UNITED STATES


SECURITIES AND EXCHANGE COMMISSION


Washington, D.C.  20549




Form 10-K/A


(Amendment No.  1)





ý
ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2010 ̈
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period from ___________ to ___________.





Commission file number:  000-52001




Delta Oil & Gas, Inc.


(Exact name of registrant as specified in its charter)




Colorado

91-210350(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)Suite 604 - 700 West Pender Street, Vancouver, British Columbia Canada, V6C 1G8(Address of principal executive offices)                            (Zip Code)Registrant’s telephone, including area code:   (866) 355-3644





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




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


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


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




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




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




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




Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.




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





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




As of June 30, 2010, the aggregate market value of the Company’s common equity held by non-affiliates computed by reference to the closing price 0.12 was:$1,211,160




The number of shares of our common stock outstanding as of March 30, 2011 was: 14,157,107







Table of Contents












Explanatory Note
  Delta Oil & Gas, Inc. (the “Company”) is filing this Amendment No. 1 to its Annual Report for the fiscal year ended December 31, 2010 on Form 10-K which was originally filed with the Securities and Exchange Commission (“SEC”) on March 31, 2011 (the “2010 Form 10-K”), to incorporate the Company’s revisions and responses to comment letters from the SEC dated December 20, 2011 and May 15, 2012.
  As a consequence of these revisions, the Company is also filing new certifications of its Chief Executive Officer and Chief Financial Officer, with conforming changes, as Exhibits 31.1, 31.2, 32.1 and 32.2.
  Except for the amended disclosures made in response to the comment letter and the correction of certain typographical errors, the information in this Form 10-K/A has not been updated to reflect events that occurred after March 31, 2011, the filing date of the 2010 Form 10-K.  Accordingly, this Form 10-K/A should be read in conjunction with the Company’s filings made with the SEC subsequent to the filing of the 2010 Form 10-K. The following sections have been amended, “Item 2 - Properties,” and “Item 15.  Exhibits, Financial Statement Schedules.” Except for the amended sections, all other information in the Company’s Original Form 10-K remains
unchanged.

















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FORM 10-K/A


DELTA OIL & GAS, INC.


DECEMBER 31, 2010









Table of Contents


PagePART IItem 1.
Business
6Item 1A.
Risk Factors.
14Item 1B.
Unresolved Staff Comments.
22Item 2.
Properties.
22Item 3.
Legal Proceedings.
30Item 4.
Reserved.
30PART IIItem 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
31Item 6.
Selected Financial Data.
33Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
33Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
38Item 8.
Financial Statements and Supplementary Data.
38Item 9.
Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.
38Item 9A.
Controls and Procedures.
38Item 9B.
Information.
39PART IIIItem 10.
Directors, Executive Officers and Corporate Governance.
40Item 11.
Executive Compensation.
40Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
40Item 13.
Certain Relationships and Related Transactions, and Director Independence.
40Item 14.
Principal Accounting Fees and Services.
40PART IVItem 15.
Exhibits, Financial Statement Schedules.
41GlossarySignature PageExhibit Index








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Cautionary Note Regarding Forward Looking Statements




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




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




·
changes in our business strategy;




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




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




·
results of current and future exploration activities;




·
results of pending and future feasibility studies;




·
accidents and labor disputes;




·
disappointing results from our exploration or development efforts;




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




·
decline in demand for our common stock;




·
changes in general market conditions;




·
investor perception of our industry or our prospects;




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




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




·
the availability of pipeline capacity;




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




·
the availability of alternate fuel sources;




·
the effect of inclement weather, such as hurricanes;




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




·
unexpected changes in business and economic conditions;




·
changes in interest rates and currency exchange rates;




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




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




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




·
local and community impacts and issues.











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




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




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






















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PART I




ITEM 1. BUSINESS.




Business of Delta




We were incorporated under the laws of the State of Colorado on January 9, 2001 under the name Delta Oil & Gas, Inc.





We are engaged in the acquisition, development and production of oil and natural gas properties in North America.  We seek to acquire and develop properties with undeveloped reserves that are economically attractive to us.  We will employ expertise in geological and geophysical areas to mitigate, as far possible, the inherent risk of oil and gas exploration.  We seek to create value and reduce risks through the acquisition and development of property interests in areas that have:





·
Significant undeveloped reserves;


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


·
Existing infrastructure or the ability to install our own infrastructure of oil and natural gas pipelines and production platforms.





During the 1st and 2nd Quarters of 2010, Management engaged in a detailed strategic review of all of our development lands, exploratory lands and working interest Partners held at that time.  The outcome of these reviews lead to an internal declaration of core and non-core properties. Those properties within the ‘Core’ were to receive priority focus for development and expansion and those in the ‘non-core’ grouping were to be considered as low priority for development and considered for divestment should offers fall within range of their true values.





Historically, Delta has taken small working interest positions in multiple and diverse projects.  Under our new Core / Non-core strategy Delta will generally focus on larger working interest relationships in substantive project areas and move to strategically explore and develop those projects.  The sale of our Saskatchewan, Canada Wordsworth interests are a case in point. We believe that this core strategy will enable us to develop Delta Oil and Gas to the next level in its growth towards becoming a significant oil and natural gas producing entity.





Our current focus is on the exploration of our Core land portfolio comprised of substantial working interests in acreage in King City, California; Northern California and Eastern Texas.  As a result of our acquisition in March 2009 of a controlling interest in The Stallion Group, a Nevada corporation, we expanded our property interests to include acreage in the North Sacramento Valley, California.





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





CORE PROPERTIES




Texas Prospect




On July 15, 2009, we entered into an assignment agreement with Mr. Barry Lasker (the “Assignor”) and were assigned all of Assignor’s rights and obligations under two oil, gas and liquid hydrocarbon lease agreements, each dated March 26, 2009 (the “Leases”) covering an aggregate area of approximately 243 acres in Newton County, Texas (the “Texas Prospect”).  These Leases provide us with the ability to drill up to 3 exploration wells.  The costs of the leases were $169,566.  In December 2009, we sold a sixty (60%) percent interest in the Leases to Hillcrest Resources Ltd. (“Hillcrest”) and received $111,424.  As at
December 31, 2010, the costs of the leases were $74,018.










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




Net Revenue DistributionBefore Payout

After PayoutWell #1
36%

20%Well #2
36%

24%Well #3
36%

24%







Under the terms of the Leases, we have the ability to participate in additional wells drilled in the Texas Prospect.  In the event that we elect to participate, we will negotiate with Hillcrest our respective levels of participation in additional wells.  Our percentage of the costs and net revenue distribution, both before and after payout, associated with each additional well will be proportional to our level of participation.  The Company is in the process of licensing and permitting 2 additional wells on these lands.  Drilling will commence as soon as permits have been issued.




The Company paid $304,478, as its proportionate share of the drilling and completion costs for the year ended December 31, 2010.  On June 4, 2010, the first well (the “Donner #1”) was successfully drilled and encountered hydrocarbons.  The well was completed and the well went into production during the quarter ended September 30, 2010.  The following represents the revenue from the drilling program:




Well Name

Year ended

Dec 31, 2010

Year ended

Dec 31, 2009Donner #1

$121,576

$nil







Lonestar Prospect, California, USA




On September 1, 2010, the Company entered into an agreement for the joint exploration and development of the Lonestar Prospect located in California, USA.  The Company is obligated to pay 25% of the costs in order to earn a 20% working Interest in the initial well, named internally  as California #1-1.  As at December 31, 2010, the Company had expended $329,804 in drilling and completion costs for California #1-1.  The revenue from this well for the year ended December 31, 2010 was $95,637.




King City, California




On May 25, 2009, we entered into a farm-out agreement with Sunset Exploration (“Sunset”), a California corporation, to participate in the drilling and exploration of lands located in Monterey County, California.  The prospect area where the drilling and exploration will take place is comprised of approximately 10,000 acres.  We are obligated to pay 66.67% of the costs of the initial test well up to casing point, in order to earn a 40.0% working interest.  Thereafter, we will be obligated to pay 40.0% of the costs of any future wells which we elect to participate in order to earn a 40.0% working interest.  We paid Sunset $100,000 as an advance towards the permitting
and processing of lands and the costs of a gravity survey and a 2D seismic program. We commenced a gravity survey and 2D seismic program in August 2009.  We have undertaken extensive reviews of the data provided from the program.  We are very encouraged by the results which appear to be indicating the potential for significant hydrocarbon targets.  Delta and its Partners are now working on setting the location for our 1st exploratory well.  We have agreed that we will permit a 2-3 well drilling program around the exploratory well and that we will commence drilling our 1st exploration well as soon as well licenses and drilling
permits have been issued.













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NON-CORE PROPERTIES




2009-3 Drilling Program - 4 Wells




On August 7, 2009, we entered into an agreement with Ranken Energy to participate in a four well drilling program in Garvin County, Oklahoma (the “2009-3 Drilling Program”).  We purchased a 6.25% working interest before casing point and 5.0% working interest after casing point in the 2009-3 Drilling Program for $37,775.  In addition to the total buy-in cost, we are responsible for our proportionate share of the drilling and completion costs.  During the year ended December 31, 2009, we paid additional drilling costs in the amount of $78,090.  The first well (the “Jackson #1-18”) started production during the quarter ending March 31, 2010 and the second
well (the “Miss Gracie #1-18”) started production during the quarter ending June 30, 2010.  The following represents the revenues from this drilling program:




Well Name

Year ended

Dec 31, 2010

Year ended

Dec 31, 2009Jackson #1-18

$38,844

$nilMiss Gracie #1-18

$199,392

$nilJoe Murray Farms

$94,446

$nil




The increase in revenues was due to wells not being in production for the corresponding prior year.  Drilling and completion costs of $154,581 were moved to the proved properties pool for depletion.




2009-1 Drilling Program - 5 Wells




On July 27, 2009, we entered into an agreement with Ranken Energy to participate in a five well drilling program in Garvin County, Oklahoma (the “2009-1 Drilling Program”).  We initially acquired a 5.0% working interest in the 2009-1 Drilling Program in exchange for our payment of a total of $13,125 in buy-in costs, which equates to $2,625 in buy-in costs for each well, plus our proportionate share of the drilling and completion costs.  During the fourth quarter of 2009, our working interest in the 2009-1 Drilling Program was reduced to 3.75%.  The reduction in our working interest was attributable to the landowner exercising an option to increase its working interest
causing in a proportional reduction to all working interests held in this drilling program.




During the year ended December 31, 2009, we paid estimated drilling and completion costs of $72,175for three wells which we refer to as Saddle #1-18, Saddle #2-18 and  Saddle #3-18.  The first three wells in this drilling program started to produce hydrocarbons during the quarter ending March 31, 2010.  Total revenue received from all three wells for the year ended December 31, 2010 was $41,830, (December 31, 2009: $nil).  The increase in revenue from the prior year was due to the wells not being in existence for the corresponding year.




2007-1 Drilling Program - 3 Wells




On September 10, 2007, we entered into an agreement with Ranken Energy to participate in a four well drilling program in Garvin County, Oklahoma (the “2007-1 Drilling Program”).  We purchased a 20% working interest in the 2007-1 Drilling Program for $77,100. Drilling of the first and second wells (the “Pollock #1-35” and the “Hulsey #1”) was completed in the N.E. Anitoch Prospect and the Washington Creek Prospect respectively.  The Pollock #1-35 did not prove to be commercially viable, but the Hulsey #1 has been producing in the range of approximately 50 to 60 barrels of oil per day with approximately 50 Mcf of natural gas per day since February
2008.




Drilling of the third well in this drilling program (the “River #1”) was completed during the three months ended September 30, 2008.  River #1 is currently in production and the total revenue received for the year ended December 31, 2010 was $35,857 (December 31, 2009: $47,468), the decrease in revenue was caused by a decrease in production, which was partially offset by an increase in commodity prices during the period.












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Hulsey #1-8 started producing during the first quarter of 2008 and the total revenue received for the year ended December 31, 2010 was $69,500 (December 31, 2009: $66,212).  The increase in revenue was caused by an increase in commodity prices during the period.




Hulsey #2-8 commenced production during the three months ended March 31, 2009 and produced $18,362 in oil revenues for the year ended December 31, 2010 (December 31, 2009: $20,034).  The small decrease is due to a decrease in production from this well which was offset by higher commodity prices during the period.  Our proportionate costs associated with the Hulsey #2-8 well amounted to $139,674, which was moved to the proved properties cost pool for depletion.




2006-3 Drilling Program




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




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




Three other wells drilled (the “Elizabeth #1-25”, the “Plaster #1-1” and the “Dale #1 re-entry”) were deemed by the operator to be commercially viable and production casing was set in each.  The Elizabeth #1-25 located in the Meridian Prospect cost $99,129, the Plaster #1-1 located in the Plaster Prospect cost $116,581, and re-entry into the Dale #1 located in the Dale Prospect cost $18,150, all of which was paid August and September, 2007.  Subsequent to the completion of these wells, two remain economically viable at this time.  The Plaster #1 encountered hydrocarbon showings and is producing natural
gas with amounts of associated oil as of January, 2008.  The Dale #1 re-entry has been producing in the range of 2 to 3 barrels of oil per day.  The Elizabeth #1-25 has been plugged and abandoned as of February 7, 2008.




Total revenue received from the Plaster #1 and Dale #1 wells for the for the year ended December 31, 2010 was $6,779 (December 31, 2009: $7,920).   The decrease in revenue for the year ended December 31, 2010 was caused by a decrease in production which was partially offset by higher commodity prices.




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.




Wordsworth Prospect




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




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




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










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




The revenue received from all wells in the Wordsworth Prospect for the year ended December 31, 2010 was $136,546 (December 31, 2009: $195,491).  The decrease in revenue was caused by the disposal of the Wordsworth prospect.  On July 1, 2010, we entered into a Purchase and Sale Agreement (the “Agreement”) with Petrex Energy Ltd. (“Petrex”) whereby Petrex agreed to purchase our remaining 5% working interest in the Wordsworth prospect and our right to participate in future wells in the Wordsworth prospect for CDN $757,500, inclusive of 5% GST on Tangibles, which equates to US $704,490; this resulted in a gain on sale of future revenues of $518,874.




Willows Gas Field




On February 15, 2007, Stallion, our majority-owned subsidiary, entered into a Farm Out Agreement with Production Specialties Company (“Production Specialties”) for participation in a natural gas prospect area located in the North Sacramento Valley, California.  On October 15, 2007, Stallion drilled its first prospect well paying 12.5% of the costs of the first well to earn a 6.25% working interest.  For subsequent wells, Stallion will pay 6.25% of the costs of future wells to earn 6.25% working interest.Stallion participated in the drilling of the first well (“Wilson Creek #1-27”)  on
the prospect area and encountered a number of prospective pay zones.  Testing was completed and stabilized flow rates exceeded a combined 1.5 million cubic feet per day of sweet high quality gas.  Thereafter, the Wilson Creek #1-27 was connected to a nearby pipeline and begun producing natural gas in April 2008.  Total costs for the Wilson Creek #1-27 well in the end year ended December 31, 2009 was $255,971.  During 2009 and in light of the lower natural gas commodity prices, we reviewed the future economic viability of this well and decided to suspend production until further notice in order to determine whether production of this well will be profitable.  During the quarter ended March 31, 2010, we decided to resume production on this well due to an increase in commodity prices.  Total revenue received from Wilson Creek #1-27 for
the year ended December 31, 2010 was $9,596 (December 31, 2009: $nil).  The increase in revenue was caused by our decision to resume production in the reporting period, however, the well is not producing any hydrocarbons, and the Company is currently reviewing its commercial viability.




Palmetto Point Prospect - 12 Wells Phase  I




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




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




Effective February 1, 2009, we disposed of our interests in the Palmetto Point Prospect - 12 Wells Phase - I project described above.  These interests were disposed of together with the interests in the Palmetto Point Prospect – 50 Wells Phase II project described below.  We received no revenue from the Palmetto Point Phase I producing wells during the year ended December 31, 2009.










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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 North-eastern Louisiana.  Drilling commenced in September 2006.  The site of the first twenty wells was located within range to tie into existing pipeline infrastructure should the wells be suitable for commercial production.  The drilling program was conducted by Griffin Exploration in its capacity as operator.  We agreed to pay 10% of all prospect
fees, mineral leases, surface leases, and drilling and completion costs to earn a net 8.0% share of all production zones to the base of a geological formation referred to as the Frio formation and 7.5% of all production to the base of a geological formation referred to as the Wilcox formation.  The cost during the quarter ending September 30, 2006 amounted to $100,000.  During the fourth quarter of fiscal 2006, we made additional payments of $300,000 that was employed in the further development of prospects on lands in Mississippi and Louisiana in accordance with the terms of the operating agreement.




We acquired, through our acquisition of a controlling interest of the Stallion Group in March 2009, an additional interest in this same drilling program.  Pursuant to the agreement entered into by the Stallion Group with Griffin Exploration on August 2, 2006, the Stallion Group agreed to pay 30% of all prospect fees, mineral leases, surface leases, and drilling and completion costs to earn a net 19.2% share of all production zones to the base of a geological formation referred to as the Frio formation and 17.25% of all production to the base of a geological formation referred to as the Wilcox formation.  The Stallion Group’s cost during the
quarter ending September 30, 2006 amounted to $300,000.  During the fourth quarter of fiscal 2006, the Stallion Group made additional payments of $600,000 that were employed in the further development of prospects on lands in Mississippi and Louisiana in accordance with the terms of the operating agreement.  As a result of our acquisition of a controlling interest of the Stallion Group in March 2009 pursuant to our tender offer, we became obligated to pay 40% of all prospect fees, mineral leases, surface leases, and drilling and completion costs to earn a net 27.2% share of all production zones to the base of a geological formation referred to as the Frio formation and 24.75% of all production to the base of a geological formation referred to as the Wilcox formation




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




No revenue was received from the Palmetto Point Phase II producing wells during the year ended December 31, 2009.




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










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• 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.




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




Competition




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




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




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




Research and Development




We did not incur any research and development expenditures in the fiscal years ended December 31, 2010 or 2009.




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.










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




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




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




Environmental Regulation




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




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




Compliance with Environmental Laws




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










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Employees




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




We engage contractors from time to time to consult with us on specific corporate affairs or to perform specific tasks in connection with our oil and gas operations.  As of December 31, 2010, we engaged approximately 3 contractors that provided work to us on a recurring basis, which includes Messrs. Paton-Gay, Bolen and 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 $544,454 for the year ended December 31, 2010 and $2,337,765 for the year ended December 31, 2009. 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.













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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 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. In addition, acquisitions of working interests may require additional debt or equity financing, resulting in additional
leverage or dilution of ownership.




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


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


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




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




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




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




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




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




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




As noted in our financial statements, we commenced operations 10 years ago. The audit report of Mark Bailey & Company, Ltd. dated March30, 2011 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.











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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.




Market Risks




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




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




•           changes in the worldwide price for oil and gas;




•           disappointing results from our exploration or development efforts;




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




•           decline in demand for our common stock;




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




•           technological innovations by competitors or in competing technologies;




•           investor perception of our industry or our prospects; and




•           general economic trends.




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




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




The oil and gas industry is highly competitive. We compete with major integrated and independent oil and gas companies for the acquisition of desirable oil and gas properties and leases, for the equipment and services required to develop and operate properties, and in the marketing of oil and gas to end-users. Many competitors have financial and other resources that are substantially greater than ours, which could, in the future, make acquisitions of producing properties at economic prices difficult for us. In addition, many larger competitors may be better able to














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respond to factors that affect the demand for oil and natural gas production, such as changes in worldwide oil and natural gas prices and levels of production, the cost and availability of alternative fuels and the application of government regulations. We also face significant competition in attracting and retaining experienced, capable and technical personnel with experience in the oil and gas industry.




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




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




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




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




•           the availability of pipeline capacity;




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




•           the availability of alternate fuel sources;




•           the effect of inclement weather, such as hurricanes;




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




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




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




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




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




Risks Relating to Our Business




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




Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We seek to acquire working interests in properties which we believe will result in projects that will add value over time. However, we cannot guarantee that all of our prospects will result in viable projects or that we will not abandon these properties. Additionally, we cannot guarantee that any undeveloped acreage we have an interest in will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such acreage
or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs.












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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.




Our reserve estimates generated for 2010 were compiled by Harper & Associates, Mark E. Anderson and AJM Petroleum Consultants independent consultants. In conducting their evaluations, the consultants evaluate our properties and independently develop proved reserve estimates.  There are numerous uncertainties and risks that are inherent in estimating quantities of oil and natural gas reserves and projecting future rates of production and timing of development expenditures as many factors are beyond our control. Many factors and assumptions are incorporated into these estimates including: expected reservoir characteristics based on geological, geophysical
and engineering assessments;




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




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




•
future development and operating costs.




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




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




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




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




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




•           unexpected drilling conditions including blowouts and explosions;




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




•           equipment failures, fires or accidents;




•           pollution and other environmental risks; and




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










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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.




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


In June 2009, the United States House of Representatives passed the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill or ACESA. Further, on November 5, 2009, the United States Senate passed out of committee the Clean Energy Jobs and American Power Act, also known as the Boxer-Kerry Bill. These bills contain provisions that would establish a cap and trade system for restricting greenhouse gas emissions in the United States. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are
considered greenhouse gases. Under such a system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The ultimate outcome of this federal legislative initiative remains uncertain.
  In addition to pending climate legislation, the Environmental Protection Agency, or EPA, has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding could lead to regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. EPA has
proposed such greenhouse gas regulations and may issue final rules this year.
  In the courts, several decisions have been issued that could increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people and property.
  Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and natural gas.


Risks Relating to our Common Stock




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




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











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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.




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




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




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




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




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




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




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




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




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










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




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




Indemnification of officers and directors.




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




ITEM 1B.Unresolved Staff Comments.




None.




ITEM 2. Properties.




Description of Our Property




Our principal executive offices are located at Suite 604, 700 West Pender Street, Vancouver, British Columbia, Canada V6C 1G8.  Our principle executive offices are provided to us at no cost by our Chief Financial Officer.
      - 22 -
 Table of Contents


Proved Reserves Reporting
  On December 31, 2008, the Securities and Exchange Commission, or the SEC, released a Final Rule, Modernization of Oil and Gas Reporting, approving revisions designed to modernize oil and gas reserve reporting requirements. The new reserve rules are effective for our financial statements for the year ended December 31, 2010 and our 2010 year-end proved reserve estimates. The most significant revisions to the reporting requirements include:


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


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




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




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




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




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




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




Reported Reserves Table




The following table sets forth summary information regarding our estimated proved reserves at December 31, 2010, 2009 and 2008:





December 31,2010
2009
2008Oil

(Bbls)
Gas

(Mcf)
Gas

(Mcf)
Oil

(Bbls)
Gas

(Mcf)
Oil

(Bbls)Proved Producing &Non-Producing

Reserves(1)
219,090
173,930
41,230
116,940
209,173
53,355Present value ofproved reserves(2)
6,624,506
1,066,900
1,121,422Standardized measureof discounted future

net cash flows (3)
4,761,927
1,162,410
968,550






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 Table of Contents







(1) Estimates of reserves as of year-end 2010 and 2009 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period of the applicable year, in accordance with revised guidelines of the SEC applicable to reserves estimates beginning with the year-end 2009. Estimates of reserves as of year-end 2008 were prepared using constant prices and costs in accordance with previous guidelines of the SEC based on hydrocarbon prices received on a field-by-field basis as
of December 31, 2008. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
  (2) Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on certain prevailing economic conditions. The estimated future production in our reserve reports dated December 31, 2010 and 2009 is priced based on the 12-month un-weighted arithmetic average of the first-day-of-the month price for the period January through
December of the applicable year. The estimated future production in our reserve reports dated December 31, 2008 is priced using constant year-end pricing.  PV-10 is a non-GAAP measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP.
  (3) The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.




The table below sets forth summary information regarding our estimated proved reserves.  All of our estimated proved reserves are located in the United States and attributable to our properties in Newton County, Texas, Colusa County, California and Garvin and Murray counties in Oklahoma that comprise the 2006-3, 2007-1, 2009-1 and 2009-3 drilling programs referenced above in "Item 1, Business."





ReservesReserve Category

Oil & NGL’s

(Bbls)


Natural Gas

(Mcf)


Total

(BOE)PROVEDDeveloped:


89,960



165,150



117,215Undeveloped:


129,400



8,780



130,863TOTAL PROVED at December 31, 2010


219,090



173,930



248,078




The conversion of proved undeveloped reserves into proved developed reserves during the year ended December 31, 2010 did not materially contribute to the significant increase in proved developed reserves from December 31, 2009 to December 31, 2010.  The significant increase in proved developed reserves from December 31, 2009 to December 31, 2010 was attributable to an increase in reserves resulting from our newly acquired properties.
  The technologies used to establish the appropriate level of certainty for reserve estimates from properties included in the total reserves disclosed above consisted of seismic and geologic interpretations.










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Proved Undeveloped Reserves
  As of December 31, 2010, we had 131,000 BOE (Barrels of Oil Equivalent) of proved undeveloped reserves, or PUDs, as compared to 20,000 BOE of PUDs as of December 31, 2009.  The significant increase in PUDS from December 31, 2009 to December 31, 2010 was attributable to an increase in reserves from the Company’s newly acquired properties.  All PUDs as of December 31, 2010 were located in the United States.  Each of these PUD’s will be converted from undeveloped to developed as the wells begin production.   We anticipate that all of the PUD’s will be will be developed within five years after first disclosure as proved undeveloped reserves. During the
year ended December 31, 2010, we expended $258,345 to convert proved undeveloped reserves to proved developed reserves.


The Company has established its drilling budget for 2011 and set forth below are the amounts it anticipates expending on each of the core properties.  It is anticipated that the proposed expenditure of $350,000 for development drilling during the budget year 2011, if successful,  will result in moving approximately 50% of our proved undeveloped reserves into a proved reserves category in the Company's Hartburg, Newton County Texas property base.




The Company  has also proposed to expend $375,000 to drill an exploration well on our King City Oilfield property which if successful in proving commercial quantities of hydrocarbons, will result in adding additional proved and undeveloped reserves in this fiscal period.




The Company does not propose any other development drilling in 2011; however, depending on the success of the two wells previously noted the Company may expand its drilling program during 2011.




Internal Controls Over Preparation of Proved Reserve Estimates




Our policies regarding internal controls over reserve estimates requires reserves to be in compliance with the SEC definitions and guidance and for reserves to be prepared by an independent third party reserve engineering firm under the supervision of our management. Our management provides to our third party reserves engineers reserves estimate preparation material such as property interests, production, current costs of operation and development, current prices for production, geoscience and engineering data, and other information. This information is reviewed by other members of management to ensure accuracy and completeness of the data prior to submission to our third party reserve engineering
firm.  During 2010, we retained Harper & Associates, Inc., Mark E. Andersen and AJM Petroleum Consultants as independent third-party reserve engineers, to prepare our estimates of proved reserves.  For more information about the evaluations performed by Harper & Associates, Inc., Mark E. Andersen, and AJM Petroleum Consultants, see copies of their respective reports filed as exhibits to this Form 10-K.




Our Chief Executive Officer, Christopher Paton-Gay, is the person primarily responsible for overseeing the preparation of reserves audits conducted by independent third-party engineers.  Mr. Paton-Gay has over 30 years of industry experience, which includes having founded and been chairman and president of two private oil and gas companies.  In these capacities, Mr. Paton-Gay has a very high degree of working knowledge and understanding of geologic formations, drilling and completion parameters, and all facets of production.  Given his extensive hands on familiarity with the properties he has previously operated and those current properties we hold,  we  consider Mr.
Paton-Gay to be a qualified person in overseeing the preparation of our internal reserve estimates and for coordinating any reserves audits conducted by a third-party engineering firm. Mr. Paton-Gay  was also one of the founding Directors of the Explorers and Producers Association of Canada and is a graduate of the ICD - Institute of Corporate Directors Canada.




Reserves Reported to Other Agencies




We did not file any reports during the year ended December 31, 2010 with any federal authority or agency other than the SEC with respect to our estimates of oil and natural gas reserves.




Production




The following table sets forth summary information regarding production by final product sold for the years ended December 31, 2010, 2009 and 2008:







Production Data
Year ended December 31,2010
2009
2008Production -Oil (Bbls)
9,309
5,775
3,377Gas (Mcf)
36,657
12,279
28,559Average Sales Price -Oil (Bbls)
$75.00
$56.00
$90.00Gas (Mcf)
$4.00
$4.00
$6.00Average Production Costs per Mcf
$1.00
$2.00
$3.29









- 25 -
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The table below sets forth summary information regarding production by final product for each country containing 15% or more of our proved reserves for the years ended December 31, 2010, 2009 and 2008.  All production in Canada was attributable to the Wordsworth Prospect in Saskatchewan which we disposed of in 2010 and all production in the United States is attributable to our properties in Newton County, Texas, Colusa County, California and Garvin and Murray counties in Oklahoma that comprise the 2006-3, 2007-1, 2009-1 and 2009-3 drilling programs referenced above in "Item 1, Business."





Production Data
Year Ended December 312010
2009
2008USA
Canada
USA
Canada
USA
CanadaProduction -Oil (Bbls)
7,456
1,853
1,877
3,898
5,116
1,261Gas (Mcf)
36,657
0
12,279
0
28,559
0Average Sales Price -Oil (Bbls)
$75.00
$74.00
$53.00
$58.00
$98.00
$88.00Gas (Mcf)
$4.00
$0.00
$4.00
$0.00
$9.00
$0.00Average Production CostsOil (Bbls)
$20.00
$26.00
$20.00
$14.00
$19.00
$40.00Gas (Mcf)
$1.00
$0.00
$2.00
$0.00
$3.00
$0.00





Production costs may vary substantially among wells depending on the methods of recovery employed and other factors, but generally include severance taxes, administrative overhead, maintenance and repair, labor and utilities.  The reserves attributable to the Willows Gas Field in North Sacramento Valley, California were not material to our production in the United States and have not been itemized in the table above for this reason.
  The table below sets forth summary information regarding production by final product for each field that contains 15% or more of our total proved reserves expressed on an oil-equivalent-barrels basis for the years ended December 31, 2010, 2009 and 2008.
  Production Data
Year Ended December 312010
2009
2008Oil (Bbls)
Gas (Mcf)
Oil (Bbls)
Gas (Mcf)
Oil (Bbls)
Gas (Mcf)Production -Garvin & Murray County, Oklahoma, USA
5,981
11,085
1,656
12,003
3,815
-Newton County, Texas, USA

(Texas Prospect)
1,475
-
-
-
-
14,929Saskatchewan, Canada

(Wordsworth) 1
1,853
-
3,898
-
1,261
-Palmetto Point, Mississippi

(Palmetto) 2
-
-
221
276
1,301
13,630Colusa County, California, USA

(Lonestar Prospect)
-
25,572
-
-
-
-
  1
We disposed of our interests in the Wordsworth prospect during 2010.2
Effective February 1, 2009, we disposed of all of our interests in the Palmetto Point Prospect 12 Wells Phase - I project and  50 Wells Phase - II project.
   
 - 26 -
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Productive Wells and Acreage




The following table shows our producing wells and acreage as of December 31, 2010:


Producing Wells 3
Developed AcreageOil
GasGross 1
Net 2
Gross 1
Net 2
Gross 1
Net 2Saskatchewan, Canada

(Wordsworth) 4
0
0
0
0
0
0CANADA TOTALS
0
0
0
0
0
0Garvin & Murray County, Oklahoma, USA  5
6
0.38
8
0.5
940
109King City, California, USA
0
0
0
0
0
0Willows Gas Field, North Sacramento Valley, California, USA
0
0
0
0
0
0Newton County, Texas, USA

(Texas Prospect)
1
0.36
0
0
155
56Colusa County, California, USA

(Lonestar Prospect)
0
0
1
0.25
691
173USA TOTALS
7
0.74
9
0.75
1,786
338





1
A gross well or acre is a well or acre in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.2
A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or

acres equals one. The number of net wells or acres is the sum of the fractional working interest owned in gross wells or acres expressed as hole numbers and fractions thereof.3
Productive wells are producing wells and wells capable of production.4
We disposed of our interests in the Wordsworth prospect during 2010.5
Our properties in Garvin and Murray counties in Oklahoma consist of the 2006-3, 2007-1, 2009-1 and 2009-3 drilling programs referenced above in ‘Item 1, Business’.









- 27 -
 Table of Contents








Undeveloped Acreage





The following table set forth undeveloped acreage as of December 31, 2010:


Undeveloped Acreage 1

as of December 31, 2010Gross
NetSaskatchewan, Canada

(Wordsworth) 2
0
0CANADA TOTALS
0
0Garvin & Murray County, Oklahoma, USA 3
1,660
301King City, California, USA
10,000
4,000Willows Gas Field, North Sacramento Valley, California, USA
0
0Newton County, Texas, USA

(Texas Prospect)
209
75Colusa County, California, USA

(Lonestar Prospect)
661
165USA TOTALS
12,530
4,541




1







2



3
"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.



We disposed of our interests in the Wordsworth prospect during 2010.



Our properties in Garvin and Murray counties in Oklahoma consist of the 2006-3, 2007-1, 2009-1 and 2009-3

drilling programs referenced above in ‘Item 1, Business’.





Drilling Activity


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








Geographical Area
Net Exploratory Wells Drilled
Net Development Wells DrilledProductive 1
Dry 2
Productive 1
Dry 2Garvin, McClain & Murray Counties, Oklahoma 32010
0.60
0
0.0375
02009
0.45
0.20
0
02008
0.30
0.20
0
0Newton County, Texas, USA

(Texas Prospect)2010
0.36
0
0
02009
0
0
0
02008
0
0
0
0Colusa County, California, USA

(Lonestar Prospect)2010
0.25
0
0
02009
0
0
0
02008
0
0
0
0     - 28 -
 Table of Contents
 
   
 Geographical Area
Net Exploratory Wells Drilled
Net Development Wells Drilled2008
Productive 1
Dry 2
Productive 1
Dry 2King City, California, USA2010
0
0
0
02009
0
0
0
02008
0
0
0
0Palmetto Point, Mississippi

(Palmetto) 42010
0
0
0
02009
0
0
0
02008
1.17
1.22
0
0Saskatchewan, Canada

(Wordsworth) 52010
0
0
0
02009
0.05
0
0.10
02008
0.075
0
0
0Willows Gas Field, North Sacramento Valley, California,2010
0
0
0
02009
0
0
0
02008
0.0625
0
0
0


The table below sets forth summary information regarding our drilling activity for the last three years for each country in which we engaged in drilling activity for the years ended December 31, 2010, 2009 and 2008.





Geographical Area
Net Exploratory Wells Drilled
Net Development Wells DrilledProductive 1
Dry 2
Productive 1
Dry 2Canada2010
0
0
0
02009
0.05
0
0.1
02008
0.075
0
0
0USA2010
0.60
0
0.0375
02009
0.45
0.2
0
02008
1.53
1.42
0
0




1
A productive well is an exploratory or development well that is not a dry well.  Although a well may be classified as productive upon completion, future changes in oil and gas prices, operating costs and production may result in the well becoming uneconomical.2
A dry well (hole) is an exploratory or development well found to be incapable of producing either

oil or gas in sufficient quantities to justify completion as an oil or gas well.3
Our properties in Garvin and Murray counties in Oklahoma consist of the 2006-3, 2007-1, 2009-1 and 2009-3 drilling programs and the drilling activity in McClain County, Oklahoma relates to the Owl Creek Prospect referenced above in "Item 1, Business.” which was sold in 2008.4
Effective February 1, 2009, we disposed of all of our interests in the Palmetto Point Prospect 12 Wells Phase - I project and  50 Wells Phase - II project.5
We disposed of our interests in the Wordsworth prospect during 2010.










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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. Reserved.










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PART II




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




Market Prices




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




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




Fiscal Year Ended December 31, 2010Fiscal Quarter Ended:
High Bid
Low BidMarch 31, 2010
$0.45
$0.08June 30, 2010
$0.21
$0.02September 30, 2010
$0.12
$0.02December 31, 2010
$0.15
$0.07Fiscal Year Ended December 31, 2009Fiscal Quarter Ended:
High Bid
Low BidMarch 31, 2009
$0.25
$0.09June 30, 2009
$0.225
$0.10September 30, 2009
$0.19
$0.09December 31, 2009
$0.19
$0





Holders of Common Stock




As of March23, 2011, we had approximately eighty-two (82) shareholders of record of our common stock.   Several other shareholders hold shares in street name.




Dividend Policy




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




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








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Securities Authorized for Issuance under Equity Compensation Plans




Our board of directors adopted the 2010 Incentive Compensation Plan (the “Incentive Compensation Plan”) on March 8, 2010.  The Board has submitted the Incentive Compensation Plan for shareholder approval at the 2011 annual meeting of the shareholders.  Grants of 600,000 options have been made under the Incentive Compensation Plan subsequent to December 31, 2010.  As of December 31, 2010, no securities were issued  under the Incentive Compensation Plan.
  The Incentive Compensation Plan authorizes us to grant awards in the form of shares of common stock, including unrestricted shares of common stock; options to purchase shares of common stock; stock appreciation rights or similar rights with a fixed or variable price related to the fair market value of the shares of common stock and with an exercise or conversion privilege related to the passage of time, the occurrence of one or more events, or the satisfaction of performance criteria or other conditions; any other security with the value derived from the value of the shares of common stock, such as restricted stock and restricted stock units; deferred stock units; dividend equivalent rights; or any combination of
the foregoing.  Our board of directors administers the Plan.
  The Plan allows for the grant of incentive stock options, non-qualified stock options and restricted stock awards.  The exercise price of any option shall be determined at the time the option is granted by the board of directors. However, the exercise price may generally not be less than 100 percent of the fair market value of the shares of common stock on the date of the grant. Each option expires on the date determined by the board of directors, but not later than ten years after the grant date. The board of directors may determine in its discretion whether any option shall be subject to vesting and the terms and conditions of any such vesting.  The Incentive Compensation Plan also
provides for the immediate vesting of options, as well as authorizes the board of directors to cancel outstanding options or to make adjustments to the transfer restrictions on those options in the event of certain changes in corporate control of the company.  Awards, including options, made under the Incentive Compensation Plan are not assignable and also subject to any restrictions and conditions imposed by the board of directors.


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.  Grants of 800,000 options have been made under the 2005 Stock Incentive Plan and are outstanding as of December 31, 2009 and 249,902 remain available for issuance under the 2005 Stock Incentive Plan as of December 31, 2010.
  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, 2010.


Equity Compensation Plan as of December 31, 2010


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 holders
800,000

100,000
$0.12

$0.15
249,902

-Total
900,000
$0.123
249,902










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Recent Sales of Unregistered Securities




There were no sales 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.




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




For the Years Ended December 31, 2010 and 2009




Revenues




We generated total revenue of $1,384,345 for the year ended December 31, 2010, an increase of approximately 171% from revenues of $510,917 for the year ended December 31, 2009.  During the year ended December 31, 2010, $861,170 of the revenue we generated was attributable to natural gas and oil sales and $518,874 was attributable to a gain on the disposition of our working interest in the Wordsworth Prospect during the three months ended June 30, 2010.  During the year ended December 31, 2009, $352,841 of the revenue was attributable to natural gas and oil sales and $158,076 was attributable to a gain on the disposition of our working interest in the Owl Creek prospect.




The increase in total revenue for the year ended December 31, 2010, when compared to the year ended December 31, 2009, was attributable to an increase in revenues from oil and gas sales of $508,329, which was caused by the addition of producing wells in Texas, California and Oklahoma.  Furthermore, the sale of the Company’s interest in the Wordsworth prospect generated an additional increase of $360,798.




Costs and Expenses




We incurred costs and expenses in the amount of $1,926,624 for the year ended December 31, 2010, a 33% decrease from costs and expenses of $2,871,082 for year ended December 31, 2009.




The decrease in costs and expenses for the year ended December 31, 2010, when compared the year ended December 31, 2009, is primarily attributable to the collective results of the following factors:




·
General and administrative costs for the year ended December 31, 2010 decreased to$597,318 from $700,512 for the year ended December 31, 2009, a decreaseof 15%.  The decrease in general and administrative costs was caused by a decrease in stock based compensation expense attributable to the issuances of stock options and shares of common stock to management.  Stock based compensation expense for the year ended December 31, 2010 was $nil as compared to $199,745  for the year ended December 31, 2009.  Further decreases in administrative costs was due to foreign exchange losses decreasing to $59,892 (December 31, 2009:
$88,440).




·
Legal and Professional fees for the year ended December 31, 2010 decreased to $84,535 from $107,938 for the year ended December 31, 2009, a decrease of 22%.  The decrease in legal costs was attributable to higher legal costs in the prior year relating to the acquisition of The Stallion Group and the preparation and filing of the S-4 registration statement.










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·
Consulting fees for the year ended December 31, 2010 increased to $285,298 from $207,121 for the year ended December 31, 2009, an increase of 38%.  The increase in consulting fees was attributable to the addition of one executive from the acquisition of The Stallion Group.




·
Natural gas and oil operating costs for the year ended December 31, 2010 increased to $157,187 from $120,022 for the year ended December 31, 2009, an increase of 31%. The increase in natural gas and oil operating costs is attributable to an increase in the number of producing wells for the year ended December 31, 2010, as compared to the year ended December 31, 2009.




·
Depreciation and depletion expensefor the year ended December 31, 2010 increased to $184,537 from $42,446 for the year ended December 31, 2009, an increase of 335%. The increase in depreciation and depletion expense is attributable to the additions of producing wells which was partially offset by the disposal of the Wordsworth wells;




·
Impairment of natural gas and oil properties expense for the year ended December 31, 2010 decreased to $nil from $1,255,561 for the year ended December 31, 2009, a decrease of 100%.  The decrease in impairment of natural gas and oil properties expense for the year ended December 31, 2010, is attributable to no impairment of oil and natural gas properties during the year ended December 31, 2010, as compared to impairments of oil and natural gas properties relating to the Willow’s Gas Field during the year ended December 31, 2009.




·
Loss on sale of Investment of $985,464 for the year ended December 31, 2010, resulted from the dissolution of the Company’s 80% subsidiary, The Stallion Group, on December 31, 2010.




Net Operating Loss




The net operating loss for the year ended December 31, 2010 was $542,279, compared to a net operating loss of $2,360,165 for the year ended December 31, 2009.




Other Income and Expense




We reported other net income, generated from interest received, of $202 for the year ended December 31, 2010, as compared to other income of $9,062 in the year ended December 31, 2009.




Net Loss




Net loss for the year ended December 31, 2010 was $544,454, compared to a net loss of $2,337,765 for the year ended December 31, 2009. The decrease in loss for the year ended December 31, 2010 was attributable to the an increase in revenues from the additions of new producing wells and the sale of the Company’s interest in the Wordsworth 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.










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Summary of Quarterly Results on a Non-GAAP basis




Set forth below is a summary of the Company’s financial results for the eight most recently completed quarters, removing non-cash items.  The following information is presented for informational purposes only; the net income/(loss) totals below do not match the Financial Statements due to the removal of non-cash items.




Dec 31, 2010
Sept 30, 2010
Jun 30, 2010
Mar 31, 2010
Dec 31, 2009
Sep 31, 2009
Jun 30, 2009
Mar 31, 2009$
$
$
$
$
$
$
$Revenue
358,700
693,894
206,319
125,432
135,054
101,491
206,521
68,051Operating Costs
(1,280,437)
(194,407)
(201,940)
(249,840)
(1,338,180)
(187,057)
(1,064,153)
(281,692)Non-cash items *
985,464
-
-
-
1,124,869
-
750,305
130,692Net Income/(loss)
64,327
499,395
1,695
(124,408)
(78,257)
(83,210)
(100,439)
(82,719)




*  Non-cash items are those items that are related to impairment charges or losses on sale of investments.  These charges are non-recurring on an operational basis and have been excluded in the presentation above.




Liquidity and Capital Resources




As of December 31, 2010, we had total current assets of $794,655 and total current liabilities in the amount of $128,676.  As a result, we had working capital of $665,979 as of December 31, 2010.




The revenue we currently generate from natural gas and oil sales does not exceed our operating expenses.  Our management anticipates that the current cash on hand may not be sufficient to fund our continued operations at the current level for the next twelve months.  As such, we may require additional financing to fund our operations and proposed drilling activities for the year ended December 31, 2011.  We will also require additional funds to expand our acquisition, exploration and production of natural oil and gas properties.  Additional capital will be required to effectively expand our operations through the acquisition and drilling of new prospects and to implement our
overall business strategy.  We believe that debt financing will not be an alternative for funding as we have limited tangible assets to secure any debt financing.  We anticipate that additional funding will be in the form of equity financing from the sale of our common stock.  We intend to seek additional funding in the form of equity financing from the sale of our common stock, but cannot provide any assurance that we will be able to raise sufficient funding from the sale of our common stock to fund our operations and acquisition of new prospects.  If we are unable to obtain additional financing, we will experience liquidity problems and management expects that we will need to curtail operations, liquidate assets, seek additional capital on less favorable terms and/or pursue other remedial measures.  Any additional equity financing may
involve substantial dilution to our then existing shareholders.




Cash Generated/(Used) in Operating Activities




Operating activities generated $134,263 in cash for the year ending December 31, 2010, compared to $313,490 in cash used in operating activities for the year ended December 31, 2009.  Our positive cash flow from operating activities for the year ending December 31, 2010 was caused by an increase in natural gas and oil revenues.










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Cash Used in Investing Activities




Cash flows used by investing activities for the year ending December 31, 2010 was $95,693, compared to $260,659 cash generated from investing activities for the year ended December 31, 2009.  Our negative cash flow from investing activities for the year ending December 31, 2010 was primarily caused by investments in natural gas and oil working interests which were partially offset by sale proceeds of natural gas and oil working interests in the amount of $705,949.




Cash from Financing Activities




Cash flows used by financing activities for the year ending December 31, 2010 primarily consisted of $20,142 related to the dissolution of The Stallion Group, compared to $48,045 in cash used from financing activities for the year ended December 31, 2009.




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




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




·
Property acquisition costs; and




·
Sale of the Wordsworth prospect.




Off-Balance Sheet Arrangements




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




Going Concern




As shown in the accompanying financial statements, we have incurred a net loss of $5,406,237 since inception.  To achieve profitable operations, we may require additional capital for obtaining producing oil and gas properties through either the purchase of producing wells or successful exploration activity.  We believe that we will be able to obtain sufficient funding to meet our business objectives, including anticipated cash needs for working capital and are currently evaluating several financing options.  However, there can be no assurances offered in this regard.  As a result of the foregoing, there exists substantial doubt about our ability to continue as a going
concern.




Critical Accounting Policies




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




Oil & Gas Joint Ventures




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






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Natural Gas and Oil Properties




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




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




Revenue Recognition




Revenue from sales of crude oil, natural gas and refined petroleum products are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customers. Title transfers for crude oil, natural gas and bulk refined products generally occur at pipeline custody points or when a tanker lifting has occurred.  Revenues from the production of oil and natural gas properties in which we share an undivided interest with other producers are recognized based on the actual volumes sold by us during the period.  Gas imbalances occur when our actual sales differ from its entitlement under existing working interests.  We record a liability for gas imbalances when we have
sold more than our working interest of gas production and the estimated remaining reserves make it doubtful that the partners can recoup their share of production from the field.  At December 31, 2010 and 2009, we had no overproduced imbalances.




Recent Accounting Pronouncements




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




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




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






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




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




Not applicable




ITEM 8. Financial Statements and Supplementary Data.




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




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




None.




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, 2010, 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.










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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, 2010.  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, 2010, our internal control over financial reporting is effective based on those criteria.




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







Changes in Internal Control Over Financial Reporting




There have been no changes in our internal controls over financial reporting during the quarter ended December 31, 2010, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.




ITEM 9B.Other Information.




None.












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PART III




ITEM 10. Directors, Executive Officers and Corporate Governance.




The information required by Item 10 concerning directors, corporate governance and executive officers of the Company is incorporated herein by reference to the information set forth in our definitive proxy statement for the 2011 Annual Meeting of Stockholders under the headings “Election of Directors” and “Corporate Governance”, respectively, which proxy statement we expect to file with the Securities and Exchange Commission within 120 days after the end of our fiscal year ended December 31, 2010 (the “Proxy Statement”).




The information concerning compliance with Section 16(a) of the Exchange Act is incorporated herein by reference to the information set forth in our Proxy Statement under the heading “Section 16(a) Beneficial Ownership Reporting Compliance.”




The information concerning our code of ethics is incorporated herein by reference to the information set forth in our Proxy Statement under the heading “Code of Ethics and Conduct.”




ITEM 11. Executive Compensation.




The information required by Item 11 concerning executive compensation is incorporated herein by reference to the information set forth in our Proxy Statement under the heading “Executive Compensation.”




The information required by Item 11 concerning compensation of directors is incorporated herein by reference to the information set forth in our Proxy Statement under the heading “Compensation of Directors for Year Ended December 31, 2010.”




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




The information required by Item 12 concerning security ownership of certain beneficial owners and management is incorporated herein by reference to the information set forth in our Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”




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




The information required by Item 13 concerning certain relationships and related party transactions and director independence is incorporated herein by reference to the information set forth in our Proxy Statement under the headings “Transactions With Related Persons” and “Director Independence.”




ITEM 14. Principal Accounting Fees and Services.




The information required by Item 14 is incorporated by reference to the information in our Proxy Statement under the headings “Ratification of Appointment of Independent Registered Public Accounting Firm” and “Audit Committee.”










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PART IV




ITEM 15. Exhibits, Financial Statement Schedules.




(a)(1)





Index to Financial Statements

Page (s)Reports of Independent Registered Public Accounting Firms

F-1Financial Statements:Consolidated Balance Sheets as of December 31, 2010 and
2009

F-3Consolidated Statements of Operations – Years Ended December 31, 2010 and December 31, 2009

F-4Consolidated Statement of Stockholders’ Equity (Deficiency) and from inception January 9, 2001 to December 31, 2010

F-5Consolidated Statements of Cash Flows for the Years Ended December 31, 2010 and December 31, 2009

F-6Notes to Consolidated Financial Statements

F-7










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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
 To the Board of Directors and Stockholders of Delta Oil & Gas, Inc.
 
 We have audited the accompanying consolidated balance sheet of Delta Oil & Gas, Inc. as of December 31, 2010, and the related consolidated statements of operations, comprehensive income, changes in stockholders’ equity, and cash flows for the year then ended. Delta Oil & Gas, Inc.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audit.
 
 We conducted our audit in accordance with the 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. The company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included 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, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
 
 In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Delta Oil & Gas, Inc. as of December 31, 2010, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
 
 The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 1(c) to the consolidated financial statements, the Company has suffered recurring losses from operations since inception. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1(c). The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
 
 graphic80
 
 Mark Bailey & Company, Ltd.
 Reno, Nevada
 March 30, 2011












F - 1
 Table of Contents










REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
 
 To the Board of Directors and Stockholders of
 Delta Oil & Gas, Inc.
 
 We have audited the accompanying consolidated balance sheet of Delta Oil & Gas, Inc.(the “Company”) as at December 31, 2009, the related consolidated statements of operations, consolidated statement of comprehensive income/(loss), consolidated statement of changes in stockholders’ equity and consolidated statement of cash flows for the year then ended.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audit.
 
 We conducted our audit in accordance with Standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting.  Accordingly, we express no such opinion.
 
 An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audit provides a reasonable basis for our opinion.
 
 In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Delta Oil & Gas, Inc. as at December 31, 2009, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
 
 The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern.  As discussed in Note 1(c) to the consolidated financial statements, the Company has suffered recurring losses from operations since inception.  These factors raise substantial doubt about the Company’s ability to continue as a going concern.  Management’s plans in regard to these matters are also described in Note 1(c).  The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
 
 
 
 
 /s/STS PARTNERS LLP
 STS PARTNERS LLP
 CHARTERED ACCOUNTANTS
 
 Vancouver, British Columbia, Canada
 April 12, 2010








F - 2
 Table of Contents






DELTA OIL & GAS, INC.Consolidated BalanceSheets(Stated in U.S. Dollars)December 31,


December 31,2010


2009ASSETSCurrentCash and cash equivalents

$
525,128


$
446,808Restricted cash


8,370



-Accounts receivable


252,589



70,496Franchise tax prepaid


-



1,004Prepaid expenses


8,568



17,464Advancement for oil and gas exploration costs


-



49,898794,655



585,670Natural Gas And Oil PropertiesProved property


1,099,016



380,483Unproved property


188,767



484,8871,287,783



865,370Property, Plant and Equipment (net)


797



3,499TOTAL ASSETS

$
2,083,235


$
1,454,539LIABILITIES AND STOCKHOLDERS' EQUITYLIABILITIESCurrentAccounts payable and accrued liabilities

$
100,403


$
37,882Project cost advanced received


5,424



-Due to related party


22,849



1,527128,676



39,409Long TermAsset retirement obligation


19,121



21,487TOTAL LIABILITIES


147,797



60,896STOCKHOLDERS' 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, 13,857,107 and 13,557,107 shares issuedand outstanding, respectively


13,857



13,557Additional paid-in capital


7,173,508



7,115,308Accumulative Other Comprehensive Income


154,310



94,418Accumulated Deficit


(5,406,237
)


(5,911,527
)1,935,438



1,311,756Noncontrolling Interest


-



81,887TOTAL STOCKHOLDERS' EQUITY


1,935,438



1,393,643TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
2,083,235


$
1,454,539The accompanying notes are an integral part of these consolidated financial statements






F - 3
 Table of Contents






DELTA OIL & GAS, INC.Consolidated StatementsOf Operations(Stated in U.S. Dollars)YEARS ENDEDDecember 31,2010


2009RevenueNatural gas and oil sales

$
861,170


$
352,841Gain on sale of natural gas and oil properties


518,874



158,076Management fee


4,301



-1,384,345



510,917Costs And ExpensesNatural gas and oil operating costs


157,187



120,022General and administrative


597,318



700,512Accretion


2,118



2,236Depreciation and depletion


184,537



42,446Impairment of natural gas and oil properties


-



1,255,561Loss on sale of natural gas and oil properties


-



750,305Loss on sale of Investment


985,464



-1,926,624



2,871,082Net Operating Loss


(542,279
)


(2,360,165
)Other IncomeInterest income


202



9,062202



9,062Loss Before Income Taxes


(542,077
)


(2,351,103
)Income taxes


2,377



5,406Net Loss


(544,454
)


(2,356,509
)Less: Net loss attributable tothe noncontrolling interest


-



18,744Net Loss Attributable to Delta Oil & Gas, Inc.

$
(544,454
)

$
(2,337,765
)Basic And Diluted Loss Per Common ShareBasic

$
(0.04
)

$
(0.19
)Diluted

$
(0.04
)

$
(0.19
)Weighted Average Number Of Common Shares OutstandingBasic


13,802,039



12,576,983Diluted


13,802,039



12,576,983Consolidated Statement of Comprehensive Income/(Loss)Comprehensive Income /(Loss)Net Income/(Loss)

$
(544,454
)

$
(2,356,509
)Other Comprehensive Income /(Loss)Foreign Currency Translation


59,892



88,440Comprehensive Income/(Loss)

$
(484,562
)

$
(2,268,069
)The accompanying notes are an integral part of these consolidated financial statements




F - 4
 Table of Contents






DELTA OIL & GAS INC.Consolidated StatementsOf Changes In Stockholders' EquityFor the years ended December 31, 2010 and 2009(Stated in U.S. Dollars)COMMON STOCKNUMBER





SHARE

SHARE



CUMULATIVEOF COMMON

PAR

ADDITIONAL

SUBSCRIPTIONS

SUBSCRIPTIONS

DEFICIT

COMPREHENSIVE

NONCONTROLLINGSHARES VALUE

VALUE

PAID-IN CAPITAL

RECEIVED

RECEIVABLE

ACCUMULATED

INCOME/(LOSS)

INTEREST

TOTALBalance, December 31, 2008

9,368,102


9,368


6,088,272


-


-


(3,573,762
)

5,978


-


2,529,856Shares issued for acquisition

of oil & gas properties

3,909,005


3,909


875,616


-


-


-


-


-


879,525Registration of shares

under Form S-4

-


-


(48,045
)

-


-


-


-


-


(48,045
)Noncontrolling interest

in subsidiary

-


-


-


-


-


-


-


100,631


100,631Shares issued to President,

CEO & CFO as part of their

compensation package

at $0.15

280,000


280


41,720


-


-


-


-


-


42,000Options issued to IR

consultant

-


-


35,998


-


-


-


-


-


35,998Options issued to CEO,

CFO & director

-


-


121,747


-


-


-


-


-


121,747Comprehensive Income/(Loss):Cumulative translation

adjustment

-


-


-


-


-


-


88,440


-


88,440Net loss for the year

-


-


-


-


-


(2,337,765
)

-


(18,744
)

(2,356,509
)Comprehensive loss

























(2,268,069
)Balance, December 31, 2009

13,557,107


13,557


7,115,308


-


-


(5,911,527
)

94,418


81,887


1,393,643Shares issued to President,

CEO & CFO as part of their

compensation package

at $0.195

300,000


300


58,200


-


-


-


-


-


58,500Eliminate noncontrolling interest

-


-


-


-


-


81,887


-


(81,887
)

-Eliminate deficit on investment

-


-


-


-


-


967,857


-


-


967,857Comprehensive Income/(Loss):Cumulative translation adjustment

-


-


-


-


-


-


59,892


-


59,892Net loss for the year

-


-


-


-


-


(544,454
)

-


-


(544,454
)Comprehensive loss

























(484,562
)Balance, December 31, 2010

13,857,107

$
13,857

$
7,173,508

$
-

$
-

$
(5,406,237
)
$
154,310

$
-

$
1,935,438The accompanying notes are an integral part of these consolidated financial statements




F - 5
 Table of Contents






DELTA OIL & GAS, INC.Consolidated Statements Of Cash Flows(Stated in U.S. Dollars)YEARS ENDEDDECEMBER 31,2010


2009Cash Flows From Operating Activities:Net income for the year

$
(544,454
)

$
(2,337,765
)Adjustments to reconcile net loss to net cashused in operating activities:Accretion


2,118



2,236Depreciation and depletion


184,537



42,446Impairment of natural gas and oil properties


-



1,255,561Loss on sale of natural gas and oil properties


-



750,305Loss on sale of investment


985,464



-Stock-based compensation expense


-



157,745Shares issued to President & CEO for servicess rendered


39,000



30,000Shares issued to CFO for services rendered


19,500



12,000Net income/(loss) attributable to the noncontrolling interest


-



(18,744
)Gain on sale of natural gas and oil properties


(518,874
)


(158,075
)Changes in operating assets and liabilities:Accounts receivable


(182,093
)


(4,882
)Accounts payable and accrued liabilities


62,521



11,329Project cost advance received


5,424



-Due to related party


21,322



1,527Franchise tax prepaid


1,004



(1,004
)Prepaid expenses


8,896



(6,271
)Advancement for oil and gas exploration costs


49,898



(49,898
)Net Cash Generated/(Used) In Operating Activities


134,263



(313,490
)Cash Flows From Investing Activities:Purchase of other equipment


-



(5,805
)Sale proceeds of natural gas and oil working interests


705,949



430,315Investment in natural gas and oil working interests


(801,642
)


(685,169
)Net Cash Generated /(Used) In Investing Activities


(95,693
)


(260,659
)Cash Flows From Financing Activities:Restricted cash


(8,370
)


-Share issue expenses


-



(48,045
)Eliminate cash in sales of investment


(11,772
)


-Net Cash Provided/(Used) By Financing Activities


(20,142
)


(48,045
)Net Increase/(Decrease) In Cash And Cash Equivalents


18,428



(622,194
)Effect of foreign currency adjustments on cash


59,892



88,440Cash And Cash Equivalents At Beginning Of Period(Excess Of Deposits Over Checks Issued)


446,808



980,562Cash And Cash Equivalents at end of Period

$
525,128


$
446,808Supplemental Disclosures Of Non-Cash, Investing and Financing Activities200,000 shares issued to the President & CEO as part of their

$
39,000


$
30,000compensation package100,000 shares issued to the CFO for services rendered

$
19,500


$
12,0003,909,005 shares issued for the acquisition of Oil and Gas properties

$
-


$
879,526Supplemental DisclosuresIncome taxes paid

$
2,377


$
5,406The accompanying notes are an integral part of these consolidated financial statements







F - 6
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)


1.           OPERATIONS





a)
Organization





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





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





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





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





b)
Business acquisition





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




March 26, 2009Purchase price:Share consideration – issued 3,909,005 common shares at $0.225 per share

$
879,526Cash payment - $0.0008 for 58,653,139 common shares


46,908Fair value of Non-Controlling Interests


100,631Total

$
1,027,065Represented By:

Net assets purchased


(45,399
)Increase in Oil and Gas Properties


(970,535
)Net Assets attributable to Non-Controlling Interests


(11,131
)$
Nil









F - 7
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)




1.        OPERATIONS (continued)




b)
Business acquisition





Purchase Price Allocation:





Share capital

$
3,495,046Accumulated deficit


(3,452,287
)Cumulative translation adjustment


13,771Total

$
56,530Investment in Subsidiary – 80.31%

$
45,399Non-Controlling Interest – 19.69%

$
11,131





As the acquisition was completed on March 26, 2009, the net loss of $76,453 of Stallion was included in the   consolidated financial statements as of December 31, 2009.





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





Cash and cash Equivalents

$
565Accounts receivable


13,712Prepaid Expenses


3,001Natural gas and oil properties


194,670Capital Assets, Net


4,190Total Assets

$
216,138Accounts Payable

$
(144,144
)Asset Retirement Obligation

Total Net Assets

Total Net Assets purchased – 80.31%


(15,464
)$
56,530$
45,399





The Company dissolved The Stallion Group on December 31, 2010.





c)
Going Concern





The accompanying financial statements have been prepared assuming that the Company will continue as a going concern.





As shown in the accompanying consolidated financial statements, the Company has incurred a net loss of $5,406,237 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 - 8
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


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





e)
Oil and Gas Joint Ventures





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








F - 9
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





2.           SIGNIFICANT ACCOUNTING POLICIES (continued)





f)
Revenue Recognition





Revenue from sales of crude oil, natural gas and refined petroleum products are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customers.  Title transfers for crude oil, natural gas and bulk refined products generally occur at pipeline custody points or when a tanker lifting has occurred.  Revenues from the production of oil and natural gas properties in which the Company shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period.  Gas imbalances occur when the Company’s actual sales differ from its entitlement under existing working interests.  The
Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that the partners can recoup their share of production from the field. As at December 31, 2010 and 2009, the Company had no overproduced imbalances.





g)
Cash and Cash Equivalent





Cash consists of cash on deposit with high quality major financial institutions, and to date has not experienced losses on any of its balances.  The carrying amounts approximated fair market value due to the liquidity of these deposits.  For purposes of the balance sheet and statements of cash flows, the Company considers all highly liquid instruments with maturity of three months or less at the time of issuance to be cash equivalents.





h)     Restricted Cash





Restricted cash consists of funds deposited in a trust account for the Texas Prospect, which can only be used for drilling and completion costs associated with the first well that is being drilled at this location.





i)      Concentration of Credit Risk





Financial instruments which potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents and accounts receivable.  The Company maintains cash at two financial institutions.  The Company periodically evaluates the credit worthiness of financial institutions, and maintains cash accounts only in large high quality financial institutions, thereby minimizing exposure for deposits in excess of federally insured amounts.  The Company believes credit risk associated with cash and cash equivalents to be minimal.  Deposits are insured up to $100,543, the amount that may be subject to
credit risk for the year ended December 31, 2010 is $424,457.





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 - 10
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





2.           SIGNIFICANT ACCOUNTING POLICIES (continued)





j)      Environmental Protection and Reclamation Costs (continued)





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





k)
Foreign Currency Translation





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





l)
Other Equipment





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





m)
Impairment of Long-Lived Assets





In the event that facts and circumstances indicate that the costs of long-lived assets, other than oil and gas properties, may be impaired, an evaluation of recoverability would be performed.  If an evaluation is required, the estimated future undiscounted cash flows associated with the asset would be compared to the asset’s carrying amount to determine if a write-down to market value or discounted cash flow value is required.  Impairment of oil and gas properties is evaluated subject to the full cost ceiling as described under Oil and Natural Gas Properties in Note 2c.





n)
Loss Per Share





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





The dilutive effect of outstanding options and warrants and their equivalents is reflected in diluted earnings per share by application of the treasury stock method.  Hence 900,000 options were excluded from the earnings per share calculation for the year ended December 31, 2010, since they were considered to be anti-dilutive.  The table below presents the computation of basic and diluted earnings per share for the year ended December 31, 2010 and 2009:





December 31, 2010


December 31, 2009Basic earnings per share computation:Loss from continuing operations and  net loss

$
(544,454
)

$
(2,337,765
)Basic shares outstanding


13,802,039



12,576,983Basic earnings per share

$
(0.04
)

$
(0.19
)








F - 11
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





2.
SIGNIFICANT ACCOUNTING POLICIES (continued)







Diluted earnings per share computation:Income (Loss) from continuing operations

$
(544,454
)

$
(2,337,765
)Basic shares outstanding


13,802,039



12,576,983Incremental shares from assumed conversions:Stock options


-



-Warrants


-



-Diluted shares outstanding


13,802,039



12,576,983Diluted earnings per share

$
(0.04
)

$
(0.19
)





The calculation for earnings per share excluded stock options as these were not in the money as at December 31, 2010 and 2009, respectively and have an anti-dilutive effect.





o)
Income Taxes





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





p)
Financial Instruments





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





Level 1





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





Level 2





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





Level 3





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





The Company’s financial instruments consist of cash and cash equivalent, accounts receivable, franchise tax prepaid, accounts payable and accrued liabilities and project cost advance received.






F - 12
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





2.           SIGNIFICANT ACCOUNTING POLICIES (continued)





p)    Financial Instruments (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





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





r)     Stock-Based Compensation.




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





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





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





3.           RECENT ACCOUNTING PRONOUNCEMENTS





In January 2010, the FASB issued Accounting Standards Update 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements. The ASU amends Subtopic 820-10 with new disclosure requirements and clarification of existing disclosure requirements. New disclosures required include the amount of significant transfers in and out of levels 1 and 2 fair value measurements and the reasons for the transfers. In addition, the reconciliation for level 3 activity will be required on a gross rather than net basis. The ASU provides additional guidance related to the level of disaggregation in determining classes of assets
and liabilities and disclosures about inputs and valuation techniques. The amendments are effective for annual or interim reporting periods beginning after December 15, 2009, except for the requirement to provide the reconciliation for level 3 activities on a gross basis, which will be effective for fiscal years beginning after December 15, 2010. The Company is currently assessing the impact of ASU 2010-6 and does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.





In January 2009, the SEC issued revisions to the natural gas and oil reporting disclosures, “Modernization of Oil and Gas Reporting, Final Rule” (the “Final Rule”). In addition to changing the definition and disclosure requirements for natural gas and oil reserves, the Final Rule changed the requirements for determining quantities of natural gas and oil reserves. The Final Rule requires the use of the 12-month un-weighted arithmetic average of the first-day-of-the-month prices for natural gas and oil, rather than the end-of-period price used prior to
adoption of the Final Rule, in estimating reserves. The Final Rule also changed certain accounting requirements under the full cost method of accounting for natural gas and oil activities. The





F - 13
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





3.           RECENT ACCOUNTING PRONOUNCEMENTS (continued)





amendments are designed to modernize the requirements for the determination of natural gas and oil reserves, aligning them with current practices and updating them for changes in technology. The Final Rule was effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. In addition, in January 2010, the FASB issued an accounting standards update relating to standards for extractive oil and gas activities. The accounting standards update amends existing standards to align the proved reserves calculation and disclosure requirements under U.S. GAAP with the requirements in the SEC rules. The Company adopted the new standards effective December 31, 2009. The new standards
were applied prospectively as a change in estimate. The application of this guidance will continue to result in future amounts recorded for depreciation, depletion and amortization and ceiling limitations being different from what would have been recorded had the Final Rule not been mandated. In April 2010, the FASB issued a further accounting standards update regarding extractive oil and gas industries to incorporate in accounting standards the revisions to Rule 4-10 of the SEC’s Regulation S-X. The amendment primarily consists of the addition and deletion of definitions of terms related to fossil fuel exploration and production arising from technology changes over the past several decades. The accounting guidance in Rule 4-10 did not change.





In April 2010, the FASB’s EITF issued Stock Compensation – Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades;an amendment to previously issued guidance regarding the classification of a share-based payment award as either equity or a liability. The amendments clarify that a share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance or service condition.
Therefore, such an award should not be classified as a liability if it otherwise qualifies as equity. This guidance is effective for fiscal years and interim periods within those fiscal years beginning on or after December 15, 2010. Earlier application is permitted. This guidance should be applied by recording a cumulative-effect adjustment to the opening balance of retained earnings, and the cumulative-effect adjustment should be calculated for all awards outstanding as of the beginning of the fiscal year in which it is initially applied, as if the guidance had been applied consistently since the inception of the award. The cumulative-effect adjustment should be presented separately. The adoption of this guidance did not impact the Company’s operating results, financial position or cash flows.





4.           NATURAL GAS AND OIL PROPERTIES





a)
Proved Properties





Properties

December 31, 2009


Additions


Disposals


Transfer

from

unproved

properties


Depletion

for the

period

Impairment

December 31,

2010USA properties

$
317,857


$
41,496


-


$
918,054


$
(178,391
)
-

$
1,099,016Canada properties


62,626



(28,335
)


(28,668
)


-



(5,623
)
-


-Total

$
380,483


$
13,161



(28,668
)

$
918,054


$
(184,014
)
-

$
1,099,016










F - 14
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)




4.             NATURAL GAS AND OIL PROPERTIES





b)
Proved Properties – Descriptions





Properties in USA





i.
Oklahoma, USA





2006-3 Drilling Program





In April 2007, the Company entered into the 2006-3 Drilling Program for a buy-in cost of $113,700 which will provide 12.5% Before Casing Point (“BCP”) working interest and After Casing Point (“ACP”) working interest of 10%.  In September 2007, Wolf#1-7 was abandoned. Its costs amount to $70,495 was moved to the proven cost pool for depletion.  In October 2007, Ruggles #1-15 was also abandoned and the cost of $84,506 was moved to the proven cost pool for depletion.





In the 2006-3 Drilling Program, Elizabeth #1-25 was plugged and abandoned on February 7, 2008.  Its cost amounted to $127,421 was moved to the proven cost pool for depletion.  Plaster #1-11 and Dale #1-15 started producing in January and February 2008, respectively, total cost of $205,064 was moved to the proven cost pool.  Loretta #1-22 was plugged and abandoned in 2009, its cost amounted to $139,334 was moved to the proved cost pool.





2007-1 Drilling Program





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





In the 2007-1 Drilling Program, Pollack #1-35 was plugged and abandoned on January 19, 2008.  Its cost amounted to $152,101 was moved to the proven cost pool for depletion.  Hulsey #1-8 started producing in February 2008; the cost of $200,382 was moved to the proven cost pool.  River #1-28 started producing in June 2008; the cost of $169,159 was moved to the proven cost pool.  Hulsey #2-8 started producing in January 2009; its cost amounted to $139,674 was moved to the proven cost pool for depletion.





2009-1 Drilling Program





On July 27, 2009, the Company entered into the 2009-1 Drilling Program for five wells which will provide 5.714286% Before Casing Point (“BCP”) working interest and 5.00% After Casing Point (“ACP”) working interest.  The Company’s buy-in costs for each well is $2,625.  During the three months to September 2009, the Company had paid buy-in, estimated drilling and completion costs for three wells, Saddle #1-28, Saddle #2-28 and Saddle #3-28.  Saddle #1-28 and Saddle #2-28 started producing in November 2009 and Saddle #3-28 in December 2009, the total cost amounted to $96,633 was moved to the proven cost pool for depletion.





2009-3 Drilling Program - 4 Wells




On August 7, 2009, the Company entered into an agreement with Ranken Energy to participate in a four      well drilling program in Garvin County, Oklahoma (the “2009-3 Drilling Program”).  The Company purchased a 6.25% working interest before casing point and 5.0% working interest after casing point in the 2009-3 Drilling Program for $37,775.  In addition to the total buy-in cost, the Company will be responsible for our proportionate share of the drilling and completion costs.  During the year ended December 31, 2009, the Company paid additional drilling costs in the amount of $115,017.  Jackson #1-18 started producing in January
2010, the total cost amounted to $62,956 was moved to the proven cost pool for depletion.  Brewer #1-20 was plugged and abandoned on June 2, 2010.  Its cost amounted to $64,922 was moved to the proven cost pool for depletion.  Miss Gracie #1-18 started producing in March 2010, the total cost amounted to $71,368 was moved to the proven cost pool for depletion.  Waunice # 1-36 started production in June 2010 and was plugged and abandoned on September 23, 2010.  Its cost amounted to $44,939 was moved to the









F - 15
 Table of Contents





Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





4.           NATURAL GAS AND OIL PROPERTIES (continued)





a)
Proved Properties – Descriptions





Properties in U.S.A.





2009-3 Drilling Program - 4 Wells (continued)





proven cost pool for depletion.





Joe Murray Farm #1-18





Joe Murray Farm #1-18 started producing in August 2010, the total cost amounted to $44,571 was moved to the proven cost pool for depletion.





ii.     Palmetto Point Prospect, Mississippi, USA





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





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





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




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




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




On January 11, 2008, the Company paid $11,030 for PP F-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








F - 16
 Table of Contents






Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





4. NATURAL GAS AND OIL PROPERTIES (continued)





a)
Proved Properties - Descriptions





Properties in U.S.A.




iii.    Mississippi II, Mississippi, USA (continued)




formation and 7.5% of all production to the base of the Wilcox formation.  In January 2007, the well CMR USA 39-14 was found to be proved.  The cost of $35,126 was added to the proven cost pool.  Dixon#1 was abandoned in January 2007, its costs amounted to $40,605 was moved to the proven cost pool for depletion.  Randall#1 was abandoned in June 2007, its costs amounted to $26,918 was moved to the proven cost pool for depletion.  BR F-24 was abandoned and its cost amounted to $41,999 was moved to the proven cost pool for depletion.  Faust #1, USA 1-37 and BR F-33 were found to be proven and the total cost of $129,360 was added to the proven cost
pool.





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





iv. Mississippi III, Mississippi, USA





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





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





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





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





vi.      Texas Prospect, Texas, USA





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





In August 2010, the first exploration well, Donner #1, started producing, the cost amounted to $304,479 was moved to the proven cost pool for depletion.





vii.
California #1-1 - Lonestar Prospect, California, USA




On September 1, 2010, the Company entered into an agreement for the joint exploration and development of the Lonestar Prospect located in California, USA.  The Company has 25% working interest in the initial Prospect Test Well, California 1-1.





In November 2010, Morrow 1-7 started producing, the cost amounted to $329,804 was moved to the proven cost pool for depletion.







F - 17
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





4.
NATURAL GAS AND OIL PROPERTIES (continued)





a)
Proved Properties - Descriptions





Properties in Canada





viii.
Wordsworth Prospect, Saskatchewan, Canada





On April 10, 2007, the Company entered into an agreement (the “Agreement”) with Petrex Energy Ltd., for a participation and Farm-out agreement where the Company will participate for 15% gross working interest before payout (BPO) and 7.5% gross working interest after pay out (APO) in a proposed four well horizontal drilling program in the Wordsworth area in Southeast Saskatchewan, Canada. The well, HZ 1C2-23 was drilled in September 2008 also started production from November 2008.  In June 2009, the Company joined the drilling of a new well, HZ 1B1-23/3B8, and paid CAD$49,826 for 5% working interest.





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





On July 1, 2010, the Company sold the remaining 5% of its Working Interest for CAD$750,000.





b)    Unproved Properties





Properties

December 31,

2009


Addition


Disposals


Transfer

to proved

properties


December 31,

2010USA properties

$
332,541


$
774,280


$
-


$
(918,054
)

$
188,767Canada properties


152,346



(1,142
)


(151,204
)


-



-Total

$
484,887


$
773,138


$
(151,204
)-

$
(918,054
)

$
188,767





c)
Costs not being amortized





The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2010, 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


2010


2009


2008


2007

and

PriorProperty acquisition costs and

transfer to proved property pool

$
-



(37,775
)


17,900



-



19,875Exploration and development

$
188,767



(258,345
)


(163,389
)


-



610,501Capitalized interest

$
-







-



-



-Total

$
188,767



(296,120
)


(145,489
)


-



630,376










F - 18
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





4.
NATURAL GAS AND OIL PROPERTIES (continued)





Properties in U.S.A.





i.
Mississippi II, Mississippi, USA





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





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





ii.     King City, California, USA





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





iii.
Texas Prospect, Texas, USA





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





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





Properties in Canada





vi.
Wordsworth Prospect, Saskatchewan, Canada





In April 2007, the Company entered into an agreement (the “Agreement”) with Petrex Energy Ltd., for a participation and Farm-out agreement where the Company will participate for 15% gross working interest before payout (BPO) and 7.5% gross working interest after pay out (APO) in a proposed four well horizontal drilling program in the Wordsworth area in Southeast Saskatchewan, Canada.  As at December 31, 2010, the Company had expended $152,714 of the well 3B9-23/3A11 and 2 HZ 3B9 LEG.  During the year ended December 31, 2010, the Company sold its working interest in the Wordsworth Prospect.





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.






F - 19
 Table of Contents






Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





5.
NATURAL GAS AND OIL EXPLORATION RISK (continued)





a)
Exploration Risk





Prices for natural gas and oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond its control.  Other factors that have a direct bearing on the Company’s


prospects are uncertainties inherent in estimating natural gas and oil reserves and future hydrocarbon production and cash flows, particularly with respect to wells that have not been fully tested and with wells having limited production histories; access to additional capital; changes in the price of natural gas and oil; availability and cost of services and equipment; and the presence of competitors with greater financial resources and capacity.





b)    Distribution Risk





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





c)
Credit Risk





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





d)
Foreign Operations Risk





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





6.
CURRENT LIABILITIES





The Company received $5,424 as of December 31, 2010 from Hillcrest Resources Ltd., as its share in the Texas project.  The Company will expend these funds for drilling the first exploration hole.





7.
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.










F - 20
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





7.
INCOME TAXES PAYABLE (continued)





Income tax expense for the years ended December 31, 2010 and 2009 consists of the following:





December 31


December 312010


2009State income taxes

$
2,377


$
5,406Net income tax expense

$
2,377


$
5,406





The effective income tax rate for years ended December 31, 2010 and December 31, 2009 differs from the       U.S. Federal statutory income tax rate due to the following:





December 31


December 31US

2010


2009Federal statutory income tax rate


(34.00
%)


(34.00
%)State income taxes (average), net of federal benefit


(6.12
%)


(3.77
%)Valuation allowance


40.12
%


37.77
%Net income tax provision (benefit)


-



-





CanadaFederal statutory income tax rate


(15.00
%)


(15.00
%)Provincial income taxes


(12.00
%)


(12.00
%)Valuation allowance


27.00
%


27.00
%Net income tax provision (benefit)


-



-





The current loss components of the deferred tax assets/(liabilities) as of December 31, 2010 and 2009 are as follows:





December 31


December 312010


2009US operating loss/(profit)

$
613,995


$
1,335,796Canadian operating loss


179,236



795,059$
793,231


$
2,130,855Tax at effective rate


294,765



656,516Change in estimate due to Canadian resource pool


(239,504
)


(140,846
)Change in estimate due to resource properties


(236,348
)


(211,821
)Change in estimate due to acquisition of Stallion


0.00



846,317Allowance for current rate change


50,370



112,291(Increase) decrease in valuation allowance


130,717



(1,262,457
)Deferred tax asset

$
-


$
-Effective income tax rate


37.16
%


30.81
%





The Company has $4,427,208 (2009: $6,362,891) net operating loss carry forward that will begin to expire on between, 2015 and 2030.





F - 21
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





7. INCOME TAXES PAYABLE (continued)





The cumulative components of the deferred tax assets as of December 31, 2010 and as of December 31, 2009 are as follows:





December 31


December 312010


2009US operating loss carry forward
$
2,309,273


$
4,518,268Canadian operating loss carry forward

2,117,935



1,844,623Resources pools Canada - available for expense

Resource assets capitalized

2,363,875

1,394,857



2,249,167

873,189$
8,185,940


$
9,485,247Effective income tax rate

37.16



30.81
%Deferred tax asset

3,041,895



2,922,467Valuation allowance

(3,041,895
)


(2,922,467
)$
-


$
-





8. ASSET RETIREMENT OBLIGATIONS





The Company follows the Accounting for Asset Retirement Obligations Topic of the FASB Accounting standards Codification.  This addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.  It also requires recognition of the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred.  As of December 31, 2010 and December 31, 2009, the Company recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with Asset retirement Obligations of the FASB
Accounting Standards Codification.  The liability for the fair value of an asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production.  The Company amortizes the amount added to the oil and gas properties and recognizes accretion expense in connection with the discounted liability over the remaining life of the respective well.  The estimated liability is based on historical experience in plugging and abandoning wells, estimated useful lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements.  The liability is a discounted liability using a credit-adjusted risk-free rate of 12%.





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





The Company amortizes the amount added to oil and gas properties and recognizes accretion expense in connection with the discounted liability over the remaining useful lives of the respective wells.





The information below reflects the change in the asset retirement obligations during the years ended December 31, 2010 and year ended December 31, 2009:





December 31,

2010


December 31,

2009Balance, beginning of period

$
21,487


$
23,604Liabilities assumed


5,161



6,138Revisions


(9,645
)


(10,491
)Accretion expense


2,118



2,236Balance, end of period

$
19,121


$
21,487








F - 22
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





9.           SHARE CAPITAL





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





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





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





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





Preferred Stock





The Company did not issue any preferred stock during the year ended December31, 2010 (December 31, 2009 - Nil).





ii. Stock Options





Compensation expense related to incentive stock options granted is recorded at their fair value as calculated by the Black-Scholes option pricing model.  Compensation expense was nil for year ended December 31,









F - 23
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





9. SHARE CAPITAL (continued)





2010 and $157,746 for the year ended December 31, 2009 related to options granted during the year ended December 31, 2009.  The changes in stock options are as follows:





NUMBER


WEIGHTED AVERAGE

EXERCISE PRICEBalance outstanding, December 31, 2009

Granted

Expired

Exercised

Balance outstanding, December 31, 2010

900,000

-

-

-


$
0.12

-

-

-900,000


$
0.12





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





December 31,

2010


December 31, 2009Risk-fee interest rate


-



2.50%Expected life of the option


-


3 yearExpected volatility


-


199.13% &

476.13%Expected dividend yield


-



-





The following table summarized information about the stock options outstanding as at December 31, 2010:





Options outstanding

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

Number of shares$0.15

$0.12
100,000

800,000
1.27

1.92

100,000

800,000





iii.
Common Stock Share Purchase Warrants





During the year ended December 31, 2010, 496,797 share purchase warrants expired on February 1, 2010.  As at December 31, 2010, there were no share purchase warrants outstanding for the purchase of common shares.





10.
RELATED PARTIES





During the year ended December 31, 2010, the Company paid $285,297 (December 31, 2009 - $207,121) for consulting fees and $42,447 (December 31, 2009 - $27,578) for accounting services to Companies controlled by directors and officers of the Company.  There was $22,849 (December 31, 2009 - $1,527) payable to directors and officers of the Company for the consulting fees and the reimbursement of expenses incurred on behalf of the Company.  Amounts paid to related parties are based on exchange amounts agreed upon by those related parties.





On March 8, 2010, the Company issued 300,000 shares of common stock in consideration for services rendered to Officers of the Company.  The price of the share as of March 8, 2010 was $0.195.  The total cost of $58,500 was recorded in the compensation expense for shares granted and was included in the general and administration expense.






F - 24
 Table of Contents






Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





11.
COMMITMENT AND CONTRACTURAL OBLIGATIONS





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





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




12. SEGMENTED INFORMATION




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





December 31, 2010


December 31, 2009RevenueUnited States

$
728,924


$
157,351Canada


655,421



353,566Total Revenue

$
1,384,345


$
510,917





AssetsUnited States

$
1,539,691


$
750,840Canada


543,544



703,699Total Assets

$
2,083,235


$
1,454,539





LiabilitiesUnited States

$
122,930


$
43,780Canada


24,867



17,116Total Liabilities

$
147,797


$
60,896










F - 25
 Table of Contents







Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)





13.        UNAUDITED OIL AND GAS RESERVE QUANTITIES





Costs Incurred


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





2008Property acquisition costs
USA

CanadaProved

57,250Unproved

(57,250
)Development costsExploratory costs

591,664


117,822Oil and gas expenditures

591,664


117,8222009Property acquisition costs
USA

CanadaProved

27,750Unproved

17,900Development costsExploratory costs

424,678


79,430Oil and gas expenditures

470,328


79,4302010Property acquisition costs
USA

CanadaProved

17,900Unproved

(17,900
)Development costsExploratory costs

1,741,655


(180,681
)Oil and gas expenditures

1,741,655


(180,681
)





The following unaudited reserve estimates presented as of December 31, 2010 and 2009 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.





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.








F - 26
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)








13.          UNAUDITED OIL AND GAS RESERVE QUANTITIES (continued)





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, 2008


206,173



53,355Revisions of previous estimate


(96,325
)


122,095Discoveries


13,140



27,500Reserves sold to third party


(78,340
)


(60,190
)Production


(1,858
)


(11,150
)Estimated quantity, December 31, 2009


42,790



131,610Revisions of previous estimate


49,180



-Discoveries


181,000



128,000Reserves sold to third party


(19,000
)


-Production


(34,880
)


(85,680
)Estimated quantity, December 31, 2010


219,090



173,930





Proved Reserves at year end

Developed

Undeveloped

TotalCrude Oil (Bbls)December 31, 2010

89,690

129,400

219,090December 31, 2009

23,970

18,820

42,790Gas (MCF)December 31, 2010

165,150

8,780

173,930December 31, 2009

124,350

7,260

131,610





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 - 27
 Table of Contents








Delta Oil & Gas, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER 31, 2010


(Stated in U.S. Dollars)







13.          UNAUDITED OIL AND GAS RESERVE QUANTITIES (continued)





December 31, 2010


December 31, 2009Future Cash inflows

$
8,489,300


$
3,143,360Future production costs


(1,374,687
)


(1,019,970
)Future development costs


(415,750
)


(15,250
)Future income tax expense


(427,924
)


(178,430
)Future cash flows


6,270,939



1,929,71010% annual discount for estimated timing of cash flows


(1,509,012
)


(767,300
)Standardized measure of discounted future next cash

$
4,761,927


$
1,162,410





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 31,2010


December 31,2009Beginning of year

$
1,162,410


$
968,550Sales and transfers of oil and gas produced, net production costs


5,345,940



1,009,942Net changes in prices and production costs and other


(354,717
)


(368,016
)Net changes due to discoveries


(741,812
)


(614,428
)Changes in future development costs


(400,500
)


265,654Revisions of previous estimates


-



-Other


-



-Net change in income taxes


(249,494
)


(99,292
)Accretion discount


-



-Future cash flows


3,599,417



193,860End of year

$
4,761,827


$
1,162,410










F - 28
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(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.


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GLOSSARY OF SELECTED OIL AND GAS TERMS




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


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




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




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




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




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




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




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




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




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




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




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




MBbls.  One thousand barrels.




MBOE.  One thousand BOEs.




Mcf.  One thousand cubic feet.




MMcf.  One million cubic feet.




NGLs.  Natural gas liquids.




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




Oil.  Crude oil or condensate.




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






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




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




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




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




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










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




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




SEC.  The United States Securities and Exchange Commission.




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




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




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













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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 11th day of September, 2012.




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-GayChristopher Paton-Gay, Chief Executive Officer and Director

(Principal Executive Officer)

September 11, 2012/s/ Douglas N. Bolen

September 11,  2012Douglas N. Bolen, President and Director/s/ Kulwant Sandher

September 11, 2012Kulwant Sandher, Chief Financial Officer and Director

(Principal Financial Officer and Principal Accounting Officer)













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DELTA OIL & GAS, INC.





EXHIBIT INDEX
 TO
 2010 ANNUAL REPORT ON FORM 10-K/A


Exhibit

Number

Description

Incorporated by Reference to:

FiledHerewith3.1

Amended and Restated Articles of Incorporation of Delta.

Exhibit 3 of Delta’s Form SB-2 filed on February 13, 20023.2

Articles of Amendment to the Articles of Incorporation of Delta

Exhibit 3.1 of Delta’s Quarterly Report of Form 10-Q for the period ended September 30, 2009.3.3

Articles of Amendment to the Articles of Incorporation of Delta

Exhibit 3.1 of Delta’s Form 8-K dated October 21, 2009.3.4

By-laws of Delta, as amended.

Exhibit 3.4 of Delta's Form 10-K for the year ended December 31, 200910.1

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, 200710.2

Farmout Agreement by and between Sunset Exploration, Inc. and Delta, effective May 25, 2009

Exhibit 10.1 of Delta’s Quarterly Report of Form 10-Q dated June 30, 200910.3

Letter Agreement by and between Ranken Energy Corporation and Delta relating to 2009-1 Drilling Program

Exhibit 10.2 of Delta’s Quarterly Report of Form 10-Q dated June 30, 200910.4

Assignment of Oil, Gas, & Liquid Hydrocarbon Leases dated July 15, 2009, relating to the Texas Prospect

Exhibit 10.1 of Delta’s Quarterly Report of Form 10-Q dated September 30, 200910.5

Letter Agreement by and between Delta and Ranken Energy Corporation dated August 7, 2009

Exhibit 10.2 of Delta’s Quarterly Report of Form 10-Q dated September 30, 200910.6

Amended and Restated Consulting Agreement, dated as of March 8, 2010, by and between Delta and Warwick Management Services

Exhibit 10.1 of Delta’s Form 8-K filed March 9, 201010.7

Amended and Restated Consulting Agreement, dated as of March 8, 2010, by and between Delta and Last Mountain Management Ltd.

Exhibit 10.2 of Delta’s Form 8-K filed March 9, 201010.8

Amended and Restated Consulting Agreement, dated as of March 8, 2010, by and between Delta and CPG Consulting Ltd.

Exhibit 10.3 of Delta’s Form 8-K filed March 9, 201010.9

Delta 2010 Incentive Compensation Plan

Exhibit 10.1 of Delta’s Form 8-K filed March 12, 2010









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Exhibit

Number

Description

Incorporated by Reference to:

Filed

Herewith10.10

Exploration Agreement by and between Barry Lasker and Delta, dated March 27, 2009

Exhibit 10.12 of Delta's Form 10-K for the year ended December 31, 200910.11

Assignment and Assumption Agreement, dated as of December 8, 2009, between Delta and Hillcrest Resources, Ltd.

Exhibit 10.13 of Delta's Form 10-K for the year ended December 31, 200910.12

Purchase and Sale Agreement, dated as of July 1, 2010, between Delta Oil & Gas, Inc. and Petrex Energy Ltd.

Exhibit 10.1 of Delta’s Form 8-K dated August 9, 2010.10.13

Lonestar Prospect Exploration Agreement, dated September 1, 2010

Exhibit 10.9 of Delta’s Quarterly Report of Form 10-Q dated September 30, 201014.1

Code of Ethics and Conduct

Exhibit 10.1 of Delta’s Form 10-KSB filed on April 19, 200416.1

Letter from STS Partners LLP

Exhibit 16.1 of Delta’s Form 8-K dated September 24, 2010.21.1

Subsidiaries of Delta.

The same titled exhibit to Delta’s Report on Form 10-K for the fiscal year ended December 31, 2010.23.1

Consent of Harper & Associates, Inc.

The same titled exhibit to Delta’s Report on Form 10-K for the fiscal year ended December 31, 2010.23.2

Consent of Mark E. Andersen

The same titled exhibit to Delta’s Report on Form 10-K for the fiscal year ended December 31, 2010.23.3

Consent of AJM Petroleum Consultants

The same titled exhibit to Delta’s Report on Form 10-K for the fiscal year ended December 31, 2010.23.4

Consent of Independent Registered Public Accounting Firm

The same titled exhibit to Delta’s Report on Form 10-K for the fiscal year ended December 31, 2010.31.1

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



X99.1

Report of Harper & Associates, Inc. independent consulting engineers

The same titled exhibit to Delta’s Report on Form 10-K for the fiscal year ended December 31, 2010.99.2

Report of Mark E. Andersen independent consulting engineers

The same titled exhibit to Delta’s Report on Form 10-K for the fiscal year ended December 31, 2010.99.3

Report of AJM Petroleum Consultants  independent consulting engineers

The same titled exhibit to Delta’s Report on Form 10-K for the fiscal year ended December 31, 2010.












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