UNITED STATES


SECURITIES AND EXCHANGE COMMISSION


Washington, D.C.  20549




Form 10-K/A


(Amendment No. 2)




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




For the fiscal year ended December 31, 2008




 ̈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.)2600 144 4th Avenue, S.W., Calgary, Alberta, Canada, T2P 3N4(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, $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, 2008, the aggregate market value of the Company’s common equity held by non-affiliates computed by reference to the closing price $0.09 was: $4,037,292




The number of shares of our common stock outstanding as of January 14, 2009 was: 46,840,506




Documents Incorporated by Reference:  Parts of our definitive proxy statement to be prepared and filed with the Securities and Exchange Commission not later than 120 days after December 31, 2008 are incorporated by reference into Part III of this Form 10-K.


Table of Contents


Documents Incorporated by Reference:  Parts of our definitive proxy statement to be prepared and filed with the Securities and Exchange Commission not later than 120 days after December 31, 2008 are incorporated by reference into Part III of this Form 10-K.





EXPLANATORY NOTE


This Amendment No. 2 on Form 10-K/A (this “Amendment”) to the Annual Report on Form 10-K for the year ended December 31, 2008 (the “Original Annual Report”), as amended by Amendment No. 1 (collectively with the Original Annual Report, the “Amended Annual Report”), of
Delta Oil & Gas, Inc. (the “Company”) is being filed to (i) make the disclosures in Item 2 under the subheading “Reported Reserves” consistent with the disclosures in footnote 14 of this Amendment, and (ii) file a dual dated audit report of the Company’s independent  registered public accounting firm. In addition, the Company is including as exhibits to this Amendment the certifications required pursuant to Sections 302 and 906 of the Sarbanes-Oxley Act
of 2002.
  Except as described above, this Amendment does not attempt to modify or update any other disclosures set forth in the Company’s Amended Annual Report. Accordingly, the remainder of the Company’s Amended Annual Report remains unchanged. This Amendment continues to speak as of March 31, 2009, the date
of our initial filing of the Original Annual Report, and unless otherwise indicated herein, does not reflect information obtained after that date. Therefore, in conjunction with reading this Amendment, you also should read all other filings that we have made with the Securities and Exchange Commission since March 31, 2009.







Table of Contents








FORM 10-K


DELTA OIL & GAS, INC.


DECEMBER 31, 2008




logo







Table of Contents






PART I




PageItem 1.          Business.
4Item 1A.       Risk Factors.
11Item 1B.       Unresolved Staff Comments.
18Item 2.          Properties.
18Item 3.          Legal Proceedings.
22Item 4.          Submission of Matters to a Vote of Security Holders.
22




PART II




Item 5.          Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
23Item 6.          Selected Financial Data.
24Item 7.          Management’s Discussion and Analysis of Financial Condition and Results ofOperations.
24Item 7A.       Quantitative and Qualitative Disclosures About Market Risk.
30Item 8.          Financial Statements and Supplementary Data.
30Item 9.          Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.
30Item 9A.       Controls and Procedures.
30Item 9B.        Other Information.
31




PART III




Item 10.         Directors, Executive Officers and Corporate Governance.
32Item 11.         Executive Compensation.
33Item 12.         Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
36Item 13.         Certain Relationships and Related Transactions, and Director Independence.
36Item 14.         Principal Accounting Fees and Services.
37




PART IV




Item 15.        Exhibits, Financial Statement Schedules.
38Signature PageExhibit Index









- 2 -
 Table of Contents





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.




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.







- 3 -
 Table of Contents





PART I


ITEM 1. Business.




Business Development




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 exploration, development, acquisition and operation of 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.




Business of Delta




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




Todd Creek Prospect and Hillspring Prospect




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




Todd Creek Prospect




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




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




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




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




Hillspring Prospect




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







- 4 -
 Table of Contents





Strachan Prospect




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




1.
in the Spacing Unit for the Earning Well:




(a)
a 2.0% interest in the petroleum and natural gas below the base of the Mannville, excluding natural gas in the Leduc formation; and




(b)
a 4.0% interest in the natural gas in the Leduc formation before payout, subject to payment of the Overriding Royalty which is convertible upon payout at royalty owners option to 50% of our Interest;




2.
a 1.6% interest in the rights below the base of the Shunda formation in Section 10, Township 38, Range 9W5M; and




3.
a 1.289% interest in the rights below the base of the Shunda formation in Section 15 and 16, Township 38, Range 9W5M, down to the base of the deepest formation penetrated.




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




Based on results indicating the presence of a potential gas well, the operator inserted casing into the total depth of the well in July 2006 and have 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. All twelve wells have been drilled and currently seven wells are producing, we anticipate that three wells will be producing and are currently waiting to be tied into the pipeline, and two wells were not commercially viable and were plugged and abandoned. We refer to this drilling program as Palmetto Point Phase I.  Total revenue received from these
wells for the year ended December 31, 2008 was $38,981, compared with $70,821 in revenues for the year ended December 31, 2007.  The decrease in revenue was caused by the ceasing of production in wells that had higher than expected water content; however, this was partially offset by an increase in commodity prices during the year.







- 5 -
 Table of Contents





In October 2007, as part of Palmetto Point Phase I, we drilled a well (the "PP F-12") on the prospect.  Subsequent testing revealed that the PP F-12 well contained oil reserves suitable for commercial production.  The PP F-12 well began producing on October 2, 2007.   This
well is situated in what is known as the Belmont Lake Oil Field.  Based on the positive results from the PP F-12 well, the operator suggested drilling an additional two development wells in the immediate vicinity in which we would participate.  In November 2007, we participated in the drilling of a step-out well from the PP F-12 (the “PP F-12 #2”).  This well was drilled to total depth, logged, tested and cased.   The PP F-12 #2 encountered approximately
three feet of hydrocarbon showings and as such the operator recommended re-entering the well and directionally drilling on an angle toward the PP F-12.  Upon completion and testing of this re-entry (the “PP F-12 #2-3”), the operator encountered approximately 32 feet of hydrocarbon pay and the well was connected to a nearby pipeline and is currently producing oil.  Total revenue received from these two oil wells was $101,992 for the year ended December 31, 2008 compared to $57,964
for the prior year ended December 31, 2007.  The increase in revenue was caused by the addition of a second offset well and an increase in commodity prices during the year.  The revenue generated from, these wells has been less than we anticipated as a result of an approximate four month halt in production of these wells during the fiscal year ended December 31, 2008 due to the flooding of the Mississippi basin where these wells are located.




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 did not incur any additional payments other than drilling
costs for these prospects in 2007.  We do not anticipate that we will incur any additional payments other than drilling costs for these prospects going forward.




To date, we have drilled seven wells of which two have been abandoned (the Dixon #1 and the Randall #1).  Our costs attributable to these two abandoned wells was $67,523. Of the successful four wells, the Redbug #1, Redbug #2 and the Buffalo River #1 began producing
in the three months ended March 31, 2007 and the Faust #1, is awaiting connection to the nearby pipeline for production. The revenue received from these wells for the year ended December 31, 2008 was $79,050 as compared to $13,045 for the year ended December 31, 2007.  The increase in revenue was caused by ongoing production for the entire year ended December 31, 2008, as opposed to partial production in 2007 as a result of production commencing during the nine months ended September 30, 2007 and an
increase in commodity prices during the year.




Wordsworth Prospect




On April 10, 2006, we entered into a farmout, option and participation letter agreement (“FOP Agreement”) where we acquired a 15% working interest in certain leasehold interests located in southeast Saskatchewan, Canada referred to as the Wordsworth area for the purchase price of
$152,724. We are responsible for our proportionate share of the costs associated with drilling, testing, and completing the first test well on the property. In exchange for us paying our proportionate share of the costs associated with drilling, testing, and completing the first test well on the property, we earned a 15% working interest before payout and a 7.5% working interest after payout on the Wordsworth prospect. Payout refers to the return of our initial investment in the property. In addition, we also
acquired an option to participate and acquire a working interest in a vertical test well drilled to 1200 meters to test the Mississippian (Alida) formation in LSD 13 of section 24, township 7, range 3 W2.  Our total costs as at December 31, 2007 was $222,649.












- 6 -
 Table of Contents





During June 2006, the first well was drilled to a horizontal depth of 2033 meters in the Wordsworth prospect. The initial drilling of this well and subsequent testing revealed that this well contained oil reserves suitable for commercial production. In June 2006, this initial well began producing
as an oil well.  The revenue received from this well for the year ended December 31, 2008 was $104,989, as compared to $131,213 for the year ended December 31, 2007.  The reduction in revenue was caused by the natural decline of reserves in the well; however, this was partially offset by the increase in commodity prices during the year.




The second horizontal well was drilled in May 2007 at a cost of $198,152. Initial logs indicated hydrocarbon showings in an oil-bearing zone estimated to be approximately 770 feet in the horizontal section. However, due to the high water content in fluid removed from this well,
the operator determined that it was not commercially productive and it was plugged and abandoned.




In April 2008, the operator recommended re-entering the second horizontal well with a view to drilling horizontally in a different direction starting at the base of the vertical portion of that well. We elected to participate in this re-entry on the same terms and conditions
as the previous wells.  This well was drilled at a cost of $33,812. No economic hydrocarbons were found and this well was plugged and abandoned.




Owl Creek Prospect




On June 1, 2006, we entered into an Assignment Agreement with Brinx Resources, Ltd., (“Brinx Resources”), a Nevada oil & gas exploration company, in order to acquire a working interest in lands and leases owned by Brinx Resources. 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, we acquired a 20% working interest in an oil well drilled at the Owl Creek Prospect (the “Powell #2”).  The Powell #2 was drilled to total depth of 5,617 feet on May 18, 2006 and underwent testing. Based
upon the positive result of the testing of the Powell #2, this well was completed and commercial production commenced in August 2006.  Under the terms of the Assignment Agreement, we are responsible for our proportionate share of the costs of completion and tie-in for production of the Powell #2 which was $68,987.  Initially, the Powell #2 began flowing oil and natural gas under its own pressure without the assistance of a pump.  Revenue generated from the Powell #2 for the year
ended December 31, 2008 was $265,062, as compared to $481,584 for the year ended December 31, 2007.  In July 2008, the Company disposed of its holdings in Powell #2 and the surrounding area for $760,438.




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




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




In January 2007, we commenced drilling of another well (the “Isbill #2-36”). Our 20% working interest in the Isbill #2-36 cost $157,437 for both drilling and completion. The Isbill #2-36 was drilled to approximately 5,900 feet and encountered two potential pay zones
and is a direct offset well to the Powell #2 which is currently producing.  The revenue received from the Isbill #2-36 for the year ended December 31, 2008 was $122,969, as compared to $141,042 for the year ended December 31, 2007.  In July 2008, the Company disposed of its holdings in Isbill #2-36 and the surrounding area for $549,388.







- 7 -
 Table of Contents





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




Three other wells drilled (the “Elizabeth #1-25”, the “Plaster #1-1” and the “Dale #1 re-entry”) were deemed by the operator to be commercially viable and production casing was set in each.    The Elizabeth #1-25 located in the Meridian
Prospect cost $99,129, the Plaster #1-1 located in the Plaster Prospect cost $116,581, and re-entry into the Dale #1 located in the Dale Prospect cost $18,150.  Subsequent to the completion of these wells, two remain economically viable at this time.  The Plaster #1 encountered hydrocarbon showings and is producing natural gas with amounts of associated oil as of January, 2008. The Dale #1 re-entry has been producing in the range of 2 to 3 barrels of oil per day. The Elizabeth #1-25 has been
plugged and abandoned.  Total revenue received from these wells for the year ended December 31, 2008 was $46,923.  These two wells did not generate any revenue prior to 2008.




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




2007-1 Drilling Program - 3 Wells




On September 10, 2007, we entered into an agreement with Ranken Energy to participate in a three well drilling program in Garvin County, Oklahoma (the “2007-1 Drilling Program”).  We purchased a 20% working interest in the 2007-1 Drilling Program for $77,100. Drilling of
the first and second wells (the “Pollock #1-35” and the “Hulsey #1”) has been completed in the N.E. Anitoch Prospect and the Washington Creek Prospect respectively.  The Pollock #1-35 did not prove to be commercially viable but the Hulsey #1 has been producing in the range of 50 to 60 barrels of oil per day with approximately 50 Mcf of natural gas per day.  Drilling of the third well in this drilling program (the “River #1”) was completed during the three
months ended September 30, 2008.  River #1 commenced production and the total revenue received for the year ended December 31, 2008 was $79,897.  Hulsey #1-8 started producing during the first quarter of 2008 and the total revenue received for the year ended December 31, 2008 was $111,498.




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




- 8 -
 Table of Contents






•           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.




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, 2008 or 2007.




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.







- 9 -
 Table of Contents





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.




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.




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.




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







- 10 -
 Table of Contents





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 employees other than our Chief Executive Officer, Mr. Douglas N. Bolen, and our Chief Financial Officer, Mr. Kulwant Sandher.




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 $215,826 for the year ended December 31, 2008 and $2,249,959 for the year ended December 31, 2007. 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





- 11 -
 Table of Contents





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.





Because our chief executive officer does not have any significant training and/or experience in oil and natural gas exploration, development, acquisition and production, our financial success could suffer irreparable harm as a result of his decisions and choices.





Mr. Douglas N. Bolen, our chief executive officer, does not have any significant training or experience with oil and natural gas exploration, development, acquisition and production. With no direct training or experience in these areas, our chief executive officer may not be fully aware of many
of the specific requirements related to working within this industry. Our management’s decisions and choices may fail to take into account standard engineering or managerial approaches oil and gas companies commonly utilize. Consequently, our operations, earnings, and ultimate financial success could suffer irreparable harm due to management’s lack of experience in this industry.





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.





Mr. Bolen, our chief executive officer, and Mr. Sandher, our chief financial officer, 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. Bolen and Sandher, it is possible that Messrs. 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.





- 12 -
 Table of Contents








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 have only recently commenced operations. 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.





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.








- 13 -
 Table of Contents





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.





In the event that we are unable to successfully compete within our industry, we may not be able to achieve profitable operations.





We operate in the highly competitive areas of oil and natural gas exploration, development, acquisition and production. Factors that affect our ability to compete successfully in the marketplace include:





•           seeking to acquire desirable producing properties or new leases for future exploration;





•           the availability of funds and information relating to a property; and





•           marketing of oil and natural gas production.





Our competitors include major integrated oil companies, substantial independent energy companies, and affiliates of major interstate and intrastate pipelines and national and local natural gas gatherers, many of which possess greater financial and other resources than we do. If we are unable
to successfully compete against our competitors, our business, prospects, financial condition and results of operation may be adversely affected.





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:








- 14 -
 Table of Contents




•           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.





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.





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








•
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.





- 15 -
 Table of Contents








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.





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.





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.





- 16 -
 Table of Contents








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




We are required to evaluate our internal controls under Section 404 of the Sarbanes-Oxley Act of 2002.  Beginning with our annual report on Form 10-K for the fiscal year ending December 31, 2008, we are required to furnish a report by our management on our internal control over financial reporting.  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 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





- 17 -
 Table of Contents





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 1600, 144 4th Avenue S.W., Calgary, Alberta T2P 3N4 and we pay $243 per month for this location.


Reported Reserves





Below are estimates of our net Proved Reserves and the present value of estimated future net revenues from such Reserves based upon the standardized measure of discounted future net cash flows relating to proved oil and gas reserves in accordance with the provisions of Statement of Financial Accounting Standards No. 69, "Disclosures about
Oil and Gas Producing Activities" (SFAS No. 69). The standardized measure of discounted future net cash flows is determined by using estimated quantities of Proved Reserves and the periods in which they are expected to be developed and produced based on period-end economic conditions. The estimated future production is priced at period-end prices, except where fixed and determinable price escalations are provided by contract. The resulting estimated future cash inflows are then reduced by estimated future costs
to develop and produce reserves based on period-end cost levels. No deduction has been made for depletion, depreciation or for indirect costs, such as general corporate overhead. Present values were computed by discounting future net revenues by 10% per year.





- 18 -
 Table of Contents




December 31,2008
2007
2006Oil
(Bbls)
Gas
(Mcf)
Gas
(Mcf)
Oil
(Bbls)
Gas
(Mcf)
Oil
(Bbls)Proved Producing & Non-Producing Reserves
209,173
53,355
166,660
74,894
113,947
72,341Estimated future net cash flows from proved oil and gas reserves
1,121,422
$4,213,549
$795,23Standarized measure of discounted
future net cash flows
968,550
$2,759,875
$611,152





Production





Production Data
Year ended December 31,2008
2007
2006Production -Oil (Bbls)
3,377
11,514
29,280Gas (Mcf)
28,559
33,394
3,797Average Sales Price -Oil (Bbls)
$90.00
$64.00
$58.00Gas (Mcf)
$6.00
$6.00
$4.60Average Production Costs per Mcf
$3.29
$2.00
$2.50





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.





Productive Wells and Acreage





The following table shows our producing wells and acreage as of December 31, 2008:





Producing Wells 3
Developed AcreageOil
GasGross 1
Net 2
Gross 1
Net 2
Gross 1
Net 2Alberta, Canada
(Todd Creek)
Nil
Nil
Nil
Nil
Nil
NilAlberta, Canada
(Hillspring)
Nil
Nil
Nil
Nil
Nil
NilPalmetto Point, Mississippi
(Palmetto)
2
0.17
3
0.255
1,273
127Saskatchewan, Canada
(Wordsworth)
2
0.15
Nil
Nil
160
12Ranken 2006-03
Drilling Program
1
0.10
Nil
Nil
340
34Ranken 2007-01
Drilling Program
2
0.40
2
0.40
300
60Garvin & McClain Counties, Oklahoma
(Owl Creek)
Nil
Nil
Nil
Nil
Nil
Nil




- 19 -
 Table of Contents








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.





Undeveloped Acreage





The following table set forth undeveloped acreage as of December 31, 2008:


Undeveloped Acreage 1
as of December 31, 2008Gross
NetAlberta, Canada
(Todd Creek)
Nil
NilAlberta, Canada
(Hillspring)
Nil
NilAlberta, Canada
(Strachan)
Nil
NilPalmetto Point, Mississippi
(Palmetto) – Phase I & II
300,000
30,000Saskatchewan, Canada
(Wordsworth)
4,800
720Ranken 2006 – 03
Drilling Program
820
80Ranken 2007 – 01
Drilling Program
420
200Garvin & McClain Counties, Oklahoma
(Owl Creek)
Nil
Nil





1
"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.




- 20 -
 Table of Contents





Drilling Activity





The following table sets forth, for each of the last three fiscal years by geographic area the number of net productive and dry exploratory wells drilled and the number of net productive and dry development wells drilled.





Geographical Area
Net Exploratory Wells Drilled
Net Development Wells DrilledProductive 1
Dry 2
Productive 1
Dry 2Alberta, Canada
(Todd Creek)2008
0
0
0
02007
0
0
0
02006
0.20
0
0
0Alberta, Canada
(Hillspring)2008
0
0
0
02007
0
0
0
02006
0
0
0
0Alberta, Canada
(Strachan)2008
0
0
0
02007
0
0
0
02006
0
0
0
0Palmetto Point, Mississippi
(Palmetto)2008
1.17
1.22
0
02007
1.17
1.22
0
02006
1.44
0.36
0
0Saskatchewan, Canada
(Wordsworth)2008
0.075
0
0
02007
0.075
0.075
0
02006
0.075
0
0
0Ranken 2006-3 Drilling Program2008
0.10
0
0
02007
0.10
0.20
0
02006
0
0
0
0Ranken 2007-1 Drilling Program2008
0.20
0.20
0
02007
0.20
0.20
0
02006
0
0
0
0Garvin & McClain Counties, Oklahoma
(Owl Creek)2008
0
0
0
02007
0.20
0
0.20
02006
0.20
0
0.20
0.20Totals





1
A productive well is an exploratory or development well that is not a dry well.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.





- 21 -
 Table of Contents





Present Activities





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


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. Submission of Matters to a Vote of Security Holders.




No matters were submitted to a vote of our shareholders during the fourth quarter of the fiscal year ended December 31, 2008.







- 22 -
 Table of Contents





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 “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.




Fiscal Year Ended December 31, 2008Fiscal Quarter Ended:
High Bid
Low BidMarch 31, 2008
$0.305
$0.15June 30, 2008
$0.18
$0.089September 30, 2008
$0.10
$0.045December 31, 2008
$0.065
$0.01Fiscal Year Ended December 31, 2007Fiscal Quarter Ended:
High Bid
Low BidMarch 31, 2007
$1.28
$0.71June 30, 2007
$0.94
$0.50September 30, 2007
$0.565
$0.155December 31, 2007
$0.59
$0.21




Holders of Common Stock




As of January 31, 2008, we had approximately eighty-seven (87) shareholders of record of our common stock and 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.







- 23 -
 Table of Contents





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, 2008.


Equity Compensation Plan as of December 31, 2008


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 holdersEquity compensation plans not approved by security holder
0
0
5,249,512Total
0
0
5,249,512





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.




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




This Report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words “believe,” “expect,” “anticipate,” “intend,” “estimate,” “may,” “should,”
“could,” “will,” “plan,” “future,” “continue,” and other expressions that are predictions of or indicate future events and trends and that do not relate to historical matters identify 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.  We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  A wide variety of factors could cause or contribute to such differences and could adversely
impact revenues, profitability, cash flows and capital needs.





- 24 -
 Table of Contents





There can be no assurance that the forward-looking statements contained in this document will, in fact, transpire or prove to be accurate.




Factors that could cause or contribute to our actual results differing materially from those discussed herein or for our stock price to be adversely affected include, but are not limited to: (i) changes in our business strategy; (ii) the uncertainty of reserve estimates and timing of development expenditures; (iii) access and availability
of materials, equipment, supplies, labor and supervision, power and water; (iv) results of current and future exploration activities; (v) results of pending and future feasibility studies; (vi) accidents and labor disputes; (vii)  disappointing results from our exploration or development efforts; (viii) failure to meet our revenue or profit goals or operating budget; (ix) decline in demand for our common stock; (x) downward revisions in securities analysts’ estimates or changes in general market
conditions; (xi) investor perception of our industry or our prospects; (xii) technological changes in the oil and gas exploration industry, including technological innovations by competitors or in competing technologies; (xiii) the proximity of natural gas production to natural gas pipelines; (xiv) the availability of pipeline capacity; (xv) the demand for oil and natural gas by utilities and other end users; (xvi) the availability of alternate fuel sources; (xvii) the effect of inclement weather, such as hurricanes;
(xviii) changes in oil and gas exploration, processing and overhead costs;  (xix) unexpected changes in business and economic conditions; (xx) changes in interest rates and currency exchange rates;  (xxi) commodity price fluctuations, including changes in the worldwide price for oil and gas; (xxii) state and federal regulation of oil and natural gas marketing; and (xxiii) federal regulation of natural gas sold or transported in interstate commerce; (xxiv) local and community impacts and issues;





For the Years Ended December 31, 2008 and 2007




Revenues





We generated total revenue of $1,927,539 for the year ended December 31, 2008, an increase of approximately 111% from revenues of $913,808 for the year ended December 31, 2007.  During the year ended December 31, 2008, $860,092 of the revenue we generated 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 during the three months ended September 30, 2008.  During the year ended December 31, 2007, our revenue generated was entirely attributable to natural gas and oil sales.  The increase in total revenue for the year ended December 31, 2008, when compared to the year ended December 31, 2007, is attributable revenue of $1,067,447, which was recognized from the sale of our working interest in the Owl Creek Prospect during
the nine months ended September 30, 2008.  The decrease in revenue generated from natural gas and oil sales for the year ended December 31, 2008, when compared to the year ended December 31, 2007, is primarily attributable our inability to recognize revenue for the entire 2008 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.





Costs and Expenses





We incurred costs and expenses in the amount of $2,141,979 for the year ended December 31, 2008, a 32% decrease from costs and expenses of $3,185,239 for year ended December 31, 2007.





The decrease in costs and expenses for the year ended December 31, 2008, when compared the year ended December 31, 2007, is primarily attributable to the following factors:





·
General and administrative costs for the year ended December 31, 2008 decreased to$222,269 from $1,375,933 for the year ended December 31, 2007, a decreaseof 78%.  The decrease in general and administrative costs was caused by a reduction in stock based compensation expense attributable
to the issuances of stock options and shares of common stock.  Stock based compensation expense for the year ended December 31, 2008 was $47,700 as compared to $680,397 for the year ended December 31, 2007.  Further reductions in administrative costs was due to foreign exchange gains increasing to $181,370 (December 31, 2007: $(184,136)) as the Canadian dollar weakened against the US dollar.





- 25 -
 Table of Contents








·
Natural gas and oil operating costs for the year ended December 31, 2008 increased to $222,269 from $199,062 for the year ended December 31, 2007, an increase of 12%. The increase in natural gas and oil operating costs is attributable to an increase in the number of new producing wells for the year ended December 31, 2008, as compared to the year ended
December 31, 2007.





·
Depreciation and depletion expensefor the year ended December 31, 2008 decreased to $265,942 from $667,513 for the year ended December 31, 2007, a decrease of 60%. The decrease in depreciation and depletion expense is attributable to the disposal of two wells and 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, 2008 increased to $1,393,687 from $936,584 for the year ended December 31, 2007, an increase of 49%.  The substantial increase in impairment of natural gas and oil properties expense for the year ended December 31, 2008, as compared to the year ended December
31, 2007, is attributable to the impairment of our working interests in the Company’s prospects resulting from our third party evaluation that the costs associated with these prospects are highly unlikely to be recovered based on the commodity price prevalent at December 31, 2008.





Net Operating Loss





The net operating loss for the year ended December 31, 2008 was $214,440, compared to a net operating loss of $2,271,431 for the year ended December 31, 2007.





Other Income and Expense





We reported other net income of $2,009 for the year ended December 31, 2008, as compared to other income of $37,052 in the year ended December 31, 2007. Other expenses were attributable to interest expenses for a note payable which was paid in full during the reporting period.





Net Loss





Net loss for the year ended December 31, 2008 was $215,826, compared to a net loss of $2,249,959 for the year ended December 31, 2007. The reduction in loss for the year ended December 31, 2008 was attributable to an increase in revenues from new and existing wells, a reduction in operating expenses and the sale of the Owl Creek Prospect.





There are material events and uncertainties which could cause our reported financial information to not to be indicative of future operating results or financial condition.  Our inability to successfully identify, execute or effectively integrate future acquisitions may negatively affect our results of operations.  The
success of any acquisition depends on a number of factors beyond our control, including the ability to estimate accurately the recoverable volumes of reserves, rates of future production and future net revenues attainable from the reserves and to assess possible environmental liabilities.  Drilling for oil and natural gas may also involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting
operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return.  Our ability to achieve our target results are also dependent upon the current and future market prices for crude oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.  We do not operate the properties in which we have an interest and we have limited ability to exercise influence over operations for these properties
or their associated costs.  Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our returns on capital in drilling or acquisition activities and our targeted production growth rate. As a result, our historical results should not be indicative of future operations.








- 26 -
 Table of Contents





Liquidity and Capital Resources





As of December 31, 2008, we had total current assets of $1,057,369 and total current liabilities in the amount of $50,157.  As a result, we had working capital of $1,007,212 as of December 31, 2008.





The revenue we currently generate from natural gas and oil sales does not exceed our operating expenses.  As such, we will require additional financing activities including issuance of our equity or debt securities to fund our operations and proposed drilling activities beyond the year ended December 31, 2008.  During
the three months March 31, 2008, we received $90,000 from financing activities involving loan issuance.  We repaid this loan during the quarter ended September 30, 2008, including interest charges of $5,016.  We received $0 from financing activities involving share issuances for the year ended December 31, 2008, compared to $45,000 for the year ended December 31, 2007.





We will require additional funds to expand our acquisition, exploration and production of natural oil and gas properties.  Our management also anticipates that the current cash on hand may not be sufficient to fund our continued operations at the current level for the next twelve months.  Additional capital will be required
to effectively expand our operations through the acquisition and drilling of new prospects and to implement our overall business strategy.  It is uncertain whether we will be able to obtain financing when sought or obtain it on terms acceptable to us.  If we are unable to obtain additional financing, the full implementation of our ability to expand our operations will be impaired.  Any additional equity financing may involve substantial dilution to our then existing shareholders.





Cash Used in Operating Activities





Operating activities generated $445,122 in cash for the year ending December 31, 2008, compared to $90,830 in cash used for operating activities for the year ended December 31, 2007.  Our positive cash flow for the year ending December 31, 2008 was caused by the redemption of certain cash equivalents.





Cash Used in Investing Activities





Cash flows provided by investing activities for the year ending December 31, 2008 was $596,614, compared to $1,551,813 cash used in investing activities for the year ended December 31, 2007.  Our positive cash flow for the year ending December 31, 2008 was primarily caused by sale proceeds of natural gas and oil working interests
in the amount of $1,309,826.





Cash from Financing Activities





Cash flows provided by financing activities for the year ending December 31, 2008 primarily consisted of $(132,289) related to the cost of registration of shares under Form S-4, compared to $45,000 in cash received from financing activities for the year ended December 31, 2007.





The underlying drivers that resulted in material changes and the specific inflows and outflows of cash for the year ending December 31, 2008 are as follows:





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




·
Property acquisition costs; and




·
Sale of the Owl Creek Prospect.





Off-Balance Sheet Arrangements




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







- 27 -
 Table of Contents





Going Concern





As shown in the accompanying financial statements, we have incurred a net loss of $3,573,762 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 and GasJoint 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.





- 28 -
 Table of Contents




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, 2008 and 2007, we had no overproduced imbalances.


Recent Accounting Pronouncements





In December 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 141R, “Business Combinations”. This statement replaces SFAS 141 and defines the acquirer in a business combination as the entity that obtains control of one or more businesses in a business combination and establishes the acquisition date as the
date that the acquirer achieves control. SFAS 141R requires an acquirer to recognize the assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree at the acquisition date, measured at their fair values as of that date. SFAS 141R also requires the acquirer to recognize contingent consideration at the acquisition date, measured at its fair value at that date. This statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December
15, 2008, and earlier adoption is prohibited. The adoption of this statement is not expected to have a material effect on our financial statements.





In December 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements Liabilities –an Amendment of ARB No. 51”. This statement amends ARB 51 to establish accounting and reporting standards for the Non-controlling interest in a subsidiary and
for the deconsolidation of a subsidiary. This statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008, and earlier adoption is prohibited. The adoption of this statement is not expected to have a material effect on our future financial statements.





In March 2008, the FASB issued Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS 161”), which is effective January 1, 2009.  SFAS 161 requires enhanced disclosures about derivative instruments and hedging activities to allow for a better understanding of their effects on an entity’s
financial position, financial performance, and cash flows.  Among other things, SFAS 161 requires disclosures of the fair values of derivative instruments and associated gains and losses in a tabular formant.  SFAS 161 is not currently applicable to us since we do not have derivative instruments or hedging activity.





In May 8, 2008, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 162, the Hierarchy of Generally Accepted Accounting Principles, which will provide framework for selecting accounting principles to be used in preparing financial statements that are presented in conformity with U.S.
generally accepted accounting principles (GAAP) for nongovernmental entities.  With the issuance of SFAS No. 162, the GAAP hierarchy for nongovernmental entities will move from auditing literature to accounting literature.  The adoption of this statement is not expected to have a material effect on our financial statements.




In June 2008, the FASB issued FASB Staff Position Emerging Issues Task Force (EITF) No. 03-6-1, determining whether instruments granted in share-based payment transactions are participating securities (“FSP EITF No. 03-6-1”).  Under FSP EITF No. 03-6-1, unvested share-based payment awards that contain
rights to receive non-forfeitable dividends (whether paid or unpaid) are participating securities, and should be included in the two-class method of computing EPS. FSP EITF No. 03-6-1 is effective for fiscal years beginning after December 15, 2008, and interim periods within those years, and is not expected to have a significant impact on our financial statements.











- 29 -
 Table of Contents





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.




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, 2008, 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, 2008.  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, 2008, our internal control over financial reporting is effective based on those criteria.







- 30 -
 Table of Contents




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, 2008, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.




ITEM 9B.      Other Information.




None.







- 31 -
 Table of Contents





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 SinceDouglas N. Bolen
43
Chief Executive Officer, Principal Executive Officer, Director
2004Kulwant Sandher
47
Chief Financial Officer, Secretary, Principal Financial Officer,Principal Accounting Officer, Director
2007





Douglas N. Bolen.  Mr. Douglas Bolenhas been our Chief Executive Officer and Director since April 15, 2004. 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.





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.





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.





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, 2008, 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, 2008 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.





- 32 -
 Table of Contents




Director Independence





Our board of directors has determined that none of our directors are “independent” as such term is defined by NASDAQ Rule 4200(a)(15).




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, 2008, all filing requirements applicable to our officers, directors and greater than ten percent beneficial owners were complied with, with the following exceptions: Messrs. Bolen and Sandher each failed to file a Form 4 in a timely fashion during fiscal year 2008.





Code of Ethics and Conduct




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





ITEM 11.  Executive Compensation.


Summary Compensation Table





The following table presents information concerning the total compensation of our Chief Executive Officer and Chief Financial Officer during the last fiscal year (the “Named Executive Officers”) for services rendered to the Company in all capacities for the years ended December 31, 2008 and 2007:




Name (a)
Year
Salary
($)
Bonus
($)
Stock
Awards
($) (1)
Option
Awards
($) (1)
All Other
Compensation
($)
Total
($)Douglas N. Bolen
CEO and President
2008
2007
89,947
66,000
-
-
26,500
460,000
-
-
-
-
116,447
526,000Kulwant Sandher
CFO, Secretary, Treasurer
2008
2007
89,946
66,000
-
-
21,200
137,500
-
-
-
-
111,146
203,500





(1)
Represents the expense for stock options, as indicated, recognized by the Company in accordance with Financial Accounting Standard No. 123(R) (“FAS 123(R)”), which requires that compensation cost relating to share-based awards be recognized in the financial statements.  The cost is measured based on the fair value of the awards.  The
values set forth in this column represent the dollar amounts recognized in accordance with FAS 123(R), disregarding the estimate of forfeitures for service-based vesting conditions.  The expense recognized by the employer in accordance with FAS 123(R) may differ from the value that will eventually be realized by the named executive officers, which will be based on the market value of the common stock at the time of vesting of restricted shares or at the time of the exercise of stock options.  The
named executive officers will realize value in connection with the stock options only if and to the extent the price of the common stock exceeds the exercise price of the stock options at such time as the officers exercise the stock options.  The assumptions used to determine the FAS 123(R) values are described in Note 2to the Notes to the Consolidated Financial Statements of Delta Oil & Gas, Inc.  No stock options were granted
to named executive officers in 2008.





- 33 -
 Table of Contents





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 Mr. Douglas Bolen, our Chief Executive Officer, or Mr. Kulwant Sandher, our Chief Financial Officer, during the fiscal years ended December 31, 2008 and 2007. Mr. Bolen and Mr. Sandher each received remuneration for services rendered during the fiscal years ended December 31, 2008 and 2007 indirectly
through compensation paid to a company under their exclusive control.




On March 1, 2006, we entered into a Consulting Agreement with Last Mountain Management, Inc. (“LMM”) to provide consulting services to us. Mr. Bolen is the sole shareholder, officer, and director of LMM. The Consulting Agreement is effective for a period of one (1) year commencing March 1, 2006 and we have a right to
cancellation anytime within any six month term. Under the terms of the Consulting Agreement, LMM is paid monthly compensation of $7,000 Canadian dollars plus applicable Canadian Good and Services Tax. The total cash compensation paid to LMM during the fiscal year ended December 31, 2008 was $89,947.  This compensation is ncluded in the summary compensation table above in “Salary.” Under the terms of the Consulting Agreement, LMM was issued 500,000 shares of our common stock during the year
ended December 31, 2008. The aggregate fair value of these shares was computed in accordance with FAS 123R and is reported in the summary compensation table above in the column titled “Stock Awards.”




On January 1, 2008, we entered into a Consulting Agreement with Hurricane Corporate Services Ltd. (“Hurricane”) to provide consulting services to us. Mr. Sandher is the sole shareholder, officer, and director of Hurricane. The Consulting Agreement is effective for a period of one (1) year and automatically renews for
additional one year periods unless notice of termination is provided under the Consulting Agreement. Under the terms of the Consulting Agreement, Hurricane is paid monthly compensation of $7,000 plus applicable Canadian Good and Services Tax and issue 400,000 shares of our common stock for each annual period that this Consulting Agreement is in good standing. The total cash compensation paid to Hurricane during the fiscal year ended December 31, 2008 was $89,946.  This compensation is included
in the summary compensation table above in “Salary.” Under the terms of the Consulting Agreement, Hurricane was issued 400,000 shares of our common stock during the year ended December 31, 2008. The aggregate fair value of these shares was computed in accordance with FAS 123R and is reported in the summary compensation table above in the column titled “Stock Awards.”




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 2008.




At no time during the last fiscal year was any outstanding option repriced or otherwise modified. 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.





- 34 -
 Table of Contents




Outstanding Equity Awards at Fiscal Year-End




Option AwardsName (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)Douglas N. Bolen
CEO and President
-
-
-
-
-Kulwant Sandher
CFO, Secretary, Treasurer
-
-
-
-
-




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 5,249,512 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.




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 2008, our board of directors was comprised of Mr. Douglas Bolen and Mr. Kulwant Sandher, each of whom also serve as executive officers   The compensation arrangements
for Messrs. Bolen and Sandher is discussed under “Executive Compensation” in this annual report.





- 35 -
 Table of Contents




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




The following table sets forth, as of March 15, 2009, 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 OwnershipName and Address of Beneficial Owner(1)
Shares Owned (2)
Options Exercisable
Within 60 Days (3)
Percent of
ClassDirectors and Executive OfficersDouglas N. Bolen
1,430,000
-
3.05%Kulwant Sandher
551,710
-
1.18%All current directors and executive officers as a group (six persons)
1,981,710
-
4.23%More Than 5% Beneficial OwnersNone

-




*
Represents less than 1% of the class.





(1)
Unless otherwise provided, the address of each person is c/o 2600 144 4th Avenue S.W., Calgary, Alberta T2P3N4, Canada





(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 15, 2009.





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 15, 2009. Such information is not necessarily to be construed as an admission of beneficial ownership for other purposes.





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, 2008 or in any presently proposed transaction which, in either case, has or will materially affect us.





On March 1, 2006, we entered into a Consulting Agreement with Last Mountain Management, Inc. (“LMM”) to provide consulting services to us. Mr. Bolen is the sole shareholder, officer, and director of LMM. The Consulting Agreement is effective for a period of one (1) year commencing
March 1, 2006 and automatically renews for additional one month periods unless notice of termination is provided under the Consulting Agreement. Under the terms of the Consulting Agreement, LMM is paid monthly compensation of $5,000 plus applicable Canadian Good and Services Tax. Following the execution of the Consulting Agreement, LMM has been issued 1,000,000 shares of our common stock.





- 36 -
 Table of Contents







On January 1, 2008, we entered into a Consulting Agreement with Hurricane Corporate Services Ltd. (“Hurricane”) to provide consulting services to us. Mr. Sandher is the sole shareholder, officer, and director of Hurricane. The Consulting Agreement is effective for a period of
one (1) year and automatically renews for additional one year periods unless notice of termination is provided under the Consulting Agreement. Under the terms of the Consulting Agreement, Hurricane is paid monthly compensation of $7,000 plus applicable Canadian Good and Services Tax plus  issued 400,000 shares of our common stock for each annual period that this Consulting Agreement is in good standing.





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, 2008 and December 31, 2007:


Fiscal 2008 Fees


Fiscal 2007 FeesFee CategoryAudit Fees

$
33,800


$
25,000Audit-Related Fees


-



-Tax Fees


-



-All Other Fees


-



-Total Fees

$
33,800


$
25,000




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 2008 and 2007, 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.




The audit report of STS Partners LLP, Chartered Accountants on the financial statements of the Company for the year ended December 31, 2008 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, 2008 and December 31, 2007 contained an uncertainty about the Company’s ability to continue as a going concern.





- 37 -
 Table of Contents







During our fiscal years ended December 31, 2008 and 2007, 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, 2008 and 2007, 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-1Financial Statements:Consolidated Balance Sheets as of December 31, 2008 and 2007

F-2Consolidated Statements of Operations – Years Ended December 31, 2008 and December 31, 2007 and Cumulative period from inception January 9, 2001 to December 31, 2008

F-3Consolidated Statement of Stockholders’ Equity (Deficiency) and from inception January 9, 2001 to December 31, 2008

F-4Consolidated Statements of Cash Flows for the Years Ended December 31, 2008 and December 31, 2007 and Cumulative period from inception January 9, 2001 to December 31, 2008

F-5Notes to Consolidated Financial Statements

F-6





(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.





- 38 -
 Table of Contents





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”) (a Development Stage Company) as at December 31, 2008 and 2007, the related consolidated statements of operations and comprehensive income (loss), changes in stockholders’
equity and cash flows for the years then ended, and for the period from inception on January 9, 2001 through to December 31, 2008.  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 audits.
 
 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. (A Development Stage Company) as at December 31, 2008 and 2007, and the results of its operations and its cash
flows for the years then ended, and for the period from inception on January 9, 2001 through to December 31, 2008, 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(b) 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(b).  The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
 
  /s/ STS PARTNERS LLP
 STS PARTNERS LLP
 CHARTERED ACCOUNTANTS
  Vancouver, British Columbia, Canada
 March 23, 2009 , except for Note 4 c, as to which the date is October 14, 2009




F -1
 Table of Contents


DELTA OIL & GAS, INC.(A Development Stage Company)Consolidated Balance Sheets(Stated in U.S. Dollars)December 31,


December 31,2008


2007ASSETSCurrentCash and cash equivalents

$
980,562


$
71,115GIC receivable


-



236,112Accounts receivable


65,614



153,990Franchise tax prepaid


-



6,912Prepaid expenses


11,193



19,3641,057,369



487,493Natural Gas And Oil PropertiesProved property


892,096



1,432,776Unproved property


630,376



1,368,2601,522,472



2,801,036Other EquipmentComputer equipment


4,483



4,483Less: accumulated depreciation


(4,311
)


(3,351
)172



1,132$
2,580,013


$
3,289,661LIABILITIES AND STOCKHOLDERS' EQUITYLIABILITIESCurrentAccounts payable and accrued liabilities

$
26,553


$
166,217Long TermAsset retirement obligation


23,604



111,80350,157



278,020STOCKHOLDERS' EQUITYShare CapitalPreferred Shares, 25,000,000 shares authorized of $0.001par value of which none have been issuedCommon stock, 100,000,000 shares authorized of $0.001par value, 46,840,506 and 45,940,506 shares issuedand outstanding, respectively


46,841



45,941Additional paid-in capital


6,050,799



6,136,288Cumulative Other Comprehensive Income


5,978



187,348Deficit Accumulated During The Development Stage


(3,573,762
)


(3,357,936
)2,529,856



3,011,641$
2,580,013


$
3,289,661The accompanying notes are an integral part of these consolidated financial statements
  
 F -2
 Table of Contents
 
 DELTA OIL & GAS, INC.(A Development Stage Company)Consolidated Statements Of Operations(Stated in U.S. Dollars)CUMULATIVE PERIODFROM INCEPTIONJANUARY 9, 2001YEAR ENDED


TODECEMBER 31,


DECEMBER 31,2008


2007


2008RevenueNatural gas and oil sales

$
860,092


$
913,808


$
2,385,030Gain on sale of natural gas and oil properties


1,067,447



-



2,128,6061,927,539



913,808



4,513,636Costs And ExpensesNatural gas and oil operating costs


222,269



199,062



557,381General and administrative


257,552



1,375,933



3,040,677Accretion


2,529



4,876



7,405Depreciation and depletion


265,942



667,513



1,438,958Impairment of natural gas and oil properties


1,393,687



936,584



3,007,152Dry well costs written off


-



1,271



119,9612,141,979



3,185,239



8,171,534Net Operating Loss


(214,440
)


(2,271,431
)


(3,657,898
)Other Income And ExpenseForgiveness of debt


-



-



39,933Interest income


7,025



37,052



68,194Interest expense


(5,016
)


-



(5,016
)2,009



37,052



103,111Loss Before Income Taxes

$
(212,431
)

$
(2,234,379
)

$
(3,554,787
)Income taxes


3,395



15,580



18,975Net Loss

$
(215,826
)

$
(2,249,959
)

$
(3,573,762
)Basic And Diluted Loss Per Common Share

$
-


$
(0.05
)Weighted Average Number OfCommon Shares Outstanding


46,284,768



45,705,191Consolidated Statement of Comprehensive Income/(Loss)Comprehensive (Loss)Net Loss

$
(215,826
)

$
(2,249,959
)

$
(3,573,762
)Other Comprehensive Income/(Loss)Foreign Currency Translation


(181,370
)


187,348



5,978Comprehensive (Loss)

$
(397,196
)

$
(2,062,611
)

$
(3,567,784
)The accompanying notes are an integral part of these consolidated financial statements


F -3
 Table of Contents




Consolidated Statement Of Changes In Stockholders' EquityPeriod From Inception, January 9, 2001, to December 31, 2008(Stated in U.S. Dollars)DEFICITCOMMON STOCK


ACCUMULATEDNUMBER





SHARE


SHARE


DURING THE


CUMULATIVEOF COMMON

PAR

ADDITIONAL


SUBSCRIPTIONS


SUBSCRIPTIONS


DEVELOPMENT


COMPREHENSIVESHARES VALUE

VALUE

PAID-IN CAPITAL


RECEIVED


RECEIVABLE


STAGE


INCOME


TOTALShares issued for cash at $0.00018


13,750,000


$
13,750


$
(11,250
)

$
-


$
-


$
-


$
-


$
2,500Shares issued for cash at $0.0036


27,500,000



27,500



72,500



-



-



-



-



100,000Shares issued for cash at $0.045


46,750



47



2,078



-



-



-



-



2,125Net (loss) for the period ended


-



-



-



-



-



(184,407
)


-



(184,407
)Balance, December 31, 2001


41,296,750



41,297



63,328



-



-



(184,407
)


-



(79,782
)Net (loss) for the year


-



-



-



-



-



(62,760
)


-



(62,760
)Balance, December 31, 2002


41,296,750



41,297



63,328



-



-



(247,167
)


-



(142,542
)Net (loss) for the year


-



-



-



-



-



(24,423
)


-



(24,423
)Balance, December 31, 2003


41,296,750



41,297



63,328



-



-



(271,590
)


-



(166,965
)Share subscriptions received


-



-



-



160,000



-



-



-



160,000Net (loss) for the year


-



-



-



-



-



(31,574
)


-



(31,574
)Balance, December 31, 2004


41,296,750



41,297



63,328



160,000



-



(303,164
)


-



(38,539
)Units issued for cash at $1.00,


2,483,985



2,484



2,481,241



(160,000
)


-



-



-



2,323,725net of share issuance costOptions exercised for cash at $0.8


245,000



245



195,755



-



(16,000
)


-



-



180,000Stock-based compensation


-



-



370,267



-



-



-



-



370,267Net (loss) for the year


-



-



-



-



-



(570,050
)


-



(570,050
)Balance, December 31, 2005


44,025,735



44,026



3,110,591



-



(16,000
)


(873,214
)


-



2,265,403Subscriptions receivable


-



-



-



-



16,000



-



-



16,000Options exercised for cash at $0.8


305,000



305



243,695



-



-



-



-



244,000Options exercised for cash at $1.00


12,500



13



12,488



-



-



-



-



12,501Shares issued for cash at $2.75,


727,271



727



1,849,268



-



-



-



-



1,849,995net of finders feeStock-based compensation


-



-



195,719



-



-



-



-



195,719Net (loss) for the year


-



-



-



-



-



(234,763
)


-



(234,763
)Balance, December 31, 2006


45,070,506



45,071



5,411,761



-



-



(1,107,977
)


-



4,348,855Options exercised for cash at $0.75


60,000



60



44,940



-



-



-



-



45,000Shares issued to President & CEO as


500,000



500



459,500



-



-



-



-



460,000part of his compensation package at $0.92Shares issued to Investor Relations


60,000



60



40,740



-



-



-



-



40,800Services, Inc. as part of the agreementShares issued to CFO for services rendered


250,000



250



137,250



-



-



-



-



137,500Stock-based compensation


-



-



42,097



-



-



-



-



42,097Comprehensive Income/(loss):Cumulative translation adjustment


-



-



-



-



-



-



187,348



187,348Net (loss) for the year


-



-



-



-



-



(2,249,959
)


-



(2,249,959
)Comprehensive (loss)






























(2,062,611
)Balance, December 31, 2007


45,940,506


$
45,941


$
6,136,288


$
-


$
-


$
(3,357,936
)

$
187,348


$
3,011,641Shares issued to President & CEO & CFO as


900,000



900



46,800



-



-



-



-



47,700part of their compensation package at $0.053Registration 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 income






























(397,196
)Balance, December 31, 2008


46,840,506


$
46,841


$
6,050,799


$
-


$
-


$
(3,573,762
)

$
5,978


$
2,529,856The accompanying notes are an integral part of these consolidated financial statements


F -4
 Table of Contents


DELTA OIL & GAS, INC.(A Development Stage Company)Consolidated Statements Of Cash Flows(Stated in U.S. Dollars)CUMULATIVE PERIODFROM INCEPTIONJANUARY 9, 2001YEAR ENDED


TODECEMBER 31,


DECEMBER 31,2008


2007


2008Cash Flows From Operating Activities:Net loss for the period

$
(215,826
)

$
(2,249,959
)

$
(3,573,762
)Adjustments to reconcile net loss to net cashused in operating activities:Gain on sale of property


(1,067,447
)


-



(2,128,606
)Accretion


2,529



4,876



7,405Depreciation and depletion


265,942



667,513



1,438,958Impairment of natural gas and oil properties


1,393,687



936,584



3,007,152Dry well costs written off


-



1,271



119,961Stock-based compensation expense


-



42,097



608,083Shares issued to President & CEO for servicess rendered


26,500



460,000



486,500Shares issued to CFO for services rendered


21,200



137,500



158,700Shares issued to Investor Relations Services Inc for services rendered


-



40,800



40,800Realized foreign exchange loss


(181,370
)


184,136



2,766Changes in operating assets and liabilities:GIC


236,112



(236,112
)


-Accounts receivable


88,376



(65,539
)


(65,614
)Accounts payable and accrued liabilities


(139,664
)


10,668



(89,470
)Tax Prepaid


6,912



(6,912
)


-Prepaid expenses


8,171



(17,753
)


(11,193
)Net Cash Generated/(Used) In Operating Activities


445,122



(90,830
)


1,680Cash Flows From Investing Activities:Purchase of other equipment


-



(991
)


(4,483
)Sale proceeds of natural gas and oil working interests


1,309,826



-



2,809,826Investment in natural gas and oil working interests


(713,212
)


(1,550,822
)


(6,630,019
)Net Cash Generated /(Used) In Investing Activities


596,614



(1,551,813
)


(3,824,676
)Cash Flows From Financing Activities:Registration of shares under Form S-4


(132,289
)


-



(132,289
)Proceeds from issuance of common stock


-



45,000



4,935,847Net Cash Provided/(Used) By Financing Activities


(132,289
)


45,000



4,803,558Net Increase/(Decrease) In Cash And Cash Equivalents


909,447



(1,597,643
)


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


71,115



1,668,758



-Cash And Cash Equivalents At End Of Period

$
980,562


$
71,115


$
980,562Supplemental Disclosures Of Non-Cash, Investing and Financing Activities500,000 shares issued to the President & CEO as part of his

$
26,500


$
460,000


$
486,500compensation package400,000 shares issued to the CFO for services rendered

$
21,200


$
137,500


$
158,70060,000 shares issued to Investor Relations Services Inc.,for services rendered.

$
-


$
40,800


$
40,800Supplemental Disclosures Of Non-Cash TransactionsIncome taxes paid

$
3,395


$
6,109


$
18,975Investment in natural gas and oil working interests included in

$
-


$
116,023


$
116,023accounts payableThe accompanying notes are an integral part of these consolidated financial statements
 
 F -5
 Table of Contents
 
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (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 a development stage, independent natural gas and oil company engaged in the exploration, development and acquisition of natural gas and oil properties in the United States and Canada.  The Company’s entry into the natural gas and oil business began on February 8, 2001.
 
 The Company is subject to several categories of risk associated with its development stage activities.  Natural gas and oil exploration and production is a speculative business, and involves a high degree of risk.  Among the factors that have a direct bearing on the Company’s prospects are uncertainties inherent
estimating  natural gas and oil reserves, future hydrocarbon production, and cash flows, particularly with respect to wells that have not been fully tested and with wells having limited production histories; access to additional capital; changes in the price of natural gas and oil; availability and cost of services and equipment; and the presence of competitors with greater financial resources and capacity.
 
 The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs.  At this time, management knows of no substantial costs from environmental accidents or events for which the Company may be currently liable.  In addition, the Company’s oil and gas business makes it vulnerable to
changes in prices of crude oil and natural gas.  Such prices have been volatile in the past and can be expected to be volatile in the future.  By definition, proved reserves are based on current oil and gas prices and estimated reserves.  Price declines reduce the estimated quantity of proved reserves and increase annual depletion expense (which is based on proved reserves).
 
 b) 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 $3,573,762 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.  All significant inter-company balances and transactions have been eliminated.
 
 F -6
 Table of Contents
 
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 
 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 Statement of Financial Accounting Standards No. 143 (“SFAS 143”), “Accounting for Asset Retirement Obligations”, which requires that asset retirement obligations (“ARO”) associated with the retirement of a tangible long-lived asset, including natural gas and oil properties, be
recognized as liabilities in the period in which it is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated assets. The cost of tangible long-lived assets, including the initially recognized ARO, is depleted, such that the cost of the ARO is recognized over the useful life of the assets. The ARO is recorded at fair value, and accretion expense is recognized over time as the discounted cash flows are accreted to the expected settlement value. The fair value of
the ARO is measured using expected future cash flow, discounted at the Company’s credit-adjusted risk-free interest rate.
 
 F -7
 Table of Contents
 
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 
 2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
 
 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) Revenue Recognition
 
 Revenue from sales of crude oil, natural gas and refined petroleum products are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customers.  Title transfers for crude oil, natural gas and bulk refined products generally occur at pipeline custody points or when a tanker lifting has occurred.  Revenues
from the production of oil and natural gas properties in which the Company shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period.  Gas imbalances occur when the Company’s actual sales differ from its entitlement under existing working interests.  The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful
that the partners can recoup their share of production from the field. At December 31, 2008 and 2007, the Company had no overproduced imbalances.
 
 g) Cash and Cash Equivalent
 
 Cash consists of cash on deposit with high quality major financial institutions, and to date has not experienced losses on any of its balances.  The carrying amounts approximated fair market value due to the liquidity of these deposits.  For purposes of the balance sheet and statements of cash flows, the Company considers
all highly liquid instruments with maturity of three months or less at the time of issuance to be cash equivalents.
 
 h)    GIC Receivable
 
 GIC Receivable is non-redeemable until April 24, 2008 and bears an interest rate of 3.80 % and was redeemed during the year.
 
 i)    Concentration of Credit Risk
 
 Financial instruments which potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents and accounts receivable.  The Company maintains cash at 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 $82,102, the amount that may be subject to credit risk for the year ended December 31, 2008 is $898,560.
 
 The Company has recorded trade accounts receivable from the business operations. Management periodically evaluates the collectability of the trade receivables and believes that the Company’s receivables are fully collectable and that the risk of loss is minimal.
 
 j) Environmental Protection and Reclamation Costs
 
 The operations of the Company have been, and may 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.
 
 F -8
 Table of Contents
 
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 
 2.
SIGNIFICANT ACCOUNTING POLICIES (Continued)
 
 The Company’s policy is to meet or, if possible, surpass standards set by relevant legislation, by application of technically proven and economically feasible measures.  Environmental expenditures that relate to ongoing environmental and reclamation programs will be charged against statements of operations as incurred or  capitalized
and amortized depending upon their future economic benefits.  The Company does not currently anticipate any material capital expenditures for environmental control facilities because all property holdings are at early stages of exploration.  Therefore, estimated future removal and site restoration costs are presently considered minimal.
 
 k) Foreign Currency Translation
 
 United States funds are considered the Company’s functional currency.  Transaction amounts denominated in foreign currencies are translated into their United States dollar equivalents at exchange rates prevailing at the transaction date.  Monetary assets and liabilities are adjusted at each balance sheet date
to reflect exchange rates prevailing at that date, and non-monetary assets and liabilities are translated at the historical rate of exchange.  Gains and losses arising from restatement of foreign currency monetary assets and liabilities at each year-end are included in other comprehensive income.
 
 l) Other Equipment
 
 Computer equipment is stated at cost.  Provision for depreciation on computer equipment is calculated using the straight-line method over the estimated useful life of three years.
 
 m) Impairment of Long-Lived Assets
 
 In the event that facts and circumstances indicate that the costs of long-lived assets, other than oil and gas properties, may be impaired, and evaluation of recoverability would be performed.  If an evaluation is required, the estimated future undiscounted cash flows associated with the asset would be compared to the asset’s
carrying amount to determine if a write-down to market value or discounted cash flow value is required.  Impairment of oil and gas properties is evaluated subject to the full cost ceiling as described under Natural Oil and Gas Properties.
 
 n) Loss Per Share
 
 In February 1997, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 128, “Earnings Per Share” (“SFAS 128”).  Under SFAS 128, basic and diluted earnings per share are to be presented.  Basic earnings per share is computed by dividing
income available to common shareholders by the weighted average number of common shares outstanding in the period.  Diluted earnings per share takes into consideration common shares outstanding (computed under basic earnings per share) and potentially dilutive common shares.
 
 o) Income Taxes
 
 The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax bases of assets and liabilities, and their reported amounts in the financial statements, and (ii) operating loss and tax credit
carryforwards for tax purposes.  Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period.
 
 p) Financial Instruments
 
 The Company’s financial instruments consist of cash and cash equivalents, GIC receivable, accounts receivable, franchise tax prepaid, accounts payable, accrued liabilities and loan payable.
 
 F -9
 Table of Contents
 
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 
 2.
SIGNIFICANT ACCOUNTING POLICIES (Continued)
 
 It is management’s opinion that the Company is not exposed to significant interest or credit risks arising from these financial instruments.  The fair value of these financial instruments is approximated to their carrying values.
 
 q)      Comprehensive Loss
 
 SFAS No. 130, “Reporting Comprehensive Income,” establishes standards for the reporting and display of comprehensive loss and its components in the financial statements. The Company is disclosing this information on its Consolidated Statements of Changes in Stockholders’ Equity and Consolidated Statement of Operations.
 
 r)      Stock-Based Compensation
 
 The Company records stock-based compensation in accordance with SFAS 123(R), “Share-Based Payments,” which requires the measurement and recognition of compensation expense based on estimated fair values for all share-based awards made to employees and directors, including
stock options. In March 2005, the Securities and Exchange Commission issued SAB 107 relating to SFAS 123(R). The Company applied the provisions of SAB 107 in its adoption of SFAS 123(R).
 
 SFAS 123(R) requires companies to estimate the fair value of share-based awards on the date of grant using an option-pricing model. The Company uses the Black-Scholes option-pricing model as its method of determining fair value. This model is affected by the Company’s stock price as well as assumptions regarding a number of subjective
variables. These subjective variables include, but are not limited to the Company’s expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise behaviors. The value of the portion of the award that is ultimately expected to vest is recognized as an expense in the statement of operations over the requisite service period.
 
 All transactions in which goods or services are the consideration received for the issuance of equity instruments are accounted for based on the fair value of the consideration received or the fair value of the equity instrument issued, whichever is more reliably measurable.
 
 3.
RECENT ACCOUNTING PRONOUNCEMENTS
 
 In December 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 141R, “Business Combinations”. This statement replaces SFAS 141 and defines the acquirer in a business combination as the entity that obtains control of one or more businesses in a business combination and establishes the acquisition date as the
date that the acquirer achieves control. SFAS 141R requires an acquirer to recognize the assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree at the acquisition date, measured at their fair values as of that date. SFAS 141R also requires the acquirer to recognize contingent consideration at the acquisition date, measured at its fair value at that date. This statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December
15, 2008, and earlier adoption is prohibited. The adoption of this statement is not expected to have a material effect on the Company's financial statements.
 
 In December 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements Liabilities –an Amendment of ARB No. 51”. This statement amends ARB 51 to establish accounting and reporting standards for the Non-controlling interest in a subsidiary
and for the deconsolidation of a subsidiary. This statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008, and earlier adoption is prohibited. The adoption of this statement is not expected to have a material effect on the Company's future financial statements.
 
 In March 2008, the FASB issued Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS 161”), which is effective January 1, 2009.  SFAS 161 requires enhanced disclosures about derivative instruments and hedging activities to allow for a better understanding of their effects on an
entity’s
 
 F -10
 Table of Contents
 
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 
 3.
RECENT ACCOUNTING PRONOUNCEMENTS (continued)
 
 financial position, financial performance, and cash flows.  Among other things, SFAS 161 requires disclosures of the fair values of derivative instruments and associated gains and losses in a tabular formant.
 SFAS 161 is not currently applicable to the Company since the Company does not have derivative instruments or hedging activity.
 
 In May 8, 2008, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 162, the Hierarchy of Generally Accepted Accounting Principles, which will provide framework for selecting accounting principles to be used in preparing financial statements that are presented in conformity with
U.S. generally accepted accounting principles (GAAP) for nongovernmental entities.  With the issuance of SFAS No. 162, the GAAP hierarchy for nongovernmental entities will move from auditing literature to accounting literature.  The adoption of this statement is not expected to have a material effect on the Company’s financial statements.
 
 In June 2008, the FASB issued FASB Staff Position Emerging Issues Task Force (EITF) No. 03-6-1, determining whether instruments granted in share-based payment transactions are participating securities (“FSP EITF No. 03-6-1”).  Under FSP EITF No. 03-6-1, unvested share-based payment awards that
contain rights to receive non-forfeitable dividends (whether paid or unpaid) are participating securities, and should be included in the two-class method of computing EPS. FSP EITF No. 03-6-1 is effective for fiscal years beginning after December 15, 2008, and interim periods within those years, and is not expected to have a significant impact on the Company’s financial statements.
 
 4.           NATURAL GAS AND OIL PROPERTIES
 
 a)      Proved Properties
 Properties

December 31, 2007


Additions


Disposals


Depletion for the year


Impairment


December 31, 2008USA properties

$
1,197,630


$
1,375,949


$
(754,647
)

$
(191,522
)

$
(760,629
)

$
866,781Canada properties


235,146



496,688



-



(73,461
)


(633,058
)


25,315Total

$
1,432,776


$
1,872,637


$
(754,647
)

$
(264,983
)

$
(1,393,687
)

$
892,096
 
 
 F -11
 Table of Contents
 
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 
 4.           NATURAL GAS AND OIL PROPERTIES
 
 a)      Proved Properties
 
 Properties in U.S.A.
 
 i. Oklahoma, USA
 
 In June 2006, the Company entered into an agreement to accept the assignment of an undivided 20% working interest in a potential oil well known as the Powell#2 and an option to purchase a 20% interest in all future wells drilled on the land surrounding Powell#2.  In addition the Company has an option to participate in any lands
of mutual interest that may be acquired in the future by the Owl Creek participating partners.  On June 30, 2008, the cost to the Company for this assignment was $394,499.  On August 20, 2008, the Company assigned all of its interest in exchange for a cash amount of $760,438.
 
 In July 2006, the Company also elected to participate in Isbill #1-36, which was abandoned during the year.  Its costs amounted to $80,738 was moved to the proven cost pool for depletion.
 
 In January 2007, the Company elected to participate in Isbill #2-36 well.  The Company paid $187,559 for its 20% of working interest.  Isbill #2-36 started production from April 2007.  On July 31, 2008, the Company expended $196,181 on Isbill #2-36.  On August 20, 2008, the Company assigned all of
its interest in exchange for a cash amount of $549,388.
 
 In April 2007, the Company entered into the 2006-3 Drilling Program for a buy-in cost of $113,700 which will provide 12.5% Before Casing Point (“BCP”) working interest and After Casing Point (“ACP”) working interest of 10%.  In September 2007, Wolf#1-7 was abandoned. Its costs amount to $68,118 was moved
to the proven cost pool for depletion.  In October 2007, Ruggles #1-15 was also abandoned and the cost of $84,328 was moved to the proven cost pool for depletion.
 
 In October 2007, the Company elected to participate in Powell #3-25 and paid $112,319 for the estimated drilling costs.  Powell #3-25 was abandoned on November 9, 2007.  Its costs amounted to $81,998 was moved to the proven cost pool for depletion.  The unused estimated drilling costs were applied to operating
costs of other wells.
 
 In the 2006-3 Drilling Program, Elizabeth #1-25 was plugged abandoned on February 7, 2008.  Its cost amounted to $127,421 was moved to the proven cost pool for depletion.  Plaster #1-11 and Dale #1-15 started producing in January and February 2008, respectively, total cost of $205,064 was moved to the proven cost pool.
 
 In the 2007-1 Drilling Program, Pollack #1-35 was plugged and abandoned on January 19, 2008.  Its cost amounted to $150,841 was moved to the proven cost pool for depletion.  Hulsey #1-8 started producing in February 2008; the cost of $161,039 was moved to the proven cost pool.  River #1-28 started producing
in June 2008; the cost of $150,582 was moved to the proven cost pool.
 
 ii. Palmetto Point Prospect, Mississippi, USA
 
 On February 21, 2006, the Company entered into an agreement (the “Agreement”) with 0743608 B.C. Ltd., (“Assignor”) a British Columbia, Canada based oil and gas exploration company, in order to accept an assignment of the Assignor’s ten percent (10%) gross working and revenue interest in a ten-well drilling
program (the “Drilling Program”) to be undertaken by Griffin & Griffin Exploration L.L.C., (“Griffin”) a Mississippi based exploration company.  Under the terms of the Agreement, the Company paid the Assignor $425,000 as payment for the assignment of the Assignor’s 10% gross working and revenue interest in the Drilling Program.  The Company also entered into a joint Operating Agreement directly with Griffin on February 24, 2006.
 
 F -12
 Table of Contents
 
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 
 4.           NATURAL GAS AND OIL PROPERTIES (Continued)
 
 a) Proved Properties - Descriptions
 
 Properties in U.S.A.
 
 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 abandoned properties were added to the capitalized cost in determination of the depletion expense.
  On August 4, 2006, the Company elected to participate in an additional two well program in Mississippi owned by Griffin & Griffin Exploration and paid $70,000.  As of December 31, 2008, both wells were found to be proved wells.
  On October 10, 2007, the Company elected to participate in the drilling of PP F-12 and PP F-12-3 in Mississippi operated by Griffin & Griffin Exploration.  The Company’s 10% of the estimated drilling costs was $88,783. PP F-12 started production from October 2007, and PP F-12-3 started production from November 2007.  An
additional AFE in the amount of $36,498 for workovers on the PP F-12, PP F-12-3 was paid on January 31, 2008.
  On January 11, 2008, the Company paid $11,030 for PP F-41salt water disposal well.
  iii. Mississippi II, Mississippi, USA
 
 In August 2006, the Company entered into a joint venture agreement with Griffin & Griffin Exploration, LLC. to acquire an interest in a drilling program comprised of up to 50 natural gas and/or oil wells.  The area in which the wells are to be drilled is comprised of approximately 300,000 gross acres of land located between
Southwest Mississippi and North East Louisiana. The wells are targeting the Frio and Wilcox Geological formations. The Company has agreed to pay 10% of all prospect fees, mineral leases, surface leases and drilling and completion costs to earn a net 8% share of all production zones to the base of the Frio formation and 7.5% of all production to the base of the Wilcox formation.  In January 2007, the well CMR USA 39-14 was found to be proved.  The cost of $35,126 was added to the proven
cost pool.  Dixon#1 was abandoned in January 2007, its costs amounted to $40,605 was moved to the proven cost pool for depletion.  Randall#1 was abandoned in June 2007, its costs amounted to $26,918 was moved to the proven cost pool for depletion.  BR F-24 was abandoned and its cost amounted to $41,999 was moved to the proven cost pool for depletion.  Faust #1, USA 1-37 and BR F-33 were found to be proven and the total cost of $129,360 was added to the proven cost pool.
 
 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.
 
 F - 13
 Table of Contents
 
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 
 4.           NATURAL GAS AND OIL PROPERTIES (Continued)
 
 a) Proved Properties - Descriptions
 
 Properties in Canada
 
 v.         Wordsworth Prospect, Saskatchewan, Canada
 
 On April 10, 2006, the Company entered into an agreement (the “Agreement”) with Petrex Energy Ltd., for a participation and Farmout agreement where the Company will participate for 15% gross working interest before payout (BPO) and 7.5% gross working interest after pay out (APO) in a proposed four well horizontal drilling program
in the Wordsworth area in Southeast Saskatchewan, Canada. The well, HZ 1C2-23 was drilled in September 2008 also started production from November 2008.  As at December 31, 2008, the Company had advanced $338,557 as its share of the costs in this Agreement.  Currently, there are two producing wells on this prospect.
 
 vi.       Todd Creek, Alberta, Canada
 
 In January 2005, the Company acquired a 20% working interest in 13.75 sections (8,800 acres) of land in Todd Creek, Alberta, Canada, at a cost of $597,263.  One of the wells, 13-28-9-2W5M, has had production since October 2006.
 
 The Company paid $314,959 (CDN$352,376) on October 27, 2006 for well 13-33-8-2W5M.  It was abandoned and the cost was moved to the proved properties cost pool for depletion.  During the year ended of December 31, 2007, the remaining wells at Todd Creek were abandoned and the cost was moved to the proven cost pool for
depletion.
  vii.       Hillspring, Alberta, Canada
 
 In January 2005, the Company acquired a 10% working interest in 1 section (64 acres) of land in Hillspring, Alberta, Canada, at a cost of $414,766.   During the year ended of December 31, 2007, it was abandoned and the cost was moved to proven cost pool for depletion.
  viii.      Strachan Prospect, Alberta, Canada
 
 In September 2005, the Company entered into a participation and farm-out agreement with Odin Capital Inc. (“Odin”) where the Company will participate for 4% share of the costs of drilling a test well in certain lands located in the Leduc formation, Alberta, Canada.  In exchange for the participation costs, the Company
will earn interests in certain petroleum and natural gas wells ranging from 1.289% to 4.0%.  The Company has advanced $388,662 as its share of the costs in the Leduc formation property.  The well was abandoned in the three month ended of March 31, 2008; the cost of $388,662 was moved to the proven cost pool for depletion.




F - 14
 Table of Contents
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 
 4.           NATURAL GAS AND OIL PROPERTIES (continued
 
 b)   Unproved Properties
 
 Properties

December 31, 2007


Addition


Transfer to proved properties


December 31, 2008USA properties

$
781,446


$
454,842


$
(805,977
)

$
430,311Canada properties


586,814



111,235



(497,984
)


200,065Total

$
1,368,260


$
566,077


$
(1,303,961
)

$
630,376
 
 (c)   Costs Not Being Amortized
  The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2008, 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


2008


2007


2006


2005
and PriorProperty acquisition costs and Transfer
to Proved Property Pool.


19,875



-



19,875



-



-Exploration and development


610,501



-



-



-



610,501Capitalized interest


-



-



-



-



-Total


630,376



-



19,875




-


610,501
 Properties in U.S.A.
  i.    Oklahoma, USA
 
 In April 2007, the Company entered into the 2006-3 Drilling Program for a buy-in cost of $113,700 which will provide 12.5% Before Casing Point (“BCP”) working interest and After Casing Point (“ACP”) working interest of 10%.
 
 In September 2007, the Company entered into the 2007-1 Drilling Program for a buy-in cost of $77,100 which will provide 25% Before Casing Point (“BCP”) working interest and 20% After Casing Point (“ACP”) working interest.  During August to September 2008, the Company paid estimated drilling costs of $82,830
and estimated completion costs of $80,905 for the well, Hulsey #2-8.
 
 ii.    Mississippi II, Mississippi, USA
 
 In August, 2006, the Company entered into a joint venture agreement with Griffin & Griffin Exploration, LLC. to acquire an interest in a drilling program comprised of up to 50 natural gas and/or oil wells.  The area in which the wells are to be drilled is comprised of approximately 300,000 gross acres of land located between
Southwest Mississippi and North East Louisiana. The wells are targeting the Frio and Wilcox Geological formations. The Company has agreed to pay 10% of all prospect fees, mineral leases, surface leases and drilling and completion costs to earn a net 8% share of all production zones to the base of the Frio formation and 7.5% of all production to the base of the Wilcox formation.
 
 Properties in Canada
 
 iii.   Wordsworth Prospect, Saskatchewan, Canada
 
 In April 2007, the Company entered into an agreement (the “Agreement”) with Petrex Energy Ltd., for a participation and Farmout agreement whereby the Company will participate in a 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, 2008, the Company had expended $162,996 on the well 3B9-23/3A11.  In March 2008, the Company joined the drilling of a new well, 2 HZ 3B9 LEG.  As at December 31, 2008, the Company had expended $37,070 on this well.
 F - 15
 Table of Contents
 
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 
 5. NATURAL GAS AND OIL EXPLORATION RISK
 
 a)  Exploration Risk
 
 The Company’s future financial condition and results of operations will depend upon prices received for its natural gas and oil production and the cost of finding, acquiring, developing and producing reserves.  Substantially all of its production is sold under various terms and arrangements at prevailing market prices.  Prices
for natural gas and oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond its control.  Other factors that have a direct bearing on the Company’s prospects are uncertainties inherent in estimating natural gas and oil reserves and future hydrocarbon production and cash flows, particularly with respect to wells that have not been fully tested and with wells having limited production histories; access to additional capital; changes
in the price of natural gas and oil; availability and cost of services and equipment; and the presence of competitors with greater financial resources and capacity.
 
 b)    Distribution Risk
 
 The Company is dependent on the operator to market any oil production from its wells and any subsequent production which may be received from other wells which may be successfully drilled on the Prospect.  It relies on the operator’s ability and expertise in the industry to successfully market the same.  Prices
at which the operator sells gas/oil both in intrastate and interstate commerce; will be subject to the availability of pipe lines, demand and other factors beyond the control of the operator.  The Company and the operator believe any oil produced can be readily sold to a number of buyers.
 
 c) Credit Risk
 
 A substantial portion of the Corporation’s accounts receivable is with joint venture partners in the oil and gas industry and is subject to normal industry credit risks.
 
 d) Foreign Operations Risk
 
 The Company is exposed to foreign currency fluctuations, political risks, price controls and varying forms of fiscal regimes or changes thereto which may impair its ability to conduct profitable operations as it operates internationally and holds foreign denominated cash and other assets.
 
 6. 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.
 
 The effective income tax rate for years ended December 31, 2008 and the year ended December 31, 2007 differs from the U.S. Federal statutory income tax rate due to the following:
 
 2008


2007Federal statutory income tax rate


(34.0
%)


(34.0
%)State income taxes, net of federal benefit


(3.77
%)


(3.77
%)Permanent differences in debt


0
%


0.00
%Increase in valuation allowance


37.77
%


37.77
%Net income tax provision (benefit)


—



—
 
 
 F - 16
 Table of Contents
 
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 
 6. INCOME TAXES PAYABLE (continued)
 
 The Canadian corporate tax rate for 2008 is 25%. The effective weighted average tax rate for the years ended December 31, 2008 and December 31, 2007 is 34%.
 
 A reconciliation of income taxes at statutory rates with the reported taxes is as follows:
 
 2008


2007Loss before income taxes

$
(212,431
)

$
(2,234,379
)Income tax recovery at 34% (estimated)


72,227



759,689Unrecognized benefit of operating loss carry forwards


(72,227
)


(759,689
)Franchise tax


3,395



15,5803,395



15,580
 
 Significant components of the Company’s deferred income tax assets are as follows:
 
 2008


2007Operating loss carry forwards

$
3,457,724


$
3,248,398Natural gas and oil properties


1,610,527



2,578,0865,068,251



5,826,484Statutory tax rate


34
%


34
%Deferred income tax asset


1,723,205



1,981,005Valuation allowance


(1,723,205
)


(1,981,005
)Net deferred tax assets

$
-


$
-
 
 The Company has approximately $3,457,724 (2007 - $3,248,398) of operating loss carry forwards which expire beginning in 2025.  The Company has natural gas and oil properties available to further reduce taxable income of $1,610,527.
 
 The company has provided a valuation allowance against its deferred tax assets given that it is in the development stage and it is more likely than not that these benefits will not be realized.
 
 7. ASSET RETIREMENT OBLIGATIONS
 
 The Company follows SFAS 143 “Accounting for asset retirement obligations”.  SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.  SFAS 143 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, 2008 and December 31, 2007, we recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with SFAS No. 143.  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.
 
 F - 17
 Table of Contents
 
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 
 7. ASSET RETIREMENT OBLIGATIONS (continued)
 
 The information below reflects the change in the asset retirement obligations during the years ended December 31, 2008 and 2007:
 
 December 31,


December 31,2008


2007Balance, beginning of year

$
111,803


$
40,635Liabilities assumed


8,898



66,292Revisions


(99,626
)


-Accretion expense


2,529



4,876Balance, end of year

$
23,604


$
111,803
 
 8. SHARE CAPITAL
 
 i. Common Stock
 
 On January 11, 2006, the Company issued 75,000 common shares for exercise of stock options at $0.80 per share.
 
 On January 24, 2006, the Company issued 230,000 common shares for exercise of stock options at $0.80 per share.
 
 On January 25, 2006, the Company issued 12,500 common shares for exercise of stock options at $1.00 per share.
 
 On April 25, 2006, the Company issued 727,271 common shares pursuant to a private placement at $2.75 per share.
 
 On January 23, 2007, the Company issued 60,000 common shares for exercise of stock options at $0.75 per share.
 
 On March 1, 2007, the Company issued 500,000 common shares to the President and CEO as part of his compensation package.  The price of the share as of March 1, 2007 was $0.92.
 
 On May 1, 2007, the Company issued 60,000 common shares to Investor Relations Services, Inc. as part of the investor relation services and consulting agreement.  The price of the share as of May 1, 2007 was $0.68.
 
 On July 8, 2007, the Company issued 250,000 common shares to its Chief Financial Officer as compensation for his services rendered and in lieu of cancellation of stock options.  The price of the share was $0.55, being the average of the share price of July 6 and July 9, 2007.
 
 On August 13, 2008, the Company issued 900,000 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 $0.053.
 
 Preferred Stock
 
 The Company did not issue any preferred stock during the period ended December 31, 2008 (December 31, 2007 - $ Nil).
 
 F - 18
 Table of Contents
 
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 
 8. SHARE CAPITAL (continued)
 
 ii. Stock Options
 
 Compensation expense related to stock options granted is recorded at their fair value as calculated by the Black-Scholes option pricing model.  Options exercised for the year ended December 31, 2008 was nil (Year ended December 31, 2007 - $42,097, related to options granted during the year ended December 31, 2007).  The
changes in stock options are as follows:
 
 Number


Weighted average
exercise priceBalance outstanding, December 31 2007


240,000


$
0.75Granted


-



-Forfeited


-



-Exercised


-



-Balance outstanding, December 31 2008


240,000


$
0.75
 
 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:
 
 Year ended December 31, 2008


Year ended December 31, 2007Risk-fee interest rate


0.00
%


3.77
%Expected life of the option

0 years


3 yearsExpected volatility


0.00
%


69.03
%Expected dividend yield


-



-
 
 
 The following table summarized information about the stock options outstanding as at December 31, 2008:
 
 Options outstanding

Options exercisableExercise price
Number of shares
Remaining contractual life (years)

Number of shares$ 0.75
240,000
0.22

240,000
 
 iii.   Common Stock Share Purchase Warrants
 
 As at December 31, 2008, share purchase warrants outstanding for the purchase of common shares as follows:
  Warrants outstanding
 Exercise price
Number of shares
Expiry date$ 1.50
$ 3.00
2,483,985
727,271
February 1, 2010
April 30, 2009
 
 No warrants were issued during the years ended December 31, 2008 and December 31, 2007.
 
 F - 19
 Table of Contents
 
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 
 10. RELATED PARTIES
 
 During the year ended December 31, 2008, the Company paid $179,893 (December 31, 2007 - $122,814) for consulting fees and $39,750 for accounting services to Companies controlled by directors and officers of the Company.  Amounts paid to related parties are in the normal course of business and are based on exchange amounts agreed
upon by those related parties.
 
 On August 13, 2008, the Company issued 900,000 shares of common stock in consideration for services rendered to Officers of the Company.  The price of the Company’s shares as of August 13, 2008 was $0.053.  The total cost of $47,700 was recorded in the compensation expense for shares granted and was included in
the general and administration expense.
 
 These shares were issued pursuant to Section 4(2) of the Securities Act of 1933, as amended.
 
 11. COMMITMENT AND CONTRACTURAL OBLIGATIONS
 
 A lease agreement for the Vancouver, Canada office commenced June 1, 2008 and terminates on May 31, 2009.  The lease agreement provides a fixed rental fee of $1,425 per month plus additional charges for services supplied by the landlord or incurred on behalf of the Company in the previous month.
 
 The Company also rents an office in Calgary, Canada on a month to month basis for $295 per month.
  12. SEGMENTED INFORMATION
  In accordance with SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, 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, 2008


December 31, 2007RevenueUnited States

$
1,816,335


$
764,507Canada


111,204



149,301Total Revenue

$
1,927,539


$
913,808
 
 AssetsUnited States

$
1,346,373


$
2,140,338Canada


1,233,640



1,149,323Total Assets

$
2,580,013


$
3,289,661
 
 LiabilitiesUnited States

$
46,508


$
216,629Canada


3,649



61,391Total Liabilities

$
50,157


$
278,020
 
 
 F - 20
 Table of Contents
 
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 
 13. SUBSEQUENT EVENT
 
 On February 9, 2009, the Company’s S-4 Registration statement was approved by the SEC for the acquisition of The Stallion Group (“Stallion”) by way of an offer to purchase all the outstanding shares of Stallion in exchange for 0.333333 shares of the Company and $0.0008 cash.  The offer expired on March 26, 2009
at 5.00pm Eastern Standard Time,  and the Company will issue 19,545,026 common shares and $46,908.10 in cash to the holders of The Stallion’s Group’s common stock that were tendered.
  14.           UNAUDITED OIL AND GAS RESERVE QUANTITIES
 
    2006Property acquisition costs:

USA


Canada


TotalProved


300,325



-



300,325Unproved


-



-



-Development costs


-



-



-Exploratory costs


519,400



845,681



1,365,081Oil and gas expenditures


819,725



845,681



1,665,4062007Property acquisition costs:

USA


Canada


TotalProved


36,575



-



36,575Unproved


154,225



-



154,225Development costs


-



-



-Exploratory costs


1,403,137



265,656



1,668,793Oil and gas expenditures


1,593,937



265,656



1,859,5932008Property acquisition costs:

USA


Canada


TotalProved


57,250



-



57,250Unproved


(57,250
)


-



(57,250
)Development costs


-



-



-Exploratory costs


591,664



117,822



709,486Oil and gas expenditures


591,664



117,822



709,486
 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 - 21
 Table of Contents
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 14.           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 GasChanges in proved reserves

(Bbls)


(MCF)Estimated quantity, December 31, 2006


72,341



113,947Revisions of previous estimate


(17,150
)


0Discoveries


31,217



86,107Production


(11,514
)


(33,394
)Estimated quantity, December 31, 2007


74,894



166,660Revisions of previous estimate


0



(120,951
)Discoveries


174,199



36,205Reserves sold to third party


(36,543
)


0Production


(3,377
)


(28,559
)Estimated quantity, December 31, 2008


209,173



53,355
 
 
 Proved Reserves at year end

Developed


Undeveloped


TotalCrude Oil (Bbls)December 31, 2008


190,983



18,190



209,173December 31, 2007


57,764



17,130



74,894Gas (MCF)December 31, 2008


53,355



-



53,355December 31, 2007


166,660



-



166,660
 
 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 - 22
 Table of Contents
 Delta Oil & Gas, Inc.
 (A Development Stage Company)
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER 31, 2008
 (Stated in U.S. Dollars)
 14.           UNAUDITED OIL AND GAS RESERVE QUANTITIES (continued)
 
 December 31, 2008


December 31, 2007Future Cash inflows

$
2,133,418


$
5,291,324Future production costs


(651,954
)


(746,110
)Future development costs


(280,904
)


(25,990
)Future income tax expense


(79,138
)


(305,675
)Future cash flows


1,121,422



4,213,54910% annual discount for estimated timing of cash flows


(152,871
)


(1,453,674
)Standardized measure of discounted future next cash

$
968,550


$
2,759,875
 
 
 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,
2008


December 31,
2007Beginning of year

$
2,759,875


$
2,119,304Sales and transfers of oil and gas produced, net production costs


(3,157,906
)


946,808Net changes in prices and production costs and other


94,156



(746,110
)Net changes due to discoveries


1,300,802



771,538Changes in future development costs


(254,914
)


(25,990
)Revisions of previous estimates


-



-Other


-



-Net change in income taxes


226,537



(305,675
)Accretion discount


-



-Future cash flows


(1,791,325
)


640,571End of year

$
968,550


$
2,759,875
 F - 23
 Table of Contents


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/A to be signed on its behalf by the undersigned, thereunto duly authorized, this  16th day of October, 2009.
  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

October 16, 2009Christopher Paton-Gay, Chief Executive Officer and Director/s/ Douglas N. Bolen

October 16, 2009Douglas N. Bolen, President and Director/s/ Kulwant Sandher

October 16, 2009Kulwant Sandher, Chief Financial Officer and Director








- 39 -
 Table of Contents
 
 DELTA OIL & GAS, INC.
  EXHIBIT INDEX
 TO
 2008 ANNUAL REPORT ON FORM 10-K
 
 Exhibit
Number
Description
Incorporated by Reference to:
Filed Herewith3.1
Amended and Restated Articles of Incorporation of Delta.
Exhibit 3 of Delta’s Form SB-2 filed on February 13, 20023.2
By-laws of Delta, as amended.
Exhibit 3 of Delta’s Form SB-2 filed on February 13, 2002.10.1
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, File No.  000-5200110.2
Assignment Agreement by and between Delta and Production Specialties Company dated November 8, 2006.
Exhibit 10.1 of Delta’s Form 10QSB dated November 20, 2006, File No. 000-52001.10.3
Assignment Agreement by and between Brinx Resources Ltd. and Delta.
Exhibit 10.1 of Delta’s Form 8-K dated June 2, 2006, File No. 000-5200.10.4
Drilling Program Agreement by and between Griffin & Griffin Exploration, L.L.C. and 0743608 B.C. Ltd. dated December 21, 2005.
Exhibit 10.1 of Delta’s Form 8-K dated February 27, 2006, File No. 333-82636.10.5
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, File No. 333-82636.10.6
Farmout Agreement by and between Production Specialties Company and Delta dated May 25, 2005.
Exhibit 10.1 of Delta’s Form 8-K dated September 29, 2005, File No. 333-82636.10.7
Participation Proposal by and between Win Energy Corporation and Delta dated November 26, 2004
Exhibit 10.1 of Delta’s Form 8-K dated February 15, 2005, File No. 333-82636.10.8
Assignment Agreement with 0743608 B.C. Ltd dated February 21, 2006.
Exhibit 10.2 of Delta’s Form 8-K dated February 27, 2006, File No. 333-8263610.9
Participation Proposal with Win Energy Corporation dated November 26, 2004.
Exhibit 10.2 of Delta’s Form 8-K dated February 15, 2005, File No. 333-82636.10.10
Letter Agreement by and between Win Energy Corporation and Delta dated December 26, 2004.
Exhibit 10.3 of Delta’s Form 8-K dated February 15, 2005, File No. 333-82636.10.11
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, File No. 000-52001.10.12
Consulting Agreement by and between Delta and Last Mountain Investments, Inc. dated March 1, 2006.
Exhibit 10.10 of Delta’s Form 10SB12G/A dated February 27, 2007, File No. 000-52001.10.13
Consulting Agreement by and between Delta and Hurricane Corporate Services Ltd. dated January 1, 2008.
Exhibit 10.13 of Delta's Registration Statement, Form S-4 filed January 23, 2009, File No. 000-52001.
  
 - 40 -
 Table of Contents
 
 
 Exhibit
Number
Description
Incorporated by Reference to:
Filed Herewith21.1
Subsidiaries of Delta.
Exhibit 21.1 of Delta's Form 10-K filed
on March 31, 2009, File No. 000-52001.31.1
Certificate of Christopher Paton-Gay, Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

X31.2
Certificate of Kulwant Sandher, Chief Finance Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

X32.1
Certificate of Christopher Paton-Gay, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

X32.2
Certificate of Kulwant Sandher, Chief Finance Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

X
 
 
 
 - 41 -