UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

Commission File Number: 0-29832

AUSTRALIAN-CANADIAN OIL ROYALTIES LTD.

1301 Ave. M, Cisco, Texas 76437

(Address of Principal Executive Offices)

(254) 442-2638

(Issuer’s Telephone Number, including Area Code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12 (g) of the Act: Common Stock, no par value

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

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 [X]

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

Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of issuer’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 [X]

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

[  ] Large accelerated filer    [  ] Accelerated filer    [  ] Non-accelerated filer (do not check if a smaller reporting company)    [X] Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule12b-2 of the Exchange Act).

Yes [  ]    No [X]

The aggregate market value of the common stock held by non-affiliates on April 12, 2012 was $7,300,908 based on the closing price of the stock that day as quoted on the OTCBB.

The Registrant had 49,960,000 common shares outstanding as of April 12, 2012.

FORWARD LOOKING STATEMENTS

Statements made in this Form 10-K that are not historical or current facts are “forward looking statements” made pursuant to the safe harbor provisions of Section 27A of the Securities Act of 1933 (the “Act”) and Section 21E of the Securities Exchange Act of 1934. These statements often can be identified by the use of terms such as “may,” “will,” “expect,” “believe,” “anticipate,” “estimate,” “approximate,” or “continue,” or the negative thereof. We intend that such forward-looking statements be subject to the safe harbors for such statements. We wish to caution readers not to place undue reliance on any such forward-looking statements, which speak only as of the date made. Any forward-looking statements represent management’s best judgment as to what may occur in the future. However, forward-looking statements are subject to risks, uncertainties and important factors beyond our control that could cause actual results and events to differ materially from historical results of operations and events and those presently anticipated or projected. We disclaim any obligation subsequently to revise any forward-looking statements to reflect events or circumstances after the date of such statement or to reflect the occurrence of anticipated or unanticipated events.

Available Information

Australian-Canadian Oil Royalties Ltd. files annual, quarterly, current reports, proxy statements, and other information with the Securities and Exchange Commission (the “SEC”). You may obtain copies of our SEC filings by going to the SEC’s website at https://www.sec.gov.

PART I

ITEM 1. BUSINESS

Business Development

Australian-Canadian Oil Royalties Ltd. (“ACOR”, “the Company”, “we”, “us” or “our”) was incorporated in British Columbia, Canada, in April of 1997. The Company’s U.S. office is located at 1301 Avenue M, Cisco, Texas 76437. Our website address is www.aussieoil.com. The information contained on, or that can be accessed through, our website is not part of, and is not incorporated into, this Annual Report on Form 10-K (“Form 10-K”)

The Company has continued to be active with its Working Interests and overriding royalty positions held both domestically and internationally. The business of ACOR during 2011 was to work on its existing Working Interest projects as well as study the oil and gas exploration acreage available in Australia in basins that demonstrate a high probability of success with the maximum rate of return for dollars invested. For additional information on our acquisition of additional Working Interests in the Bowen/Surat Basin in Queensland, Australia see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.

Current Business Operations

The Company is a purchaser and holder of both Overriding Royalty Interests and Working Interests both on an international and domestic basis. ACOR’s business is related to the principal products of oil and gas, and is dependent on various factors, which are discussed below. The average sales price per barrel of oil from the Company’s interests located in Australia during 2011 was $114.35.

The acquisition, exploration, development, production and sale of oil and gas are subject to many factors that are outside the Company’s control. These factors include: market prices; national and international economic conditions; import and export quotas; availability of drilling rigs, casing, pipe, and other equipment and supplies; availability of and proximity to pipelines and other transportation facilities; the supply and price of competitive fuels; and the regulation of prices, production, transportation, and marketing by domestic and foreign governmental authorities. Additionally, the Company generally has no control over whether the owner or operator of leases to which its Overriding Royalty Interests are attributable will elect to explore for oil and gas on such properties, or to develop them following discoveries that may occur. Each of these factors may affect the rate at which oil and gas are produced on properties in which the Company has an interest or affect whether wells will be drilled on such properties, and could otherwise materially affect ACOR’s earnings.

Due to extreme flooding most exploration activities were cancelled or delayed on the Company’s Australian interests during 2011. However, one well was drilled on one of the Company’s interests, which was completed as a producer. For further information on each of the Company’s interests see "Item 2. Properties".

Proposed Future Business Operations

The Company’s strategy is three fold: 1) to seek Overriding Royalty Interests in oil and gas concessions within sedimentary basins in Australia, 2) to explore and develop the oil and gas concessions in Queensland, Australia in which it holds a Working Interest and 3) to seek other Working Interests in oil and gas concessions within sedimentary basins of Australia to promote oil and gas exploration through seismic programs and drilling operations.

The Company’s ability to explore other oil and gas opportunities is dependent on adequate capital resources being available and equity being obtained, and/or finding partners to fund the exploration and drilling programs on the areas in which the Company holds Working Interests.

Competition

The Company is competing with other oil companies for oil and gas leases and concessions. The oil and gas industry is highly competitive in all of its phases, with competition for favorable producing royalties, overriding royalties, and good oil and gas leases being particularly intense. The Company believes that the exploration program, promised expenditures, geological and geophysical skill, and familiarity with an area of operations are the primary competitive factors in the identification, selection, and acquisition of desirable leases. When attempting to purchase interests in such properties, the Company competes with independent operators and major oil companies.

Foreign Taxes and United States Tax Credits

As a result of its Overriding Royalty Interests attributable to properties outside the United States, the Company is subject to the imposition of taxes by foreign governments upon the Company's income derived from such foreign jurisdictions. These taxes are of various types, with differing tax rates, and are subject to change. Generally, the Company's income from a foreign jurisdiction will be taxed in the same manner as that for other companies operating in the jurisdiction, but discriminatory taxation by a particular jurisdiction may occur. The current non-resident corporate income tax rate in Australia, for Overriding Royalty Interests, is 30%.

As a Canadian corporation, the Company is liable for income taxes under the laws of Canada. Under Canadian law the Company's Australian-source income is subject to a 46% tax (on Canadian income). We believe the 30% Australian tax should be a credit toward the payment of the 46% Canadian tax under double taxation treaties between the countries.

The Company is taxable in the U.S. on U.S. source income. Because there has been neither U.S. source net income nor any income effectively connected with a U.S. trade or business, there have been no U.S. taxes incurred to date.

Governmental Regulation

Oil and gas operations are subject to federal, state and local laws and regulations governing waste, environmental quality, pollution control, conservation and other measures regarding environmental and ecological matters. It is impossible to predict the impact of environmental legislation and regulations on the Company's operations and earnings in the future.

The domestic production and sale of oil and gas are subject to federal regulation by the Department of Energy and the Federal Energy Regulation Commission. Rates of production of oil and gas have for many years been subject to federal and state conservation laws and regulations. In addition, oil and gas operations are subject to extensive federal and state regulations concerning exploration, development, production, transportation, and pricing, and even to interruption or termination by governmental authorities.

In foreign countries, the Company may be subject to governmental restrictions on production, pricing and export controls. Regulations existing or imposed upon the Company or its properties at the time of their acquisition may change to an unpredictable extent. The Company will have little or no control over the change of regulations or imposition of new regulations and restrictions, expropriation or nationalization by foreign governments or the imposition of additional foreign taxes. Management believes that these actions are unlikely to be undertaken by the state governments of South Australia, Queensland or Victoria, where all of the foreign oil and gas properties from which the Company receives royalty income are currently located.

Foreign Currency

Due to the nature of the Company's activities in Australia, portions of the Company's operating capital may at times be held in various foreign currencies. This subjects the Company to the risk of currency fluctuations and changes in rates of conversion for different currencies. The Company does not engage or expect to engage in any hedging or other transactions, which are intended to manage risks relating to foreign currency fluctuations. Additionally, revenues generated in foreign countries in which the Company has or may acquire interests may be subject to governmental regulations, which restrict the free convertibility of such funds, and all remittances of funds out of these countries might require the approval of the applicable government's exchange control agency. Presently, the Company experiences no difficulties with the free convertibility of funds from Australia. In the Company's opinion, the foreign exchange control laws currently in effect in Australia, do not unreasonably delay the remittance of funds generated in Australia to the United States. The exchange rate on April 3, 2012 was $1.00 Australian = $1.03745 United States dollar.

Regulation of Oil and Natural Gas Production

Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local authorities and agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.

Many states require permits for drilling operations, drilling bonds and reports concerning operations, and impose other requirements relating to the exploration and production of oil and natural gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells.

Environmental Matters

Our operations and properties will be subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may: (i) require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; (ii) limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and (iii) impose substantial liabilities for pollution resulting from our operations. The permits required for several of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are in substantial compliance with current applicable environmental law and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on our business operations, as well as the oil and natural gas industry in general.

Research and Development Activities

Significant flooding that occurred in 2010 for large parts of Australia continued to cause mobilization for 2011 work programs to be either cancelled or delayed for the majority of the Company’s interests located within the Cooper-Eromanga Basin of Queensland and South Australia. The record flooding also caused a number of our producing properties to be shut in due to lack of accessibility, which affected the Company’s revenues.

The severe flooding in 2010 caused the Snatcher 1, 2 and 3 wells drilled during the last quarter of 2009 to be shut in during most of 2010 and all of 2011. Subsequent to the end of 2011 work was reported to be ongoing in the field to reclaim existing Snatcher wells. The operator currently anticipates returning the field into production in April 2012. The Company holds an Overriding Royalty Interest in these three wells. For additional information on the Snatcher wells see PEL 111 under “Item 2. Properties”.

Of particular interest is the development of the Company’s 50% Working Interest in ATP 582. ATP 582 covers approximately 5,308,764 gross acres and lies in the Georgina Basin, which is a part of the Cooper-Eromanga Basin. The improvement in multi high-pressure fracing technology over the past 10 years has made low permeable shale more economic to produce both oil and gas and has been widely used in North America to unlock unconventional reservoirs in shale bearing hydrocarbons. This technology has not been utilized in the Georgina Basin; however on the adjoining concession to the east, in the Northern Territory, two horizontal wells (MacIntyre-2 and Baldwin-2H) were drilled into the Arthur Creek Shale during the last quarter of 2011. Plans are to utilize the high pressure multiple stage fracing on these two wells in the Arthur Creek Shale formation in the second half of 2012. ATP 582 is well positioned with approximately 1,000,000 acres on the northern most part known to have the presence of the Arthur Creek Shale in place. For additional information see “Properties” ATP 582.

The Longtom gas project on VIC/P54 commenced production in October 2009 under a sales agreement with Santos Ltd. VIC/P54 is located in the Bass Strait of the Gippsland Basin. The Company holds a 1/20^th of 1% of the Gross Production in this concession, which has two successful wells (Longtom #3 testing 23 million cubic feet of gas per day and the Longtom #4 testing 58 million cubic feet of gas per day). For additional information see VIC/P54 in Item 2. Properties – Bass Strait of the Gippsland Basin.

Personnel

The Company hires part time employees on an as needed basis. The Company also engages consultants and professionals when needed for specific projects and/or tasks.

Definitions

The following definitions are provided to clarify certain terms used in this report:

Authority to Prospect (“ATP”) - a concession granted by the State of Queensland, Australia, which entitles its holders to an exclusive right to explore for oil and natural gas in Queensland in the particular area covered by the ATP. Each ATP has an initial term of four years. The area covered by an ATP is reduced by relinquishment of approximately one-fourth of the area at the start of the third year of its effectiveness and an additional one-fourth of the original area at the start of the fourth year of its effectiveness. The area to be relinquished is chosen by the holder of the ATP. An ATP will require some kind of geological and/or geophysical operations, such as new seismic or seismic interpretation, drilling or other operations during the term of the tenure. The amount of work to be performed depends upon the expenditures required for each specific year of the tenure. Holders are only required to expend those amounts as set out in the original concession document. Applications for renewal may be filed at the time of expiration of an ATP.

Carried Working Interest – where Working Interest is paid by a third party through the drilling phase or both the drilling and completion of a well. After the carried portion of the well has been satisfied then the Carried Working Interest holder is responsible for its share of expenditures.

Developmental Wells - oil and gas wells drilled within the proven 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 oil or gas in sufficient quantities to justify completion.

Exploration Permit – an exclusive offshore exploration permit with a term of six years. Said permit is managed by the Victorian State Government.

Exploratory Well - a well drilled to find and produce oil and gas in an unproved area or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

Gross Production - the total production of oil, gas, or natural gas liquids from a property or group of properties for any specified period of time.

MCF - thousand cubic feet of natural gas

MMCF - million cubic feet of natural gas

Net Royalty Acre - generally, a measurement of royalty or overriding royalty and the equivalent of the full customary one-eighth royalty of the gross production of revenue free and clear of exploration, drilling and production costs from one acre of land. The number of net royalty acres used in this report applies to figures as of December 31, 2011 and the number will change as relinquishments take place on the ATPs, as an ATP expires or is canceled, or any new areas are added.

Overriding Royalty Interest (“ORRI”) - an interest assigned out of the lessee’s leasehold or Working Interest. The amounts payable from Overriding Royalty Interests are payments calculated as a percentage of either Gross Production or the gross revenues of the Working Interest (based on the wellhead price) from a concession or lease, usually free and clear of all exploration, drilling and development and production costs, except for any applicable taxes and federal levies. In calculating the wellhead price, pipeline and trucking costs have already been deducted from the refinery price. The overriding royalties discussed herein are generally expressed as a percent of the Gross Production.

Petroleum Exploration License (“PEL”) - an exclusive oil and gas Exploration Permit issued by the South Australian Department of Primary Industries and Resources. The initial term of the tenure is for a five (5) year period.

Petroleum Resource Rent Tax – a tax on net income in Australia reduced by indexing on offshore production, which replaces the royalty and is a deduction from Australian income tax.

Producing Wells - wells capable of producing oil or gas in commercial quantities, including those wells capable of producing in commercial quantities that are shut in, or wells that are not currently producing in commercial quantities but have been commercially productive in the past.

Royalty - generally, a share of the production reserved by the grantor of an oil or gas lease or concession. The royalty interest is customarily free of cost or expense incident to exploration, development or production, except for production or gathering taxes.

Spud Date or Spudded – The date drilling operations begin.

Working Interest - all or a fractional part of the ownership rights granted by a concession or lease. The owner of a Working Interest or a part thereof pays all costs of exploration and is entitled to the Gross Production, less royalties retained by the grantor or lessor, and less Overriding Royalty Interests or other non-operating interests created and assigned from the Working Interest. The owner of a Working Interest may incur operating expenses in excess of income.

ITEM 2. PROPERTIES

The Company’s principal office space is located at 1301 Avenue M, Cisco, Texas 76437. The office space is for corporate identification, mailing, and courier purposes and costs us approximately $3,200 in rent a year, which is paid to an affiliate. This $3,200 has been recorded as an expense and contributed capital in the financials.

The Company holds Overriding Royalty Interests in the Cooper-Eromanga Basins that cover parts of Queensland and South Australia. The Company’s overriding royalties total 387,721 net royalty acres under 10,610,564 gross surface acres in 11 concessions located in the Cooper-Eromanga Basins. In addition the Company also owns 623 net royalty acres under 155,676 gross acres in a concession located in the Bass Strait of the Gippsland Basin located offshore of the state of Victoria, Australia. See Table of Overriding Royalty Interests for ownership and acreage for each concession.

The Eromanga Basin encompasses the southwestern portion of the state of Queensland and the northeast corner of South Australia, and is Australia’s main onshore producing oil and gas basin.

The Cooper Basin is located in the northeast part of the State of South Australia. Management believes the Company’s overrides are in a prime location since the majority of the Company’s interests form nearly continuous blocks adjoining the producing block of Santos et al. which has reserves in excess of one billion barrels of oil equivalent.

The Company has Overriding Royalty Interests in VIC/P54 Permits in the Gippsland Basin. The Bass Strait of the Gippsland Basin is located between the states of Victoria and Tasmania which have had in excess of 4 billion barrels of oil/condensate and 12 TCF gas reserves discovered since exploration drilling began in 1964.

On the 10,766,240 gross surface acres where ACOR holds Overriding Royalty Interests, there are large anticlines, large faults and hundreds of seismic structures, all of which indicate possibilities for oil and gas reserves. In addition, about $27 million worth of seismic information has been completed and is available on the areas.

During 2011 the Company received revenues from six of its Overriding Royalty Interests known as ATP 267, ATP 299, ATP 560, PEL 111, PEL 115 and VIC/P54. For further information see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation”.

In addition to the Company’s large overriding royalty position it also has Working Interests in four concessions, which are all located in the Cooper/Eromanga Basin. See the table for Working Interest Holdings for additional information.

NON-PRODUCING OVERRIDING ROYALTY INTERESTS

(1) Our Company has entered into an agreement where the partner will pay for the Native Title clearance, conduct a 2-D seismic program, drill one well, and earn 50% interest in this concession.

PRODUCING OVERRIDING ROYALTY INTERESTS

WORKING INTEREST HOLDINGS

(1) Our Company has entered into an agreement where the partner will pay for the Native Title clearance, conduct a 2-D seismic program, drill one well, and earn 50% interest in this concession.

The following is a summary of the Company’s Australian properties divided into three areas: 1) Gippsland Basin - Victoria, 2) Cooper/Eromanga Basin of South Australia, and 3) Cooper/Eromanga Basin of Queensland:

Bass Strait of the Gippsland Basin

The Company holds Overriding Royalty Interests in VIC/P54, a producing oil and gas concession, located in the Bass Strait of the Gippsland Basin. The Bass Strait of the Gippsland Basin is located between the State of Victoria and Tasmania which has in excess of 4 billion barrels of oil/condensate and 12 TCF gas reserves discovered since exploration drilling began in 1964. The following is a report on the Company’s interests in the Bass Strait of the Gippsland Basin:

A review of the Longtom discoveries is important to see the magnitude of these wells. The Longtom-3 was drilled and completed during the summer of 2006. Two production tests were conducted on the well:

The first test produced gas from the 400 sand at 23MMscf/d. The results from this test confirm the flow potential of the 400 sand reservoir in the Longtom field, addressing a major concern leading up to the drilling of the Longtom-3 well. A flow was not achieved in the second test of Longtom-2 (conducted over the 400 sand). Nexus Energy Pty. Ltd. has interpreted this test as having failed due to down-hole mechanical problems.

The second test, over the 100, 200 and 300 sand intervals in the horizontal hole section exceeded expectations producing an estimated 77MMcf/d when bypassing the test separator and 59MMcf/d when flowing through the test separator (the separator’s flow capacity). Sampling during the test recorded expected levels of carbon dioxide (less than 1%) and less than one part per million hydrogen sulphide.

In addition, the second test indicated that the condensate yield is higher in the 100 sands than in the sands above it, which is expected to provide an economic boost to the project.

The Longtom-4 development well was drilled during the summer of 2008. The Longtom #4 tested 58 million cubic feet of gas per day with liquid hydrocarbons. The net pay section in both Longtom #3 & #4 is 4,000 feet thick and the total depth of both wells was approximately 15,000 feet.

A 12” pipeline was constructed to the Longtom Field with the first delivery of gas beginning on October 21, 2009. Revenues from gas sales for the Company began in 2010. During 2010 the Longtom Field was shut in due to mercury levels exceeding gas plant standards. A processing plant was installed to remove the excess mercury and production from the Longtom Field resumed in November 2010.

The Company’s net revenues from the Longtom Field for 2011 were $44,129.51 representing approximately 35% of the total revenues reported for the year. The operator of VIC/P54 is evaluating the Gemfish prospect for their next target as it is in a separate reservoir and structural setting. No drilling dates have been announced as of the date of this report.

Cooper/Eromanga Basin - South Australia

The Company holds Overriding Royalty Interests in five oil and gas concessions and holds Working Interests in three oil and gas concessions located in the Cooper/Eromanga Basin of South Australia. The following is a brief summary report on each of the Company’s interests in South Australia:

PEL 88

ACOR owns a 3/10ths of 1% Overriding Royalty Interest under PEL 88, which covers 816,436 gross acres. Three prospects have been identified on PEL 88, Acacia, Casuarina and Lancier. The potential recoverable reserves of each of these prospects are 15,000,000 barrels of oil in the Acacia, 18,000,000 barrels of oil in the Casuarina and 48,000,000 barrels of oil in the Lancier. No assurance can be made that these prospects will be drilled.

PEL 100

ACOR holds a 1% Working Interest in the Cleansweep #1, which was drilled in the 2008 fiscal year and was completed as a Birkhead formation producer. The well tested 444 barrels of oil on a drill stem test. The Cleansweep well is estimated to have the potential of 4.8 million barrels of recoverable oil in place. Recent seismic mapping has confirmed that Angelica #1 drilled in 1998 was drilled off structure. A more detailed review of the existing seismic identified a four-way drape structure of Eromanga Basin sediments over a basement horst bald of Permian strata. A detailed 3D seismic program is planned to ensure that Angelica #2 tests the crest of this structure; however, this program has been delayed due to flooding in the area. The Angelica 3D seismic survey is proposed to cover 302 square kilometers and was planned for the fourth quarter of 2011, however it was delayed and as of the date of this report has not been rescheduled.

PEL 111

ACOR owns a 1/10th of 1% Overriding Royalty Interest under PEL 111, which covers 290,101 gross acres. Mapping of PEL 111 seismic data coupled with the reprocessing of existing seismic data identified 20 leads and prospects for potential oil and gas in the Birkhead, Hutton, Tirrawarra and Patchawarra formations. The Warhawk #1 was drilled in 2008 and was cased and suspended as a future producer. During 2009 three wells (Snatcher 1, 2 & 3) were drilled and completed as producers in the Birkhead channel sands. The Snatcher #1 well tested 218 barrels of oil per day.

The Snatcher #1 began producing on December 20, 2009 with both the Snatcher wells 2 & 3 coming on line during the first quarter of 2010; however, they were shut in due to flooding and continued to remain shut in through 2011. The severe flooding caused major road and access problems. The operator anticipates returning the field to production in April 2012.

Plans to drill Liberator #1 during the summer of 2010, which is located approximately 700 meters northwest of Snatcher #3, has been delayed due to flooding in the area. As of the date of this report no announcement has been made as to a drilling date for the Liberator #1.The operator reports another prospect is on their 2012 plans for drilling, known as the Angelica #2.

Santos has commenced construction of the Charo-Tirrawarra pipeline, which is to facilitate the transportation of crude oil from the Charo and Snatcher Fields. The pipeline is scheduled for commissioning in April 2012.

PEL 112 & 444

Holloman Energy Corp. (“Holloman”), the operator of PEL 112 & PEL 444, has identified 38 leads on PEL 112. The Company owns a 13.83% Working Interest under both PEL 112 & PEL 444 and is 100% fully carried for its 13.83% Working Interest in the next two wells drilled on either PEL. The Company will be obligated to pay its proportionate part on any exploration costs thereafter. PEL 112 and PEL 444 comprise approximately 1.125 million gross acres and are both located within Australia’s most prolific onshore oil and gas-producing basin, the Cooper/Eromanga Basin.

Subsequent to December 31, 2012 Holloman was granted a variation on its license conditions on PEL 112. Under the terms of the variation, the date by which Holloman is obligated to acquire 100 kilometers of 2D seismic on PEL was moved to January 10, 2013. Holloman also reports in their February 27, 2012 Press Release that it has recently received a series of offers relating to one or both of its Cooper Basin licenses. Holloman is reviewing those proposals as of the date of this report. ACOR’s Carried Working Interest in both PEL 112 and 444 will be adjusted in a joint effort with Holloman to attract a joint venture partner to conduct seismic and drill multiple wells.

During 2011, Beach Energy Limited discovered three new oil pools on PEL 92, a license, which abuts the northwestern most corner, the PEL 112. One of those discoveries, the Germein-1 oil discovery, is less than 7 miles from PEL 112. Although no formal reserve estimates or production data are yet available on these discoveries, Beach Energy Limited reports that the PEL 92 Parsons-4 well, which tested at 7,600 barrels of oil per day, is now online. ACOR does not own an interest in PEL 92, however the information on PEL 92 is important, as it is relevant to ACOR’s Working Interest in PEL 112.

In October 2011, Senex Energy Limited (“Senex”) initiated an eleven well drilling program on Petroleum Retention License ("PRL") 15 and PEL 104, both of which lie directly southwest of PEL 444. PRL 15 contains the prolific Growler oil field, which is expected to produce approximately 700,000 barrels of oil during Senex's current fiscal year. Senex reports completion of seven of the eleven wells. Five of the Senex wells were successfully completed and suspended for future production. The Growler-6 well tested for production at 1,374 barrels of oil per day. One of the two economically unsuccessful exploration wells (Spitfire-1) resulted in the discovery of a new oil field on PEL 104. ACOR does not own an interest in PEL 104 or PRL 15, however the information on PEL 104 is important, as it is relevant to ACOR’s Working Interest in PEL 444.

PEL 115

This permit covers 65,730 gross acres under which ACOR holds an Overriding Royalty Interest of 10% of 1% of Gross Production. PEL 115 is located in the prolific Cooper/Eromanga Basin in South Australia. The Mirage-1 well completed in July 2005 initially flowed clean oil at a rate of 372 barrels of oil per day on a ½ inch choke. Mirage-1 is currently producing on optimized beam pump operation at a rate of 140 barrels of oil per day from the perforated 52-foot interval from 4330 feet to 4481 feet.

The interpreted recoverable oil reserve for the Mirage Oil Field based on 2D seismic geophysical mapping is in a range from a mean of 1.3 million barrels up to a maximum of 3.6 million barrels. The interpretation of the 3D data set suggests that Mirage-1 could be part of a larger feature covering approximately 20 square kilometers that includes the Lightning and Jindivik prospects, 3.10 miles to the northeast. Such an area has the potential of containing up to 23 million barrels of oil in place, subject to the presence of suitable Murta sand reservoir.

In the southern part of PEL 115 the interpretation of the 3D Mirage and extensive 2D seismic data have defined four Jurassic and Permian oil and gas prospects (Voodoo, Fury, Airacobra and Thunderbolt). During 2009 the Fury #1 and Airacobra #1 were drilled and completed as producers. Based on the analysis of the wire line log data and sidewall cores and similarity of the Murta oil column in Fury-1 to those seen in the producing Mirage Oil Field, 5 kilometers to the southwest, Fury-1 has been completed for production with 7 inch production casing run to 6,446 feet. Production from Fury-1 was delayed due to flooding and damages incurred to the roads and area during 2011. As of the date of this report no announcements have been received as to when production will begin.

Subsequent to December 31, 2012 a group announced it had reached an agreement with Orca Energy Limited, operator of PEL 115, to farm-in to PEL 115. Under the terms of the agreement, the group has the right to earn a further 22% in PEL 115 by committing to fund Orca’s remaining 20% share of the cost of an unconventional gas well on the permit. Under this agreement the group’s ownership will increase to 55% working interest.

PEL 424

Formerly known as PEL’s 86, 87 & 89, these PEL’s were grouped together for a new Petroleum Exploration License know as PEL 424 covering 1,516,733 acres under which the Company holds a 10% of 1% of 8/8ths Overriding Royalty Interest represented by a total of 12,134 net royalty acres. The operator of PEL 424 was Victoria Petroleum N.L. which became Senex Energy Limited during 2011. PEL 424 is located in the Cooper/Eromanga Basin in South Australia. As of the date of this report no information was available as to the plans for this area.

Cooper/Eromanga Basin – Queensland

The Company holds Overriding Royalty Interests in seven oil and gas concessions and holds Working Interests in one oil and gas concession located in the Cooper/Eromanga Basin of Queensland. The following is a report on each of the Company’s interests in Queensland:

ATP 267

The Company owns an Overriding Royalty Interest of 17.15% of 1% in ATP 267, which covers approximately 220,800 acres. ATP 267 has 25 Producing Wells in six oil fields known as the Kihee, Koora, Nockatunga, Winna, Maxwell, Dikera, Thungo and Murhero fields. The Company received revenues from its Overriding Royalty Interest in these wells during 2011. No new wells were drilled during 2011 on this concession.

ATP 299

The Company owns a .0575% of 1% Overriding Royalty Interest under ATP-299 and its Petroleum Licenses which covers 441,600 gross acres and currently has 104 completed wells under which ACOR receives overriding royalties. The Tintaburra Block is reported to contain approximately 84 million barrels of proved plus probable oil in place. ATP 299 has 104 Producing Wells in 25 oil fields. The Company received revenues of from its Overriding Royalty Interest in these wells during 2011. No new wells were drilled during 2011 on this concession.

ATP 560

ATP 560 covers 625,600 acres under which the Company holds a 25% of 1% override. The Utopia Oil Field is situated in ATP 560P in the Eromanga Basin in southwest Queensland, approximately 150 km north east of the Jackson Oilfield and 50 km south of the Kenmore Oilfield. The Utopia field is a broad low-relief structure, with a maximum relief of approximately 10 m. The field produces from the Early Cretaceous Murta Formation and is the largest known Murta pool in the Queensland Eromanga Basin. The oil pool is at an approximate depth of 1020 m. The most recent technical review of Utopia undertaken in June 2004 determined the field could contain up to 2.86 million barrels of recoverable oil.

During 2011 the Utopia-11H, a horizontal development well, was drilled and completed as a Murta oil producer after a 176.5 meter horizontal drain hole was successfully drilled. The operator reports excellent oil shows in a very good quality reservoir sand continued to be encountered while drilling the horizontal leg. The Utopia-11H well was put into production during the third quarter of 2011.

ATP 582

ATP-582 is located in Queensland Australia in the prolific Cooper/Eromanga Basin. The permit area covers approximately 5,308,764 gross acres. ATP 582 lies within the Georgina Basin, which covers most of the central-eastern part of the Northern Territory and is considered one of the most prospective undeveloped onshore petroleum provinces in Northern Territory and Queensland. Although the Georgina Basin has not had a discovery today, the Company believes the Cambrian Thorntonia-Arthur Creek succession of the Georgina Basin possess all of the required elements necessary for petroleum generation, migration and entrapment. Of particular interest in the Georgina Basin and on ATP 582 is the presence of the Arthur Creek Shale, which has similar characteristics to the Bakken Shale of Western Canada and North Dakota that has produced more than 10 TCF of gas and 1 Billion barrels of oil.

More improvement in multi high-pressure fracing technology over the past 10 years has made low permeable shale very economic to produce both oil and gas and has been widely used in North America to unlock unconventional reservoirs in shale bearing hydrocarbons. This technology has not been utilized in the Georgina Basin; however, on the adjoining concession to the east in the Northern Territory plans are to drill two horizontal wells into the Arthur Creek Shale utilizing the current high pressure multiple stage fracing on this formation. ATP 582 is well positioned with a large portion of its 5,308,764 acres known to have the presence of the Arthur Creek Shale in place.

On the adjoining concession to the west of ATP 582 two horizontal wells drilled into the Arthur Creek Shale. The first well drilled was the Baldwin-2H well followed by the MacIntyre-2H well located approximately 60 kilometers northeast of the Baldwin-2H well. PetroFrontier Corp. delayed completion of these two wells due to the upcoming wet season and plans to complete both of these wells with a multiple staged frac program. As of the date of this report no definitive plans have been announced as to the timing for the completion of these two wells.

In addition to the Arthur Shale opportunity, ACOR management has identified two prospects on ATP-582 from the 850 miles of seismic data, owned by ACOR. ATP 582 is up dip of the approximately $1 billion dollar annual production from the Santos-Exxon producing block and is along strike with many new discovery wells that have sustained daily production of 1,000 - 3,000 barrels of oil per day. The two prospects that have been identified are:

The Samphire Prospect covers approximately 3,800 acres and exhibits approximately 110 feet of closure. It is possible that a good potential exists for a 10-15 million barrel field, with a possible potential of approximately 40 million barrels.

The Samphire West Prospect covers around 4,700 acres. If the Samphire prospect proves to be productive, a number of additional field discoveries may result from leads in the Southern part of ATP-582. Both prospects are a series of sandstone (clastic) reservoirs of pinch-outs and structural traps that have formed on the flank of the local high.

On September 26th, 2006 (subsequently replaced by an agreement dated on or about February 23, 2012) the Company entered into an agreement where the partner will pay to obtain Native Title clearance, pay all expenses in connection with applying for Environmental Authority, shoot a new seismic grid survey over the leads identified by ACOR management from old seismic data to confirm good drillable targets with plans to drill a well to earn a 50% Working Interest under ATP 582 (ACOR will be carried for 50% Working Interest). During the fourth quarter of 2011 native title was cleared on ATP 582. A request was filed during the fourth quarter of 2011 to renew ATP 582 for a new exploration term. As of the date of this report ATP 582 had not been renewed, however it is reported the renewal is expected to occur in April 2012.

For information on Working Interests acquired by the Company and located in the Bowen/Surat Basin in Queensland, Australia see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.

ITEM 3. LEGAL PROCEEDINGS

Management is not aware of any legal proceeding contemplated by any governmental authority or any other party involving the Company or its properties. As of the date of this Form 10-K, no director, officer or affiliate, any owner of record or beneficially of more than 5% of the common equity securities of the Company or any associate of any such director, officer, affiliate of the Company or any security holder is (i) a party adverse to our Company in any legal proceeding, or (ii) has an adverse interest to our Company in any legal proceedings. Management is not aware of any other legal proceedings pending or that have been threatened against the Company or its properties.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

During the fiscal year ended December 31, 2011, no shareholders’ meeting was held.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market For Common Equity

The principal trading market for the common equity securities of the Company is the National Association of Securities Dealers OTC Bulletin Board quotation system. The symbol is: AUCAF. The following are the highs and lows for each quarter for fiscal year ended December 31, 2010 and 2011, respectively. These quotations reflect inter-dealer prices, without retail mark-up, mark- down or commissions, and may not represent actual transactions.

The approximate number of securities holders of record of the Company on April 12, 2012 was 376 of record, which does not include stockholders whose shares are held in street or nominee names. We have no outstanding stock options or warrants to purchase our securities.

Dividend Policy

No dividends have ever been declared by the Board of Directors on our common stock. Our losses do not currently indicate the ability to pay any cash dividends, and the Company does not indicate the intention of paying cash dividends on our common stock in the foreseeable future.

Securities Authorized For Issuance Under Compensation Plans

Stock Compensation Plan (the “Plan”) - The Board approved the Plan in 2008 and registered 1,000,000 shares for the Plan. The purpose of the Plan is to provide a means by which key employees, officers, directors, and consultants may be given an opportunity to acquire Common Stock of the Company in payment for services performed for the Company. The Plan provides incentives for such persons to exert maximum efforts for the success of the Company. No shares have been issued under the Plan to date.

Recent Sales of Unregistered Securities

During the fiscal year ended December 31, 2011, the Company issued a total of 2,657,396 unregistered shares as follows:

No underwriter, sales or placement agent was involved in any of the transactions.

The facts relied on to make the exemption from registration provided by Section 4(2) of the Securities Act of 1933 available for the sale of securities discussed above were: (1) the limited number of purchasers; (2) the sophistication or accreditation of the purchasers; (3) their relationship with the Company and/or access to material information about the Company; (4) the information furnished to them by the Company; (5) the absence of any general solicitation or advertising; and (6) restrictions on transfer of the securities issued to them as indicated by a legend on the certificates representing such securities.

Repurchases of Securities

The Company has not repurchased any of its own securities.

ITEM 6. SELECTED FINANCIAL DATA

N/A

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

The following discussion should be read in conjunction with our audited financial statements and the related notes accompanied thereto. The following discussion contains forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this Form 10-K. Our audited financial statements are stated in United States Dollars and are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”).

General Discussion:

ACOR’s 2011 fiscal year was another challenging year due to the return of flooding conditions covering most of the oil and gas concessions under which the Company holds an interest. Because of the flooding only one well was drilled and completed as a producer during 2011 on the Company’s properties in Australia.

ACOR began its movement from being primarily an oil royalty company to an exploration company in 2000 when ACOR et al was awarded three large concessions in South Australia. ACOR entered into a farm-out arrangement with Holloman to drill three wells retaining a 13.8325% Carried Working Interest. During the quarter ended March 31, 2008, Holloman drilled the Pecos #1 well on PEL 112 being the first of the three well programs. The Pecos #1 was completed as a Dry Hole. During 2008 Holloman obtained approval from the South Australian Government for new exploration terms giving a new five-year work program for PEL 112 and consolidating PEL 108 & 109 to a new Exploration Permit PEL 444. The Company’s terms and conditions mentioned above are subject to change on these two permits as Holloman is seeking a joint venture partner to expand the work program. For further information on activities on the Company’s properties see "Item 2. Properties".

A 12” pipeline was constructed to the Longtom Field with the first delivery of gas beginning on October 21, 2009 on VIC/P54. Revenues from gas sales for the Company begin during the first half of 2010. The Longtom #4 tested 58 million cubic feet of gas per day with liquid hydrocarbons. The net pay section in both Longtom #3 & #4 is 4,000 feet thick and the total depth of both wells was approximately 15,000 feet.

ACOR has Overriding Royalty Interests under 10,766,240 gross surface acres in the Cooper/Eromanga and Bass Strait of the Gippsland Basin plus has working interests under 6,507,224 gross surface acres. For additional information regarding these concessions including those mentioned above in this section see "Item 2. Properties".

The Company’s management is optimistic about the future drilling planned on its Australian interests, especially for the next couple of years.

Results of Operations

The Company's oil and gas revenues increased approximately 62% when comparing 2010 to 2011. In 2010 the revenues were $77,652 compared to $125,726 in 2011. The majority of these revenues came from the Company’s ownership in ATP 299 and ATP 267, oil and gas concessions located in the Cooper/Eromanga Basin of Queensland, Australia, and VIC/P54 located in the Bass Strait of Gippsland Basin of Victoria, Australia.

The categories of Personnel Costs, Professional fees and Promotion and advertising reported expenditures of $144,840 for 2010 compared to $258,345 for 2011. Of the $144,840 the Company paid $10,000 through the issuance of unregistered common stock in 2010 and of the $258,345 the Company paid $179,778 through the issuance of unregistered common stock in 2011. The unregistered shares were issued for those services based on the closing stock price at the time of issuance without any discount for their lack of liquidity. The basic allocation of the 2010 Personnel Cost of $58,055 was $39,317 for contract services, $17,141 in wages and $1,600 for officer compensation. The allocation of the 2011 Personnel Cost of $149,432 was $105,494 for contract services, $22,184 in wages, $21,600 for officer compensation and $154 for miscellaneous fees. The Directors’ fees and other operating expense category for 2010 was $5,885 increasing to $52,506 for 2011. No Directors’ fees were awarded in 2010.

The other categories of expenditures did not significantly change when comparing the fiscal year ended 2010 to 2011.

Other Income (Expense) for the Company includes interest expense of $2,353 for 2010 compared to an interest expense of $5,149 for 2011.

Australian income taxes increased from $10,026 in 2010 to $17,925 for 2011, which is directly related to the increase in revenues.

The net loss for the year ended December 31, 2010 was $147,311 compared to a net loss of $262,283 for the year ended December 31, 2011. Per share losses were $0.01 per share for the year ended 2010 and $0.01 per share for 2011.

Liquidity and Capital Resources

The Company's Total Current Assets as of December 31, 2010 were $31,337 compared to $56,948 on December 31, 2011. The increase in current assets is due to the increase in cash on hand. The Company’s receivables are due from oil and gas sales earned during the year but were not received on or before the end of the reporting year.

The Total Current Liabilities as of December 31, 2010 were $217,211 placing the Company's liquidity ratio of current assets to current liabilities at 0.14 to 1. The Total Current Liabilities as of December 31, 2011 were $343,564 placing the Company's liquidity ratio of current assets to current liabilities at 0.17 to 1. The slight improvement in liquidity ratio from 2010 to 2011 is directly related to more current assets as of December 31, 2011.

The Company plans to meet its operating expenditures from a private placement of its restricted common stock. The Company is seeking exploration partners on its various oil and gas concessions located in Australia.

Total assets of the Company increased from $988,302 on December 31, 2010 to $1,227,350 on December 31, 2011, an increase of $239,048.  The Company Net Property and Equipment increased from $955,881 in 2010 to $961,727.  This increase of $5,846 was attributed to the capital expenditures made on ATP 582, an Australian oil and gas concession. The increase in assets is due to the Company’s wholly owned subsidiary, Cooper/Eromanga Inc., placing an environmental bond for ATP 582 of $207,591 shown in the financial statements as restricted cash under Other Assets.

Total Current Liabilities of the Company increased from $217,211 on December 31, 2011 to $343,564 on December 31, 2011. This increase is due to loans from shareholders of the Company for the environmental bond mentioned above for ATP 582.

The accrued expenses of $115,486 and $41,655 for the years ended December 31, 2010 and 2011 respectively were for consulting fees and director’s fees. The $115,486 in accrued expenses reported on December 31, 2010 is allocated $2,903 for accrued interest payable, $35,600 for accrued director’s fees and $76,983 for consulting fees. The $41,655 in accrued expenses reported on December 31, 2011 is allocated $5,298 for accrued interest payable, $35,600 for accrued director’s fees and $757for other fees.

Plan of Operation and Funding

The Company plans to seek additional oil and gas concessions in Australia on a ground level basis and will seek partners to join in this process. The Company has been successful in entering into farm-out arrangements to defer the exploration commitments on six Australian concessions to joint venture partners and has confidence of being able to repeat this process in the event the Company is successful in acquiring other concessions in Australia.

Material Commitments

The Company has material financial commitments on several of its working interest properties located in Australia. Concessions PEL 112, 444 and ATP 582 have expenditure requirements that may exceed the Company’s Carried Working Interest in each of these concessions. See "Item 2. Properties" for additional information.

Purchase of Significant Equipment

The Company does not intend to purchase any significant equipment during the next twelve months.

Subsequent Events:

The Company has acquired a 100% Working Interest in PL 18 and PL 40, and a 50% Working Interest in PL 280, located in the Bowen/Surat Basin in Queensland Australia. This basin was home to the first oil discovery in Australia, and is currently the focus of significant coal-seam gas exploration and production activity by others.

The assets acquired by the Company include 5 oilfields: Yellowbank Creek, Thomby Creek, Louise, McWhirter, Narrows and Beardmore. These fields were developed in the 1970's and 1980's, and have collectively produced approximately 7-10% of the estimated oil originally in place ("OOIP"). The Company believes that up to 50% of the OOIP is potentially recoverable through the application of well-established enhanced recovery techniques including downspacing, horizontal drilling, and reservoir pressure maintenance through waterflooding.

In 2007, the vendors of the Surat assets (the "Vendors") obtained an independent resource report by CDS Data Services Pty Ltd. ("CDS Report") to assess the remaining recoverable oil resources in the 5 fields. The CDS Report provided a range of 3.8 million barrels of oil equivalent to 6.7 million barrels of remaining recoverable oil resources. Since 2007, there has been no significant investment in the fields as the Vendors were unsuccessful in securing the necessary capital to develop the remaining oil resources. The fields were recently producing 4 barrels of oil per day (bopd) of high quality 51 degree oil, which is sold at a premium of approximately US$8.50 above Brent crude oil price, or a premium of approximately US$24.00 above West Texas Intermediate crude oil price.

The Company currently has 50,000,000 shares of common stock authorized and 49,960,000 shares of common stock outstanding. The Company has agreed to hold an annual and special meeting of shareholders as soon as practicable, in order to, among other things, amend the authorized share capital of the Company to provide for an unlimited number of shares of common stock. Upon such amendments taking effect and in accordance with the terms of the share exchange agreement dated November 17, 2011 (the "Share Exchange Agreement") among ACOR, 1629518 Alberta Ltd. and certain other parties thereto, the Company will issue an additional 69,065 shares of the Company to Bill Petrie Sr, Bill Petrie, Jr, and Jesse Meidl, along with the issuance of 5,000,000 Share Purchase Warrants of ACOR (the "Warrants") to certain persons in accordance with the Share Exchange Agreement. The Warrants will have a strike price of US$0.25 per share, and will only vest if the Company trades at a price above US$1.00 per share for 10 consecutive days, with a total of 100,000 Company shares trading during the 10 day period, and expire 24 months after the date of issuance.

The Company has agreed to pay the Vendors US$3.0 million within 12 months of the closing of the Acquisition (the "Deferred Consideration"). The Vendors have secured a first lien over PL 18, PL 40, and PL 280. The Company intends to secure a reserve based lending facility to refinance the Deferred Consideration, which does not accrue interest or other charges within 12 months of closing.

The Board of the Company are pleased to add two experienced oil industry executives: William Petrie Sr. and Jesse Meidl.

Mr. Petrie has in excess of 35 years' experience as a petroleum geologist, primarily in Western Canada. He began his career with Mobil Oil, leaving after several years to join the independent sector. He has been involved as President and Director for a number of public and private oil and gas companies. In these positions he was responsible for generating, evaluating, and successfully exploiting oil and gas exploration, development, and acquisition opportunities throughout North America.

Mr. Meidl has over 15 years of experience in the oil and gas sector. He is Chief Financial Officer of a private international energy company, headquartered in London, England. Prior thereto, he was an investment banker in the International Oil & Gas group of Thomas Weisel Partners in London (Now Stifel Nicolas). Mr. Meidl was previously the Chief Financial Officer for Arsenal Energy Inc., an international exploration company listed on the Toronto Stock Exchange, which held production assets in Canada and the USA and exploration assets in Egypt, Colombia and Uzbekistan. He qualified as a Chartered Accountant with KPMG in Calgary, where he specialized in oil and gas exploration and production and services. He also holds the ICAEW Corporate Finance qualification and a B. Comm. degree from the University of Saskatchewan (Canada).

It is planned that during the second quarter of 2012, the Company will be undertaking a workover program of certain wells on PL 40 and PL 280 which will reactivate two old wells at a cost of A$400,000. The workover program is anticipated to bring total field production to approximately 25 barrels of oil per day.

The Company will also be obtaining an updated reserve and resource report over all of the assets in the Company's portfolio, including the Surat basin assets and ATP 582. It is anticipated the report will be finalized in the second quarter of 2012.

Recent Accounting Pronouncements

The FASB established the FASB Accounting Standards Codification (“Codification”) as the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements issued for interim and annual periods ending after September 15, 2009. The codification has changed the manner in which U.S. GAAP guidance is referenced, but did not have an impact on our financial position, results of operations or cash flows.

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2010-06, “Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements.” This ASU requires some new disclosures and clarifies some existing disclosure requirements about fair value measurement as set forth in Accounting Standards Codification (“ASC”) 820. ASU 2010-06 amends ASC 820 to now require: (1) a reporting entity should disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and (2) in the reconciliation for fair value measurements using significant unobservable inputs, a reporting entity should present separately information about purchases, sales, issuances, and settlements. In addition, ASU 2010-06 clarifies the requirements of existing disclosures. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Early application is permitted. The Company will comply with the additional disclosures required by this guidance upon its adoption in January 2010.

Also in January 2010, the FASB issued Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas—Oil and Gas Reserve Estimation and Disclosures.”  This ASU amends the “Extractive Industries—Oil and Gas” Topic of the Codification to align the oil and gas reserve estimation and disclosure requirements in this Topic with the SEC’s Release No. 33-8995, “Modernization of Oil and Gas Reporting Requirements (Final Rule),” discussed below.  The amendments are effective for annual reporting periods ending on or after December 31, 2009, and the adoption of these provisions on December 31, 2009 did not have a material impact on our financial statements.

SEC’s Final Rule on Oil and Gas Disclosure Requirements

On December 31, 2008, the SEC issued Release No. 33-8995, “Modernization of Oil and Gas Reporting Requirements (Final Rule),” which revises the disclosures required by oil and gas companies.  The SEC disclosure requirements for oil and gas companies have been updated to include expanded disclosure for oil and gas activities, and certain definitions have also been changed that will impact the determination of oil and gas reserve quantities.  The provisions of this final rule are effective for registration statements filed on or after January 1, 2010, and for annual reports for fiscal years ending on or after December 31, 2009

In August 2009, the FASB issued ASU No. 2009-05, “Fair Value Measurements and Disclosures (Topic 820) — Measuring Liabilities at Fair Value,” related to fair value measurement of liabilities. This update provides clarification that in circumstances in which a quoted price in an active market for an identical liability is not available, a reporting entity is required to measure fair value using one or more valuation techniques. This guidance is effective for the first reporting period beginning after issuance.

In June 2009, the FASB issued guidance under ASC 105, “Generally Accepted Accounting Principles.” This guidance established a new hierarchy of GAAP sources for non-governmental entities under the FASB Accounting Standards Codification. The Codification is the sole source for authoritative U.S. GAAP and supersedes all accounting standards in U.S. GAAP, except for those issued by the SEC. The guidance was effective for financial statements issued for reporting periods ending after September 15, 2009. The adoption had no impact on the Company’s financial position, cash flows or results of operations.

In May 2009, the FASB issued guidance under ASC 855 “Subsequent Events,” which sets forth: (1) the period after the balance sheet date during which management of reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The guidance was effective on a prospective basis for interim or annual financial periods ending after June 15, 2009.

In April 2009, the FASB updated its guidance under ASC 820, “Fair Value Measurements and Disclosures,” related to estimating fair value when the volume and level of activity for an asset or liability have significantly decreased and identifying circumstances that indicate a transaction is not orderly. The guidance was effective for interim and annual reporting periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009. The adoption of this guidance did not have any impact on the Company’s results of operations.

Also in April 2009, the FASB updated its guidance under ASC 825, “Financial Instruments,” which requires disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This guidance also requires those disclosures in summarized financial information at interim reporting periods. The guidance was effective for interim reporting periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009.

The FASB updated its guidance under ASC 805, “Business Combinations,” in April 2009, which addresses application issues on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This guidance was effective for business combinations occurring on or after the beginning of the first annual period on or after December 15, 2008.

In June 2008, the FASB updated its guidance under ASC 260, “Earnings Per Share.” This guidance clarified that all unvested share-based payment awards with a right to receive nonforfeitable dividends are participating securities and provides guidance on how to allocate earnings to participating securities and compute basic earnings per share using the two-class method. This guidance was effective for fiscal years beginning after December 15, 2008. The Company adopted this guidance on January 1, 2009. The adoption did not have a material impact on the Company’s earnings per share calculations.

In March 2008, the FASB issued guidance under ASC 815, “Derivatives and Hedging,” which changes the disclosure requirements for derivative instruments and hedging activities. Entities will be required to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related items affect an entity’s financial position, operations and cash flows. This guidance was effective as of the beginning of an entity’s fiscal year that begins after November 15, 2008. The Company adopted this guidance on January 1, 2009.

Accounting For Natural Gas and Oil Producing Activities

We use the full cost method to account for our natural gas and oil producing activities. Under this accounting method, we capitalize substantially all of the costs incurred in connection with the acquisition, development, and exploration of natural gas and oil reserves in full cost pools maintained by geographic areas, regardless of whether reserves are actually discovered and apply a quarterly full cost ceiling test. Adverse changes in conditions (primarily gas price declines) could result in permanent write-downs in the carrying value of oil and gas properties as well as non-cash charges to operations, but would not affect cash flows.

Property, Equipment and Depreciation

We follow the full cost method of accounting for our oil and gas operations whereby all costs related to the acquisition of methane, petroleum, and natural gas interests are capitalized. Under this method, all productive and non-productive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such costs include land and lease acquisition costs, annual carrying charges of non-producing properties, geological and geophysical costs, costs of drilling and equipping productive and non-productive wells, and direct exploration salaries and related benefits. Proceeds from the disposal of oil and gas properties are recorded as a reduction of the related capitalized costs without recognition of a gain or loss unless the disposal would result in a change of 20 percent or more in the depletion rate.

Depreciation and depletion of proved oil and gas properties is computed on the units-of-production method based upon estimates of proved reserves, as determined by independent consultants, with oil and gas being converted to a common unit of measure based on their relative energy content.

The costs of acquisition and exploration of unproved oil and gas properties, including any related capitalized interest expense, are not subject to depletion, but are assessed for impairment either individually or on an aggregated basis. The costs of certain unevaluated leasehold acreage are also not subject to depletion. Costs not subject to depletion are periodically assessed for possible impairment or reductions in value. If a reduction in value has occurred, costs subject to depletion are increased or a charge is made against earnings for those operations where a reserve base is not yet established.

Estimated future removal and site restoration costs are provided over the life of proven reserves on units-of-production basis. Costs, which include production equipment removal and environmental remediation, are estimated each period by management based on current regulations, actual expenses incurred, and technology and industry standards. The charge is included in the provision for depletion and depreciation and the actual restoration expenditures are charged to the accumulated provision amounts as incurred.

We apply a ceiling test to capitalized costs which limits such costs to the aggregate of the estimated present value, using a ten percent discount rate of the estimated future net revenues from production of proven reserves at year end at market prices less future production, administrative, financing, site restoration, and income tax costs plus the lower of cost or estimated market value of unproved properties. If capitalized costs are determined to exceed estimated future net revenues, a write-down of carrying value is charged to depletion in the period.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

N/A

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The following financial statement information for Australian-Canadian Oil Royalties Ltd. begins following the signature page of this form. The Index to the Financial Statements is on page F-1.

Report of Independent Registered Public Accounting Firm

Balance Sheets

Statements of Operations and Comprehensive (Loss)

Statements of Stockholders’ Equity

Statements of Cash Flows

Notes to Financial Statements

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Our principal independent accountant from inception through September 5, 2005 was Robert Early & Company, P.C. of Abilene, Texas. Beginning September 6, 2005 Killman, Murrell & Company, P.C. of Odessa, Texas became independent accountant for the Company. There are no disagreements or reportable events between the Company and its previous auditor Robert Early & Company, P.C. or its current auditor, KWCO, P.C. (formerly Killman, Murrell & Company, P.C.)

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

In connection with the preparation of this Form 10-K, an evaluation was carried out by our management, with the participation of the Chief Executive Officer and Principal Accounting Officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 ("Exchange Act")) as of December 31, 2011. Disclosure controls and procedures are designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including the Chief Executive Officer and the Principal Financial Officer, to allow timely decisions regarding required disclosures.

Based on that evaluation, our management concluded that our disclosure controls and procedures were effective in reporting information required to be disclosed within the time periods specified in the SEC's rules and forms.

Management's Report on Internal Control Over Financial Reporting

Management of our company is responsible for establishing and maintaining adequate internal control over financial reporting. Our company's internal control over financial reporting is a process, under the supervision of the Chief Executive Officer and the Principal Accounting Officer, designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with GAAP accounting principles. Internal control over financial reporting includes those policies and procedures that:

Our management conducted an assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management concluded that there was no material weakness in our internal controls over financial reporting, and accordingly, our controls are effective.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Also, 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.

This Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the SEC that permit the Company to provide only management’s report in this Form 10-K.

Changes in Internal Control over Financial Reporting

There were no changes in internal control over financial reporting (as defined in Rule 13a-15(f) of the Exchange Act) during the quarter ended December 31, 2011, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not applicable.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors - The Board of Directors of the Company presently consists of seven members. Each director is elected at the annual meeting of shareholders to hold office until the next annual meeting of shareholders and until his successor has been elected and qualified. The following table sets forth information concerning the persons currently serving as directors of the Company.

(1) Robert Kamon resigned as a director and secretary effective February 17, 2012.

(2) Jesse Meidl and William Petrie, Sr. were appointed as directors effective February 29, 2012.

Executive Officers - Unless otherwise specified by the Board, all executive officers are elected for a term of one year, commencing with the date of the first meeting of the Board following the annual meeting of shareholders, and serve until their successors are elected or appointed and qualified, or until their respective death, resignation, removal or disqualification. All of the Company’s officers are executive officers. The following table sets forth certain information with respect to the persons currently serving as executive officers of the Company.

(1) Robert Kamon resigned as a director and secretary effective February 17, 2012.

Andre Sakhai, President and Director, attended Arizona State University, which included a curriculum of financial accounting and microeconomics, as well as money and banking. Mr. Sakhai is a licensed real estate salesperson in the state of New York and has other experience in computer functions as well as experience in all aspects of the financial markets.

Robert Kamon, Director and Secretary, is a petroleum-engineering graduate of the University of Texas at Austin, Texas. Mr. Kamon has been President of three NASDAQ listed companies. He is currently the President of several private companies - Australian Grazing and Pastoral Co. Pty. Ltd. since 1954, International Oil Lease Service Corp. since 1961, and Tensleep Oil and Production, Inc. since 1989. Mr. Kamon resigned as Secretary and Director on February 17, 2012.

Kenneth W. Campbell, Director, is a graduate of the University of Brandon (Manitoba, Canada). He has been the President of Solar Energy Resources, Ltd., a privately held independent Canadian oil and gas producer for more than twenty-five years.

Howard Siegel, Director, is a graduate of the University of Oklahoma and has a law degree from Saint Mary’s University Law School. Mr. Siegel has been a member of the State of Texas Bar Association since 1969 and became a member of the Colorado Bar Association in 1989. Mr. Siegel has over thirty years of experience in all matters of corporate law, oil and gas, real estate, employee benefits, taxation and general practice.

Jan Soleimani, Director, is the owner of Bokara Rug Company in New York. His company manufactures high quality handmade rugs for distribution to elite furniture stores across the United States. Mr. Soleimani has been an active businessman for 34 years in the manufacturing and distribution of high quality handmade rugs plus has been involved in other successful business ventures including real estate development.

Bernard Lipton, Director, is a certified public accountant certified by the State of New York in 1968. He is the founder and managing member of Lipton & Association LLP and has been self-employed for the past forty years. His practice encompasses the tri-state area around New York and services clients in all fields with an extensive tax practice.

Mahnaz (Michelle) Nourmand, Chief Financial Officer, is a graduate of Queens College of New York where she received her Bachelor Degree in Accounting.  In 1990 she received her MBA of Business also from Queens College.  Currently, Ms. Nourmand is a Senior Manager & Tax Accountant for The Tobacco & Food Distribution of Corona, New York.  Ms. Nourmand has 18 years experience and is a practicing Certified Public Accountant with an emphasis on corporate accounting preparing projections, budgets and financial statements.

Jesse Meidl, Director, has over 15 years of experience in the oil and gas sector. He is Chief Financial Officer of a private international energy company, headquartered in London, England. Prior thereto, he was an investment banker in the International Oil & Gas group of Thomas Weisel Partners in London (Now Stifel Nicolas). Mr. Meidl was previously the Chief Financial Officer for Arsenal Energy Inc., an international exploration company listed on the Toronto Stock Exchange, which held production assets in Canada and the USA and exploration assets in Egypt, Colombia and Uzbekistan. He qualified as a Chartered Accountant with KPMG in Calgary, where he specialized in oil and gas exploration and production and services. He also holds the ICAEW Corporate Finance qualification and a B. Comm. degree from the University of Saskatchewan (Canada).

William Petrie, Sr., Director, has in excess of 35 years' experience as a petroleum geologist, primarily in Western Canada. He began his career with Mobil Oil, leaving after several years to join the independent sector. He has been involved as President and Director for a number of public and private oil and gas companies. In these positions he was responsible for generating, evaluating, and successfully exploiting oil and gas exploration, development, and acquisition opportunities throughout North America.

Family Relationships

There are no family relationships between the officers and directors of the Company; however, Ely Sakhai, a major shareholder, is the father of Andre Sakhai, President and Director of the Company.

Code of Business Conduct and Ethics

We have not adopted a Code of Business Conduct and Ethics at this time, though we plan to implement such policies in fiscal year 2012.

Audit Committee Financial Expert

Our audit committee does not have an “audit committee financial expert,” as defined under applicable SEC rules.  However, the directors of the Company have extensive knowledge of the Company and its operations. The directors of the Company understand the audit process, are involved in the financial reporting process, and have a basic understanding of GAAP and internal controls over financial reporting.

ITEM 11. EXECUTIVE COMPENSATION

The executive officers of ACOR have received no salary or cash bonuses since the organization of the Company. The Company has no bonus, pension, or profit sharing plans. The Company pays for copies, phone usage, travel expenses, and other labor to non-related parties.

Officer Compensation – The executive officers of ACOR have received no cash salary or cash bonuses since the organization of the Company, with the exception of its Chief Financial Officer, Mahnaz Nourmand, who received 111,429 restricted shares valued at $20,000 for 2010 and 2011.

Director Compensation – In 2006 the Board approved the issuance of 30,000 restricted shares to each director, in 2007 and 2008 the Board approved the issuance of 40,000 restricted shares to each director, in 2009 the Board approved the issuance of 50,000 restricted shares to each director, and in 2011 the Board approved the issuance of 40,000 restricted shares to each director, to be issued only when requested by the director. Howard Siegel was issued 30,000 shares in 2006, 40,000 shares in 2007 and 40,000 shares in 2008. Kenneth Campbell, Robert Kamon and Andre Sakhai received all 110,000 shares in 2008. Jan Soleimani received 80,000 shares in 2008. In 2009 the Company issued 50,000 shares to Howard Siegel and Robert Kamon. In 2010, the Company issued 50,000 shares to Andre Sakhai and Kenneth Campbell for 2009 directors’ fees. In 2011, the Company issued 40,000 shares to each of the directors.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The following table sets forth information regarding the beneficial ownership of the common stock of the Company as of April 12, 2012 by each of the Company’s officers and directors, each person who is known by the Company to own beneficially more than 5% of the outstanding common stock and all officers and directors of the Company as a group. The title of class is common stock, no par value.

* Tensleep Oil & Production, Inc. (Tensleep) is controlled by Robert Kamon. Robert Kamon owns 50% of the shares of Tensleep.

** Robert Kamon’s (4,104,717 shares) and Tensleep’s (908,000 shares) holdings are all attributed to Robert Kamon for purposes of presenting his beneficial ownership percentage. Robert Kamon is President of Tensleep Oil & Production, Inc.

Note: The stockholders identified in this table have sole voting and investment power with respect to the shares beneficially owned by them.

The owners have no rights to acquire additional shares through options, warrants, rights, or conversion privileges within the next sixty days.

Changes in Control

The Company is not aware of any current arrangements, which would result in a change of control of the Company.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE.

The Company owns 13.8325% Working Interest, Ely Sakhai, major shareholder, owns 16.6667% Working Interest and Robert Kamon, former Director and Secretary, owns 4.5% Working Interest in PEL 444 and PEL 112 in Australia. Ely Sakhai acquired an equal 12½% Working Interest in the Park City Gas Field in Kentucky for cash, while the Company acquired its 12½% Working Interest through the issuance of restricted common shares. Ely Sakhai is the father of Andre Sakhai, who is a Director and President of the Company.

Robert Kamon is President of Tensleep Oil & Production, Inc., International Oil Lease Service Corp. (IOLS), and Australian Grazing & Pastoral Co., Pty. Ltd. (AGP). IOLS and AGP are in the business of applying for and acquiring oil and gas concessions in Australia; therefore, activities may involve a conflict of interest with the Company. Tensleep Oil and Production, Inc. is also in the business of oil and gas exploration and its activities may involve a conflict of interest with the Company.

Robert Kamon, former Director and Secretary of the Company provided office space and services, with no cash costs to the Company. These contributed costs had estimated unpaid values of $3,200 for both 2011 and 2010. These amounts have been recorded as operating expenses and as additional paid-in capital in their respective years.

During 2011 and 2010, the Company reimbursed commonly-controlled entities for personnel and office expenses totaling $23,809 and $17,772, respectively. These entities, Tensleep Oil & Production, Inc., and Secretarial Services, Inc., are within the control of the Company’s former Secretary, Robert Kamon. Additionally, the Company repaid Australian Grazing & Pastoral Co., Pty. Ltd., also controlled by Robert Kamon, for filing fees during 2010, which totaled $23,275.

The Company borrowed $218,500 from two of its stockholders (Ken Kamon and Ely Sakhai) in 2011. The terms of the loan are 5% interest per annum if paid by February 12, 2012 and if paid after February 12, 2012 the interest rate shall be 12% per annum or the maximum rate allowed by law. During 2010, the Company borrowed $25,000 from Ely Sakahi, a stockholder of the Company and $25,655 from Ken Kamon, a stockholder of the Company (this $25,655 plus $3,365 in interest was repaid during 2011). These funds were used to pay for administrative costs and efforts to promote the Company's name and availability.

At December 31, 2011 and 2010, the Company’s accounts payable was $5,617 and $11,243, respectively. Accounts payable to related parties was $52,794 and $39,216 in 2011 and 2010, respectively.

Common Shares to Directors – The Compensation Committee approved 40,000 shares of restricted stock per director for 2011, valued at $0.20 per share, being the average market value from January 1, 2011 through May 13, 2011. The Compensation Committee approved 50,000 shares of restricted stock per director for the year 2009, valued at $0.13 per share, being the market value on July 1, 2009. The Compensation Committee approved 40,000 shares of restricted stock per director for the year 2008, valued at $0.22 per share, being the market value on September 24, 2008. The Compensation Committee approved 40,000 shares of restricted stock per director for the year 2007, valued at $0.30 per share, being the market value on June 22, 2007. This recommendation by the Compensation Committee was voted on and approved by the Board of Directors and has been recorded as an expense in these financial statements in the amounts of $32,500 and $44,000, respectively for 2009 and 2008. This stock will be issued to each director at the director's discretion. During 2009, Robert Kamon and Howard Siegel each received 50,000 shares for their fees for 2009. During 2008, Andre Sakhai, Robert Kamon and Kenneth Campbell each received 110,000 shares for their fees for 2006, 2007 and 2008; Howard Siegel received 40,000 for 2008; and Jan Soleimani received 80,000 for 2007 and 2008. During 2010, Andre Sakhai and Kenneth Campbell received 50,000 shares for their 2009 fees. During 2011, all the directors received 40,000 shares each for their 2011 fees.

DIRECTOR INDEPENDENCE

Kenneth Campbell, Howard Siegel, Jan Soleimani, Bernard Lipton, Jesse Meidl and William Petrie, Sr. are not officers of the Company and are classed as independent directors. Andre Sakhai is President of the Company and is classed as an independent director.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

The firm of KWCO, P.C. (formerly Killman, Murrell & Company, P.C.) served as the Company’s independent auditor for the years ended December 31, 2005, 2006, 2007, 2008, 2009, 2010 and 2011. The Board of Directors of the Company, in its discretion, may direct the appointment of different public accountants at any time during the year, if the Board believes that a change would be in the best interests of the stockholders. The Board of Directors has considered the audit fees, audit-related fees, tax fees and other fees paid to the Company's accountants, as disclosed below, and has determined that the payment of such fees is compatible with maintaining the independence of the accountants.

Audit and Audit-Related Fees: The aggregate fees, including expenses, billed by the Company's principal accountant in connection with the audit of our financial statements for the most recent fiscal year included in our Annual Report on Form 10-K; and for the review of our financial information and our quarterly reports on Form 10-Q during the years ending December 31, 2011 and 2010 were $44,417 and $38,325 respectively.

Tax Fees: The Company incurred no fees for tax compliance with the Company's principal auditor for 2011 and 2010.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

* Filed herewith.

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 to be signed on its behalf by the undersigned, thereunto duly authorized.

Australian-Canadian Oil Royalties Ltd.

INDEX TO FINANCIAL STATEMENTS

Board of Directors

Australian-Canadian Oil Royalties Ltd.

Cisco, Texas

We have audited the accompanying balance sheets of Australian-Canadian Oil Royalties Ltd. as of December 31, 2011 and 2010, and the related statements of operations, 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 audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Australian-Canadian Oil Royalties Ltd. as of December 31, 2011, and 2010, 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 financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 10 to the financial statements, the Company has suffered recurring losses from operations and its limited capital resources raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also discussed in Note 11. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ KWCO, PC
KWCO, P.C.

Odessa, Texas

April 12, 2012

Australian-Canadian Oil Royalties Ltd.

Balance Sheets

December 31, 2011 and 2010

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

Australian-Canadian Oil Royalties Ltd.

Statements of Operations

For the Years Ended December 31, 2011 and 2010

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

Australian-Canadian Oil Royalties Ltd.

Statements of Stockholders' Equity

For the Years Ended December 31, 2011 and 2010

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

Australian-Canadian Oil Royalties Ltd.

Statements of Cash Flows

For the Years Ended December 31, 2011 and 2010

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

Australian-Canadian Oil Royalties Ltd.

Notes to Financial Statements

December 31, 2011 and 2010

NOTE 1: DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

DESCRIPTION OF BUSINESS

Australian-Canadian Oil Royalties Ltd. (the Company) was incorporated April 28, 1997 in Vancouver, British Columbia, Canada. Its primary business plan is the purchase of Overriding Royalty Interests for long-term passive income and capital gains, with sales of these interests as deemed in the best interest of the Company. Current primary income sources are royalties earned on Overriding Royalty Interests held by the Company. The Company also engages related entities and third parties for leasing operations in Australia. The primary producing properties held by the Company are located in Australia’s main onshore oil and gas producing basin. These financial statements are prepared in U.S. dollars for use in U.S. securities filings.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Stock Based Compensation

The Company accounts for services acquired (and other expenses paid) using stock as compensation (or payment) based on the fair value of the shares issued. Fair value is determined based on the closing price of the stock on the date the Company becomes obligated to issue the shares.

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas producing activities and, accordingly, capitalizes all costs incurred in the acquisition, exploration, and development of proved oil and gas properties, including the costs of abandoned properties, Dry Holes, geophysical costs, and annual rentals. All general corporate costs are treated as expenses as incurred. In general, sale or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recorded. Capitalized costs are recorded in cost centers on a country-by-country basis. Most of the Company’s oil and gas properties consist of Overriding Royalty Interests that are located in Australia. The Company had not participated in the exploration and development of proved oil and gas properties until 2002. Capitalized costs are subject to a “ceiling test,” which basically limits such costs to the aggregate of the “estimated present value,” discounted at a 10% interest rate of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties. Costs in excess of the ceiling test are adjusted against income.

Costs of producing royalty interests are being amortized over the estimated reserves reported by the Queensland, Australia government (for Queensland properties) and the operator of the Victoria, Australia petroleum lease (Victoria property). Costs of non-producing interests are not being amortized pending development or production and sale of oil or gas, but they are assessed for impairment on an aggregate country-by-country basis.

Australian-Canadian Oil Royalties Ltd.

Notes to Financial Statements (continued)

December 31, 2011 and 2010

Office Equipment and Software

Office equipment and software are carried at depreciated cost. Acquisitions are recorded at cost. Expenditures for major renewals and betterments that extend the useful lives are capitalized. Expenditures for maintenance and repairs are charged to expense as incurred. The cost of software and equipment is depreciated over the estimated useful lives of the related asset. Depreciation is computed on the straight-line method for financial reporting purposes.

Income Taxes

Deferred tax liabilities and assets result from temporary differences between the financial statement and income tax bases of assets and liabilities. The company records and adjusts any deferred tax asset valuations based on judgment as to future realization of the deferred tax benefits supported by demonstrated trends in the Company’s operating results.

As a Canadian corporation, the Company is liable for income taxes under the laws of Canada. Under Canadian laws the Company’s Canadian-source income is subject to a 46% tax (denominated in Canadian dollars). Operating losses can be carried forward for seven years. The Company has unused operating loss carry-forwards at December 31, 2011 that may be applied against future Canadian taxable income. These expire as presented below. Because the timing of realization of the tax benefit from these loss carry-forwards cannot be currently projected, a valuation allowance has been established to completely offset this asset.

The potential tax benefit from these operating loss carry-forwards is $1,167,477 and $1,119,613 in 2011 and 2010, respectively. The Company has recognized a valuation allowance against these deferred tax assets due to the inability to foresee when such benefits will be realized.

The Company is subject to a 30% Australian income tax on Australian source royalty income. This tax is withheld by the payer. The Company incurred Australian income taxes on its oil and gas production totaling $17,168 and $10,026 in 2011 and 2010, respectively.

Australian-Canadian Oil Royalties Ltd.

Notes to Financial Statements (continued)

December 31, 2011 and 2010

Loss Per Share

U.S. accounting rules provide for the calculation of “Basic” and “Diluted” earnings per share. Basic earnings per common share are computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted loss per common share reflect the potential dilution of securities that could share in the loss of the entity on as “as if converted” basis. This is computed by dividing net income available to common shareholders, as adjusted if necessary, by the weighted average number of common shares outstanding plus potentially dilutive securities.

Weighted average shares outstanding were 21,096,182 and 19,772,491 for 2011 and 2010, respectively. Outstanding common stock equivalents have been excluded from the calculation of diluted losses per share because their effect would be antidilutive.

Cash Flows

The Company considers unrestricted cash and cash investments with initial maturity or marketability of three months or less to be cash equivalents for purposes of presenting its Statement of Cash Flows. Cash investments whose use is limited through collateral restrictions are not considered to be cash for cash flows.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimated.

Financial Instruments

Unless otherwise specified, management believes the carrying value of its financial instruments approximates their fair value due to the short term to maturity.

Reclassifications

Certain 2010 amounts have been reclassified in order to conform to the 2011 financial statement presentation.

Recent Accounting Pronouncements

The FASB established the FASB Accounting Standards Codification (“Codification”) as the source of authoritative U.S. generally accepted accounting principles (“GAAP”) recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements issued for interim and annual periods ending after September 15, 2009. The codification has changed the manner in which U.S. GAAP guidance is referenced, but did not have an impact on our financial position, results of operations or cash flows.

Australian-Canadian Oil Royalties Ltd.

Notes to Financial Statements (continued)

December 31, 2011 and 2010

In June 2011, the FASB issued Accounting Standards Update 2011-05, Presentation of Comprehensive Income. This update provides the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The Company does not believe that this will materially impact the presentation of its financial statements.

 In May 2011, the FASB issued Accounting Standards Update 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This update does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. This update may require certain additional disclosures related to fair value measurements. We do not expect the adoption of this update will materially impact our financial statement disclosures.

In December 2010, the FASB (Financial Accounting Standards Board) issued Accounting Standards Update 2010-29 (ASU 2010-29), Business Combinations (Topic 805) – Disclosure of Supplementary Pro Forma Information for Business Combinations . This Accounting Standards Update requires a public entity to disclose pro forma information for business combinations that occurred in the current reporting period. The disclosures include pro forma revenue and earnings of the combined entity for the current reporting period as though the acquisition date for all business combinations that occurred during the year had been as of the beginning of the annual reporting period. The amendments in this Update are effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010.  Early adoption is permitted. The Company does not expect the provisions of ASU 2010-29 to have a material effect on our financial statements.

In July 2010, the FASB issued Accounting Standards Update 2010-20 (ASU 2010-20), Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses.   The amendments in this Update are to provide financial statement users with greater transparency about an entity’s allowance for credit losses and the credit quality of its financing receivables. The disclosures about activity that occurs during the reporting period are effective for interim and annual reporting periods beginning on or after December 15, 2010.  The Company does not expect the provisions of ASU 2010-20 to have a material effect on our financial statements.

In February 2010, the FASB issued ASU No. 2010-09 Subsequent Events (ASC Topic 855) - Amendments to Certain Recognition and Disclosure Requirements (ASU 2010-09).  ASU No. 2010-09 requires an entity that is an SEC filer to evaluate subsequent events through the date that the financial statements are issued and removes the requirement for an SEC filer to disclose a date, in both issued and revised financial statements, through which the filer had evaluated subsequent events. The adoption did not have an impact on the Company’s financial statements.

Australian-Canadian Oil Royalties Ltd.

Notes to Financial Statements (continued)

December 31, 2011 and 2010

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2010-06, “Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements.” This ASU requires some new disclosures and clarifies some existing disclosure requirements about fair value measurement as set forth in Accounting Standards Codification (“ASC”) 820. ASU 2010-06 amends ASC 820 to now require: (1) a reporting entity should disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and (2) in the reconciliation for fair value measurements using significant unobservable inputs, a reporting entity should present separately information about purchases, sales, issuances, and settlements. In addition, ASU 2010-06 clarifies the requirements of existing disclosures. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Early application is permitted. The adoption did not have an impact on our financial statement.

Also in January 2010, the FASB issued Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas—Oil and Gas Reserve Estimation and Disclosures.”  This ASU amends the “Extractive Industries—Oil and Gas” Topic of the Codification to align the oil and gas reserve estimation and disclosure requirements in this Topic with the SEC’s Release No. 33-8995, “Modernization of Oil and Gas Reporting Requirements (Final Rule),” discussed below.  The amendments are effective for annual reporting periods ending on or after December 31, 2009, and the adoption of these provisions on December 31, 2009 did not have a material impact on our financial statements.

NOTE 2: ACCOUNTS RECEIVABLE

At December 31, 2011 and 2010 the Company has accrued receivables for oil and gas production from its Australian Overriding Royalty Interests totaling $26,770 and $28,992, respectively. Collection of the accrued Australian production generally occurs during the quarter following the quarter of production.

The cost basis of the receivables are believed to approximate their fair values. No allowance for bad debts has been established because the Company has not experienced any significant inability to collect its receivables.

NOTE 3: PROPERTIES AND EQUIPMENT

The following table presents costs of property and equipment at December 31, 2011 and 2010.

Depreciation expense was $370 for both 2011 and 2010. The office equipment and the software are being depreciated on a straight-line basis over three years.

Australian-Canadian Oil Royalties, Ltd.

Notes to Financial Statements (continued)

December 31, 2011 and 2010

NOTE 4: LOANS FROM SHAREHOLDERS AND NOTES PAYABLE

During 2011, the Company borrowed $218,500 from two stockholders to cover costs related to petroleum concession ATP 582.

During 2010, the Company borrowed $26,266 from a stockholder to cover the cost of rentals on petroleum concession ATP 582.

NOTE 5: TRANSACTIONS WITH RELATED PARTIES

An officer provided office space and services, with no cash costs to the Company. These contributed costs had estimated unpaid values of $3,200 for both 2011 and 2010. These amounts have been recorded as operating expenses and as additional paid-in capital in their respective years.

During 2011 and 2010, the Company reimbursed commonly-controlled entities for personnel and office expenses totaling $23,809 and $17,772, respectively. These entities, Tensleep Oil & Production, Inc., and Secretarial Services, Inc., are within the control of the Company’s Secretary. Additionally, the Company repaid Australian Grazing & Pastoral Co., Pty. Ltd., also controlled by the Company’s Secretary, for filing fees during 2011, which totaled $23,275.

The Company borrowed $218,500 from two of its stockholder in 2011 that was deposited in an Australian bank to comply with environmental bond requirements of the Queensland, Australia government. This cash deposit ($207,591) is classified in Other Assets on the Balance Sheet. During 2010 the Company borrowed $25,000 from one of its previous officers and $26,266 from a stockholder (this $26,266 was repaid during 2011). These funds were used to pay for administrative costs and efforts to promote the Company's name and availability.

At December 31, 2011 and 2010, the Company’s accounts payable was $5,617 and $11,243, respectively. Accounts payable to related parties was $52,794 and $39,216 in 2011 and 2010, respectively.

Common Shares to Directors – The Compensation Committee approved 40,000 shares of restricted stock per director for the year 2011, valued at $0.20, being the average market price from January 1, 2011 through May 13, 2011. All shares awarded to directors in 2011 were issued during the year. In 2010, the Company did not award any shares to directors for compensation. At December 31, 2011, the Company had accrued director’s fees of $35,600 for 80,000 shares that were awarded in prior periods, which have not been issued. Stock is issued to each director at the director’s direction.

NOTE 6: FOREIGN OPERATIONS

As noted above, the Company was incorporated in Canada. Additionally, the Company operates primarily in Australia where most of its properties are presently located. Approximately 95% of all operating revenues reported by the Company during 2011 and 2010 were received from Australian oil and gas royalty interests. Depletion expense and Australian income taxes reported by the Company during 2011 and 2010 are also related to the revenue received from the Australian royalties. Australian revenues were $125,262 and $76,830 in 2011 and 2010.

Essentially all of the Company’s administrative costs are incurred in the United States. Leasing operating expenses and taxes have been incurred in the U.S. and taxes have been paid to Australia.

Australian-Canadian Oil Royalties, Ltd.

Notes to Financial Statements (continued)

December 31, 2011 and 2010

NOTE 7: STOCK TRANSACTIONS

During 2011, the Company issued a total of 2,657,396 shares. A total of 1,311,112 were issued for cash; 351,429 shares were issued for Directors’ and Officers’ fees valued at 68,000 and 994,855 shares were issued for services valued at $179,778.

During 2010, the Company issued a total of 557,143 shares. A total of 357,143 shares were issued for cash; 100,000 shares were issued for Directors’ Fees valued at $13,000 and 100,000 shares were issued for services valued at $10,000.

NOTE 8: SUBSEQUENT EVENTS

We have evaluated events and transactions that occurred after the balance sheet date of December 31, 2011 through the date the financial statements were ready for issuance as noted below:

The Company acquired a 100% Working Interest in PL 18, PL 40, and a 50% Working Interest in PL 280, located in the Bowen/Surat Basin in Queensland Australia. This basin was home to the first oil discovery in Australia, and is currently the focus of significant coal-seam gas exploration and production activity by others. In connection with the transaction, the Company sold 5,473,385 shares for cash and issued 21,780,935 shares to the sellers.

The assets acquired by the Company include 5 oilfields: Yellowbank Creek, Thomby Creek, Louise, McWhirter, Narrows and Beardmore. These fields were developed in the 1970's and 1980's, and have collectively produced approximately 7-10% of the estimated oil originally in place ("OOIP"). The Company believes that up to 50% of the OOIP is potentially recoverable through the application of well-established enhanced recovery techniques including downspacing, horizontal drilling, and reservoir pressure maintenance through waterflooding.

In 2007, the vendors of the Surat assets (the "Vendors") obtained an independent resource report by CDS Data Services Pty Ltd. ("CDS Report") to assess the remaining recoverable oil resources in the 5 fields. The CDS Report provided a range of 3.8 million barrels of oil equivalent to 6.7 million barrels of remaining recoverable oil resources. Since 2007, there has been no significant investment in the fields as the Vendors were unsuccessful in securing the necessary capital to develop the remaining oil resources. The fields were recently producing 4 barrels of oil per day (bopd) of high quality 51 degree oil, which is sold at a premium of approximately US$8.50 above Brent crude oil price, or a premium of approximately US$24.00 above West Texas Intermediate crude oil price.

After the acquisition, the Company currently has 50,000,000 shares of common stock authorized and 49,960,000 shares of common stock outstanding. The Company has agreed to hold an annual and special meeting of shareholders as soon as practicable, in order to, among other things, amend the authorized share capital of the Company to provide for an unlimited number of shares of common stock. Upon such amendments taking effect and in accordance with the terms of the share exchange agreement dated November 17, 2011 (the "Share Exchange Agreement") among ACOR, 1629518 Alberta Ltd. and certain other parties thereto, the Company will issue an additional 69,065 shares of the Company to Bill Petrie Sr, Bill Petrie Jr, and Jesse Meidl, along with the issuance of 5,000,000 Share Purchase Warrants of ACOR (the "Warrants") to certain persons in accordance with the Share Exchange Agreement. The Warrants will have a strike price of US$0.25 per share, and will only vest if the Company trades at a price above US$1.00 per share for 10 consecutive days, with a total of 100,000 Company shares trading during the 10 day period, and expire 24 months after the date of issuance.

The Company has agreed to pay the Vendors US$3.0 million within 12 months of the closing of the Acquisition (the "Deferred Consideration"). The Vendors have secured a first lien over PL 18, PL 40, and PL 280. The Company intends to secure a reserve based lending facility to refinance the Deferred Consideration, which does not accrue interest or other charges within 12 months of closing.

Australian-Canadian Oil Royalties, Ltd.

Notes to Financial Statements (continued)

December 31, 2011 and 2010

The Board of the Company are pleased to add two experienced oil industry executives: William Petrie Sr. and Jesse Meidl.

Mr. Petrie has in excess of 35 years' experience as a petroleum geologist, primarily in Western Canada. He began his career with Mobil Oil, leaving after several years to join the independent sector. He has been involved as President and Director for a number of public and private oil and gas companies. In these positions he was responsible for generating, evaluating, and successfully exploiting oil and gas exploration, development, and acquisition opportunities throughout North America.

Mr. Meidl has over 15 years of experience in the oil and gas sector. He is Chief Financial Officer of a private international energy company, headquartered in London, England. Prior thereto, he was an investment banker in the International Oil & Gas group of Thomas Weisel Partners in London (Now Stifel Nicolas). Mr. Meidl was previously the Chief Financial Officer for Arsenal Energy Inc., an international exploration company listed on the Toronto Stock Exchange, which held production assets in Canada and the USA and exploration assets in Egypt, Colombia and Uzbekistan. He qualified as a Chartered Accountant with KPMG in Calgary, where he specialized in oil and gas exploration and production and services. He also holds the ICAEW Corporate Finance qualification and a B. Comm. degree from the University of Saskatchewan (Canada).

It is planned that during the second quarter of 2012, the Company will be undertaking a workover program of certain wells on PL 40 and PL 280 which will reactivate two old wells at a cost of A$400,000. The workover program is anticipated to bring total field production to approximately 25 barrels of oil per day.

The Company will also be obtaining an updated reserve and resource report over all of the assets in the Company's portfolio, including the Surat basin assets and ATP 582. It is anticipated the report will be finalized in the second quarter of 2012.

NOTE 9: CONCENTRATION OF RISK

The producing oil and gas assets of the Company are all located in Australia. These continue to be the primary source of operating revenues for the Company.

Accounts at the bank are insured by the Federal Deposit Insurance Corporation (FDIC) up to $250,000 per depositor. Combined balances at December 31, 2011 at the Company’s primary bank did not exceed federally insured limits. At December 31, 2011, $209,153 was held in an Australian bank. At December 31, 2011, $207,591 in the Australian bank is restricted to comply with environmental bond requirements of the Queensland, Australia government and accordingly is classified as Other Assets on the Balance Sheet.

NOTE 10: GOING CONCERN CONSIDERATIONS

As of December 31, 2011, the Company has limited disposable cash and its revenues are not sufficient to, and cannot be projected to, cover operating expenses and expansion by the Company. These factors raise substantial doubt as to the ability of the Company to continue as a going concern. Management’s plans include attempting to raise funds from the public through a stock offering, and attempting to acquire additional producing interests in exchange for stock. Management intends to make every effort to identify and develop sources of funds. There is no assurance that Management will be successful. The Company is effectively debt free and could continue to operate at subsistence levels pending development of funding sources.

Australian-Canadian Oil Royalties, Ltd.

Notes to Financial Statements (continued)

December 31, 2011 and 2010

NOTE 11: SUPPLEMENTARY DATA – RESERVES OF OIL AND GAS (UNAUDITED)

The following schedules set out available information about the Company’s oil and gas activities at December 31, 2011.

Reserves of Oil and Gas - Royalty Interests

The current quantities of reserves of oil and gas relating to royalty interests are presented based on information obtained from estimated reserves as reported by the Queensland, Australia Government and the operator of the Victoria, Australia petroleum lease. Reserve data for Victoria lease was derived from reserve data reported by the operator at October 1, 2009, adjusted for actual production in 2010 and 2011. Reserve data is revised annually and published by the Queensland government on their website. No reserve information is presented relating to the Company’s Working Interests because the necessary information is not available or the Company’s interests are not large enough to economically and reasonably obtained this information.

NOTE 11: SUPPLEMENTARY DATA – RESERVES OF OIL AND GAS (UNAUDITED) (continued)

Results of Operations for Producing Activities

For the Year Ended December 31, 2011

Capitalized Costs Relating to Oil and Gas Producing Activities

At December 31, 2011

Australian-Canadian Oil Royalties, Ltd.

Notes to Financial Statements (continued)

December 31, 2011 and 2010

NOTE 11: SUPPLEMENTARY DATA – RESERVES OF OIL AND GAS (UNAUDITED) (continued)

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development

For the Year Ended December 31, 2011