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As filed with the Securities and Exchange Commission on February 6, 2014

Registration No. 333-                

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549



FORM F-10
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933



BAYTEX ENERGY CORP.
(Exact name of registrant as specified in its charter)

Alberta, Canada
(Province or other jurisdiction of incorporation or organization)

1381
(Primary Standard Industrial Classification Code Number, if applicable)

Not applicable
(I.R.S. Employer Identification No., if applicable)

2800, 520 – 3rd Avenue S.W.
Calgary, Alberta, Canada, T2P 0R3
Tel: 587-952-3000
(Address and telephone number of Registrant's principal executive offices)

Baytex Energy USA Ltd.
600 17th St., Suite 1600 S.
Denver, CO 80202
Tel: 303-825-2777
(Name, address (including zip code) and telephone number (including area code) of agent for service in the United States)



Copies to:

Murray J. Desrosiers
Baytex Energy Corp.
2800, 520 – 3rd Avenue S.W.
Calgary, Alberta, Canada, T2P 0R3
Tel: 587-952-3000
Fax: 587-952-3029

  Shannon M. Gangl
Burnet, Duckworth & Palmer LLP
2400, 525 – 8th Avenue S.W.
Calgary, Alberta, Canada T2P 1G1
Tel: 403-260-0100
Fax: 403-260-0332
  Andrew J. Foley, Esq.
Paul, Weiss, Rifkind, Wharton & Garrison LLP
1285 Avenue of the Americas
New York, New York 10019-6064
Tel: 212-373-3078
Fax: 212-492-0078
  James M. Prince
Vinson & Elkins LLP
1001 Fannin Street
Suite 2500
Houston, TX 77002-6760
Tel: 713-758-3710
Fax: 713-615-5962
  John S. Osler, QC
McCarthy Tétrault
Suite 3300
421 7th Avenue SW
Calgary, AB T2P 4K9
Tel: 403-260-3554
Fax: 403-260-3501

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

Province of Alberta, Canada
(Principal jurisdiction regulating this offering)

It is proposed that this filing shall become effective (check appropriate box below):

A.

  o   upon filing with the Commission pursuant to Rule 467(a) (if in connection with an offering being made contemporaneously in the United States and Canada).

B.

  ý   at some future date (check the appropriate box below):

  1.   o   pursuant to Rule 467(b) on (            ) at (            ) (designate a time not sooner than 7 calendar days after filing).

  2.   o   pursuant to Rule 467(b) on (            ) at (            ) (designate a time 7 calendar days or sooner after filing) because the securities regulatory authority in the review jurisdiction has issued a receipt or notification of clearance on (            ).

  3.   o   pursuant to Rule 467(b) as soon as practicable after notification of the Commission by the Registrant or the Canadian securities regulatory authority of the review jurisdiction that a receipt or notification of clearance has been issued with respect hereto.

  4.   ý   after the filing of the next amendment to this Form (if preliminary material is being filed).

          If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to the home jurisdiction's shelf prospectus offering procedures, check the following box. o

CALCULATION OF REGISTRATION FEE

               
 
Title of Each Class
of Securities to be
Registered

  Amount
to be Registered

  Proposed Maximum
Offering Price
per Subscription
Receipt

  Proposed Maximum
Aggregate Offering
Price(1)

  Amount of
Registration
Fee(1)

 

Subscription Receipts

          U.S.$1,351,200,000   U.S.$174,034.56

 

(1)
Calculated pursuant to Rule 457(o) under the Securities Act of 1933, as amended. U.S. dollar amounts are calculated based on the Bank of Canada noon rate of US$0.9008=Cdn$1.00 on February 5, 2014.

          The Registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registration statement shall become effective as provided in Rule 467 under the Securities Act of 1933 or on such date as the Commission, acting pursuant to Section 8(a) of the Act, may determine.

   


Information contained herein is subject to completion or amendment. A registration statement relating to these securities has been filed with the Securities and Exchange Commission. These securities may not be sold nor may offers to buy be accepted prior to the time the registration statement becomes effective. This short form prospectus shall not constitute an offer to sell or the solicitation of an offer to buy nor shall there be any sale of these securities in any State of the United States of America in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such State.

A copy of this preliminary short form prospectus has been filed with the securities regulatory authorities in each of the provinces of Canada but has not yet become final for the purpose of the sale of securities. Information contained in this preliminary short form prospectus may not be complete and may have to be amended. The securities may not be sold until a receipt for the short form prospectus is obtained from the securities regulatory authorities.

No securities regulatory authority has expressed an opinion about these securities and it is an offence to claim otherwise. This short form prospectus constitutes a public offering of these securities only in those jurisdictions where they may be lawfully offered for sale and therein only by persons permitted to sell such securities.

Information has been incorporated by reference into this short form prospectus from documents filed with securities commissions or similar authorities in Canada. Copies of the documents incorporated herein by reference may be obtained on request without charge from the Corporate Secretary of Baytex Energy Corp. at Suite 2800, Centennial Place, East Tower, 520 - 3rd Avenue S.W., Calgary, Alberta, Canada, T2P 0R3, Telephone (587) 952-3000 and are also available electronically at www.sedar.com.

PRELIMINARY SHORT FORM PROSPECTUS
SUBJECT TO COMPLETION, DATED FEBRUARY 6, 2014

New Issue

  February 6, 2014

LOGO

$    •   
    •    Subscription Receipts each
representing the right to receive one Common Share


$    •    per Subscription Receipt


 

We are hereby qualifying for distribution    •    subscription receipts (the "Subscription Receipts") at a price of $    •    per Subscription Receipt (the "Offering"). Each Subscription Receipt will entitle the holder thereof to receive, without payment of additional consideration or further action on the part of such holder, one common share ("Common Share") in our capital (an "Underlying Common Share") upon closing of the Acquisition (as defined herein).

The terms of the Offering, including the offering price for the Subscription Receipts, were determined by negotiation between us and Scotia Capital Inc. ("Scotia") and RBC Dominion Securities Inc. (collectively, the "Underwriters"). See "Plan of Distribution".

The gross proceeds from the sale of the Subscription Receipts (the "Escrowed Funds") will be held by Valiant Trust Company, as escrow agent (the "Escrow Agent"), and invested in short-term obligations of, or guaranteed by, the Government of Canada (or other approved investments). Upon satisfaction of the Escrow Condition (as defined herein) on or before 5:00 p.m. (Calgary time) on June 30, 2014, the Escrowed Funds and the interest earned thereon (less any amounts required to pay the Dividend Equivalent Amount (as defined herein) upon the issuance of the Underlying Common Shares, if applicable) will be released to us to enable us to convert these funds to Australian dollars and complete the Acquisition. On the closing of the Acquisition, each holder of Subscription Receipts will receive one Underlying Common Share for each Subscription Receipt held, without payment of additional consideration or further action on the part of such holder, and such holder will also be entitled to receive the Dividend Equivalent Amount, being an amount per Subscription Receipt equal to the amount per Common Share of any cash dividends for which record date(s) have occurred during the period commencing on the closing of the Offering through the date immediately preceding the date the Underlying Common Shares are issued pursuant to the Subscription Receipts. See "Details of the Offering".

On February 6, 2014, we entered into an agreement to acquire, through a scheme of arrangement under Australian law, all of the fully diluted shares of Aurora Oil & Gas Limited (TSX: AEF, ASX: AUT) ("Aurora") for total consideration of approximately $1.8 billion, plus assumed debt of approximately $744 million, for a total transaction value of approximately $2.6 billion (the "Acquisition"), as described in more detail under "Recent Developments — The Acquisition" and "About Aurora".

We will utilize the Escrowed Funds to pay a portion of the purchase price for the Acquisition. If: (i) the Acquisition is not completed by June 30, 2014; (ii) the Implementation Agreement (as defined herein) is terminated in accordance with its terms at any earlier time; or (iii) we have advised the Underwriters or announced to the public that we do not intend to proceed with the Acquisition (the time of occurrence of any such event being the "Termination Time"), holders of Subscription Receipts shall receive an amount equal to the full subscription price attributable to the Subscription Receipts and their pro rata entitlement to interest accrued on such amount up to and including the Termination Time. See "Details of the Offering".


Further particulars concerning the attributes of the Subscription Receipts are set out under "Details of the Offering" and further particulars concerning the attributes of the Common Shares are set out under "Description of Common Shares".

 
  Price to
the Public(1)
  Underwriters'
Fee(2)
  Net Proceeds to the
Corporation(3)
 

Per Subscription Receipt

  $   $   $  

Total(4)

  $   $   $  

Notes:

(1)
All dollar amounts in this short form prospectus are expressed in Canadian dollars, except where otherwise indicated.

(2)
The fee payable to the Underwriters is 4.0% of the gross proceeds of the Offering (the "Underwriters' Fee"). The Underwriters' Fee in respect of the Subscription Receipts is payable as to 50% upon the closing of the Offering and 50% upon the closing of the Acquisition. If closing of the Acquisition has not occurred by June 30, 2014, the Underwriters' Fee will be reduced to the amount payable upon closing of the Offering. See "Details of the Offering" and "Plan of Distribution".

(3)
Excluding interest accrued, if any, on the Escrowed Funds, and before deducting expenses of the Offering, estimated to be $3 million (exclusive of GST), which will be deducted from our general funds.

(4)
We have granted to the Underwriters an option (the "Over-allotment Option") to purchase up to an additional    •    Subscription Receipts at a price of $    •    per Subscription Receipt on the same terms and conditions as the Offering, exercisable from time to time, in whole or in part, for a period commencing at closing of the Offering and ending on the earlier of: (i) 30 days following closing of the Offering; and (ii) the Termination Time, to cover over-allotments, if any, and for market stabilization purposes. A purchaser who acquires Subscription Receipts forming part of the Underwriters' over-allocation position acquires those Subscription Receipts under this short form prospectus, regardless of whether the over-allocation position is ultimately filled through the exercise of the Over-allotment Option or secondary market purchases. If the Over-allotment Option is exercised in full, the total gross proceeds of the Offering, the Underwriters' Fee and the net proceeds to us (before deducting expenses of the Offering) will be $    •    , $    •    and $    •    , respectively. This short form prospectus also qualifies the distribution of the Subscription Receipts issuable upon exercise of the Over-allotment Option. See "Plan of Distribution" and the table below.

The following table sets forth the number of Subscription Receipts that may be offered by us pursuant to the Over-allotment Option.

Underwriters' Position   Maximum size or
number of securities held
  Exercise period   Exercise price

Over-allotment Option

  • Subscription Receipts   Commencing at closing of the Offering
and ending on the earlier of: (i) 30 days
following closing of the Offering; and
(ii) the Termination Time
  $• per Subscription Receipt

NEITHER THE U.S. SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THE SUBSCRIPTION RECEIPTS NOR PASSED UPON THE ACCURACY OR ADEQUACY OF THIS SHORT FORM PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENCE.

Your ability to enforce civil liabilities under United States federal securities laws may be affected adversely by the fact that we are formed under the laws of the Province of Alberta, that some of our officers and directors are residents of Canada or otherwise reside outside of the United States, that some or all of the Underwriters and experts named in this short form prospectus may be residents of Canada or otherwise reside outside of the United States, and that a substantial portion of our assets and the assets of said persons may be located outside the United States.

Mary Ellen Peters, one of our directors, resides outside of Canada. Ms. Peters has appointed Burnet, Duckworth & Palmer LLP, Suite 2400, 525 - 8th Avenue S.W., Calgary, Alberta, Canada, T2P 1G1, as her agent for service of process. In addition, all or some of the designated professionals of BDO Audit (WA) Pty Ltd., Aurora's external auditor and Ryder Scott Company, L.P., Aurora's independent qualified reserves evaluator are incorporated, continued or otherwise organized under the laws of a foreign jurisdiction or reside outside of Canada. BDO Audit (WA) Pty Ltd. has appointed BDO Canada LLP, Suite 600, 36 Toronto Street, Toronto, Ontario M5C 2C5 as its agent for service of process. Ryder Scott Company, L.P has appointed Ryder Scott Canada at Suite 600, 1015 4th St. S.W., Calgary, Alberta, Canada T2R 1J4 as its agent for service of process. It may not be possible for you to enforce judgments obtained in Canada against a person that resides outside of Canada, even if the party has appointed an agent for service of process. See "Enforcement of Judgments Against Foreign Persons or Companies".

We are permitted, under the multi-jurisdictional disclosure system adopted by the United States and Canada, to prepare this short form prospectus in accordance with the disclosure requirements of Canada. Prospective investors should be aware that such requirements are different from those of the United States. Our financial statements included or incorporated by reference in this short form prospectus have been prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP") (which, since January 1, 2011, have been consistent with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board) and are subject to Canadian auditing and auditor independence standards. Aurora's historical financial statements contained in this short form prospectus have been prepared in accordance with Australian Accounting


Standards ("AAS"), which include Australian equivalents to IFRS. Compliance with AAS ensures compliance with IFRS as issued by the International Accounting Standards Board. Canadian GAAP and AAS differs from generally accepted accounting principles in the United States ("U.S. GAAP"). Thus, these financial statements may not be comparable to financial statements of United States companies.

Data on oil and gas reserves contained in or incorporated by reference into this short form prospectus has been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States disclosure standards. See "Presentation of Financial and Oil and Gas Information".

Prospective investors should be aware that the acquisition of the Subscription Receipts described herein may have tax consequences both in the United States and Canada. Such consequences may not be fully described herein. See "Certain Canadian Federal Income Tax Considerations" and "Certain United States Federal Income Tax Considerations".

Our outstanding Common Shares are listed and posted for trading on the Toronto Stock Exchange (the "TSX") and the New York Stock Exchange ("NYSE") under the trading symbol "BTE". On February 5, 2014, the last trading day prior to the public announcement of the Offering, the closing price of the Common Shares on the TSX was $41.16 per Common Share and the closing price of the Common Shares on the NYSE was U.S.$37.16 per Common Share.

The Underwriters, as principals, conditionally offer the Subscription Receipts, subject to prior sale, if, as and when issued by us and accepted by the Underwriters in accordance with the conditions contained in the Underwriting Agreement (as defined herein). The Offering is subject to the approval of certain legal matters relating to Canadian law on our behalf by Burnet, Duckworth & Palmer LLP, Calgary, Alberta and on behalf of the Underwriters by McCarthy Tétrault LLP, Calgary, Alberta and to the approval of certain legal matters relating to United States law on our behalf by Paul, Weiss, Rifkind, Wharton & Garrison LLP, New York, New York and on behalf of the Underwriters by Vinson & Elkins LLP, Houston, Texas.

Subscriptions for Subscription Receipts will be received subject to rejection or allotment in whole or in part and the right is reserved to close the subscription books at any time without notice. The closing of the Offering is anticipated to occur on or about February 24, 2014 or such other date as may be agreed upon by us and the Underwriters (the "Closing Date"), but in any event not later than March 28, 2014. Except in certain limited circumstances: (i) Subscription Receipts and Underlying Common Shares will be registered and represented electronically through the non-certificated inventory of CDS Clearing and Depository Services Inc. ("CDS"); (ii) no certificates evidencing the Subscription Receipts and Underlying Common Shares will be issued; and (iii) purchasers of Subscription Receipts will receive only a customer confirmation from the Underwriter or other registered dealer who is a CDS participant and from or through whom a beneficial interest in the Subscription Receipts is purchased. See "Plan of Distribution".

Subject to applicable laws, the Underwriters may, in connection with the Offering, effect transactions which stabilize or maintain the market price of the Common Shares at levels other than those that might otherwise prevail on the open market in accordance with applicable market stabilization rules. Such transactions, if commenced, may be discontinued at any time. The Underwriters propose to offer the Subscription Receipts initially at the offering price specified above. After a reasonable effort has been made to sell all the Subscription Receipts at the price specified, the Underwriters may subsequently reduce the selling price to investors from time to time in order to sell any of the Subscription Receipts remaining unsold. Any such reduction will not affect the proceeds received by us. See "Plan of Distribution".

Scotia is a wholly-owned subsidiary of a Canadian chartered bank which has agreed to fully underwrite and commit to provide us with new senior secured credit facilities which will replace the Credit Facilities (as defined under the heading "Consolidated Capitalization") in connection with the Acquisition. Each of Scotia and RBC Dominion Securities Inc. are wholly-owned subsidiaries of Canadian chartered banks, which are lenders to our subsidiary, Baytex Energy Ltd. ("Baytex Energy") pursuant to the Credit Facilities. Scotia has also provided financial advice to us in connection with the Acquisition. Consequently, we may be considered to be a connected issuer to each of these Underwriters for the purposes of securities regulations in certain provinces. See "Relationship between Us and the Underwriters" and "Use of Proceeds".

There is currently no market through which the Subscription Receipts may be sold and there is no guarantee that an active trading market will develop. Accordingly, purchasers may not be able to resell the Subscription Receipts distributed under this short form prospectus. This may affect the pricing of the Subscription Receipts in the secondary market, the transparency and the availability of trading prices and the liquidity of the Subscription Receipts. See "Risk Factors".

An investment in the securities offered hereunder is speculative and involves a high degree of risk. The risk factors identified under the headings "Risk Factors" and "Forward-Looking Statements" in this short form prospectus, the Annual Information Form (as defined herein) and the Annual MD&A (as defined herein) should be carefully reviewed and evaluated by prospective subscribers before purchasing the securities being offered hereunder.

Our head office is located at Suite 2800, Centennial Place, East Tower, 520 - 3rd Avenue S.W., Calgary, Alberta, Canada, T2P 0R3 and our registered office is located at Suite 2400, 525 - 8th Avenue S.W., Calgary, Alberta, Canada, T2P 1G1.



TABLE OF CONTENTS

 
  Page

IMPORTANT NOTICE ABOUT INFORMATION IN THIS SHORT FORM PROSPECTUS

  2

PRESENTATION OF FINANCIAL AND OIL AND GAS INFORMATION

  2

SELECTED DEFINITIONS

  5

CONVERSIONS

  11

ABBREVIATIONS

  11

CONVENTIONS

  12

OIL AND GAS EQUIVALENCY

  12

NON-GAAP FINANCIAL MEASURES

  12

ENFORCEMENT OF JUDGMENTS AGAINST FOREIGN PERSONS OR COMPANIES

  13

DOCUMENTS INCORPORATED BY REFERENCE

  14

MARKETING MATERIALS

  15

FORWARD-LOOKING STATEMENTS

  15

WHERE YOU CAN FIND MORE INFORMATION

  17

EXCHANGE RATES

  18

RISK FACTORS

  19

SUMMARY DESCRIPTION OF OUR BUSINESS

  27

RECENT DEVELOPMENTS

  28

ABOUT AURORA

  35

USE OF PROCEEDS

  54

DESCRIPTION OF COMMON SHARES

  55

CONSOLIDATED CAPITALIZATION

  56

DETAILS OF THE OFFERING

  57

PLAN OF DISTRIBUTION

  60

RELATIONSHIP BETWEEN US AND CERTAIN UNDERWRITERS

  62

PRIOR SALES

  63

MARKET FOR SECURITIES

  63

DIVIDENDS TO SHAREHOLDERS

  64

CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

  65

CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

  70

LEGAL MATTERS

  74

INTEREST OF EXPERTS

  74

DOCUMENTS FILED AS PART OF THE REGISTRATION STATEMENT

  74

SCHEDULE "A" — FINANCIAL STATEMENTS OF AURORA

  A-1

SCHEDULE "B" — PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS OF BAYTEX

  B-1

1



IMPORTANT NOTICE ABOUT INFORMATION IN THIS SHORT FORM PROSPECTUS

        You should rely only on the information contained or incorporated by reference in this short form prospectus, and, if you reside in the United States, on the other information included in the registration statement of which this short form prospectus forms a part. We have not, and the Underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. You should assume that only the information appearing in this short form prospectus, as well as information we previously filed with the securities regulatory authority in each of the provinces of Canada and with the SEC that is incorporated by reference into this short form prospectus, is accurate as of the respective dates of the applicable documents. Our business, financial condition, results of operations and prospects may have changed since those dates.

        We are not, and the Underwriters are not, making an offer to sell these Subscription Receipts in any jurisdiction where the offer or sale is not permitted.


PRESENTATION OF FINANCIAL AND OIL AND GAS INFORMATION

        Unless indicated otherwise, our financial information in this short form prospectus, including the documents incorporated by reference herein, has been prepared in accordance with Canadian GAAP (which, since January 1, 2011, have been consistent with IFRS as issued by the International Accounting Standards Board). Aurora's historical financial statements contained in this short form prospectus have been prepared in accordance with AAS, which include Australian equivalents to the IFRS. Compliance with AAS ensures compliance with IFRS as issued by the International Accounting Standards Board. Canadian GAAP and AAS differ from U.S. GAAP and thus these financial statements may not be comparable to the financial statements of U.S. companies.

        The securities regulatory authorities in Canada have adopted NI 51-101 (as defined below), which imposes oil and gas disclosure standards for Canadian public issuers engaged in oil and gas activities. The recovery and resource estimates provided in this short form prospectus and in the documents incorporated by reference herein are estimates only. Actual reserves and contingent resources (and any volumes that may be reclassified as reserves) and future production from such reserves or contingent resources may be greater than or less than the estimates provided herein.

        The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of proved and probable reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery. The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions.

        All estimates of future revenue in this prospectus and in the documents incorporated herein by reference are, unless otherwise noted, after the deduction of royalties, development costs, production costs and well abandonment costs but before deduction of future income tax expenses and before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future net revenues contained in this prospectus and in the documents incorporated herein by reference do not represent the fair market value of the applicable reserves.

        There is no assurance that the forecast price and cost assumptions estimated will be attained and variances could be material. The recovery and reserves estimates described herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater or less than the estimates provided herein and in the documents incorporated herein by reference. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

        Unless otherwise stated, all of the reserves information contained herein and in the documents incorporated herein by reference, have been calculated and reported using assumptions and methodology guidelines outlined in accordance with the standards contained in the COGE Handbook, NI 51-101 and the

2


reserve definitions contained in the Canadian Securities Administrators Staff Notice 51-324. Numbers in the reserves tables and other oil and gas information contained in this prospectus may not add due to rounding.

        NI 51-101 permits oil and gas issuers, in their filings with Canadian securities regulatory authorities, to disclose not only proved, probable and possible reserves but also resources, and to disclose reserves and production on a gross basis before deducting royalties. Probable reserves, possible reserves and resources are of a higher risk and are less likely to be accurately estimated or recovered than proved reserves. We are permitted to disclose reserves in accordance with Canadian securities law requirements and the disclosure herein and in the documents incorporated by reference herein may include reserves designated as probable reserves, possible reserves and resources, as defined under Canadian standards.

        The SEC does not permit the inclusion of estimates of resources in reports filed with it by companies domiciled in the United States.

        The SEC definitions of proved, probable and possible reserves are different than NI 51-101; therefore, proved, probable and possible reserves disclosed herein and in the documents incorporated by reference into this short form prospectus may not be comparable to United States standards. The SEC currently requires United States oil and gas companies, in their filings with the SEC, to disclose only proved reserves after the deduction of royalties and interests of others but permits the optional disclosure of probable and possible reserves, as defined under SEC rules. The SEC does not allow proved and probable reserves to be aggregated except in the case of reserves determined using probabilistic methods, whereas NI 51-101 requires issuers to disclose aggregate proved and probable reserves.

        Moreover, as permitted by NI 51-101, we have determined and disclosed herein, and in the documents incorporated by reference, the net present value of future net revenue from our reserves and the reserves associated with the Aurora Assets (as defined herein) using only forecast prices and costs. The SEC requires that reserves and related future net revenue be estimated based on historical 12-month average prices, but permits the optional disclosure of revenue estimates based on different price and cost criteria, including standardized future prices or management's own forecasts.

        Additional information prepared in accordance with Accounting Standards Codification 932 "Extractive Activities — Oil & Gas" issued by the United States Financial Accounting Standards Board ("ASC 932") relating to our petroleum and natural gas reserves is set forth in the Supplemental Oil and Gas Disclosures (as defined herein), which is incorporated herein by reference.

        ASC 932 disclosure relating to Aurora's petroleum and natural gas reserves is not, and is not required to be; included in this short form prospectus.

        Certain documents incorporated by reference into this short form prospectus contain estimates of "contingent resources". The SEC would prohibit a United States oil and gas company from including an estimate of "contingent resources" in its filings with the SEC. "Contingent resources" are not, and should not be confused with, petroleum and natural gas reserves. "Contingent resources" are defined in the COGE Handbook (as defined herein) as: "those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage."

        The outstanding contingencies applicable to our disclosed contingent resources do not include economic contingencies. Economic contingent resources are those resources that are currently economically recoverable based on specific forecasts of commodity prices and costs.

        A range of contingent resources estimates (low, best and high) were prepared by the independent qualified reserves evaluators. A low estimate (C1) is considered to be a conservative estimate of the quantity of the resource that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. Those resources in the low estimate have the highest degree of certainty (a 90% confidence level) that the actual quantities recovered will equal or exceed the estimate. A best estimate (C2) is considered to be

3


the best estimate of the quantity of the resource that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources in the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate. A high estimate (C3) is considered to be an optimistic estimate of the quantity of the resource that will actually be recovered. It is unlikely that the actual remaining quantities of resource recovered will equal or exceed the high estimate. Those resources in the high estimate have a lower degree of certainty (a 10% confidence level) that the actual quantities recovered will equal or exceed the estimate.

        The primary contingencies which currently prevent the classification of our contingent resources as reserves consist of: preparation of firm development plans, including determination of the specific scope and timing of the project; project sanction; access to capital markets; stakeholder and regulatory approvals; access to required services and field development infrastructure; oil prices and price differentials between light, medium and heavy gravity crude oils; future drilling program and testing results; further reservoir delineation and studies; facility design work; limitations to development based on adverse topography or other surface restrictions; and the uncertainty regarding marketing and transportation of petroleum from development areas.

        There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that we will produce any portion of the volumes currently classified as contingent resources. The estimates of contingent resources involve implied assessment, based on certain estimates and assumptions, that the resource described exists in the quantities predicted or estimated and that the resource can be profitably produced in the future.

        Other principal differences between SEC oil and gas disclosure requirements and NI 51-101 include the following, some of which may be material:

        The NGLs referred to in this prospectus are reported on a combined basis with any condensate as required under NI 51-101.

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SELECTED DEFINITIONS

        Unless the context otherwise requires, all references in this short form prospectus to "Baytex", the "Corporation", "we", "us" or "our" means Baytex Energy Corp. and its consolidated subsidiaries, any partnership of which Baytex Energy Corp. and its subsidiaries are the partners and our significant equity investments and joint ventures.

In this short form prospectus, the following terms shall have the following meanings:

"2013 Acquired Assets" means the 100% operated WI in approximately 2,700 net acres in the Heard Ranch and Axle Tree blocks in South Texas, together with interests in 11 net producing wells as well as associated interests in field infrastructure and related assets, acquired by Aurora on March 29, 2013 with an effective date of March 1, 2013.

"2017 Aurora Notes" means the U.S.$365 million aggregate principal amount of 9.875% senior unsecured notes issued by a subsidiary of Aurora which are due February 15, 2017 and will be assumed by us in connection with the Acquisition.

"2020 Aurora Notes" means the U.S.$300 million aggregate principal amount of 7.50% senior unsecured notes issued by a subsidiary of Aurora which are due April 1, 2020 and will be assumed by us in connection with the Acquisition.

"2021 Debentures" means our U.S.$150 million 6.75% series B senior unsecured debentures due February 17, 2021 and issued pursuant to the Canadian Indenture.

"2022 Debentures" means our $300 million 6.625% series C senior unsecured debentures due July 19, 2022 and issued pursuant to the Canadian Indenture.

"ABCA" means the Business Corporations Act (Alberta), R.S.A. 2000, c. B-9, including the regulations promulgated thereunder, as amended from time to time.

"Acquisition" means the proposed acquisition by us of all of the issued and outstanding Aurora Shares pursuant to the Implementation Agreement.

"AMI" means area of mutual interest, a contractually defined area in which oil and gas companies hold oil and gas rights.

"Annual Information Form" has the meaning ascribed thereto under "Documents Incorporated by Reference".

"Annual Financial Statements" has the meaning ascribed thereto under "Documents Incorporated by Reference".

"Annual MD&A" has the meaning ascribed thereto under "Documents Incorporated by Reference".

"ASIC" means the Australian Securities and Investments Commission.

"ASX" means ASX Limited (ABN 98 008 624 691) and, where the context permits, the Australian Securities Exchange operated by ASX Limited.

"Aurora" means Aurora Oil & Gas Limited, a publicly traded corporation organized under the Corporations Act.

"Aurora 2012 Reserves Report" means the independent engineering evaluation of Aurora's oil and natural gas reserves dated January 30, 2013 prepared by Ryder Scott effective December 31, 2012, which is entitled "Aurora Oil & Gas Limited — Estimated Future Reserves and Income Attributable to Certain Leasehold Interests".

"Aurora 2013 Reserves Report" means the independent engineering evaluation of Aurora's oil and natural gas reserves dated January 31, 2014 prepared by Ryder Scott effective December 31, 2013, which is entitled "Aurora Oil & Gas Limited — Estimated Future Reserves and Income Attributable to Certain Leasehold Interests".

"Aurora Assets" means those oil, petroleum and natural gas properties and related assets of Aurora described in more detail under "Recent Developments — The Acquisition" and "About Aurora".

"Aurora Board" means the board of directors of Aurora.

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"Aurora Notes" means collectively, the 2017 Aurora Notes and the 2020 Aurora Notes.

"Aurora Options" has the meaning ascribed thereto under "Recent Developments — The Acquisition".

"Aurora Performance Rights" has the meaning ascribed thereto under "Recent Developments — The Acquisition".

"Aurora Reserves Reports" means the Aurora 2012 Reserves Report and the Aurora 2013 Reserves Report.

"Aurora Shareholders" means the holders of all of the issued and outstanding Aurora Shares.

"Aurora Shares" means the ordinary shares in the capital of Aurora, as presently constituted.

"Australian Court" means the Federal Court of Australia (Western Australian Registry) or any other court of competent jurisdiction under the Corporations Act (as agreed by the parties to the Implementation Agreement in writing).

"Baytex Energy" means Baytex Energy Ltd., a corporation amalgamated under the ABCA and our wholly-owned subsidiary.

"Board of Directors" means our board of directors.

"Canadian Indenture" means the amended and restated trust indenture which provides for the issuance of Debt Securities in Canada among us, as issuer, Baytex Energy and certain of our other subsidiaries, as guarantors, and Valiant Trust Company, as trustee, dated January 1, 2011, as supplemented by a supplemental trust indentures dated February 17, 2011, February 18, 2011, July 19, 2012 and December 19, 2012. The 2021 Debentures and the 2022 Debentures were issued under the Canadian Indenture.

"CDS" means CDS Clearing and Depository Services Inc.

"COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook.

"Common Shares" means the common shares in our capital.

"Common Share Rights Incentive Plan" means our Common Share Rights Incentive Plan, as described in the Information Circular under "Executive Compensation — Common Share Rights Incentive Plan".

"Corporations Act" means the Australian Corporations Act 2001 (Cth).

"Credit Facilities" has the meaning ascribed thereto under "Consolidated Capitalization".

"Debentures" means, collectively, the 2021 Debentures and the 2022 Debentures.

"Debt Securities" means our senior or subordinated debt securities.

"Developed Non-Producing Reserves" are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

"Developed Producing Reserves" are those reserves that are expected to be recovered from completion in intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

"Developed Reserves" are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

"development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (a) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground draining, road building, and relocating public roads, gas lines and power lines, pumping equipment and wellhead assembly; (b) drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of

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platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly; (c) acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and (d) provide improved recovery systems.

"development well" means a well drilled inside the established limits of an oil and gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

"Dividend Equivalent Amount" means an amount per Subscription Receipt equal to the amount per Common Share of any cash dividends for which record date(s) have occurred during the period beginning on the closing date of the Offering to the date immediately preceding the date the Underlying Common Shares are issued pursuant to the Subscription Receipts.

"Eagle Ford" means the Eagle Ford shale trend in South Texas, which produces oil, natural gas, natural gas liquids and condensate.

"Elixir" means Elixir Petroleum Limited.

"EDGAR" means the Electronic Data Gathering, Analysis and Retrieval System established by the SEC.

"Effective Date" in relation to the Acquisition means the date on which the Acquisition becomes effective.

"Escrow Agent" means Valiant Trust Company, which is deemed an "Acceptable Institution" under the guidelines of the Investment Industry Regulatory Organization of Canada and the Canadian Investor Protection Fund, in its capacity as escrow agent pursuant to the Subscription Receipt Agreement.

"Escrow Condition" has the meaning ascribed thereto under "Details of the Offering".

"Escrowed Funds" means the gross proceeds from the sale of the Subscription Receipts.

"Exchange Act" means the United States Securities Exchange Act of 1934, as amended.

"Existing Target Facility" means the existing U.S.$300 million senior secured credit facility established under the credit agreement dated as of November 7, 2011 among Aurora USA Oil & Gas, Inc., Aurora, UBS AG, Stamford Branch, as administrative agent and the financial institutions party thereto, as amended and supplemented.

"exploration costs" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (a) costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies; (b) costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records; (c) dry hole contributions and bottom hole contributions; (d) costs of drilling and equipping exploratory wells; and (e) costs of drilling exploratory type stratigraphic test wells.

"exploratory well" means a well that is not a development well, a service well or a stratigraphic test well.

"Final Order" means the order issued by the Australian Court pursuant to section 411(4)(b) of the Corporations Act approving the Acquisition.

"forecast prices and costs" means in relation to an issuer, prices and costs that are: (a) generally acceptable as being a reasonable outlook of the future; and (b) if and only to the extent that, there are fixed or presently determinable future prices or costs to which an issuer is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

"Flour Bluff Field" means the Flour Bluff Gas Field located near Corpus Christi, Texas.

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"gross" means: (a) in relation to an issuer's interest in production or reserves, its "company gross reserves", which are its working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the issuer; (b) in relation to wells, the total number of wells in which an issuer has an interest; and (c) in relation to properties, the total area of properties in which an issuer has an interest.

"Implementation Agreement" means the Implementation Agreement between us and Aurora dated effective February 6, 2014 pursuant to which we have agreed to acquire all of the issued and outstanding Aurora Shares, as more particularly described under "Recent Developments — The Acquisition".

"HSR Act" means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the rules and regulations thereunder.

"Incentive Plan" means our Common Share Rights Incentive Plan, as described in the Information Circular under "Executive Compensation — Common Share Rights Incentive Plan".

"Information Circular" has the meaning ascribed thereto under "Documents Incorporated by Reference".

"Interim Financial Statements" has the meaning ascribed thereto under "Documents Incorporated by Reference".

"Interim MD&A" has the meaning ascribed thereto under "Documents Incorporated by Reference".

"Ipanema" means the Ipanema AMI in the Sugarkane Field.

"Longhorn" means the Longhorn AMI in the Sugarkane Field.

"JOA" means joint operating agreement among co-owners of WIs in a designated field, AMI, unit or lease.

"Marathon" means Marathon Oil EF LLC, a wholly-owned subsidiary of Marathon Oil Corporation.

"net" means: (a) in relation to an issuer's interest in production or reserves its working interest (operating or non-operating) share after deduction of royalty obligations, plus its royalty interests in production or reserves; (b) in relation to an issuer's interest in wells, the number of wells obtained by aggregating the issuer's working interest in each of its gross wells; and (c) in relation to an issuer's interest in a property, the total area in which the issuer has an interest multiplied by the working interest owned by the issuer.

"New Credit Facilities" has the meaning ascribed thereto under See "Recent Developments — New Credit Facilities".

"NI 51-101" means National Instrument 51-101 — Standards of Disclosure for Oil and Gas Activities.

"Notes" means the unsecured subordinated promissory notes issued by Baytex Energy and certain other Operating Entities to us.

"NYSE" means the New York Stock Exchange.

"Operating Entities" means our direct and indirect wholly-owned subsidiaries that are actively involved in the acquisition, production, processing, transportation and marketing of crude oil, natural gas liquids and natural gas, being Baytex Energy, Baytex Energy Partnership and Baytex Energy USA Ltd., and "Operating Entity" means any one of them, as applicable.

"Participant" means a participant in the depository service of CDS.

"Possible Reserves" are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

"Probable Reserves" are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

"Proved Reserves" are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

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"Reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

"Ryder Scott" means Ryder Scott Company, L.P, independent petroleum consultants of Houston, Texas.

"service well" means a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt water disposal, water supply for injection, observation or injection for combustion.

"Scotia" means Scotia Capital Inc.

"SEC" means the U.S. Securities and Exchange Commission.

"SEDAR" means the System for Electronic Document Analysis and Retrieval established by the provincial securities regulatory authorities in Canada.

"Share Award Incentive Plan" means our Share Award Incentive Plan, as described in the Information Circular under "Executive Compensation — Share Award Incentive Plan".

"Shareholders" mean the holders from time to time of Common Shares.

"Sproule" means Sproule Associates Limited, independent petroleum consultants of Calgary, Alberta, Canada.

"Sproule Report" means the independent evaluation of our oil and natural gas reserves prepared by Sproule dated March 11, 2013 and effective December 31, 2012 entitled "Evaluation of the P&NG Reserves of Baytex Energy Corp. (As of December 31, 2012)".

"Subscription Receipt Agreement" means the agreement to be dated the date of closing of the Offering among us, Scotia and the Escrow Agent governing the terms of the Subscription Receipts.

"Subscription Receipt Beneficial Owner" means a purchaser acquiring a beneficial interest in the Subscription Receipts.

"Subscription Receipt Certificates" means the certificates representing the Subscription Receipts.

"Subscription Receipts" means the subscription receipts offered hereby.

"subsidiary" has the meaning ascribed thereto in the ABCA and, for greater certainty, includes all corporations, partnerships and trusts owned, controlled or directed, directly or indirectly, by us.

"Sugarkane Field" means the Sugarkane natural gas and condensate field within the Eagle Ford and includes the two contiguous fields designated by the Railroad Commission of Texas as the Sugarkane and Eagleville Fields.

"Supplemental Oil and Gas Disclosures" has the meaning ascribed thereto under "Documents Incorporated by Reference".

"Tax Act" means the Income Tax Act (Canada), as amended, including the regulations promulgated thereunder.

"Termination Time" has the meaning ascribed thereto under "Details of the Offering".

"TSX" means the Toronto Stock Exchange.

"Underlying Common Shares" means the Common Shares issuable pursuant to the terms of the Subscription Receipts.

"Underwriters" means, collectively, Scotia and RBC Dominion Securities Inc.

"Underwriting Agreement" means the agreement to be entered into among us and the Underwriters in respect of the Offering.

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"Undeveloped Reserves" are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to sub-divide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

"United States" or "U.S." means the United States, as defined in Rule 902(l) under Regulation S under the United States Securities Act of 1933, as amended.

"U.S. GAAP" means United States generally accepted accounting principles.

"WI" means working interest, an interest in an oil and gas lease that gives the owner the right to drill and produce oil and gas on the leased acreage.

Words importing the singular number only include the plural, and vice versa, and words importing any gender include all genders.

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CONVERSIONS

        The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units).

To Convert From
 
To
  Multiply By  

Mcf

  cubic metres     28.174  

cubic metres

  cubic feet     35.494  

Bbls

  cubic metres     0.159  

cubic metres

  Bbls     6.289  

Feet

  Metres     0.305  

Metres

  Feet     3.281  

Miles

  kilometres     1.609  

Kilometres

  Miles     0.621  

Acres

  hectares     0.405  

Hectares

  Acres     2.471  

Gigajoules

  MMbtu     0.950  

MMbtu

  gigajoules     1.0526  


ABBREVIATIONS

Oil and Natural Gas Liquids
 
Natural Gas

Bbl

  barrel   Mcf   thousand cubic feet

Bbls

  barrels   MMcf   million cubic feet

Bbls/d

  barrels per day   Bcf   billion cubic feet

Mbbls

  thousand barrels   Mcf/d   thousand cubic feet per day

MMbbls

  million barrels   MMcf/d   million cubic feet per day

Mstb

  thousand stock tank barrels of oil   MMbtu   million British Thermal Units

NGLs

  natural gas liquids   GJ   Gigajoule

 

Other
   

AECO

  the natural gas storage facility located at Suffield, Alberta, connected to TransCanada's Alberta System

API

  American Petroleum Institute

°API

  an indication of the specific gravity of crude oil measured on the API gravity scale

BOE or Boe

  barrel or barrels of oil equivalent, using the conversion factor of six Mcf of natural gas being equivalent to one barrel of oil

Boe/d

  barrels of oil equivalent per day

m3

  cubic metres

MBoe

  thousand barrels of oil equivalent

Mcfe

  thousand cubic feet of gas equivalent, using the conversion factor of 1 barrel of oil being equivalent to 6 Mcf of natural gas

MMBoe

  million barrels of oil equivalent

RLI

  reserve life index

WTI

  West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for the crude oil standard grade

WCS

  Western Canadian Select heavy oil reference price

$000s

  thousands of dollars

$MM

  millions of dollars

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CONVENTIONS

        Certain terms used herein are defined in the "Selected Definitions". Certain other terms used herein but not defined herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101. All financial information herein has been presented in Canadian dollars in accordance with GAAP, except where otherwise indicated. References to "$" or "CDN$" are to Canadian dollars, references to "U.S.$" are to United States dollars and references to "A$" are to Australian dollars.


OIL AND GAS EQUIVALENCY

        The term "Boe" means a barrel of oil equivalent on the basis of 6 Mcf of natural gas to 1 Bbl of oil. The term "Mcfe" means a thousand cubic feet of gas equivalent on the basis of 1 Bbl of oil to 6 Mcf of natural gas. Boes and Mcfes may be misleading, particularly if used in isolation. A Boe conversion ratio of 6 Mcf: 1 Bbl or an Mcfe conversion ratio of 1 Bbl: 6 Mcf a is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf: 1Bbl, utilizing a conversion ratio at 6 Mcf: 1 Bbl may be misleading as an indication of value.


NON-GAAP FINANCIAL MEASURES

        In this short form prospectus and the documents incorporated by reference herein, we refer to certain financial measures (such as funds from operations, payout ratio, total monetary debt, net debt and operating netback) which do not have any standardized meaning prescribed by Canadian GAAP and are considered non-GAAP measures. While funds from operations, payout ratio and operating netback are commonly used in the oil and gas industry, our determination of these measures may not be comparable with calculations of similar measures for other issuers.

Funds from Operations

        We define funds from operations as cash flow from operating activities adjusted for financing costs, changes in non-cash operating working capital and other operating items. We believe that this measure assists in providing a more complete understanding of certain aspects of our results of operations and financial performance, including our ability to generate the cash flow necessary to fund future dividends to shareholders and capital investments.

        Funds from operations as used herein, as it relates to Aurora, means funds provided by operating activities before changes in non-cash working capital. We consider it a key measure as it demonstrates the ability of the business to generate the cash flow necessary to fund future growth through capital investment.

        However, funds from operations should not be construed as an alternative to traditional performance measures determined in accordance with Canadian GAAP or U.S. GAAP, such as cash flow from operating activities and net income. Please refer to our most recent management's discussion and analysis of financial condition and results of operations, which is incorporated by reference herein, for a reconciliation of funds from operations to cash flow from operating activities.

Payout Ratio

        We define payout ratio as cash dividends (net of participation in our dividend reinvestment plan) divided by funds from operations. We believe that this measure assists in providing a more complete understanding of certain aspects of our results of operations and financial performance, including our ability to generate the cash flow necessary to fund future dividends to shareholders and capital investments.

Total Monetary Debt and Net Debt

        We define total monetary debt as the sum of monetary working capital, being current assets less current liabilities (excluding non-cash items such as unrealized gains or losses on financial derivatives), the principal amount of long-term debt and long-term bank loan. We believe that this measure assists in providing a more complete understanding of our cash liabilities.

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Operating Netback

        We define operating netback as product revenue less royalties, production and operating expenses and transportation expenses divided by barrels of oil equivalent sales volume for the applicable period. We believe that this measure assists in characterizing our ability to generate cash margin on a unit of production basis. Aurora defines operating netback as revenue from production less royalties, production taxes, gathering and transportation costs, facility maintenance and operated costs calculated on a Boe basis.


ENFORCEMENT OF JUDGMENTS AGAINST FOREIGN PERSONS OR COMPANIES

        Mary Ellen Peters, one of our directors, resides outside of Canada. Ms. Peters has appointed Burnet, Duckworth & Palmer LLP, Suite 2400, 525 - 8th Avenue S.W., Calgary, Alberta, Canada, T2P 1G1, as her agent for service of process. In addition, all or some of the designated professionals of BDO Audit (WA) Pty Ltd., Aurora's external auditor and Ryder Scott Company, L.P., Aurora's independent qualified reserves evaluator are incorporated, continued or otherwise organized under the laws of a foreign jurisdiction or reside outside of Canada. BDO Audit (WA) Pty Ltd. has appointed BDO Canada LLP, Suite 600, 36 Toronto Street, Toronto, Ontario M5C 2C5 as its agent for service of process. Ryder Scott Company, L.P has appointed Ryder Scott Canada at Suite 600, 1015 4th St. S.W., Calgary, Alberta, Canada T2R 1J4 as its agent for service of process. It may not be possible for you to enforce judgments obtained in Canada against a person that resides outside of Canada, even if the party has appointed an agent for service of process.

        Purchasers are advised that it may not be possible for investors to enforce judgments obtained in Canada against a person that resides outside of Canada, even if the party has appointed an agent for service of process.

        We are a corporation formed under, and governed by, the laws of the Province of Alberta, Canada and our principal place of business is in Canada. Substantially all of our directors and officers and the experts named in this short form short form prospectus are residents of Canada or otherwise reside outside of the United States, and all or a substantial portion of their assets and our assets are located outside the United States. As a result, it may be difficult for investors in the United States to effect service of process within the United States upon those directors, officers and experts who are not residents of the United States or to enforce against them judgments of United States courts based upon civil liability under the United States federal securities laws or the securities laws of any state within the United States.

        We have been advised by our Canadian counsel, Burnet, Duckworth & Palmer LLP, that there is substantial doubt whether an action could be brought in Canada in the first instance on the basis of liability predicated solely upon United States federal securities laws. We have appointed Baytex Energy USA Ltd., 600 - 17th Street, Suite 1600 S, Denver, CO 80202, as our agent in the United States upon which service of process against us may be made in any action based on this short form prospectus.

        We filed with the SEC, concurrently with our registration statement on Form F-10 of which this short form prospectus forms a part, an appointment of agent for service of process on Form F-X. Under the Form F-X, we appointed Baytex Energy USA Ltd. as our agent for service of process in the United States in connection with any investigation or administrative proceeding conducted by the SEC, and any civil suit or action brought against or involving us in a United States court arising out of or related to or concerning the offering of debt securities under this short form prospectus.

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DOCUMENTS INCORPORATED BY REFERENCE

        Information has been incorporated, or deemed to be incorporated by reference, into this short form prospectus from documents filed with securities commissions or similar authorities in Canada and with the SEC in the United States. Copies of the documents incorporated herein by reference may be obtained on request without charge from our Corporate Secretary at Suite 2800, Centennial Place, East Tower, 520 - 3rd Avenue S.W., Calgary, Alberta, Canada, T2P 0R3, Telephone: (587) 952-3000. In addition, copies of the documents incorporated herein by reference may be obtained from the securities commissions or similar authorities in Canada through the SEDAR website at www.sedar.com and in the United States through EDGAR at the SEC's website at www.sec.gov.

        Under applicable securities laws in Canada and the United States, the Canadian securities commissions and the SEC allow us to incorporate by reference certain information that we file with them, which means that we can disclose important information to you by referring you to those documents. Information that is incorporated by reference is an important part of this short form prospectus. The following documents filed with securities commissions or similar authorities in each of the provinces of Canada and with the SEC in the United States are incorporated by reference into this short form prospectus:

        Any documents of the type described in Section 11.1 of Form 44-101F1 — Short Form Prospectus promulgated under National Instrument 44-101 — Short Form Prospectus Distributions (including, without limitation, any annual information form, audited consolidated financial statements, together with the auditor's report thereon, and related management's discussion and analysis, information circular, material change reports, marketing materials, business acquisition reports and condensed interim unaudited consolidated financial statements and related management's discussion and analysis) subsequently filed by us with the securities commissions or similar regulatory authorities in the relevant provinces of Canada after the date of this short form prospectus and prior to the termination of the Offering shall be deemed to be incorporated by reference herein in this short form prospectus. In addition, any similar documents filed by us with the SEC in our periodic reports on Form 6-K or annual reports on Form 40-F and any other documents filed with or furnished to the SEC pursuant to Section 13(a), 13(c) or 15(d) of the Exchange Act, in each case after the date of this short form prospectus and prior to the termination of the Offering, shall be deemed to be incorporated by reference into

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this short form prospectus and the registration statement of which this short form prospectus forms a part. To the extent that any document or information incorporated by reference into this short form prospectus is included in a report that is filed with or furnished to the SEC on Form 40-F, 20-F, 10-K, 10-Q, 8-K or 6-K (or any respective successor form), such document or information shall also be deemed to be incorporated by reference as an exhibit to the registration statement of which this short form prospectus forms a part.

        Any statement contained in this short form prospectus or in a document (or part of a document) incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded to the extent that a statement contained in this short form prospectus or in a document (or part of a document) incorporated or deemed to be incorporated by reference herein (or in any other subsequently filed document which also is or is deemed to be incorporated by reference) modifies or supersedes that statement. The modifying or superseding statement need not state that it has modified or superseded a prior statement or include any other information set forth in the document that it modifies or supersedes. The making of a modifying or superseding statement is not to be deemed an admission for any purposes that the modified or superseded statement, when made, constituted a misrepresentation, an untrue statement of a material fact or an omission to state a material fact that is required to be stated or that is necessary to make a statement not misleading in light of the circumstances in which it was made. Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to be incorporated by reference into or to constitute a part of this short form prospectus.


MARKETING MATERIALS

        Any "template version" of any "marketing materials" (as such terms are defined under applicable Canadian securities laws) that are utilized by the Underwriters in connection with the Offering are not part of this short form prospectus to the extent that the contents of the template version of the marketing materials have been modified or superseded by a statement contained in this short form prospectus. Any template version of any marketing material that has been, or will be, filed on SEDAR before the termination of the distribution under the Offering (including any amendments to, or an amended version of, any template version of any marketing materials) is deemed to be incorporated into this short form prospectus.


FORWARD-LOOKING STATEMENTS

        In the interest of providing shareholders and potential investors with information regarding Baytex and Aurora, including management's assessment of future plans and operations, certain statements made in this short form prospectus and the documents incorporated by reference are "forward-looking statements" within the meaning of Section 27A of the United States Securities Act of 1933, as amended, Section 2 of the Exchange Act and "forward looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this short form prospectus speak only as of the date thereof and are expressly qualified by this cautionary statement.

        Specifically, this short form prospectus contains forward-looking statements relating to, but not limited to: our plans to increase our dividend upon completion of the Acquisition; the anticipated benefits from the Acquisition, including our belief that the Acquisition will be an excellent fit with our business model and will provide shareholders with exposure to a low-risk, repeatable, high-return asset with leading capital efficiencies; our beliefs that the assets acquired as part of the Acquisition will provide material production, long-term growth and high quality reserves with upside potential; our expectations and anticipated timing of receipt of positive cash flow from the acquired assets; our expectations regarding the effect of well downspacing, improving completion techniques and new development targets on the reserves potential of the acquired assets; forecasted production and production mix following completion of the Acquisition; anticipated effect of the Acquisition on us, including in respect of reserves, production and funds from operations; Aurora's forecasted production and production growth for 2014; pro forma production, reserves, funds from operations, operating netbacks, liquidity, bank debt, working capital and debt to funds from our operation following completion of the Acquisition; average estimated reserves per well from Aurora's wells on the acquired assets; accretive, operating

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and financial metrics and the strategic rationale for the Acquisition; drilling plans, including number of wells planned for 2014 on the acquired assets; expectations regarding the Acquisition and the Offering, including anticipated timing of mailing of the scheme booklet to Aurora shareholders, timing of completion of the Acquisition and the Offering, and approvals required for the Acquisition; and the terms of the Subscription Receipts. In addition, information and statements relating to resources and reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the resources or reserves, as applicable, described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future. Cash dividends on our Common Shares are paid at the discretion of our Board of Directors and can fluctuate. In establishing the level of cash dividends, our Board of Directors considers all factors that it deems relevant, including, without limitation, the outlook for commodity prices, our operational execution, the amount of funds from operations and capital expenditures and our prevailing financial circumstances at the time. Although we believe that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because we can give no assurance that they will prove to be correct. See "Special Notes to Reader — Forward-Looking Statements" in the Annual Information Form, which is incorporated by reference into this short form prospectus and which is available on the SEDAR website at www.sedar.com and through EDGAR at the SEC's website at www.sec.gov for further information with respect to forward-looking statements.

        The forward-looking statements contained in this short form prospectus are based on certain key assumptions regarding, among other things: the receipt of regulatory, shareholder and other approvals for the Acquisition; our ability to execute and realize on the anticipated benefits of the Acquisition; timing of closing and regulatory approvals for the Offering; petroleum and natural gas prices and pricing differentials between light, medium and heavy gravity crude oil; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; the availability and cost of labour and other industry services; the amount of future cash dividends that we intend to pay; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties and the acquired assets in the manner currently contemplated; current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated; and the estimates of our production and reserves volumes and Aurora's production and reserve volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects. You are cautioned that such assumptions, although considered reasonable by us at the time of preparation, may prove to be incorrect.

        Actual results achieved during the forecast period will vary from the information provided in this short form prospectus and in the documents incorporated by reference herein, respectively, as a result of numerous known and unknown risks and uncertainties and other factors which are discussed in this short form prospectus and in the documents incorporated herein by reference. Such factors include, but are not limited to: the Acquisition may not be completed on the terms contemplated or at all; failure to realize the anticipated benefits of the Acquisition; closing of the Offering and/or the Acquisition could be delayed or not completed if we are not able to obtain the necessary stock exchange, shareholder and regulatory approvals or any other approvals required for completion or, unless waived, some other condition to closing is not satisfied; declines in oil and natural gas prices; variations in interest rates and foreign exchange rates; uncertainties in the credit markets; the cost of borrowing; refinancing risk for existing debt and debt service costs; access to external sources of capital; risks associated with our hedging activities; third party credit risk; risks associated with the exploitation of our properties and our ability to acquire reserves; government regulation and changes in governmental legislation; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum and natural gas reserves; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with properties operated by third parties; risks associated with delays in business operations; risks associated with the marketing of our petroleum and natural gas production; risks associated with large projects or expansion of our activities; the failure to realize anticipated benefits of acquisitions and dispositions or to manage growth; changes in climate change laws and other environmental, health and safety regulations; competition in the oil and gas industry for, among other things, acquisitions of reserves, undeveloped lands, skilled personnel and drilling and related equipment; the application of accounting policies; the activities of our Operating Entities and their key personnel; depletion of

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our reserves; risks associated with securing and maintaining title to our properties; seasonality; our permitted investments; risks associated with the ownership of our securities, including the discretionary nature of dividend payments and changes in market-based factors; risks for United States and other non-resident shareholders; closing of the Offering and/or the Acquisition could be delayed or not completed if we are not able to obtain the necessary stock exchange approvals or any other approvals required for completion or, unless waived, some other condition to the closing is not satisfied; and other factors, many of which are beyond our control. Statements relating to "reserves" and "contingent resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and contingent resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.

        Readers are cautioned that the foregoing list of risk factors is not exhaustive. New risk factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. Further information regarding these factors may be found under the heading "Risk Factors" in this short form prospectus and under the heading "Risk Factors" in the Annual Information Form.

        We do not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law. The forward-looking statements contained in this short form prospectus and in certain documents incorporated by reference into this short form prospectus are expressly qualified by this cautionary statement. Information on, or connected to our website, even if referred to in a document incorporated by reference, does not constitute part of this short form prospectus.


WHERE YOU CAN FIND MORE INFORMATION

        We have filed with the SEC a registration statement on Form F-10 relating to the Subscription Receipts, of which this short form prospectus forms a part. This short form prospectus does not contain all of the information contained in the registration statement, certain items of which are contained in the exhibits to the registration statement as permitted by the rules and regulations of the SEC. For further information about us and the Subscription Receipts, please refer to the registration statement.

        We are subject to the information requirements of the Exchange Act and applicable Canadian securities legislation, and in accordance with those requirements, we file and furnish reports and other information with the SEC and with the securities regulatory authorities of the provinces of Canada. Under the multi-jurisdictional disclosure system adopted by the United States and Canada, we generally may prepare these reports and other information in accordance with the disclosure requirements of Canada. These requirements are different from those of the United States. As a foreign private issuer, we are exempt from the rules under the Exchange Act prescribing the furnishing and content of proxy statements and our officers and directors and our Shareholders holding 10% or more of our Common Shares are exempt from the beneficial ownership reporting and short-swing profit recovery provisions contained in Section 16 of the Exchange Act.

        The reports and other information filed and furnished by us with the SEC may be read and copied at the SEC's public reference room at 100 F Street, N.E., Washington, D.C. 20549. Copies of the same documents can also be obtained from the public reference room of the SEC in Washington by paying a fee. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. The SEC also maintains a website at www.sec.gov that makes available reports and other information that we file electronically with it, including the registration statement that we have filed with respect to this Offering.

        Copies of reports, statements and other information that we file with the Canadian provincial securities regulatory authorities are electronically available through the SEDAR website at www.sedar.com.

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EXCHANGE RATES

        The financial statements incorporated by reference herein are in Canadian dollars, unless otherwise indicated. The following tables set forth: (i) the rates of exchange for Canadian dollars, expressed in United States dollars in effect at the end of each of the periods indicated; and (ii) the average of exchange rates in effect on the last day of each month during such period, in each case based on the noon buying rate in the City of New York for cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York for United States Dollars.


United States Dollars

 
  Nine Months Ended    
   
   
 
 
  Year Ended December 31,  
 
  September 30,
2013
 
 
  2013   2012   2011  

Average for the Period(1)

  $ 0.9769   $ 0.9708   $ 1.0008   $ 1.0151  

End of Period

  $ 0.9723   $ 0.9402   $ 1.0051   $ 0.9833  

Note:

(1)
Determined by averaging the rates on the last business day of each month during the respective period.

        On February 5, 2014, the rate of exchange for the Canadian dollar, expressed in United States dollars, based on the Bank of Canada noon rate for United States dollars, was CDN.$1.00=U.S.$0.9008.

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RISK FACTORS

        An investment in the Subscription Receipts, including the Underlying Common Shares, is subject to a number of risks. In addition to the risk factors set forth below, additional risk factors relating to our business are discussed in our Annual Information Form, our Annual MD&A and certain other documents incorporated by reference or deemed to be incorporated by reference herein, which risk factors are incorporated herein by reference. Prospective purchasers of the Subscription Receipts should consider carefully the risk factors set forth below, as well as the other information contained in and incorporated by reference in this short form prospectus before purchasing the Subscription Receipts. If any event arising from these risks occurs, our business, prospects, financial condition, results of operations or cash flows, or your investment in the Subscription Receipts could be materially adversely affected.

Forward Looking Statements May Prove Inaccurate

        Purchasers are cautioned not to place undue reliance on forward looking statements. By their nature, forward looking statements involve numerous assumptions, known and unknown risks and uncertainties, of both a general and specific nature, that could cause actual results to differ materially from those suggested by the forward looking statements or contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate.

Risks Relating to the Offering

There is currently no public market for the Subscription Receipts and there can be no assurance that an active trading market will develop.

        There is currently no market through which the Subscription Receipts may be sold and there is no guarantee that an active trading market will develop. Accordingly, purchasers may not be able to resell the Subscription Receipts distributed under this short form prospectus. This may affect the pricing of the Subscription Receipts in the secondary market, the transparency and the availability of trading prices and the liquidity of the securities. There can be no assurance that an active trading market will develop for the Subscription Receipts after the Offering, or if developed, that such a market will be sustained at the price level of the Offering.

If the Escrow Condition is not satisfied on or prior to the Termination Time, the Subscription Receipts will not be exchanged into Common Shares.

        The Subscription Receipts will be exchanged for Common Shares upon the satisfaction of the Escrow Condition. We may, in our sole discretion, waive certain closing conditions in our favor in the Implementation Agreement or agree with Aurora to amend the Implementation Agreement and consummate the Acquisition on terms that may be substantially different from those contemplated in this short form prospectus. Other events, many of which are beyond our control including the acceptance of a superior proposal by Aurora, could result in termination of the Implementation Agreement prior to the Termination Time. If the Acquisition is not completed by the Termination Time, or if we advise the Underwriters or announce to the public that we do not intend to proceed with the Acquisition, or if the Implementation Agreement has been terminated in accordance with its terms, holders of Subscription Receipts shall receive an amount equal to the full subscription price attributable to the Subscription Receipts and their pro rata entitlement to interest accrued on such amount. As a result, the expected benefits of the Acquisition may not be fully realized. See "Recent Developments — The Acquisition" and "About Aurora". There can be no assurance that the Escrow Condition will be satisfied on or prior to the Termination Time. Until the Escrow Condition is satisfied and the Common Shares are delivered pursuant to the Subscription Receipt Agreement, holders of Subscription Receipts have the rights described under "Details of the Offering".

There can be no assurance that the Acquisition will close after the conditions for the release of the Escrowed Funds have been satisfied.

        The Escrowed Funds will be held by the Escrow Agent, and invested in short-term obligations of, or guaranteed by, the Government of Canada (or other approved investments) pending delivery by us to the

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Underwriters of a certificate on the third Business Day prior to the anticipated Effective Date to the effect that the Escrow Condition has been satisfied. Upon satisfaction of the Escrow Condition prior to the Termination Time, the Escrowed Funds will be released to us to enable us to convert these funds to Australian dollars and complete the Acquisition. Although we have been advised by our Australian counsel that the Acquisition is unconditional once the Final Order has been filed with the ASIC, there is a possibility that the Acquisition is not completed by the Termination Time. As a result, the expected benefits of the Acquisition may not be fully realized. See "Recent Developments — The Acquisition" and "About Aurora".

Risks Relating to the Acquisition

We may not complete the Acquisition on the terms negotiated or at all.

        The Acquisition is subject to satisfaction of the conditions described herein and normal commercial risk that the Acquisition may not be completed on the terms negotiated or at all. This could result from events which are beyond our control, including the acceptance of a superior proposal by Aurora. If closing of the Acquisition does not take place by the Termination Time, we will repay to holders of Subscription Receipts, commencing on or before the second Business Day following the Termination Time, an amount equal to the issue price of the Subscription Receipts plus a pro rata share of the interest earned on the Escrowed Funds. In that case, the total return that a purchaser of Subscription Receipts would be entitled to receive would be limited to the purchaser's pro rata share of interest earned on the subscription price for such purchaser's Subscription Receipts. The purchaser would not be entitled to participate in any growth in the trading price of our Common Shares. Further, the purchaser would be restricted from using the funds devoted to the acquisition of the Subscription Receipts for any other investment opportunities until the Escrowed Funds are returned to the purchaser. See "Recent Developments — The Acquisition", "About Aurora" and "Risk Factors — Use of Proceeds".

It is possible that we will fail to realize the anticipated benefits of the Acquisition.

        We are proposing to complete the Acquisition to strengthen our position in the oil and natural gas industry and to create the opportunity to realize certain benefits. Achieving the benefits of the Acquisition depends in part on successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as our ability to realize the anticipated growth opportunities and synergies from integrating the Aurora Assets into our existing portfolio of properties. The integration of the Aurora Assets requires the dedication of substantial management effort, time and resources, which may divert management's focus and resources from other strategic opportunities and from operational matters during this process. The integration process may result in the loss of key employees and the disruption of ongoing business, customer and employee relationships that may adversely affect our ability to achieve the anticipated benefits of the Acquisition.

There may be potential undisclosed liabilities associated with the Acquisition.

        In connection with the Acquisition, there may be liabilities that we failed to discover or were unable to quantify in our due diligence (which we conducted prior to the execution of the Implementation Agreement). The representations, warranties and indemnities contained in the Implementation Agreement are limited and our ability to seek remedies for breach of such provisions following completion of the Acquisition will be limited.

Acquisitions require engineering, title, environmental and economic assessments that may be materially incorrect.

        Acquisitions of oil and gas properties or companies are based in large part on engineering, environmental and economic assessments made by the acquiror, independent engineers and consultants. These assessments include a series of assumptions regarding such factors as recoverability and marketability of oil and natural gas, environmental restrictions and prohibitions regarding releases and emissions of various substances, future prices of oil and gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. All such assessments involve a measure of geologic, engineering, environmental and regulatory uncertainty that could result in lower production and reserves or higher operating or capital expenditures than anticipated or unanticipated difficulty in obtaining required permits.

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        Aurora typically has not incurred the expense of a title examination prior to ordinary course acquisitions by its operator of oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights. In addition, its practice has been to not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Instead, it has relied upon the judgment of oil and natural gas lease brokers or landmen to perform the fieldwork in examining records in the appropriate governmental or county clerk's office before attempting to acquire a lease or other developed rights in a specific mineral interest.

        Prior to drilling an oil or natural gas well, however, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion.

        Aurora's failure to obtain perfect title to its leaseholds may adversely affect the production and reserves associated with the Aurora Assets and our ability in the future to increase production and reserves. Although select title and environmental reviews were conducted by us in connection with the Acquisition, this review cannot guarantee that any unforeseen defects in the chain of title will not arise to defeat our title to certain assets or that environmental defects, liabilities or deficiencies do not exist or are greater than anticipated.

We will not be the operator of a substantial majority of the drilling locations in Aurora's acreage following completion of the Acquisition, and, therefore, we will not be able to control the timing of development, associated costs, or the rate of production on that non-operated acreage.

        All of Aurora's current AMIs in the Sugarkane Field are operated by Marathon and we will be reliant upon Marathon to successfully operate the Sugarkane Field AMIs. Marathon will make decisions based on its own best interests and the collective best interests of all of the owners of WIs in the Sugarkane Field in connection with their operation (subject to its contractual and legal obligations to other owners of WIs), which may not be in our best interests. If we are not willing or are unable to fund our capital expenditure requirements relating to our drilling locations when required by our single operator, our interests in our drilling locations may be diluted or forfeited.

        As a substantial majority of Aurora's acreage is operated by Marathon, we expect that we will not be the operator of the identified gross and net drilling locations in the Aurora Reserves Reports. As we carry out our exploration and development programs with respect to the Aurora Assets, we may enter into additional arrangements with respect to existing or future drilling locations that result in additional locations being operated by others. As a result, we may have virtually no ability to exercise influence over the operational decisions of the operator, including the setting of capital expenditure budgets and drilling locations and schedules. Dependence on the operator could prevent us from realizing our target returns of those locations. The success and timing of development activities operated by our partners will depend on a number of factors that will largely be outside of our control, including:

Following completion of the Acquisition, we could experience periods of higher capital and operating costs as activity in the Eagle Ford accelerates or if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as scheduled and on budget.

        Industry activity in the Eagle Ford has accelerated since late 2008 when only a few rigs were operating. As activity in the Eagle Ford region increases, competition for equipment, labour and supplies is also expected to

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increase. In addition, capital and operating costs in the oil and gas industry have generally risen during periods of increasing commodity prices as producers seek to ramp-up production in order to capitalize on higher commodity prices. In situations where cost inflation exceeds price inflation, our profitability, cash flow and ability to complete development activities as scheduled and on budget may be negatively impacted.

        In addition to rising costs, increasing activity in the Eagle Ford and the oil and gas industry in general may impact the availability of necessary equipment, including drilling equipment. As activity increases, so does demand for equipment, which may lengthen the lead time for obtaining the equipment or, in the most extreme cases, make obtaining the equipment unavailable at a cost we are able or willing to pay.

Availability of adequate transportation arrangements with third parties may increase operating costs.

        For the transportation and relocation of Aurora's hydraulic fracturing equipment, sand and chemicals, it currently relies predominantly on truck transportation services operated by third parties. Truck carriers are subject to regulation as motor carriers by the U.S. Department of Transportation ("DOT") and by various state agencies, whose regulations include certain permit requirements of state highway and safety authorities. Increased costs of trucking services for the transport of hydraulic fracturing equipment, sand and chemicals would result in increased transportation expenses, which would negatively affect our results of operations.

A large proportion of the total estimated proved and probable reserves attributable to the Aurora Assets at December 31, 2013 were undeveloped. These reserves may not ultimately be developed.

        At December 31, 2013, approximately 79% of the total estimated proved reserves, and substantially all of the probable reserves, attributable to the Aurora Assets as set forth in the Aurora 2013 Reserves Report, were undeveloped. Recovery of undeveloped reserves requires successful drilling and incurrence of significant capital expenditures. The Aurora Reserve Reports assume that these expenditures can and will be made and that these operations will be conducted successfully. These assumptions, however, may not prove correct. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to write them off. Any such write-offs of these reserves could reduce our ability to borrow and adversely affect our liquidity. In addition, to the extent we do not operate these undeveloped properties, we will be subject to operational decisions of the operator that we may have a limited ability to influence in respect of the development of these reserves on any particular schedule, or at all.

Expiration of licenses and leases will have a negative effect on our business operations.

        The properties comprising the Aurora Assets are held in the form of licenses and leases and WIs in licenses and leases. If we or the holder of the license or lease fails to meet the specific requirement of a license or lease to bring the acreage into production or otherwise, the license or lease may terminate or expire. There can be no assurance that any of the obligations required to maintain each license or lease will be met. The termination or expiration of such licenses or leases or the WIs relating to a license or lease may have a material adverse effect on our business, financial condition, results of operations and prospects.

A change in the jurisdictional characterization of some of the Aurora Assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of the Aurora Assets, which may cause our revenues to decline and operating expenses to increase.

        Section 1(b) of the Natural Gas Act of 1938 (the "Natural Gas Act") exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission ("FERC") under that statute. Aurora believes that the gathering systems it operates meet the traditional tests FERC has used to establish a pipeline's status as a gathering. However, the distinction between FERC-regulated transmission pipelines and unregulated gathering services is the subject of ongoing litigation and may be determined by FERC on a case-by-case basis. Consequently, the classification and regulation of Aurora's gathering facilities are subject to change based on future determinations by FERC, the courts or the U.S. Congress ("Congress").

        While Aurora's natural gas gathering pipelines are currently exempt from FERC regulation under the Natural Gas Act, we may be subject to certain FERC reporting requirements. Other FERC regulations may indirectly affect our businesses and the markets for products derived from these businesses, including, for

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example, FERC's requirements as to access transportation, natural gas quality, ratemaking, capacity release and market center promotion. A change in these requirements may affect our financial condition and results of operations.

Regulation of sales and transportation may impact the marketing of production from the Aurora Assets.

        The sales prices of oil, natural gas liquids, and natural gas are presently not regulated, but rather are set by the market. We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures and what effect, if any, such proposals might have on the operations of the underlying properties.

        The FERC regulates rates and service conditions for the transportation of natural gas in interstate commerce, which affects the marketing of natural gas we produce, as well as the revenues we receive for sales of such production. The FERC exercises its ratemaking authority by applying cost-of-service principles, allowing for the negotiation of rates where there is a cost-based alternative rate or granting market-based rates in certain circumstances, typically with respect to storage services. The FERC has also undertaken various initiatives to increase competition in the natural gas industry, which may indirectly affect our businesses and the markets for products derived from these businesses. These policies include regulations on open access transportation, natural gas quality, capacity release and market center promotion. We may be also indirectly subject to certain reporting requirements of the FERC based on the sale of gas from producing properties in which we have interest.

        The prices and terms of access to intrastate pipeline transportation are subject to state regulation. The FERC and, to a lesser extent, the Railroad Commission of Texas have proposed and implemented new rules and regulations affecting gas transportation in recent years. We do not believe that we will be affected by any such rules or changes to existing rules in a manner materially different than any other similarly situated natural gas producer.

        Rates and service conditions for the interstate transportation of oil and natural gas liquids are regulated by the FERC. In general, these rates must be cost-based or based on rates in effect in 1992, although the FERC has established an indexing system for such transportation rates that allows pipelines to take an annual inflation-based rate increase. Shippers may, however, contest rates that do not reflect costs of service. The FERC has also established market-based rates and settlement rates as alternative forms of ratemaking in certain circumstances. We cannot predict with any certainty what effect, if any, these regulations will have, but other factors being equal, the regulations may, over time ten to increase transportation costs which may have the effect of reducing net prices for oil and natural gas liquids.

Sales of oil and natural gas, and any hedging activities related to such energy commodities, expose us to potential regulatory risks.

        The FERC, the Federal Trade Commission ("FTC") and the Commodity Futures Trading Commission ("CFTC") hold statutory authority to monitor certain segments of the physical and future energy commodities and derivatives markets relevant to the Aurora Assets. These agencies have issued broad regulations prohibiting fraud and manipulation in such markets. With regard to physical sales of oil and natural gas, any hedging activities related to these energy commodities and certain other activities, we will be required to observe the market-related regulations issued by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could expose us to enforcement actions and penalties and thus materially and adversely affect our financial condition and results of operations.

        Under the Natural Gas Act, as amended by the Domenici-Barton Energy Policy Act of 2005, the FERC is authorized to impose civil penalties of up to U.S.$1 million per day for each violation of the Natural Gas Act and the FERC's regulations thereunder, including market-related regulations. The FERC may also order disgorgement of profits associated with any violation. The FTC is authorized to seek the judicial imposition of penalties of up to U.S.$1 million per day for each violation of such law and its implementing regulations. The CFTC also has statutory authority to assess fines of up to U.S.$1 million for violations of the Commodity Exchange Act and its anti-market manipulation regulations.

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We may be subject to new pipeline safety laws and regulations.

        The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2012, which President Obama signed into law on January 3, 2012, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues, such as the exemption of gathering systems from integrity management programs. These studies could result in the adoption of new regulatory requirements for existing pipelines, including gathering systems. DOT, through the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration ("PHMSA") has also published an advanced notice of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity management requirements and add new regulations governing the safety of gathering lines. We cannot predict the effect of new regulatory initiatives on us or the Aurora Assets. Penalties for safety violations and potential regulatory changes could have a material effect on our operations, operating expenses, and revenues.

Certain federal income tax deductions currently available with respect to oil and natural gas development and exploration may be eliminated as a result of future legislation.

        President Obama's budget proposal for the fiscal year 2014 recommended the elimination of certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to: (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities for oil and gas production; and (iv) an extension of the amortization period for certain geological and geophysical expenditures.

        It is unclear whether any such changes will actually be enacted or, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could materially affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production and materially affect the economic return from the development of reserves attributed to the Aurora Assets.

The recent adoption of derivatives legislation by Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with the Aurora Assets.

        Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. This legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), was signed into law by President Obama on July 21, 2010 and requires the CFTC and the SEC to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank Act, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade execution requirements in connection with any future derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require certain of our counterparties to any future derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity) and trigger changes in the terms and availability of derivatives to protect against risks we may encounter. If we reduce our use of derivatives with respect to the Aurora Assets as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures on the Aurora Assets. Any of these consequences could have a material adverse effect on us, our financial condition and the results of our operations.

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Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

        Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight geological formations. We routinely utilize hydraulic fracturing techniques in many of our drilling and completion programs. At present, the hydraulic fracturing process in the United States is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the Safe Drinking Water Act's (the "SDWA") Underground Injection Control Program and, in May 2012, issued a draft permitting guidance document addressing the performance of hydraulic fracturing activities using diesel fuel. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing activities and issued a progress report in December 2012, with a draft final report expected to be available this year for public comment and peer review. In October 2011, the EPA announced its intention to propose federal Clean Water Act regulations by 2014 governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. In addition, in November 2011, the EPA announced that it would require record-keeping and reporting of the chemicals used by oil and natural gas exploration and production companies in hydraulic fracturing, which is intended to provide transparency with regard to the use of chemicals in hydraulic fracturing. Moreover, in May 2013, the Bureau of Land Management issued a proposed rule that would require public disclosure of chemicals used in hydraulic fracturing operations, and impose other operational requirements for all hydraulic fracturing operations on federal lands, including Native American trust lands.

        Also, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. Public interest in hydraulic fracturing and initiatives by environmental groups may also increase regulatory scrutiny and regulation. The results of government studies or heightened public interest could spur additional initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

        Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states in the U.S. have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction, completion and operating requirements on hydraulic fracturing operations, including the states in which Aurora operates the Aurora Assets. For example, Texas requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production in Texas) and to the public. In addition, some local governments, including some found in Texas, have adopted ordinances within their jurisdictions regulating the time, place and manner of drilling activities in ground or hydraulic fracturing activities in general. The disclosure of information regarding the constituents of hydraulic fracturing fluids could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil or surface water. In addition, disclosure of our proprietary chemical formulas or disclosure of any chemicals used in such formulas to the public could diminish the value of those formulas to us and result in fewer innovations or reduced access to new technology. If new laws, regulations or ordinances that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations on the Aurora Assets. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of new federal legislation or regulatory initiatives by the EPA, our fracturing activities on the Aurora Assets could become subject to additional permitting requirements, and also to attendant permitting delays and cost increases. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from reserves attributed to the Aurora Assets and have an adverse effect on our business, financial condition and results of operations.

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Recently issued rules regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs.

        In August 2012, the EPA published final rules that subject oil and natural gas production and natural gas processing operations to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs. With regards to production activities, the final rules require, among other things, the reduction of volatile organic compound emission from three subcategories of fractured and re-fractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all "other" fractured and re-fractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare. However, the "other" wells used must reduced emission completions, also known as "green completions," with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, pneumatic controllers, and storage vessels. Compliance with these requirements could increase our costs of development and production and our capital expenditures, which costs and expenditures could be significant and adversely impact our business.

Following the Acquisition, we will have a substantial amount of indebtedness, which may adversely affect our cash flows and ability to operate our business, remain in compliance with the agreements governing our indebtedness and service our debt obligations as they become due.

        Our high level of indebtedness following the Acquisition could have important consequences to investors, including the following:

        Subject to the restrictions in the agreements governing our indebtedness, we may incur substantial additional indebtedness (including secured indebtedness) in the future, which may exacerbate the risks described above. In addition, financial covenants in the Aurora Notes may restrict us from freely distributing cash to us from Aurora's operating subsidiaries.

Many of the operational, environmental and reserves risks set forth in the "Risk Factors" section of the Annual Information Form apply to the Aurora Assets.

        In addition to the risk factors set forth above, many of the risk factors set forth in the Annual Information Form and in this short form prospectus relating to the oil and natural gas business, environmental and our operations and reserves apply in respect of the Aurora Assets that we are acquiring pursuant to the Acquisition.

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SUMMARY DESCRIPTION OF OUR BUSINESS

        Through our subsidiaries, we are engaged in the business of acquiring, developing, exploiting and holding interests in petroleum and natural gas properties and related assets in Canada (primarily in the provinces of British Columbia, Alberta and Saskatchewan) and in the United States (primarily in the states of North Dakota and Wyoming). We act as the primary financing vehicle for our subsidiaries by providing access to debt and equity capital markets. As at the date of this short form prospectus, our primary assets are the shares of Baytex Energy that we own and the Notes. Cash flow from the business carried on by our subsidiaries is flowed to us by way of dividends, interest and principal repayments on the Notes and intercompany loans.

        We pay monthly cash dividends to holders of our Common Shares in accordance with our dividend policy. In the event that we do not comply with covenants under the Credit Facilities, the New Credit Facilities and the Debenture Indenture, our ability to pay dividends to Shareholders may be restricted. See "Description of Common Shares — Dividend Policy".

        For a description of us and the general development of our business over the last three completed financial years, see "Baytex Energy Corp.", "General Development of Our Business" and "Description of Our Business and Operations" in the Annual Information Form, which is incorporated by reference herein.

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RECENT DEVELOPMENTS

Operational Update

        During the fourth quarter of 2013, our transportation operations were hampered by severe winter weather which impacted our ability to deliver crude oil from the field to sales delivery points. As inventory levels reached capacity, production was curtailed by up to 5,000 Bbls/d during the month of December. Based on field estimates, our average production during the fourth quarter of 2013 is estimated at 58,000 Boe/d, which brings full-year 2013 production to approximately 57,100 Boe/d. We drilled 24 gross (23.7 net) operated oil wells in the fourth quarter of 2013, including 11 cold multi-lateral wells at Peace River, the remaining five wells of our 15-well cyclic steam stimulation module at Cliffdale and seven horizontal wells at Lloydminster.

The Acquisition

The Acquisition Agreement

        On February 6, 2014 we entered into the Implementation Agreement with Aurora, whereby it is proposed that we, or a wholly-owned subsidiary of us, will acquire all of the issued and outstanding Aurora Shares for A$4.10 per share for total consideration of approximately CDN$1.8 billion plus assumed debt of approximately CDN$744 million for a total transaction value of approximately CDN$2.6 billion.

        With the Acquisition, we will obtain a significant position in the core of the liquids-rich Eagle Ford resource play. The Aurora Assets will provide material production, long-term growth and high quality reserves with upside potential and will provide us with a platform for further potential growth opportunities.

        The Acquisition is to be carried out by way of a scheme of arrangement (the "Scheme of Arrangement") under Part 5.1 of the Corporations Act, subject to receipt of certain approvals. The Scheme of Arrangement shall be substantially in the form attached to the Implementation Agreement as Annexure 2, subject to any alterations or conditions required by the Australian Court or agreed between us and Aurora. Subject to approval of the Australian Court, the Acquisition must be approved by the Aurora Shareholders at a special meeting of Aurora Shareholders expected to be held in late April/early May 2014. The Acquisition must be approved by (i) at least 75% of the votes cast and (ii) by a majority in number of the Aurora Shareholders who casts votes.

        The Aurora Board has unanimously approved the Acquisition and recommended that Aurora Shareholders vote in favour of the Scheme of Arrangement. All of the directors of Aurora controlling approximately 5.5% of the issued and outstanding Aurora Shares have agreed to vote their Aurora Shares in favour of the Acquisition. The Aurora Board's recommendation and stated voting intention are given in the absence of a Superior Proposal (as described below) and subject to an independent expert concluding that the Acquisition is in the best interests of Aurora Shareholders.

Acquisition Consideration

        Pursuant to the Scheme of Arrangement, each Aurora Shareholder will receive, for each Aurora Share held, A$4.10 cash.

        Pursuant to the Acquisition Agreement, the parties have agreed to use reasonable endeavours (acting co-operatively and in good faith) to procure that, as soon as practicable, each holder of Aurora Options or Aurora Performance Rights (the "Unlisted Securities") enters into an agreement with us and Aurora, in a form acceptable to both us and Aurora (each acting reasonably), under which each holder agrees to the cancellation of all of their Unlisted Securities in exchange for an amount per Unlisted Security equal to: (i) for the Aurora Options, the amount equal to the assessed value of each Aurora Option using a standard methodology, and (ii) for the Aurora Performance Rights $4.10 cash, with such transfer or cancellation to be subject to the Acquisition becoming effective and to take effect on the Implementation Date.

        The Acquisition will constitute a "change of control" pursuant to the trust indenture dated February 8, 2012 governing the 2017 Aurora Notes between Aurora USA Oil & Gas, Inc., each of the guarantors party thereto and U.S. Bank National Association and the trust indenture dated March 31, 2013 governing the 2020 Aurora Notes between Aurora, each of the guarantors party thereto and U.S. Bank National Association (collectively, the "Aurora Note Indentures"). Pursuant to the Aurora Note Indentures, upon completion of the Acquisition,

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each holder of Aurora Notes will have the right to require us to repurchase all or any part of that holder's Aurora Notes pursuant to an offer ("Change of Control Offer") on the terms set forth in the Aurora Note Indentures. Within 30 days following completion of the Acquisition, we will be required to mail a notice to each holder of Aurora Notes describing the Acquisition and offering to repurchase Aurora Notes properly tendered prior to the expiration date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed, pursuant to the procedures required by the Aurora Note Indentures and described in such notice. In the Change of Control Offer, we will offer a payment ("Change of Control Payment") in cash equal to 101% of the aggregate principal amount of Aurora Notes repurchased, plus accrued and unpaid interest, if any, on Aurora Notes repurchased to the date of purchase (the "Change of Control Purchase Date"), subject to the rights of holders of Aurora Notes on the relevant record date to receive interest due on the relevant interest payment date. Promptly following the expiration of the Change of Control Offer, we will, to the extent lawful, accept for payment all Aurora Notes or portions of Aurora Notes properly tendered pursuant to the Change of Control Offer.

        In the event that holders of not less than 90% in aggregate principal amount of either series of the outstanding Aurora Notes accept a Change of Control Offer and we purchase all of such series of Aurora Notes held by such holders, we will have the right, upon not less than 30 nor more than 60 days prior notice, given not more than 30 days following the purchase pursuant to the Change of Control Offer described above, to redeem all of such series of the Aurora Notes that remain outstanding following such purchase at a redemption price equal to the Change of Control Payment plus, to the extent not included in the Change of Control Payment, accrued and unpaid interest, if any, on such series of the Aurora Notes that remain outstanding, to the date of redemption (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date).

        We have agreed to retain a Canadian chartered bank (or one or more of its affiliates as may be appropriate in the circumstances), of which Scotia is a wholly-owned subsidiary, to act as manager in connection with the Change of Control Offers required to be made by us to the holders of the Aurora Notes following completion of the Acquisition at prevailing market rates for a person acting in such a role. See "Relationship between Us and Certain Underwriters".

Aurora Non-Solicitation; Termination Fee

        The Implementation Agreement provides, among other things, for a non-completion fee of A$18.8 million in the event the Acquisition is not completed in certain circumstances, including circumstances where Aurora may receive and accept a Superior Proposal. The Implementation Agreement also contains certain non-solicitation covenants of Aurora and a right to counter in favour of us. Aurora's non-solicitation covenants are subject to exceptions where the directors of Aurora determine such covenants may involve a breach of their fiduciary or statutory duties.

Covenants, Representations and Warranties

        Aurora has agreed that prior to the Implementation Date (as defined in the Implementation Agreement), it shall, and shall cause each of its subsidiaries and affiliates to, conduct its business in the ordinary course and in substantially the same manner as previously conducted (subject to ongoing capital requirements being satisfied), and not to undertake certain types of restricted activities unless we otherwise agree or unless otherwise expressly contemplated or permitted by the Implementation Agreement.

        We and Aurora have made certain representations and warranties relating to, among other things, corporate existence, corporate authorization, capitalization, no conflicts, shareholder and governmental approvals and absence of certain changes. Like many public company acquisition agreements, the representations, warranties and indemnities contained in the Implementation Agreement are limited and, other than in exceptional circumstances, we will not be able to seek remedies for breach of such provisions following completion of the Acquisition.

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Conditions to Closing

        The Acquisition is subject to a number of customary closing conditions, including the receipt of required regulatory approvals and court approvals, as well as the approval of Aurora Shareholders as described above. Regulatory approvals include approval of the Australian Foreign Investment Review Board and the applicable approvals required under the HSR Act.

        The disclosure booklet that will be prepared in connection with the meeting of Aurora Shareholders to be called to consider and approve the Acquisition is expected to be mailed to Aurora Shareholders in April, 2014. The Acquisition is expected to close in late April/early May, 2014 or such other date as we and Aurora may agree but in any event, not later than June 30, 2014.

Strategic Benefits of the Acquisition

        The Acquisition enhances our growth-and-income business model, delivers production and reserves per share growth and provides attractive capital efficiencies for future investment. The Acquisition is accretive to us on all metrics while maintaining a strong balance sheet.

        The following are the key benefits of the Acquisition:

 



   

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Pro Forma the Acquisition and the Offering

Selected Pro Forma Financial Information

        The following tables set out certain pro forma financial information for: (i) us and Aurora as at December 31, 2012 before giving effect to the Acquisition; (ii) us as at and for the year ended December 31, 2012 after giving effect to the Acquisition; (iii) us and Aurora as at September 30, 2013 before giving effect to the Acquisition; and (iv) us as at and for the nine month period ended September 30, 2013 after giving effect to the Acquisition.

 
  As at and for the Year Ended
December 31, 2012
  As at and for the Nine Months Ended
September 30, 2013
 
 
  Baytex
before giving
effect to the
Acquisition
  Aurora
before giving
effect to the
Acquisition
  Baytex
after giving
effect to the
Acquisition(1)
  Baytex
before giving
effect to the
Acquisition
  Aurora
before giving
effect to the
Acquisition
  Baytex
after giving
effect to the
Acquisition(1)
 
(expressed in $000s, except per share amounts)
   
   
   
   
   
   
 

Petroleum and natural gas sales, net of royalties

    1,024,949     207,548     1,232,497     846,063     289,983      

General and administrative expenses

    44,646     15,148     59,794     33,060     17,337      

Operating and transportation expenses

    439,615     24,530     464,145     327,534     30,022      

Net income

    258,631     58,899     254,273     133,672     81,867      

Per share (basic)

    2.16     13.60     1.65     1.08     18.27      

Per share (diluted)

    2.12     13.35     1.63     1.07     17.95      

Total assets

                      2,741,169     1,561,721      

Total liabilities

                      1,445,104     1,013,230      

Shareholders' equity

                      1,296,065     548,491      

Note:

(1)
For pro forma adjustments, see Schedule "B" to this short form prospectus.

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        For additional pro forma financial information in respect of us, including our outstanding share capital, after giving effect to the Acquisition, see Schedule "B" — "Pro Forma Consolidated Financial Statements of Baytex". Reference should also be made to the Annual Financial Statements, the Annual MD&A, the Interim Financial Statements and the Interim MD&A, which are incorporated by reference herein, and the audited financial statements of Aurora for the years ended December 31, 2012 and 2011, together with the notes thereto and the report of the auditors thereon, and the unaudited interim consolidated financial statements of Aurora as at September 30, 2013 and 2012 and for the three and nine month periods ended September 30, 2013 and 2012, together with the notes thereto, which are attached hereto as Schedule "A".

        The Acquisition is a significant acquisition for us for the purposes of Part 8 of National Instrument 51-102 – Continuous Disclosure Obligations.

Selected Combined Operational Information

        The following table sets out certain combined operational information for the oil and natural gas assets which will be owned, directly or indirectly, on a consolidated basis by us following completion of the Acquisition, for the periods indicated. Important information concerning the oil and natural gas properties and operations of each of us and Aurora is contained elsewhere in, or incorporated by reference in, this prospectus. Readers are encouraged to carefully review such information and those documents as the information set forth in the table below is a summary only and is qualified in its entirety by such detailed information.

Pro Forma Production

 
  Twelve months ended December 31, 2012   Nine months ended September 30, 2013  
 
  Baytex
before giving
effect to the
Acquisition
  Aurora
before giving
effect to the
Acquisition
  Baytex
after giving
effect to the
Acquisition(1)
  Baytex
before giving
effect to the
Acquisition
  Aurora
before giving
effect to the
Acquisition
  Baytex
after giving
effect to the
Acquisition(1)
 

Daily Natural Gas Production (Mcf/d)

    43,100     11,548     54,648     41,979     24,176     66,155  

Crude Oil and NGLs (Bbls/d)

    46,807     8,754     55,561     49,827     16,139     65,966  

Total (Boe/d)

    53,986     10,678     64,664     56,823     20,167     76,990  

Operating Netback ($/Boe)(2)

    31.10     46.76     33.69     33.41     47.21     37.02  

Pro Forma Reserves

 
  Baytex as at December 31, 2012
before giving effect to the Acquisition
  Aurora as at December 31, 2013
(Baytex Internal Estimate)
  Pro Forma Baytex after giving
effect to the Acquisition(1)
 
 
  Gross   Net   Gross   Net   Gross   Net  

Category of Reserves (Mboe)

                                     

Total Proved

    143,444     118,814     106,694     78,954     250,138     197,768  

Total Probable

    148,152     118,379     59,876     44,308     208,028     162,687  

Total Proved plus Probable plus Possible

    291,596     237,193     166,570     123,262     458,166     360,455  

Notes:

(1)
Reserves information provided herein is from the Sproule Report as at December 31, 2012 and our internal estimate of Aurora's reserves as at as at December 31, 2013, prepared by a non-independent qualified reserves evaluator in accordance with NI 51-101 and the COGE Handbook.

(2)
Operating netback does not have a standardized meaning under Canadian GAAP. See "Non-GAAP Financial Measures".

        The pro forma reserve information in the foregoing table is derived (i) in respect of our reserves as at December 31, 2012, from the Sproule Report and (ii) in respect of Aurora's reserves as at December 31, 2013, from estimates of our internal non-independent qualified reserves evaluator as at December 31, 2013 made in connection with our evaluation of the Acquisition. Our internal estimates of Aurora's reserves as at December 31, 2013 differ from the estimates contained in the Aurora 2013 Reserves Report. They were prepared for use by our management in the evaluation of the Acquisition. Since the estimates of our reserves

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and our internal estimate of the reserves of Aurora reflected in the above table were estimated as at different dates, they have been generated based on different assumptions in respect of commodity pricing, development costs, development timing and the timing and amount of capital expenditures, among other metrics. In addition, our reserves as at December 31, 2012 have not been adjusted to account for exploration or development results, production, revisions, acquisitions, dispositions, pricing or any other changes after December 31, 2012. As a result, the above table and the disclosure elsewhere in this short form prospectus describing our reserves on a consolidated pro forma basis for the Acquisition is presented for hypothetical purposes, does not reflect the actual combined estimated of our reserves and those of Aurora at December 31, 2013 and should not necessarily be viewed as predictive of our reserves and future production once the Acquisition is completed.

        For pro forma financial information in respect of us, including our outstanding share capital, after giving effect to the Acquisition, see Schedule "B" — "Pro Forma Consolidated Financial Statements of Baytex".

New Credit Facilities

        In connection with the Acquisition, we have entered into an agreement with a Canadian chartered bank (the "Bank") pursuant to which the Bank has agreed to fully underwrite and commit to provide us with new senior secured credit facilities in the aggregate principal amount of $2.5 billion (the "New Credit Facilities") which will replace our Credit Facilities. The New Credit Facilities are comprised of revolving facilities consisting of a $50 million revolving operating loan facility and a $950 million extendible syndicated loan facility with a syndicate of chartered banks (collectively the "Revolving Facilities") and non-revolving facilities consisting of a $200 million non-revolving syndicated term facility (the "Term Loan A Facility") and a $1.3 billion non-revolving syndicated equity bridge (the "Equity Bridge") (collectively, the "Non-Revolving Facilities"). The Revolving Facilities will be for a four year term extendible annually for a one, two, three or four year period (subject to a maximum four-year term at any time) and will contain standard commercial covenants for facilities of this nature. The Revolving Facilities will not require any mandatory principal payments during the four-year term. Advances (including letters of credit in connection with the Revolving Facilities only) under the New Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the agent bank's prime lending rate, bankers' acceptance discount rates or London Interbank Offered Rates, plus applicable margins. The New Credit Facilities will be secured by a floating charge over all of our assets, excluding the Aurora Assets, and will be guaranteed by certain material restricted subsidiaries other than Aurora and its subsidiaries. The Revolving Facilities will not include a term-out feature or a borrowing base restriction but will restrict our ability to borrow through the use of customary financial covenants. The Revolving Facilities and the Term Loan A Facility will contain restrictions on our and our subsidiaries' ability to make distributions when (i) a default or event of default under the Revolving Facilities has occurred and is continuing, or (ii) distributions would be reasonably expected to have a material adverse effect on or impair our ability to fulfill our financial obligations under the Credit Facilities.

        Each of the Term Loan A Facility and the Equity Bridge non-revolving facilities are single drawdown facilities and will be available solely to finance (directly or indirectly) the Acquisition together with reasonable transaction costs and expenses related thereto. The Term Loan A Facility will have a two year term and the Equity Bridge will have a one year term. Each of the Term Loan A Facility and the Equity Bridge provide for mandatory reductions and repayments for specified equity and debt issuances and dispositions. In addition, with respect to any proceeds arising in connection with the issuance of the Subscription Receipts, the Equity Bridge will be reduced by an amount equal to the gross proceeds received by us in connection with the Offering, once such proceeds are placed into escrow with the Escrow Agent. The Equity Bridge will prohibit us and our subsidiaries from making distributions, other than inter-company distributions or acquisitions and will impose additional financial covenant restrictions under the New Credit Facilities if and for long as there is any outstanding indebtedness under the Equity Bridge.

        In connection with the Acquisition, we also expect to establish replacement credit facilities through Aurora's subsidiary, Aurora USA Oil & Gas, Inc, with the Bank for the Existing Target Facility of up to U.S.$300 million.

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Dividend Increase

        We are committed to a growth-and-income model and its three fundamental principles: delivering organic production growth, paying a meaningful dividend and maintaining capital discipline. Through the combination of an expanded inventory of high capital efficiency projects and an improved outlook for heavy oil differentials, we remain confident in our business plan going forward. Consequently, we intend increase the monthly dividend on our Common Shares by 9% to $0.24 from $0.22 per Common Share, subject to the completion of the Acquisition.

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ABOUT AURORA

        Except as otherwise indicated all information regarding Aurora and the Aurora Assets contained in this short form prospectus, including all reserves and related information, financial information and all pro forma financial information reflecting the pro forma effects of the Acquisition, has been derived in part from information provided by Aurora and other third parties. The Aurora Reserves Reports were prepared by Aurora. We were not given the opportunity to participate in the preparation of the Aurora Reserves Reports or to review the reserves data with management of Aurora or Ryder Scott in conjunction with the preparation of the Aurora Reserves Reports. As a result, we are unable to assess Aurora's procedures for providing information to Ryder Scott or for assembling and reporting other information to Ryder Scott associated with Aurora's oil and gas activities. See "Risk Factors" in this short form prospectus.

General

        Aurora is an ASX and TSX listed oil and natural gas company active exclusively in the United States. Its primary asset is 22,200 net (80,200 gross) acres in the prolific Sugarkane Field located in South Texas in the core of the liquids-rich Eagle Ford. Aurora's 2013 fourth quarter gross production was 24,678 Boe/d (82% liquids) of predominantly light, high-quality crude oil. The Sugarkane Field has been largely delineated with infrastructure in place which will facilitate low-risk future annual production growth. In addition, these assets have significant future reserves upside potential from well downspacing, improving completion techniques and new development targets in additional zones. In addition, Aurora holds approximately 14,000 net acres in the Eaglebine play regionally on trend with the Eagle Ford.

        Aurora is an Australian corporation with its head and registered office located at Level 1, 338 Barker Road, Subiaco, WA 6008, Australia. Aurora also has an operational office located in Houston, Texas at 1200 Smith Street, Suite 2300, Houston, TX 77002 USA. It has appointed Davies Ward Phillips & Vineberg LLP at 155 Wellington Street West, Toronto, Ontario M5Y 3J7, as its agent for service of process in Canada.

        The following chart summarizes the material subsidiaries of Aurora.

GRAPHIC

        Aurora's current principal focus of operation is on the development of its Sugarkane Field interests currently operated by Marathon. The Sugarkane Field covers an identified area exceeding 200,000 acres and is a reservoir that lies approximately 20 kilometers south of the main Texas Austin Chalk formation, located within South Texas.

        Unconventional shale production is typically characterized by high initial production rates, followed by steep decline rates and prolonged "tail" production profiles. The majority of Aurora's acreage is located in the

35


central portion of the Eagle Ford trend, primarily within the condensate-rich window, extending into the volatile oil window to the northwest. The Sugarkane Field is over-pressured (generally having a pressure gradient of approximately 0.8 psi per foot), enhancing both the initial production rates and estimated ultimate recovery per well. The combination of high liquids content and high production rate results in attractive economics for development wells.

        We believe that this is one of the fastest developing unconventional shale developments in North America. There is limited and predictable variation in geological and reservoir properties across the region, with respect to thickness, depth and hydrocarbon composition of shale intersected. Unlike conventional oil and natural gas traps where the target reservoir may fail to contain hydrocarbons, all of the wells drilled on Aurora's properties are expected to intersect the Eagle Ford formation. Furthermore, a high proportion of the hydrocarbons produced by Aurora from the Eagle Ford are condensate or light/medium oil, which have historically resulted in a higher price realization per unit than dry natural gas.

        The diagram below is an indicative pictorial representation of Aurora's Sugarkane Field AMIs. It is not intended to be schematically definitive, to scale or reference ownership of mineral rights.

GRAPHIC

36


Aurora's Recent Developments

2013 Operational and Financial Update

        Aurora's principal assets and the approximate associated gross and net land positions as of December 31, 2013, are shown in the table below:

 
  AVERAGE WORKING
INTEREST
  GROSS ACREAGE   NET ACREAGE  

Sugarloaf AMI

    28.1%     24,000     6,750  

Longhorn AMI

    31.9%     28,500     9,100  

Ipanema AMI

    36.4%     4,800     1,750  

Excelsior AMI

    9.1%     20,100     1,800  

Operated Sugarkane Acreage (2013 Acquired Assets)

    100.0%     2,800     2,800  
                 

Total Sugarkane Field

          80,200     22,200  

Eaglebine Operated

    91.1%     15,000     14,000  
                 

Total

          95,200     36,200  
                 

        Based on realized commodity pricing achieved by Aurora for the year ended December 31, 2013, approximately 94% of Aurora's production revenue related to oil, condensate and NGL sales, with the balance being natural gas production revenue.

        During the last three years, substantial drilling activity was undertaken across Aurora's Sugarkane Field AMIs. As of December 31, 2013, the total number of gross producing wells in which Aurora has an interest was 387, as compared to 216 gross wells as of December 31, 2012 and 71 gross wells as of December 31, 2011.

        The following table summarizes the status of wells in which Aurora has a WI, categorized by Sugarkane Field AMI, as of December 31, 2013.

 
  SUGARLOAF   LONGHORN   IPANEMA   EXCELSIOR   AXLE TREE   HEARD
RANCH
  TOTAL  

Producing

    97     178     7     86     11     8     387  

Workover

                             

Fracture Stimulation

                        2     2  

Completions

    3     13         10         1     27  

Drilling

    2     4         2         1     9  

Total

    102     195     7     98     11     12     425  

2013 Reserves Update

        On February 3, 2014, Aurora publicly announced that Ryder Scott had provided the Aurora 2013 Reserves Report to Aurora. Set out below is a summary of reserves estimates and the value of future net revenue of Aurora associated with such reserves with an effective date as of December 31, 2013 based on the Aurora 2013 Reserves Report.

37


        The following tables provides a summary of the reserve estimates as at December 31, 2013 evaluated by Ryder Scott using forecast prices and costs contained in the Aurora 2013 Reserves Report.


SUMMARY OF OIL AND NATURAL GAS RESERVES
AS OF DECEMBER 31, 2013
FORECAST PRICES AND COSTS

 
  RESERVES  
 
  LIGHT AND MEDIUM OIL   NATURAL GAS LIQUIDS   NATURAL GAS   BOE  
RESERVES CATEGORY
  Gross
(MMbbls)
  Net
(MMbbls)
  Gross
(MMbbls)
  Net
(MMbbls)
  Gross
(Bcf)
  Net
(Bcf)
  Gross
(MMBoe)
  Net
(MMBoe)
 

PROVED:

                                                 

Developed Producing

    14.1     10.4     13.1     9.7     42.9     31.7     34.4     25.4  

Developed Non-Producing

    0.6     0.5             0.2     0.2     0.7     0.5  

Undeveloped

    34.4     25.3     64.6     47.6     184.8     136.3     129.8     95.6  
                                   

TOTAL PROVED

    49.1     36.2     77.8     57.4     227.9     168.1     164.9     121.5  

PROBABLE

    11.6     8.6     31.0     23.0     98.3     73.0     58.9     43.8  
                                   

TOTAL PROVED PLUS PROBABLE

    60.7     44.8     108.8     80.3     326.2     241.0     223.8     165.3  
                                   

POSSIBLE

    1.4     1.0     32.3     23.8     87.8     64.4     48.4     35.5  
                                   

TOTAL PROVED PLUS PROBABLE PLUS POSSIBLE(1)

    62.1     45.8     141.1     104.1     414.0     305.4     272.2     200.8  
                                   

Note:

(1)
Possible reserves are those reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

        The table below shows the before tax net present value of future net revenue of Aurora's reserves on an undiscounted basis and with a 5%, 10%, 15% and 20% discount being applied:


SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF DECEMBER 31, 2013
FORECAST PRICES AND COSTS

 
  NET PRESENT VALUES OF FUTURE
NET REVENUE
BEFORE INCOME TAXES DISCOUNTED AT (%/year)
 
RESERVES CATEGORY
  0%   5%   10%   15%   20%  
 
  (in U.S.$ million)
 

PROVED:

                               

Developed Producing

    1,079     857     721     629     564  

Developed Non-Producing

    28     25     23     21     20  

Undeveloped

    2,610     1,645     1,101     766     546  
                       

TOTAL PROVED

    3,717     2,527     1,845     1,416     1,130  

PROBABLE

    1,143     702     464     324     233  
                       

TOTAL PROVED PLUS PROBABLE

    4,860     3,229     2,309     1,740     1,363  
                       

POSSIBLE(1)

    701     371     205     111     55  

TOTAL PROVED PLUS PROBABLE PLUS POSSIBLE(1)

    5,561     3,600     2,514     1,851     1,418  
                       

Note:

(1)
Possible reserves are those reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

38


        The forecast pricing parameters detailed in the table below were used in the Aurora 2013 Reserves Report by Ryder Scott. NGL pricing was estimated at 30% of the oil pricing. The figures were then adjusted for quality and regional price variations. Further adjustments were made for the calorific value of the gas.


SUMMARY OF PRICE ASSUMPTIONS
AS OF DECEMBER 31, 2013
FORECAST PRICES AND COSTS

Period ended
  West Texas
Intermediate Price
(U.S.$/Bbl)
  Natural Gas Price
(U.S.$/MMbtu)
 

2014

    94.49     4.23  

2015

    87.98     4.17  

2016

    83.74     4.13  

Thereafter

    83.74     4.13  

        Well costs are based on estimates provided by the operator of Aurora's non-operated acreage, together with internally generated estimates for its operated acreage. These estimates are then adjusted for horizontal well lengths accordingly. In general the well costs are based on a nominal 5,000 foot lateral design with a drill and complete cost of U.S.$7.5 million. This results in well costs ranging from U.S.$6.7 million to U.S.$10.5 million depending on location, depth, lateral length and artificial lift design.

Aurora's 2012 Oil and Gas Information and Reserves Data

        The disclosure below and the Aurora 2012 Reserves Report are each based on Aurora's WIs in the Sugarkane Field as at December 31, 2012 and do not include any reserves, production or other oil and gas information since December 31, 2012. For more recent reserves and other information relating to Aurora, see "Recent Information Respecting Aurora" above.

Reserves and Future Net Revenue

        The following table discloses, in aggregate, Aurora's gross and net reserves estimated using the Aurora 2012 Reserves Report forecast prices and costs, by product type.


SUMMARY OF OIL AND NATURAL GAS RESERVES
AS OF DECEMBER 31, 2012
FORECAST PRICES AND COSTS

 
  RESERVES  
 
  LIGHT AND MEDIUM OIL   NATURAL GAS LIQUIDS   NATURAL GAS   BOE  
RESERVES CATEGORY
  Gross
(Mbbls)
  Net
(Mbbls)
  Gross
(Mbbls)
  Net
(Mbbls)
  Gross
(MMcf)
  Net
(MMcf)
  Gross
(MBoe)
  Net
(MBoe)
 

PROVED:

                                                 

Developed Producing

    7,752     5,710     8,778     6,490     30,133     22,258     21,552     15,909  

Developed Non-Producing

                                 

Undeveloped

    23,694     17,436     30,656     22,653     112,722     83,263     73,137     53,967  
                                   

TOTAL PROVED

    31,446     23,146     39,433     29,143     142,885     105,522     94,688     69,876  

PROBABLE

    1,433     1,069     3,595     2,677     18,915     14,091     8,181     6,094  
                                   

TOTAL PROVED PLUS PROBABLE

    32,879     24,215     43,028     31,820     161,769     119,612     102,869     75,970  
                                   

POSSIBLE

    2,436     1,793     36,702     27,166     154,182     114,285     64,835     48,006  
                                   

TOTAL PROVED PLUS PROBABLE PLUS POSSIBLE(1)

    35,315     26,008     79,731     58,986     315,952     233,897     167,705     123,976  
                                   

Note:

(1)
Possible reserves are those reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

39


        The following tables disclose, in the aggregate, the net present value of Aurora's net revenue attributable to the reserves categories in the previous table, estimated using the Aurora 2012 Reserves Report forecast prices and costs, before deducting future income tax expenses and after deducting future income tax expenses, on an undiscounted basis and with a 5%, 10%, 15% and 20% discount.


SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF DECEMBER 31, 2012
FORECAST PRICES AND COSTS

 
  NET PRESENT VALUES OF FUTURE NET REVENUE
BEFORE INCOME TAXES DISCOUNTED AT (%/year)
 
RESERVES CATEGORY
  0%   5%   10%   15%   20%  
 
  (in U.S.$ million)
 

PROVED:

                               

Developed Producing

    801.5     606.7     500.7     434.1     388.0  

Developed Non-Producing

                     

Undeveloped

    1,512.5     845.1     506.2     311.4     189.5  
                       

TOTAL PROVED

    2,314.0     1,451.8     1,006.9     745.5     577.5  

PROBABLE

    141.3     75.3     44.0     26.9     16.5  
                       

TOTAL PROVED PLUS PROBABLE

    2,455.2     1,527.2     1,050.9     772.3     594.0  
                       

POSSIBLE(1)

    1,133.5     552.1     308.0     183.3     112.0  

TOTAL PROVED PLUS PROBABLE PLUS POSSIBLE(1)

    3,588.8     2,079.3     1,358.9     955.6     706.0  
                       

Note:

(1)
Possible reserves are those reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.


 
  NET PRESENT VALUES OF FUTURE
NET REVENUE
AFTER INCOME TAXES DISCOUNTED
AT (%/year)
 
RESERVES CATEGORY
  0%   5%   10%   15%   20%  
 
  (in U.S.$ million)
 

PROVED:

                               

Developed Producing

    658.2     520.1     445.8     397.8     363.2  

Developed Non-Producing

                     

Undeveloped

    1,026.5     551.2     319.9     188.5     105.5  
                       

TOTAL PROVED

    1,684.7     1,071.3     765.7     586.3     468.7  

PROBABLE

    86.4     42.1     23.0     13.0     7.0  
                       

TOTAL PROVED PLUS PROBABLE

    1,771.1     1,113.4     788.7     599.3     475.7  
                       

POSSIBLE(1)

    681.8     278.9     286.9     169.4     102.5  

TOTAL PROVED PLUS PROBABLE PLUS POSSIBLE(1)

    2,452.9     1,392.3     1,075.6     768.7     578.2  
                       

Note:

(1)
Possible reserves are those reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

40


        The following table discloses, by production group, the net present value to Aurora of future net revenue attributable to its reserves, before deducting future income tax expenses, estimated using forecast prices and costs, and calculated using a 10% discount rate.


FUTURE NET REVENUE
BY PRODUCTION GROUP
AS OF DECEMBER 31, 2012
FORECAST PRICES AND COSTS

RESERVES
CATEGORY
  PRODUCTION GROUP   FUTURE NET REVENUE
BEFORE INCOME TAXES
(discounted at 10%/year)
  UNIT VALUE(1)  
 
   
  (U.S.$000s)
  (U.S.$/Boe)
  (U.S.$/Mcfe)
 

Proved

  Light and Medium Crude Oil (including solution gas and other by-products)     495,077     21.39      

  Natural Gas Liquids     407,134     13.97      

  Natural Gas (including by-products)     104,655         0.99  
                       

  Total     1,006,866              
                       

Proved plus Probable

  Light and Medium Crude Oil (including solution gas and other by-products)     507,254     20.95      

  Natural Gas Liquids     427,241     13.43      

  Natural Gas (including by-products)     116,396         0.97  
                       

  Total     1,050,891              
                       

Proved plus Probable plus Possible(2)

  Light and Medium Crude Oil (including solution gas and other by-products)     482,192     18.54      

  Natural Gas Liquids     672,657     11.40      

  Natural Gas (including by-products)     203,992         0.87  
                       

  Total     1,358,841              
                       

Notes:

(1)
Unit values are based on net reserve volumes.

(2)
Possible reserves are those reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

41


Pricing and Cost Assumptions

        The forecast pricing parameters used in the Aurora 2012 Reserves Report were accepted by Ryder Scott and were based on the December 31, 2012 forward strip NYMEX West Texas Intermediate prices for oil and condensate sales and Henry Hub prices for natural gas sales, without adjustment for inflation. NGL sales are referenced to Mt. Belvieu Texas Propane but were estimated at 30% of the oil pricing. These prices are shown in the following table and are then further adjusted for gravity, quality, local conditions and/or distance from market to calculate reserves.


SUMMARY OF PRICE ASSUMPTIONS
AS OF DECEMBER 31, 2012
FORECAST PRICES AND COSTS

Period ended
  NYMEX
West Texas
Intermediate Price
(U.S.$/Bbl)
  Natural Gas Price
(U.S.$/MMbtu)
 

Historical prices

             

12-31-2012

    94.10     2.71  

Forecast prices

             

12-31-2013

    93.19     3.56  

12-31-2014

    92.36     4.03  

12-31-2015

    90.26     4.23  

12-31-2016

    88.29     4.42  

12-31-2017 and thereafter

    86.88     4.63  

        For the proved reserves lease and well operating costs were estimated at U.S.$7,000 per well, per month for the fixed costs and U.S.$4.00/Boe for the variable component. For the probable and possible reserve cases these figures were decreased to U.S.$6,000 per well per month for the fixed costs and U.S.$3.00/Boe for the variable. Gross capital development costs for a 5,000 foot lateral were estimated at U.S.$8.9 million per well for 2012 with adjustment for variation in horizontal section length, then U.S.$7.8 million for 2013 and thereafter again adjusting for horizontal section length. These capital costs include the drilling, stimulation, completion, production line tie-in and associated field infrastructure.

Reconciliation of Changes in Reserves

        The following table sets forth a reconciliation of Aurora's total gross (before royalty) proved, probable and proved plus probable reserves from the Sugarkane Field as at December 31, 2012 against such reserves as at December 31, 2011, based on forecast price and cost assumptions.

 
  LIGHT AND MEDIUM OIL   NATURAL GAS LIQUIDS   NATURAL GAS  
FACTOR
  Gross
Proved
(Mbbls)
  Gross
Probable
(Mbbls)
  Gross
Proved
Plus
Probable
(Mbbls)
  Gross
Proved
(Mbbls)
  Gross
Probable
(Mbbls)
  Gross
Proved
Plus
Probable
(Mbbls)
  Gross
Proved
(MMcf)
  Gross
Probable
(MMcf)
  Gross
Proved
Plus
Probable
(MMcf)
 

December 31, 2011

    30,352     4,561     34,913     30,649     4,329     34,977     116,297     16,861     133,157  

Extensions & Improved Recovery

    4,229     850     5,079     5,037     291     5,328     18,895     2,275     21,170  

Technical Revisions

    (3,046 )   (3,985 )   (7,031 )   (4,332 )   (2,710 )   (7,042 )   (18,315 )   (8,581 )   (26,896 )

Discoveries

                                     

Acquisitions

    1,806         1,806     9,380     1,681     11,061     30,198     8,337     38,535  

Dispositions

                                     

Economic Factors

    8     7     15     1     4     5     6     23     29  

Production

    (1,902 )       (1,902 )   (1,301 )       (1,301 )   (4,226 )       (4,226 )

December 31, 2012

    31,446     1,433     32,879     39,433     3,595     43,028     142,854     18,915     161,769  

42


Additional Information Relating to Reserves Data

Undeveloped Reserves — Proved Undeveloped Reserves

        The following table sets forth the volumes of net (after royalty interests) proved undeveloped reserves that were first attributed for the years ended December 31 2010, 2011 and 2012. These figures are net of royalties paid.

 
  LIGHT AND MEDIUM OIL
(Mbbls)
  NATURAL GAS LIQUIDS
(Mbbls)
  NATURAL GAS
(MMcf)
 
 
  First
Attributed(1)
  Cumulative at
Year End
  First
Attributed(1)
  Cumulative at
Year End
  First
Attributed(1)
  Cumulative at
Year End
 

Year

                                     

2010

    271     271     5,381     5,381     24,101     24,101  

2011

    21,985     20,209     16,426     21,261     58,713     79,982  

2012

    890     17,436     6,702     22,653     20,284     83,263  

Note:

(1)
First Attributed is annual change in proved undeveloped reserves plus those that have been developed in the period.

        Proved undeveloped reserves are generally those reserves related to wells that have been tested and not yet tied-in, wells drilled near the end of the fiscal year or wells further away from Aurora's gathering systems. In addition, such reserves may relate to planned infill drilling locations. The majority of these reserves are planned to be on stream within a five year timeframe.

Undeveloped Reserves — Probable Undeveloped Reserves

        The following table sets forth the volumes of probable undeveloped reserves that were first attributed for the years ended December 31 2010, 2011 and 2012.

 
  LIGHT AND MEDIUM OIL
(Mbbls)
  NATURAL GAS LIQUIDS
(Mbbls)
  NATURAL GAS
(MMcf)
 
 
  First
Attributed(1)
  Cumulative at
Year End
  First
Attributed(1)
  Cumulative at
Year End
  First
Attributed(1)
  Cumulative at
Year End
 

Year

                                     

2010

    290     290     5,903     5,903     31,171     31,171  

2011

    25,719     3,024     13,472     2,950     38,952     11,409  

2012

    (1,065 )   1,069     6,430     2,677     22,966     14,091  

Note:

(1)
First Attributed is annual change in proved undeveloped reserves plus those that have been developed in the period.

        Probable undeveloped reserves are generally those reserves tested or indicated by analogy to be productive, infill drilling locations and lands contiguous to production. The majority of these reserves are planned to be on stream within a five year timeframe.

        Under the terms of the mineral leases in which Aurora holds an interest, there are requirements to drill and produce a well to hold the acreage past its primary terms. The joint operating arrangements in which Aurora has participated therefore focused the early drilling program on ensuring that all acreage was held by production, before infill drilling occurs. Thereafter, the drilling has been carried out in order to maximize the efficiency and minimize costs, with wells being drilled in batches from common surface locations.

Significant Factors or Uncertainties

        The process of evaluating reserves is inherently complex. It requires significant judgments and decisions based on available geological, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on the then-current production forecasts, geological evaluation, engineering data, prices and economic

43


conditions. The reserves associated with the assets described in the Aurora 2012 Reserves Report have been evaluated by Ryder Scott and considering certain factors and assumptions. These factors and assumptions include among others: (i) historical production in the area compared with production rates from analogous producing areas; (ii) initial production rates; (iii) production decline rates; (iv) ultimate recovery of reserves; (v) success of future development activities; (vi) marketability of production; (vii) effects of government regulations; and (viii) other government levies imposed over the life of the reserves. See also, "Risk Factors".

        As circumstances change and additional data becomes available, reserve estimates also change. Estimates are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions. Revisions to reserve estimates can arise from changes in year-end prices, reservoir performance and geologic conditions or production. These revisions can be either positive or negative.

Future Development Costs

        The table below summarizes Aurora's share of the future development costs for the Sugarkane Field project based on the Ryder Scott development schedule used in the Aurora 2012 Reserves Report.

 
  FUTURE DEVELOPMENT COSTS
AS OF DECEMBER 31, 2012
FORECAST PRICES
 
Year
  Proved Reserves   Proved Plus Probable Reserves  
 
  (U.S.$000s)
  (U.S.$000s)
 

2013

    255,740.1     263,683.4  

2014

    252,159.5     255,731.5  

2015

    271,278.3     280,252.0  

2016

    239,310.8     300,199.3  

2017

    200,183.0     210,829.5  

2018+

    28,304.6     28,304.6  
           

Total (Undiscounted)(1)

    1,258,254.8     1,350,857.1  
           

Note:

(1)
Includes capital expenditure on abandonment obligations at end of field life.

Other Oil and Gas Information

Oil and Natural Gas Properties

        All principal properties of Aurora are located in the Sugarkane Field in Texas, United States. There are no properties in which Aurora has an interest to which reserves have been attributed which are not planned to be developed.

        Aurora's principal assets and the approximate associated gross and net land positions as of December 31, 2012, excluding the 2013 Acquired Assets, are shown in the table below:

 
  AVERAGE WORKING
INTEREST
  GROSS ACREAGE   NET ACREAGE  

Sugarloaf AMI

    28.1%     24,300     6,700  

Longhorn AMI

    31.9%     28,100     8,900  

Ipanema AMI

    36.4%     4,500     1,600  

Excelsior AMI

    9.1%     20,200     1,800  
                 

Total

          77,000     19,100  
                 

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Operating Arrangements for Aurora's Principal Properties

        The operations within each of the four Sugarkane Field AMIs are governed by a JOA, under which Marathon is the designated operator. Aurora's interests within each of the Sugarloaf, Longhorn, and Ipanema AMIs are also subject to farmout arrangements. Aurora's interests and operations related within the acreage associated with the 2013 Acquired Assets are not subject to any JOA or farmout agreements.

        Farmout arrangements provide an incentive to operators to drill a producing well in exchange for a WI in those wells and generally in the related AMI. Under Aurora's farmout arrangements, it has no WIs in the farmout wells until payout on each separate farmout program is achieved, but this does not impact Aurora's post-farmout WIs on any other wells in the same contract area. Payout occurs when the farminor receives from WI revenues, net of operating costs, an amount equal to the costs incurred by the farminor within each separate farmout program. The farminor is entitled to receive a 100% priority return from each farmout program until repayment of all costs plus an amount equal to a 12% internal rate of return on such costs. Aurora's WIs are presented above on the basis of interests in the contract area (on a post-farmout basis) and not on a per-well basis. Once each farmout program reaches payout, Aurora starts to receive an interest of production from the wells within that farmout program as per the farmout agreements.

        The following two farmout programs had not reached payout as of December 31, 2013: three wells in Longhorn and one well in Ipanema. Payout has been achieved on all wells in Sugarloaf and Aurora is receiving revenue based on its WIs in each of these three wells.

        A JOA grants authority to, and delineates the responsibilities of, the party acting as the operator in the AMI. A JOA also outlines the rights that WI holders are entitled to, including participation in wells, access to newly acquired leases within a specified area, revenue distributions and access to information. The terms of the JOA for each of Aurora's AMIs are substantially similar and are described in more detail below.

        Under each JOA, Marathon, as the operator, generally incurs the initial costs for drilling operations and related costs, including equipment expenses, labour expenses, royalties, expenses for title examinations, legal expenses, taxes and insurance expenses. The operator has the right to be reimbursed from the other parties to the relevant JOA who have elected to participate in proportion to their respective WIs and may request payment of certain expenses and estimated capital costs in advance. Similarly, production of oil and natural gas from the relevant AMI is shared among the participants in the AMI in proportion to each participant's WI in that AMI, subject to any farmout, royalty agreements or other agreements impacting a party's WI. The operator has no obligation under the JOA to provide a schedule of long-term future operations or expenses.

        The operator generally establishes the drilling program; however, each party to a JOA has the right at any time to propose the drilling of a new well or reworking of existing wells in the relevant AMI. The proposing party must consult with the other parties to the JOA at least 30 days prior to providing notice of such proposal to the other parties, which notice must include or be accompanied by an itemized report detailing, among other things, the estimated cost of the proposed operations. After notice of such a proposal, the other parties to the JOA have 30 days (or 24 hours, if a rig is on location) to consent to participating in the cost of the proposed operations. If a party does not consent or reply within the required time period, such party will not have to pay any costs associated with the proposed operations. However, such non-consenting party will relinquish its rights to the production of oil and gas from the proposed operations. Under the terms of the JOA, and subject to the following paragraph, such non-consenting party will relinquish its interest in the production until the consenting parties are reimbursed for their costs and expenses in the proposed operations, including costs for equipment, and for an additional amount, which generally ranges from one and one half times to four times the costs and expenses for the operations. Once these reimbursement amounts are paid, the WI of the non-consenting party is restored.

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        However, notwithstanding the previous paragraph, in the circumstances described below, any non-consenting party relinquishes all rights to the production of oil and gas from the proposed operations:

        The operator will perform all of the proposed work for the consenting parties where less than all parties participate in operations; provided, however, that if the operator is a non-consenting party and there is no drilling rig already present at the proposed location of the operations, the consenting parties must either formally request that the operator commence operations or designate one of the consenting parties as operator for such proposed work.

        Under each of the JOAs, any and all losses incurred through title failures are shared jointly between all parties to the JOA in proportion to their WIs. In effect, these provisions provide that even though Aurora was not a party to the original leases underlying a particular AMI, it will share in any loss of those leases that may occur as a result of title problems.

        If a party to a JOA acquires or obtains the right to acquire from anyone not a party to the JOA any additional leasehold or other oil and gas interest within the AMI, that party must notify the other parties of the acquisition of such interests or a right to acquire such interests and the other parties may mutually agree to acquire such interests in proportion to their WIs. If all parties to the JOA agree to participate in such acquisition, in proportion to their WIs in the AMIs, such interests will become subject to the terms of the JOA. Further, if all parties to the JOA acquire additional interests that become subject to the JOA, the parties have agreed to assign or reserve for the party to the JOAs who was the original operator an overriding royalty with respect to the acquired interest (subject to a cap that ranges from 4% to 6% of the interest acquired).

        Aurora is generally able to divest its WIs in the JOAs; however, under the Sugarloaf, Ipanema and Longhorn JOAs, any assignment is subject to the written consent of the party to the JOA who was the original operator, which must not be unreasonably withheld upon receipt of proof that the proposed assignee is financially capable of fulfilling its obligations in respect of the WI. Additionally, under each of the Longhorn and Ipanema JOAs, Aurora must provide notice to the operator of any proposed divestment of WIs and the operator will have a pre-emptive right to acquire any such interests on the same terms as proposed, except in the case of assignments by way of mortgage or disposal of WIs by way of merger, reorganization, consolidation or sale of all

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or substantially all of Aurora's assets to a subsidiary or parent company or to a subsidiary of a parent company or to a third party in which any one party owns a majority of the stock.

        Under the JOAs, the operator and other parties in each JOA have a first priority lien in Aurora's oil and gas rights in the relevant AMI and a security interest in its share of oil and/or gas when extracted and in all equipment purchased under the relevant JOA. If Aurora fails to fully discharge its financial obligations, including making payments in advance to the operator as described above, it will be in default under the JOAs. Subject to certain cure periods, upon default, Aurora may be sued for damages, its production revenues may be directed to the operator and it may be deemed to be a non-consenting party with respect to certain wells. The operator grants a like lien and security interest to the non-operators to secure payment of operator's proportionate share of expense.

        Under each of the JOAs, the operator may resign at any time on written notice and will be deemed to resign if it terminates its legal existence, is no longer capable of serving as operator or it no longer owns an interest in the area subject to the JOA. The operator can be removed if it fails or refuses to carry out its duties under the JOA or becomes insolvent, bankrupt or is placed in receivership, by the affirmative vote of two or more of the non-operating parties owning a majority of the WIs in the relevant contract area. Such resignation or removal is effective on the first day of the calendar month following a 90-day period from the date of written notice or action by the non-operators, as applicable, unless a successor operator is selected prior to that date.

        Where an operator has resigned or has been removed under the foregoing circumstances, the successor operator shall be selected from the parties holding WIs in the relevant contract area, by an affirmative vote of two or more parties owning a majority of the WIs. An operator that has been removed must participate in voting for a successor operator, but may be excluded from the vote if it fails to vote or votes only to succeed itself, at which point the successor operator shall be selected by the affirmative vote of two or more parties owning a majority interest based on ownership remaining after excluding the voting interest of the operator that was removed.

Wells

        Aurora's wells produce light and medium oil, NGLs (including condensate) and natural gas, with the ratio of gas to liquids production varying by well. The gas to liquids ratio observed across the gas condensate wells varies between 60 and 400 Bbls per MMcf. The volatile oil wells produce at approximately 1,000 Mcf/Bbl. The following table sets out the number of producing and non-producing wells net to Aurora's WI, both before royalties and after royalties, in the Sugarkane Field as at December 31, 2012.

Net Wells as at December 31, 2012
  Before Royalties   After Royalties  

Producing

    50.5     37.3  

Drilled, not producing

    4.4     3.2  
           

Total Net Wells

    54.9     40.5  
           

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        The following table summarizes the status of wells in which Aurora had a gross WI, categorized by Sugarkane Field AMI, as of December 31, 2012.

 
  SUGARLOAF   LONGHORN   IPANEMA   EXCELSIOR   TOTAL  

Farmout Wells(1)

                               

Producing — subject to payout

        3.0     1.0         4.0  

Post-Farmout Wells

                               

Producing

    57.5     19.2     6.0     60.0     216.0  

On test

                     

Fracking

        4.0         4.0     8.0  

Drilled and Cased

    3.5     5.5         3.0     12.0  

Drilling

    4.0     3.0             7.0  
                       

Total Gross Wells

    65.0     108.0     7.0     67.0     243.0  
                       

Note:

(1)
Once the farmout wells are paid out, Aurora will start to receive an interest of production from these farmout wells as per the farmout agreements.

Leasehold Interests and Royalties

        In Texas, mineral rights may be held privately or by the government. In the Eagle Ford, substantially all of the mineral interests are owned and leased by private owners. To drill wells or produce oil and gas, a company must either own the mineral rights or lease them from the mineral rights holder. Generally, Aurora's leases are for a primary term of five years. Marathon, as operator, has responsibility of managing the lease administration for Aurora's Sugarkane AMIs.

        Aurora has an interest in numerous individual leases from private lessors across its four AMIs and in the 2013 Acquired Assets within the Sugarkane Field, each of which is current (typically a cash bonus and delay rental was paid upon execution of the lease with no such additional payments being required within the primary term of the lease). The undeveloped portion of the leaseholds under these leases generally expire between 2014 and 2015. The leases contain provisions requiring that the acreage be developed within a specified lease period or else it must be re-leased. The development provisions of these leases generally require the drilling of one or more wells that produce hydrocarbons from which the mineral owners derive royalties. Each producing well will hold a certain amount of land while it is still producing, hence the reference to "land held by production". The specific details of each lease and royalty rate are different as they are individually negotiated but, in general, the net revenue interests for the WI participants, including Aurora, ranges from 70 to 75% with an average across Aurora's current acreage of approximately 74%.

        Over time, each field designated by the Railroad Commission of Texas will have its own rules depending on the individual characteristics of the field. Approximately half of the Sugarkane Field has been designated as a natural gas field and the remainder as an oil field. Under these designations, operators are able to hold a certain number of acres around every producing well drilled (depending on the well length) per the specific field rules. The rules currently in effect for natural gas wells within the Sugarkane Field allow each well to hold up to 320 acres plus an additional 200 acres for each 1,000 feet of horizontal well. A typical 5,000 foot horizontal well is therefore able to hold up to 1,320 acres, although units are generally 600 to 900 acres. The northern half of the Sugarkane Field falls within two Railroad Commission designated fields: the Eagleville I Field and the Eagleville II Field. These fields have been designated as oil fields. Under the relevant field rules, operators are able to hold on average 320 acres for wells with lateral lengths of 5,000 feet plus additional acreage for longer laterals.

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Properties With No Attributed Reserves

        The following table sets forth the gross and net acres of unproved properties held by Aurora, as of December 31, 2012, and the net area of unproved property for which Aurora expects its rights to expire during the next year.

 
  UNDEVELOPED LAND (ACRES)  
 
  Gross   Net   Net Area to Expire in
2013
 

South Texas, Flour Bluff Field

    1,400     280      

California, North Belridge

    125     40      

South Texas, Pan de Azucar and Brioche

    5,260     5,260     5,160  
               

Total

    6,785     5,580     5,160  
               

        Other than immaterial abandonment costs liability for two wells at North Belridge, Aurora does not have work commitments on the above lands.

Additional Information Concerning Abandonment and Reclamation Costs

        Aurora estimates the costs associated with well abandonment and reclamation based on its previous experience, current regulations, costs, technology and industry standards area by area. Abandonment and reclamation costs are expected to be incurred on 785 gross (182 net) well locations for the proved full field development. These wells are comprised of currently producing, non-producing, planned production and service wells.

        Aurora's share of the expected total abandonment and reclamation costs for wells with assigned reserves, non-producing and service wells and facilities, net of salvage value are summarized, without discount and using a discount rate of 10%, in the following table.

NET PRESENT VALUES OF FUTURE NET REVENUE
BEFORE INCOME TAXES DISCOUNTED AT (%/year)
USING FORECAST PRICING AND COSTS

 
  PROVED NET PRESENT VALUE   PROVED PLUS PROBABLE
NET PRESENT VALUE
 
CATEGORY
  0%   10%   0%   10%  
 
  (U.S.$000s)
  (U.S.$000s)
 

Abandonment and disconnect costs for wells with reserves assigned

    9,023     382.5     9,486     402.1  

Reclamation costs for wells with reserves assigned

    2,256     95.6     2,371     100.5  

Abandonment and reclamation costs for wells with no reserves assigned and facilities

                 

Total abandonment and reclamation cost provision

    11,279     478.1     11,587     502.6  

Portion of the above total:

                         

forecast to be paid during the next three years; and

                 

not included in the Aurora 2012 Reserves Report

                 

Notes:

(1)
For the full field development at the effective date of the Aurora 2012 Reserves Report there are 182 net proved wells and 11 net probable wells.

(2)
Well life has been modeled for 30 years and abandonment liability is discounted accordingly.

(3)
For the purposes of this table, management's estimated aggregate abandonment and reclamation costs have been allocated 80% as to abandonment costs and 20% as to reclamation costs.

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Costs Incurred

        The following table summarizes Aurora's property acquisition costs, exploration costs and development costs (before property dispositions) incurred during the year ended December 31, 2012.

EXPENDITURE
  YEAR ENDED
DECEMBER 31, 2012
 
 
  (U.S.$000s)
 

Property acquisition costs:

       

Proved properties

    13,900  

Unproved properties

    4,606  

Drilling and completion:

       

Proved properties

    575,933  

Unproved properties

    1,473  

Facilities and equipment:

       

Proved properties

    104,215  

Unproved properties

     

Exploration costs

     

Development costs

     
       

Total

    700,127  
       

Exploration and Development Activities

        The following table sets forth the number and status of wells in which Aurora had a working interest as at December 31, 2012.

 
  DEVELOPMENT(1)   EXPLORATORY  
 
  Gross   Net   Gross   Net  

Light and Medium Oil

    100     23.64          

Natural Gas

    56     15.16          

Service

                 

Stratigraphic Test

                 

Dry

                 
                   

Total

    156     38.80          
                   

Note:

(1)
These wells commenced production during 2012 or completed their farmout payout period.

Infrastructure

        There has been considerable focus on the installation of the required infrastructure to allow for full field development in the Sugarkane Field. In the first quarter of 2011, Aurora agreed to the participation and installation of centralized processing facilities across the Sugarkane Field. In total, nine central processing facilities were installed and gathering system improvements made, which provide the following capability:

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        During 2012, the final three central processing facilities were installed and commissioned, the initial six central processing facilities were upgraded for increased capacity and operational efficiency, and the vast majority of the field gathering system was installed (over 300 miles of pipework), including the commissioning of the Three Rivers oil pipeline which crosses the Excelsior and Longhorn AMIs. We expect future production to be accommodated within the existing infrastructure and planned capacity upgrades as necessary.

        It is anticipated that the efficiencies of these central processing facilities will lead to material savings on capital well costs as well as subsequent operating costs. The same central facilities have deep saline water wells and holding pits to allow water storage and real time distribution to fracture stimulation operations. Produced water is separated at the central processing facilities and then recycled back to the pits or disposed of via dedicated disposal wells.

        The gas export system downstream of the central facilities was predominantly built in 2011, with the most recent central facilities having now been tied in. At the end of 2012, an additional interconnect allowed gas exports to a third processing facility and increased the field take away capacity to over 100 MMbtu/day.

        In 2013 Aurora acquired assets in the Sugarkane Field complex known as Heard Ranch and Axle Tree ranch. During 2013/2014, these assets had central facilities and gathering systems installed to manage production expected from the development plans of these assets. In particular the Axle Tree development includes two amine treatment plants to process H2S (up to 6000 ppm from some wells) out of the gas for sale or field use.

Marketing and Sales of Production

        Production from Aurora's leases is moved from individual well test facilities via inter-field transfer lines to central processing facilities where oil, condensate, natural gas liquids and natural gas are treated to sales quality, products are metered and gas compressed up to pipeline inlet pressure specification. Afterwards, treated production is sold either at the lease or moved via truck or pipeline to the particular market for sale.

        Currently, Aurora's share of production from the Sugarkane Field AMIs is marketed and sold on its behalf by Marathon, as operator. Under the terms of its JOAs, Aurora has the right to separately dispose of its share of hydrocarbon production from its AMIs under different arrangements, including, without limitation, through different agents. Aurora is responsible for marketing and sales of hydrocarbon production from its operated acreage.

        Marathon sells oil, condensate, NGLs and natural gas under a variety of arrangements with the realised price in reference to a range of local prevailing spot markers adjusted for gravity, quality, local conditions and any relevant costs incurred.

        Future production associated with Aurora's assets will require transportation, storage and processing capacity to be either constructed or contracted, as well as additional marketing efforts to commit products to sale. Significant regional processing and transportation infrastructure has been constructed or is under construction, with significant additional capacity expected in the area and prospective markets being examined and discussed.

        Aurora's properties are accessible year round. Facilities through which its production is processed and/or delivered may be temporarily shut down for a short period of time during the year to conduct repair and maintenance operations.

Production Estimates

        The following tables summarize Aurora's estimated future annual production volumes for the assets evaluated in the Aurora 2012 Reserves Report for the 12 months beginning January 1, 2013 and ending December 31, 2013 for each product type, which is reflected in the estimate of future net revenues disclosed

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earlier in this section using the forecast prices contained in the table entitled "Summary of Price Assumptions as of December 31, 2012 (Forecast Prices and Costs)".

RESERVE CATEGORY
  LIGHT AND
MEDIUM OIL
  NATURAL GAS
LIQUIDS
  NATURAL GAS   COMBINED  
 
  (Bbls/d)
  (Bbls/d)
  (Mcf/d)
  (Boe/d)
 

Proved

                         

Developed producing

    3,964     4,896     15,844     11,501  

Developed Non-Producing

                 

Undeveloped

    3,140     1,907     6,370     6,109  
                   

Total Proved

    7,104     6,803     22,215     17,610  

Probable

        122     609     224  
                   

Total Proved plus Probable

    7,104     6,926     22,824     17,834  

Possible(1)

                 
                   

Total Proved plus Probable plus Possible

    7,104     6,926     22,824     17,834  
                   

Note:

(1)
Possible reserves are those reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Production Volume

        The following table discloses Aurora's net production volumes for the year ended December 31, 2012 based on 365 days for each product type from the Sugarkane Field.

 
  Light and
medium oil
  Natural gas
liquids
  Natural gas   Combined  
 
  (Bbls)
  (Bbls)
  (Mcf)
  (Boe)
 

    1,395,904     963,415     3,115.8     2,878,612  

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Production History

        The following table summarizes Aurora's share of average daily gross production for each of the periods indicated.

 
  Financial Year Ended December 31, 2012  
 
  Three Months
Ended March 31,
2012
  Three Months
Ended June 30,
2012
  Three Months
Ended September 30,
2012
  Three Months
Ended December 31,
2012
 

Light and Medium Oil

                         

Average daily production (Bbls/d)

    3,052     5,792     5,885     6,046  

Prices received (U.S.$/Bbl)

    110.41     94.70     101.29     95.46  

Royalties paid (U.S.$/Bbl)

    29.68     25.60     26.90     24.87  

Production costs (U.S.$/Bbl)(1)

    13.80     11.50     12.40     10.44  

Resulting netback (U.S.$Bbl)(2)

    66.93     57.60     61.98     60.15  

Natural Gas Liquids

                         

Average daily production (Bbls/d)

    541     939     1,934     2,656  

Prices received (U.S.$/Bbl)

    55.13     22.93     30.16     34.58  

Royalties paid (U.S.$/Bbl)

    13.53     6.33     7.95     9.03  

Production costs (U.S.$/Bbl)

    7.83     2.69     3.87     4.16  

Resulting netback (U.S.$Bbl)(2)

    33.77     13.91     18.33     21.39  

Condensate Gas Liquids

                         

Average daily production (Bbls/d)

    409     466     2,354     4,872  

Prices received (U.S.$/Bbl)

    124.22     101.72     101.32     98.35  

Royalties paid (U.S.$/Bbl)

    32.74     24.86     26.21     25.59  

Production costs (U.S.$/Bbl)(1)

    15.41     12.40     11.58     10.77  

Resulting netback (U.S.$Bbl)(2)

    76.07     64.46     63.53     61.99  

Natural Gas

                         

Average daily production (MMcf/d)

    4.91     7.00     14.15     20.00  

Prices received (U.S.$/Mcf)

    2.54     1.81     2.53     3.73  

Royalties paid (U.S.$/Mcf)

    0.58     0.50     0.67     0.98  

Production costs (U.S.$/Mcf)(1)

    0.35     0.15     0.33     0.39  

Resulting netback (U.S.$/Mcf)(2)

    1.61     1.16     1.54     2.36  

Notes:

(1)
The calculation of production costs allocates operating costs on a prorated basis from production volumes in Boes.

(2)
Netbacks have been calculated as the price received subtracting royalties and production costs.

        Although there were 220 producing wells on the Sugarloaf, Ipanema, Excelsior and Longhorn AMIs during the year ended December 31, 2012, due to its farm-out arrangements, Aurora did not have an interest in production in four of these wells during this entire period and did not have an interest in production of two other wells to the period ended March 31, 2012.

Other Interests and Investments

        Aurora has a minor interest in undeveloped acreage in the Eagle Ford in two separate development areas in Fayette County, Washington and Burleson Counties, located in Southeast Texas and a small WI in producing acreage in Fayette County and in the associated producing Black Jack Springs Unit #1 well.

        Aurora also has an immaterial interest in non-U.S. and offshore activities through its equity investment in Elixir. Elixir holds a diversified portfolio of oil and natural gas interests across the exploration, appraisal, development and production spectrum, including: oil and natural gas development and production from the shallow shelf in the Gulf of Mexico, United States; exploration and appraisal activities in the northern North

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Sea, United Kingdom; and a very large acreage position of approximately 1.3 million acres onshore France in the East Paris Basin prospective for both conventional and unconventional hydrocarbon bearing formations.


USE OF PROCEEDS

        The gross proceeds from the Offering will be held by the Escrow Agent, and invested in short-term obligations of, or guaranteed by, the Government of Canada (or other approved investments) pending the satisfaction of the Escrow Condition. Upon satisfaction of the Escrow Condition on or before the Termination Time, the Escrowed Funds and the interest earned thereon (less any amounts required to pay the Dividend Equivalent Amount upon the issuance of the Underlying Common Shares, if applicable) will be released to us to enable us to convert these funds to Australian dollars and complete the Acquisition. We will utilize the Escrowed Funds, together with funds available under the New Credit Facilities, to pay for Aurora Shares pursuant to the Acquisition. See "Recent Developments — New Credit Facilities".

        On the closing of the Acquisition, each holder of Subscription Receipts will receive one Underlying Common Share for each Subscription Receipt held, without payment of additional consideration or further action on the part of such holder, and such holder will also be entitled to receive an amount per Subscription Receipt equal to the Dividend Equivalent Amount. If the Acquisition is not completed by the Termination Time, or if we advise the Underwriters or announce to the public that we do not intend to proceed with the Acquisition, or if the Implementation Agreement has been terminated in accordance with its terms, holders of Subscription Receipts shall receive an amount equal to the full subscription price attributable to the Subscription Receipts and their pro rata entitlement to interest accrued on such amount up to and including the date of the Termination Time. See "Details of the Offering".

        The following table sets forth the principal purposes to which we propose to use the net proceeds of the Offering:

Proceeds to Us
  Offering not including
Over-allotment Option
  Offering including full exercise of
Over-allotment Option
 
 
  ($000s)
  ($000s)
 

Gross proceeds raised pursuant to this Offering(1)

         

Underwriters' Fee(2)

    (• )   (• )

Expenses and costs relating to the Offering

    (• )   (• )

Total estimated net proceeds to the Corporation

         

Funds from the Offering used to fund the purchase price for Aurora Shares(2)

         

Remaining portion of purchase price for Aurora Shares to be funded by the New Credit Facilities(3)

         

Notes:

(1)
The gross proceeds of the Offering will be held in escrow by the Escrow Agent pending satisfaction of the Escrow Condition on or before 5:00 p.m. (Calgary time) on June 30, 2014. See "Details of the Offering".

(2)
The Underwriters' Fee is payable as to 50% upon the closing of the Offering and 50% upon the closing of the Acquisition. If the Acquisition has not occurred by the Termination Time, the Underwriters' Fee will be reduced to the amount payable upon closing of the Offering. See "Details of the Offering" and "Plan of Distribution".

(3)
See "Recent Developments — The Acquisition" and "About Aurora".

        The use of the net proceeds of the Offering is consistent with our stated business objective of acquiring, developing, exploiting and holding interests in petroleum and natural gas properties and related assets in Canada and the United States. Other than the successful completion of the Offering, there is no particular significant event or milestone that must occur for this objective to be accomplished.

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DESCRIPTION OF COMMON SHARES

        Our authorized capital consists of an unlimited number of Common Shares without nominal or par value and 10,000,000 preferred shares, without nominal or par value, issuable in series.

        Holders of Common Shares are entitled to notice of, to attend and to one vote per share held at any meeting of our Shareholders (other than meetings of a class or series of our shares other than the Common Shares as such).

        Holders of Common Shares will be entitled to receive dividends as and when declared by the Board of Directors on the Common Shares as a class, subject to prior satisfaction of all preferential rights to dividends attached to shares of other classes of our shares ranking in priority to the Common Shares in respect of dividends.

        Holders of Common Shares will be entitled in the event of any liquidation, dissolution or winding-up of us, whether voluntary or involuntary, or any other distribution of our assets among our shareholders for the purpose of winding-up our affairs, and subject to prior satisfaction of all preferential rights to return of capital on dissolution attached to all shares of other classes of our shares ranking in priority to the Common Shares in respect of return of capital on dissolution, to share ratably, together with the holders of shares of any other class of our shares ranking equally with the Common Shares in respect of return of capital on dissolution, in such of our assets as are available for distribution.

Dividend Policy

        Our dividend policy is to pay a monthly dividend on our Common Shares on or about the 15th day following the end of each calendar month to Shareholders of record on or about the last business day of each such calendar month. Our dividend policy follows the general corporate philosophy of financial self sufficiency whereby, over the long term, development capital expenditures and dividend payments are planned to be financed from internally generated funds from operations. Unless otherwise indicated, all dividends paid or to be paid on our Common Shares are designated as "eligible dividends" for Canadian income tax purposes.

        The amount of future cash dividends, if any, will be subject to the discretion of the Board of Directors and may vary depending on a variety of factors and conditions existing from time to time, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates, the satisfaction of the liquidity and solvency tests imposed by the ABCA for the declaration and payment of dividends and other factors beyond our control. Pursuant to the ABCA, after the payment of a dividend, we must be able to pay our liabilities as they become due and the realizable value of our assets must be greater than our liabilities and the legal stated capital of our outstanding securities. As at September 30, 2013, our stated capital was approximately $2 billion. Cash dividends to Shareholders are not assured or guaranteed and there can be no guarantee that we will maintain our dividend policy. See "Dividends to Shareholders" and "Risk Factors".

        The agreement governing the Credit Facilities, the New Credit Facilities and the Debenture Indenture restrict or will restrict our ability to pay cash dividends in certain circumstances and contain certain limitations on maximum cumulative dividends. See "Dividends to Shareholders", "Consolidated Capitalization" and "Recent Developments — New Credit Facilities".

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CONSOLIDATED CAPITALIZATION

        The following table sets forth, as at September 30, 2013, our pro forma consolidated capitalization: (i) before giving effect to the Offering and Acquisition; (ii) after giving effect to the Offering and Acquisition (assuming the Over-allotment Option is not exercised); and (iii) after giving effect to the Offering and Acquisition (assuming the Over-allotment Option is exercised in full). There have been no material changes in our share and loan capital, on a consolidated basis, since September 30, 2013.

 
  As at September 30, 2013
before giving effect to the
Offering and the Acquisition
  As at September 30, 2013
after giving effect to the
Offering and the Acquisition(1)
  As at September 30, 2013
after giving effect to the
Offering, the Acquisition and
the Over-allotment Option(1)
 
(amounts in $000s,
except where noted)

   
   
   
 

Debt:

                   

Credit Facilities(2)

    $244,651     $    •          

New Credit Facilities(1)(3)(4)

            $    •      

2021 Debentures(5)

    U.S.$150,000     U.S.$150,000     U.S.$150,000  

2022 Debentures(5)

    $300,000     $300,000     $300,000  

2017 Aurora Notes(5)(6)

        U.S.$365,000     U.S.$365,000  

2020 Aurora Notes(6)

        U.S.$300,000     U.S.$300,000  

Shareholders' Capital:

                   

Common Shares (unlimited)(7)

    $1,969,018
(124,497,000 Common Shares

)
  $    •  
(    •    Common Shares

)
  $    • 
(
    •    Common Shares

)

Preferred Shares (10,000,000)

             

Notes:

(1)
Based on the issuance of    •    Underlying Common Shares pursuant to the exchange of     •    Subscription Receipts for aggregate proceeds of $    •    less Underwriters' Fees of $    •    and expenses of the Offering estimated to be $3 million (exclusive of GST). If the Over-allotment Option is exercised in full, the aggregate gross proceeds, Underwriters' Fees, estimated expenses of the Offering and net proceeds will be $    •    , $    •    , $    •    and $    •    , respectively. The aggregate net proceeds of the Offering will be used to finance a portion of the Acquisition with the balance of the Acquisition to be funded by cash on hand and advances under the New Credit Facilities. We will assume the Aurora Notes at closing. See "Recent Developments — The Acquisition", "About Aurora", "Use of Proceeds" and "Details of the Offering" in this short form prospectus. See also the pro forma financial information in respect of us after giving effect to the Acquisition set forth in Schedule "B" — "Pro Forma Consolidated Financial Statements of Baytex".

(2)
As at September 30, 2013, Baytex Energy had a $40 million extendible operating loan facility with a chartered bank and a $810 million extendible syndicated loan facility with a syndicate of chartered banks, which is extendible annually for a one, two, three or four year period (subject to a maximum four-year term at any time) (the "Credit Facilities"). On June 4, 2013, the maturity date of the Credit Facilities was extended to June 14, 2017. The Credit Facilities contain standard commercial covenants for facilities of this nature. The Credit Facilities do not require any mandatory principal payments during the four-year term. Advances (including letters of credit) under the Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the agent bank's prime lending rate, bankers' acceptance discount rates or London Interbank Offered Rates, plus applicable margins. The Credit Facilities are secured by a floating charge over all of Baytex Energy's assets and are guaranteed by us and certain material restricted subsidiaries. The Credit Facilities do not include a term-out feature or a borrowing base restriction. The Credit Facilities contain restrictions on Baytex Energy's ability to make distributions to us, including the declaration or payment of any dividend or distribution to us as the holder of the capital stock of Baytex Energy and the payment of interest or principal on subordinated debt owed to us. Baytex Energy and its subsidiaries are restricted from making distributions to us when (i) a default or event of default under the Credit Facilities has occurred and is continuing, or (ii) distributions would be reasonably expected to have a material adverse effect on or impair the ability of Baytex Energy to fulfill its financial obligations to its lenders under the Credit Facilities. Baytex Energy is in compliance in all material respects with the terms of the agreements governing the Credit Facilities.

(3)
In connection with the Acquisition, we have entered into an agreement with a Canadian chartered bank for new senior secured credit facilities in the aggregate principal amount of $2.5 billion which will replace our Credit Facilities. See "Recent Developments — New Credit Facilities".

(4)
Does not include working capital deficit of $57.7 million as at September 30, 2013.

(5)
The 2021 Debentures were issued on February 17, 2011, bear interest at a rate of 6.75% and mature on February 17, 2021. The 2022 Debentures were issued on July 19, 2012, bear interest at a rate of 6.625% and mature on July 19, 2022. For information regarding the

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(6)
The 2017 Aurora Notes were issued on February 8, 2012 and the 2020 Aurora Notes were issued on March 21, 2013. Subject to Aurora's obligation to make a Change of Control Offer to the holders of the Aurora Notes as described under "Recent Developments — The Acquisition — Acquisition Consideration", the Aurora Notes will remain outstanding in accordance with their terms following completion of the Acquisition.

(7)
As at September 30, 2013, we had 1,022,000 rights to acquire Common Shares (issued pursuant to our Common Share Rights Incentive Plan) outstanding. In addition, as at September 30, 2013, we had 733,000 restricted awards and 597,000 performance awards (granted pursuant to our Share Award Incentive Plan) outstanding.


DETAILS OF THE OFFERING

Subscription Receipts

        The Offering consists of    •    Subscription Receipts at a price of $    •    per Subscription Receipts. Each Subscription Receipt will entitle the holder thereof to receive without payment of additional consideration or further action on the part of such holder, one Common Share.

        The following is a summary of the material attributes and characteristics of the Subscription Receipts. This summary does not purport to be complete and is subject to, and qualified in its entirety by, reference to the terms of the Subscription Receipt Agreement, which, following the Closing Date, will be available for inspection at our offices and will be filed on SEDAR at www.sedar.com and EDGAR at www.sec.gov.

        The Escrowed Funds will be held by the Escrow Agent, and invested in short-term obligations of, or guaranteed by, the Government of Canada (or other approved investments) pending delivery by us to the Underwriters of a certificate on the third Business Day prior to the anticipated Effective Date to the effect that the Final Order has been filed with the ASIC and all other material conditions (other than payment of the purchase price) necessary to complete the Acquisition have been satisfied (the "Escrow Condition"). Upon satisfaction of the Escrow Condition on or before 5:00 p.m. (Calgary time) on June 30, 2014 (the "Termination Time"), the Escrowed Funds and the interest earned thereon (less any amounts required to pay the Dividend Equivalent Amount upon the issuance of the Underlying Common Shares, if applicable) will be released to us to enable us to convert these funds to Australian dollars and complete the Acquisition. Upon the closing of the Acquisition, each holder of Subscription Receipts will receive one Underlying Common Share for each Subscription Receipt held, without payment of additional consideration or further action on the part of such holder, and such holder will also be entitled to receive an amount per Subscription Receipt equal to the Dividend Equivalent Amount, being an amount per Subscription Receipt equal to the amount per Common Share of any cash dividends for which record date(s) have occurred during the period commencing on the closing of the Offering to the date immediately preceding the date the Underlying Common Shares are issued pursuant to the Subscription Receipts. All or a portion of the Dividend Equivalent Amount will be satisfied by the payment by the Escrow Agent to holders of Subscription Receipts of interest earned on the Escrowed Funds. The difference, if any, between the amount of interest earned on the Escrowed Funds and the Dividend Equivalent Amount will be paid by us as a partial refund of the subscription price of the Subscription Receipts. If holders of Subscription Receipts become entitled to receive Underlying Common Shares, we and the Escrow Agent will pay such amounts to holders on the later of the date the Underlying Common Shares are issued and the date such dividend(s) is paid to holders of Common Shares. See "Certain Canadian Federal Income Tax Considerations" and "Certain United States Federal Income Tax Considerations".

        We will utilize the Escrowed Funds, together with funds available under the New Credit Facilities, to pay for Aurora Shares pursuant to the Acquisition. See "Recent Developments — The Acquisition", "About Aurora" and "Use of Proceeds".

        If the Acquisition is not completed by the Termination Time, or if we advise the Underwriters or announce to the public that we do not intend to proceed with the Acquisition, or if the Implementation Agreement has been terminated in accordance with its terms, holders of Subscription Receipts shall receive an amount equal to the full subscription price attributable to the Subscription Receipts and their pro rata entitlement to interest accrued on such amount up to and including the date of the Termination Time. In such event, the issuance of a cheque in payment of the subscription price for the Subscription Receipts and pro rata interest, if any, will

57


require the surrender of the certificate(s), by the holder thereof, presenting the same at the principal office of the Escrow Agent in Calgary, Alberta. If any certificates representing Subscription Receipts have not been surrendered one year after the Termination Time, the Escrow Agent will mail the cheques that the holders thereof are entitled to receive to their last addresses of record.

        Upon satisfaction of the Escrow Condition and the issuance of the Underlying Common Shares, we will issue a press release specifying that the Underlying Common Shares have been issued.

        We have granted to the Underwriters the Over-allotment Option to purchase up to an additional    •    Subscription Receipts at a price of $    •    per Subscription Receipt on the same terms and conditions as the Offering, exercisable from time to time, in whole or in part, for a period commencing at closing of the Offering and ending on the earlier of: (i) 30 days following closing of the Offering; and (ii) the Termination Time, to cover over-allotments, if any, and for market stabilization purposes.

        Under the Subscription Receipt Agreement, original purchasers of Subscription Receipts under the Offering will have a contractual right of rescission against us both prior to and following the issuance of Underlying Common Shares to such purchaser upon the exchange of the Subscription Receipts to receive the amount paid for the Subscription Receipts if this short form prospectus (including the documents incorporated by reference herein) and any amendment contains a misrepresentation or is not delivered to such purchaser, provided such remedy for rescission is exercised within 180 days of closing of the Offering.

        Holders of Subscription Receipts are not Shareholders. Holders of Subscription Receipts are entitled only to receive Underlying Common Shares on surrender of their Subscription Receipts to the Escrow Agent or to a return of the subscription price for the Subscription Receipts together with any payments of interest as described above.

        The Subscription Receipts will be issued in "book-entry only" form and must be purchased or transferred through a Participant. See "Details of the Offering — Book-Entry Only System".

        In the event that, prior to the date the Underlying Common Shares become issuable pursuant to the Subscription Receipts, there is a subdivision, consolidation, reclassification or other change of the Common Shares or any reorganization, amalgamation, merger or sale of all or substantially all of our assets, the Subscription Receipts will thereafter evidence the right of the holder to receive the securities, property or cash deliverable in exchange for or on conversion of or in respect of the Underlying Common Shares to which the holder of a Subscription Receipt would have been entitled immediately after such event if it had been a holder of such Underlying Common Shares prior to such event. Similarly, any distribution to all or substantially all of the holders of Common Shares of rights, options, warrants, evidences of indebtedness or assets will result in an adjustment in the number of Underlying Common Shares to be issued to holders of Subscription Receipts. Alternatively, such securities, evidences of indebtedness or assets may, at our option, be issued to the Escrow Agent and delivered to holders of Subscription Receipts following the closing of the Acquisition.

        The Subscription Receipt Agreement will provide for modifications and alterations thereto and to the Subscription Receipts issued thereunder by way of an extraordinary resolution. The term "extraordinary resolution" will be defined in the Subscription Receipt Agreement to mean, in effect, a resolution passed by the affirmative votes of the holders of not less than 662/3% of the number of outstanding Subscription Receipts represented and voted at a meeting of holders or an instrument or instruments in writing signed by the holders of not less than 662/3% of the number of outstanding Subscription Receipts.

Book-Entry Only System

        The Subscription Receipts will be issued in "book-entry only" form and must be purchased or transferred through a Participant.

        Except as otherwise provided herein, on the Closing Date, the Subscription Receipts will be registered and represented electronically through CDS, and will be deposited with CDS pursuant to the book-entry only system. Unless the book-entry only system is terminated as described below, a Subscription Receipt Beneficial Owner will not be entitled to receive a certificate for Subscription Receipts, or, unless requested, for the Underlying

58


Common Shares. Purchasers of Subscription Receipts will not be shown on the records maintained by CDS, except through a Participant.

        Beneficial interests in Subscription Receipts will be represented solely through the book-entry only system and such interests will be evidenced by customer confirmations of purchase from the registered dealer from which the Subscription Receipts are purchased in accordance with the practices and procedures of that registered dealer. In addition, registration of interests in and transfers of the Subscription Receipts will be made only through the depository service of CDS.

        As indirect holders of Subscription Receipts, investors should be aware that they (subject to the situations described below): (a) may not have Subscription Receipts registered in their name; (b) may not have physical certificates representing their interest in the Subscription Receipts; (c) may not be able to sell the Subscription Receipts to institutions required by law to hold physical certificates for securities they own; and (d) may be unable to pledge Subscription Receipts as security.

        The Subscription Receipts will be issued to beneficial owners thereof in fully registered and certificate form (the "Subscription Receipt Certificates") only if: (a) required to do so by applicable law; (b) the book-entry only system ceases to exist; (c) we or CDS advises the Escrow Agent that CDS is no longer willing or able to properly discharge its responsibilities as depository with respect to the Subscription Receipts and we are unable to locate a qualified successor; or (d) we, at our option, decide to terminate the book-entry only system through CDS.

        Upon the occurrence of any of the events described in the immediately preceding paragraph, the Escrow Agent must notify CDS, for and on behalf of Participants and Subscription Receipt Beneficial Owners of the availability through CDS of Subscription Receipt Certificates. Upon surrender by CDS of the global certificates representing the Subscription Receipts and receipt of instructions from CDS for the new registrations, the Escrow Agent will deliver the Subscription Receipts in the form of Subscription Receipt Certificates and thereafter we will recognize the holders of such Subscription Receipt Certificates as Subscription Receipt holders under the Subscription Receipt Agreement.

        Neither we nor the Underwriters will assume any liability for: (a) any aspect of the records relating to the beneficial ownership of the Subscription Receipts held by CDS or any payments relating thereto; (b) maintaining, supervising or reviewing any records relating to the Subscription Receipts; or (c) any advice or representation made by or with respect to CDS and contained in this short form prospectus and relating to the rules governing CDS or any action to be taken by CDS or at the direction of a Participant. The rules governing CDS provide that it acts as the agent and depository for the Participants. As a result, Participants must look solely to CDS and Subscription Receipt Beneficial Owners must look solely to Participants for any payments relating to the Subscription Receipts paid by or on behalf of us to CDS.

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PLAN OF DISTRIBUTION

        Pursuant to the terms and conditions of the Underwriting Agreement among us and each of the Underwriters, we have agreed to sell and the Underwriters have severally agreed to purchase on the Closing Date, an aggregate of    •    Subscription Receipts at a price of $    •    per Subscription Receipt payable in cash to us against delivery of such Subscription Receipts, subject to compliance with all necessary legal requirements and terms and conditions of the Underwriting Agreement. The Underwriting Agreement provides that we will pay the Underwriters' Fee of 4.0% of the gross proceeds of the Offering, or $    •    per Subscription Receipt. The Underwriters' Fee in respect of the Subscription Receipts is payable as to 50% upon the closing of the Offering and 50% on the closing of the Acquisition. If the Acquisition is not completed by the Termination Time, the Underwriters' Fee will be reduced to the amount payable upon closing of the Offering. The offering price of the Subscription Receipts was determined by negotiation between us and Scotia on behalf of itself and on behalf of the other Underwriters.

        We have granted to the Underwriters the Over-allotment Option to purchase up to an additional    •    Subscription Receipts at a price of $    •    per Subscription Receipt on the same terms and conditions as the Offering, exercisable from time to time, in whole or in part, for a period commencing at closing of the Offering and ending at 5:00 p.m. (Calgary time) on the earlier of: (i) 30 days following closing of the Offering; and (ii) the Termination Time, to cover over-allotments, if any, and for market stabilization purposes. A purchaser who acquires Subscription Receipts forming part of the Underwriters' over-allocation position acquires those Subscription Receipts under this short form prospectus, regardless of whether the over-allocation position is ultimately filled through the exercise of the Over-allotment Option or secondary market purchases. If the Over-allotment Option is exercised in full, the total Offering, the Underwriters' Fee and the net proceeds to us (before deducting expenses of the Offering) will be $    •    , $    •    and $    •    , respectively. This short form prospectus also qualifies the distribution of the Subscription Receipts issuable upon exercise of the Over-allotment Option.

        The obligations of the Underwriters, under the Underwriting Agreement, are several, and not joint and several, and may be terminated on the occurrence of certain stated events, including, in the event that at or prior to closing of the Offering: (i) any order to cease or suspend trading in any of our securities, prohibiting or restricting the distribution of any of the Subscription Receipts or Underlying Common Shares, suspending the effectiveness of the registration statement filed by us with the SEC or preventing or suspending the use of any prospectus relating to the Subscription Receipts or Underlying Common Shares has been issued or made, or proceedings are announced, commenced or threatened for the making of any such order, by any securities commission or similar regulatory authority, the TSX, the NYSE or any other competent authority, and such order or proceeding has not been rescinded, revoked or withdrawn or such announced, commenced or threatened proceeding has not been terminated or withdrawn; (ii) any inquiry, action, suit, investigation or other proceeding (whether formal or informal) in relation to us or any of our directors or senior officers is announced, commenced or threatened by any federal, provincial, state, municipal, other governmental agency or by any securities commission or similar regulatory authority, the TSX, the NYSE or any other competent authority, or there is a change in law, regulation or policy or the interpretation or administration thereof, if, in the sole opinion of the Underwriters, or any one of them, acting reasonably, the change, announcement, commencement or threatening thereof, as the case may be adversely effects the distribution or trading of the Subscription Receipts and Underlying Common Shares; (iii) there should develop, occur or come into effect or existence any event, action, state, condition or major financial occurrence of national or international consequence, including, without limitation, any military conflict, civil insurrection, act of terrorism, war or like event, or a governmental action, law, regulation, inquiry or any occurrence of any nature whatsoever, which, in the sole opinion of the Underwriters, or any one of them, acting reasonably, seriously adversely affects or involves, or will seriously adversely affect or involve, the financial markets generally or our business, operations or affairs on a standalone basis or on a consolidated basis after giving effect to the Acquisition; (iv) there should occur any material adverse change or development in our operations, capital or condition (financial or otherwise), business on a standalone basis or on a consolidated basis after giving effect to the Acquisition or our properties, assets, prospects, liabilities or obligations (absolute, accrued, contingent or otherwise) on a standalone basis or on a consolidated basis after giving effect to the Acquisition which, in the sole opinion of the Underwriters, or any one of them, acting reasonably, has or could reasonably be expected to have a material adverse effect on the

60


market price, value or marketability of the Subscription Receipts and Underlying Common Shares; (v) we are in breach of, default under or non-compliance with any covenant, term or condition of the Underwriting Agreement in any material respect, or any representation or warranty given by us in the Underwriting Agreement becomes or is false in any material respect; (vi) the Underwriters shall become aware of any material information with respect to us or the Acquisition which had not been publicly disclosed or disclosed in writing to the Underwriters prior to the date of the Underwriting Agreement which, in the sole opinion of the Underwriters or any one of them, acting reasonably, could be expected to have a material adverse effect on the market price or value of the Subscription Receipts, the Common Shares or any other of our securities; (vii) a general moratorium on commercial banking activities is declared by either United States federal, New York or state authorities or a material disruption in commercial banking or securities settlement or clearance services in Canada or in the United States occurs; (viii) the Implementation Agreement is terminated and not replaced by an amendment or restatement of such on substantially the same terms and satisfactory in form and containing terms and conditions acceptable to the Underwriters, acting reasonably, or we otherwise notify the Underwriters that the Acquisition will not occur; or (ix) the Termination Time has occurred.

        In addition, the obligations of us and the Underwriters under the Underwriting Agreement to complete the purchase and sale of the Subscription Receipts will terminate automatically if the Acquisition is not completed by June 30, 2014, or if we advise the Underwriters or announce to the public that we do not intend to proceed with the Acquisition, or if the Implementation Agreement has been terminated in accordance with its terms. See "Details of the Offering". The closing of the Offering is conditional upon the Underwriters being advised by the Financial Industry Regulatory Authority that it has no objection to the proposed underwriting terms and arrangements among us and the Underwriters, as set forth in the Underwriting Agreement.

        Under the Underwriting Agreement, we shall not be obliged to sell to the Underwriters, nor shall the Underwriters be obliged to purchase, less than all of the Subscription Receipts that the Underwriters have agreed to purchase. In certain circumstances, if an Underwriter fails to purchase the Subscription Receipts which it has agreed to purchase, the other Underwriters may, but are not obligated to, purchase such Subscription Receipts unless the number of Subscription Receipts which one or more of the Underwriters agreed but failed or refused to purchase is more than 5% of the total number of Subscription Receipts being offered, in which case the remaining Underwriters are obligated to purchase such Subscription Receipts on a pro-rata basis. The Underwriters are, however, obligated to take up and pay for all Subscription Receipts if any Subscription Receipts are purchased under the Underwriting Agreement.

        We have agreed to indemnify each of the Underwriters and their respective affiliates and their respective directors, officers, employees, shareholders, agents and each person who controls the Underwriters within the meaning of Section 15 of the 1933 Act or Section 20 of the Exchange Act against certain liabilities, including liabilities under the U.S. securities laws and Canadian securities laws or to contribute to payments the Underwriters may be required to make because of any of these liabilities.

        Subject to applicable laws, the Underwriters may, in connection with the Offering, effect transactions which stabilize or maintain the market price of the Common Shares at levels other than those that might otherwise prevail on the open market in accordance with applicable market stabilization rules. Such transactions, if commenced, may be discontinued at any time.

        The public offering price for the Subscription Receipts offered in Canada and in the United States is payable in Canadian dollars only. The Underwriters propose to offer the Subscription Receipts initially at the offering price specified herein. After a reasonable effort has been made to sell all of the Subscription Receipts at the price specified, the Underwriters may subsequently reduce the selling price to investors from time to time in order to sell any of the Subscription Receipts remaining unsold. In the event the offering price of the Subscription Receipts is reduced, the compensation received by the Underwriters will be decreased by the amount the aggregate price paid by the purchasers for the Subscription Receipts is less than the gross proceeds paid by the Underwriters to us for the Subscription Receipts. Any such reduction will not affect the proceeds received by us.

        Other than the Underlying Common Shares and in connection with the Acquisition, we have agreed not to directly or indirectly issue any Common Shares or securities or other financial instruments convertible into or having the right to acquire Common Shares (other than for purposes of issuing Common Shares pursuant to our

61


dividend reinvestment plan, Share Award Incentive Plan and Common Share Rights Incentive Plan) or enter into any agreement or arrangement under which we acquire or transfer to another, in whole or in part, any of the economic consequences of ownership of Common Shares, whether that agreement or arrangement may be settled by the delivery of Common Shares or other securities or cash, or agree to become bound to do so, or disclose to the public any intention to do so, prior to 90 days after the Closing Date without the prior written consent of Scotia, on behalf of the Underwriters, which consent will not be unreasonably withheld or delayed.

        There is currently no market through which the Subscription Receipts may be sold and purchasers may not be able to resell the Subscription Receipts purchased under this short form prospectus.

        Subscriptions for Subscription Receipts will be received subject to rejection or allotment in whole or in part and the right is reserved to close the subscription books at any time without notice. The Closing Date is anticipated to occur on or about February 24, 2014 or such other date as may be agreed upon by us and the Underwriters, but in any event not later than March 28, 2014.

        This Offering is being made concurrently in all of the provinces of Canada and in the United States pursuant to the multi-jurisdictional disclosure system implemented by the securities regulatory authorities in Canada and the United States. The Subscription Receipts will be offered in the United States and/or Canada through the Underwriters either directly or, if applicable, through their respective U.S. or Canadian registered broker-dealer affiliates.

        Certain Underwriters and their affiliates have performed, and may in the future perform, various underwriting, financial advisory, investment banking, commercial lending and other services in the ordinary course of business with us and our affiliates, for which they receive or will receive customary compensation. See "Relationship between Us and Certain Underwriters".


RELATIONSHIP BETWEEN US AND CERTAIN UNDERWRITERS

        Scotia is a wholly-owned subsidiary of a Canadian chartered bank which has agreed to fully underwrite and commit to provide us with the New Credit Facilities which will replace the Credit Facilities in connection with the Acquisition. See "Recent Developments — New Credit Facilities" for a description of the New Credit Facilities. Each of Scotia and RBC Dominion Securities Inc. are wholly-owned subsidiaries of Canadian chartered banks (the "Lenders"), which are lenders to our subsidiary, Baytex Energy pursuant to the Credit Facilities, and to which Baytex Energy is indebted pursuant to the Credit Facilities. See Note 2 under the heading "Consolidated Capitalization" for a description of the Credit Facilities. In addition, Scotia acted as our financial advisor in connection with the Acquisition. Consequently, we may be considered to be a connected issuer of such Underwriters for the purposes of securities regulations in certain provinces.

        As at September 30, 2013, an aggregate of approximately $244.7 million was outstanding under our Credit Facilities. We are in compliance with the Credit Facilities and the Lenders have not waived a breach of the Credit Facilities since they were executed. Our financial position has not substantially changed since the indebtedness under the Credit Facilities was incurred. We may be considered to be a "connected issuer" of each of these Underwriters for the purposes of securities regulations in certain provinces. The net proceeds received pursuant to this Offering will not be used to reduce our indebtedness.

        The decision to offer the Subscription Receipts and the determination of the terms of the Offering were made through negotiations between us and Scotia, on behalf of the Underwriters. The Lenders did not have any involvement in such decision or determination; however, the Lenders have been advised of the Offering and the terms thereof. As a consequence of the Offering, each of the Underwriters will receive its share of the Underwriters' Fee payable by us to the Underwriters. See "Use of Proceeds".

        We have agreed to retain a Canadian chartered bank (or one or more of its affiliates as may be appropriate in the circumstances), of which Scotia is a wholly-owned subsidiary, to act as manager in connection with the Change of Control Offers required to be made by us to the holders of the Aurora Notes following completion of the Acquisition as described under "Recent Developments — The Acquisition — Acquisition Consideration" at prevailing market rates for a person acting in such a role.

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PRIOR SALES

        The following is a description of prior sales of Common Shares and securities convertible into Common Shares during the twelve-month period ended January 31, 2014:


MARKET FOR SECURITIES

        The Common Shares are listed and posted for trading on the TSX and the NYSE under the trading symbol "BTE". The Common Shares commenced trading on the TSX on January 6, 2011 and on the NYSE on January 3, 2011. The following table sets forth certain trading information for the Common Shares in Canada and the United States for the periods indicated.

 
  Canada Composite Trading   United States Composite Trading  
 
  Price Range    
  Price Range    
 
 
  High
($)
  Low
($)
  Volume
Traded
  High
($US)
  Low
($US)
  Volume
Traded
 

2013

                                     

January

    47.04     43.17     11,685,057     47.09     43.79     2,949,901  

February

    47.61     42.22     13,235,046     47.47     41.04     3,233,303  

March

    45.38     42.00     14,229,551     44.21     41.10     3,474,977  

April

    43.05     36.37     17,625,019     42.50     35.42     4,994,797  

May

    41.60     37.75     16,525,672     41.47     37.04     5,052,109  

June

    39.51     36.56     10,374,749     38.22     34.71     3,190,546  

July

    44.44     37.65     16,395,772     43.08     35.70     3,634,313  

August

    43.49     40.29     9,083,228     42.12     38.55     3,530,714  

September

    43.44     40.76     9,125,099     42.20     39.18     3,169,676  

October

    44.74     40.82     13,112,997     42.84     39.26     2,807,133  

November

    43.75     41.19     11,651,629     41.84     39.25     4,840,744  

December

    42.73     40.21     11,807,054     40.16     37.76     3,056,178  

2014

                                     

January

    42.50     39.18     13,653,728     39.42     35.51     4,269,728  

February (to 5)

    41.23     39.83     1,910,902     37.20     35.99     634,431  

        On February 5, 2014, the last trading day prior to the date of this short form prospectus, the closing price of the Common Shares was $41.16 on the TSX and U.S.$37.16 on the NYSE (as reported by such stock exchanges).

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DIVIDENDS TO SHAREHOLDERS

        Our dividend policy is to pay a monthly dividend on our Common Shares on or about the 15th day following the end of each calendar month to Shareholders of record on or about the last business day of each such calendar month. See "Description of Common Shares — Dividend Policy".

        Since we commenced operations on January 1, 2011, the following per Common Share dividends have been paid by us for the months indicated.

 
  Dividends per
Common Share ($)
 
Month
  2014   2013   2012   2011  

January

    0.22     0.22     0.22     0.20  

February

        0.22     0.22     0.20  

March

        0.22     0.22     0.20  

April

        0.22     0.22     0.20  

May

        0.22     0.22     0.20  

June

        0.22     0.22     0.20  

July

        0.22     0.22     0.20  

August

        0.22     0.22     0.20  

September

        0.22     0.22     0.20  

October

        0.22     0.22     0.20  

November

        0.22     0.22     0.20  

December

        0.22     0.22     0.20  
                   

Total

  $ 0.22   $ 2.64   $ 2.64   $ 2.40  
                   

        In connection with the Acquisition, we intend increase the monthly dividend on our Common Shares by 9% to $0.24 from $0.22 per Common Share, subject to the completion of the Acquisition. See "Recent Developments — Dividend Increase".

        Pursuant to the Credit Facilities, we are restricted from paying dividends to Shareholders if a default or event of default has occurred and is continuing and, if no default or event of default has occurred which is continuing, where the dividend would or would reasonably be expected to have a material adverse effect on us or on our or our subsidiaries' ability to fulfill their obligations under the Credit Facilities or under any hedge agreements with lenders (or their affiliates) under the Credit Facilities. The New Credit Facilities will also contain restrictions on our ability to pay dividends. See "Recent Developments — New Credit Facilities" for a description of the New Credit Facilities.

        The Debenture Indenture also contains certain limitations on maximum cumulative dividends. Restricted payments include the declaration or payment of any dividend or distribution by us and the payment of interest or principal on subordinated debt owed by us. We and certain of our subsidiaries are restricted from making any restricted payments unless at the time of, and immediately after giving effect to, the proposed restricted payment, no default or event of default under the Debenture Indenture has occurred and is continuing, and either: (i) (a) we could incur at least $1.00 of additional indebtedness (other than certain permitted debt) in accordance with the "Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock" covenant in the Debenture Indenture; (b) the ratio of consolidated debt to consolidated cash flow from operations does not exceed 3.0 to 1.0; and (c) the aggregate amount of all restricted payments declared or made after August 26, 2009 (other than certain permitted restricted payments) does not exceed the sum of: (A) 80% of consolidated cash flow from operations accrued on a cumulative basis since August 26, 2009, plus (B) 100% of the aggregate net cash proceeds received by us after August 26, 2009 from (x) the issuance by us of convertible debentures, or (y) capital contributions in respect of certain permitted equity that we receive from any person; plus (C) the aggregate net proceeds, including the fair market value of property received after August 26, 2009 other than cash (as determined by the Board of Directors), received by us from any person, other than a subsidiary, from the issuance or sale of debt securities (including convertible debentures) or disqualified stock that have been converted into or exchanged for certain permitted equity of us, plus the aggregate net cash proceeds received by

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us at the time of such conversion or exchange; or (ii) the aggregate amount of all restricted payments declared or made pursuant to paragraph (i) does not exceed the sum of certain unpaid funds from restricted payments not previously expended under paragraph (i), plus $50,000,000. As at the date of this short form prospectus, we are in compliance with these covenants.

        Cash dividends are not guaranteed. Our historical cash dividends may not be reflective of future cash dividends, which will be subject to review by the Board of Directors taking into account our prevailing financial circumstances at the relevant time. Although we intend to pay dividends to Shareholders, these cash dividends may be reduced or suspended. The actual amount distributed will depend on numerous factors, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates, the satisfaction of the liquidity and solvency tests imposed by the ABCA for the declaration and payment of dividends and other factors beyond our control. See "Risk Factors".

        As described above under "Details of the Offering — Subscription Receipts", if the Acquisition is completed prior to the Termination Time, the holder of a Subscription Receipt, in addition to receiving a Common Share in exchange therefore, will be entitled to receive the Dividend Equivalent Amount which will be paid by way of a pro rata share of accrued interest on the Escrowed Funds. The difference, if any, between the amount of interest earned on the Escrowed Funds and the Dividend Equivalent Amount will be paid by us as a partial refund of the subscription price of the Subscription Receipts.


CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

        Prospective investors should be aware that the purchase of Subscription Receipts has tax consequences, which are not described in this short form prospectus. Accordingly, prospective investors are advised to consult their own tax advisors with respect to the tax aspects of investing in, holding and disposing of the Subscription Receipts and the Underlying Common Shares.

        In the opinion of Burnet, Duckworth & Palmer LLP, counsel to the Corporation, and McCarthy Tétrault LLP, counsel to the Underwriters (collectively, "Counsel"), the following is a fair and adequate summary of the principal Canadian federal income tax considerations pursuant to the Tax Act generally applicable to a subscriber who acquires the Subscription Receipts pursuant to the Offering and who, for purposes of the Tax Act, holds the Subscription Receipts and will hold the Underlying Common Shares (collectively, the "Securities") as capital property and deals at arm's length with, and is not affiliated with us and the Underwriters. Generally, the Securities will be considered to be capital property to a holder provided the holder does not hold the Securities in the course of carrying on a business of trading or dealing in securities and has not acquired them in one or more transactions considered to be an adventure in the nature of trade. Certain holders resident in Canada who might not otherwise be considered to hold their Underlying Common Shares as capital property may, in certain circumstances, be entitled to have their Underlying Common Shares and every other "Canadian security" as defined in the Tax Act treated as capital property by making the irrevocable election permitted by subsection 39(4) of the Tax Act. This election is not available in respect of the Subscription Receipts.

        This summary is not applicable to: (i) a holder that is a "financial institution", as defined in the Tax Act for purposes of the mark-to-market rules; (ii) a holder an interest in which would be a "tax shelter investment" as defined in the Tax Act; (iii) a holder that is a "specified financial institution" as defined in the Tax Act; (iv) a holder whose functional currency for the purposes of the Tax Act is the currency of a country other than Canada; or (v) that has or will enter into a "derivative forward agreement" as defined in the Tax Act, in respect of the Subscription Receipts or Underlying Common Shares. Any such holder should consult its own tax advisor with respect to an investment in the Securities.

        This summary is based upon the provisions of the Tax Act in force as of the date hereof and Counsel's understanding of the current published administrative and assessing practices of the Canada Revenue Agency ("CRA"). Except for specifically proposed amendments (the "Proposed Amendments") to the Tax Act that have been publicly announced by the federal Minister of Finance prior to the date hereof, this summary does not take into account or anticipate changes in the income tax law, whether by legislative, governmental or judicial action, nor any changes in the administrative or assessing practices of the CRA. This summary does not take into

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account or anticipate provincial, territorial or foreign tax considerations, which may differ significantly from those discussed herein.

        This summary is of a general nature only and is not intended to be, nor should it be construed to be, legal or tax advice to any prospective purchaser or holder of Securities, and no representations with respect to the income tax consequences to any prospective purchaser or holder are made. Consequently, prospective holders of Securities should consult their own tax advisors with respect to their particular circumstances.

Holders Resident in Canada

        The following portion of the summary is applicable to a holder of Subscription Receipts who, for purposes of the Tax Act, is resident in Canada (a "Resident Holder").

Acquisition of Common Shares Pursuant to Terms of the Subscription Receipts

        A Resident Holder will not realize a capital gain or loss on the issuance of an Underlying Common Share pursuant to a Subscription Receipt.

        The cost of any such Underlying Common Shares will generally be equal to the amount paid by such Resident Holder to acquire the Subscription Receipt. However, such cost may be reduced by a portion of the Dividend Equivalent Amount, if any is received. See "Holders Resident in Canada — Dividend Equivalent Amount". The cost of Underlying Common Shares received will generally be averaged with the cost of all other Common Shares held by the Resident Holder as capital property to determine the adjusted cost base of each Common Share held by the Resident Holder.

Other Dispositions of Subscription Receipts

        A disposition or deemed disposition by a Resident Holder of Subscription Receipts, other than on the exchange thereof for an Underlying Common Share, but including on the repayment of the issue price thereof by us in the event the Acquisition is not completed before the Termination Time, will generally result in the Resident Holder realizing a capital gain (or capital loss) equal to the amount, if any, by which the proceeds of disposition are greater (or less) than the aggregate of the Resident Holder's adjusted cost base thereof and any reasonable costs of disposition. The cost to a Resident Holder of a Subscription Receipt will generally be the amount paid to acquire the Subscription Receipt. Such capital gain (or capital loss) will be subject to the tax treatment described below under "Holders Resident in Canada — Taxation of Capital Gains and Capital Losses".

        In the event that a Resident Holder becomes entitled to the repayment of the issue price of a Subscription Receipt, any amount that is paid to the holder as, or on account of, interest and that is included in the Resident Holder's income, will be excluded from the holder's proceeds of disposition.

Pro Rata Share of Interest

        If the Acquisition is not completed by the Termination Time or if we advise the Underwriters or announce to the public that we do not intend to proceed with the Acquisition, or if the Implementation Agreement has been terminated in accordance with its terms, holders of Subscription Receipts shall be entitled to receive from the Escrow Agent an amount equal to the full subscription price thereof plus their pro rata share of interest accrued on the Escrowed Funds.

        A Resident Holder that is a corporation, partnership, unit trust or any trust of which a corporation or a partnership is a beneficiary will be required to include in computing its income for a taxation year the amount of any such interest accrued to the Resident Holder on the Escrowed Funds to the end of the Resident Holder's taxation year, or that is receivable or received by the Resident Holder before the end of that taxation year, except to the extent that such interest was included in computing the Resident Holder's income for a preceding taxation year.

        Any other Resident Holder that is entitled to receive its share of accrued interest will be required to include in computing income for a taxation year such interest that is receivable or received by the Resident Holder in that taxation year, depending upon the method regularly followed by the Resident Holder in computing income.

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        A Resident Holder that is, throughout the relevant taxation year, a "Canadian-controlled private Corporation" (as defined in the Tax Act) may be liable to pay a refundable tax of 62/3% on its certain investment income, including interest income.

Dividend Equivalent Amount

        As described above under "Details of the Offering — Subscription Receipts", if the Acquisition is completed prior to the Termination Time, the holder of a Subscription Receipt, in addition to receiving a Common Share, will be entitled to receive the Dividend Equivalent Amount, if any, which will be first paid by way of a pro rata share of accrued interest on the Escrowed Funds. The amount of such interest will generally be included in computing the Resident Holder's income as described above under "Holders Resident in Canada — Pro Rata Share of Interest".

        If the amount of accrued interest that is paid to the Resident Holder is less than the Dividend Equivalent Amount, we will pay to the Resident Holder the amount of any shortfall as a partial refund of the subscription price of the Subscription Receipts. Such shortfall amount generally will reduce the cost to the Resident Holder of the Common Shares acquired on the exchange of the Subscription Receipts.

        For greater certainty, no part of the Dividend Equivalent Amount will benefit from the gross-up and dividend tax credit rules normally applicable in respect of taxable dividends received by individuals from "taxable Canadian corporations" (as defined in the Tax Act); and, where this amount is received by a corporation, the amount will not be deductible in computing the corporation's taxable income and will not result in the requirement to pay the refundable Part IV tax.

Disposition of Common Shares

        A disposition or a deemed disposition of a Common Share by a Resident Holder (except to us) will generally result in the Resident Holder realizing a capital gain (or a capital loss) equal to the amount by which the proceeds of disposition of the Common Share exceeds (or are less than) the aggregate of the adjusted cost base to the Resident Holder thereof and any reasonable costs of disposition. Such capital gain (or capital loss) will be subject to the tax treatment described below under "Holders Resident in Canada — Taxation of Capital Gains and Capital Losses".

Taxation of Capital Gains and Capital Losses

        Generally, one-half of any capital gain (a "taxable capital gain") realized by a Resident Holder in a taxation year must be included in the Resident Holder's income for the year, and one-half of any capital loss (an "allowable capital loss") realized by a Resident Holder in a taxation year must be deducted from taxable capital gains realized by the Resident Holder in that year. Allowable capital losses in excess of taxable capital gains realized in a taxation year generally may be carried back and deducted in any of the three preceding taxation years or carried forward and deducted in any subsequent taxation year against net taxable capital gains realized in such years, to the extent and under the circumstances described in the Tax Act.

        The amount of any capital loss realized by a Resident Holder that is a corporation on the disposition of a Common Share may be reduced by the amount of dividends received or deemed to be received by it on such Common Share (or on a share for which the Common Share has been substituted) to the extent and under the circumstances described by the Tax Act. Similar rules may apply where a corporation is a member of a partnership or a beneficiary of a trust that owns Common Shares, directly or indirectly, through a partnership or a trust.

        A Resident Holder that is, throughout the relevant taxation year, a "Canadian-controlled private corporation", as defined in the Tax Act, may be liable to pay a refundable tax of 62/3% on certain investment income, including taxable capital gains.

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        Capital gains realized by an individual (including certain trusts) may give rise to liability for alternative minimum tax as calculated under the detailed rules set out in the Tax Act. Resident Holders who are individuals should consult their own tax advisors in this regard.

Receipt of Dividends on Common Shares

        Dividends received or deemed to be received on Common Shares held by a Resident Holder will be included in the Resident Holder's income for the purposes of the Tax Act.

        Such dividends received by a Resident Holder that is an individual (other than certain trusts) will be subject to the gross-up and dividend tax credit rules in the Tax Act normally applicable to dividends received from taxable Canadian corporations, including the enhanced gross-up and dividend tax credit in respect of dividends designated by us as "eligible dividends". There may be limitations on our ability to designate dividends as "eligible dividends".

        Taxable dividends received by a Resident Holder who is an individual (other than certain trusts) may result in such Resident Holder being liable for alternative minimum tax under the Tax Act. Resident Holders who are individuals should consult their own tax advisors in this regard.

        A Resident Holder that is a corporation will include such dividends in computing its income and generally will be entitled to deduct the amount of such dividends in computing its taxable income. A Resident Holder that is a "private corporation" or "subject corporation" (as such terms are defined in the Tax Act) may be liable under Part IV of the Tax Act to pay a refundable tax of 331/3% of dividends received or deemed to be received on the Common Shares to the extent such dividends are deductible in computing the Resident Holder's taxable income.

Holders Not Resident in Canada

        This portion of the summary applies to a holder of Subscription Receipts who, for purposes of the Tax Act, is not, and is not deemed to be, resident in Canada and is not an insurer who carries on an insurance business in Canada and elsewhere (a "Non-Resident Holder"). Prospective holders of Subscription Receipts who are not resident in Canada should consult their own tax advisors with respect to their particular circumstances in their country of residence.

Acquisition of Common Shares pursuant to terms of the Subscription Receipts

        A Non-Resident Holder will not realize a capital gain or loss on the issuance of an Underlying Common Share pursuant to a Subscription Receipt.

Other Dispositions of Subscription Receipts

        On a disposition of a Subscription Receipt (other than on the acquisition of a Common Share pursuant to the terms of Subscription Receipts as discussed above), a Non-Resident Holder will not be subject to tax under the Tax Act in respect of any capital gain realized by such Non-Resident Holder, unless the Subscription Receipt constitutes "taxable Canadian property" (as defined in the Tax Act) of the Non-Resident Holder at the time of disposition and the holder is not entitled to relief under an applicable income tax convention.

        As long as the Common Shares are then listed on a designated stock exchange (which currently includes the TSX), Subscription Receipts will not constitute "taxable Canadian property" to a Non-Resident Holder at the time of the disposition or deemed disposition thereof unless at any particular time during the 60-month period immediately preceding the disposition the following two conditions have been met concurrently: (a) the Non-Resident Holder, persons with whom the Non-Resident Holder does not deal at arm's length (within the meaning of the Tax Act), partnerships in which the Non-Resident Holder or a person with whom the Non-Resident Holder does not deal at arm's length (within the meaning of the Tax Act) holds a membership interest directly or indirectly through one or more partnerships, or any combination thereof owned 25% or more of the issued Common Shares, and (b) more than 50% of the fair market value of the Common Shares was derived directly or indirectly from one or any combination of (i) real or immovable property situated in Canada, (ii) "Canadian resource properties" (as defined in the Tax Act), (iii) "timber resource properties" (as defined in

68


the Tax Act) or (iv) an option, an interest or right in such property, whether or not such property exists (the conditions described in (a) and (b) are the "TCP Conditions"). A Non-Resident Holder contemplating a disposition of Subscription Receipts that may constitute taxable Canadian property should consult a tax advisor prior to such disposition.

Pro Rata Share of Interest

        If the Acquisition is not completed by the Termination Time or if we advise the Underwriters or announce to the public that we do not intend to proceed with the Acquisition, or if the Implementation Agreement has been terminated in accordance with its terms, holders of Subscription Receipts shall be entitled to receive from the Escrow Agent an amount equal to the full subscription price thereof plus their pro rata share of accrued interest on the Escrowed Funds. A Non-Resident Holder will generally not be subject to Canadian withholding tax in respect of amounts paid or credited or deemed to have been paid or credited by us as, on account or in lieu of payment of, or in satisfaction of, any such interest.

Dividend Equivalent Amount

        As described above under "Details of the Offering — Subscription Receipts", if the Acquisition is completed prior to the Termination Time, the holder of a Subscription Receipt, in addition to receiving a Common Share, will be entitled to receive the Dividend Equivalent Amount, if any, which will be first paid by way of a pro rata share of accrued interest on the Escrowed Funds. The amount of such interest payable to a Non-Resident Holder will be subject to the Canadian federal tax considerations described above under "Holders Not Resident in Canada — Pro Rata Share of Interest", unless such interest constitutes "participating debt interest" (within the meaning of the Tax Act). If such interest is considered to be participating debt interest, the amount paid to a Non-Resident Holder would be subject to Canadian withholding tax at the statutory rate of 25% (subject to reduction under an applicable income tax convention between Canada and the Non-Resident Holder's country of residence). In this respect, it is uncertain whether or not such interest would constitute "participating debt interest" for purposes of the Tax Act. We have advised Counsel that we intend to withhold at the statutory rate of 25% (subject to reduction under an applicable income tax convention between Canada and the Non-Resident Holder's country of residence) on the portion of any Dividend Equivalent Amount which is paid by way of a pro rata share of accrued interest on the Escrowed Funds that is paid to a Non-Resident Holder.

        If the amount of accrued interest that is paid to the Non-Resident Holder is less than the Dividend Equivalent Amount, we will pay to the Non-Resident Holder the amount of any shortfall as a partial refund of the subscription price of the Subscription Receipts. Such shortfall amount generally will reduce the cost to the Non-Resident Holder of the Common Shares acquired on the exchange of the Subscription Receipts.

Disposition of Common Shares

        A Non-Resident Holder will not be subject to tax under the Tax Act in respect of any capital gain realized by such Non-Resident Holder on a disposition of a Common Share issuable pursuant to the terms of the Subscription Receipts, unless the Common Shares constitute "taxable Canadian property" (as defined in the Tax Act) of the Non-Resident Holder at the time of disposition and the Non-Resident Holder is not entitled to relief under an applicable income tax convention.

        As long as the Common Shares are then listed on a designated stock exchange (which currently includes the TSX), Common Shares will not constitute "taxable Canadian property" to a Non-Resident Holder at the time of the disposition or deemed disposition thereof unless at any particular time during the 60 month period immediately preceding the disposition, the TCP Conditions are met. A Non-Resident Holder contemplating a disposition of Subscription Receipts that may constitute taxable Canadian property should consult a tax advisor prior to such disposition.

Receipt of Dividends on Common Shares

        Any dividends paid or credited, or deemed to be paid or credited, on the Common Shares to a Non-Resident Holder will be subject to Canadian withholding tax at the rate of 25% of the gross amount of the dividend unless the rate is reduced under the provisions of an applicable income tax convention between Canada

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and the Non-Resident Holder's country of residence. For instance, where the Non-Resident Holder is a resident of the United States that is entitled to full benefits under the Canada United States Income Tax Convention (1980) as amended and is the beneficial owner of the dividends, the rate of Canadian withholding tax applicable to dividends is generally reduced to 15%.


CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

General

        The following is a discussion of certain United States federal income tax consequences to United States Holders (as defined below) relating to the acquisition, ownership and disposition of Subscription Receipts and Common Shares. This discussion is based on existing provisions of the United States Internal Revenue Code of 1986, as amended (the "Code"), its legislative history, existing final, temporary and proposed Treasury Regulations promulgated thereunder, administrative pronouncements or practice, judicial decisions, and interpretations of the foregoing, all as of the date hereof. Future legislative, judicial or administrative modifications, revocations or interpretations, which may or may not be retroactive, may result in United States federal income tax consequences significantly different from those discussed herein. This discussion is not binding on the Internal Revenue Service (the "IRS"). No ruling has been or will be sought or obtained from the IRS with respect to any of the United States federal income tax consequences discussed herein. There can be no assurance that the IRS will not challenge any of the conclusions described herein or that a United States court will not sustain such challenge.

        For purposes of this discussion, a "United States Holder" is a beneficial owner of Subscription Receipts or Common Shares that is (i) an individual who is a citizen or a resident alien of the United States for U.S. federal income tax purposes, (ii) a corporation (or other entity treated as a corporation for United States federal income tax purposes) created or organized in or under the laws of the United States, any state thereof, or the District of Columbia, (iii) an estate the income of which is subject to United States federal income taxation regardless of its source, or (iv) a trust (A) if a court within the United States is able to exercise primary supervision over its administration and one or more United States persons have authority to control all substantial decisions of the trust, or (B) that has a valid election in effect under applicable Treasury regulations to be treated as a United States person.

        If a partnership or other pass-through entity holds Subscription Receipts or Common Shares, the tax treatment of a partner in or owner of the partnership or pass-through entity will generally depend upon the status of the partner or owner and the activities of the entity. Partners, partnerships or other pass-through entities considering holding Subscription Receipts or Common Shares should consult their tax advisors regarding the tax consequences of the acquisition, ownership and disposition of Subscription Receipts and Common Shares.

        This discussion does not address any United States federal alternative minimum tax, United States federal estate, gift, or other non-income tax; or state, local or non-United States tax consequences of the acquisition, ownership and disposition of Subscription Receipts and Common Shares. In addition, this discussion does not address the United States federal income tax consequences to certain categories of United States Holders subject to special rules, including United States Holders that are (i) banks, financial institutions or insurance companies; (ii) regulated investment companies or real estate investment trusts; (iii) brokers or dealers in securities or currencies or traders in securities that elect to use a mark-to-market method of accounting; (iv) tax-exempt organizations, qualified retirement plans, individual retirement accounts or other tax-deferred accounts; (v) holders that hold the Subscription Receipts or Common Shares as part of a hedge, straddle, conversion transaction or a synthetic security or other integrated transaction; (vi) holders that have a "functional currency" other than the U.S. dollar; (vii) holders that own directly, indirectly or constructively 10% or more of the voting power of our stock; (viii) United States expatriates; and (ix) holders that purchase or otherwise acquire Subscription Receipts or Common Shares other than through this Offering. Further, this discussion does not address the indirect consequences to holders of equity interests in entities that own the Subscription Receipts or Common Shares or to holders of the Subscription Receipts or Common Shares that are not United States Holders.

70


        This discussion assumes that Subscription Receipts and Common Shares are held as "capital assets" (generally, property held for investment), within the meaning of Section 1221 of the Code, in the hands of a United States Holder at all relevant times and that we are not and will not become, a passive foreign investment company, or PFIC, as discussed under "Certain United States Federal Income Tax Considerations — Passive Foreign Investment Company Considerations."

        The following discussion is for general information only and is not intended to be, nor should it be construed to be, legal or tax advice to any holder or prospective holder of Subscription Receipts or Common Shares and no opinion or representation with respect to the United States federal income tax consequences to any such holder or prospective holder is made. Prospective purchasers are urged to consult their tax advisors as to the particular consequences to them under Unites States federal, state and local, and applicable foreign, tax laws of the acquisition, ownership and disposition of Subscription Receipts and Common Shares.

Taxation of Subscription Receipts

Consequences if the Acquisition is Not Completed

        If the Acquisition is not completed (see "Details of the Offering"), holders of Subscription Receipts shall receive an amount equal to the full subscription price attributable to the Subscription Receipts and their pro rata entitlement to interest accrued on such amount up to and including the date of the Termination Time. We intend to treat United States Holders of Subscription Receipts as subject to tax for United States federal income tax purposes in respect of amounts earned on the Escrowed Funds at the time, depending upon the holder's method of accounting, such holders are entitled to such amounts or such amounts are distributed to such holders (which income would include amounts withheld in respect of any Canadian withholding tax).

Consequences if the Acquisition is Completed

        We do not intend to treat United States Holders of Subscription Receipts as subject to tax for United States federal income tax purposes in respect of amounts earned on the Escrowed Funds in the event that the Acquisition is completed. If the Acquisition is completed, the Escrowed Funds and the interest earned thereon (less any amounts required to pay the Dividend Equivalent Amount, if applicable) will be released to us. See "Details of the Offering". However, it is possible that the IRS could successfully assert that a United States Holder of Subscription Receipts is subject to tax with respect to the holder's share of the income earned on Escrowed Funds at or before relinquishment of such Subscription Receipts even if Common Shares rather than the holder's share of the Escrowed Funds are received. In all likelihood, the amount of any Dividend Equivalent Amount to which the United States holder is entitled (including amounts withheld in respect of any Canadian withholding tax) would be subject to tax for United States federal income tax purposes. It is unclear in such an event how and to what extent the overall taxable amount would be adjusted if the United States Holder were also taxable with respect to its share of the Escrowed Funds.

        Notwithstanding any change in value of the Common Shares after the Closing Date, no gain or loss will be recognized upon any receipt of the Common Shares. In addition, a United States Holder's disposition of Subscription Receipts prior to relinquishment either for Common Shares or for the holder's share of Escrowed Funds will generally result in such holder realizing a capital gain (or capital loss) equal to the amount by which the proceeds of the disposition are greater (or less) then the aggregate of the adjusted cost basis in the Subscription Receipts (except that, possibly, ordinary income could arise with respect to entitlement to a Dividend Equivalent Amount).

        Prospective purchasers of Subscription Receipts are urged to consult their own tax advisers regarding the United States federal income tax consequences of the Subscription Receipts.

Distributions on Common Shares

        The gross amount of any distribution we pay will generally be subject to United States federal income tax as dividend income to the extent paid out of our current or accumulated earnings and profits, as determined under United States federal income tax principles. Such amount will be includable in gross income by a United States

71


Holder as ordinary income on the date such United States Holder actually or constructively receives the distribution.

        Certain dividends received by non-corporate United States Holders from a qualified foreign corporation ("QFC") may be eligible for reduced rates of taxation ("qualified dividends"). A QFC includes a foreign corporation that is eligible for the benefits of a comprehensive income tax treaty with the United States that the United States Treasury Department determines to be satisfactory for these purposes and that includes an exchange of information provision. The United States Treasury has determined that the United States – Canada Income Tax Convention meets these requirements, and we believe we are eligible for the benefits of the Tax Convention. A foreign corporation is also treated as a QFC with respect to dividends paid by that corporation on ordinary shares that are readily tradable on an established securities market in the United States. U.S. Treasury guidance indicates that our Common Shares are readily tradable on an established securities market in the United States; however, there can be no assurance that the Common Shares will be considered readily tradable on an established securities market in future years.

        We believe that we are currently, and will continue to be, a QFC so as to allow all dividends we pay to be qualified dividends for United States federal income tax purposes. Distributions in excess of our current and accumulated earnings and profits will be treated first as a non-taxable return of capital reducing a United States Holder's tax basis in Common Shares. Any distribution in excess of such tax basis will be treated as capital gain and will be either long-term or short-term capital gain depending upon whether the United States Holder held the Common Shares for more than one year. See "Certain United States Federal Income Tax Considerations — Sale, Exchange, or Other Taxable Disposition of Common Shares". Dividends we pay generally will not be eligible for the dividends-received deduction available to certain United States corporate shareholders.

        The limitations on foreign taxes eligible for credit are calculated separately with respect to specific classes of income. For foreign tax credit purposes, dividends received by a United States Holder with respect to shares of a foreign corporation generally constitute foreign-source income and are treated as "passive category" or "general category" income. Subject to certain limitations, any Canadian tax withheld with respect to distributions made on the Common Shares may be treated as foreign taxes eligible for credit against a United States Holder's United States federal income tax liability. Alternatively, a United States Holder may, subject to applicable limitations, elect to deduct the otherwise creditable Canadian withholding taxes for United States federal income tax purposes. The rules governing the foreign tax credit are complex and their application depends on each taxpayer's particular circumstances. Accordingly, United States Holders are urged to consult their own tax advisors regarding the availability of the foreign tax credit under their particular circumstances.

        The gross amount of distributions paid in any foreign currency will be included by each United States Holder in gross income in a U.S. dollar amount calculated by reference to the exchange rate in effect on the day the distributions are paid, regardless of whether the payment is in fact converted into U.S. dollars. If the foreign currency is converted into U.S. dollars on the date of the payment, the United States Holder should not be required to recognize any foreign currency gain or loss with respect to the receipt of the foreign currency distributions. If instead the foreign currency is converted at a later date, any currency gains or losses resulting from the conversion of the foreign currency will be treated as United States source ordinary income or loss.

Sale, Exchange, or Other Taxable Disposition of Common Shares

        A United States Holder will generally recognize capital gain or loss upon the sale, exchange or other taxable disposition of the Common Shares measured by the difference between the amount received and the United States Holder's adjusted tax basis in the Common Shares which should generally equal the United States Holder's adjusted tax basis in the Subscription Receipts. Any gain or loss will be long-term capital gain or loss if the Common Shares have been held for more than one year and will generally be United States source gain or loss. For this purpose, the holding period in the Common Shares received upon relinquishment of the Subscription Receipts generally will begin on the day following such relinquishment. Long-term capital gains recognized by non-corporate United States Holders are generally subject to United States federal income tax at preferred rates. A holder's ability to deduct capital losses is subject to limitations.

72


        For cash-basis United States Holders that receive foreign currency in connection with a sale or other taxable disposition of Common Shares, the amount realized will be based upon the U.S. dollar value of the foreign currency received with respect to such Common Shares as determined on the settlement date of such sale or other taxable disposition. Accrual-basis United States Holders may elect the same treatment required of cash-basis taxpayers with respect to a sale or other taxable disposition of Common Shares, provided that the election is applied consistently from year to year. Such election cannot be changed without the consent of the IRS. Accrual-basis United States Holders that do not elect to be treated as cash-basis taxpayers (pursuant to the Treasury Regulations applicable to foreign currency transactions) for this purpose may have a foreign currency gain or loss for United States federal income tax purposes because of differences between the U.S. dollar value of the foreign currency received prevailing on the date of such sale or other taxable disposition and the value prevailing on the date of payment. Any such currency gain or loss will generally be treated as ordinary income or loss that is United States source, in addition to the gain or loss, if any, recognized on the sale or other taxable disposition of Common Shares.

Passive Foreign Investment Company Considerations

        Special, adverse, United States federal income tax rules apply to United States persons owning stock of a PFIC. A foreign corporation will be considered a PFIC for any taxable year in which (i) 75% or more of its gross income is passive income, or (ii) 50% or more of the average value (or, if elected, the adjusted tax basis) of its assets are considered "passive assets" (generally, assets that generate passive income). We believe we are not currently a PFIC for United States federal income tax purposes, and we do not expect to become a PFIC in the future. However, the determination of PFIC status for any year is very fact specific, and there can be no assurance in this regard. Accordingly, it is possible that we may become a PFIC in the current taxable year or in future years. If we are classified as a PFIC in any year during which a holder holds Common Stock, we generally will continue to be treated as a PFIC to such a holder in all succeeding years, regardless of whether we continue to meet the income or asset test discussed above. United States Holders are urged to consult their own tax advisors regarding the adverse tax consequences of owning the Common Shares were we to be a PFIC and certain elections that may be made that are designed to lessen those adverse consequences.

Additional Tax on Passive Income

        An additional 3.8% tax will generally be imposed on the "net investment income" of individuals, estates and trusts whose income exceeds certain thresholds. "Net investment income" generally includes the following: (1) gross income from interest and dividends other than from the conduct of a non-passive trade or business; (2) other gross income from a passive trade or business; and (3) net gain attributable to the disposition of property other than property held in a non-passive trade or business. Therefore, dividends on, and capital gains from the sale or other taxable disposition of, the Common Shares and Subscription Receipts may be subject to this additional tax.

United States Information Reporting and Backup Withholding

        Under United States federal income tax law and regulations, certain categories of United States Holders must file information returns with respect to their investment in, or involvement in, a foreign corporation. Penalties for failure to file certain of these information returns are substantial. In addition, new United States return disclosure obligations (and related penalties for failure to disclose) have also been imposed on United States individuals who hold certain specified foreign financial assets in excess of U.S.$50,000. The definition of specified foreign financial assets includes not only financial accounts maintained in foreign financial institutions, but also may include the Common Shares and Subscription Receipts. United States Holders of Common Shares and/or Subscription Receipts should consult with their own tax advisors regarding the requirements of filing any information returns.

        Dividends on Common Shares, amounts earned on Escrowed Funds and/or the Dividend Equivalent Amount relating to Subscription Receipts and proceeds from the sale or other disposition of Common Shares and/or Subscription Receipts that are paid in the United States or by a United States-related financial intermediary will be subject to United States information reporting rules, unless a United States Holder is a corporation or other exempt recipient. In addition, payments that are subject to information reporting may be

73


subject to backup withholding (currently at a 28% rate) if a United States Holder does not provide its taxpayer identification number and otherwise comply with the backup withholding rules. Backup withholding is not an additional tax. Amounts withheld under the backup withholding rules are available to be credited against a United States Holder's United States federal income tax liability and may be refunded to the extent they exceed such liability, provided the required information is provided to the IRS in a timely manner.


LEGAL MATTERS

        Certain legal matters relating to Canadian law in connection with the Subscription Receipts offered hereby will be passed upon on our behalf by Burnet, Duckworth & Palmer LLP, Calgary, Alberta and on behalf of the Underwriters by McCarthy Tétrault LLP, Calgary, Alberta. Certain legal matters relating to United States law in connection with the Subscription Receipts offered hereby will be passed upon on our behalf by Paul, Weiss, Rifkind, Wharton & Garrison LLP, New York, New York and on behalf of the Underwriters by Vinson & Elkins LLP, Houston, Texas.


INTEREST OF EXPERTS

        As of the date hereof, the partners and associates of each of Burnet, Duckworth & Palmer LLP and McCarthy Tétrault LLP each beneficially own, directly or indirectly, less than 1% of our outstanding Common Shares.

        Deloitte LLP, our independent registered chartered accountants, are independent of us within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.

        BDO Audit (WA) Pty Ltd., Aurora's external auditor, has confirmed that they are independent of Aurora in accordance with Canadian Auditing Standards as adopted by the Canadian Auditing and Assurance Standards Board.

        Information relating to our reserves included in this short form prospectus and in the Annual Information Form was calculated based on an evaluation of, and reports on, our crude oil and natural gas reserves conducted and prepared by Sproule, our independent qualified reserves evaluators. As of the date hereof Sproule does not have any registered or beneficial interest, direct or indirect, in any of our securities or other property or any of our associates or affiliates. For the purposes of this paragraph, Sproule shall be interpreted to include its designated professionals.

        Information relating to Aurora's reserves included in this short form prospectus was calculated based on an evaluation of, and reports on, our crude oil and natural gas reserves conducted and prepared by Ryder Scott, Aurora's independent qualified reserves evaluators. As of the date hereof Ryder Scott does not have any registered or beneficial interest, direct or indirect, in any securities or other property of Aurora or any of Aurora's associates or affiliates. For the purposes of this paragraph, Ryder Scott shall be interpreted to include its designated professionals.

        In addition, none of the aforementioned persons or companies, nor any director, officer or employee of any of the aforementioned persons or companies, is or is expected to be elected, appointed or employed as a director, officer or employee of us or of any of our associate or affiliate entities, except for John A. Brussa, one of our directors, who is a partner of Burnet, Duckworth & Palmer LLP.


DOCUMENTS FILED AS PART OF THE REGISTRATION STATEMENT

        The following documents have been or will be filed with the SEC as part of the registration statement of which this short form prospectus forms a part: (i) the documents listed under the heading "Documents Incorporated by Reference"; (ii) consents of independent auditors and engineers and legal counsel; and (iii) powers of attorney pursuant to which amendments to the registration statement may be signed.

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SCHEDULE "A"


FINANCIAL STATEMENTS OF AURORA

A-1



AURORA OIL & GAS LIMITED

ANNUAL FINANCIAL REPORT
For the year ended December 31, 2012

A-2



MANAGEMENT REPORT

For the year ended December 31, 2012

        Management, in accordance with Australian Accounting Standards including Australian equivalents to International Financial Reporting Standards (AIFRS), has prepared the accompanying consolidated financial statements of Aurora Oil and Gas Limited (Aurora). Financial and operating information presented throughout this report is consistent with that shown in the consolidated financial statements.

        Management is responsible for the integrity of the financial information. Internal control systems are designed and maintained to provide reasonable assurance that assets are safeguarded from loss or unauthorized use and to produce reliable accounting records for financial reporting purposes.

        BDO Audit (WA) Pty Ltd were appointed by the Company's Board of Directors to conduct an audit of the consolidated financial statements. Their examination included a review and evaluation of Aurora's internal control systems and included such tests and procedures, as they considered necessary, to provide a reasonable assurance that the consolidated financial statements are presented fairly in accordance with Australian Accounting Standards including Australian equivalents to compliance with AIFRS ensures that the financial statements of Aurora comply with International Financial Reporting Standards.

        The Board of Directors is responsible for ensuring that management fulfils its responsibilities for financial reporting and internal control. The Board exercises this responsibility through the Audit and Risk Management Committee, with assistance from the Reserves Committee regarding the annual evaluation of our petroleum and natural gas reserve. The Audit and Risk Management Committee meets regularly with management and the independent auditors to ensure that management's responsibilities are properly discharged, to review the consolidated financial statements and recommend that the consolidated financial statements be presented to the Board of Directors for approval. The Audit and Risk Management Committee also considers the independence of the external auditors and reviews their fees. The external auditors have access to the Audit and Risk Management Committee without the presence of management.

 

Signed — Jonathan Stewart   Signed — Graham Dowland    

Jonathan Stewart

 

Graham Dowland

 

 
Executive Chairman   Finance Director    

February 27, 2013

 

 

 

 

A-3



INDEPENDENT AUDIT REPORT

For the year ended December 31, 2012



LOGO
  Tel: +61 8 6382 4600
Fax: +61 8 6382 4601
www.bdo.com.au
  38 Station Street
Subiaco, WA 6008
PO Box 700 West Perth WA 6872
Australia
   

 


INDEPENDENT AUDITOR'S REPORT
TO THE MEMBERS OF AURORA OIL & GAS LIMITED

Report on the Financial Report

        We have audited the accompanying financial report of Aurora Oil & Gas Limited, which comprises the consolidated statement of financial position as at 31 December 2012 and 31 December 2011, the consolidated statement of profit or loss and other comprehensive income, the consolidated statement of changes in equity and the consolidated statement of cash flows for the years then ended, notes comprising a summary of significant accounting policies and other explanatory information.

Management's Responsibility for the Financial Report

        Management is responsible for the preparation and fair presentation of the financial report in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of the financial report that is free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

        Our responsibility is to express an opinion on the financial report based on our audit. We conducted our audit in accordance with international generally accepted auditing standards. Those standards require that we comply with relevant ethical requirements relating to audit engagements and plan and perform the audit to obtain reasonable assurance about whether the financial report is free from material misstatement.

        An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial report. The procedures selected depend on the auditor's judgement, including the assessment of the risks of material misstatement of the financial report, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the company's preparation of the financial report that gives a true and fair view in order to design 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. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial report.

        We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

BDO Audit (WA) Pty Ltd ABN 79 112 284 787 is a member of a national association of independent entities which are all members of BDO Australia Ltd ABN 77 050 110 275, an Australian company limited by guarantee. BDO Audit (WA) Pty Ltd and BDO Australia Ltd are members of BDO International Ltd, a UK company limited by guarantee, and form part of the international BDO network of independent member firms. Liability limited by a scheme approved under Professional Standards Legislation (other than for the acts or omissions of financial services licensees) in each State or Territory other than Tasmania.

A-4



LOGO
           

 

Opinion

        In our opinion, the financial report presents fairly, in all material respects the consolidated financial position of Aurora Oil & Gas Limited as at 31 December 2012 and 31 December 2011 and its performance for the years then ended in accordance with International Financial Reporting Standards as disclosed in Note 1.


/s/ BDO Audit (WA) Pty Ltd

Glyn O'Brien
Director

Perth, Western Australia
Dated this 27th day of February 2013

A-5



AURORA OIL & GAS LIMITED

CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME

For the year ended December 31, 2012

 
   
  Consolidated  
 
  Note   December 31,
2012
  December 31,
2011
 
 
   
  US$'000
  US$'000
 

Revenue from continuing operations

    (5 )   295,059     75,969  

Other income

    (6 )   5,008     1,052  
                 

Total income

          300,067     77,021  

Expenses

                   

Royalties

    (7 )   (77,625 )   (20,067 )

Production and operating expenses

    (7 )   (34,581 )   (6,737 )

Depletion, depreciation and amortisation expense

    (7 )   (39,161 )   (4,367 )

Exploration and evaluation costs

    (7 )   (4,939 )   (652 )

Finance Costs

    (7 )   (28,027 )   (136 )

Administrative expenses

          (15,134 )   (8,783 )

Share-based payment expenses

    (7 )   (4,398 )   (4,052 )
                 

Profit from continuing operations before income tax expense

          96,202     32,227  

Income tax expense

    (8 )   (37,356 )   (1,643 )
                 

Net profit attributable to owners of the Company

          58,846     30,584  
                 

Other comprehensive income

                   

Changes in fair value on equity instruments measured at fair value through other comprehensive income

    (11 )   957     (1,302 )

Change in fair value of cash flow hedges

    (19 )   (1,154 )    
                 

Other comprehensive (expenses) for the year net of tax

          (197 )   (1,302 )
                 

Total comprehensive income for the year attributable to owners of the Company

         
58,649
   
29,282
 
                 

Earnings / (loss) per share attributable to owners of the Company

                   

Basic earnings per share (US cents per share)

    (25 )   13.60     7.49  

Diluted earnings per share (US cents per share)

    (25 )   13.35     7.37  

   

The above consolidated statement of profit or loss and other comprehensive income should be read in conjunction with the accompanying notes.

A-6



AURORA OIL & GAS LIMITED

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As at December 31, 2012

 
   
  Consolidated  
 
  Note   December 31,
2012
  December 31,
2011
 
 
   
  US$'000
  US$'000
 

Current assets

                   

Cash and cash equivalents

    (9 )   67,584     70,246  

Trade and other receivables

    (10 )   89,535     14,626  
                 

Total current assets

          157,119     84,872  
                 

Non-current assets

                   

Other financial assets

    (11 )   842     2,507  

Property, plant and equipment

    (12 )   71,063     21,319  

Exploration and evaluation expenditure

    (13 )        

Oil and gas properties

    (14 )   882,373     272,128  
                 

Total non-current assets

          954,278     295,954  
                 

Total assets

          1,111,397     380,826  
                 

Current liabilities

                   

Trade and other payables

    (15 )   180,619     73,434  

Derivative financial instruments

    (19 )   1,535      

Provisions

    (16 )   334     92  
                 

Total current liabilities

          182,488     73,526  
                 

Non-current liabilities

                   

Borrowings

    (17 )   390,453     30,000  

Deferred tax liabilities

    (18 )   83,523     1,643  

Derivative financial instrument

    (19 )   114      

Provisions

    (20 )   1,705     565  
                 

Total non-current liabilities

          475,795     32,208  
                 

Total liabilities

          658,283     105,734  
                 

Net assets

          453,114     275,092  
                 

Equity

                   

Contributed equity

    (21 )   405,169     290,194  

Share-based payment reserve

    (24 )   12,165     7,767  

Fair value reserve

    (24 )   (7,054 )   (8,011 )

Foreign exchange reserve

    (24 )   (7,505 )   (7,505 )

Cash flow hedge reserve

    (24 )   (1,154 )    

Retained earnings / (accumulated losses)

    (24 )   51,493     (7,353 )
                 

Total equity

          453,114     275,092  
                 

The above consolidated statement of financial position should be read in conjunction with the accompanying notes.

On behalf of the Board of Directors:

Signed — Jonathan Stewart

  Signed — Graham Dowland
   

Jonathan Stewart
Executive Chairman

 

Graham Dowland
Finance Director

 

 

A-7



AURORA OIL & GAS LIMITED

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended December 31, 2012

 
  Contributed
Equity
  Other
Reserve
  Accumulated
Profits /
(Losses)
  Total  
 
  US$'000
  US$'000
  US$'000
  US$'000
 

Balance at January 1, 2011

    222,730     10,738     (30,609 )   202,859  

Adjustment arising from change in functional currency on January 1, 2011

    28,565     (21,237 )   (7,328 )    
                   

Balance as at January 1, 2011 restated

    251,295     (10,499 )   (37,937 )   202,859  

Profit for the year

            30,584     30,584  

Other comprehensive income

                         

Change in fair value of equity instruments measured at fair value through other comprehensive income

        (1,302 )       (1,302 )
                   

Total comprehensive income for the year

        (1,302 )   30,584     29,282  
                   

Transactions with owners, in their capacity as owners

                         

Contributed equity net of transaction costs

    38,899              

Options and performance rights expense recognised during the year

        4,052          
                   

Balance as at December 31, 2011

    290,194     (7,749 )   (7,353 )   275,092  
                   

Profit for the year

            58,846     58,846  

Other comprehensive income

                         

Change in fair value of equity instruments measured at fair value through other comprehensive income

        916         916  

Change in fair value of cash flow hedges net of tax

        (1,154 )       (1,154 )

Recognition of fair value of equity instruments measured at fair value through other comprehensive income on disposal

        41         41  
                   

Total comprehensive income for the year

        (197 )   58,846     58,649  
                   

Transactions with owners, in their capacity as owners

                         

Contributed equity net of transaction costs

    114,975             114,975  

Options and performance rights expense recognised during the year

        4,398         4,398  
                   

Balance as at December 31, 2012

    405,169     (3,548 )   51,493     453,114  
                   

   

The above consolidated statement of changes in equity should be read in conjunction with the accompanying notes.

A-8



AURORA OIL & GAS LIMITED

CONSOLIDATED STATEMENT OF CASH FLOWS

For the year ended December 31, 2012

 
   
  Consolidated  
 
   
  December 31,
2012
  December 31,
2011
 
 
   
  US$'000
  US$'000
 

Cash flows from operating activities

                   

Receipts from oil and gas sales

          221,539     62,315  

Payments to suppliers and employees

          (67,433 )   (27,368 )

Other revenue

          1,167      

Interest paid

          (11,151 )    
                 

Net cash inflow from operating activities

    (32 )   144,122     34,947  
                 

Cash flows from investing activities

                   

Payments for capitalised oil and gas assets

          (452,635 )   (64,514 )

Payment for property, plant and equipment

          (51,352 )   (12,226 )

Transaction costs

          (4,939 )    

Payment for other financial assets

          (252 )   (1,614 )

Payment for acquisition of subsidiary, net of cash acquired

    (22 )   (98,765 )    

Interest received

          247     711  
                 

Net cash (outflow) from investing activities

          (607,696 )   (77,643 )
                 

Cash flows from financing activities

                   

Proceeds from issues of shares

          120,138     42,130  

Share issue costs

          (5,163 )   (3,231 )

Proceeds from borrowings

          394,579     30,000  

Repayment of borrowings

          (39,000 )    

Borrowing costs

          (11,558 )   (2,328 )
                 

Net cash inflow from financing activities

          458,996     66,571  
                 

Net increase / (decrease) in cash and cash equivalents

          (4,578 )   23,875  

Cash and cash equivalents at the beginning of the financial year

          70,246     45,997  

Effect of exchange rates on cash holdings in foreign currencies

          1,916     374  
                 

Cash and cash equivalents at the end of the financial year

    (9 )   67,584     70,246  
                 

   

The above consolidated statement of cash flows should be read in conjunction with the accompanying notes.

A-9



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the year ended December 31, 2012

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A-10



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

A-11



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

A-12



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

A-13



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

A-14



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Fixtures and fittings

  5 years

Plant and equipment

  5 – 15 years

A-15



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

A-16



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

A-17



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

A-18



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

A-19



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

A-20



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

2.     CRITICAL ACCOUNTING ESTIMATES AND JUDGEMENTS

A-21



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

2.     CRITICAL ACCOUNTING ESTIMATES AND JUDGEMENTS (Continued)

3.     FINANCIAL RISK MANAGEMENT

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Financial assets

             
 

Cash and cash equivalents

    67,584     70,246  
 

Trade receivables

    89,535     14,626  
 

Financial assets at fair value through other comprehensive income

    842     2,507  
             
 

    157,961     87,379  
             
 

Financial liabilities

             
 

Trade and other payables

    180,619     73,434  
 

Borrowings

    390,453     30,000  
 

Derivative financial instruments

    1,649      
             
 

    572,721     103,434  
             

A-22



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

3.     FINANCIAL RISK MANAGEMENT (Continued)

   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Impact on post-tax profits

             
 

US$ oil / condensate price + $10

    26,470     10,431  
 

US$ oil / condensate price - $10

    (26,470 )   (10,431 )
 

Impact on equity

             
 

US$ oil / condensate price + $10

    26,470     10,431  
 

US$ oil / condensate price - $10

    (26,470 )   (10,431 )
             

A-23



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

3.     FINANCIAL RISK MANAGEMENT (Continued)

   
  December 31, 2012  
   
  AUD   CAD   Total  
   
  US$'000
  US$'000
  US$'000
 
 

Financial assets

                   
 

Cash and cash equivalents

    924     1,111     2,035  
 

Trade and other receivables

    320     4     324  
 

Other financial assets

    842         842  
                 
 

Total financial assets

    2,086     1,115     3,201  
                 
 

Financial liabilities

                   
 

Trade and other payables

    2,359     48     2,407  
                 
 

Total financial liabilities

    2,359     48     2,407  
                 

 

   
  December 31, 2011  
   
  AUD   CAD   Total  
   
  US$'000
  US$'000
  US$'000
 
 

Financial assets

                   
 

Cash and cash equivalents

    1,134     465     1,599  
 

Trade and other receivables

    93         93  
 

Other financial assets

    2,507         2,507  
                 
 

Total financial assets

    3,734     465     4,199  
                 
 

Financial liabilities

                   
 

Trade and other payables

    403     590     933  
                 
 

Total financial liabilities

    403     590     933  
                 

   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Impact on post-tax profits

             
 

AUD / US$ + 10%

    (39 )   397  
 

AUD / US$ - 10%

    18     (281 )
 

CAD / US$ + 10%

    110     83  
 

CAD / US$ - 10%

    (104 )   (124 )
 

Impact on equity

             
 

AUD / US$ + 10%

    (39 )   397  
 

AUD / US$ - 10%

    18     (281 )
 

CAD / US$ + 10%

    110     83  
 

CAD / US$ - 10%

    (104 )   (124 )
             

A-24



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

3.     FINANCIAL RISK MANAGEMENT (Continued)

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Impact on post-tax profit

             
 

Hypothetical 90 basis points(1) increase in interest

    2,677     (362 )
 

Hypothetical 90 basis points(1) decrease in interest

    (2,677 )   362  
 

Impact on equity

             
 

Hypothetical 90 basis points(1) increase in interest

    2,677     362  
 

Hypothetical 90 basis points(1) decrease in interest

    (2,677 )   (362 )
             

A-25



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

3.     FINANCIAL RISK MANAGEMENT (Continued)

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Impact on post-tax profit

             
 

Hypothetical 50%(1) increase in price

         
 

Hypothetical 20%(1) decrease in price

         
 

Impact on equity

             
 

Hypothetical 50%(1) increase in price

    421     1,254  
 

Hypothetical 20%(1) decrease in price

    (168 )   (501 )
             

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Cash and cash equivalents

    67,584     70,246  
 

Trade receivables

    89,535     14,045  
 

Prepaid exploration, development and lease acquisition expenses

        12,560  
             
 

Total

    157,119     96,851  
             

A-26



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

3.     FINANCIAL RISK MANAGEMENT (Continued)

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Cash at bank and short-term bank deposits

             
 

Held with Australian banks and financial institutions

             
 

AA Rated

    2,080     7,774  
 

Held with US banks and financial institutions

             
 

AA Rated

         
 

A- Rated

    65,278     62,472  
 

BBB Rated

    226      
             
 

Total

    67,584     70,246  
             

A-27



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

3.     FINANCIAL RISK MANAGEMENT (Continued)

   
  Consolidated  
 
Contractual maturities of financial liabilities
  Less than
12 months
  Between
1 and 5 years
  Total
contractual
cash flows
  Carrying
Amount
 
   
  US$'000
  US$'000
  US$'000
  US$'000
 
 

At December 31, 2012

                         
 

Non derivative

                         
 

Non-interest bearing

    180,619         180,620     180,619  
 

Borrowings — fixed rate

        365,000     513,125     360,453  
 

Borrowings — variable rate

        30,000     33,071     30,000  
                     
 

Total non derivative

    180,619     395,000     726,816     571,072  
                     
 

Derivatives

                         
 

Gross settled forward commodity price contracts

                         
 

— cash flow hedges:

                         
 

— (inflow)

    (534 )       (534 )   (534 )
 

— outflow

    2,069     114     2,183     2,183  
                     
 

Total derivative

    1,535     114     1,649     1,649  
                     
 

At December 31, 2011

                         
 

Non derivative

                         
 

Non-interest bearing

    73,433         73,433     73,433  
 

Variable rate(1)

        30,000     30,121     30,000  
                     
 

Total non derivative

    73,433     30,000     103,554     103,433  
                     

A-28



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

3.     FINANCIAL RISK MANAGEMENT (Continued)

4.     SEGMENT INFORMATION

   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Revenue from oil and gas exploration and production

    294,812     75,079  
 

Revenue from other corporate activities

    5,255     1,942  
             
 

    300,067     77,021  
             

   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Assets from oil and gas exploration and production

    1,041,143     306,173  
 

Assets from corporate activities:

             
 

Cash and cash equivalents

    67,584     70,246  
 

Other corporate assets

    2,670     4,407  
             
 

    1,111,397     380,826  
             

A-29



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

4.     SEGMENT INFORMATION (Continued)

   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Liabilities from oil and gas exploration and production

    655,090     102,100  
 

Liabilities from corporate activities

    3,193     3,634  
             
 

    658,283     105,734  
             

   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Profit from oil and gas exploration and production

    74,016     40,980  
 

(Loss) from other corporate activities

    (15,170 )   (10,396 )
             
 

    58,846     30,584  
             

5.     REVENUE

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

From continuing operations

             
 

Sales revenue

             
 

Oil and gas sales

    294,936     75,079  
 

Realised profit / (loss) on forward commodity price contracts

    (124 )    
             
 

    294,812     75,079  
             
 

Other revenue

             
 

Interest

    247     649  
 

Other

        241  
             
 

    247     890  
             
 

Total revenue from continuing operations

    295,059     75,969  
             

6.     OTHER INCOME

   
   
  Consolidated  
   
  Notes   December 31,
2012
  December 31,
2011
 
   
   
  US$'000
  US$'000
 
 

Foreign exchange gain

    (i )   3,042     989  
 

Net gain on financial assets

          770      
 

Net gain on foreign currency derivatives not qualifying as hedges

          1,167      
 

Other

          29     63  
                   
 

Total other income

          5,008     1,052  
                   

A-30



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

7.     EXPENSES

   
   
  Consolidated  
   
  Notes   December 31,
2012
  December 31,
2011
 
   
   
  US$'000
  US$'000
 
 

Royalties expense

    (i )   77,625     20,067  
 

Production and operating expense

                   
 

Sales taxes

    (ii )   10,073     2,822  
 

Operating expenses

    (iii )   24,508     3,915  
                   
 

Total production and operating expenses

          34,581     6,737  
                   
 

Deprecation and depletion expense

                   
 

Depreciation

    (iv )   3,202     929  
 

Depletion

    (v )   35,959     3,438  
                   
 

Total depletion and depreciation expense

          39,161     4,367  
                   
 

Share-based payment expenses

                   
 

Options

          3,857     3,969  
 

Performance rights

          541     83  
                   
 

Total share-based payment expense

    (vi )   4,398     4,052  
                   
 

Finance costs

                   
 

Interest expense

          24,539     70  
 

Amortisation of borrowing costs

          2,638     66  
 

Amortisation of debt premium and debt discount

          289      
 

Other financing fees

          561      
                   
 

Total finance costs

    (vii )   28,027     136  
                   
 

Exploration and evaluation costs written off

    (viii )   4,939     652  
                   

A-31



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

8.     INCOME TAX EXPENSE

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

(a) Income tax expense

             
 

Current tax

         
 

Deferred tax

    37,356     1,643  
             
 

Income tax expense

    37,356     1,643  
             
 

(b) Reconciliation of income tax expense to prima facie tax payable

             
 

Profit from continuing operations before income tax expense

    96,202     32,227  
             
 

Tax at the Australian statutory tax rate of 30% (December 31, 2011: 30%)

    28,861     9,668  
 

Tax effect of amounts that are not deductible (taxable) in calculating taxable income

             
 

Share-based payment expense

    1,157     1,041  
 

Foreign exchange gains not assessable

    (1,026 )   (321 )
 

Revenue losses not previously recognised now brought to account

    (357 )   (426 )
 

(Expense) / benefit from a previously unrecognised temporary difference now recognised

    3,205     (8,833 )
 

Income tax rate differences

    5,359     456  
 

Other non-allowable deductions

    157     58  
             
 

Income tax expense

    37,356     1,643  
             
 

(c) Tax expense (income) relating to items of other comprehensive income

             
 

Financial assets at fair value through other comprehensive income

    1,509      
 

Cash flow hedges

    495      
             
 

    2,004      
             

9.     CASH AND CASH EQUIVALENTS

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Held with Australian banks and financial institutions

             
 

Cash at bank and in hand

    1,976     7,137  
 

Deposits at call

    104     637  
 

Held with US banks and financial institutions

             
 

Cash at bank and in hand

    65,504     62,472  
             
 

    67,584     70,246  
             

A-32



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

10.   TRADE AND OTHER RECEIVABLES

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Trade receivables

    89,535     14,626  
             

11.   OTHER FINANCIAL ASSETS

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Financial assets at fair value through other comprehensive income

    842     2,507  
             

A-33



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

12.   PROPERTY, PLANT AND EQUIPMENT

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Production facilities and field equipment

             
 

Production facilities and field equipment at cost

    73,685     21,468  
 

Production facilities and field equipment accumulated depreciation

    (3,876 )   (880 )
             
 

Total production facilities and field equipment

    69,809     20,588  
             
 

Reconciliation of movement in production facilities and field equipment

             
 

Balance at the beginning of the financial period

    20,588      
 

Additions

    52,217     21,297  
 

Transfer from oil and gas properties

        171  
 

Depreciation expense

    (2,996 )   (880 )
             
 

Total production facilities and field equipment

    69,809     20,588  
             
 

Office equipment

             
 

Office equipment at cost

    1,509     780  
 

Office equipment accumulated depreciation

    (256 )   (49 )
             
 

Total office equipment

    1,253     731  
             
 

Reconciliation of movement in office equipment

             
 

Balance at the beginning of the financial period

    731      
 

Additions

    729     780  
 

Depreciation expense

    (206 )   (49 )
             
 

Total office equipment

    1,254     731  
             
 

Total property, plant and equipment

    71,063     21,319  
             

A-34



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

13.   EXPLORATION AND EVALUATION EXPENDITURE

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Balance at the beginning of the financial period

        71  
 

Transfer to Producing Projects

         
 

Capitalised expenditure

         
 

Exploration and evaluation expenditure written off

        (71 )
             
 

Total exploration and evaluation expenditure

         
             

14.   OIL AND GAS PROPERTIES

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Producing projects

             
 

At cost

    917,501     275,671  
 

Accumulated depletion

    (41,207 )   (3,543 )
             
 

Net carrying value

    876,294     272,128  
             
 

Development projects

             
 

At cost

    6,079      
             
 

Net carrying value

    6,079      
             
 

Total

    882,373     272,128  
             

A-35



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

14.   OIL AND GAS PROPERTIES (Continued)

   
  Tangible Costs   Intangible Costs   Prepaid Drilling,
Completion and
Lease Acquisition Costs
  Total  
   
  US$'000
  US$'000
  US$'000
  US$'000
 
 

PRODUCING PROJECTS

                         
 

Cost

                         
 

Balance at January 1, 2011

    2,174     109,121     5,866     117,161  
 

Transfer from development projects

        38,508         38,508  
 

Additions

    10,422     98,718         109,140  
 

Increase in restoration provision

        565         565  
 

Transfer to property, plant and equipment

    (171 )           (171 )
 

Capitalised borrowing costs(1)

        3,774         3,774  
 

Net movement in prepaid costs

            6,694     6,694  
                     
 

Balance at December 31, 2011

    12,425     250,686     12,560     275,671  
                     
 

Additions

    51,998     595,602         647,600  
 

Increase in restoration provision

        1,140         1,140  
 

Capitalised borrowing costs(1)

        5,650         5,650  
 

Net movement in prepaid costs

            (12,560 )   (12,560 )
                     
 

Balance at December 31, 2012

    64,423     853,078         917,501  
                     
 

Accumulated depletion

                         
 

Balance at January 1, 2011

    (1 )   (38 )       (39 )
 

Depletion charge

    (161 )   (3,277 )       (3,438 )
 

Amortisation(2)

        (66 )       (66 )
                     
 

Balance at December 31, 2011

    (162 )   (3,381 )       (3,543 )
                     
 

Depletion charge

    (2,525 )   (33,434 )       (35,959 )
 

Amortisation(2)

        (1,705 )       (1,705 )
                     
 

Balance at December 31, 2012

    (2,687 )   (38,520 )       (41,207 )
                     
 

Net carrying value

                         
 

Balance at December 31, 2011

    12,263     247,305         272,128  
                     
 

Balance at December 31, 2012

    61,736     814,558         876,294  
                     

A-36



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

14.   OIL AND GAS PROPERTIES (Continued)

   
  Tangible Costs   Intangible Costs   Prepaid Drilling,
Completion and
Lease Acquisition
Costs
  Total  
   
  US$'000
  US$'000
  US$'000
  US$'000
 
 

DEVELOPMENT PROJECTS

                         
 

Cost

                         
 

Balance at January 1, 2011

        38,508         38,508  
 

Transfer to producing projects

        (38,508 )       (38,508 )
                     
 

Balance at December 31, 2011

                 
                     
 

Additions

        6,079         6,079  
                     
 

Balance at December 31, 2012

        6,079         6,079  
                     
 

Net carrying value

                         
 

Balance at December 31, 2011

                 
                     
 

Balance at December 31, 2012

        6,079         6,079  
                     

15.   TRADE AND OTHER PAYABLES

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Trade payable and accruals

    180,619     73,434  
             

16.   PROVISIONS — CURRENT

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Employee Benefits

    334     92  
             

A-37



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

17.   BORROWINGS — NON CURRENT

   
   
  Consolidated  
   
   
  December 31,
2012
  December 31,
2011
 
   
   
  US$'000
  US$'000
 
 

Secured

                   
 

Senior secured syndicated facility

    (a )   30,000     30,000  
 

Unsecured

                   
 

Senior unsecured notes

    (b )   360,453      
                   
 

          390,453     30,000  
                   

 
Owner / Grantor
  Issuer   Percentage
Owned
  Percentage
Pledged
  Class of stock
 

Aurora Oil and Gas Limited

  Aurora USA Oil and Gas Inc.     100%     100%   Common Stock
 

Aurora USA Oil and Gas Inc.

  Wardanup Oil and Gas Inc.     100%     100%   Common Stock
 

Aurora USA Oil and Gas Inc.

  Sugarloaf Oil and Gas Inc.     100%     100%   Common Stock
 

Aurora USA Oil and Gas Inc.

  Yallingup Oil and Gas Inc.     100%     100%   Common Stock
 

Aurora USA Oil and Gas Inc.

  Trigg Oil and Gas Inc.     100%     100%   Common Stock

A-38



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

17.   BORROWINGS — NON CURRENT (Continued)

18.   DEFERRED TAX LIABILITIES

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

(a) Deferred tax asset

             
 

Arising from temporary differences attributable to:

             
 

Tax losses(1)

             
 

Australia

    216     284  
 

United States

    142,967     42,623  
 

Share issue expense

    464     239  
 

Other

    8,492     7,406  
             
 

Total deferred tax asset

    152,139     50,552  
 

Less set off of deferred tax liabilities under set-off provisions (b)

    (152,139 )   (50,552 )
             
 

(b) Deferred tax liability

             
 

Arising from temporary differences attributable to:

             
 

Financial assets through other comprehensive income

    1,509      
 

Cash flow hedge

    495      
 

Oil and gas properties

    (232,547 )   (52,189 )
 

Management fees and borrowing costs

    (5,119 )   (7 )
             
 

Total deferred tax liabilities

    (235,662 )   (52,195 )
 

Less set off of deferred tax asset under set-off provisions (a)

    152,139     50,552  
             
 

Net deferred tax liabilities

    (83,523 )   (1,643 )
             
 

Deferred tax liabilities expected to be settled within 12 months

         
             
 

Deferred tax liabilities expected to be settled after more than 12 months

    (83,523 )   (1,643 )
             

19.   DERIVATIVE FINANCIAL INSTRUMENTS

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Forward commodity contracts — cash flow hedges

             
 

Current

    1,535      
 

Non-current

    114      
             
 

Total derivative financial instrument liabilities

    1,649      
             

A-39



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

19.   DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

   
   
   
   
   
  Weighted average US$ / barrel    
 
 
Year of
delivery
  Subject of
contract
  Reference   Option
traded
  Barrels   Strike price   Floor price   Ceiling
price
  Fair value  
   
   
   
   
   
   
   
   
  US$'000
 
 

2013

  Oil   Nymex WTI   Swap     102,000     92.15             (111 )
 

2013

  Oil   LLS   Swap     108,000     95.40             (1,144 )
 

2013

  Oil   Nymex WTI   Zero Cost Collar     210,000         77.86     102.89     (280 )
 

2014

  Oil   Nymex WTI   Swap     78,000     90.66             (114 )
                                           
 

Total

    498,000                       (1,649 )
                                           

20.   PROVISIONS — NON-CURRENT

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Restoration provision

    1,705     565  
 

Reconciliation of movement in restoration provision

             
 

Balance at the beginning of the financial period

    565      
 

Provision made during the year

    1,140     565  
             
 

Balance at the end of the financial year

    1,705     565  
             

21.   CONTRIBUTED EQUITY

   
  December 31,
2012
  December 31,
2011
  December 31,
2012
  December 31,
2011
 
   
  Securities
  Securities
  US$'000
  US$'000
 
 

Share capital

                         
 

Ordinary shares

    447,885,778     411,655,353     405,169     290,194  
                     
 

Total contributed equity

    447,885,778     411,655,353     405,169     290,194  
                     

A-40



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

21.   CONTRIBUTED EQUITY (Continued)

   
  Date   Number of
Securities
  Issue Price   US$'000  
 

Balance at December 31, 2010

          383,455,342           222,730  
 

Adjustment to reflect change in functional currency on January 1, 2011

                    28,565  
                         
 

Balance January 1, 2011 restated

          383,455,342           251,295  
 

Placement

   
25-Jan-11
   
23,399,480
 
A$

1.60
   
37,212
 
 

Placement

    25-Jan-11     2,760,520   C$ 1.60     4,433  
 

Options exercised

    01-Apr-11     250,000   A$ 0.50     129  
 

Prospectus share issue

    09-Jun-11     1   A$ 3.00      
 

Performance rights exercised

    26-Aug-11     1,290,000          
 

Options exercised

    17-Nov-11     500,000   A$ 0.70     356  
 

Share issue costs

                      (3,231 )
                         
 

Balance at December 31, 2011

          411,655,343           290,194  
                         
 

Placement

    16-May-12     15,802,816   A$ 3.55     54,721  
 

Placement

    16-May-12     18,000,000   C$ 3.55     61,359  
 

Placement

    28-Jun-12     1,137,619   A$ 3.55     4,058  
 

Performance rights exercised

    15-Aug-12     390,000          
 

Performance rights exercised

    20-Aug-12     900,000          
 

Share issue costs

                      (5,163 )
                         
 

Balance at December 31, 2012

          447,885,778           405,169  
                         

22.   BUSINESS COMBINATION

   
  US$'000  
 

Purchase consideration (refer to (b) below):

       
 

Cash paid

    106,136  
 

Fair value of shares owned prior to the on-market cash offer

    3,405  
         
 

Total purchase consideration

    109,541  
         

A-41



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

22.   BUSINESS COMBINATION (Continued)

   
  Fair value  
   
  US$'000
 
 

Cash and cash equivalents

    7,371  
 

Trade and other receivables

    1,636  
 

Property, plant and equipment

    360  
 

Oil and gas properties

    164,664  
 

Trade and other payables

    (8,830 )
 

Borrowings

    (9,000 )
 

Deferred tax liability

    (46,526 )
 

Provisions

    (134 )
         
 

Net identifiable assets acquired

    109,541  
         

   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Outflow of cash to acquire subsidiary, net of cash acquired

             
 

Cash consideration

    106,136      
 

Less: Balances acquired

             
 

Cash

    7,371      
             
 

Outflow of cash — investing activity

    98,765      
             

A-42



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

23.   OPTIONS AND PERFORMANCE RIGHTS

   
   
  December 31, 2012   December 31, 2011   Exercise Price   Expiry  
   
   
  Number
  Number
   
   
 
 

Type 18

  AUTAZ     900,000     2,190,000     n/a     19-Feb-15  
 

Type 19

  AUTAI     150,000     150,000   A$ 1.60     9-Nov-15  
 

Type 20

  AUTAI     150,000     150,000   A$ 1.85     9-Nov-15  
 

Type 21

  AUTAI     150,000     150,000   A$ 2.10     9-Nov-15  
 

Type 22

  AUTAZ     600,000     600,000   A$ 1.60     24-Jan-16  
 

Type 23

  AUTAZ     600,000     600,000   A$ 1.85     24-Jan-16  
 

Type 24

  AUTAZ     600,000     600,000   A$ 2.10     24-Jan-16  
 

Type 25

  AUTAK     250,000     250,000   A$ 3.00     30-Apr-15  
 

Type 26

  AUTAK     250,000     250,000   A$ 3.50     30-Apr-16  
 

Type 27

  AUTAK     250,000     250,000   A$ 4.00     30-Apr-17  
 

Type 28

  AUTAK     500,000     500,000   A$ 3.28     30-May-16  
 

Type 29

  AUTAK     250,000     250,000   A$ 3.28     30-May-16  
 

Type 30

  AUTAK     500,000     500,000   A$ 3.58     30-May-16  
 

Type 31

  AUTAK     250,000     250,000   A$ 3.58     30-May-16  
 

Type 32

  AUTAK     300,000     300,000   A$ 3.76     30-Sep-15  
 

Type 33

  AUTAK     350,000     350,000   A$ 4.10     30-Sep-16  
 

Type 34

  AUTAK     350,000     350,000   A$ 4.45     30-Sep-17  
 

Type 35

  AUTAM     49,396         n/a     01-Jan-15  
 

Type 36

  AUTAM     98,795         n/a     01-Jan-15  
 

Type 37

  AUTAM     197,586         n/a     01-Jan-15  
 

Type 38

  AUTAO     100,000         n/a     19-Oct-15  
 

Type 39

  AUTAO     100,000         n/a     19-Oct-15  
 

Type 40

  AUTAO     100,000         n/a     19-Oct-15  
 

Type 41

  AUTAK     250,000       A$ 4.00     19-Oct-17  
 

Type 42

  AUTAK     250,000       A$ 4.50     19-Oct-18  
 

Type 43

  AUTAK     250,000       A$ 5.00     19-Oct-19  
 

Type 44

  AUTAO     5,962         n/a     01-Jan-15  
 

Type 45

  AUTAO     11,923         n/a     01-Jan-15  
 

Type 46

  AUTAO     23,847         n/a     01-Jan-15  
                             
 

Total

    7,837,509     7,690,000              
                             

A-43



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

23.   OPTIONS AND PERFORMANCE RIGHTS (Continued)

   
  Date    
   
  Number  
 

Balance at December 31, 2010

    4,890,000  
 

Granted during the year:

    24-Jan-11   Type 22   AUTAZ     600,000  
 

    24-Jan-11   Type 23   AUTAZ     600,000  
 

    24-Jan-11   Type 24   AUTAZ     600,000  
 

    29-Apr-11   Type 25   AUTAK     250,000  
 

    29-Apr-11   Type 26   AUTAK     250,000  
 

    29-Apr-11   Type 27   AUTAK     250,000  
 

    30-May-11   Type 28   AUTAK     500,000  
 

    30-May-11   Type 29   AUTAK     250,000  
 

    30-May-11   Type 30   AUTAK     500,000  
 

    30-May-11   Type 31   AUTAK     250,000  
 

    3-Jun-11   Type 32   AUTAK     300,000  
 

    3-Jun-11   Type 33   AUTAK     350,000  
 

    3-Jun-11   Type 34   AUTAK     350,000  
 

Exercised during the year:

    31-Mar-11   Type 8   AUTAQ     (250,000 )
 

    26-Aug-11   Type 18   AUTAZ     (1,290,000 )
 

    18-Nov-11   Type 16   AUTAM     (500,000 )
 

Lapsed during the year:

    7-Oct-11   Type 18   AUTAZ     (210,000 )
                       
 

Balance at December 31, 2011

    7,690,000  
                       
 

Granted during the year:

    1-Feb-12   Type 35   AUTAM     49,796  
 

    1-Feb-12   Type 36   AUTAM     99,593  
 

    1-Feb-12   Type 37   AUTAM     199,185  
 

    18-Oct-12   Type 38   AUTAO     100,000  
 

    18-Oct-12   Type 39   AUTAO     100,000  
 

    18-Oct-12   Type 40   AUTAO     100,000  
 

    18-Oct-12   Type 41   AUTAK     250,000  
 

    18-Oct-12   Type 42   AUTAK     250,000  
 

    18-Oct-12   Type 43   AUTAK     250,000  
 

    31-Dec-12   Type 44   AUTAO     5,962  
 

    31-Dec-12   Type 45   AUTAO     11,923  
 

    31-Dec-12   Type 46   AUTAO     23,847  
 

Exercised during the year:

    15-Aug-12   Type 18   AUTAZ     (390,000 )
 

    20-Aug 12   Type 18   AUTAZ     (900,000 )
 

Lapsed during the year:

    20-Apr-12   Type 35, 36, 37   AUTAM     (1,987 )
 

    17-May-12   Type 35, 36, 37   AUTAM     (810 )
                       
 

Balance at December 31, 2012

    7,837,509  
                       

A-44



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

24.   RESERVES AND RETAINED EARNINGS

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

(a) Share based payment reserve

             
 

Balance at the beginning of the financial period

    7,767     2,969  
 

Adjustment arising from change in functional currency on January 1, 2011

        746  
             
 

Restated opening balance

    7,767     3,715  
 

Share-based payment expense

    4,398     4,052  
             
 

Closing balance

    12,165     7,767  
             
 

(b) Fair value reserve

             
 

Balance at the beginning of the financial period

    (8,011 )   (5,196 )
 

Adjustment arising from change in functional currency on January 1, 2011

        (1,513 )
             
 

Restated opening balance

    (8,011 )   (6,709 )
 

Change in financial assets at fair value through other comprehensive income

    (593 )   (1,302 )
 

Recognition of fair value of equity instruments measured at fair value through other comprehensive income on disposal

    41      
 

Deferred tax

    1,509      
             
 

Closing balance

    (7,054 )   (8,011 )
             
 

(c) Foreign exchange reserve

             
 

Balance at the beginning of the financial period

    (7,505 )   12,965  
 

Adjustment arising from change in functional currency on January 1, 2011

        (20,470 )
             
 

Restated opening balance

    (7,505 )   (7,505 )
 

Currency translation differences arising during the period / year

         
             
 

Closing balance

    (7,505 )   (7,505 )
             
 

(d) Cash flow hedge reserve

             
 

Balance at the beginning of the financial period

         
 

Change in derivative financial instruments at fair value through other comprehensive income

    (1,649 )    
 

Deferred tax

    495      
             
 

Closing balance

    (1,154 )    
             
 

(e) Retained earnings / (accumulated losses)

             
 

Balance at the beginning of the financial period

    (7,353 )   (30,609 )
 

Adjustment arising from change in functional currency on January 1, 2011

        (7,328 )
             
 

Restated opening balance

    (7,353 )   (37,937 )
 

Net profit for the year

    58,846     30,584  
             
 

Closing balance

    51,493     (7,353 )
             

25.   EARNINGS PER SHARE

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US Cents
  US Cents
 
 

(a) Earnings per share attributable to members of the Company

             
 

Basic earnings per share

    13.60     7.49  
 

Diluted earnings per share

    13.35     7.37  
             

A-45



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

25.   EARNINGS PER SHARE (Continued)

 

   
  US$'000   US$'000  
 

(b) Earnings used in calculation of basic / diluted earnings per share

             
 

Net Profit after tax

    58,846     30,584  

 

   
  Shares   Shares  
 

(c) Weighted average number of ordinary shares used as the denominator in calculating:

             
 

Basic earnings per share

    432,588,491     408,518,986  
 

Diluted earnings per share

    439,407,647     415,017,754  
             

26.   DIVIDENDS

27.   SHARE BASED PAYMENTS

 
Grant date:
  Type 18
AUTAZ
19-Feb-10
 
 

Expected price volatility(1)

    85%  
 

Exercise price

    Nil  
 

Expiry date

    19-Feb-2015  
 

Share price at grant date

    A$0.29  
 

Risk free interest rate(2)

    4.8%  

A-46



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

27.   SHARE BASED PAYMENTS (Continued)

 
Earliest exercise date:
  July 31, 2013  
 

Jonathan Stewart

    900,000  

 
Vesting date:
  July 31, 2013  
 

Weighted average fair value

  A$ 0.03  

 
Grant Date
  Expiry Date   Balance at
start of
the year
  Granted
during
the year
  Exercised
during
the year
  Net other
changes(1)
  Balance at
end of
the year
  Vested and
exercisable at
end of the year
 
   
   
  Number
  Number
  Number
  Number
  Number
  Number
 
 

At December 31, 2012

                               
 

19-Feb-2010

    19-Feb-2015     2,190,000         (1,290,000 )       900,000      
 

At December 31, 2011

                               
 

19-Feb-2010

    19-Feb-2015     3,690,000         (1,290,000 )   (210,000 )   2,190,000    
 

A-47



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

27.   SHARE BASED PAYMENTS (Continued)

   
  Expected
price
volatility(1)
  Exercise
price
  Vest
date
  Expiry
date
  Share price
at
grant
date
  Risk free
interest rate(2)
  Fair value per
performance
right
 
 

Grant date: February 1, 2012 — valuation grant date: May 29, 2012(3)

             
 

Type 35A: AUTAM

    55%   N/a     15-Feb-12     1-Jan-15   A$ 3.42     2.74%   US$ 3.47  
 

Type 35B: AUTAM

    N/a   N/a     15-Feb-12     1-Jan-15   A$ 3.42     N/a   US$ 2.46  
 

Type 36A: AUTAM(4)

    45%   N/a     1-Jan-14     1-Jan-15   A$ 3.89     2.79%   US$ 2.84  
 

Type 36B: AUTAM(4)

    N/a   N/a     1-Jan-14     1-Jan-15   A$ 3.89     N/a   US$ 4.05  
 

Type 37A: AUTAM(4)

    45%   N/a     1-Jan-15     1-Jan-15   A$ 3.89     2.65%   US$ 2.83  
 

Type 37B: AUTAM(4)

    N/a   N/a     1-Jan-15     1-Jan-15   A$ 3.89     N/a   US$ 4.05  
 

Grant date: May 29, 2012(5)

                               
 

Type 35A: AUTAM

    55%   N/a     15-Feb-12     1-Jan-15   A$ 3.42     2.74%   US$ 3.47  
 

Type 35B: AUTAM

    N/a   N/a     15-Feb-12     1-Jan-15   A$ 3.42     N/a   US$ 2.46  
 

Type 36A: AUTAM(4)

    45%   N/a     1-Jan-14     1-Jan-15   A$ 3.89     2.79%   US$ 2.84  
 

Type 36B: AUTAM(4)

    N/a   N/a     1-Jan-14     1-Jan-15   A$ 3.89     N/a   US$ 4.05  
 

Type 37A: AUTAM(4)

    45%   N/a     1-Jan-15     1-Jan-15   A$ 3.89     2.65%   US$ 2.83  
 

Type 37B: AUTAM(4)

    N/a   N/a     1-Jan-15     1-Jan-15   A$ 3.89     N/a   US$ 4.05  
 

Grant date: October 18, 2012

                               
 

Type 38: AUTAO

    N/a   N/a     18-Oct-13     19-Oct-15   A$ 3.94     N/a   US$ 4.09  
 

Type 39: AUTAO

    N/a   N/a     18-Oct-14     19-Oct-15   A$ 3.94     N/a   US$ 4.09  
 

Type 40: AUTAO

    N/a   N/a     18-Oct-15     19-Oct-15   A$ 3.94     N/a   US$ 4.09  
 

Grant date: December 31, 2012

                               
 

Type 44A: AUTAO

    45%   N/a     1-Jan-13     1-Jan-16   A$ 3.63     2.63%   US$ 1.89  
 

Type 45A: AUTAO

    45%   N/a     1-Jan-14     1-Jan-16   A$ 3.63     2.62%   US$ 2.07  
 

Type 46A: AUTAO

    45%   N/a     1-Jan-15     1-Jan-16   A$ 3.63     2.66%   US$ 2.27  

A-48



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

27.   SHARE BASED PAYMENTS (Continued)

 
Grant Date
  Expiry Date   Exercise
Price
  Balance at
start of
the year
  Granted
during
the year
  Exercised
during
the year
  Forfeited
during
the year
  Balance at
end of
the year
  Vested and
exercisable
at end of
the year
 
   
   
  A$
  Number
  Number
  Number
  Number
  Number
  Number
 
 

At December 31, 2012

                                     
 

1-Feb-2012

  1-Jan-2015     N/a         99,674         (2,797 )   96,877      
 

29-May-2012

  1-Jan-2015     N/a         248,900             248,900      
 

18-Oct-2012

  18-Oct-2015     N/a         300,000             300,000      
 

31-Dec-2012

  1-Jan-2015     N/a         41,732             41,732      
                                       
 

Total

        690,306         (2,797 )   687,509      
                                       

   
  December 31, 2012   December 31, 2011  
 
Recipient
  Grant date   Number of options
granted
  Grant date   Number of options
granted
 
 

Gren Schoch

            24-Jan-2011     750,000  
 

Graham Dowland

            24-Jan-2011     1,050,000  
 

Darren Wasylucha

            29-Apr-2011     750,000  
 

Fiona Harris

            30-May-2011     500,000  
 

Alan Watson

            30-May-2011     500,000  
 

William Molson

            30-May-2011     500,000  
 

Michael Verm

            3-Jun-2011     1,000,000  
 

Douglas Brooks(1)

    18-Oct-12     750,000        
 

   
  Expected
price
volatility(i)
  Exercise
price
  Vest
date
  Expiry date   Share price
at
grant date
  Risk free
interest rate(ii)
  Fair value
per option
 
 

Grant date: October 18, 2012

                               
 

Type 41: AUTAK

    50%     A$4.00     19-Oct-13     19-Oct-17     A$3.94     2.50%   US$ 1.60  
 

Type 42: AUTAK

    50%     A$4.50     19-Oct-14     19-Oct-18     A$3.94     2.50%   US$ 1.67  
 

Type 43: AUTAK

    50%     A$5.00     19-Oct-15     19-Oct-19     A$3.94     2.50%   US$ 1.74  

A-49



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

27.   SHARE BASED PAYMENTS (Continued)

   
  Expected
price
volatility(1)
  Exercise
price
  Vest
date
  Expiry date   Share price
at
grant date
  Risk free
interest rate(2)
  Fair value
per option
 
 

Grant date: January 24, 2011

                               
 

Type 22: AUTAZ

    85%     A$1.60     24-Jan-12     24-Jan-16     A$2.70     5.29%   US$ 1.41  
 

Type 23: AUTAZ

    85%     A$1.85     24-Jan-13     24-Jan-16     A$2.70     5.29%   US$ 1.56  
 

Type 24: AUTAZ

    85%     A$2.10     24-Jan-14     24-Jan-16     A$2.70     5.29%   US$ 1.68  
 

Grant date: April 29, 2011

                               
 

Type 25: AUTAK

    85%     A$3.00     30-Apr-12     30-Apr-15     A$2.65     5.24%   US$ 1.45  
 

Type 26: AUTAK

    85%     A$3.50     30-Apr-13     30-Apr-16     A$2.65     5.24%   US$ 1.60  
 

Type 27: AUTAK

    85%     A$4.00     30-Apr-14     30-Apr-17     A$2.65     5.24%   US$ 1.73  
 

Grant date: May 30, 2011

                               
 

Type 28: AUTAK

    85%     A$3.28     30-May-12     30-May-16     A$3.19     5.00%   US$ 1.93  
 

Type 29: AUTAK

    85%     A$3.28     30-Sep-12     30-May-16     A$3.19     5.00%   US$ 1.98  
 

Type 30: AUTAK

    85%     A$3.58     30-May-13     30-May-16     A$3.19     5.00%   US$ 2.00  
 

Type 31: AUTAK

    85%     A$3.58     30-Sep-13     30-May-16     A$3.19     5.00%   US$ 2.04  
 

Grant date: June 3, 2011

                                           
 

Type 32: AUTAK

    85%     A$3.76     30-Sep-12     30-Sep-15     A$3.40     5.09%   US$ 1.94  
 

Type 33: AUTAK

    85%     A$4.10     30-Sep-13     30-Sep-16     A$3.40     5.09%   US$ 2.16  
 

Type 34: AUTAK

    85%     A$4.45     30-Sep-14     30-Sep-17     A$3.40     5.09%   US$ 2.34  

A-50



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

27.   SHARE BASED PAYMENTS (Continued)

 
Grant Date
  Expiry Date   Exercise
Price
  Balance at
start of the year
  Granted
during
the year
  Exercised
during
the year
  Forfeited
during
the year
  Balance at
end of
the year
  Vested and
exercisable
at end of the year
 
   
   
  A$
  Number
  Number
  Number
  Number
  Number
  Number
 
 

At December 31, 2012

                                     
 

18-Oct-12

    19-Oct-17 to 19-Oct-19     4.00 - 5.00         750,000             750,000      
 

3-Jun-11

    30-Sept-15 to 30-Sept-17     3.76 - 4.45     1,000,000                 1,000,000     300,000  
 

30-May-11

    30-May-16     3.28 - 3.58     1,500,000                 1,500,000     750,000  
 

29-Apr-11

    30-April-15 to 30-Apr-17     3.00 - 4.00     750,000                 750,000     250,000  
 

24-Jan-11

    24-Jan-16     1.60 - 2.10     1,800,000                 1,800,000     600,000  
 

9-Nov-10

    9-Nov-15     1.60 - 2.10     450,000                 450,000     300,000  
                                         
 

Total

    5,500,000     750,000             6,250,000     2,200,000  
                                         
 

Weighted average exercise price

   
A$2.92
   
A$4.50
   
N/a
   
N/a
   
A$3.11
   
A$2.64
 
                                         
 

At December 31, 2011

                                     
 

3-Jun-11

    30-Sept-15 to 30-Sept-17     3.76 - 4.45         1,000,000             1,000,000      
 

30-May-11

    30-May-16     3.28 - 3.58         1,500,000             1,500,000      
 

29-Apr-11

    30-April-15 to 30-Apr-17     3.00 - 4.00         750,000             750,000      
 

24-Jan-11

    24-Jan-16     1.60 - 2.10         1,800,000             1,800,000      
 

9-Nov-10

    9-Nov-15     1.60 - 2.10     450,000                 450,000     150,000  
                                         
 

Total

    450,000     5,050,000             5,500,000     150,000  
                                         
 

Weighted average exercise price

    A$1.85     A$3.01     N/a     N/a     A$2.92     A$1.60  
                                         

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Options issued

    3,857     3,969  
 

Performance rights issued under PRP

    32     83  
 

Performance rights issued under LTIP

    509      
             
 

    4,398     4,052  
             

A-51



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

28.   KEY MANAGEMENT PERSONNEL DISCLOSURE

 
Name
  Position
 

Mr. Jonathan Stewart(1)

  Executive Chairman
 

Mr. Graham Dowland

  Finance Director
 

Mr. Ian Lusted

  Technical Director
 

Mr. Gren Schoch

  Non-Executive Director
 

Ms. Fiona Harris

  Non-Executive Director
 

Mr. Alan Watson

  Non-Executive Director
 

Mr. William Molson

  Non-Executive Director

 
Name
  Position
 

Mr. Douglas E Brooks(2)

  Chief Executive Officer
 

Mr. Michael Verm

  Chief Operating Officer

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Short-term employee benefits

    4,023     2,385  
 

Post-employment benefits

    222     107  
 

Share-based payments

    3,735     3,412  
             
 

    7,980     5,904  
             

A-52



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

28.   KEY MANAGEMENT PERSONNEL DISCLOSURE (Continued)

 
December 31, 2012
  Balance at start of the year   Granted as compensation   Exercised   Net other changes   Balance at the end of year   Vested and exercisable   Unvested  
 

Directors of Aurora Oil and Gas Limited

                               
 

Jonathan Stewart

                                           
 

Performance rights PRP

    1,800,000         (900,000 )       900,000         900,000  
 

Performance rights LTIP

        152,279             152,279         152,279  
                                 
 

Balance at

                                           
 

December 31, 2012

    1,800,000     152,279     (900,000 )       1,052,279         1,052,279  
                                 
 

Graham Dowland

                                           
 

Options

    1,050,000                 1,050,000     350,000     700,000  
 

Performance rights LTIP

        48,088             48,088         48,088  
                                 
 

Balance at

                                           
 

December 31, 2012

    1,050,000     48,088             1,098,088     350,000     748,088  
                                 
 

Ian Lusted

                                           
 

Performance rights PRP

    390,000         (390,000 )                
 

Performance rights LTIP

        48,533             48,533         48,533  
                                 
 

Balance at

                                           
 

December 31, 2012

    390,000     48,533     (390,000 )       48,533         48,533  
                                 
 

Gren Schoch

                                           
 

Options

    750,000                 750,000     250,000     500,000  
                                 
 

Balance at

                                           
 

December 31, 2012

    750,000                 750,000     250,000     500,000  
                                 
 

Fiona Harris

                                           
 

Options

    500,000                 500,000     250,000     250,000  
                                 
 

Balance at

                                           
 

December 31, 2012

    500,000                 500,000     250,000     250,000  
                                 
 

Alan Watson

                                           
 

Options

    500,000                 500,000     250,000     250,000  
                                 
 

Balance at

                                           
 

December 31, 2012

    500,000                 500,000     250,000     250,000  
                                 
 

William Molson

                                           
 

Options

    500,000                 500,000     250,000     250,000  
                                 
 

Balance at

                                           
 

December 31, 2012

    500,000                 500,000     250,000     250,000  
                                 

 

A-53



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

28.   KEY MANAGEMENT PERSONNEL DISCLOSURE (Continued)

 
December 31, 2012
  Balance at start of the year   Granted as compensation   Exercised   Net other changes   Balance at the end of year   Vested and exercisable   Unvested  
 

Other key management personnel of the Group

                               
 

Michael Verm

                                           
 

Performance rights LTIP

        22,103             22,103         22,103  
 

Options

    1,000,000                 1,000,000     300,000     700,000  
                                 
 

Balance at

                                           
 

December 31, 2012

    1,000,000     22,103             1,022,103     300,000     722,103  
                                 
 

Douglas E Brooks(1)

                                           
 

Performance rights LTIP

        300,000             300,000         300,000  
 

Options

        750,000             750,000         750,000  
                                 
 

Balance at

                                           
 

December 31, 2012

        1,050,000             1,050,000         1,050,000  
                                 

 
December 31, 2011
  Balance at start of the year   Granted as compensation   Exercised   Net other changes   Balance at the end of year   Vested and exercisable   Unvested  
 

Directors of Aurora Oil and Gas Limited

                               
 

Jonathan Stewart

                                           
 

Performance rights PRP

    2,550,000         (750,000 )       1,800,000         1,800,000  
                                 
 

Balance at

                                           
 

December 31, 2011

    2,550,000         (750,000 )       1,800,000         1,800,000  
                                 
 

Graham Dowland

                                           
 

Options

        1,050,000             1,050,000         1,050,000  
                                 
 

Balance at

                                           
 

December 31, 2011

        1,050,000             1,050,000         1,050,000  
                                 
 

Ian Lusted

                                           
 

Performance rights PRP

    750,000         (360,000 )       390,000         390,000  
                                 
 

Balance at

                                           
 

December 31, 2011

    750,000         (360,000 )       390,000         390,000  
                                 
 

Gren Schoch

                                           
 

Options

        750,000             750,000         750,000  
                                 
 

Balance at

                                           
 

December 31, 2011

        750,000             750,000         750,000  
                                 
 

Fiona Harris

                                           
 

Options

        500,000             500,000         500,000  
                                 
 

Balance at

                                           
 

December 31, 2011

        500,000             500,000         500,000  
                                 

A-54



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

28.   KEY MANAGEMENT PERSONNEL DISCLOSURE (Continued)

 
December 31, 2011
  Balance at start of the year   Granted as compensation   Exercised   Net other changes   Balance at the end of year   Vested and exercisable   Unvested  
 

Alan Watson

                                           
 

Options

        500,000             500,000         500,000  
                                 
 

Balance at

                                           
 

December 31, 2011

        500,000             500,000         500,000  
                                 
 

William Molson(1)

                                           
 

Options

        500,000             500,000         500,000  
                                 
 

Balance at

                                           
 

December 31, 2011

        500,000             500,000         500,000  
                                 

 


Other key management personnel of the Group


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
 

Michael Verm(2)

                                           
 

Options

        1,000,000             1,000,000         1,000,000  
                                 
 

Balance at December 31,

                                           
 

2011

        1,000,000             1,000,000         1,000,000  
                                 

 
Year ended
December 31, 2012
  Balance at start of the year   Exercise of options / performance rights   On-market trade   Net other changes   Balance at the end of year  
 

Directors of Aurora Oil and Gas Limited

                   
 

Jonathan Stewart(1)

    18,446,321     900,000         400,000     19,746,321  
 

Graham Dowland

    2,203,828                 2,203,828  
 

Ian Lusted

    1,031,950     390,000             1,421,950  
 

Gren Schoch(1)

    5,396,554         100,000     500,000     5,996,554  
 

Fiona Harris(1)

    100,000         10,000     40,000     150,000  
 

Alan Watson(1)

    952,381             97,619     1,050,000  
 

William Molson(1)

    1,412,390             100,000     1,512,390  

 


Other key management personnel of the Group


 

 

 

 

 

 

 

 

 

 
 

Michael Verm

    14,700                 14,700  
 

Douglas E Brooks(2)

            14,000         14,000  

A-55



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

28.   KEY MANAGEMENT PERSONNEL DISCLOSURE (Continued)

 
Year ended
December 31, 2011
  Balance at start of the year   Exercise of options / performance rights   On-market trade   Net other changes   Balance at the end of year  
 

Directors of Aurora Oil and Gas Limited

                   
 

Jonathan Stewart

    17,696,321     750,000             18,446,321  
 

Graham Dowland

    2,203,828                 2,203,828  
 

Ian Lusted

    971,950     360,000     (300,000 )       1,031,950  
 

Gren Schoch(1)

    4,196,554         200,000     1,000,000     5,396,554  
 

Fiona Harris(2)

                100,000     100,000  
 

Alan Watson

    952,381                 952,381  
 

William Molson(3)

            100,000     1,312,390     1,412,390  

 


Other key management personnel of the Group


 

 

 

 

 

 

 

 

 

 
 

Michael Verm(4)

            14,700         14,700  

 
Name
  Position
 

Mr. Douglas Brooks

  Chief Executive Officer (appointed October 18, 2012)
 

Mr. Michael Verm

  Chief Operating Officer
 

Mr. Darren Wasylucha

  Executive Vice President, Corporate Affairs
 

Ms. Julie Foster

  Company Secretary and Financial Controller
 

Mr. Barclay Ridge

  Vice President, Land

A-56



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

29.   CONSOLIDATED ENTITIES

   
   
   
  December 31,
2012
  December 31,
2011
 
   
  Jurisdiction of
Incorporation /
Formation
  Class of Equity
Interest
 
   
  Equity Holding  
 
Name of Entity
 
   
   
   
   
  %
 
   
   
   
  %
   
 
 

Aurora USA Oil and Gas, Inc.
(
formerly Corpus Christi Gas, Inc.)

  Delaware   Common     100     100  
 

Wardanup Oil and Gas, Inc.

  Delaware   Common     100     100  
 

Sugarloaf Oil and Gas, Inc.

  Delaware   Common     100     100  
 

West Black Lake Oil and Gas, Inc.(1)

  Delaware   Common         100  
 

Aurora West Coast Oil and Gas, Inc.(1)

  California   Common         100  
 

Meelup Oil and Gas, Inc.(2)

  Delaware   Common         100  
 

Mullaloo Oil and Gas, Inc.(3)

  Delaware   Common         100  
 

Yallingup Oil and Gas, Inc.

  Delaware   Common     100     100  
 

Trigg Oil and Gas, Inc.

  Delaware   Common     100     100  
 

Aurora USA Development, LLC.

  Texas   Membership interest     100      
 

AWT Exploration Oil and Gas, Inc.

  Delaware   Common     100      
 

Eureka Energy Limited

  Australia   Ordinary     100      
 

Kiana Projects Pty Ltd

  Australia   Ordinary     100      
 

Hosston Holdings Pty Ltd

  Australia   Ordinary     100      
 

Hosston Oil and Gas, Inc.

  Delaware   Common     100      
 

EKA 002, Inc.

  Delaware   Common     100      
 

EKA 003, Inc.

  Delaware   Common     100      
 

EKA 003, LLC.

  Delaware   Membership interest     100    
 

A-57



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

29.   CONSOLIDATED ENTITIES (Continued)

   
  Company  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Sale of goods and services

             
 

Management fees and expense recharges to subsidiaries

    6,811     2,034  
 

Loans to subsidiaries

             
 

Balance at beginning of the year

    1,688     193,850  
 

Loans advanced

    26,828     69,540  
 

Loans repaid

    (2,600 )   (261,702 )
             
 

Balance at end of year

    25,916     1,688  
             

30.   JOINTLY CONTROLLED ASSETS

   
   
  Working Interest*  
 
Project
  Activity   December 31,
2012
  December 31,
2011
 
 

Sugarloaf

  Sugarkane field development (USA)     28.1%     15.7%  
 

Ipanema

  Sugarkane field development (USA)     36.4%     36.4%  
 

Longhorn

  Sugarkane field development (USA)     31.9%     31.9%  
 

Excelsior

  Sugarkane field development (USA)     9.14%     9.14%  

A-58



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

30.   JOINTLY CONTROLLED ASSETS (Continued)

   
   
  Working Interest*  
 
Project
  Activity   December 31,
2012
  December 31,
2011
 
 

Flour Bluff

  Gas field development and production project (USA)     20%     20%  
 

North Belridge

  Oil wells (USA)     32.5%     32.5%  
 

Pan De Azucar

  Oil exploration and development (USA)     100%      
 

Black Jack Springs

  Oil exploration and development (USA)     9.4%      
 

Brioche

  Oil exploration and development (USA)     100%    
 

31.   PARENT ENTITY FINANCIAL INFORMATION

   
  Company  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Current assets

    3,018     7,874  
             
 

Total assets

    353,981     236,499  
 

Current liabilities

   
2,877
   
1,981
 
             
 

Total liabilities

    2,877     1,981  
 

Contributed equity

   
405,169
   
290,195
 
 

Share-based payment reserve

    13,004     7,767  
 

Fair value reserve

    (7,054 )   (8,011 )
 

Accumulated losses

    (60,015 )   (55,433 )
             
 

Total equity

    351,104     234,518  
             
 

(Loss) for the year

    (4,583 )   (9,991 )
             
 

Total comprehensive (loss) for the year

    (3,626 )   (11,293 )
             

A-59



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

31.   PARENT ENTITY FINANCIAL INFORMATION (Continued)

   
  Company  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Rent

             
 

Payable:

             
 

Within one year

    615     178  
 

Later than one year but not later than five years

    1,890     185  
 

Later than five years

         
             
 

    2,505     363  
             

32.   RECONCILIATION OF PROFIT AFTER INCOME TAX TO NET CASH INFLOW FROM OPERATING ACTIVITIES

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Net Profit for the year

    58,846     30,584  
 

  (i)  Add / (less) non-cash items

             
 

        Depreciation, depletion and amortisation

    39,161     4,367  
 

        Amortisation of borrowing costs

    2,927     66  
 

        Transaction costs expensed

    4,939     652  
 

        Share based payment expense

    4,398     4,052  
 

        Net gain on sale of available for sale assets

    (770 )    
 

        Net foreign exchange (gains)

    (3,146 )   (989 )
 

 (ii)  Add / (less) items classified as investment / financing activities:

             
 

        Net interest

    (247 )   (641 )
 

        Borrowing costs

    563        
 

(iii)  Change in assets and liabilities during the financial year

             
 

        Increase in receivables

    (73,273 )   (12,912 )
 

        Increase in payables

    73,126     8,217  
 

        Increase in deferred tax liability

    37,356     1,643  
 

        Increase in employee provisions

    242     (92 )
             
 

Net cash provided by operating activities

    144,122     34,947  
             

33.   RELATED PARTY TRANSACTIONS

A-60



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

33.   RELATED PARTY TRANSACTIONS (Continued)

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Payment for services

        125  
             

34.   REMUNERATION OF AUDITORS

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

(a)  BDO Audit (WA) Pty Ltd for:

             
 

       (i)  Audit and assurance services

             
 

             Audit and review of financial statements

    345     101  
 

             Due diligence services

    87     75  
             
 

Total remuneration of BDO Audit (WA) Pty Ltd

    432     176  
             
 

(b)  BDO Corporate Finance (WA) Pty Ltd for:

             
 

       (i)  Tax services

             
 

             Notice of meeting disclosure consulting

    2      
             
 

Total remuneration of BDO Corporate Finance (WA) Pty Ltd

    2      
             
 

(c)  BDO Canada LLP for:

             
 

       (i)  Other services

             
 

             Financial Statement language translation services

    58     31  
             
 

Total remuneration of BDO Canada LLP

    58     31  
             
 

Total auditors' remuneration

    492     207  
             

35.   CONTINGENCIES

A-61



AURORA OIL & GAS LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the year ended December 31, 2012

36.   COMMITMENTS

   
  Consolidated  
   
  December 31,
2012
  December 31,
2011
 
   
  US$'000
  US$'000
 
 

Oil and gas properties

             
 

Payable:

             
 

Within one year

    38,912     15,007  
 

Later than one year but not later than five years

         
 

Later than five years

         
             
 

    38,912     15,007  
             
 

Property, plant and equipment

             
 

Payable:

             
 

Within one year

    2,484     205  
 

Later than one year but not later than five years

         
 

Later than five years

         
             
 

    2,484     205  
             
 

Rent

             
 

Payable:

             
 

Within one year

    845     316  
 

Later than one year but not later than five years

    2,077     358  
 

Later than five years

         
             
 

    2,922     674  
             
 

Total commitments

    44,318     15,886  
             

37.   EVENTS OCCURRING AFTER BALANCE SHEET DATE

A-62



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

UNAUDITED INTERIM FINANCIAL REPORT
For the three and nine months ended September 30, 2013

A-63



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME

For the three and nine months ended September 30, 2013 and 2012

 
   
  Consolidated  
 
   
  Three months ended   Nine months ended  
 
  Note   September 30,
2013
  September 30,
2012
  September 30,
2013
  September 30,
2012
 
 
   
  US$'000
  US$'000
  US$'000
  US$'000
 

Revenue from continuing operations

  4     143,626     85,483     405,388     182,540  

Other income

  4     146     27     99     4,994  
                       

Total income

        143,772     85,510     405,487     187,534  

Expenses

                             

Royalties

  4     (38,717 )   (22,528 )   (108,575 )   (48,323 )

Production and operating expenses

  4     (15,970 )   (10,342 )   (42,846 )   (22,199 )

Administrative expenses

        (8,041 )   (2,666 )   (17,036 )   (8,862 )

Depletion, depreciation and amortisation expense

  4     (24,978 )   (14,117 )   (65,344 )   (24,125 )

Share-based payment expense

  4     (1,462 )   (991 )   (4,325 )   (3,296 )

Finance costs

  4     (16,269 )   (9,056 )   (43,115 )   (17,811 )

Exploration and evaluation costs

  4         (887 )   (282 )   (3,930 )

Foreign exchange loss

  4             (282 )    
                       

Profit from continuing operations before income tax expense

        38,335     24,923     123,682     58,988  

Income tax (expense)

  5     (13,661 )   (8,910 )   (43,703 )   (23,940 )
                       

Net profit attributable to owners of the Company

        24,674     16,013     79,979     35,048  
                       

Other comprehensive income

                             

Items that may be reclassified to profit or loss:

                             

Changes in fair value on equity instruments measured at fair value through other comprehensive income

        (58 )   (1,601 )   (208 )   957  

Change in fair value of cash flow hedges

        (4,249 )   (1,982 )   (3,510 )   (909 )
                       

Other comprehensive income for the period net of tax

        (4,307 )   (3,583 )   (3,718 )   48  
                       

Total comprehensive income for the period attributable to owners of the Company

        20,367     12,430     76,261     35,096  
                       

Earnings per share attributable to owners of the Company

                             

Basic earnings per share (US cents per share)

        5.50     3.58     17.85     8.20  

Diluted earnings per share (US cents per share)

        5.39     3.52     17.53     8.05  

   

The above consolidated statement of profit or loss and other comprehensive income should be read in conjunction with the accompanying notes.

A-64



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As at September 30, 2013

 
   
  Consolidated  
 
  Note   September 30,
2013
  December 31,
2012
 
 
   
  US$'000
  US$'000
 

Current assets

                   

Cash and cash equivalents

          105,517     67,584  

Trade and other receivables

    6     58,375     89,535  
                 

Total current assets

          163,892     157,119  
                 

Non-current assets

                   

Other financial assets

    7     504     842  

Property, plant and equipment

    8     119,851     71,063  

Oil and gas properties

    9     1,234,198     882,373  
                 

Total non-current assets

          1,354,553     954,278  
                 

Total assets

          1,518,445     1,111,397  
                 

Current liabilities

                   

Trade and other payables

    11     188,024     180,619  

Derivative financial instruments

    10     6,235     1,535  

Provisions

    12     542     334  
                 

Total current liabilities

          194,801     182,488  
                 

Non-current liabilities

                   

Borrowings

    13     660,653     390,453  

Deferred tax liabilities

    14     126,240     83,523  

Derivative financial instruments

    10     428     114  

Provisions

    15     3,031     1,705  
                 

Total non-current liabilities

          790,352     475,795  
                 

Total liabilities

          985,153     658,283  
                 

Net assets

          533,292     453,114  
                 

Equity

                   

Contributed equity

    16     405,148     405,169  

Share-based payment reserve

          16,103     12,165  

Fair value reserve

          (7,262 )   (7,054 )

Foreign exchange reserve

          (7,505 )   (7,505 )

Cash flow hedges reserve

          (4,664 )   (1,154 )

Retained earnings

          131,472     51,493  
                 

Total equity

          533,292     453,114  
                 

   

The above consolidated statement of financial position should be read in conjunction with the accompanying notes.

A-65



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the three and nine months ended September 30, 2013 and 2012

 
  For the nine months ended
September 30, 2013
 
 
  Contributed
Equity
  Other
Reserve
  Accumulated
Profits / (Losses)
  Total  
 
  US$'000
  US$'000
  US$'000
  US$'000
 

Balance at January 1, 2012

    290,194     (7,749 )   (7,353 )   275,092  

Profit for the period

            35,048     35,048  

Other comprehensive income

                         

Change in fair value of equity instruments measured at fair value through other comprehensive income

        916         916  

Change in fair value of cash flow hedges

        (909 )       (909 )

Recognition of fair value of equity instruments measured at fair value through other comprehensive income on disposal

        41         41  
                   

Total comprehensive income for the period

        48     35,048     35,096  
                   

Transactions with owners, in their capacity as owners

                         

Contributed equity net of transaction costs

    115,116             115,116  

Options and performance rights expense recognised during the period

        3,297         3,297  
                   

Balance as at September 30, 2012

    405,310     (4,404 )   27,695     428,601  
                   

Balance as at January 1, 2013

    405,169     (3,548 )   51,493     453,114  

Profit for the period

            79,979     79,979  

Other comprehensive income

                         

Change in fair value of equity instruments measured at fair value through other comprehensive income

        (208 )       (208 )

Change in fair value of cash flow hedges

        (3,510 )       (3,510 )
                   

Total comprehensive income for the period

        (3,718 )   79,979     76,261  
                   

Transactions with owners, in their capacity as owners

                         

Contributed equity net of transaction costs

    (21 )           (21 )

Options and performance rights expense recognised during the period

        3,938         3,938  
                   

Balance as at September 30, 2013

    405,148     (3,328 )   131,472     533,292  
                   

   

The above consolidated statement of changes in equity should be read in conjunction with the accompanying notes.

A-66



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the three and nine months ended September 30, 2013 and 2012

 
  For the three months ended September 30, 2013  
 
  Contributed
Equity
  Other
Reserve
  Accumulated
Profits / (Losses)
  Non-
Controlling
Interests
  Total  
 
  US$'000
  US$'000
  US$'000
  US$'000
  US$'000
 

Balance at July 1, 2012

    405,325     (1,812 )   11,682     27,349     442,544  

Profit for the period

            16,013         16,013  

Other comprehensive income

                               

Change in fair value of equity instruments measured at fair value through other comprehensive income

        (1,642 )           (1,642 )

Change in fair value of cash flow hedges

        (1,982 )           (1,982 )

Recognition of fair value of equity instruments measured at fair value through other comprehensive income on disposal

        41             41  
                       

Total comprehensive income for the period

        (3,583 )   16,013         12,430  
                       

Transactions with owners, in their capacity as owners

                               

Contributed equity net of transaction costs

    (15 )               (15 )

Options and performance rights expense recognised during the period

        991             991  

Non-controlling interest on acquisition of subsidiary

                (27,349 )   (27,349 )
                       

Balance as at September 30, 2012

    405,310     (4,404 )   27,695         428,601  
                       

Balance as at July 1, 2013

    405,156     (482 )   106,798         511,472  

Profit for the period

            24,674         24,674  

Other comprehensive income

                               

Change in fair value of equity instruments measured at fair value through other comprehensive income

        (58 )           (58 )

Change in fair value of cash flow hedges

        (4,249 )           (4,249 )
                       

Total comprehensive income for the period

        (4,307 )   24,674         20,367  
                       

Transactions with owners, in their capacity as owners

                               

Contributed equity net of transaction costs

    (8 )               (8 )

Options and performance rights expense recognised during the period

        1,461             1,461  
                       

Balance as at September 30, 2013

    405,148     (3,328 )   131,472         533,292  
                       

   

The above consolidated statement of changes in equity should be read in conjunction with the accompanying notes.

A-67



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

CONSOLIDATED STATEMENT OF CASH FLOWS

For the three and nine months ended September 30, 2013 and 2012

 
  Consolidated  
 
  Three months ended   Nine months ended  
 
  September 30,
2013
  September 30,
2012
  September 30,
2013
  September 30,
2012
 
 
  US$'000
  US$'000
  US$'000
  US$'000
 

Cash flows from operating activities

                         

Receipts from oil and gas sales

    152,718     45,786     436,504     95,878  

Payments to suppliers and employees

    (64,254 )   (14,558 )   (173,180 )   (36,657 )

Other revenue

    22         99     1,167  

Interest paid

    (29,641 )   (10,978 )   (48,148 )   (11,098 )
                   

Net cash inflow from operating activities

    58,845     20,250     215,275     49,290  
                   

Cash flows from investing activities

                         

Payments for capitalised oil and gas assets

    (107,097 )   (117,539 )   (395,208 )   (286,758 )

Payment for property, plant and equipment

    (10,860 )   (4,263 )   (41,468 )   (22,282 )

Payment for other financial assets

                (252 )

Payment for acquisition of subsidiary, net of cash acquired

        (27,349 )       (98,765 )

Interest received

    11     31     44     224  
                   

Net cash (outflow) from investing activities

    (117,946 )   (149,120 )   (436,632 )   (407,833 )
                   

Cash flows from financing activities

                         

Proceeds from issues of shares

                120,138  

Share issue costs

    (8 )   (15 )   (21 )   (5,022 )

Proceeds from borrowings

        167,475     330,000     364,579  

Repayment of borrowings

        (9,000 )   (60,000 )   (39,000 )

Borrowing costs

    (737 )   (5,453 )   (10,632 )   (11,102 )
                   

Net cash inflow / (outflow) from financing activities

    (745 )   153,007     259,347     429,593  
                   

Net increase / (decrease) in cash and cash equivalents

    (59,846 )   24,137     37,990     71,050  

Cash and cash equivalents at the beginning of the financial period

    165,222     118,930     67,584     70,246  

Effect of exchange rates on cash holdings in foreign currencies

    141     152     (57 )   1,923  
                   

Cash and cash equivalents at the end of the financial period

    105,517     143,219     105,517     143,219  
                   

   

The above consolidated statement of cash flows should be read in conjunction with the accompanying notes.

A-68



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

NOTES TO THE FINANCIAL STATEMENTS

For the three and nine months ended September 30, 2013

1.     BASIS OF PREPARATION

2.     SEGMENT INFORMATION

   
  Three months ended   Nine months ended  
   
  September 30,
2013
  September 30,
2012
  September 30,
2013
  September 30,
2012
 
   
  US$'000
  US$'000
  US$'000
  US$'000
 
 

Revenue from oil and gas exploration and production

    143,615     85,452     405,344     182,316  
 

Revenue from other corporate activities

    157     58     143     5,218  
                     
 

    143,772     85,510     405,487     187,534  
                     

   
  September 30,
2013
  December 31,
2012
 
   
  US$'000
  US$'000
 
 

Assets from oil and gas exploration and production

    1,409,962     1,041,143  
 

Assets from corporate activities:

             
 

Cash and cash equivalents

    105,517     67,584  
 

Other corporate assets

    2,966     2,670  
             
 

    1,518,445     1,111,397  
             

A-69



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

NOTES TO THE FINANCIAL STATEMENTS (Continued)

For the three and nine months ended September 30, 2013

2.     SEGMENT INFORMATION (Continued)

   
  September 30,
2013
  December 31,
2012
 
   
  US$'000
  US$'000
 
 

Liabilities from oil and gas exploration and production

    982,829     655,090  
 

Liabilities from other corporate activities

    2,324     3,193  
             
 

    985,153     658,283  
             

   
  Three months ended   Nine months ended  
   
  September 30,
2013
  September 30,
2012
  September 30,
2013
  September 30,
2012
 
   
  US$'000
  US$'000
  US$'000
  US$'000
 
 

Profit from oil and gas exploration and production

    32,781     19,674     99,822     41,840  
 

Profit/(Loss) from other corporate activities

    (8,107 )   (3,661 )   (19,843 )   (6,792 )
                     
 

    24,674     16,013     79,979     35,048  
                     

3.     DIVIDENDS

4.     PROFIT FOR THE PERIOD

   
   
  Three months ended   Nine months ended  
   
  Note   September 30,
2013
  September 30,
2012
  September 30,
2013
  September 30,
2012
 
   
   
  US$'000
  US$'000
  US$'000
  US$'000
 
 

Income

                             
 

Revenue from continuing operations

                             
 

Oil and gas sales

        145,481     85,550     408,381     182,581  
 

Realised (loss) on forward commodity price contract

        (1,866 )   (98 )   (3,037 )   (265 )
 

Interest

        11     31     44     224  
                         
 

        143,626     85,483     405,388     182,540  
                         
 

Other income

                             
 

Foreign exchange gain

  (i)     124     27         3,056  
 

Net gain on sale of available-for-sale financial assets

                    770  
 

Net gain on foreign currency derivatives not qualifying as hedges

                    1,167  
 

Other

        22         99     1  
                         
 

        146     27     99     4,994  
                         

A-70



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

NOTES TO THE FINANCIAL STATEMENTS (Continued)

For the three and nine months ended September 30, 2013

4.     PROFIT FOR THE PERIOD (Continued)

   
   
  Three months ended   Nine months ended  
   
  Note   September 30,
2013
  September 30,
2012
  September 30,
2013
  September 30,
2012
 
   
   
  US$'000
  US$'000
  US$'000
  US$'000
 
 

Expenses

                             
 

Royalties expense

  (ii)     (38,717 )   (22,528 )   (108,575 )   (48,323 )
 

Production and operating expenses

                             
 

Production taxes

  (iii)     (4,773 )   (2,925 )   (13,516 )   (6,214 )
 

Operating expenses

  (iv)     (11,197 )   (7,417 )   (29,330 )   (15,985 )
                         
 

Total production and operating expenses

        (15,970 )   (10,342 )   (42,846 )   (22,199 )
                         
 

Depletion and depreciation

                             
 

Depletion

  (v)     (22,758 )   (13,558 )   (59,446 )   (22,871 )
 

Depreciation

  (vi)     (2,220 )   (559 )   (5,898 )   (1,254 )
                         
 

Total depletion and depreciation expense

        (24,978 )   (14,117 )   (65,344 )   (24,125 )
                         
 

Share-based payment expense

                             
 

Options

        (567 )   (841 )   (1,909 )   (3,077 )
 

Performance Rights

        (895 )   (150 )   (2,416 )   (219 )
                         
 

Total share-based payment expense

  (vii)     (1,462 )   (991 )   (4,325 )   (3,296 )
                         
 

Finance costs

                             
 

Interest expense

        (14,804 )   (7,637 )   (39,092 )   (15,420 )
 

Amortisation of borrowing costs

        (1,159 )   (1,085 )   (3,253 )   (1,831 )
 

Amortisation of debt premium / discount

        (8 )   (55 )   (24 )   (281 )
 

Other financing fees

        (298 )   (279 )   (746 )   (279 )
                         
 

Total finance costs

  (viii)     (16,269 )   (9,056 )   (43,115 )   (17,811 )
                         
 

Exploration and evaluation costs written off

  (ix)         (887 )   (282 )   (3,930 )
                         
 

Foreign exchange loss

  (i)             (282 )    
                         

A-71



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

NOTES TO THE FINANCIAL STATEMENTS (Continued)

For the three and nine months ended September 30, 2013

4.     PROFIT FOR THE PERIOD (Continued)

5.     INCOME TAX

   
  Three months ended   Nine months ended  
   
  September 30,
2013
  September 30,
2012
  September 30,
2013
  September 30,
2012
 
   
  US$'000
  US$'000
  US$'000
  US$'000
 
 

(a) Income tax expense

 
 

Current tax

                 
 

Deferred tax

    13,661     8,910     43,703     23,940  
                     
 

Income tax expense

    13,661     8,910     43,703     23,940  
                     
 

(b) Reconciliation of income tax expense to prima facie tax payable

 
 

Profit from continuing operations before income tax expense

    38,335     24,923     123,682     58,988  
                     
 

Tax at the Australian statutory tax rate of 30% (September 30, 2012: 30%)

    11,501     7,476     37,105     17,696  
 

Tax effect of amounts that are not deductible (taxable) in calculating taxable income

                         
 

Share-based payment expense

    194     217     603     757  
 

Foreign exchange gains/(losses) not assessable

    16     (6 )   75     (913 )
 

Revenue losses not previously recognised now brought to account

    (330 )   (4 )   (157 )   (294 )
 

(Expense)/benefit from a previously unrecognised temporary difference now recognised

    (248 )   484     (611 )   1,150  
 

Income tax rate differences

    2,043     286     6,337     3,502  
 

Other non-allowable deductions

    485     457     351     2,042  
                     
 

Income tax expense

    13,661     8,910     43,703     23,940  
                     
 

(c) Tax expense (income) relating to items of other comprehensive income

 
 

Financial assets at fair value through other comprehensive income

    (681 )   (829 )   (519 )   1,509  
 

Cash flow hedges

    1,814     849     1,504     389  
                     
 

    1,133     20     985     1,898  
                     

6.     TRADE AND OTHER RECEIVABLES

   
   
  Consolidated  
   
   
  September 30,
2013
  December 31,
2012
 
   
   
  US$'000
  US$'000
 
 

Trade receivables

  (i)     58,375     89,535  
                 

A-72



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

NOTES TO THE FINANCIAL STATEMENTS (Continued)

For the three and nine months ended September 30, 2013

6.     TRADE AND OTHER RECEIVABLES (Continued)

7.     OTHER FINANCIAL ASSETS

   
  Consolidated  
   
  September 30,
2013
  December 31,
2012
 
   
  US$'000
  US$'000
 
 

Non-current

             
 

Financial assets at fair value through other comprehensive income

    504     842  
             

8.     PROPERTY, PLANT AND EQUIPMENT

   
  Consolidated  
   
  September 30,
2013
  December 31,
2012
 
   
  US$'000
  US$'000
 
 

Production facilities and field equipment

             
 

Production facilities and field equipment at cost

    126,944     73,685  
 

Production facilities and field equipment accumulated depreciation

    (9,472 )   (3,876 )
             
 

Net production facilities and field equipment

    117,472     69,809  
             
 

Office equipment

             
 

At cost

    2,926     1,510  
 

Accumulated depreciation

    (547 )   (256 )
             
 

Net office equipment

    2,379     1,254  
             
 

Total property, plant and equipment

    119,851     71,063  
             

A-73



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

NOTES TO THE FINANCIAL STATEMENTS (Continued)

For the three and nine months ended September 30, 2013

9.     OIL AND GAS PROPERTIES

   
  Consolidated  
   
  September 30,
2013
  December 31,
2012
 
   
  US$'000
  US$'000
 
 

Producing projects

             
 

At cost

    1,258,801     917,501  
 

Accumulated depletion

    (102,728 )   (41,207 )
             
 

Net carrying value

    1,156,073     876,294  
             
 

Development projects

             
 

At cost

    78,125     6,079  
             
 

Net carrying value

    78,125     6,079  
             
 

Total

    1,234,198     882,373  
             

   
  Consolidated  
   
  September 30,
2013
  December 31,
2012
 
   
  US$'000
  US$'000
 
 

Producing projects

             
 

Cost

             
 

Opening balance

    917,501     275,671  
 

Additions

    331,903     653,250  
 

Increase in restoration provision

    1,326     1,140  
 

Net movement in prepaid costs

    8,071     (12,560 )
             
 

Closing balance

    1,258,801     917,501  
             
 

Accumulated depletion and amortisation

             
 

Opening balance

    (41,207 )   (3,543 )
 

Depletion charge

    (61,521 )   (37,664 )
             
 

Closing balance

    (102,728 )   (41,207 )
             
 

Net carrying value

             
 

Opening carrying value

    876,294     272,128  
             
 

Closing carrying value

    1,156,073     876,294  
             
 

Development projects

             
 

Cost

             
 

Opening balance

    6,079      
 

Additions

    72,046     6,079  
             
 

Closing balance

    78,125     6,079  
             
 

Net carrying value

             
 

Opening carrying value

    6,079      
             
 

Closing carrying value

    78,125     6,079  
             

A-74



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

NOTES TO THE FINANCIAL STATEMENTS (Continued)

For the three and nine months ended September 30, 2013

10.   DERIVATIVE FINANCIAL INSTRUMENTS

   
  Consolidated  
   
  September 30,
2013
  December 31,
2012
 
   
  US$'000
  US$'000
 
 

Forward commodity contracts — cash flow hedges

             
 

Current

    6,235     1,535  
 

Non — current

    428     114  
             
 

Total derivative financial instrument liabilities

    6,663     1,649  
             

   
   
   
   
   
  Weighted average US$ / barrel    
 
 
Year of
delivery
  Subject of
contract
  Reference   Option
traded
  Barrels   Strike price   Floor price   Ceiling price   Fair value
US$'000
 
 

2013

  Oil   Nymex WTI   Swap     363,100     98.69             1,045  
 

2013

  Oil   LLS   Swap     27,000     95.40             255  
 

2013

  Oil   Nymex WTI   Zero Cost Collar     112,500         79.00     103.35     236  
 

2014

  Oil   Nymex WTI   Swap     1,158,300     91.81             4,348  
 

2014

  Oil   Nymex WTI   Zero Cost Collar     270,000         80.00     98.67     892  
 

2015

  Oil   Nymex WTI   Swap     186,000     91.40             (113 )
                                           
 

Total

                2,116,900                       6,663  
                                           

11.   TRADE AND OTHER PAYABLES

   
  Consolidated  
   
  September 30,
2013
  December 31,
2012
 
   
  US$'000
  US$'000
 
 

Trade payables and accruals

    188,024     180,619  
             

A-75



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

NOTES TO THE FINANCIAL STATEMENTS (Continued)

For the three and nine months ended September 30, 2013

12.   PROVISIONS — CURRENT

   
  Consolidated  
   
  September 30,
2013
  December 31,
2012
 
   
  US$'000
  US$'000
 
 

Employee benefits

    542     334  
             

13.   BORROWINGS

   
   
  Consolidated  
   
   
  September 30,
2013
  December 31,
2012
 
   
   
  US$'000
  US$'000
 
 

Secured

                 
 

Senior secured syndicated facility

  (a)         30,000  
 

Unsecured

                 
 

Senior unsecured notes

  (b)     660,653     360,453  
                 
 

        660,653     390,453  
                 

 
Owner / Grantor
  Issuer   Percentage
Owned
  Percentage
Pledged
  Class of stock
 

Aurora Oil and Gas Limited

  Aurora USA Oil and Gas, Inc.     100%     100%   Common Stock
 

Aurora USA Oil and Gas, Inc.

  Wardanup Oil and Gas, Inc.     100%     100%   Common Stock
 

Aurora USA Oil and Gas, Inc.

  Sugarloaf Oil and Gas, Inc.     100%     100%   Common Stock
 

Aurora USA Oil and Gas, Inc.

  Yallingup Oil and Gas, Inc.     100%     100%   Common Stock
 

Aurora USA Oil and Gas, Inc.

  Trigg Oil and Gas, Inc.     100%     100%   Common Stock
 

Aurora USA Oil and Gas, Inc.

  Aurora USA Development, LLC.     100%     100%   Membership Interest
 

Aurora USA Oil and Gas, Inc.

  ATW Exploration Oil and Gas, Inc.     100%     100%   Common Stock
 

Aurora USA Oil and Gas, Inc.

  Aurora EF Production Company     100%     100%   Common Stock
 

Aurora USA Oil and Gas, Inc.

  EKA 002, Inc.     100%     100%   Common Stock
 

Aurora USA Oil and Gas, Inc.

  EKA 003, Inc.     100%     100%   Common Stock
 

EKA 003, Inc.

  EKA 003, LLC.     100%     100%   Membership Interest

A-76



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

NOTES TO THE FINANCIAL STATEMENTS (Continued)

For the three and nine months ended September 30, 2013

13.   BORROWINGS (Continued)

14.   DEFERRED TAX

   
  Consolidated  
   
  September 30,
2013
  December 31,
2012
 
   
  US$'000
  US$'000
 
 

(a) Deferred tax asset

             
 

Arising from temporary differences attributable to:

             
 

Tax losses(1)

             
 

Australia

    902     216  
 

United States

    177,355     142,967  
 

Share issue expense

    620     464  
 

Other

    9,344     8,492  
 

Financial assets through other comprehensive income

    990     1,509  
 

Cash flow hedge

    1,999     495  
             
 

Total deferred tax asset

    191,210     154,143  
 

Less set off against deferred tax liabilities under set-off provisions (b)

    (191,210 )   (154,143 )
             
 

(b) Deferred tax liability

             
 

Arising from temporary differences attributable to:

             
 

Oil and gas properties

    (312,411 )   (232,547 )
 

Management fees and borrowing costs

    (5,039 )   (5,119 )
             
 

Total deferred tax liabilities

    (317,450     (237,666 )
 

Less set off of deferred tax asset under set-off provisions (a)

    191,210     154,143  
             
 

Net deferred tax liabilities

    (126,240 )   (83,523 )
 

Deferred tax liabilities expected to be settled within 12 months

         
             
 

Deferred tax liabilities expected to be settled after more than 12 months

    (126,240 )   (83,523 )
             

A-77



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

NOTES TO THE FINANCIAL STATEMENTS (Continued)

For the three and nine months ended September 30, 2013

15.   PROVISIONS — NON-CURRENT

   
  Consolidated  
   
  September 30,
2013
  December 31,
2012
 
   
  US$'000
  US$'000
 
 

Restoration provision

    3,031     1,705  
             

16.   CONTRIBUTED CAPITAL

   
  Date   Number of Securities   Issue Price   US$'000  
 

Balance January 1, 2012

          411,655,343           290,194  
 

Placement

    16-May-12     15,802,816     A$3.55     54,721  
 

Placement

    16-May-12     18,000,000     C$3.55     61,359  
 

Placement

    28-Jun-12     1,137,619     A$3.55     4,058  
 

Performance rights exercise

    15-Aug-12     390,000          
 

Performance rights exercise

    20-Aug-12     900,000          
 

Share issue costs

                      (5,163 )
                         
 

Balance at December 31, 2012

          447,885,778           405,169  
                         
 

Performance rights exercised

    08-Aug-13     900,000          
 

Share issue costs

                      (21 )
                         
 

Balance at September 30, 2013

          448,785,778           405,148  
                         

17.   BUSINESS COMBINATION

   
  US$'000  
 

Purchase consideration (refer to (b) below):

       
 

Cash paid

    106,136  
 

Fair value of shares owned prior to the on-market cash offer

    3,405  
         
 

Total purchase consideration

    109,541  
         

A-78



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

NOTES TO THE FINANCIAL STATEMENTS (Continued)

For the three and nine months ended September 30, 2013

17.   BUSINESS COMBINATION (Continued)

   
  Fair value  
   
  US$'000
 
 

Cash and cash equivalents

    7,371  
 

Trade and other receivables

    1,636  
 

Property, plant and equipment

    360  
 

Oil and gas properties

    164,664  
 

Trade and other payables

    (8,830 )
 

Borrowings

    (9,000 )
 

Deferred tax liability

    (46,526 )
 

Provisions

    (134 )
         
 

Net identifiable assets acquired

    109,541  
         

   
  September 30,
2013
  December 31,
2012
 
   
  US$'000
  US$'000
 
 

Outflow of cash to acquire subsidiary, net of cash acquired

             
 

Cash consideration

        106,136  
 

Less: Balances acquired

             
 

Cash

        7,371  
             
 

Outflow of cash — investing activity

        98,765  
             

A-79



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

NOTES TO THE FINANCIAL STATEMENTS (Continued)

For the three and nine months ended September 30, 2013

18.   COMMITMENTS

   
  Consolidated  
   
  September 30,
2013
  December 31,
2012
 
   
  US$'000
  US$'000
 
 

Oil and gas properties

             
 

Payable:

             
 

Within one year

    64,322     38,912  
 

Later than one year but not later than five years

         
 

Later than five years

         
             
 

    64,322     38,912  
             
 

Property, plant and equipment

             
 

Payable:

             
 

Within one year

    16,429     2,484  
 

Later than one year but not later than five years

         
 

Later than five years

         
             
 

    16,429     2,484  
             
 

Rent

             
 

Payable:

             
 

Within one year

    1,559     845  
 

Later than one year but not later than five years

    5,292     2,077  
 

Later than five years

    1,513      
             
 

    8,364     2,922  
             
 

Total Commitments

    89,115     44,318  
             

19.   CONTINGENCIES

A-80



AURORA OIL & GAS LIMITED
ABN 90 008 787 988

NOTES TO THE FINANCIAL STATEMENTS (Continued)

For the three and nine months ended September 30, 2013

20.   RELATED PARTY TRANSACTIONS

 
Recipient
  Grant date   Vesting
date
  Number   Exercise
price
  Total fair
value
US$'000
  Expense
recognised at
Sept 30, 2013
US$'000
  Expiry  
 

Jonathan Stewart

    29-May-13     01-Jan-13     43,508   Nil     95     95     01-Jan-13  
 

    29-May-13     01-Jan-14     127,769   Nil     233     117     01-Jan-14  
 

    29-May-13     01-Jan-15     255,537   Nil     541     97     01-Jan-15  
 

    29-May-13     01-Jan-16     163,007   Nil     363     39     01-Jan-16  
                     
 

Graham Dowland

    29-May-13     01-Jan-13     10,733   Nil     23     23     01-Jan-13  
 

    29-May-13     01-Jan-14     33,528   Nil     60     31     01-Jan-14  
 

    29-May-13     01-Jan-15     67,057   Nil     142     25     01-Jan-15  
 

    29-May-13     01-Jan-16     48,253   Nil     107     12     01-Jan-16  
                     
 

Ian Lusted(1)

    29-May-13     01-Jan-13     9,785   Nil     21     21     01-Jan-13  
                     
 

Douglas Brooks(2)

    01-Jan-13     01-Jan-14     17,090   Nil     49     36     01-Jan-14  
 

    01-Jan-13     01-Jan-15     34,179   Nil     102     37     01-Jan-15  
 

    01-Jan-13     01-Jan-16     68,359   Nil     211     51     01-Jan-16  
                     
 

Total related party transactions

                878,805         1,947     584        
                     

21.   EVENTS OCCURRING AFTER BALANCE DATE

22.   ROUNDING OF AMOUNTS

A-81



SCHEDULE "B"


PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS OF BAYTEX

B-1



BAYTEX ENERGY CORP.

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
As at and for the nine months ended September 30, 2013
and for the year ended December 31, 2012

B-2


FOREWORD

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

        The following unaudited pro forma consolidated financial statements give effect to the proposed acquisition (the "Proposed Acquisition") by Baytex Energy Corp. of Aurora Oil & Gas Limited and its subsidiaries (collectively, "Aurora") under the acquisition method of accounting. The unaudited pro forma consolidated statement of financial position gives effect to the Proposed Acquisition as if it had closed on September 30, 2013. The unaudited pro forma consolidated statements of income and comprehensive income for the nine-months ended September 30, 2013 and for the year ended December 31, 2012 give effect to the Proposed Acquisition as if it had closed on January 1, 2012.

        The unaudited pro forma consolidated financial statements are presented for illustrative purposes only. The pro forma adjustments are based upon available information and certain assumptions that we believe are reasonable in the circumstances, as described in the notes to the unaudited pro forma consolidated financial statements.

        The unaudited pro forma consolidated financial statements are based on Baytex's and Aurora's consolidated financial statements as at and for the nine-months ended September 30, 2013 and for the year ended December 31, 2012. Aurora's consolidated financial statements have been translated from United States dollars to Canadian dollars. The unaudited pro forma consolidated financial statements, including the notes thereto, are qualified in their entirety by reference to, and should be read in conjunction with, Baytex's historical consolidated financial statements and the related notes thereto, which are incorporated by reference in this prospectus and the historical consolidated financial statements of Aurora, including the notes thereto, which are included elsewhere in this prospectus.

        The pro forma information presented, including allocation of purchase price, is based on preliminary estimates of fair values of assets acquired and liabilities assumed, available information and assumptions and may be revised as additional information becomes available. The actual adjustments to the consolidated financial statements upon the closing of the Proposed Acquisition will depend on a number of factors, including additional information available and the net assets of Aurora on the closing date of the Proposed Acquisition. Therefore, the actual adjustments will differ from the pro forma adjustments, and the differences may be material. For example, the final purchase price allocation is dependent on, among other things, the finalization of asset and liability valuations as well as reserve evaluations. A final determination of these fair values will reflect an independent third-party valuation. This final valuation will be based on the actual net tangible and intangible assets and liabilities of Aurora that exist as of the closing date of the Proposed Acquisition. Any final adjustment may change the allocation of purchase price, which could affect the fair value assigned to the assets and liabilities and could result in a change to the unaudited pro forma consolidated financial statements.

        Pro forma adjustments are necessary to reflect the purchase price and purchase accounting adjustments based on preliminary estimates of the fair values of the Aurora net assets acquired. The unaudited pro forma consolidated financial statements do not reflect any operating efficiencies and cost savings that may be realized with respect to the combined companies.

B-3



BAYTEX ENERGY CORP.

PRO FORMA CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As at September 30, 2013
(Unaudited)
(In thousands of Canadian dollars)

 
  Baytex
Energy Corp.
  Aurora Oil &
Gas Limited
  Note   Pro Forma
adjustments
  Pro Forma
consolidated
 
 
   
  (3b)
   
   
   
 

ASSETS

                             

Current assets

                             

Cash and cash equivalents

  $ 315   $ 108,524           $ 108,839  

Trade and other receivables

    194,195     60,557             254,752  

Crude Oil inventory

    406                 406  

Financial derivatives

    10,577                 10,577  
                       

    205,493     169,081             374,574  

Non-current assets

                             

Financial Derivatives

    1,270                 1,270  

Exploration and evaluation assets

    177,395       (3c)     1,283,392     1,283,392  

Oil and gas properties

    2,288,408     1,269,373   (3c)         3,557,781  

Other plant and equipment

    30,848     123,267             154,115  

Goodwill

    37,755       (3c)     444,280     444,280  
                       

  $ 2,741,169   $ 1,561,721       $ 1,727,672   $ 6,030,562  
                       

LIABILITIES AND SHAREHOLDERS' EQUITY

                             

Current liabilities

                             

Trade and other payables

  $ 225,230   $ 193,940           $ 419,170  

Dividends payable to shareholders

    27,389                 27,389  

Financial derivatives

    20,021     6,413             26,434  
                       

    272,640     200,353             472,993  

Non-current liabilities

                             

Bank Loan

    244,651                 244,651  

Long-term debt

    446,659     679,482   (3c), (3e)     617,883     1,744,024  

Asset retirement obligations

    245,489     3,117             248,606  

Deferred income tax liability

    234,557     129,838   (3g)     425,280     789,675  

Financial derivatives

    1,108     440             1,548  
                       

    1,445,104     1,013,230         1,043,163     3,501,497  
                       

Shareholders' equity

                             

Shareholders' capital

    1,969,018     416,695   (3h)     (416,695 )   3,230,018  

              (3a)     1,261,000        

Contributed Surplus

    58,616                 58,616  

Reserves

        (3,423 ) (3h)     3,423      

Accumulated other comprehensive loss

    (6,722 )               (6,722 )

Deficit

    (724,847 )   135,219   (3f), (3h)     (163,219 )   (752,847 )
                       

    1,296,065     548,491         684,509     2,529,065  

  $ 2,741,169   $ 1,561,721       $ 1,727,672     6,030,562  
                       

   

See the accompanying notes to the unaudited pro forma consolidated financial statements, which are an integral part of these statements.

B-4



BAYTEX ENERGY CORP.

PRO FORMA CONSOLIDATED STATEMENT OF INCOME AND COMPREHENSIVE INCOME

For the nine months ended September 30, 2013
(Unaudited)
(In thousands of Canadian dollars, except for per share amounts)

 
  Baytex
Energy Corp.
  Aurora Oil &
Gas Limited
  Note   Pro forma
adjustments
  Pro forma
consolidated
 
 
   
  (3b)
   
   
   
 

Revenues, net of royalties

  $ 846,063   $ 289,983       $   $ 1,136,046  

Expenses

                             

Production and operating

    206,780     18,768             225,548  

Transportation and blending

    120,754     11,254             132,008  

Exploration and evaluation

    7,737     289             8,026  

Depletion and depreciation

    239,507     66,886   (3l)     88,861     395,254  

General and administrative

    33,060     17,337             50,397  

Share-based compensation

    27,524     4,427             31,951  

Financing costs

    37,858     44,133   (3e)          

Loss on financial derivatives

    18,515                 18,515  

Foreign exchange loss

    1,077     289             1,366  

Gain on divestiture of oil and gas properties

    (20,989 )               (20,989 )
                       

    671,823     163,382              
                       

Net income before income taxes

    174,240     126,601              
                       

Income tax expense

                             

Current income tax recovery

    (6,821 )               (6,821 )

Deferred income tax expense

    47,389     44,734   (3g)          
                       

    40,568     44,734             (6,821 )
                       

Net income attributable to shareholders

    133,672     81,867              
                       

Other comprehensive income

                             

Changes in fair value of equity instruments and cash flow hedges

        3,806             3,806  

Foreign currency translation adjustment

    (5,740 )               (5,740 )
                       

Comprehensive Income

  $ 139,412   $ 78,061              
                       

Weighted average common shares outstanding
(#, thousands)

                             

Basic

    123,318         (3i)          

Diluted

    124,860         (3i)          

Earnings per common share

                             

Basic

  $ 1.08         (3i)            

Diluted

  $ 1.07         (3i)            

   

See the accompanying notes to the unaudited pro forma consolidated financial statements, which are an integral part of these statements.

B-5



BAYTEX ENERGY CORP.

PRO FORMA CONSOLIDATED STATEMENT OF INCOME AND COMPREHENSIVE INCOME

For the year ended December 31, 2012
(Unaudited)
(In thousands of Canadian dollars, except for per share amounts)

 
  Baytex
Energy Corp.
  Aurora Oil &
Gas Limited
  Note   Pro forma
adjustments
  Pro forma
consolidated
 
 
   
  (3b)
   
   
   
 

Revenues, net of royalties

  $ 1,024,949   $ 207,548       $   $ 1,232,497  

Expenses

                             

Production and operating

    232,375     20,237             252,612  

Transportation and blending

    207,240     4,293             211,533  

Exploration and evaluation

    12,202     4,943             17,145  

Depletion and depreciation

    297,797     39,196   (31)     69,493     406,486  

General and administrative

    44,646     15,148             59,794  

Share-based compensation

    36,684     4,402             41,086  

Financing costs

    47,191     28,052   (3e)          

Gain on financial derivatives

    (61,554 )               (61,554 )

Foreign exchange gain

    (4,739 )               (4,739 )

Gain on divestiture of oil and gas properties

    (172,545 )               (172,545 )

Other income

        (5,013 )           (5,013 )

Charge on redemption of long-term debt note

    9,261                 9,261  
                       

    648,558     111,259              
                       

Net income before income taxes

    376,391     96,289              
                       

Income tax expense

                             

Current income tax (recovery) expense

    10,162                 10,162  

Deferred income tax expense

    107,598     37,390   (3g)          
                       

    117,760     37,390             10,162  
                       

Net income attributable to shareholders

    258,631     58,899              
                       

Other comprehensive income

                             

Changes in fair value of equity instruments and cash flow hedges

        197             197  

Foreign currency translation adjustment

    8,916                 8,916  
                       

Comprehensive Income

  $ 249,715   $ 58,702              
                       

Weighted average common shares outstanding (#, thousands)

                             

Basic

    119,959         (3i)          

Diluted

    121,823         (3i)          

Earnings per common share

                             

Basic

  $ 2.16         (3i)            

Diluted

  $ 2.12         (3i)            

   

See the accompanying notes to the unaudited pro forma consolidated financial statements, which are an integral part of these statements.

B-6



BAYTEX ENERGY CORP.

NOTES TO UNAUDITED
PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

As at and for the nine-months ended September 30, 2013 and for the year ended December 31, 2012
(in thousands of Canadian dollars, unless otherwise stated)

1.     BASIS OF PRESENTATION

2.     DESCRIPTION OF TRANSACTION

B-7



BAYTEX ENERGY CORP.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As at and for the nine-months ended September 30, 2013 and for the year ended December 31, 2012
(in thousands of Canadian dollars, unless otherwise stated)

3.     PRO FORMA ASSUMPTIONS AND ADJUSTMENTS

 

Estimated Cost of Acquisition

       
 

Unadjusted purchase price

  $ 1,806,908  
 

Assumed long-term debt of Aurora (Note 2)

    679,482  
         
 

Estimated purchase price

  $ 2,486,390  
 

Cash realized on exercise of Aurora options (Note 3(j))

    21,099  
 

Acquisition costs, before tax (Note 3(f))

    34,000  
         
 

Estimated cost of acquisition

  $ 2,541,489  
         

 

 

Estimated Funding Requirements

       
 

Estimated purchase price

  $ 2,486,390  
 

Assumed long-term debt of Aurora (Note 2)

    (679,482 )
 

Common share issuance costs, before tax (Note 3(d))

     
 

Acquisition costs, before tax (Note 3(f))

    34,000  
 

Cash acquired

    (108,524 )
 

Cash realized on exercise of Aurora options (Note 3(j))

    (21,099 )
         
 

Estimated net funding requirements

     
         

 

 

Assumed Financing Structure

       
 

Assumed long-term debt of Aurora (Note 2)

  $ 679,482  
 

Common share issuance, net of issuance costs, before tax (Note 3(d))

     
 

Cash realized on exercise of Aurora options (Note 3(j))

    21,099  
 

Incremental long-term debt (Note 3(e))

     
         
         
         

 

Balance Sheet (US$ to C$)

       
 

Spot rate — September 30, 2013

    1.0285  
 

Income Statement (US$ to C$)

       
 

Average rate — January 1, 2012 to December 31, 2012

    1.0009  
 

Average rate — January 1, 2013 to September 30, 2013

    1.0236  

B-8



BAYTEX ENERGY CORP.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As at and for the nine-months ended September 30, 2013 and for the year ended December 31, 2012
(in thousands of Canadian dollars, unless otherwise stated)

3.     PRO FORMA ASSUMPTIONS AND ADJUSTMENTS (Continued)

Pro forma Consolidated Statement of Financial Position
As at September 30, 2013
(Unaudited)

   
  As published
Aurora Oil &
Gas Limited
  Note   Classification
adjustments
  Currency
Translation
adjustments
  Pro forma
Aurora Oil &
Gas Limited
 
   
  USD
   
   
   
  CAD
 
 

ASSETS

                             
 

Current assets

                             
 

Cash and cash equivalents

  $ 105,517       $   $ 3,007   $ 108,524  
 

Trade and other receivables

    58,375   (3k)     504     1,678     60,557  
                         
 

    163,892         504     4,685     169,081  
 

Non-current assets

                             
 

Other financial assets

    504   (3k)     (504 )        
 

Property, plant and equipment

    119,851             3,416     123,267  
 

Oil and gas properties

    1,234,198             35,175     1,269,373  
                         
 

  $ 1,518,445       $   $ 43,275   $ 1,561,721  
                         
 

LIABILITIES AND SHAREHOLDERS' EQUITY

                             
 

Current liabilities

                             
 

Trade and other payables

  $ 188,024   (3k)   $ 542   $ 5,374   $ 193,940  
 

Derivative financial instruments

    6,235             178     6,413  
 

Provisions

    542   (3k)     (542 )        
                         
 

    194,801             5,552     200,353  
 

Non-current liabilities

                             
 

Borrowings

    660,653             18,829     679,482  
 

Deferred tax liabilities

    126,240             3,598     129,838  
 

Derivative financial instruments

    428             12     440  
 

Provisions

    3,031             86     3,117  
                         
 

    985,153             28,077     1,013,230  
                         
 

Shareholders' equity

                             
 

Contributed equity

    405,148             11,547     416,695  
 

Share-based payment reserves

    16,103             459     16,562  
 

Fair value reserve

    (7,262 )           (207 )   (7,469 )
 

Foreign exchange reserve

    (7,505 )           (214 )   (7,719 )
 

Cash flow hedges reserve

    (4,664 )           (133 )   (4,797 )
 

Retained Earnings

    131,472             3,747     135,219  
                         
 

    533,292             15,199     548,491  
 

  $ 1,518,445       $   $ 43,276   $ 1,561,721  
                         

B-9



BAYTEX ENERGY CORP.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As at and for the nine-months ended September 30, 2013 and for the year ended December 31, 2012
(in thousands of Canadian dollars, unless otherwise stated)

3.     PRO FORMA ASSUMPTIONS AND ADJUSTMENTS (Continued)

Pro forma Consolidated Statement of Income and Comprehensive Income
For the nine months ended September 30, 2013
(Unaudited)

   
  As published
Aurora Oil &
Gas Limited
  Note   Classification
adjustments
  Currency
Translation
adjustments
  Pro forma
consolidated
Aurora Oil &
Gas Limited
 
   
  USD
   
   
   
  CAD
 
 

Revenue from continuing operations

  $ 405,388   (3k)   $ (122,091 ) $ 6,686   $ 289,983  
 

Other income

    99               2     101  
 

Expenses

                             
 

Royalties

    108,575   (3k)     (108,575 )        
 

Production and operating expenses

    42,846   (3k)     (24,511 )   433     18,768  
 

Transportation expenses

      (3k)     10,995     259     11,254  
 

Administrative expenses

    17,036             402     17,438  
 

Depletion, depreciation and amortization

    65,344             1,542     66,886  
 

Share-based payment expense

    4,325             102     4,427  
 

Finance costs

    43,115             1,018     44,133  
 

Exploration and evaluation costs

    282             7     289  
 

Foreign exchange loss

    282             7     289  
                         
 

    281,805         (122,091 )   3,769     163,483  
                         
 

Net income before income taxes

    123,682             2,919     126,601  
                         
 

Income tax expense

    43,703             1,031     44,734  
                         
 

Net income attributable to owners of the Company

    79,979             1,887     81,866  
                         
 

Other comprehensive income

                             
 

Changes in fair value of equity instruments

    208             5     213  
 

Changes in fair value of cash flow hedges

    3,510             83     3,593  
                         
 

Comprehensive Income

  $ 76,261       $   $ 1,800   $ 78,061  
                         

B-10



BAYTEX ENERGY CORP.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As at and for the nine-months ended September 30, 2013 and for the year ended December 31, 2012
(in thousands of Canadian dollars, unless otherwise stated)

3.     PRO FORMA ASSUMPTIONS AND ADJUSTMENTS (Continued)

Pro forma Consolidated Statement of Income and Comprehensive Income
For the year ended December 31, 2012
(Unaudited)

   
  As published
Aurora Oil &
Gas Limited
  Note   Classification
adjustments
  Currency
Translation
adjustments
  Pro forma
consolidated
Aurora Oil &
Gas Limited
 
   
  USD
   
   
   
  CAD
 
 

Revenues, net of royalties

  $ 295,059   (3k)   $ (87,698 ) $ 187   $ 207,548  
 

Other income

    5,008             5     5,013  
 

Expenses

                             
 

Royalties

    77,625   (3k)     (77,625 )        
 

Production and operating expenses

    34,581   (3k)     (14,362 )   18     20,237  
 

Transportation expenses

      (3k)     4,289     4     4,293  
 

Administrative expenses

    15,134             14     15,148  
 

Depletion, depreciation and amortization

    39,161             35     39,196  
 

Share-based payment expense

    4,398             4     4,402  
 

Finance costs

    28,027             25     28,052  
 

Exploration and evaluation costs

    4,939             4     4,943  
                         
 

    203,865         (87,698 )   105     116,272  
                         
 

Net income before income taxes

    96,202             87     96,289  
                         
 

Income tax expense

    37,356             34     37,390  
                         
 

Net income attributable to shareholders

    58,846             53     58,899  
                         
 

Other comprehensive income

                             
 

Changes in fair value of equity instruments

    (957 )           (1 )   (958 )
 

Changes in fair value of cash flow hedges

    1,154             1     1,155  
                         
 

Comprehensive Income

  $ 58,649       $   $ 53   $ 58,702  
                         

B-11



BAYTEX ENERGY CORP.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As at and for the nine-months ended September 30, 2013 and for the year ended December 31, 2012
(in thousands of Canadian dollars, unless otherwise stated)

3.     PRO FORMA ASSUMPTIONS AND ADJUSTMENTS (Continued)

 
(in millions)
  Aurora   Fair Value
and Other
Adjustments
  Net Total  
 

Assets acquired:

                   
 

Cash and cash equivalents

  $ 108,524       $ 108,524  
 

Accounts receivable

    60,557         60,557  
                 
 

Total current assets

    169,081         169,081  
 

Exploration and evaluation assets

        1,283,392     1,283,392  
 

Other plant and equipment

    123,267         123,267  
 

Oil and gas assets and other assets

    1,269,373         1,269,373  
                 
 

  $ 1,561,721     1,283,392   $ 2,845,113  
                 
 

Liabilities assumed:

                   
 

Accounts payable and other current liabilities

  $ 193,940       $ 193,940  
 

Financial derivatives

    6,413         6,413  
                 
 

Total current liabilities

    200,353           200,353  
 

Long-term debt

    679,482     24,975     704,456  
 

Asset retirement obligation

    3,117         3,117  
 

Deferred income tax liability

    129,838     444,280     574,118  
 

Financial Derivatives

    440         440  
                 
 

  $ 1,013,230     469,255   $ 1,482,485  
 

Net assets at fair value, as at September 30, 2013

                1,362,628  
                     
 

Estimated purchase price, before assumed debt

                1,806,908  
                     
 

Goodwill

              $ 444,280  
                     

B-12



BAYTEX ENERGY CORP.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As at and for the nine-months ended September 30, 2013 and for the year ended December 31, 2012
(in thousands of Canadian dollars, unless otherwise stated)

3.     PRO FORMA ASSUMPTIONS AND ADJUSTMENTS (Continued)

B-13


LOGO



PART II

INFORMATION NOT REQUIRED TO BE DELIVERED
TO OFFEREES OR PURCHASERS

Indemnification of Directors and Officers

The constituting documents of Baytex Energy Corp. ("Baytex" or the "Registrant") contain the following provisions with respect to the protection and indemnification of our directors and officers:

        No director or officer for the time being of Baytex shall be liable for the acts, receipts, neglects or defaults of any other director, officer or employee, or for joining in any receipt or act for conformity, or for any loss, damage or expense happening to Baytex through the insufficiency or deficiency of title to any property acquired by Baytex or for or on behalf of Baytex or for the insufficiency or deficiency of any security in or upon which any of the moneys of or belonging to Baytex shall be placed or invested, or for any loss or damage arising from the bankruptcy, insolvency or tortious act of any person, firm or corporation, including any person, firm or corporation with whom or with which any moneys, securities or effects shall be lodged or deposited, or for any loss, conversion, misapplication or misappropriation of or any damage resulting from any dealings with any moneys, securities or other assets of or belonging to Baytex or for any other loss, damage or misfortune whatsoever which may happen in the execution of the duties of his or her respective office or trust or in relation thereto unless the same shall happen by or through his or her failure to exercise the powers and to discharge the duties of his or her office honestly, in good faith and with a view to the best interests of Baytex and to exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances.

        Baytex hereby indemnifies, to the maximum extent permitted under the Alberta Business Corporations Act ("ABCA"), each director and officer and each former director and officer, and may indemnify a person who acts or acted at Baytex's request as a director or officer of a body corporate of which Baytex is or was a shareholder or creditor, and their heirs and legal representatives, against all costs, charges and expenses, including any amount paid to settle an action or satisfy a judgment, reasonably incurred by him or her in respect of any civil, criminal or administrative action or proceeding to which he or she is made a party by reason of being or having been a director or officer of Baytex or such body corporate.

        Baytex may purchase and maintain insurance for the benefit of any person against any liability incurred by him or her:

        We have entered into agreements, if applicable, with each of our directors and officers to evidence our obligations to indemnify such directors and officers as described above.

        Section 124 of the Business Corporations Act (Alberta) provides as follows:

124 (1) Except in respect of an action by or on behalf of the corporation or body corporate to procure a judgment in its favour, a corporation may indemnify a director or officer of the corporation, a former director or officer of the corporation or a person who acts or acted at the corporation's request as a director or officer of a body corporate of which the corporation is or was a shareholder or creditor, and the director's

II-1


or officer's heirs and legal representatives, against all costs, charges and expenses, including an amount paid to settle an action or satisfy a judgment, reasonably incurred by the director or officer in respect of any civil, criminal or administrative action or proceeding to which the director or officer is made a party by reason of being or having been a director or officer of that corporation or body corporate, if

        (2) A corporation may, with the approval of the Court, indemnify a person referred to in subsection (1) in respect of an action by or on behalf of the corporation or body corporate to procure a judgment in its favour, to which the person is made a party by reason of being or having been a director or an officer of the corporation or body corporate, against all costs, charges and expenses reasonably incurred by the person in connection with the action if the person fulfils the conditions set out in subsection (1)(a) and (b).

        (3) Notwithstanding anything in this section, a person referred to in subsection (1) is entitled to indemnity from the corporation in respect of all costs, charges and expenses reasonably incurred by the person in connection with the defence of any civil, criminal or administrative action or proceeding to which the person is made a party by reason of being or having been a director or officer of the corporation or body corporate, if the person seeking indemnity

        (3.1) A corporation may advance funds to a person in order to defray the costs, charges and expenses of a proceeding referred to in subsection (1) or (2), but if the person does not meet the conditions of subsection (3) he or she shall repay the funds advanced.

        (4) A corporation may purchase and maintain insurance for the benefit of any person referred to in subsection (1) against any liability incurred by the person

        (5) A corporation or a person referred to in subsection (1) may apply to the Court for an order approving an indemnity under this section and the Court may so order and make any further order it thinks fit.

        (6) On an application under subsection (5), the Court may order notice to be given to any interested person and that person is entitled to appear and be heard in person or by counsel.

As contemplated by Section 124(4) of the Business Corporations Act (Alberta), the Registrant has purchased insurance against potential claims against its directors and officers and against loss for which the Registrant may be required or permitted by law to indemnify such directors and officers.

* * *

Insofar as indemnification for liabilities arising under the Securities Act of 1933, as amended, may be permitted to directors, officers or persons controlling the Registrant pursuant to the foregoing provisions, the Registrant has been informed that in the opinion of the U.S. Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933, as amended, and is therefore unenforceable.

II-2



FORM F-10

EXHIBITS OF BAYTEX ENERGY CORP.

EXHIBIT
NUMBER
  DESCRIPTION

3.1

* Underwriting Agreement.

4.1

  Annual Information Form for the year ended December 31, 2012, dated March 25, 2013 (incorporated by reference to Exhibit 99.1 to our Annual Report on Form 40-F for the fiscal year ended December 31, 2012 filed with the SEC on March 26, 2013 (File No. 001-32754)).

4.2

  Audited consolidated financial statements as at December 31, 2012 and 2011 and for the years then ended, together with the notes thereto and the auditor's report thereon (incorporated by reference to Exhibit 99.2 to our Annual Report on Form 40-F for the fiscal year ended December 31, 2012 filed with the SEC on March 26, 2013 (File No. 001-32754)).

4.3

  Management's discussion and analysis of operating and financial results for the year ended December 31, 2012 (incorporated by reference to Exhibit 99.3 to our Annual Report on Form 40-F for the fiscal year ended December 31, 2012 filed with the SEC on March 26, 2013 (File No. 001-32754)).

4.4

  Condensed interim unaudited consolidated financial statements as at September 30, 2013 and 2012 and for the nine month periods ended September 30, 2013 and 2012, together with the notes thereto (incorporated by reference to Exhibit 99.1 to our Report on Form 6-K filed with the SEC on October 30, 2013 (File No. 001-32754)).

4.5

  Management's discussion and analysis of operating and financial results for the nine month period ended September 30, 2013 (incorporated by reference to Exhibit 99.2 to our Report on Form 6-K filed with the SEC on October 30, 2013 (File No. 001-32754)).

4.6

  Information Circular — Proxy Statement dated April 1, 2013 relating to the annual and special meeting of shareholders held on May 14, 2013 (incorporated by reference to Exhibit 99.2 to our Report on Form 6-K filed with the SEC on April 10, 2013 (File No. 001-32754)).

4.7

  Supplemental Disclosures about Extraction Activities — Oil and Gas prepared in accordance with Accounting Standards Codification 932 "Extractive Activities — Oil & Gas" (incorporated by reference to Exhibit 99.1 to our Report on Form 6-K filed with the SEC on March 26, 2013 (File No. 001-32754)).

4.8

  The "template version" (as such term is defined in National Instrument 41-101 — General Prospectus Requirements) of the term sheet for the Offering dated and filed February 6, 2014.

4.9

  Investor Presentation, dated February 2014, and filed February 6, 2014.

5.1

  Consent of Deloitte LLP, independent registered chartered accountants.

5.2

  Consent of BDO Audit (WA) Pty Ltd., independent registered chartered accountants for Aurora Oil & Gas Limited.

5.3

  Consent of Sproule Associates Limited, independent engineers.

5.4

  Consent of Ryder Scott Company L.P., independent reserves evaluator for Aurora Oil & Gas Limited.

5.5

  Consent of Burnet, Duckworth & Palmer LLP, legal counsel.

6.1

  Powers of Attorney (included on the signature page of this Registration Statement).

*
To be filed by amendment.

II-3



PART III

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

Item 1.    Undertaking

        The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to the securities registered pursuant to Form F-10 or to transactions in said securities.

Item 2.    Consent to Service of Process

        A written Appointment of Agent for Service of Process and Undertaking on Form F-X for the Registrant and its agent for service of process is being filed concurrently herewith.

        Any change to the name or address of the agent for service of process of the Registrant shall be communicated promptly to the Commission by amendment to Form F-X referencing the file number of this Registration Statement on Form F-10.

II-4



SIGNATURES

        Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form F-10 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Alberta, Canada, on February 6, 2014.

    BAYTEX ENERGY CORP.

 

 

By:

 

/s/ JAMES L. BOWZER

Name: James L. Bowzer
Title:
President and Chief Executive Officer


POWER OF ATTORNEY

        KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints James L. Bowzer and W. Derek Aylesworth, or either of them, his or her true and lawful attorneys-in-fact and agents, each of whom may act alone, with full powers of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any or all amendments to this Registration Statement, including post-effective amendments, and any and all additional registration statements (including amendments and post-effective amendments thereto) in connection with any increase in the amount of securities registered with the Securities and Exchange Commission, and to file the same, with all exhibits thereto, and other documents and in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he or she might or could do in person, and hereby ratifies and confirms all his or her said attorneys-in-fact and agents or any of them or his or her substitute or substitutes may lawfully do or cause to be done by virtue hereof.

        This Power of Attorney may be executed in multiple counterparts, each of which shall be deemed an original, but which taken together shall constitute one instrument.

        Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed below by the following persons in the capacities indicated and on the dates indicated.

Signature
  Capacity   Date

 

 

 

 

 
/s/ JAMES L. BOWZER

James L. Bowzer
  President, Chief Executive Officer and Director
(Principal Executive Officer)
  February 6, 2014

/s/ W. DEREK AYLESWORTH

W. Derek Aylesworth

 

Chief Financial Officer
(Principal Financial & Accounting Officer)

 

February 6, 2014

/s/ RAYMOND T. CHAN

Raymond T. Chan

 

Director and Executive Chairman

 

February 6, 2014

/s/ JOHN A. BRUSSA

John A. Brussa

 

Director

 

February 6, 2014

/s/ EDWARD CHWYL

Edward Chwyl

 

Director

 

February 6, 2014

Signature
  Capacity   Date

 

 

 

 

 
/s/ NAVEEN DARGAN

Naveen Dargan
  Director   February 6, 2014

/s/ R.E.T. GOEPEL

R.E.T. Goepel

 

Director

 

February 6, 2014

  

Gregory K. Melchin

 

Director

 

February 6, 2014

/s/ MARY ELLEN PETERS

Mary Ellen Peters

 

Director

 

February 6, 2014

/s/ DALE O. SHWED

Dale O. Shwed

 

Director

 

February 6, 2014


AUTHORIZED REPRESENTATIVE

        Pursuant to the requirements of Section 6(a) of the Securities Act of 1933, as amended, the undersigned has signed this Registration Statement, in the capacity of the duly authorized representative of the Registrant in the United States, on February 6, 2014.

    BAYTEX ENERGY USA LTD.

 

 

By:

 

/s/ JAMES L. BOWZER

Name: James L. Bowzer
Title:
Chief Executive Officer


INDEX OF EXHIBITS OF BAYTEX ENERGY CORP.
to
FORM F-10

EXHIBIT
NUMBER
  DESCRIPTION

3.1

* Underwriting Agreement.

4.1

  Annual Information Form for the year ended December 31, 2012, dated March 25, 2013 (incorporated by reference to Exhibit 99.1 to our Annual Report on Form 40-F for the fiscal year ended December 31, 2012 filed with the SEC on March 26, 2013 (File No. 001-32754)).

4.2

  Audited consolidated financial statements as at December 31, 2012 and 2011 and for the years then ended, together with the notes thereto and the auditor's report thereon (incorporated by reference to Exhibit 99.2 to our Annual Report on Form 40-F for the fiscal year ended December 31, 2012 filed with the SEC on March 26, 2013 (File No. 001-32754)).

4.3

  Management's discussion and analysis of operating and financial results for the year ended December 31, 2012 (incorporated by reference to Exhibit 99.3 to our Annual Report on Form 40-F for the fiscal year ended December 31, 2012 filed with the SEC on March 26, 2013 (File No. 001-32754)).

4.4

  Condensed interim unaudited consolidated financial statements as at September 30, 2013 and 2012 and for the nine month periods ended September 30, 2013 and 2012, together with the notes thereto (incorporated by reference to Exhibit 99.1 to our Report on Form 6-K filed with the SEC on October 30, 2013 (File No. 001-32754)).

4.5

  Management's discussion and analysis of operating and financial results for the nine month period ended September 30, 2013 (incorporated by reference to Exhibit 99.2 to our Report on Form 6-K filed with the SEC on October 30, 2013 (File No. 001-32754)).

4.6

  Information Circular — Proxy Statement dated April 1, 2013 relating to the annual and special meeting of shareholders held on May 14, 2013 (incorporated by reference to Exhibit 99.2 to our Report on Form 6-K filed with the SEC on April 10, 2013 (File No. 001-32754)).

4.7

  Supplemental Disclosures about Extraction Activities — Oil and Gas prepared in accordance with Accounting Standards Codification 932 "Extractive Activities — Oil & Gas" (incorporated by reference to Exhibit 99.1 to our Report on Form 6-K filed with the SEC on March 26, 2013 (File No. 001-32754)).

4.8

  The "template version" (as such term is defined in National Instrument 41-101 — General Prospectus Requirements) of the term sheet for the Offering dated and filed February 6, 2014.

4.9

  Investor Presentation, dated February 2014, and filed on February 6, 2014.

5.1

  Consent of Deloitte LLP, independent registered chartered accountants.

5.2

  Consent of BDO Audit (WA) Pty Ltd., independent registered chartered accountants for Aurora Oil & Gas Limited.

5.3

  Consent of Sproule Associates Limited, independent engineers.

5.4

  Consent of Ryder Scott Company L.P., independent reserves evaluator for Aurora Oil & Gas Limited.

5.5

  Consent of Burnet, Duckworth & Palmer LLP, legal counsel.

6.1

  Powers of Attorney (included on the signature page of this Registration Statement).

*
To be filed by amendment.



QuickLinks

TABLE OF CONTENTS
IMPORTANT NOTICE ABOUT INFORMATION IN THIS SHORT FORM PROSPECTUS
PRESENTATION OF FINANCIAL AND OIL AND GAS INFORMATION
SELECTED DEFINITIONS
CONVERSIONS
ABBREVIATIONS
CONVENTIONS
OIL AND GAS EQUIVALENCY
NON-GAAP FINANCIAL MEASURES
ENFORCEMENT OF JUDGMENTS AGAINST FOREIGN PERSONS OR COMPANIES
DOCUMENTS INCORPORATED BY REFERENCE
MARKETING MATERIALS
FORWARD-LOOKING STATEMENTS
WHERE YOU CAN FIND MORE INFORMATION
EXCHANGE RATES
United States Dollars
RISK FACTORS
SUMMARY DESCRIPTION OF OUR BUSINESS
RECENT DEVELOPMENTS
ABOUT AURORA
SUMMARY OF OIL AND NATURAL GAS RESERVES AS OF DECEMBER 31, 2013 FORECAST PRICES AND COSTS
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2013 FORECAST PRICES AND COSTS
SUMMARY OF PRICE ASSUMPTIONS AS OF DECEMBER 31, 2013 FORECAST PRICES AND COSTS
SUMMARY OF OIL AND NATURAL GAS RESERVES AS OF DECEMBER 31, 2012 FORECAST PRICES AND COSTS
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2012 FORECAST PRICES AND COSTS
FUTURE NET REVENUE BY PRODUCTION GROUP AS OF DECEMBER 31, 2012 FORECAST PRICES AND COSTS
SUMMARY OF PRICE ASSUMPTIONS AS OF DECEMBER 31, 2012 FORECAST PRICES AND COSTS
USE OF PROCEEDS
DESCRIPTION OF COMMON SHARES
CONSOLIDATED CAPITALIZATION
DETAILS OF THE OFFERING
PLAN OF DISTRIBUTION
RELATIONSHIP BETWEEN US AND CERTAIN UNDERWRITERS
PRIOR SALES
MARKET FOR SECURITIES
DIVIDENDS TO SHAREHOLDERS
CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS
CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
LEGAL MATTERS
INTEREST OF EXPERTS
DOCUMENTS FILED AS PART OF THE REGISTRATION STATEMENT
SCHEDULE "A" FINANCIAL STATEMENTS OF AURORA
MANAGEMENT REPORT For the year ended December 31, 2012
INDEPENDENT AUDIT REPORT For the year ended December 31, 2012
INDEPENDENT AUDITOR'S REPORT TO THE MEMBERS OF AURORA OIL & GAS LIMITED
AURORA OIL & GAS LIMITED CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME For the year ended December 31, 2012
AURORA OIL & GAS LIMITED CONSOLIDATED STATEMENT OF FINANCIAL POSITION As at December 31, 2012
AURORA OIL & GAS LIMITED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY For the year ended December 31, 2012
AURORA OIL & GAS LIMITED CONSOLIDATED STATEMENT OF CASH FLOWS For the year ended December 31, 2012
AURORA OIL & GAS LIMITED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS For the year ended December 31, 2012
AURORA OIL & GAS LIMITED ABN 90 008 787 988 CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME For the three and nine months ended September 30, 2013 and 2012
AURORA OIL & GAS LIMITED ABN 90 008 787 988 CONSOLIDATED STATEMENT OF FINANCIAL POSITION As at September 30, 2013
AURORA OIL & GAS LIMITED ABN 90 008 787 988 CONSOLIDATED STATEMENT OF CHANGES IN EQUITY For the three and nine months ended September 30, 2013 and 2012
AURORA OIL & GAS LIMITED ABN 90 008 787 988 CONSOLIDATED STATEMENT OF CHANGES IN EQUITY For the three and nine months ended September 30, 2013 and 2012
AURORA OIL & GAS LIMITED ABN 90 008 787 988 CONSOLIDATED STATEMENT OF CASH FLOWS For the three and nine months ended September 30, 2013 and 2012
AURORA OIL & GAS LIMITED ABN 90 008 787 988 NOTES TO THE FINANCIAL STATEMENTS For the three and nine months ended September 30, 2013
SCHEDULE "B" PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS OF BAYTEX
BAYTEX ENERGY CORP. PRO FORMA CONSOLIDATED STATEMENT OF FINANCIAL POSITION As at September 30, 2013 (Unaudited) (In thousands of Canadian dollars)
BAYTEX ENERGY CORP. PRO FORMA CONSOLIDATED STATEMENT OF INCOME AND COMPREHENSIVE INCOME For the nine months ended September 30, 2013 (Unaudited) (In thousands of Canadian dollars, except for per share amounts)
BAYTEX ENERGY CORP. PRO FORMA CONSOLIDATED STATEMENT OF INCOME AND COMPREHENSIVE INCOME For the year ended December 31, 2012 (Unaudited) (In thousands of Canadian dollars, except for per share amounts)
BAYTEX ENERGY CORP. NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS As at and for the nine-months ended September 30, 2013 and for the year ended December 31, 2012 (in thousands of Canadian dollars, unless otherwise stated)
PART II INFORMATION NOT REQUIRED TO BE DELIVERED TO OFFEREES OR PURCHASERS
FORM F-10 EXHIBITS OF BAYTEX ENERGY CORP.
PART III UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
SIGNATURES
POWER OF ATTORNEY
AUTHORIZED REPRESENTATIVE
INDEX OF EXHIBITS OF BAYTEX ENERGY CORP. to FORM F-10