UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION




Washington,
D.C.  20549




Form
10-K





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




For the
fiscal year ended December 31,
2009




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




For the
transition period from 
to _______.




Commission
file number:  000-52001




Delta
Oil & Gas, Inc.


(Exact
name of registrant as specified in its charter)




Colorado
            
            91-210350(State
      or other jurisdiction of incorporation or organization)
            
            (I.R.S.
      Employer Identification No.)Suite
      604 - 700 West Pender Street, Vancouver, British Columbia Canada, V6C
      1G8(Address
      of principal executive
      offices)                    (Zip
      Code)Registrant’s
      telephone, including area code:   (866)
      355-3644





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




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




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






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




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




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




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




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




Large
accelerated filer  ̈                                                                                                   Accelerated
filer  ̈


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




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




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




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







FORM
10-K


DELTA
OIL & GAS, INC.


DECEMBER
31, 2009









Table of Contents






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




PART
      II




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




PART
      III




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




PART
      IV




Item
      15.         Exhibits, Financial Statement Schedules.
            46GlossarySignature PageExhibit Index







- 2
-


Cautionary
Note Regarding Forward Looking Statements




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




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




·
            changes
      in our business strategy;




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




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




·
            results
      of current and future exploration
activities;




·
            results
      of pending and future feasibility
studies;




·
            accidents
      and labor disputes;




·
            disappointing
      results from our exploration or development
  efforts;




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




·
            decline
      in demand for our common stock;




·
            changes
      in general market conditions;




·
            investor
      perception of our industry or our
prospects;




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




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




·
            the
      availability of pipeline capacity;




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




·
            the
      availability of alternate fuel
sources;




·
            the
      effect of inclement weather, such as
hurricanes;




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




·
            unexpected
      changes in business and economic
conditions;




·
            changes
      in interest rates and currency exchange
rates;




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




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




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




·
            local
      and community impacts and issues.




- 3
-





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




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




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




- 4
-


PART
I






ITEM 1. BUSINESS.




Business
of Delta




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




Our current focus is on the exploration
of our land portfolio comprised of working interests in acreage in King City,
California; Southern Saskatchewan, Canada; South Central, Oklahoma; and Eastern,
Texas.  As a result of our acquisition of a controlling interest in
The Stallion Group, a Nevada corporation, which is discussed below, we expanded
our property interests to include acreage in the North Sacramento Valley,
California.




Reverse
Stock Split




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





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





No
fractional shares were issued in connection with the reverse stock split and any
fractional shares potentially issuable were rounded up to the next whole
number.





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





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





Acquisition
of Controlling Interest in The Stallion Group




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




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




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




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




- 5
-





Hillspring
Prospect





On
November 26, 2004, through our wholly-owned Canadian subsidiary, Delta Oil &
Gas (Canada), Inc., we entered into an agreement (the "Agreement") with Win
Energy Corporation, ("Win Energy"), an Alberta based oil & gas exploration
company, in order to acquire an interest in leases owned by Win
Energy.  On or about January 25, 2005, we paid Win Energy $414,766 in
exchange for a 10% working interest in one section of land (640 acres) in
Hillspring located approximately 90 miles south of Calgary, Alberta in the
Southern Alberta Foothills belt.  During the year ended December 31,
2008, management reassessed its participation in this project and determined to
abandon this project due to concerns regarding its profitability.  We
did not incur any costs in connection with our abandonment of this project and
do not anticipate incurring any future costs.





Strachan
Prospect




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




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




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




Palmetto
Point Prospect - 12 Wells Phase - I




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





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





Effective
February 1, 2009, we disposed of our interests in the Palmetto Point Prospect -
12 Wells Phase - I project described above.  These interests were
disposed of together with the interests in the Palmetto Point Prospect – 50
Wells Phase II project described below.  Total revenue received from
the Palmetto Point Phase I producing wells for the year ended December 31, 2009
was $Nil, compared with $38,981in revenues for the year ended December 31,
2008.  The decrease in revenue was attributable to our disposition of
these wells during fiscal 2009.





- 6
-




Palmetto
Point Prospect - 50 wells – Phase II




During
the fiscal quarter ended September 30, 2006, we entered into a joint venture
agreement to acquire an interest in a drilling program comprised of up to fifty
natural gas and/or oil wells.  The area in which the wells are being
drilled is approximately 300,000 gross acres located between Southwest
Mississippi and Northeastern Louisiana.  Drilling commenced in
September 2006.  The site of the first twenty wells is located within
range to tie into existing pipeline infrastructure should the wells be suitable
for commercial production.  The drilling program was conducted by
Griffin Exploration in its capacity as operator.  We agreed to pay 10%
of all prospect fees, mineral leases, surface leases, and drilling and
completion costs to earn a net 8.0% share of all production zones to the base of
a geological formation referred to as the Frio formation and 7.5% of all
production to the base of a geological formation referred to as the Wilcox
formation.  The cost during the quarter ending September 30, 2006
amounted to $100,000.  During the fourth quarter of fiscal 2006, we
made additional payments of $300,000 that was employed in the further
development of prospects on lands in Mississippi and Louisiana in accordance
with the terms of the operating agreement.





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





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





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





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





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





Wordsworth
Prospect




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




- 7
-




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




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




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




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




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




Owl
Creek Prospect




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





Pursuant
to the terms of the assignment agreement with Brinx Resources, we acquired a 20%
working interest in an oil well drilled at the Owl Creek Prospect (the “Powell
#2”).  The Powell #2 was drilled to total depth of 5,617 feet on May
18, 2006 and underwent testing.  Based upon the positive result of the
testing of the Powell #2, this well was completed and commercial production
commenced in August 2006.  Under the terms of the assignment
agreement, we are responsible for our proportionate share of the costs of
completion and tie-in for production of the Powell #2, which was $68,987 and was
paid.  Initially, the Powell #2 began flowing oil and natural gas
under its own pressure without the assistance of a pump.  In July
2008, the Company disposed of its holdings in Powell #2 and the surrounding area
for aggregate consideration of $760,438.





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





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





- 8
-




In
January 2007, we commenced drilling of another well (the “Isbill
#2-36”).  Our 20% working interest in the Isbill #2-36 cost $157,437
for both drilling and completion.  The Isbill #2-36 was drilled to
approximately 5,900 feet and encountered two potential pay zones and is a direct
offset well to the Powell #2.  In July 2008, we disposed of our
holdings in Isbill #2-36 and the surrounding area for aggregate consideration of
$549,388.





In July
2008, we sold both the Powell #2 and Isbill #2-36 wells and all interest in the
Owl Creek Prospect for gross proceeds of $1,309,826.  We realized a
gain on sale of the property of $1,067,447.  We decided to dispose of
the property based on the declining rates of production experienced by the
operator and the reasonable offer for both wells and the surrounding lands of
1,120 acres.





2006-3 Drilling
Program




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




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





Three other wells drilled (the
“Elizabeth #1-25”, the “Plaster #1-1” and the “Dale #1 re-entry”) were deemed by
the operator to be commercially viable and production casing was set in
each.  The Elizabeth #1-25 located in the Meridian Prospect cost
$99,129, the Plaster #1-1 located in the Plaster Prospect cost $116,581, and
re-entry into the Dale #1 located in the Dale Prospect cost $18,150, all of
which was paid August and September , 2007.  Subsequent to the
completion of these wells, two remain economically viable at this
time.  The Plaster #1 encountered hydrocarbon showings and is
producing natural gas with amounts of associated oil as of January,
2008.  The Dale #1 re-entry has been producing in the range of 2 to 3
barrels of oil per day.  The Elizabeth #1-25 has been plugged and
abandoned as of February 7, 2008.  Total revenue received from the
Plaster #1 and Dale #1 wells for the year ended December 31, 2009 was $7,920
(December 31, 2008: $46,923).  The reduction in revenue was caused by
the suspension of production, the gradual decline in the reserves from these
wells and the reduction in commodity prices when compared to the previous
year.




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




2007-1
Drilling Program - 3 Wells




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




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




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






- 9
-




Hulsey
#2-8 commenced production during the three months ended March 31, 2009 and
produced $20,034 in oil revenues for the year ended December 31,
2009.  Our proportionate costs associated with the Hulsey #2-8 well
amounted to $139,674, which was moved to the proved properties cost pool for
depletion.




2009-1
Drilling Program - 5 Wells




On July
27, 2009, we entered into an agreement with Ranken Energy to participate in a
five well drilling program in Garvin County, Oklahoma (the “2009-1 Drilling
Program”).  We initially acquired a 5.0% working interest in the
2009-1 Drilling Program in exchange for our payment of a total of $13,125 in
buy-in costs, which equates to $2,625 in buy-in costs for each well, plus our
proportionate shares of the drilling and completion costs.  During the
fourth quarter of 2009, our working interest in the 2009-1 Drilling Program was
reduced to 3.75%.  The reduction in our working interest was
attributable to the landowner exercising an option to increase its working
interest causing in a proportional reduction to all working interests held in
this drilling program.  During the year ended December 31, 2009, we
paid estimated drilling and completion costs of $72,175for
three wells which we refer to as Saddle #1-18, Saddle #2-18
and  Saddle #3-18.  The first two wells in this drilling
program started to produce hydrocarbons in November and December 2009, resulting
in revenue of $6,390 for the year ended December 31, 2009.




2009-3
Drilling Program - 4 Wells




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




Willows
Gas Field




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




King
City, California




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








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Texas
Prospect




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





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





Net
      Revenue DistributionBefore
      Payout
            After
      PayoutWell
      #1
            36%
            20%Well
      #2
            36%
            24%Well
      #3
            36%
            28%





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





Market
for Our Products and Services




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




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




•           the
level of domestic production;




•           actions
taken by foreign oil and gas producing nations;




•           the
availability of pipelines with adequate capacity;




•           the
availability and marketing of other competitive fuels;




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




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


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


products and alternative fuels.




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




- 11
-




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





Competition




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




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




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




Research
and Development




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




Existing
and Probable Governmental Regulation




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




United
States Government Regulation




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




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




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




- 12
-




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




Environmental
Regulation




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




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





Canadian
Government Regulation




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




Pricing
and Marketing Natural Gas




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




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




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-




Royalties
and Incentives




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




Land
Tenure




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




Compliance
with Environmental Laws




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




Employees




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






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




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ITEM 1A.Risk Factors.




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




Risk
Factors




Risks
Associated With Our Business





Operational
Risks of Delta





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





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





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





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





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





We do not operate the properties in
which we have a working interest and we have limited ability to exercise
influence over operations for these properties or their associated costs. Our
dependence on the operator and other working interest owners for these projects
and our limited ability to influence operations and associated
costs


- 15
-


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





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





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





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





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




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





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


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-





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





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





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





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





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





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





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





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





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





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





Market
Risks





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





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




•           changes
in the worldwide price for oil and gas;




•           disappointing
results from our exploration or development efforts;




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




•           decline
in demand for our common stock;




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




•           technological
innovations by competitors or in competing technologies;




•           investor
perception of our industry or our prospects; and




•           general
economic trends.





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




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




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





- 18
-


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




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




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




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




•           the
availability of pipeline capacity;




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




•           the
availability of alternate fuel sources;




•           the
effect of inclement weather, such as hurricanes;




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




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




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




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




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





Risks
Relating to Our Business




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




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




- 19
-


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





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




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





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





•
            future
      development and operating costs.





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




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




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




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





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





•           unexpected
drilling conditions including blowouts and explosions;




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




•           equipment
failures, fires or accidents;




•           pollution
and other environmental risks; and




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





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






- 20
-




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


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


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





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


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





Risks
Relating to our Common Stock





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





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





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





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




- 21
-




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




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




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




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




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




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




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




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





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





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





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







- 22
-





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





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





Indemnification
of officers and directors.




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




ITEM 1B.UNRESOLVED
STAFF COMMENTS.





None.




ITEM 2. PROPERTIES.




Description
of Our Property





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





Proved
Reserves Reporting


On
December 31, 2008, the Securities and Exchange Commission, or the SEC,
released a Final Rule, Modernization of Oil and Gas
Reporting, approving revisions designed to modernize oil and gas reserve
reporting requirements. The new reserve rules are effective for our financial
statements for the year ended December 31, 2009 and our 2009 year-end
proved reserve estimates. The most significant revisions to the reporting
requirements include:
 ·
                  Commodity
      prices.  Economic producibility of reserves is now based
      on the unweighted, arithmetic average of the closing price on the first
      day of the month for the 12-month period prior to fiscal year end, unless
      prices are defined by contractual
arrangements;
 ·
                Undeveloped oil and gas
      reserves.  Reserves may be classified as “proved
      undeveloped” for undrilled areas beyond one offsetting drilling unit from
      a producing well if there is reasonable certainty that the quantities will
      be recovered;


- 23
-


·
              Reliable
      technology.  The rules now permit the use of new
      technologies to establish the reasonable certainty of proved reserves if
      those technologies have been demonstrated empirically to lead to reliable
      conclusions about reserves volumes;
 ·
              Unproved
      reserves.  Probable and possible reserves may be
      disclosed separately on a voluntary
basis;
 ·
              Preparation of reserves
      estimates.  Disclosure is required regarding the internal
      controls used to assure objectivity in the reserves estimation process and
      the qualifications of the technical person primarily responsible for
      preparing reserves
estimates; and
 ·
              Third party
      reports.  We are now required to file the report of any
      third party used to prepare or audit reserves our
    estimates.


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





Reported
Reserves Table




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





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





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





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




- 24
-




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





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





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





Proved
Undeveloped Reserves





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





Internal
Controls Over Preparation of Proved Reserve Estimates





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


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-


Reserves
Reported to Other Agencies





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





Production




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





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




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





Production
      Data
            Year
      Ended December 312009
            2008
            2007USA
            Canada
            USA
            Canada
            USA
            CanadaProduction
      -Oil
      (Bbls)
            1,877
            3,898
            5,116
            1,261
            9,370
            2,144Gas
      (Mcf)
            12,279
            0
            28,559
            0
            33,394
            0Average
      Sales Price -Oil
      (Bbls)
            $53.00
            $58.00
            $98.00
            $88.00
            $66.00
            $61.00Gas
      (Mcf)
            $4.00
            $0.00
            $9.00
            $0.00
            $6.00
            $0.00Average
      Production CostsOil
      (Bbls)
            $20.00
            $14.00
            $19.00
            $40.00
            $9.00
            $9.00Gas
      (Mcf)
            $2.00
            $0.00
            $3.00
            $0.00
            $2.00
            $0.00





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





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-


Productive
Wells and Acreage





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


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





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





Undeveloped
Acreage





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


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




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





- 27
-


Drilling
Activity




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





Geographical
      Area
            Net
      Exploratory Wells Drilled
            Net
      Development Wells DrilledProductive
      1
            Dry
      2
            Productive
      1
            Dry
      2Garvin,
      McClain & Murray Counties, Oklahoma 32009
            0.45
            0.20
            0
            02008
            0.30
            0.20
            0
            02007
            0.50
            0.40
            0.20
            0Alberta,
      Canada
              (Strachan)2009
            0
            0
            0
            02008
            0
            0
            0
            02007
            0
            0
            0
            0Palmetto
      Point, Mississippi
              (Palmetto)2009
            0
            0
            0
            02008
            1.17
            1.22
            0
            02007
            1.17
            1.22
            0
            0Saskatchewan,
      Canada
              (Wordsworth)2009
            0.05
            0
            0.10
            02008
            0.075
            0
            0
            02007
            0.075
            0.075
            0
            0Willows
      Gas Field, North Sacramento Valley, California,2009
            0
            0
            0
            02008
            0.0625
            0
            0
            02007
            0
            0
            0
            0Totals
            0.50
            0
            0.10
            0





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





Present
Activities





A
discussion of present activities on our property interests is included in the
description of business disclosure set forth above.
  - 28
-


Delivery
Commitments





We are
not obligated to provide a fixed and determined quantity of oil or gas in the
future. During the last three fiscal years, we have not had, nor do we now have,
any long-term supply or similar agreement with any government or governmental
authority.
  We are
not obligated to provide a fixed and determinable quantity of oil or natural gas
in the near future under existing contracts or agreements. Further, during the
last three years we had no significant delivery
commitments.




ITEM 3. Legal
Proceedings.




None.




ITEM 4. Reserved.




- 29
-


PART
II




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




Market
Prices




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





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




Fiscal
      Year Ended December 31, 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
            $0Fiscal
      Year Ended December 31, 2008Fiscal Quarter
      Ended:
            High
      Bid
            Low
      BidMarch
      31, 2008
            $1.525
            $0.75June
      30, 2008
            $0.90
            $0.445September
      30, 2008
            $0.50
            $0.225December
      31, 2008
            $0.325
            $0.05







Holders
of Common Stock




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





Dividend
Policy




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




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




- 30
-


Securities
Authorized for Issuance under Equity Compensation Plans





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


Equity
Compensation Plan as of December 31, 2009


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





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


Recent
Issuances of Unregistered Securities




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





ITEM 6.Selected
Financial Data.




Not
applicable.




- 31
-


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




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




For
the Years Ended December 31, 2009 and 2008




Revenues





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





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





Costs
and Expenses





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





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





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





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





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





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






- 32
-





·
            Depreciation
      and depletion expensefor the year ended
      December 31, 2009 decreased to $42,446 from $265,942 for the year ended
      December 31, 2008, a decrease of 84%. The decrease in depreciation and
      depletion expense is attributable to the disposal of Owl Creek and the
      partial disposal of the Wordsworth wells; this was partially offset by
      additional uneconomic wells that were moved to the proved property pool
      for depletion; and





·
            Impairment
      of natural gas and oil properties expense for the year ended December 31,
      2009 decreased to $1,255,561 from $1,393,687 for the year ended December
      31, 2008, a decrease of 10%.  The decrease in impairment of
      natural gas and oil properties expense for the year ended December 31,
      2009, as compared to the year ended December 31, 2008, is attributable to
      the impairment of our working interests in the Willow’s Gas Field
      resulting from our third party evaluation that the costs associated with
      these prospects are highly unlikely to be
  recovered.





Net
Operating Loss





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





Other
Income and Expense





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





Net
Loss





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





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





- 33
-


Liquidity
and Capital Resources





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





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





Cash
Used in Operating Activities





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





Cash
Used in Investing Activities





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





Cash
from Financing Activities





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





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





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




·
            Property
      acquisition costs; and




·
            Sale
      of the Owl Creek Prospect.





Off-Balance
Sheet Arrangements




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




- 34
-





Going
Concern





As shown
in the accompanying financial statements, we have incurred a net loss of
$5,911,527 since inception.  To achieve profitable operations, we
require additional capital for obtaining producing oil and gas properties
through either the purchase of producing wells or successful exploration
activity.  We believe that we will be able to obtain sufficient
funding to meet our business objectives, including anticipated cash needs for
working capital and are currently evaluating several financing
options.  However, there can be no assurances offered in this
regard.  As a result of the foregoing, there exists substantial doubt
about our ability to continue as a going concern.





Critical
Accounting Policies





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





Oil
& Gas Joint Ventures





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





Natural
Gas and Oil Properties





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





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





Revenue
Recognition





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


- 35
-


Recent
Accounting Pronouncements





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





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





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





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





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




Not
applicable




ITEM 8. Financial Statements and Supplementary
Data.




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




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




None.




- 36
-


ITEM 9A.Controls and
Procedures.




Conclusion
Regarding the Effectiveness of Disclosure Controls and Procedures




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




Management’s
Report on Internal Control Over Financial Reporting




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




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




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




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




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




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




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





Changes
in Internal Control Over Financial Reporting




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




- 37
-


ITEM 9B.       Other
Information.




None.




- 38
-


PART
III




ITEM 10. Directors,
Executive Officers and Corporate Governance.





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





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





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





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





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





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





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





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





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





- 39
-





Audit
Committee




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




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




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




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




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





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




Section 16(a)
Beneficial Ownership Reporting




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





Code
of Ethics and Conduct




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







- 40
-


ITEM 11. Executive
Compensation.




Summary
Compensation Table





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





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





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





Compensation
Components.





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





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





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




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




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




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





- 41
-




Consulting
Agreements.





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





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





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





·
            Any
      earned but unpaid annual base
compensation;


·
            Any
      earned but unissued stock awards;


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


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


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





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





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





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


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


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


·
            Material
      breach of the Consulting Agreement;
or


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





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





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


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


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


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




- 42
-




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





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




Outstanding
Equity Awards at Fiscal Year-End





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




Stock
Option Plans




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




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




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






- 43
-




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




Compensation
of Directors




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





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




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





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





*
            Represents
      less than 1% of the class.





(1) Unless
otherwise provided, the address of each person is c/o Suite 604 - 700 West
Pender Street, Vancouver, British Columbia,
 Canada V6C 1G8.
  Except as
otherwise indicated, all shares shown in the table are owned with sole voting
and investment power.
  This
column represents shares not included in “Shares Owned” that may be acquired by
the exercise of options within 60 days of
 March 5, 2010.


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




- 44
-




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




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





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





ITEM 14. Principal
Accounting Fees and Services.




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





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




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




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




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




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





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




- 45
-




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




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




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




PART
IV




ITEM 15. Exhibits,
Financial Statement Schedules.




(a)(1)





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










- 46
-





REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM











To the
Board of Directors and Stockholders of


Delta
Oil & Gas, Inc.


(A
Development Stage Company)








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





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





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





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





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







/s/ STS PARTNERSHIP 
LLP


STS
PARTNERS LLP


CHARTERED
ACCOUNTANTS




Vancouver,
British Columbia, Canada


April 12,
2010







F -
1





DELTA
      OIL & GAS, INC.Consolidated
      Balance Sheets(Stated
      in U.S. Dollars)December
      31,
            
            
            December
      31,2009
            
            
            2008ASSETSCurrentCash
      and cash equivalents
            
            $
            446,808
            
            
            $
            980,562Accounts
      receivable
            
            
            70,496
            
            
            
            65,614Franchise
      tax prepaid
            
            
            1,004
            
            
            
            -Prepaid
      expenses
            
            
            17,464
            
            
            
            11,193Advancement
      for oil and gas exploration costs
            
            
            49,898
            
            
            
            -585,670
            
            
            
            1,057,369Natural
      Gas And Oil PropertiesProved
      property
            
            
            380,483
            
            
            
            892,096Unproved
      property
            
            
            484,887
            
            
            
            630,376865,370
            
            
            
            1,522,472Property,
      Plant and Equipment (net)
            
            
            3,499
            
            
            
            172TOTAL
      ASSETS
            
            $
            1,454,539
            
            
            $
            2,580,013LIABILITIES AND STOCKHOLDERS'
      EQUITYLIABILITIESCurrentAccounts
      payable and accrued liabilities
            
            $
            37,882
            
            
            $
            26,553Due
      to related party
            
            
            1,527
            
            
            
            -39,409
            
            
            
            26,553Long
      TermAsset
      retirement obligation
            
            
            21,487
            
            
            
            23,604TOTAL
      LIABILITIES
            
            
            60,896
            
            
            
            50,157STOCKHOLDERS'
      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, 13,557,107 and 9,368,102 shares issuedand
      outstanding, respectively
            
            
            13,557
            
            
            
            9,368Additional
      paid-in capital
            
            
            7,115,308
            
            
            
            6,088,272Accumulative
      Other Comprehensive loss
            
            
            94,418
            
            
            
            5,978Accumulated
      Deficit
            
            
            (5,911,527
            )
            
            
            (3,573,762
            )1,311,756
            
            
            
            2,529,856Noncontrolling
      Interest
            
            
            81,887
            
            
            
            -TOTAL
      STOCKHOLDERS' EQUITY
            
            
            1,393,643
            
            
            
            2,529,856TOTAL
      LIABILITIES AND STOCKHOLDERS' EQUITY
            
            $
            1,454,539
            
            
            $
            2,580,013The
      accompanying notes are an integral part of these consolidated financial
      statements


F -
2


DELTA
      OIL & GAS, INC.Consolidated
      Statements Of Operations(Stated
      in U.S. Dollars)YEAR
      ENDEDDECEMBER
      31,2009
            
            
            2008RevenueNatural
      gas and oil sales
            
            $
            352,841
            
            
            $
            860,092Gain
      on sale of natural gas and oil properties
            
            
            158,076
            
            
            
            1,067,447510,917
            
            
            
            1,927,539Costs
      And ExpensesNatural
      gas and oil operating costs
            
            
            120,022
            
            
            
            222,269General
      and administrative
            
            
            700,512
            
            
            
            257,552Accretion
            
            
            2,236
            
            
            
            2,529Depreciation
      and depletion
            
            
            42,446
            
            
            
            265,942Impairment
      of natural gas and oil properties
            
            
            1,255,561
            
            
            
            1,393,687Loss
      on sale of natural gas and oil properties
            
            
            750,305
            
            
            
            -2,871,082
            
            
            
            2,141,979Net
      Operating Loss
            
            
            (2,360,165
            )
            
            
            (214,440
            )Other
      Income And (Expense)Interest
      income
            
            
            9,062
            
            
            
            7,025Interest
      expense
            
            
            -
            
            
            
            (5,016
            )9,062
            
            
            
            2,009Loss
      Before Income Taxes
            
            
            (2,351,103
            )
            
            
            (212,431
            )Income
      taxes
            
            
            5,406
            
            
            
            3,395Net
      Loss
            
            
            (2,356,509
            )
            
            
            (215,826
            )Less:
      Net loss attributable to the noncontrolling interest
            
            
            18,744
            
            
            
            -Net
      Loss Attributable to Delta Oil & Gas, Inc.
            
            $
            (2,337,765
            )
            
            $
            (215,826
            )Basic
      And Diluted Loss Per Common Share
            
            $
            (0.19
            )
            
            $
            (0.02
            )Weighted
      Average Number OfCommon
      Shares Outstanding
            
            
            12,576,983
            
            
            
            9,368,102Consolidated
      Statement of Comprehensive LossComprehensive
      LossNet
      Loss
            
            $
            (2,356,509
            )
            
            $
            (215,826
            )Other
      Comprehensive Income (Loss)Foreign
      Currency Translation
            
            
            88,440
            
            
            
            (181,370
            )Comprehensive
      Loss
            
            $
            (2,268,069
            )
            
            $
            (397,196
            )The
      accompanying notes are an integral part of these consolidated financial
      statements






F -
3
  DELTA
      OIL & GAS INC.Consolidated
      Statements Of Changes In Stockholders' EquityPeriod
      From Inception, January 9, 2001, to December
  31, 2009(Stated
      in U.S. Dollars)DEFICITCOMMON
      STOCK
              
              
              
              
              
              ACCUMULATEDNUMBER
              
              
              
              
              
              SHARE
              
              
              SHARE
              
              
              DURING
      THE
              
              
              CUMULATIVEOF
      COMMON
              
              PAR
              
              
              ADDITIONAL
              
              
              SUBSCRIPTIONS
              
              
              SUBSCRIPTIONS
              
              
              DEVELOPMENT
              
              
              COMPREHENSIVE
              
              
              NONCONTROLLINGSHARES
      VALUE
              
              VALUE
              
              PAID-IN
      CAPITAL
              
              
              RECEIVED
              
              
              RECEIVABLE
              
              
              STAGE
              
              
              INCOME/(LOSS)
              
              
              INTEREST
              
              
              TOTALShares
      issued for cash at $0.00018
              
              
              2,750,000
              
              
              $
              2,750
              
              
              $
              (250
              )
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              2,500Shares
      issued for cash at $0.0036
              
              
              5,500,000
              
              
              
              5,500
              
              
              
              94,500
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              100,000Shares
      issued for cash at $0.045
              
              
              9,350
              
              
              
              9
              
              
              
              2,116
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              2,125Net
      (loss) for the period ended
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (184,407
              )
              
              
              -
              
              
              
              -
              
              
              
              (184,407
              )Balance,
      December 31, 2001
              
              
              8,259,350
              
              
              
              8,259
              
              
              
              96,366
              
              
              
              -
              
              
              
              -
              
              
              
              (184,407
              )
              
              
              -
              
              
              
              -
              
              
              
              (79,782
              )Net
      (loss) for the year
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (62,760
              )
              
              
              -
              
              
              
              -
              
              
              
              (62,760
              )Balance,
      December 31, 2002
              
              
              8,259,350
              
              
              
              8,259
              
              
              
              96,366
              
              
              
              -
              
              
              
              -
              
              
              
              (247,167
              )
              
              
              -
              
              
              
              -
              
              
              
              (142,542
              )Net
      (loss) for the year
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (24,423
              )
              
              
              -
              
              
              
              -
              
              
              
              (24,423
              )Balance,
      December 31, 2003
              
              
              8,259,350
              
              
              
              8,259
              
              
              
              96,366
              
              
              
              -
              
              
              
              -
              
              
              
              (271,590
              )
              
              
              -
              
              
              
              -
              
              
              
              (166,965
              )Share
      subscriptions received
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              160,000
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              160,000Net
      (loss) for the year
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (31,574
              )
              
              
              -
              
              
              
              -
              
              
              
              (31,574
              )Balance,
      December 31, 2004
              
              
              8,259,350
              
              
              
              8,259
              
              
              
              96,366
              
              
              
              160,000
              
              
              
              -
              
              
              
              (303,164
              )
              
              
              -
              
              
              
              -
              
              
              
              (38,539
              )Units
      issued for cash at $1.00,
              
              
              496,797
              
              
              
              497
              
              
              
              2,483,228
              
              
              
              (160,000
              )
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              2,323,725net
      of share issuance costOptions
      exercised for cash at $0.8
              
              
              49,000
              
              
              
              49
              
              
              
              195,951
              
              
              
              -
              
              
              
              (16,000
              )
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              180,000Stock-based
      compensation
              
              
              -
              
              
              
              -
              
              
              
              370,267
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              370,267Net
      (loss) for the year
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (570,050
              )
              
              
              -
              
              
              
              -
              
              
              
              (570,050
              )Balance,
      December 31, 2005
              
              
              8,805,147
              
              
              
              8,805
              
              
              
              3,145,812
              
              
              
              -
              
              
              
              (16,000
              )
              
              
              (873,214
              )
              
              
              -
              
              
              
              -
              
              
              
              2,265,403Subscriptions
      receivable
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              16,000
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              16,000Options
      exercised for cash at $0.8
              
              
              61,000
              
              
              
              61
              
              
              
              243,939
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              244,000Options
      exercised for cash at $1.00
              
              
              2,500
              
              
              
              3
              
              
              
              12,498
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              12,501Shares
      issued for cash at $2.75,
              
              
              145,455
              
              
              
              145
              
              
              
              1,849,850
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              1,849,995net
      of finders feeStock-based
      compensation
              
              
              -
              
              
              
              -
              
              
              
              195,719
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              195,719Net
      (loss) for the year
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (234,763
              )
              
              
              -
              
              
              
              -
              
              
              
              (234,763
              )Balance,
      December 31, 2006
              
              
              9,014,102
              
              
              
              9,014
              
              
              
              5,447,818
              
              
              
              -
              
              
              
              -
              
              
              
              (1,107,977
              )
              
              
              -
              
              
              
              -
              
              
              
              4,348,855Options
      exercised for cash at $0.75
              
              
              12,000
              
              
              
              12
              
              
              
              44,988
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              45,000Shares
      issued to President & CEO as
              
              
              100,000
              
              
              
              100
              
              
              
              459,900
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              460,000part
      of his compensation package at $0.92Shares
      issued to Investor Relations
              
              
              12,000
              
              
              
              12
              
              
              
              40,788
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              40,800Services,
      Inc. as part of the agreementShares
      issued to CFO for services rendered
              
              
              50,000
              
              
              
              50
              
              
              
              137,450
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              137,500Stock-based
      compensation
              
              
              -
              
              
              
              -
              
              
              
              42,097
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              42,097Comprehensive
      Income/(loss):Cumulative
      translation adjustment
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              187,348
              
              
              
              -
              
              
              
              187,348Net
      (loss) for the year
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (2,249,959
              )
              
              
              -
              
              
              
              -
              
              
              
              (2,249,959
              )Comprehensive
      (loss)
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (2,062,611
              )Balance,
      December 31, 2007
              
              
              9,188,102
              
              
              
              9,188
              
              
              
              6,173,041
              
              
              
              -
              
              
              
              -
              
              
              
              (3,357,936
              )
              
              
              187,348
              
              
              
              -
              
              
              
              3,011,641Shares
      issued to President & CEO & CFO as
              
              
              180,000
              
              
              
              180
              
              
              
              47,520
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              47,700part
      of their compensation package at $0.053Registration
      of shares under Form S-4
              
              
              -
              
              
              
              -
              
              
              
              (132,289
              )
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (132,289
              )Comprehensive
      Income/(Loss):Cumulative
      translation adjustment
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (181,370
              )
              
              
              -
              
              
              
              (181,370
              )Net
      loss for the year
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (215,826
              )
              
              
              -
              
              
              
              -
              
              
              
              (215,826
              )Comprehensive
      loss
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (397,196
              )Balance,
      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
              
              
              3,909,005
              
              
              
              3,909
              
              
              
              875,616
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              879,525propertiesRegistration
      of shares under Form S-4
              
              
              -
              
              
              
              -
              
              
              
              (48,045
              )
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (48,045
              )Noncontrolling
      interest in subsidiary
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              100,631
              
              
              
              100,631Shares
      issued to President, CEO & CFO as
              
              
              280,000
              
              
              
              280
              
              
              
              41,720
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              42,000part
      of his compensation package at $0.03Options
      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
              
              
              $
              1,393,643The
      accompanying notes are an integral part of these consolidated financial
      statements
  F -
4


DELTA
      OIL & GAS, INC.Consolidated
      Statements Of Cash Flows(Stated
      in U.S. Dollars)YEARS
      ENDEDDECEMBER
      31,2009
            
            
            2008Cash
      Flows From Operating Activities:Net
      loss for the year
            
            $
            (2,337,765
            )
            
            $
            (215,826
            )Adjustments
      to reconcile net loss to net cashused
      in operating activities:Accretion
            
            
            2,236
            
            
            
            2,529Depreciation
      and depletion
            
            
            42,446
            
            
            
            265,942Impairment
      of natural gas and oil properties
            
            
            1,255,561
            
            
            
            1,393,687Loss
      on sale of natural gas and oil properties
            
            
            750,305
            
            
            
            -Stock-based
      compensation expense
            
            
            157,745
            
            
            
            -Shares
      issued to President & CEO for servicess rendered
            
            
            30,000
            
            
            
            26,500Shares
      issued to CFO for services rendered
            
            
            12,000
            
            
            
            21,200Shares
      issued to Investor Relations Services Inc for services
      rendered
            
            
            -
            
            
            
            -Realized
      foreign exchange loss
            
            
            88,440
            
            
            
            (181,370
            )Net
      loss attributable to the noncontrolling interest
            
            
            (18,744
            )
            
            
            -Gain
      on sale of natural gas and oil properties
            
            
            (158,075
            )
            
            
            (1,067,447
            )Changes
      in operating assets and liabilities:GIC
            
            
            -
            
            
            
            236,112Accounts
      receivable
            
            
            (4,882
            )
            
            
            88,376Accounts
      payable and accrued liabilities
            
            
            11,329
            
            
            
            (139,664
            )Due
      to related party
            
            
            1,527
            
            
            
            -Franchise
      tax prepaid
            
            
            (1,004
            )
            
            
            6,912Prepaid
      expenses
            
            
            (6,271
            )
            
            
            8,171Advancement
      for oil and gas exploration costs
            
            
            (49,898
            )
            
            
            -Net
      Cash Generated/(Used) In Operating Activities
            
            
            (225,050
            )
            
            
            445,122Cash
      Flows From Investing Activities:Purchase
      of other equipment
            
            
            (5,805
            )
            
            
            -Sale
      proceeds of natural gas and oil working interests
            
            
            430,315
            
            
            
            1,309,826Investment
      in natural gas and oil working interests
            
            
            (685,169
            )
            
            
            (713,212
            )Net
      Cash Generated /(Used) In Investing Activities
            
            
            (260,659
            )
            
            
            596,614Cash
      Flows From Financing Activities:Registration
      of shares under Form S-4
            
            
            -
            
            
            
            (132,289
            )Share
      issue expenses
            
            
            (48,045
            )
            
            
            -Proceeds
      from issuance of common stock
            
            
            -
            
            
            
            -Net
      Cash Provided/(Used) By Financing Activities
            
            
            (48,045
            )
            
            
            (132,289
            )Net
      Increase/(Decrease) In Cash And Cash Equivalents
            
            
            (533,754
            )
            
            
            909,447Cash
      And Cash Equivalents At Beginning Of Period(Excess
      Of Deposits Over Checks Issued)
            
            
            980,562
            
            
            
            71,115Cash
      And Cash Equivalents at end of year
            
            $
            446,808
            
            
            $
            980,562Supplemental
      Disclosures Of Non-Cash, Investing and Financing
Activities200,000
      shares issued to the President & CEO as part of their
            
            $
            30,000
            
            
            $
            26,500compensation
      package80,000
      shares issued to the CFO for services rendered
            
            $
            12,000
            
            
            $
            21,2003,909,005
      shares issued for the acquisition of Oil and Gas
properties
            
            $
            879,526
            
            
            $
            -Supplemental
      DisclosuresIncome
      taxes paid
            
            $
            5,406
            
            
            $
            3,395The
      accompanying notes are an integral part of these consolidated financial
      statements




F -
5





Delta
Oil & Gas, Inc.


NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER
31, 2009


(Stated
in U.S. Dollars)




1.           OPERATIONS





a)
            Organization





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





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





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





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





b)
            Business
      acquisition





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





March
      26, 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 -
6





Delta
Oil & Gas, Inc.


NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER
31, 2009


(Stated
in U.S. Dollars)




1.            OPERATIONS
(continued)




c)     
 Business acquisition





Purchase
      Price Allocation:Share
      capital
            
            $
            3,495,046Accumulated
      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 Obligatoin
            
            
            (15,464
            )Total
      Net Assets
            
            $
            56,430Total
      Net Assets purchased - 80-31%
            
            $
            45,399





c)
            Going
      Concern





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





As shown
in the accompanying consolidated financial statements, the Company has incurred
a net loss of $5,911,527 since inception.  To achieve profitable
operations, the Company requires additional capital for obtaining producing oil
and gas properties through either the purchase of producing wells or successful
exploration activity.  Management believes that sufficient funding
will be available to meet its business objectives including anticipated cash
needs for working capital and is currently evaluating several financing
options.  However, there can be no assurance that the Company will be
able to obtain sufficient funds to continue the development of its properties
and, if successful, to commence the sale of its projects under
development.  As a result of the foregoing, there exists substantial
doubt the Company’s ability to continue as a going concern.  These
consolidated financial statements do not include any adjustments that might
result from the outcome of this uncertainty.





2.           SIGNIFICANT
ACCOUNTING POLICIES





a)
            Basis
      of Consolidation





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





F -
7





Delta
Oil & Gas, Inc.


NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER
31, 2009


(Stated
in U.S. Dollars)




1.            OPERATIONS
(continued)




c)     
Business acquisition





2.           SIGNIFICANT
ACCOUNTING POLICIES (continued)





b)
            Use
      of Estimates





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





c)
            Natural
      Gas and Oil Properties





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





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





d)
            Asset
      Retirement Obligations





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





e)
            Oil
      and Gas Joint Ventures





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








F -
8





Delta
Oil & Gas, Inc.


NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER
31, 2009


(Stated
in U.S. Dollars)





2.
            SIGNIFICANT
      ACCOUNTING POLICIES (continued)





f)
            Revenue
      Recognition





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





g)
            Cash
      and Cash Equivalent





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




h)     Concentration
of Credit Risk





Financial instruments which potentially subject the Company to
concentrations of credit risk consist of cash and
cash equivalents and accounts receivable.  The Company
maintains cash at one financial institution.  The Company periodically
evaluates the credit worthiness of financial institutions, and maintains cash
accounts only in large high quality financial institutions, thereby minimizing
exposure for deposits in excess of federally insured amounts.  The
Company believes credit risk associated with cash and cash equivalents to be
minimal.  Deposits are insured up to $95,147, the amount that may be
subject to credit risk for the year ended December 31, 2009 is
$351,661.





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





i)
            Environmental
      Protection and Reclamation Costs





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





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





F -
9





Delta
Oil & Gas, Inc.


NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER
31, 2009


(Stated
in U.S. Dollars)





2.
            SIGNIFICANT
      ACCOUNTING POLICIES (continued)





j)
            Foreign
      Currency Translation





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





k)
            Other
      Equipment





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





l)
            Impairment
      of Long-Lived Assets





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





m)
            Loss
      Per Share





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





n)
            Income
      Taxes





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





o)
            Financial
      Instruments





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





Level
1






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





F -
10





Delta
Oil & Gas, Inc.


NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER
31, 2009


(Stated
in U.S. Dollars)





2.
            SIGNIFICANT
      ACCOUNTING POLICIES (continued)





Level
2






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






Level
3






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





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





It is
management’s opinion that the Company is not exposed to significant interest or
credit risks arising from these financial instruments.  The fair value
of these financial instruments is approximated to their carrying
values.





p)     Comprehensive
Loss





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





q)     Stock-Based
Compensation





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





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





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





3.
            RECENT
      ACCOUNTING PRONOUNCEMENTS





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





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





F -
11





Delta
Oil & Gas, Inc.


NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


DECEMBER
31, 2009


(Stated
in U.S. Dollars)





3.
            RECENT
      ACCOUNTING PRONOUNCEMENTS
(continued)





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





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





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








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





4.  
   NATURAL GAS
AND OIL PROPERTIES





a)
            Proved
      Properties





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





a)     
 Proved Properties – Descriptions





Properties
in U.S.A.





i.
            Oklahoma,
      USA





2006-3
Drilling Program





In April
2007, the Company entered into the 2006-3 Drilling Program for a buy-in cost of
$113,700 which will provide 12.5% Before Casing Point (“BCP”) working interest
and After Casing Point (“ACP”) working interest of 10%.  In September
2007, Wolf#1-7 was abandoned. Its costs amount to $68,118 was moved to the
proven cost pool for depletion.  In October 2007, Ruggles #1-15 was
also abandoned and the cost of $84,328 was moved to the proven cost pool for
depletion.


In the
2006-3 Drilling Program, Elizabeth #1-25 was plugged and abandoned on February
7, 2008.  Its cost amounted to $127,421 was moved to the proven cost
pool for depletion.  Plaster #1-11 and Dale #1-15






F -
12


Delta
Oil & Gas, Inc.
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER
31, 2009
 (Stated
in U.S. Dollars)


4.  NATURAL GAS
AND OIL PROPERTIES (continued)





a)    Proved
Properties – Descriptions





Properties
in U.S.A.





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





2007-1
Drilling Program





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





In the
2007-1 Drilling Program, Pollack #1-35 was plugged and abandoned on January 19,
2008.  Its cost amounted to $150,841 was moved to the proven cost pool
for depletion.  Hulsey #1-8 started producing in February 2008; the
cost of $161,039 was moved to the proven cost pool.  River #1-28
started producing in June 2008; the cost of $150,582 was moved to the proven
cost pool.  During August to September 2008, the Company paid
estimated drilling costs of $82,830 and estimated completion costs of $80,905
for the well, Hulsey #2-8.  Hulsey #2-8 started producing in January
2009; its cost amounted to $139,674 was moved to the proven cost pool for
depletion.





i.    
      Oklahoma, USA (continued)





2009-1
Drilling Program





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





ii.   Palmetto Point Prospect,
Mississippi, USA




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





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





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







F -
13




Delta
Oil & Gas, Inc.
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER
31, 2009
 (Stated
in U.S. Dollars)





4.     
NATURAL GAS AND OIL PROPERTIES
(continued)





a)    Proved
      Properties – Descriptions





Properties
in U.S.A.




On August
4, 2006, the Company elected to participate in additional two wells program in
Mississippi.




owned by
Griffin & Griffin Exploration and paid $70,000.  These wells were
found to be proved in December 2008.




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






On
January 11, 2008, the Company paid $11,030 for PP F-41salt water disposal
well.




iii.
            Mississippi
      II, Mississippi, USA





In August
2006, the Company entered into a joint venture agreement with Griffin &
Griffin Exploration, LLC. to acquire an interest in a drilling program comprised
of up to 50 natural gas and/or oil wells.  The area in which the wells are
to be drilled is comprised of approximately 300,000 gross acres of land
located




iii.   
Mississippi II, Mississippi, USA




between
Southwest Mississippi and North East Louisiana. The wells are targeting the Frio
and Wilcox Geological formations. The Company has agreed to pay 10% of all
prospect fees, mineral leases, surface leases and drilling and completion costs
to earn a net 8% share of all production zones to the base of the Frio formation
and 7.5% of all production to the base of the Wilcox formation.  In
January 2007, the well CMR USA 39-14 was found to be proved.  The cost
of $35,126 was added to the proven cost pool.  Dixon#1 was abandoned
in January 2007, its costs amounted to $40,605 was moved to the proven cost pool
for depletion.  Randall#1 was abandoned in June 2007, its costs
amounted to $26,918 was moved to the proven cost pool for
depletion.  BR F-24 was abandoned and its cost amounted to $41,999 was
moved to the proven cost pool for depletion.  Faust #1, USA 1-37 and
BR F-33 were found to be proven and the total cost of $129,360 was added to the
proven cost pool.





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





iv.    
      Mississippi III, Mississippi, USA





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





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





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





Through
the Company’s subsidiary, Stallion, the Company acquired a well working interest
in California, U.S.A.  On October 15, 2007, Stallion agreed to
participate in the drilling program to be conducted by Production Specialties
Company (“PSC”).  Stallion shall pay for the initial test well, 12.5%
of 100% of all costs and expenses of drilling, completing, testing and equipping
the Wilson Creek #1-27, to earn 6.25%






F -
14


Delta
Oil & Gas, Inc.
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER
31, 2009
 (Stated
in U.S. Dollars)


4.  NATURAL GAS AND OIL PROPERTIES
      (continued)





a)    Proved
      Properties - Descriptions





Properties
in Canada





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





vi.   Wordsworth
      Prospect, Saskatchewan, Canada





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





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





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




vii. 
 Strachan Prospect, Alberta, Canada





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




b)   Unproved
Properties




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






F -
15


Delta
Oil & Gas, Inc.
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER
31, 2009
 (Stated
in U.S. Dollars)


4.  NATURAL GAS AND OIL PROPERTIES
(continued)





b)
            Unproved
      Proved Properties - Descriptions





Properties
      in U.S.A.





c)
            Costs
      Not Being Amortized







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





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





i.    
      Mississippi II, Mississippi, USA





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





i.  
        Mississippi II, Mississippi,
USA





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





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




ii.     
King City, California, USA





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





iii.    
      Texas Prospect, Texas, USA





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






F -
16


Delta
Oil & Gas, Inc.
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER
31, 2009
 (Stated
in U.S. Dollars)


4.  
NATURAL GAS AND OIL PROPERTIES
(Continued)





b)   Unproved
      Proved Properties - Descriptions





Properties
      in U.S.A.





iv.
            2009-3
      Drilling Program - 4 Wells




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




Properties
in Canada





v.    
      Wordsworth Prospect, Saskatchewan,
Canada





In April
2007, the Company entered into an agreement (the “Agreement”) with Petrex Energy
Ltd., for a participation and Farm-out agreement where the Company will
participate for 15% gross working interest before payout (BPO) and 7.5% gross
working interest after pay out (APO) in a proposed four well horizontal drilling
program in the Wordsworth area in Southeast Saskatchewan, Canada.  As
at December 31, 2009, the Company had expended $152,347 of the well 3B9-23/3A11
and 2 HZ 3B9 LEG.





5.           NATURAL
GAS AND OIL EXPLORATION RISK





a) Exploration
Risk





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





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


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





b)    Distribution
Risk





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





c)
            Credit
      Risk





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






F -
17




Delta
Oil & Gas, Inc.
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER
31, 2009
 (Stated
in U.S. Dollars)


5.          NATURAL
GAS AND OIL EXPLORATION RISK (continued)





d)
            Foreign
      Operations Risk





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





6. INCOME
TAXES PAYABLE





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




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





December
      31
            
            
            December
      312009
            
            
            2008State
      income taxes  2008 (2007)
            
            $
            5,406
            
            
            $
            3,395Net
      income tax expense
            
            $
            5,406
            
            
            $
            3,395





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





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




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






F -
18




Delta
Oil & Gas, Inc.
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER
31, 2009
 (Stated
in U.S. Dollars)
  6. INCOME
TAXES PAYABLE (continued)





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





December
      31
            
            
            December
      312009
            
            
            2008US
      operating loss/(profit)
            
            $
            1,335,796
            
            
            $
            (587,883
            )Canadian
      operating loss
            
            
            795,059
            
            
            
            168,961$
            2,130,855
            
            
            $
            (418,922
            )Tax
      at effective rate
            
            
            656,516
            
            
            
            (123,998
            )Change in
      estimate due to Canadian resource pool
            
            
            (140,846
            )
            
            
            -Change
      in estimate due to resource properties
            
            
            (211,821
            )
            
            
            59,951Change
      in estimate due to acquisition of Stallion
            
            
            846,317
            
            
            
            -Allowance
      for current rate change
            
            
            112,291
            
            
            
            (256,948
            )(Increase)
      decrease in valuation allowance
            
            
            (1,262,457
            )
            
            
            320,995Deferred
      tax asset
            
            $
            -
            
            
            $
            -Effective
      income tax rate
            
            
            30.81
            %
            
            
            29.59
            %





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





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




December
      31
            
            
            December
      312009
            
            
            2008US
      operating loss carry forward
            
            $
            4,518,268
            
            
            $
            435,638Canadian
      operating loss carry forward
            
            
            1,844,623
            
            
            
            905,658Resources
      pools Canada - available for expense
              Resource
      assets capitalized
            
            
            2,249,167
              873,189
            
            
            
            2,706,303
              1,560,681$
            9,485,247
            
            
            $
            5,608,280Effective
      income tax rate
            
            
            30.81
            %
            
            
            29.59
            %Deferred
      tax asset
            
            
            2,922,467
            
            
            
            1,660,010Valuation
      allowance
            
            
            (2,922,467
            )
            
            
            (1,660,010
            )$
            -
            
            
            $
            -






F -
19




Delta
Oil & Gas, Inc.
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER
31, 2009
 (Stated
in U.S. Dollars)





6. INCOME
TAXES PAYABLE (continued)





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




Restated
              
              
              PriorOperating
      loss carry forward
              
              $
              4,047,599
              
              
              $
              3,457,724Natural
      Gas and Oil properties
              
              
              1,560,681
              
              
              
              1,600,5275,608,280
              
              
              
              5,068,251Effective
      income tax rate
              
              
              29.59
              %
              
              
              34.00
              %Deferred
      tax asset
              
              
              1,660,010
              
              
              
              1,723,205Valuation
      Allowance
              
              
              (1,660,010
              )
              
              
              (1,723,205Deferred
      tax asset
              
              $
              -
              
              
              $
              -
 7. ASSET
RETIREMENT OBLIGATIONS





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





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





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





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





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








F -
20




Delta
Oil & Gas, Inc.
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER
31, 2009
 (Stated
in U.S. Dollars)





8.           SHARE
CAPITAL





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





i.
            Common
      Stock





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





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





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





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





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





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





On May 1,
2007, the Company issued 12,000 common shares to Investor Relations Services,
Inc. as part of the investor relation services and consulting
agreement.  The price of the share as of May 1, 2007 was
$6.40.





On July
8, 2007, the Company issued 50,000 common shares to its Chief Financial Officer
as part of his services rendered and in lieu of cancellation of stock
options.  The price of the share was $2.75.  It was the
average of the share price of July 6 and July 9, 2007.





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





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





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





Preferred
Stock





The
Company did not issue any preferred stock during the year ended December 31,
2009 (December 31, 2008 - Nil).





ii. Stock
Options





Compensation
expense related to incentive stock options granted is recorded at their fair
value as calculated by the Black-Scholes option pricing
model.  Compensation expense of $157,746 was recorded during the year
ended December 31, 2009 (December 31, 2008 – nil) related to options granted
during the year ended December 31, 2009.  The changes in stock options
are as follows:






F -
21


Delta
Oil & Gas, Inc.
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER
31, 2009
 (Stated
in U.S. Dollars)
  8. SHARE
CAPITAL (continued)





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




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




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








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





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









F -
22




Delta
Oil & Gas, Inc.
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER
31, 2009
 (Stated
in U.S. Dollars)





iii.    
 Common Stock Share Purchase Warrants





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





Warrants
outstanding


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





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





9.
            RELATED
      PARTIES





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




On April
3, 2009, the Company issued 280,000 shares of common stock in consideration for
services rendered to Officers of the Company.  The price of the share
as of April 3, 2009 was $0.15.  The total cost of $42,000 was recorded
in the compensation expense for shares granted and was included in the general
and administration expense.





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





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





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




F -
23




Delta
Oil & Gas, Inc.
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 DECEMBER
31, 2009
 (Stated
in U.S. Dollars)





10.        COMMITMENT
AND CONTRACTURAL OBLIGATIONS





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





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




11.         SEGMENTED
INFORMATION




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





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








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








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














F -
24





Delta
Oil & Gas, Inc.
 DECEMBER
31, 2009
 (Stated
in U.S. Dollars)





UNAUDITED
      OIL AND GAS RESERVE QUANTITIES





Costs
Incurred


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





2007Property
      acquisition costs
              
              USA
              
              
              CanadaProved
              
              
              36,575
              
              
              
              -Unproved
              
              
              154,225
              
              
              
              -Development
      costs
              
              
              -
              
              
              
              -Exploratory
      costs
              
              
              1,403,137
              
              
              
              265,656Oil
      and gas expenditures
              
              
              1,593,937
              
              
              
              265,6562008Property
      acquisition costs
              
              USA
              
              
              CanadaProved
              
              
              57,250
              
              
              
              -Unproved
              
              
              (57,250
              )
              
              
              -Development
      costs
              
              
              -
              
              
              
              -Exploratory
      costs
              
              
              591,664
              
              
              
              117,822Oil
      and gas expenditures
              
              
              591,664
              
              
              
              117,8222009Property
      acquisition costs
              
              USA
              
              
              CanadaProved
              
              
              27,750
              
              
              
              -Unproved
              
              
              17,900
              
              
              
              -Development
      costs
              
              
              -
              
              
              
              -Exploratory
      costs
              
              
              424,678
              
              
              
              79,430Oil
      and gas expenditures
              
              
              470,328
              
              
              
              79,430
 The
following unaudited reserve estimates presented as of December 31, 2008 and 2007
were prepared by independent petroleum engineers.  There are many
uncertainties inherent in estimating proved reserve quantities and in projecting
future production rates and the timing of development
expenditures.  In addition,  reserve  estimates of
new discoveries that
have  little  production  history  are  more  imprecise  than  those
of properties with more production history.  Accordingly, these
estimates are expected to change as future information becomes
available.





F -
25




Delta
Oil & Gas, Inc.
 DECEMBER
31, 2009
 (Stated
in U.S. Dollars)







UNAUDITED OIL AND GAS RESERVE
QUANTITIES (continued)





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





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





Crude
      Oil
            
            
            Natural
      GasChanges
      in proved reserves
            
            (Bbls)
            
            
            (MCF)Estimated
      quantity, December 31, 2007
            
            
            74,894
            
            
            
            166,660Revisions
      of previous estimate
            
            
            0
            
            
            
            (120,951
            )Discoveries
            
            
            174,199
            
            
            
            36,205Reserves
      sold to third party
            
            
            (36,543
            )
            
            
            0Production
            
            
            (6,377
            )
            
            
            (28,559
            )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, 2008
            
            
            42,790
            
            
            
            131,610





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





UNAUDITED
STANDARIZED MEASURE





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





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





F -
26




Delta
Oil & Gas, Inc.
 DECEMBER
31, 2009
 (Stated
in U.S. Dollars)








UNAUDITED OIL AND GAS RESERVE
QUANTITIES (continued)





December
      31,
              2009
            
            
            December
      31,
              2008Future
      Cash inflows
            
            $
            3,143,360
            
            
            $
            2,133,418Future
      production costs
            
            
            (1,019,970
            )
            
            
            (651,954
            )Future
      development costs
            
            
            (15,250
            )
            
            
            (280,904
            )Future
      income tax expense
            
            
            (178,430
            )
            
            
            (79,138
            )Future
      cash flows
            
            
            1,929,710
            
            
            
            1,121,42210%
      annual discount for estimated timing of cash flows
            
            
            (767,300
            )
            
            
            (152,871
            )Standardized
      measure of discounted future next cash
            
            $
            1,162,410
            
            
            $
            968,550




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





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








F -
27











(a)(2)           Not
Applicable.





(a)(3)           Exhibits.


See
(b) below.








(b)            Exhibits.


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





(c)            Financial
Statements Excluded From Annual Report to Shareholders


Not
Applicable.


- 47
-


GLOSSARY OF SELECTEDOIL AND GAS TERMS


The
following is a description of the meanings of some of the oil and gas industry
terms used in this report.
  3-D seismic.  An
advanced technology method of detecting accumulations of hydrocarbons identified
by the collection and measurement of the intensity and timing of sound waves
transmitted into the earth as they reflect back to the surface.
  After
payout – With respect to an oil or natural gas interest in a property,
refers to the time period after which the costs to drill and equip a well have
been recovered.
  BOE.  Means a
barrel of oil equivalent and is a standard convention used to express oil and
gas volumes on a comparable oil equivalent basis.  Gas equivalents are
determined under the relative energy content method by using the ratio of 6.0
Mcf of gas to 1.0 Bbl of oil or natural gas liquid.
  Bbl.  One barrel,
or 42 U.S. gallons of liquid volume.
  Before payout– With respect to an oil and natural gas interest in a property, refers
to the time period before which the costs to drill and equip a well have been
recovered.
  Completion.  The
installation of permanent equipment for the production of oil or
gas.
  Development
well.  A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be
productive.
  Dry hole.  A well
found to be incapable of producing hydrocarbons in sufficient quantities to
justify completion as an oil or gas well.
  Exploratory
well.  A well drilled to find a new field or to find a new
reservoir in a field previously found to be productive of oil or natural gas in
another reservoir.
  Gross acres or
wells.  Refers to the total acres or wells in which the Company
has a working interest.
  Horizontal
drilling.  A drilling technique that permits the operator to
contact and intersect a larger portion of the producing horizon than
conventional vertical drilling techniques and may, depending on the horizon,
result in increased production rates and greater ultimate recoveries of
hydrocarbons.
  MBbls.  One
thousand barrels.
  MBOE.  One thousand
BOEs.
  Mcf.  One thousand
cubic feet.
  MMcf.  One million
cubic feet.
  NGLs.  Natural gas
liquids.
  Net acres or
wells.  Refers to gross the sum of fractional ownership working
interest in gross acres or wells.
  Oil.  Crude oil or
condensate.
  Operator.  The
individual or company responsible for the exploration, development and
production of an oil or gas well or lease.
  - 48
-
   Present value of proved reserves
(“PV-10”).  The present value of estimated future revenues,
discounted at 10% annually, to be generated from the production of proved
reserves determined in accordance with Securities and Exchange Commission
guidelines, net of estimated production and future development costs, using
prices and costs as of the date of estimation without future escalation, without
giving effect to (i) estimated future abandonment costs, net of the
estimated salvage value of related equipment, (ii) non-property related
expenses such as general and administrative expenses, debt service and future
income tax expense, or (iii) depreciation, depletion and
amortization.
  Productive wells. Producing
wells and wells mechanically capable of production.
  Proved Developed
Reserves.  Proved reserves that can be expected to be recovered
(i) through existing wells with existing equipment and operating methods or in
which the cost of the required equipment is relatively minor compared to the
cost of a new well, and (ii) through installed extraction equipment and
infrastructure operational at the time of the reserves estimate if the
extraction is by means not involving a well.
  Proved
reserves.  Proved oil and gas reserves are those quantities of
oil and gas, which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically producible - from a given
date forward from known reservoirs, and under existing economic conditions,
operating methods, and government regulations – prior to the time at which
contracts providing the right to operate expire, unless evidence indicates that
renewal is reasonably certain, regardless of whether deterministic or
probabilistic methods are used for the estimation. The project to extract the
hydrocarbons must have commenced or the operator must be reasonably certain that
it will commence the project within a reasonable time.  (i) The area
of the reservoir considered as proved includes:  (A) The area
identified by drilling and limited by fluid contacts, if any, and (B) Adjacent
undrilled portions of the reservoir that can, with reasonable certainty, be
judged to be continuous with it and to contain economically producible oil or
gas on the basis of available geoscience and engineering data.  (ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are
limited by the lowest known hydrocarbons (LKH) as seen in a well penetration
unless geoscience, engineering, or performance data and reliable technology
establishes a lower contact with reasonable certainty.  (iii) Where
direct observation from well penetrations has defined a highest known oil (HKO)
elevation and the potential exists for an associated gas cap, proved oil
reserves may be assigned in the structurally higher portions of the reservoir
only if geoscience, engineering, or performance data and reliable technology
establish the higher contact with reasonable certainty.  (iv) Reserves
which can be produced economically through application of improved recovery
techniques (including, but not limited to, fluid injection) are included in the
proved classification when:  (A) Successful testing by a pilot project
in an area of the reservoir with properties no more favorable than in the
reservoir as a whole, the operation of an installed program in the reservoir or
an analogous reservoir, or other evidence using reliable technology establishes
the reasonable certainty of the engineering analysis on which the project or
program was based; and (B) The project has been approved for development by all
necessary parties and entities, including government entities.
  Proved undeveloped reserves
(PUD).  Undeveloped oil and gas reserves are reserves of any
category that are expected to be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major expenditure is required for
recompletion.  (i) Reserves on undrilled acreage shall be limited to
those directly offsetting development spacing areas that are reasonably certain
of production when drilled, unless evidence using reliable technology exists
that establishes reasonable certainty of economic productibility at greater
distances.  (ii) Undrilled locations can be classified as having
undeveloped reserves only if a development plan has been adopted indicating that
they are scheduled to be drilled within five years, unless the specific
circumstances, justify a longer time.  (iii) Under no circumstances
shall estimates for undeveloped reserves be attributable to any acreage for
which an application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual
projects in the same reservoir or an analogous reservoir, or by other evidence
using reliable technology establishing reasonable certainty.
  Probable
reserves.  Probable reserves are those additional reserves that
are less certain to be recovered than proved reserves but which, together with
proved reserves, are as likely as not to be recovered.  (i) When
deterministic methods are used, it is as likely as not that actual remaining
quantities recovered will exceed the sum of estimated proved plus probable
reserves. When probabilistic methods are used, there should be at least a 50%
probability that the actual quantities recovered will equal or exceed the proved
plus probable reserves estimates.  (ii) Probable reserves may be
assigned to areas of a reservoir adjacent to proved reserves where data control
or interpretations of available data are less certain, even if the interpreted
reservoir continuity of structure or productivity does not meet the reasonable
certainty criterion. Probable reserves may be assigned to areas that are
structurally higher than the proved area if these areas are in communication
with the proved reservoir.  (iii) Probable reserves estimates also
include potential incremental quantities associated with a greater percentage
recovery of the hydrocarbons in place than assumed for proves
reserves.
  - 49
-
   Royalty.  An
interest in an oil and gas lease that gives the owner of the interest the right
to receive a portion of the production from the leased acreage (or of the
proceeds of the sale thereof), but generally does not require the owner to pay
any portion of the costs of drilling or operating the wells on the leased
acreage.  Royalties may be either landowner’s royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.
  SEC.  The United
States Securities and Exchange Commission.
  Standardized measure of discounted
future net cash flows.  Present value of proved reserves, as
adjusted to give effect to (i) estimated future abandonment costs, net of
the estimated salvage value of related equipment, and (ii) estimated future
income taxes.
  Undeveloped
acreage.  Leased acreage on which wells have not been drilled
or completed to a point that would permit the production of economic quantities
of oil or gas, regardless of whether such acreage contains proved
reserves.
  Working
interest.  An interest in an oil and gas lease that gives the
owner of the interest the right to drill for and produce oil and gas on the
leased acreage and requires the owner to pay a share of the costs of drilling
and production operations.  The share of production to which a working
interest is entitled will be smaller than the share of costs that the working
interest owner is required to bear to the extent of any royalty
burden.













- 50
-


Signatures




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




DELTA OIL & GAS,
INC.,


a Colorado corporation




By:     /s/ Christopher
Paton-Gay


Christopher Paton-Gay


Chief Executive
Officer





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




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







- 51
-


DELTA
OIL & GAS, INC.





EXHIBIT INDEX
 TO
 2009
ANNUAL REPORT ON FORM 10-K


Exhibit
              Number
            Description
            Incorporated
      by Reference to:
            Filed
              Herewith3.1
            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 dated September 30,
      2009.3.3
            Articles
      of Amendment to the Articles of Incorporation of Delta
            Exhibit
      3.1 of Delta’s Form 8-K dated October 21, 2009.3.4
            By-laws of Delta, as amended.
            
            X10.1
            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
            Strachan
      Participation and Farmout Agreement by and between Odin Capital Inc. and
      Delta dated September 23, 2005.
            Exhibit
      10.1 of Delta’s Form 8-K dated September 29, 200510.3
            Farmout
      and Option Participation Letter Agreement by and between Petrex Energy
      Ltd., Texalta Petroleum Ltd., Odin Capital Inc., Delta Oil and Gas
      (Canada) Inc., Last Mountain Investments Inc., 264646 Alberta Ltd., LL
      & S Holdings Ltd. and 0743608 B.C. Ltd. dated April 10,
      2006.
            Exhibit
      10.7 of Delta’s Form 10SB12G dated May 12, 2006.10.4
            Farmout
      Agreement by and between Sunset Exploration, Inc. and Delta, effective May
      25, 2009
            Exhibit
      10.1 of Delta’s Quarterly Report of Form 10-Q dated June 30,
      200910.5
            Letter
      Agreement by and between Ranken Energy Corporation and Delta relating to
      2009-1 Drilling Program
            Exhibit
      10.2 of Delta’s Quarterly Report of Form 10-Q dated June 30,
      200910.6
            Assignment
      of Oil, Gas, & Liquid Hydrocarbon Leases dated July 15, 2009, relating
      to the Texas Prospect
            Exhibit
      10.1 of Delta’s Quarterly Report of Form 10-Q dated September 30,
      200910.6
            Letter
      Agreement by and between Delta and Ranken Energy Corporation dated August
      7, 2009
            Exhibit
      10.2 of Delta’s Quarterly Report of Form 10-Q dated September 30,
      200910.8
            Amended
      and Restated Consulting Agreement, dated as of March 8, 2010, by and
      between Delta and Warwick Management Services
            Exhibit
      10.1 of Delta’s Form 8-K dated March 8, 201010.8
            Amended
      and Restated Consulting Agreement, dated as of March 8, 2010, by and
      between Delta and Last Mountain Management Ltd.
            Exhibit
      10.2 of Delta’s Form 8-K dated March 8, 201010.10
            Amended
      and Restated Consulting Agreement, dated as of March 8, 2010, by and
      between Delta and CPG Consulting Ltd.
            Exhibit
      10.3 of Delta’s Form 8-K dated March 8, 201010.11
            Delta
      2010 Incentive Compensation Plan
            Exhibit
      10.1 of Delta’s Form 8-K dated March 8, 2010


- 52
-





Exhibit
              Number
            Description
            Incorporated
      by Reference to:
            Filed
              Herewith10.12
            Exploration Agreement by and between Barry Lasker and
      Delta, dated March 27, 2009
            
            X10.13
            Assignment and Assumption Agreement, dated as of
      December 8, 2009, between Delta and Hillcrest Resources,
      Ltd.
            
            X14.1
            Code
      of Ethics and Conduct
            Exhibit
      10.1 of Delta’s Form 10-KSB filed on April 19, 200421.1
            Subsidiaries of Delta.
            
            X23.1
            Consent of Harper & Associates,
    Inc.
            
            X23.2
            Consent of Mark E. Andersen
            
            X23.3
            Consent of Chapman Petroleum
    Engineering
            
            X31.1
            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
            
            X99.2
            Report of Mark E. Andersen independent consulting
      engineers
            
            X99.3
            Report of Chapman Petroleum
      Engineering  independent consulting
engineers
            
            X







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