007	0.50	0.40	0.20	0
Alberta, Canada (Strachan)
2009	0	0	0	0
2008	0	0	0	0
2007	0	0	0	0
Palmetto Point, Mississippi (Palmetto)
2009	0	0	0	0
2008	1.17	1.22	0	0
2007	1.17	1.22	0	0
Saskatchewan, Canada (Wordsworth)
2009	0.05	0	0.10	0
2008	0.075	0	0	0
2007	0.075	0.075	0	0
Willows Gas Field, North Sacramento Valley, California,
2009	0	0	0	0
2008	0.0625	0	0	0
2007	0	0	0	0
Totals	0.50	0	0.10	0

1	A productive well is an exploratory or development well that is not a dry well.  Although a well may be classified as productive upon completion, future changes in oil and gas prices, operating costs and production may result in the well becoming uneconomical.
2	A dry well (hole) is an exploratory or development well found to be incapable of producing either  oil or gas in sufficient quantities to justify completion as an oil or gas well.
3	Our properties in Garvin and Murray counties in Oklahoma consist of the 2006-3, 2007-1, 2009-1 and 2009-3 drilling programs and the drilling activity in McClain County, Oklahoma relates to the Owl Creek Prospect referenced above in "Item 1, Business.” which was sold in 2008.

Present Activities

A discussion of present activities on our property interests is included in the description of business disclosure set forth above.

- 28 -

Delivery Commitments

We are not obligated to provide a fixed and determined quantity of oil or gas in the future. During the last three fiscal years, we have not had, nor do we now have, any long-term supply or similar agreement with any government or governmental authority.

We are not obligated to provide a fixed and determinable quantity of oil or natural gas in the near future under existing contracts or agreements. Further, during the last three years we had no significant delivery commitments.

ITEM 3.    Legal Proceedings.

None.

ITEM 4.   Reserved.

- 29 -

PART II

ITEM 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market Prices

Our common stock is currently quoted on the OTCBB. The OTCBB is a network of security dealers who buy and sell stock.  The dealers are connected by a computer network that provides information on current "bids" and "asks", as well as volume information.  Our shares are quoted on the OTCBB under the symbol “DLTA.”  Prior to October 27, 2009, the effective date of a 1-for-5 reverse split of our common stock,  our shares were quoted on the OTCBB under the symbol “DOIG.”

The following table sets forth the range of high and low bid quotations for our common stock for each of the periods indicated as reported by the OTCBB.  These quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.  In October 2009, we effected a 1-for-5 reverse split of our common stock, effective October 27, 2009.  Accordingly, the prices of our common stock have been retroactively adjusted to reflect the reverse split.

Fiscal Year Ended December 31, 2009
Fiscal Quarter Ended:	High Bid	Low Bid
March 31, 2009	$0.25	$0.09
June 30, 2009	$0.225	$0.10
September 30, 2009	$0.19	$0.09
December 31, 2009	$0.19	$0
Fiscal Year Ended December 31, 2008
Fiscal Quarter Ended:	High Bid	Low Bid
March 31, 2008	$1.525	$0.75
June 30, 2008	$0.90	$0.445
September 30, 2008	$0.50	$0.225
December 31, 2008	$0.325	$0.05

Holders of Common Stock

As of March 22, 2010, we had approximately ninety-two (92) shareholders of record of our common stock.   Several other shareholders hold shares in street name.

Dividend Policy

To date, we have not declared or paid cash dividends on our shares of common stock.  The holders of our common stock will be entitled to non-cumulative dividends on the shares of common stock, when and as declared by our board of directors, in its discretion.  We intend to retain all future earnings, if any, for our business and do not anticipate paying cash dividends in the foreseeable future.

Any future determination to pay cash dividends will be at the discretion of our board of directors and will be dependent upon our financial condition, results of operations, capital requirements, general business conditions and such other factors as our board of directors may deem relevant.

- 30 -

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information about our compensation plans under which shares of common stock may be issued upon the exercise of options as of December 31, 2009.

Equity Compensation Plan as of December 31, 2009

Plan Category	A  Number of securities  to be issued upon  exercise of  outstanding options,  warrants and rights	B Weighted-average  exercise price of  outstanding options,  warrants and right	C Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (A))
Equity compensation plans approved by security holders
Equity compensation plans not approved by security holders	800,000	$0.12	249,902
Total	800,000	$0.12	249,902

On January 3, 2005, we adopted the 2005 Stock Incentive Plan, which provides for the grant of stock options to our employees, officers, directors and consultants. We registered the shares of our common stock issuable under the 2005 Stock Incentive Plan and reserved these shares for the granting of options and rights.

Recent Issuances of Unregistered Securities

There were no issuances of securities without registration under the Securities Act of 1933 during the reporting period which were not previously included in a Quarterly Report on Form 10-Q or Current Report on Form 8-K.

ITEM 6.Selected Financial Data.

Not applicable.

- 31 -

ITEM 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operation.

The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this annual report on Form 10-K.  This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position.  Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this annual report on Form 10-K.

For the Years Ended December 31, 2009 and 2008

Revenues

We generated total revenue of $510,917 for the year ended December 31, 2009, a decrease of approximately 73% from revenues of $1,927,539 for the year ended December 31, 2008.  During the year ended December 31, 2009, $352,841 of the revenue we generated was attributable to natural gas and oil sales and $158,076 was attributable to a gain on the partial disposition of our working interest in the Wordsworth Prospect during the three months ended June 30, 2009.  During the year ended December 31, 2008, $860,092 of the revenue was attributable to natural gas and oil sales and $1,067,447 was attributable to a gain on the disposition of our working interest in the Owl Creek prospect.

The decrease in total revenue for the year ended December 31, 2009, when compared to the year ended December 31, 2008, was attributable to a reduction in revenue from oil and gas sales of $507,251, which was caused by our inability to recognize revenue for the entire 2009 fiscal year from the Owl Creek Prospect resulting from the sale of our working interest in this property during the nine months ended September 30, 2008 and the reduction of commodity prices for natural gas and oil.

Costs and Expenses

We incurred costs and expenses in the amount of $2,871,082 for the year ended December 31, 2009, a 34% increase from costs and expenses of $2,141,979 for year ended December 31, 2008.

The increase in costs and expenses for the year ended December 31, 2009, when compared the year ended December 31, 2008, is primarily attributable to the following factors:

·   General and administrative costs for the year ended December 31, 2009 increased to$700,512 from $257,552 for the year ended December 31, 2008, an increaseof 172%.  The increase in general and administrative costs was caused by an increase in stock based compensation expense attributable to the issuances of stock options and shares of common stock to management.  Stock based compensation expense for the year ended December 31, 2009 was $199,745 as compared to $47,700 for the year ended December 31, 2008.  Further increases  in administrative costs was due to foreign exchange losses increasing to $88,440 (December 31, 2008: $(181,370)).

·   Legal and Professional fees for the year ended December 31, 2009 increased to $107,938 from $31,638 for the year ended December 31, 2008, an increase of 241%.  The increase in legal costs was attributable to the Company’s acquisition of The Stallion Group that closed in March 2009 and the preparation and filing of the S-4 registration statement.

·   Consulting fees for the year ended December 31, 2009 increased to $207,121 from $179,893 for the year ended December 31, 2008, an increase of 15%.  The increase in consulting fees was attributable to the addition of one executive from the acquisition of The Stallion Group.

·   Natural gas and oil operating costs for the year ended December 31, 2009 decreased to $120,022 from $222,269 for the year ended December 31, 2008, a decrease of 46%. The decrease in natural gas and oil operating costs is attributable to a decrease in the number of producing wells for the year ended December 31, 2009, as compared to the year ended December 31, 2008.

- 32 -

·   Depreciation and depletion expensefor the year ended December 31, 2009 decreased to $42,446 from $265,942 for the year ended December 31, 2008, a decrease of 84%. The decrease in depreciation and depletion expense is attributable to the disposal of Owl Creek and the partial disposal of the Wordsworth wells; this 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 year ended December 31, 2009 decreased to $1,255,561 from $1,393,687 for the year ended December 31, 2008, a decrease of 10%.  The decrease in impairment of natural gas and oil properties expense for the year ended December 31, 2009, as compared to the year ended December 31, 2008, is attributable to the impairment of our working interests in the Willow’s Gas Field resulting from our third party evaluation that the costs associated with these prospects are highly unlikely to be recovered.

Net Operating Loss

The net operating loss for the year ended December 31, 2009 was $2,360,165, compared to a net operating loss of $214,440 for the year ended December 31, 2008.

Other Income and Expense

We reported other net income of $9,062 for the year ended December 31, 2009, as compared to other income of $2,009 in the year ended December 31, 2008. Other expenses were attributable to interest expenses of $5,016 for a note payable which was paid in full during the year ended December 31, 2008.

Net Loss

Net loss for the year ended December 31, 2009 was $2,337,765, compared to a net loss of $215,826 for the year ended December 31, 2008. The increase in loss for the year ended December 31, 2009 was attributable to the loss on sale of natural gas and oil properties of $750,305 and the impairment of natural gas and oil properties of $1,255,56, compared to $1,393,687 for the year ended December 31, 2008, and a reduction in revenues for the year.

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.

- 33 -

Liquidity and Capital Resources

As of December 31, 2009, we had total current assets of $585,670 and total current liabilities in the amount of $39,409.  As a result, we had working capital of $546,261 as of December 31, 2009.

The revenue we currently generate from natural gas and oil sales does not exceed our operating expenses.  Our management anticipates that the current cash on hand may not be sufficient to fund our continued operations at the current level for the next twelve months.  As such, we will require additional financing to fund our operations and proposed drilling activities for the year ended December 31, 2010.  We will also require additional funds to expand our acquisition, exploration and production of natural oil and gas properties.  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.  We believe that debt financing will not be an alternative for funding as we have limited tangible assets to secure any debt financing.  We anticipate that additional funding will be in the form of equity financing from the sale of our common stock.  We intent to seek additional funding in the form of equity financing from the sale of our common stock, but cannot provide any assurance that we will be able to raise sufficient funding from the sale of our common stock to fund our operations and acquisition of new prospects.  If we are unable to obtain additional financing, we will experience liquidity problems and management expects that we will need to curtail operations, liquidate assets, seek additional capital on less favorable terms and/or pursue other remedial measures.  Any additional equity financing may involve substantial dilution to our then existing shareholders.

Cash Used in Operating Activities

Operating activities used $225,050 in cash for the year ending December 31, 2009, compared to $445,122 in cash generated from operating activities for the year ended December 31, 2008.  Our negative cash flow for the year ending December 31, 2009 was caused by an increase in operating expenses and a decrease in revenues from natural gas and oil.

Cash Used in Investing Activities

Cash flows used by investing activities for the year ending December 31, 2009 was $260,659, compared to $596,614 cash generated from investing activities for the year ended December 31, 2008.  Our negative cash flow for the year ending December 31, 2009 was primarily caused by investments in natural gas and oil working interests which were partially offset by sale proceeds of natural gas and oil working interests in the amount of $430,315.

Cash from Financing Activities

Cash flows used by financing activities for the year ending December 31, 2008 primarily consisted of $48,045 related to the cost of registration of shares under Form S-4, compared to $132,289 in cash used from financing activities for the year ended December 31, 2008.

The underlying drivers that resulted in material changes and the specific inflows and outflows of cash for the year ending December 31, 2009 are as follows:

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

·   Property acquisition costs; and

·   Sale of the Owl Creek Prospect.

Off-Balance Sheet Arrangements

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

- 34 -

Going Concern

As shown in the accompanying financial statements, we have incurred a net loss of $5,911,527 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.

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

Unproved properties consist of lease acquisition costs and costs on well currently being drilled on the properties.  The recorded costs of the investment in unproved properties are not amortized until proved reserves associated with the projects can be determined or until they are impaired.

Revenue Recognition

Revenue from sales of crude oil, natural gas and refined petroleum products are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customers. Title transfers for crude oil, natural gas and bulk refined products generally occur at pipeline custody points or when a tanker lifting has occurred.  Revenues from the production of oil and natural gas properties in which we share an undivided interest with other producers are recognized based on the actual volumes sold by us during the period.  Gas imbalances occur when our actual sales differ from its entitlement under existing working interests.  We record a liability for gas imbalances when we have sold more than our working interest of gas production and the estimated remaining reserves make it doubtful that the partners can recoup their share of production from the field.  At December 31, 2009 and 2008, we had no overproduced imbalances.

- 35 -

Recent Accounting Pronouncements

In September 2009, Accounting Standards Codification (“ASC”) became the source of authoritative GAAP recognized by the Financial Accounting Standards Board (“FASB”) for nongovernmental entities, except for certain FASB Statements not yet incorporated into ASC. Rules and interpretive releases of the SEC under federal securities laws are also sources of authoritative GAAP for registrants. The discussion below includes the applicable ASC reference.

In July 2009, the FASB proposed an update to ASC 470 to incorporate the previously ratified EITF No. 09-1, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance, into the ASC. This proposed standard would require share-lending arrangements in an entity’s own shares to be initially measured at fair value and treated as an issuance cost, excluded from basic and diluted earnings per share, and recognize a charge to earnings if it becomes probable the counterparty will default on the arrangement. This guidance was adopted as of January 1, 2010, as required, on a retrospective basis for all arrangements outstanding as of that date. The adoption of this update will have no impact on our consolidated results of operations of financial position.

The Company adopted ASC 810-10-65, Transition and Open Effective Date Information, which requires a parent with one or more less-than-wholly-owned subsidiaries to disclose, on the face of the consolidated financial statements, the amount of consolidated net income attributable to the parent and non-controlling interest. The Company adopted this guidance effective January 1, 2009.

           The Company adopted ASC 855, Subsequent Events, which requires disclosure of events occurring after the balance sheet date but before financial statements are issued or are available to be issued. The Company adopted this guidance effective April 1, 2009, with no impact on our consolidated results of operations or financial position.

ITEM 7A.Quantitative and Qualitative Disclosures About Market Risk.

Not applicable

ITEM 8.       Financial Statements and Supplementary Data.

The financial statements are listed in Part IV Item 15 of this Annual Report on Form 10-K and are incorporated by reference in this Item 8.

ITEM 9.       Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.

None.

- 36 -

ITEM 9A. Controls and Procedures.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934.  Based on their evaluation as of December 31, 2009, the end of the period covered by this Annual Report on Form 10-K, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective at a reasonable assurance level to ensure that the information required to be disclosed in reports filed or submitted under the Securities Exchange Act of 1934, including this Annual Report, were recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and was accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting.  Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:

·   Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company;

·   Provide reasonable assurance that the transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

·   Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

All internal control systems, no matter how well designed, have inherent limitations.  Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.  Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

In connection with the filing of our Annual Report on Form 10-K, our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2009.  In making this assessment, our management used the criteria set forth by Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework.  Based on our assessment using those criteria, management believes that, as of December 31, 2009, our internal control over financial reporting is effective based on those criteria.

This annual report does not include an attestation report of our Company's registered public accounting firm regarding internal control over financial reporting.  Management's report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management's report in this annual report.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal controls over financial reporting during the quarter ended December 31, 2009, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

- 37 -

ITEM 9B.       Other Information.

None.

- 38 -

PART III

ITEM 10.     Directors, Executive Officers and Corporate Governance.  

           The following information sets forth the names of our current directors and executive officers, their ages and their present positions.

Name of Nominee	Age	Position	Director Since
Christopher Paton-Gay	49	Chief Executive Officer, Principal Executive Officer, Director	2009
Douglas N. Bolen	44	President, Chairman	2004
Kulwant Sandher	48	Chief Financial Officer, Secretary, Principal Financial Officer, Principal Accounting Officer, Director	2007

Christopher Paton-Gary.  Mr. Paton-Gay has been our Chief Executive Officer and Director since April 6, 2009.  Mr. Paton-Gay has been Chief Executive Officer, a director and Chairman of The Stallion Group since July 19, 2006.  Mr. Paton-Gay has been active in the oil and gas business in Alberta, Canada and the United States over the past two decades. Over the past twenty years, he has founded and been chairman and president of two private oil and gas companies in addition to sitting on many corporate and public sector governance boards. He has also served as one of the founding Directors of the Explorers and Producers Association of Canada. Mr. Paton-Gay has also served as a director and officer of Turner Valley Oil & Gas Inc. since 2003.

            Mr. Paton-Gay brings to the Board a wealth of experience in the oil and gas industry and this experience, coupled with his prior service as a director to numerous private and public companies, is a valued asset to our Board.

Douglas N. Bolen.  Mr. Douglas Bolen was appointed as our Chief Executive Officer, President and director on April 15, 2004.  Mr. Bolen resigned as our Chief Executive Officer on April 6, 2009, but continues to serve as our President and Chairman of the board of directors.   Mr. Bolen received a Bachelor of Arts from the University of Regina, Saskatchewan in 1991 and his Bachelor of Laws from the University of Saskatchewan in 1995. Mr. Bolen is a member in good standing of the Law Society of Saskatchewan, the Regina Bar Association and the Canadian Bar Association. From 1995 to 1999, Mr. Bolen articled and practiced law at Balfour Moss, Barristers and Solicitors, a large Regina, Canada based law firm with a practice concentration in the area of Corporate Commercial law. From 1999 to the present, Mr. Bolen has been providing consulting services to small to medium sized US based businesses.

             Mr. Bolen brings to Board an extensive knowledge in the areas of contract law, oil and gas law and securities law both in Canada and the USA.  These attributes and experience enable Mr. Bolen to assist Board in its oversight of the Company’s oil and gas exploration activities and compliance aspects associated with being a public company.

              Kulwant Sandher.  Mr. Sandher is a Chartered Accountant in both England and Canadian jurisdictions. Mr. Sandher was appointed as President and Chief Financial Officer of Turner Valley Oil & Gas Inc. on August 2004 and continues in serve in these positions. From April 17, 2006 to October 3, 2008, Mr. Sandher acted as Chief Financial Officer and as a member of the board of directors of The Stallion Group. From May 2004 to March 2006, Mr. Sandher served as Chief Operating Officer and Chief Financial Officer of Marketrend Interactive Inc. Mr. Sandher acted as Chief Financial Officer of Serebra Learning Corporation, a public company on the TSX VE, from September 1999 to October 2002.

            Mr. Sandher’s experience in finance and administration, along with his network of contacts, is a valued asset to the Board as it continues to navigate through the regulatory framework in both the USA and Canada.

Our Directors are elected annually and hold office until the next annual meeting of our stockholders or until their successors are elected and qualified. Officers are elected annually and serve at the discretion of the Board of Directors. Board vacancies are filled by a majority vote of the Board.  There are no family relationship between any of our directors, director nominees and executive officers. 

- 39 -

Audit Committee

We do not have a separately-designated standing audit committee.  The entire Board of Directors performs the functions of an audit committee, but no written charter governs the actions of the Board when performing the functions of that would generally be performed by an audit committee.  The Board approves the selection of our independent accountants and meets and interacts with the independent accountants to discuss issues related to financial reporting.  In addition, the Board reviews the scope and results of the audit with the independent accountants, reviews with management and the independent accountants our annual operating results, considers the adequacy of our internal accounting procedures and considers other auditing and accounting matters including fees to be paid to the independent auditor and the performance of the independent auditor.

For the fiscal year ending December 31, 2009, the Board:

·   Reviewed and discussed the audited financial statements with management, and

·   Reviewed and discussed the written disclosures and the letter from our independent auditors on the matters relating to the auditor's independence.

Based upon the Board’s review and discussion of the matters above, the Board authorized inclusion of the audited financial statements for the year ended December 31, 2009 to be included in the Annual Report on Form 10-K and filed with the Securities and Exchange Commission.

The Board of Directors determined that Mr. Sandher qualifies as an “audit committee financial expert,” as defined under the rules and regulations of the Securities and Exchange Commission.

Section 16(a) Beneficial Ownership Reporting

Section 16(a) of the Securities Act of 1934, as amended, requires our executive officers and directors, and persons who own more than ten percent (10%) of our common stock, to file with the Securities and Exchange Commission reports of ownership of, and transactions in, our securities and to provide us with copies of those filings. To our knowledge, based solely on our review of the copies of such forms received by us, or written representations from certain reporting persons, we believe that during the year ended December 31, 2009, all filing requirements applicable to our officers, directors and greater than ten percent beneficial owners were complied with, with the following exceptions: Mr. Bolen failed to file a Form 4 disclosing one transaction in a timely fashion during fiscal year 2009 and Mr. Sandher failed to file two Form 4s disclosing a total of three transactions in a timely fashion during fiscal year 2009.

Code of Ethics and Conduct

Our Board of Directors has adopted a Code of Ethics and Conduct that is applicable to all of our employees, officers and directors. Our Code of Ethics and Conduct is intended to ensure that our employees act in accordance with the highest ethical standards. The Code of Ethics and Conduct is available on the Investor Relations page of our website at http://www.deltaoilandgas.com. and the Code of Ethics and Conduct was filed as an exhibit to our Annual Report on Form 10-KSB for the fiscal year ended December 31, 2003.

- 40 -

ITEM 11.     Executive Compensation.  

Summary Compensation Table

The following table presents information concerning the total compensation of our Chief Executive Officer, Chief Financial Officer and President during the last fiscal year (the “Named Executive Officers”) for services rendered to the Company in all capacities for the years ended December 31, 2009 and 2008:

Name (a)	Year	Salary ($)	Bonus ($)	Stock Awards ($) (1)	Option Awards ($) (1)	All Other Compensation ($)	Total ($)
Christopher Paton-Gay CEO	2009 2008	41,251 -	- -	- -	49,748 -	- -	90,999 -
Douglas N. Bolen  President	2009 2008	84,672 89,947	- -	15,000 26,500	35,999 -	- -	135,671 116,447
Kulwant Sandher CFO, Secretary, Treasurer	2009 2008	81,198 89,946	- -	12,000 21,200	35,999 -	- -	129,197 111,146

(1)     The amounts in the table reflect the grant date fair value of options and stock awards to the named executive officer in accordance with Accounting Standards Codification Topic 718.  The ultimate values of the options and stock awards to the executives generally will depend on the future market price of Delta’s common stock, which cannot be forecasted with reasonable accuracy. The actual value, if any, that an optionee will realize upon exercise of an option will depend on the excess of the market value of the common stock over the exercise price on the date the option is exercised.

Compensation Components.

                Base Salary. At this time, we compensate our executive officers by the indirect payment of salaries to companies controlled by our executive officers.

We did not directly compensate our executive officers during the fiscal years ended December 31, 2009 and 2008. Messrs. Paton-Gay, Sandher, and Bolen each received remuneration for services rendered during the fiscal years ended December 31, 2009 and 2008 indirectly through compensation paid to a company under their exclusive control.  Messrs. Paton-Gay, Bolen, and Kulwant are the sole shareholders, officers, and directors of CPG, LMM, and WMS, respectively, which are parties to the Consulting Agreements discussed below under "Consulting Agreements."

Bonuses. At this time, we do not compensate our executive officers by the payment of bonus compensation.

Stock Options. Stock option awards are determined by the Board of Directors based on numerous factors, some of which include responsibilities incumbent with the role of each executive to the Company and tenure with the Company.  We did not grant any stock options to our executive officers during 2009.

Other than the following, at no time during the last fiscal year was any outstanding option repriced or otherwise modified:  as a result of a reverse stock split, 500,000 options exercisable by Mr. Paton-Gay at $0.03 were automatically adjusted to 100,000 stock options exercisable at $0.15. There was no tandem feature, reload feature, or tax-reimbursement feature associated with any of the stock options we granted to our executive officers or otherwise.

Other. At this time, we have no profit sharing plan in place.

- 41 -

Consulting Agreements.

On March 8, 2010 (the “Effective Date”), we entered into an Amended and Restated Consulting Agreement with Warwick Management Services ("WMS"), an Amended and Restated Consulting Agreement with Last Mountain Management Ltd. ("LMM"), and an Amended and Restated Consulting Agreement with CPG Consulting Ltd. ("CPG") (collectively, the "Consulting Agreements").  Each of the Consulting Agreements are materially the same.  The Consulting Agreements supersede and replace all prior compensatory agreements, understandings and commitments that previously existed between the Company and members of its management.  Kulwant Sandher, our Chief Financial Officer and director, is the sole shareholder, officer, and director of WMS.  Douglas Bolen, our President and Chairman of the Board, is the sole shareholder, officer, and director of LMM.  Christopher Paton-Gay, our Chief Executive Officer and director, is the sole shareholder, officer, and director of CPG.

Pursuant to the terms of the Consulting Agreements, WMS was retained to serve as the our Chief Financial Officer, LMM was retained to serve as the our President, and CPG was retained to serve as the our Chief Executive Officer.  As compensation for such services, WMS, LMM, and CPG will each receive an annual fee of $90,000 Canadian Dollars per year plus applicable taxes, payable monthly in advance on the first of each calendar month. In addition, WMS, LMM, and CPG will each be entitled to receive 100,000 shares of our common stock on an annual basis, the standard benefits enjoyed by our other top executives, and reimbursement for reasonable travel, lodging, entertainment, promotion and other ordinary and necessary business expenses.  The Consulting Agreements are for an initial term of two years and will automatically be extended for an additional one-year period on each anniversary of the Effective Date (restoring the initial two-year term), unless terminated pursuant to the terms of the Consulting Agreements. 

If the Consulting Agreements are terminated by us for a reason other than Cause, Death, or Disability (as defined in the Consulting Agreements) or by the consultant for Good Reason, the consultant will receive:

·   Any earned but unpaid annual base compensation;

·   Any earned but unissued stock awards;

·   Any owed expense reimbursement payments owed to consultant for expenses incurred prior to termination;

·   Any earned but unpaid annual bonus payments relating to the prior calendar year; and

·   A lump-sum payment equal to 150% of consultant's annual base compensation, including all stock awards that would have been earned during the eighteen (18) months immediately following termination.

If the Consulting Agreements are terminated by us for Cause, by the consultant without Good Reason, or on account of the consultant's death or disability, our sole obligation will be to pay any accrued obligations.

"Cause" is defined as a termination by the Company based upon consultant's:

·   Persistent failure to perform duties consistent with a commercially reasonable standard of care (other than due to a physical or mental impairment or due to an action or inaction directed by the Company that would otherwise constitute Good Reason);

·   Willful neglect of duties (other than due to a physical or mental impairment or due to an action or inaction directed by the Company that would otherwise constitute Good Reason);

·   Conviction of, or pleading nolo contendere to, criminal or other illegal activities involving dishonesty;

·   Material breach of the Consulting Agreement; or

·   Failure to materially cooperate with or impeding an investigation authorized by the Board.

"Good Reason" is defined as a termination by the consultant based upon the occurrence of any of the following:

·   A material diminution in consultant's position or title, or the assignment of duties to consultant that are materially inconsistent with consultant's position or title;

·   A material diminution in consultant's annual base compensation or bonus opportunity;

·   Within six (6) months immediately preceding or within two (2) years immediately following a Change of Control: (1) a material adverse change in consultant's status, authority, or responsibility; (2) a requirement that consultant report to a corporate officer or consultant instead of directly to the Board; (3) a material diminution in the budget over which consultant has managing authority; or (4) a material change in the geographic location of consultant's principal place of service with the Company; or

·   A material breach by the Company of any of its obligations under the Consulting Agreement.

- 42 -

Payments, distributions, or benefits payable upon consultant's separation of service, and that would be classified as deferred compensation, may be delayed for six (6) months.  Also, any payments that would ordinarily constitute a "parachute payment" will be reduced to one dollar less than required to be considered "parachute payments" under Section 280G of the Internal Revenue Code.  In addition, in the event of any stock splits, reverse stock splits, stock dividends, or other changes in the Company's capital, the number of shares of common stock issued to the consultants under the Consulting Agreements will be adjusted proportionately.

The Consulting Agreements also provide consultants with the option to sell and have the Company purchase any shares of Company stock held by, or due to Consultant by the Company on the Date of Termination (as defined in the Consulting Agreements).  The closing for the sale and purchase shall take place thirty (30) days following the Date of Termination (the “Purchase Date”).  The purchase price shall be paid in cash and the purchase price per share shall be determined by the Board in good faith based upon the average closing price per share on the ten business days preceding the Purchase Date.

Outstanding Equity Awards at Fiscal Year-End

	Option Awards
Name (a)	Number of Securities Underlying Unexercised Options (#) Exercisable (b)	Number of Securities Underlying Unexercised Options (#) Unexercisable (c)	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)  (d)	Option Exercise Price ($) (e)	Option Expiration Date (f)
Christopher Paton-Gay CEO	200,000 100,000	-	-	$0.12 $0.15	12/01/2012 4/06/2012
Kulwant Sandher CFO, Secretary, Treasurer	200,000	-	-	$0.12	12/01/2012
Douglas N. Bolen President	200,000	-	-	$0.12	12/01/2012

Stock Option Plans

On January 3, 2005, our Board adopted the 2005 Stock Incentive Plan (the “Stock Incentive Plan”). The Stock Incentive Plan authorizes us to reserve shares for future grants under it, of which 249,902 shares remain available for issuance.

The Stock Incentive Plan authorizes us to grant (i) to the key employees incentive stock options to purchase shares of common stock and non-qualified stock options to purchase shares of common stock and restricted stock awards, and (ii) to non-employee directors and consultants’ non-qualified stock options and restricted stock. The Plan Administrator will administer the Plan by making recommendations to the board or determinations regarding the persons to whom options or restricted stock should be granted and the amount, terms, conditions and restrictions of the awards.

Incentive stock options granted under the Stock Incentive Plan must have an exercise price at least equal to 100% of the fair market value of the common stock as of the date of grant. Incentive stock options granted to any person who owns, immediately after the grant, stock possessing more than 10% of the combined voting power of all classes of our stock, or of any parent or subsidiary corporation, must have an exercise price at least equal to 110% of the fair market value of the common stock on the date of grant. Non-statutory stock options may have exercise prices as determined by the Plan Administrator.

- 43 -

The Plan Administrator is also authorized to grant restricted stock awards under the Stock Incentive Plan. A restricted stock award is a grant of shares of the common stock that is subject to restrictions on transferability, risk of forfeiture and other restrictions and that may be forfeited in the event of certain terminations of employment or service prior to the end of a restricted period specified by the Plan Administrator.

Compensation of Directors

Our executive officers who also serve as members of our board of directors do not receive any compensation for serving on the board of directors.  In 2009, our board of directors was comprised of Mr. Douglas Bolen, Mr. Christopher Paton-Gay, and Mr. Kulwant Sandher, all of whom also serve as executive officers.   The compensation arrangements for Messrs. Bolen, Paton-Gay, and Sandher are discussed under “Executive Compensation” in this annual report.

ITEM 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The following table sets forth, as of March 5, 2010, the number and percentage of outstanding shares of common stock beneficially owned by (a) each person known by us to beneficially own more than five percent of such stock, (b) each director of the Company, (c) each named officer of the Company, and (d) all our directors and executive officers as a group. We have no other class of capital stock outstanding.

Amount and Nature of Beneficial Ownership
Name and Address of Beneficial Owner(1)	Shares Owned (2)		Options Exercisable Within 60 Days (3)		Percent of Class
Directors and Executive Officers
Christopher Paton-Gay		143,934		300,000		3.20	%
Douglas N. Bolen		386,000		200,000		4.26	%
Kulwant Sandher		234,176		200,000		3.16	%
All current directors and executive officers as a group (six persons)		864,110		700,000		10.97	%
More Than 5% Beneficial Owners
Gerald W. Williams		1,999,998		-		14.75	%
Ronald A. Zlatniski 4206 Cypress Grove Lane Greensboro, NC 27455		742,000		-		5.47	%

* Represents less than 1% of the class.

(1)      Unless otherwise provided, the address of each person is c/o Suite 604 - 700 West Pender Street, Vancouver, British Columbia,

           Canada V6C 1G8.

(2)      Except as otherwise indicated, all shares shown in the table are owned with sole voting and investment power.

(3)      This column represents shares not included in “Shares Owned” that may be acquired by the exercise of options within 60 days of

           March 5, 2010.

                The above beneficial ownership information is based on information furnished by the specified persons and is determined in accordance with Rule 13d-3 under the Exchange Act, as required for purposes of this Annual Report; accordingly, it includes shares of our common stock that are issuable upon the exercise of stock options exercisable within 60 days of March 5, 2010. Such information is not necessarily to be construed as an admission of beneficial ownership for other purposes.

- 44 -

ITEM 13.    Certain Relationships and Related Transactions, and Director Independence.

Except as set forth below, none of our directors or executive officers, nor any proposed nominee for election as a director, nor any person who beneficially owns, directly or indirectly, shares carrying more than 5% of the voting rights attached to all of our outstanding shares, nor any members of the immediate family (including spouse, parents, children, siblings, and in-laws) of any of the foregoing persons has any material interest, direct or indirect, in any transaction since the beginning of our last fiscal year on January 1, 2009 or in any presently proposed transaction which, in either case, has or will materially affect us.

On March 8, 2010, we entered into an Amended and Restated Consulting Agreement with Warwick Management Services ("WMS"), an Amended and Restated Consulting Agreement with Last Mountain Management Ltd. ("LMM"), and an Amended and Restated Consulting Agreement with CPG Consulting Ltd. ("CPG") (collectively, the "Consulting Agreements").  Each of the Consulting Agreements are materially the same.  The Consulting Agreements supersede and replace all prior compensatory agreements, understandings and commitments that previously existed between the Company and members of its management.  Kulwant Sandher, our Chief Financial Officer and director, is the sole shareholder, officer, and director of WMS.  Douglas Bolen, our President and Chairman of the Board, is the sole shareholder, officer, and director of LMM.  Christopher Paton-Gay, our Chief Executive Officer and director, is the sole shareholder, officer, and director of CPG.  The Consulting Agreements are discussed in greater detail above in "Item 11, Executive Compensation."

ITEM 14.    Principal Accounting Fees and Services.

The following table is a summary of the fees billed to us by STS Partners LLP, Chartered Accountants for professional services for the fiscal years ended December 31, 2009 and December 31, 2008:

	Fiscal 2009 Fees		Fiscal 2008 Fees
Fee Category
Audit Fees	$	34,000	$	33,800
Audit-Related Fees		-		-
Tax Fees		-		-
All Other Fees		-		-
Total Fees	$	34,000	$	33,800

Audit Fees. Consists of fees billed for professional services rendered for the audit of our consolidated financial statements and review of the interim consolidated financial statements included in quarterly reports and services that are normally provided by our independent registered public accounting firms in connection with statutory and regulatory filings or engagements.

Audit-Related Fees. Consists of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of our consolidated financial statements and are not reported under “Audit Fees.” These services include employee benefit plan audits, accounting consultations in connection with acquisitions, attest services that are not required by statute or regulation, and consultations concerning financial accounting and reporting standards.

Tax Fees. Consists of fees billed for professional services for tax compliance, tax advice and tax planning. These services include assistance regarding federal, state and international tax compliance, tax audit defense, customs and duties, mergers and acquisitions, and international tax planning.

All Other Fees. Consists of fees for products and services other than the services reported above. In fiscal 2009 and 2008, these services included administrative services.

Our practice is to consider and approve in advance all proposed audit and non-audit services to be provided by our independent registered public accounting firm.

- 45 -

The audit report of STS Partners LLP, Chartered Accountants on the financial statements of the Company for the year ended December 31, 2009 did not contain an adverse opinion or disclaimer of opinion, and was not qualified or modified as to uncertainty, audit scope or accounting principles, except that the audit reports on the financial statements of the Company for the fiscal years ended December 31, 2009 and December 31, 2008 contained an uncertainty about the Company’s ability to continue as a going concern.

During our fiscal years ended December 31, 2009 and 2008, there were no disagreements with STS Partners LLP, Chartered Accountants on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedures, which disagreements if not resolved to STS Partners LLP, Chartered Accountants’ satisfaction would have caused it to make reference to the subject matter of such disagreements in connection with its reports on the financial statements for such periods.

During our fiscal years ended December 31, 2009 and 2008, there were no reportable events (as described in Item 304(a)(1)(v) of Regulation S-K).

PART IV

ITEM 15.    Exhibits, Financial Statement Schedules.

(a)(1)

Index to Financial Statements		Page (s)
Report of Independent Registered Public Accounting Firm		F-1
Financial Statements:
	Consolidated Balance Sheets as of December 31, 2009 and 2008	F-2
	Consolidated Statements of Operations – Years Ended December 31, 2009 and December 31, 2008	F-3
	Consolidated Statement of Stockholders’ Equity (Deficiency) and from inception January 9, 2001 to December 31, 2009	F-4
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2009 and December 31, 2008	F-5
Notes to Consolidated Financial Statements		F-6

- 46 -

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Delta Oil & Gas, Inc.

(A Development Stage Company)

We have audited the accompanying consolidated balance sheets of Delta Oil & Gas, Inc. (the “Company”) as at December 31, 2009 and 2008, the related consolidated statements of operations, comprehensive loss, changes in stockholders’ equity and cash flows for the years then ended.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audits in accordance with Standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting.  Accordingly, we express no such opinion.

An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Delta Oil & Gas, Inc. as at December 31, 2009 and 2008, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern.  As discussed in Note 1(c) to the consolidated financial statements, the Company has suffered recurring losses from operations since inception.  These factors raise substantial doubt about the Company’s ability to continue as a going concern.  Management’s plans in regard to these matters are also described in Note 1(c).  The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ STS PARTNERSHIP  LLP                             

STS PARTNERS LLP

CHARTERED ACCOUNTANTS

Vancouver, British Columbia, Canada

April 12, 2010

F - 1

DELTA OIL & GAS, INC.
Consolidated Balance Sheets
(Stated in U.S. Dollars)
	December 31,			December 31,
	2009			2008
ASSETS
Current
Cash and cash equivalents	$	446,808		$	980,562
Accounts receivable		70,496			65,614
Franchise tax prepaid		1,004			-
Prepaid expenses		17,464			11,193
Advancement for oil and gas exploration costs		49,898			-
		585,670			1,057,369
Natural Gas And Oil Properties
Proved property		380,483			892,096
Unproved property		484,887			630,376
		865,370			1,522,472
Property, Plant and Equipment (net)		3,499			172
TOTAL ASSETS	$	1,454,539		$	2,580,013
LIABILITIES AND STOCKHOLDERS' EQUITY
LIABILITIES
Current
Accounts payable and accrued liabilities	$	37,882		$	26,553
Due to related party		1,527			-
		39,409			26,553
Long Term
Asset retirement obligation		21,487			23,604
TOTAL LIABILITIES		60,896			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		7,115,308			6,088,272
Accumulative Other Comprehensive loss		94,418			5,978
Accumulated Deficit		(5,911,527	)		(3,573,762	)
		1,311,756			2,529,856
Noncontrolling Interest		81,887			-
TOTAL STOCKHOLDERS' EQUITY		1,393,643			2,529,856
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,454,539		$	2,580,013
The accompanying notes are an integral part of these consolidated financial statements

F - 2

DELTA OIL & GAS, INC.
Consolidated Statements Of Operations
(Stated in U.S. Dollars)
	YEAR ENDED
	DECEMBER 31,
	2009			2008
Revenue
Natural gas and oil sales	$	352,841		$	860,092
Gain on sale of natural gas and oil properties		158,076			1,067,447
		510,917			1,927,539
Costs And Expenses
Natural gas and oil operating costs		120,022			222,269
General and administrative		700,512			257,552
Accretion		2,236			2,529
Depreciation and depletion		42,446			265,942
Impairment of natural gas and oil properties		1,255,561			1,393,687
Loss on sale of natural gas and oil properties		750,305			-
		2,871,082			2,141,979
Net Operating Loss		(2,360,165	)		(214,440	)
Other Income And (Expense)
Interest income		9,062			7,025
Interest expense		-			(5,016	)
		9,062			2,009
Loss Before Income Taxes		(2,351,103	)		(212,431	)
Income taxes		5,406			3,395
Net Loss		(2,356,509	)		(215,826	)
Less: Net loss attributable to the noncontrolling interest		18,744			-
Net Loss Attributable to Delta Oil & Gas, Inc.	$	(2,337,765	)	$	(215,826	)
Basic And Diluted Loss Per Common Share	$	(0.19	)	$	(0.02	)
Weighted Average Number Of
Common Shares Outstanding		12,576,983			9,368,102
Consolidated Statement of Comprehensive Loss
Comprehensive Loss
Net Loss	$	(2,356,509	)	$	(215,826	)
Other Comprehensive Income (Loss)
Foreign Currency Translation		88,440			(181,370	)
Comprehensive Loss	$	(2,268,069	)	$	(397,196	)
The accompanying notes are an integral part of these consolidated financial statements

F - 3

DELTA OIL & GAS INC.
Consolidated Statements Of Changes In Stockholders' Equity
Period From Inception, January 9, 2001, to December 31, 2009
(Stated in U.S. Dollars)
														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,		496,797		497		2,483,228			(160,000	)		-			-			-			-			2,323,725
net of share issuance cost
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		100,000		100		459,900			-			-			-			-			-			460,000
part of his compensation package at $0.92
Shares issued to Investor Relations		12,000		12		40,788			-			-			-			-			-			40,800
Services, Inc. as part of the agreement
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		180,000		180		47,520			-			-			-			-			-			47,700
part of their compensation package at $0.053
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		280,000		280		41,720			-			-			-			-			-			42,000
part of his compensation package at $0.03
Options issued to IR consultant		-		-		35,998			-			-			-			-			-			35,998
Options issued to CEO, CFO & director		-		-		121,747			-			-			-			-			-			121,747
Comprehensive Income/(Loss):
Cumulative translation adjustment		-		-		-			-			-			-			88,440			-			88,440
Net loss for the year		-		-		-			-			-			(2,337,765	)		-			(18,744	)		(2,356,509	)
Comprehensive loss																								(2,268,069	)
Balance, December 31, 2009		13,557,107	$	13,557	$	7,115,308		$	-		$	-		$	(5,911,527	)	$	94,418		$	81,887		$	1,393,643
The accompanying notes are an integral part of these consolidated financial statements

F - 4

DELTA OIL & GAS, INC.
Consolidated Statements Of Cash Flows
(Stated in U.S. Dollars)
	YEARS ENDED
	DECEMBER 31,
	2009			2008
Cash Flows From Operating Activities:
Net loss for the year	$	(2,337,765	)	$	(215,826	)
Adjustments to reconcile net loss to net cash
used in operating activities:
Accretion		2,236			2,529
Depreciation and depletion		42,446			265,942
Impairment of natural gas and oil properties		1,255,561			1,393,687
Loss on sale of natural gas and oil properties		750,305			-
Stock-based compensation expense		157,745			-
Shares issued to President & CEO for servicess rendered		30,000			26,500
Shares issued to CFO for services rendered		12,000			21,200
Shares issued to Investor Relations Services Inc for services rendered		-			-
Realized foreign exchange loss		88,440			(181,370	)
Net loss attributable to the noncontrolling interest		(18,744	)		-
Gain on sale of natural gas and oil properties		(158,075	)		(1,067,447	)
Changes in operating assets and liabilities:
GIC		-			236,112
Accounts receivable		(4,882	)		88,376
Accounts payable and accrued liabilities		11,329			(139,664	)
Due to related party		1,527			-
Franchise tax prepaid		(1,004	)		6,912
Prepaid expenses		(6,271	)		8,171
Advancement for oil and gas exploration costs		(49,898	)		-
Net Cash Generated/(Used) In Operating Activities		(225,050	)		445,122
Cash Flows From Investing Activities:
Purchase of other equipment		(5,805	)		-
Sale proceeds of natural gas and oil working interests		430,315			1,309,826
Investment in natural gas and oil working interests		(685,169	)		(713,212	)
Net Cash Generated /(Used) In Investing Activities		(260,659	)		596,614
Cash Flows From Financing Activities:
Registration of shares under Form S-4		-			(132,289	)
Share issue expenses		(48,045	)		-
Proceeds from issuance of common stock		-			-
Net Cash Provided/(Used) By Financing Activities		(48,045	)		(132,289	)
Net Increase/(Decrease) In Cash And Cash Equivalents		(533,754	)		909,447
Cash And Cash Equivalents At Beginning Of Period
(Excess Of Deposits Over Checks Issued)		980,562			71,115
Cash And Cash Equivalents at end of year	$	446,808		$	980,562
Supplemental Disclosures Of Non-Cash, Investing and Financing Activities
200,000 shares issued to the President & CEO as part of their	$	30,000		$	26,500
compensation package
80,000 shares issued to the CFO for services rendered	$	12,000		$	21,200
3,909,005 shares issued for the acquisition of Oil and Gas properties	$	879,526		$	-
Supplemental Disclosures
Income taxes paid	$	5,406		$	3,395
The accompanying notes are an integral part of these consolidated financial statements

F - 5

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

1.           OPERATIONS

a)   Organization

Delta Oil & Gas, Inc. (“the Company”) was incorporated as a Colorado corporation on January 9, 2001.

The Company is an independent natural gas and oil company engaged in the exploration, development and acquisition of natural gas and oil properties in the United States and Canada.  The Company’s entry into the natural gas and oil business began on February 8, 2001.  Prior to the current fiscal year, the Company was designated as a development stage enterprise.

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

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

b)   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:

	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

F - 6

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

1.            OPERATIONS (continued)

      c)       Business acquisition

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 $76,453 of Stallion was included in the consolidated financial statements as of December 31, 2009.

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

Cash and cash Equivalents	$	565
Accounts receivable		13,712
Prepaid Expenses		3,001
Natural gas and oil properties		194,670
Capital Assets, Net		4,190
Total Assets	$	216,138
Accounts Payable	$	(144,144	)
Asset Retirement Obligatoin		(15,464	)
Total Net Assets	$	56,430
Total Net Assets purchased - 80-31%	$	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 $5,911,527 since inception.  To achieve profitable operations, the Company requires additional capital for obtaining producing oil and gas properties through either the purchase of producing wells or successful exploration activity.  Management believes that sufficient funding will be available to meet its business objectives including anticipated cash needs for working capital and is currently evaluating several financing options.  However, there can be no assurance that the Company will be able to obtain sufficient funds to continue the development of its properties and, if successful, to commence the sale of its projects under development.  As a result of the foregoing, there exists substantial doubt the Company’s ability to continue as a going concern.  These consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

2.           SIGNIFICANT ACCOUNTING POLICIES

a)   Basis of Consolidation

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

F - 7

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

1.            OPERATIONS (continued)

      c)      Business acquisition

2.           SIGNIFICANT ACCOUNTING POLICIES (continued)

b)     Use of Estimates

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

c)    Natural Gas and Oil Properties

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

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

d)    Asset Retirement Obligations

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

e)   Oil and Gas Joint Ventures

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

F - 8

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

2. SIGNIFICANT ACCOUNTING POLICIES (continued)

f)   Revenue Recognition

Revenue from sales of crude oil, natural gas and refined petroleum products are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customers.  Title transfers for crude oil, natural gas and bulk refined products generally occur at pipeline custody points or when a tanker lifting has occurred.  Revenues from the production of oil and natural gas properties in which the Company shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period.  Gas imbalances occur when the Company’s actual sales differ from its entitlement under existing working interests.  The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that the partners can recoup their share of production from the field. As at December 31, 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 $95,147, the amount that may be subject to credit risk for the year ended December 31, 2009 is $351,661.

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.

i)   Environmental Protection and Reclamation Costs

The operations of the Company have been, and may be in the future be affected from time to time in varying degrees by changes in environmental regulations, including those for future removal and site restorations costs.  Both the likelihood of new regulations and their overall effect upon the Company may vary from region to region and are not predictable.

The Company’s policy is to meet or, if possible, surpass standards set by relevant legislation, by application of technically proven and economically feasible measures.  Environmental expenditures that relate to ongoing environmental and reclamation programs will be charged against statements of operations as incurred or capitalized and amortized depending upon their future economic benefits.  The Company does not currently anticipate any material capital expenditures for environmental control facilities because all property holdings are at early stages of exploration.  Therefore, estimated future removal and site restoration costs are presently considered minimal.

F - 9

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

2.   SIGNIFICANT ACCOUNTING POLICIES (continued)

j)   Foreign Currency Translation

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

k)   Other Equipment

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

l)   Impairment of Long-Lived Assets

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

m)   Loss Per Share

In February 1997, 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.

n)   Income Taxes

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

o)   Financial Instruments

The FASB Accounting Standards CodificationFinancial Instruments requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The standard establishes a fair value hierarchy based on the level of independent, objective evidence surrounding the inputs used to measure fair value. A financial instrument’s categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The standard prioritizes the inputs into three levels that may be used to measure fair value:

Level 1

Level 1 applies to assets or liabilities for which there are quoted prices in active markets for identical assets or liabilities.

F - 10

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

2. SIGNIFICANT ACCOUNTING POLICIES (continued)

Level 2

Level 2 applies to assets or liabilities for which there are inputs other than quoted prices that are observable for the asset or liability such as quoted prices for similar assets or liabilities in active markets; quoted prices for identical assets or liabilities in markets with insufficient volume or infrequent transactions (less active markets); or model-derived valuations in which significant inputs are observable or can be derived principally from, or corroborated by, observable market data.

Level 3

Level 3 applies to assets or liabilities for which there are unobservable inputs to the valuation methodology that are significant to the measurement of the fair value of the assets or liabilities.

The Company’s financial instruments consist of cash and cash equivalent, accounts receivable, franchise tax prepaid, 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.

p)     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.

q)     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.

3. RECENT ACCOUNTING PRONOUNCEMENTS

In September 2009, Accounting Standards Codification (“ASC”) became the source of authoritative GAAP recognized by the Financial Accounting Standards Board (“FASB”) for nongovernmental entities, except for certain FASB Statements not yet incorporated into ASC. Rules and interpretive releases of the SEC under federal securities laws are also sources of authoritative GAAP for registrants. The discussion below includes the applicable ASC reference.

In July 2009, the FASB proposed an update to ASC 470 to incorporate the previously ratified EITF No. 09-1, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance, into the

F - 11

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

3. RECENT ACCOUNTING PRONOUNCEMENTS (continued)

ASC. This proposed standard would require share-lending arrangements in an entity’s own shares to be initially measured at fair value and treated as an issuance cost, excluded from basic and diluted earnings per share, and recognize a charge to earnings if it becomes probable the counterparty will default on the arrangement. This guidance was adopted as of January 1, 2010, as required, on a retrospective basis for all arrangements outstanding as of that date. The adoption of this update will have no impact on our consolidated results of operations of financial position.

The Company adopted ASC 810-10-65, Transition and Open Effective Date Information, which requires a parent with one or more less-than-wholly-owned subsidiaries to disclose, on the face of the consolidated financial statements, the amount of consolidated net income attributable to the parent and non-controlling interest. The Company adopted this guidance effective January 1, 2009.

 The Company adopted ASC 855, Subsequent Events, which requires disclosure of events occurring after the balance sheet date but before financial statements are issued or are available to be issued. The Company adopted this guidance effective April 1, 2009, with no impact on our consolidated results of operations or financial position.

Statement 168 has not been incorporated into ASC and is effective for interim and annual periods ending after September 15, 2009. We adopted this guidance effective July 1, 2009, with no impact on our consolidated results of operations or financial position.

4.             NATURAL GAS AND OIL PROPERTIES

a)   Proved Properties

Properties	December 31, 2008		Additions		Disposals			Transfer from unproved properties		Depletion for the period			Impairment			December 31, 2009
USA properties	$	866,781		1,183,075		(808,020	)		353,338		(29,626	)		(1,247,691	)	$	317,857
Canada properties		25,315		19,865		(8,760	)		44,532		(10,456	)		(7,870	)		62,626
Total	$	892,096		1,202,940		(816,780	)		397,870		(40,082	)		(1,255,561	)	$	380,483

      a)       Proved Properties – Descriptions

Properties in U.S.A.

i.   Oklahoma, USA

2006-3 Drilling Program

In April 2007, the Company entered into the 2006-3 Drilling Program for a buy-in cost of $113,700 which will provide 12.5% Before Casing Point (“BCP”) working interest and After Casing Point (“ACP”) working interest of 10%.  In September 2007, Wolf#1-7 was abandoned. Its costs 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 and abandoned on February 7, 2008.  Its cost amounted to $127,421 was moved to the proven cost pool for depletion.  Plaster #1-11 and Dale #1-15

F - 12

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

4.             NATURAL GAS AND OIL PROPERTIES (continued)

a)    Proved Properties – Descriptions

Properties in U.S.A.

started producing in January and February 2008, respectively, total cost of $205,064 was moved to the proven cost pool.  Loretta #1-22 was plugged and abandoned in 2009, its cost amounted to $139,334 was moved to the proved cost pool.

2007-1 Drilling Program

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

In the 2007-1 Drilling Program, Pollack #1-35 was plugged and abandoned on January 19, 2008.  Its cost amounted to $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.  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.

i.     Oklahoma, USA (continued)

2009-1 Drilling Program

On July 27, 2009, the Company entered into the 2009-1 Drilling Program for five wells which will provide 5.714286% Before Casing Point (“BCP”) working interest and 5.00% After Casing Point (“ACP”) working interest.  The Company’s buy-in costs for each well is $2,625.  During the three months to September 2009, the Company had paid buy-in, estimated drilling and completion costs for three wells, Saddle #1-28, Saddle #2-28 and Saddle #3-28.  Saddle #1-28 and Saddle #2-28 started producing in November 2009 and Saddle #3-28 in December 2009, the total cost amounted to $72,175 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.

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.

F - 13

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

4.             NATURAL GAS AND OIL PROPERTIES (continued)

a)    Proved Properties – Descriptions

Properties in U.S.A.

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

        iii.    Mississippi II, Mississippi, USA

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.

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%

F - 14

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

4.         NATURAL GAS AND OIL PROPERTIES (continued)

a)    Proved Properties - Descriptions

Properties in Canada

working interest.  As of December 31, 2009, Stallion has expended $195,971 for the costs of Wilson Creek #1-27 and $60,000 for 3D seismic in the prospect area.  Wilson Creek #1-27 started producing gas from April 2008.  The well has been temporarily shut in pending an increase in natural gas commodity prices.

vi.   Wordsworth Prospect, Saskatchewan, Canada

On April 10, 2007, the Company entered into an agreement (the “Agreement”) with Petrex Energy Ltd., for a participation and Farm-out 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.  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.

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

As at December 31, 2009, the Company had advanced $286,830 as its share of the costs in this Agreement.

vii.   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 participated 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 had 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 proven cost pool for depletion.

b)   Unproved Properties

Properties	December 31, 2008		Addition		Disposals			Transfer to proved properties			December 31, 2009
USA properties	$	430,311	$	410,240	$	(154,671	)	$	(353,339	)	$	332,541
Canada properties		200,065		60,779		(63,966	)		(44,532	)		152,346
Total	$	630,376	$	471,019		(218,637	)	$	(397,871	)	$	484,887

F - 15

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

4.         NATURAL GAS AND OIL PROPERTIES (continued)

        b) Unproved Proved Properties - Descriptions

Properties in U.S.A.

c) Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2009, by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The majority of the evaluation activities are expected to be completed within five to ten years.

	Total		2009			2008		2007		2006  and Prior
Property acquisition costs and Transfer to Proved Property Pool		37,775		17,900			-		19,875		-
Exploration and development		447,112		(163,389	)		-		-		610,501
Capitalized interest		-		-			-		-		-
Total		484,887		(145,489	)		-		19,875		610,501

i.     Mississippi II, Mississippi, USA

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

i.     Mississippi II, Mississippi, USA

leases and drilling and completion costs to earn a net 8% share of all production zones to the base of the Frio formation and 7.5% of all production to the base of the Wilcox formation.

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

       ii.      King City, California, USA

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

iii.     Texas Prospect, Texas, USA

On July 15, 2009, the Company successfully obtained the leases on certain lands in Texas, USA.  These leases will provide the Company with the ability to drill up to 3 exploration wells.  In December 2009, the Company desired to convey a sixty (60%) percent interest in the leases to Hillcrest Resources Ltd and received $111,424 in December 2009.  As at  December 31, 2009, the costs of the leases were $79,747.

F - 16

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

4.           NATURAL GAS AND OIL PROPERTIES (Continued)

b)   Unproved Proved Properties - Descriptions

Properties in U.S.A.

iv.   2009-3 Drilling Program - 4 Wells

On August 7, 2009, the Company entered into an agreement with Ranken Energy to participate in a four well drilling program in Garvin County, Oklahoma (the “2009-3 Drilling Program”).  We purchased a 6.25% working interest before casing point and 5.0% working interest after casing point in the 2009-3 Drilling Program for $37,775.  In addition to the total buy-in cost, we will be responsible for our proportionate share of the drilling and completion costs.  During the year ended December 31, 2009, the Company paid additional drilling costs in the amount of $115,017.

Properties in Canada

  v.     Wordsworth Prospect, Saskatchewan, Canada

In April 2007, the Company entered into an agreement (the “Agreement”) with Petrex Energy Ltd., for a participation and Farm-out 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 December 31, 2009, the Company had expended $152,347 of the well 3B9-23/3A11 and 2 HZ 3B9 LEG.

5.           NATURAL GAS AND OIL EXPLORATION RISK

          a)   Exploration Risk

The Company’s future financial condition and results of operations will depend upon prices received for its natural gas and oil production and the cost of finding, acquiring, developing and producing reserves.  Substantially all of its production is sold under various terms and arrangements at prevailing market prices.  Prices for natural gas and oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond its control.  Other factors that have a direct bearing on the Company’s

prospects are uncertainties inherent in estimating natural gas and oil reserves and future hydrocarbon production and cash flows, particularly with respect to wells that have not been fully tested and with wells

having limited production histories; access to additional capital; changes in the price of natural gas and oil; availability and cost of services and equipment; and the presence of competitors with greater financial resources and capacity.

b)    Distribution Risk

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

c)   Credit Risk

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

F - 17

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

5.          NATURAL GAS AND OIL EXPLORATION RISK (continued)

d)   Foreign Operations Risk

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

6.             INCOME TAXES PAYABLE

Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently due plus deferred taxes.  Deferred taxes are provided on a liability method whereby deferred tax assets are recognized for deductible temporary differences and operating loss, tax credit carry-forwards, and for taxable temporary differences.  Temporary differences are the differences between the reported amounts of assets and liabilities and their tax bases.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax will not be realized.  Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

Income tax expense for the years ended December 31, 2009 and 2008 consists of the following:

	December 31		December 31
	2009		2008
State income taxes  2008 (2007)	$	5,406	$	3,395
Net income tax expense	$	5,406	$	3,395

The effective income tax rate for years ended December 31, 2009 and December 31, 2008 differs from the U.S. Federal statutory income tax rate due to the following:

	December 31			December 31
US	2009			2008
Federal statutory income tax rate		(34.00	%)		(34.00	%)
State income taxes (average), net of federal benefit		(6.12	%)		(6.12	%)
Valuation allowance		37.77	%		37.77	%
Net income tax provision (benefit)		-			-

Canada
Federal statutory income tax rate	(15.00	%)	(15.00	%)
Provincial income taxes	(12.00	%)	(12.50	%)
Valuation allowance	27.00	%	27.50	%
Net income tax provision (benefit)	-		-

F - 18

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

6.             INCOME TAXES PAYABLE (continued)

The current loss components of the deferred tax assets/(liabilities) as of December 31, 2009 and 2008 are as follows:

	December 31			December 31
	2009			2008
US operating loss/(profit)	$	1,335,796		$	(587,883	)
Canadian operating loss		795,059			168,961
	$	2,130,855		$	(418,922	)
Tax at effective rate		656,516			(123,998	)
Change in estimate due to Canadian resource pool		(140,846	)		-
Change in estimate due to resource properties		(211,821	)		59,951
Change in estimate due to acquisition of Stallion		846,317			-
Allowance for current rate change		112,291			(256,948	)
(Increase) decrease in valuation allowance		(1,262,457	)		320,995
Deferred tax asset	$	-		$	-
Effective income tax rate		30.81	%		29.59	%

The Company has $6,362,891 (2008: $1,341,296) net operating loss carry forward and will begin to expire on between, 2015 and 2028.

The cumulative components of the deferred tax assets as of December 31, 2009 and as of December 31, 2008 are as follows:

	December 31			December 31
	2009			2008
US operating loss carry forward	$	4,518,268		$	435,638
Canadian operating loss carry forward		1,844,623			905,658
Resources pools Canada - available for expense   Resource assets capitalized		2,249,167 873,189			2,706,303 1,560,681
	$	9,485,247		$	5,608,280
Effective income tax rate		30.81	%		29.59	%
Deferred tax asset		2,922,467			1,660,010
Valuation allowance		(2,922,467	)		(1,660,010	)
	$	-		$	-

F - 19

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

6.            INCOME TAXES PAYABLE (continued)

The 2008 deferred income tax asset and valuation allowance has been restated to correct the effective tax note, operating loss and natural oil and gas properties previously over/understated.

	Restated			Prior
Operating loss carry forward	$	4,047,599		$	3,457,724
Natural Gas and Oil properties		1,560,681			1,600,527
		5,608,280			5,068,251
Effective income tax rate		29.59	%		34.00	%
Deferred tax asset		1,660,010			1,723,205
Valuation Allowance		(1,660,010	)		(1,723,205
Deferred tax asset	$	-		$	-

7.             ASSET RETIREMENT OBLIGATIONS

The Company follows the Accounting for Asset Retirement Obligations Topic of the FASB Accounting standards Codification.  This addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.  It also requires recognition of the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred.  As of December 31, 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 Company amortizes the amount added to oil and gas properties and recognizes accretion expense in connection with the discounted liability over the remaining useful lives of the respective wells.

The information below reflects the change in the asset retirement obligations during the years ended December 31, 2009 and 2008:

	December 31, 2009			December 31, 2008
Balance, beginning of year	$	23,604		$	111,803
Liabilities assumed		6,138			8,898
Revisions		(10,491	)		(99,626	)
Accretion expense		2,236			2,529
Balance, end of year	$	21,487		$	23,604

F - 20

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

8.           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.

i.   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 year ended December 31, 2009 (December 31, 2008 - Nil).

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 $157,746 was recorded during the year ended December 31, 2009 (December 31, 2008 – nil) related to options granted during the year ended December 31, 2009.  The changes in stock options are as follows:

F - 21

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

8.             SHARE CAPITAL (continued)

	NUMBER	WEIGHTED AVERAGE EXERCISE PRICE
Balance outstanding, December 31, 2008 Granted Granted Expired Exercised Balance outstanding, December 31, 2009	48,000 100,000 800,000                     (48,000)                         -	$                      3.75                        0.15                                 0.12                                 3.75                                     -
	900,000	$                      0.12

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:

	December 31, 2009			December 31, 2008
Risk-fee interest rate		2.50	%		0.00	%
Expected life of the option	3 years			0 year
Expected volatility	199.13%  & 476.13%				0.00	%
Expected dividend yield		-			-

The following table summarized information about the stock options outstanding as at December 31, 2009:

Options outstanding			Options exercisable
Exercise  price	Number of shares	Remaining contractual life (years)	Number of shares
$0.15 $0.12	100,000 800,000	2.27 2.92	100,000 800,000

F - 22

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

iii.      Common Stock Share Purchase Warrants

As at December 31, 2009, share purchase warrants outstanding for the purchase of common shares as follows:

Warrants outstanding

Exercise price	Number of shares	Expiry date
$ 7.50	496,797	February 1, 2010

No warrants were issued during the year ended December 31, 2009.

9. RELATED PARTIES

During the year ended December 31, 2009, the Company paid $207,121 (December 31, 2008 - $179,893) for consulting fees and $27,578 (December 31, 2008 - $39,750) for accounting services to Companies controlled by directors and officers of the Company.  There was $1,527 payable to a Director of the Company for the reimbursement of expenses incurred on behalf of the Company.  Amounts paid to related parties are based on exchange amounts agreed upon by those related parties.

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.

On December 2, 2009, the Company granted 600,000 stock options in consideration for services rendered to the directors and officers of the Company.  The price of the share as of December 2, 2009 was $0.12.  The total cost of $107,997 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.

F - 23

Delta Oil & Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2009

(Stated in U.S. Dollars)

10.        COMMITMENT AND CONTRACTURAL OBLIGATIONS

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

The Company contracted with its executive officers to pay each of the executive officers $85,632 per year and issue 100,000 common shares of the Company on the anniversary of the executive agreement.  The agreement automatically renews after one year for a further 12 months.

11.         SEGMENTED INFORMATION

In accordance with Accounting Standards Codification, Segment Reporting, the Company has identified only one operating segment, which is the exploration and production of oil and natural gas.  All of the Company’s oil and gas properties are located in the United States and Canada (refer to note 4), and all revenues are attributable to United States and Canada as follows:

	December 31, 2009		December 31, 2008
Revenue
United States	$	157,351	$	1,816,335
Canada		353,566		111,204
Total Revenue	$	510,917	$	1,927,539

Assets
United States	$	750,840	$	1,346,373
Canada		703,699		1,233,640
Total Assets	$	1,454,539	$	2,580,013

Liabilities
United States	$	43,780	$	46,508
Canada		17,116		3,649
Total Liabilities	$	60,896	$	50,157

F - 24

Delta Oil & Gas, Inc.

DECEMBER 31, 2009

(Stated in U.S. Dollars)

UNAUDITED OIL AND GAS RESERVE QUANTITIES

Costs Incurred
 

The following table sets forth certain information with respect to costs incurred in connection with our oil and gas producing activities during the year ended December 31, 2009, 2008 and 2007:

2007
Property acquisition costs	USA			Canada
Proved		36,575			-
Unproved		154,225			-
Development costs		-			-
Exploratory costs		1,403,137			265,656
Oil and gas expenditures		1,593,937			265,656
2008
Property acquisition costs	USA			Canada
Proved		57,250			-
Unproved		(57,250	)		-
Development costs		-			-
Exploratory costs		591,664			117,822
Oil and gas expenditures		591,664			117,822
2009
Property acquisition costs	USA			Canada
Proved		27,750			-
Unproved		17,900			-
Development costs		-			-
Exploratory costs		424,678			79,430
Oil and gas expenditures		470,328			79,430

The following unaudited reserve estimates presented as of December 31, 2008 and 2007 were prepared by independent petroleum engineers.  There are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures.  In addition,  reserve  estimates of new discoveries that have  little  production  history  are  more  imprecise  than  those of properties with more production history.  Accordingly, these estimates are expected to change as future information becomes available.

F - 25

Delta Oil & Gas, Inc.

DECEMBER 31, 2009

(Stated in U.S. Dollars)

UNAUDITED OIL AND GAS RESERVE QUANTITIES (continued)

Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., process and costs as of the date the estimate is made. Proved developed oil and gas reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.

Unaudited net quantities of proved developed reserves of crude oil and natural gas (all located within United States) are as follows:

	Crude Oil			Natural Gas
Changes in proved reserves	(Bbls)			(MCF)
Estimated quantity, December 31, 2007		74,894			166,660
Revisions of previous estimate		0			(120,951	)
Discoveries		174,199			36,205
Reserves sold to third party		(36,543	)		0
Production		(6,377	)		(28,559	)
Estimated quantity, December 31, 2008		206,173			53,355
Revisions of previous estimate		(96,325	)		122,095
Discoveries		13,140			27,500
Reserves sold to third party		(78,340	)		(60,190	)
Production		(1,858	)		(11,150	)
Estimated quantity, December 31, 2008		42,790			131,610

Proved Reserves at year end	Developed		Undeveloped		Total
Crude Oil (Bbls)
December 31, 2009		23,970		18,820		42,790
December 31, 2008		187,983		18,190		206,173
Gas (MCF)
December 31, 2009		124,350		7,260		131,610
December 31, 2008		53,355		-		53,355

UNAUDITED STANDARIZED MEASURE

The following information has been developed utilizing procedures prescribed by SFAS 69 "Disclosures About Oil and Gas Producing Activities" and based on crude oil and natural gas reserves and production volumes estimated by the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative or realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

Future cash inflows were computed by applying year-end prices of oil and gas to the estimated future production of proved oil and gas reserves. The future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pre-tax net cash flows relating to our proved oil and gas reserves and the tax basis of proved oil and gas properties and available net operating loss carry forwards. Discounting the future net cash inflows at 10% is a method to measure the impact of the time value of money.

F - 26

Delta Oil & Gas, Inc.

DECEMBER 31, 2009

(Stated in U.S. Dollars)

UNAUDITED OIL AND GAS RESERVE QUANTITIES (continued)

	December 31, 2009			December 31,  2008
Future Cash inflows	$	3,143,360		$	2,133,418
Future production costs		(1,019,970	)		(651,954	)
Future development costs		(15,250	)		(280,904	)
Future income tax expense		(178,430	)		(79,138	)
Future cash flows		1,929,710			1,121,422
10% annual discount for estimated timing of cash flows		(767,300	)		(152,871	)
Standardized measure of discounted future next cash	$	1,162,410		$	968,550

The following presents the principal sources of the changes in the standardized measure of discounted future net cash flows.

Standardized measure of discounted cash flows:	December 31, 2009			December 31, 2008
Beginning of year	$	968,550		$	2,759,875
Sales and transfers of oil and gas produced, net production costs		1,009,942			(3,157,906	)
Net changes in prices and production costs and other		(368,016	)		94,156
Net changes due to discoveries		(614,428	)		1,300,802
Changes in future development costs		265,654			(254,914	)
Revisions of previous estimates		-			-
Other		-			-
Net change in income taxes		(99,292	)		226,537
Accretion discount		-			-
Future cash flows		193,860			(1,791,325	)
End of year	$	1,162,410		$	968,550

F - 27

(a)(2)           Not Applicable.

(a)(3)           Exhibits.

See (b) below.

(b)            Exhibits.

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

(c)            Financial Statements Excluded From Annual Report to Shareholders

Not Applicable.

- 47 -

GLOSSARY OF SELECTED OIL AND GAS TERMS

The following is a description of the meanings of some of the oil and gas industry terms used in this report.

3-D seismic.  An advanced technology method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

After payout – With respect to an oil or natural gas interest in a property, refers to the time period after which the costs to drill and equip a well have been recovered.

BOE.  Means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis.  Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or natural gas liquid.

Bbl.  One barrel, or 42 U.S. gallons of liquid volume.

Before payout – With respect to an oil and natural gas interest in a property, refers to the time period before which the costs to drill and equip a well have been recovered.

Completion.  The installation of permanent equipment for the production of oil or gas.

Development well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole.  A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well.

Exploratory well.  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Gross acres or wells.  Refers to the total acres or wells in which the Company has a working interest.

 Horizontal drilling.  A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.

MBbls.  One thousand barrels.

MBOE.  One thousand BOEs.

Mcf.  One thousand cubic feet.

MMcf.  One million cubic feet.

NGLs.  Natural gas liquids.

Net acres or wells.  Refers to gross the sum of fractional ownership working interest in gross acres or wells.

Oil.  Crude oil or condensate.

Operator.  The individual or company responsible for the exploration, development and production of an oil or gas well or lease.

- 48 -

Present value of proved reserves (“PV-10”).  The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, (ii) non-property related expenses such as general and administrative expenses, debt service and future income tax expense, or (iii) depreciation, depletion and amortization.

Productive wells. Producing wells and wells mechanically capable of production.

Proved Developed Reserves.  Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.  (i) The area of the reservoir considered as proved includes:  (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.  (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.  (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.  (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:  (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including government entities.

Proved undeveloped reserves (PUD).  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic productibility at greater distances.  (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.  (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.  (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.  (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.  (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proves reserves.

- 49 -

Royalty.  An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage.  Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

SEC.  The United States Securities and Exchange Commission.

Standardized measure of discounted future net cash flows.  Present value of proved reserves, as adjusted to give effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, and (ii) estimated future income taxes.

Undeveloped acreage.  Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas, regardless of whether such acreage contains proved reserves.

Working interest.  An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.  The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.

- 50 -

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized, this 12th day of April, 2010.

DELTA OIL & GAS, INC.,

a Colorado corporation

By:     /s/ Christopher Paton-Gay                                           

Christopher Paton-Gay

Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature and Title	Date
/s/ Christopher Paton-Gay	April 12, 2010
Christopher Paton-Gay, Chief Executive Officer and Director (Principal Executive Officer)
/s/ Douglas N. Bolen	April 12, 2010
Douglas N. Bolen, President and Director
/s/ Kulwant Sandher	April 12, 2010
Kulwant Sandher, Chief Financial Officer and Director (Principal Financial Officer and Principal Accounting Officer)

- 51 -

DELTA OIL & GAS, INC.

EXHIBIT INDEX

TO

2009 ANNUAL REPORT ON FORM 10-K

Exhibit Number	Description	Incorporated by Reference to:	Filed Herewith
3.1	Amended and Restated Articles of Incorporation of Delta.	Exhibit 3 of Delta’s Form SB-2 filed on February 13, 2002
3.2	Articles of Amendment to the Articles of Incorporation of Delta	Exhibit 3.1 of Delta’s Quarterly Report of Form 10-Q dated September 30, 2009.
3.3	Articles of Amendment to the Articles of Incorporation of Delta	Exhibit 3.1 of Delta’s Form 8-K dated October 21, 2009.
3.4	By-laws of Delta, as amended.		X
10.1	Letter Agreement by and between Delta and Ranken Energy Corporation dated September 10, 2007.	Exhibit 10.1 of Delta’s Form 10QSB dated November 7, 2007
10.2	Strachan Participation and Farmout Agreement by and between Odin Capital Inc. and Delta dated September 23, 2005.	Exhibit 10.1 of Delta’s Form 8-K dated September 29, 2005
10.3	Farmout and Option Participation Letter Agreement by and between Petrex Energy Ltd., Texalta Petroleum Ltd., Odin Capital Inc., Delta Oil and Gas (Canada) Inc., Last Mountain Investments Inc., 264646 Alberta Ltd., LL & S Holdings Ltd. and 0743608 B.C. Ltd. dated April 10, 2006.	Exhibit 10.7 of Delta’s Form 10SB12G dated May 12, 2006.
10.4	Farmout Agreement by and between Sunset Exploration, Inc. and Delta, effective May 25, 2009	Exhibit 10.1 of Delta’s Quarterly Report of Form 10-Q dated June 30, 2009
10.5	Letter Agreement by and between Ranken Energy Corporation and Delta relating to 2009-1 Drilling Program	Exhibit 10.2 of Delta’s Quarterly Report of Form 10-Q dated June 30, 2009
10.6	Assignment of Oil, Gas, & Liquid Hydrocarbon Leases dated July 15, 2009, relating to the Texas Prospect	Exhibit 10.1 of Delta’s Quarterly Report of Form 10-Q dated September 30, 2009
10.6	Letter Agreement by and between Delta and Ranken Energy Corporation dated August 7, 2009	Exhibit 10.2 of Delta’s Quarterly Report of Form 10-Q dated September 30, 2009
10.8	Amended and Restated Consulting Agreement, dated as of March 8, 2010, by and between Delta and Warwick Management Services	Exhibit 10.1 of Delta’s Form 8-K dated March 8, 2010
10.8	Amended and Restated Consulting Agreement, dated as of March 8, 2010, by and between Delta and Last Mountain Management Ltd.	Exhibit 10.2 of Delta’s Form 8-K dated March 8, 2010
10.10	Amended and Restated Consulting Agreement, dated as of March 8, 2010, by and between Delta and CPG Consulting Ltd.	Exhibit 10.3 of Delta’s Form 8-K dated March 8, 2010
10.11	Delta 2010 Incentive Compensation Plan	Exhibit 10.1 of Delta’s Form 8-K dated March 8, 2010

- 52 -

Exhibit Number	Description	Incorporated by Reference to:	Filed Herewith
10.12	Exploration Agreement by and between Barry Lasker and Delta, dated March 27, 2009		X
10.13	Assignment and Assumption Agreement, dated as of December 8, 2009, between Delta and Hillcrest Resources, Ltd.		X
14.1	Code of Ethics and Conduct	Exhibit 10.1 of Delta’s Form 10-KSB filed on April 19, 2004
21.1	Subsidiaries of Delta.		X
23.1	Consent of Harper & Associates, Inc.		X
23.2	Consent of Mark E. Andersen		X
23.3	Consent of Chapman Petroleum Engineering		X
31.1	Certificate of Christopher Paton-Gay, Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.		X
31.2	Certificate of Kulwant Sandher, Chief Finance Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.		X
32.1	Certificate of Christopher Paton-Gay, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.		X
32.2	Certificate of Kulwant Sandher, Chief Finance Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002		X
99.1	Report of Harper & Associates, Inc. independent consulting engineers		X
99.2	Report of Mark E. Andersen independent consulting engineers		X
99.3	Report of Chapman Petroleum Engineering  independent consulting engineers		X

- 53 -