EX-99.1 2 a2016aif991.htm EXHIBIT 99.1 Exhibit


Exhibit 99.1
image0a06.jpg


ANNUAL INFORMATION FORM
2016





MARCH 7, 2017




TABLE OF CONTENTS

APPENDICES:
APPENDIX A
CONTINGENT RESOURCE ESTIMATES
APPENDIX B
REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE
APPENDIX C
REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR
APPENDIX D    AUDIT COMMITTEE MANDATE AND TERMS OF REFERENCE



    


SELECTED TERMS
Capitalized terms in this Annual Information Form have the meanings set forth below:
Entities
Baytex or the Corporation means Baytex Energy Corp., a corporation incorporated under the ABCA.
Baytex Energy means Baytex Energy Ltd., a corporation amalgamated under the ABCA.
Baytex Partnership means Baytex Energy Partnership, a general partnership, the partners of which are Baytex Energy and Baytex Holdings Limited Partnership.
Baytex USA means Baytex Energy USA, Inc.
Board or Board of Directors means the board of directors of Baytex.
NYMEX means the New York Mercantile Exchange, a commodity futures exchange.
OPEC means the Organization of the Petroleum Exporting Countries.
Operating Entities means our 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 Partnership and Baytex USA, each a direct or indirect wholly-owned subsidiary of us, and Operating Entity means any one of them, as applicable.
SEC means the United States Securities and Exchange Commission
Shareholders mean the holders from time to time of Common Shares.
subsidiary has the meaning ascribed thereto in the Securities Act (Ontario) and, for greater certainty, includes all corporations, partnerships and trusts owned, controlled or directed, directly or indirectly, by us.
we, us and our means Baytex and all its subsidiaries on a consolidated basis unless the context requires otherwise.
Securities and Other Terms
2020 Aurora Notes means the 7.50% senior unsecured notes due April 1, 2020 issued by Baytex USA (formerly Aurora Oil & Gas, Inc.) pursuant to Debt Indenture #3 of which US$6.4 million was outstanding as at March 1, 2017.
2021 Debentures means the 6.75% series B senior unsecured debentures due February 17, 2021 issued by Baytex pursuant to Debt Indenture #1 of which US$150 million was outstanding as at March 1, 2017.
2021 Notes means the 5.125% senior unsecured notes due June 1, 2021 issued by Baytex pursuant to Debt Indenture #2 of which US$400 million was outstanding as at March 1, 2017.
2022 Debentures means the 6.625% series C senior unsecured debentures due July 19, 2022 issued by Baytex pursuant to Debt Indenture #1 of which $300 million was outstanding as at March 1, 2017.
2024 Notes means the 5.625% senior unsecured notes due June 1, 2024 issued by Baytex pursuant to Debt Indenture #2 of which US$400 million was outstanding as at March 1, 2017.


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ABCA means the Business Corporations Act (Alberta), R.S.A. 2000, c. B-9, as amended, including the regulations promulgated thereunder.
Canadian GAAP means generally accepted accounting principles in Canada, which are consistent with International Financial Reporting Standards as issued by the International Accounting Standards Board.
Common Shares means the common shares of Baytex.
Credit Facilities means our US$575 million secured, covenant-based credit facility with a syndicate of financial institutions.
CSS means cyclic steam stimulation.
Debt Indenture #1 means the amended and restated trust indenture among Baytex, as issuer, certain of its subsidiaries, as guarantors, and Valiant Trust Company, as indenture trustee, dated January 1, 2011, as supplemented by supplemental indentures dated February 17, 2011, February 18, 2011, July 19, 2012, December 19, 2012, June 4, 2014, June 11, 2014, July 25, 2014 and March 6, 2015.
Debt Indenture #2 means the indenture among Baytex, as issuer, certain of its subsidiaries, as guarantors, and Computershare Trust Company, N.A., as indenture trustee, dated June 6, 2014, as supplemented by supplemental indentures dated June 11, 2014 and July 25, 2014.
Debt Indenture #3 means the indenture among Aurora Oil & Gas, Inc. (now Baytex USA), as issuer, certain of its affiliates, as guarantors, and U.S. National Bank Association, as indenture trustee, dated March 21, 2013, as supplemented by supplemental indentures dated December 6, 2013, April 25, 2014 and May 5, 2014.
MD&A means management's discussion and analysis of operating and financial results.
SAGD means steam-assisted gravity drainage.
Senior Notes means, collectively, the 2021 Debentures, the 2021 Notes, the 2022 Debentures and the 2024 Notes.
Tax Act means the Income Tax Act (Canada), R.S.C. 1985, c. 1 (5th Supp.), as amended, including the regulations promulgated thereunder, as amended from time to time.
Independent Engineering
Baytex Reserves Report means the report prepared by Sproule dated February 23, 2017 entitled "Consolidation of the P&NG Reserves of Baytex Energy Corp. Evaluated by Sproule Unconventional Limited and Ryder Scott Company, L.P. (As of December 31, 2016)", which is a consolidation of: (i) the report of Sproule dated January 30, 2017 entitled "Evaluation of the P&NG Reserves of Baytex Energy Corp. in Canada (As of December 31, 2016)" and (ii) the report of Ryder Scott dated February 1, 2017 entitled "Baytex Energy Corp. Summary Report Estimated Future Reserves and Income Attributable to Certain Leasehold Interests NI 51-101 Forecast Economic Parameters Canadian Currency (As of December 31, 2016)".
COGE Handbook means the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter), as amended from time to time.
NI 51-101 means National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" of the Canadian Securities Administrators.
Ryder Scott means Ryder Scott Company, L.P., independent petroleum consultants of Houston, Texas.
Sproule means Sproule Unconventional Limited, independent petroleum consultants of Calgary, Alberta.


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Reserves Definitions
Gross means:
(a)
in relation to our interest in production, reserves and contingent resources, our interest (operating and non-operating) share before deduction of royalties and without including any of our royalty interests;
(b)
in relation to wells, the total number of wells in which we have an interest; and
(c)
in relation to properties, the total area of properties in which we have an interest.
Net means:
(a)
in relation to our interest in production, reserves and contingent resources, our interest (operating and non-operating) share after deduction of royalty obligations, plus our royalty interest in production or reserves;
(b)
in relation to wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and
(c)
in relation to our interest in a property, the total area in which we have an interest multiplied by our working interest.
Forecast Prices and Costs are 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 Baytex 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).
Reserves and Reserve Categories
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 (being the Forecast Prices and Costs used in the estimate).
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.
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.
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.
The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:
(i)
at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and
(ii)
at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves; and
(iii)
at least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves.


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A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.
Development and Production Status
Each of the reserves categories (proved, probable and possible) may be divided into developed and undeveloped categories:
(a)
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 the following categories:
i.
Developed producing reserves are those reserves that are expected to be recovered from completion 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.
ii.
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.
(b)
Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, 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 or possible) to which they are assigned.
ABBREVIATIONS
Oil and Natural Gas Liquids
Natural Gas
 
 
 
 
bbl
barrel
Mcf
thousand cubic feet
Mbbl
thousand barrels
MMcf
million cubic feet
MMbbl
million barrels
Bcf
billion cubic feet
NGL
natural gas liquids
Mcf/d
thousand cubic feet per day
bbl/d
barrels per day
MMcf/d
million cubic feet per day
 
 
m3
cubic metres
 
 
MMbtu
million British Thermal Units
 
 
 
 


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Other
 
AECO
the natural gas storage facility located at Suffield, Alberta
BOE or boe
barrel of oil equivalent, using the conversion factor of six Mcf of natural gas being equivalent to one bbl of oil. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Mboe
thousand barrels of oil equivalent
MMboe
million barrels of oil equivalent
boe/d
barrels of oil equivalent per day
WTI
West Texas Intermediate
LLS
Louisiana Light Sweet
WCS
Western Canadian Select
API
the measure of the density or gravity of liquid petroleum products derived from a specific gravity
$ Million
millions of dollars
$000s
thousands of dollars

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
Bbl
Cubic metres
0.159
Cubic metres
Bbl
6.293
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
0.948
CONVENTIONS
Certain terms used herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings in this Annual Information Form as in NI 51-101. Unless otherwise indicated, references in this Annual Information Form to "$" or "dollars" are to Canadian dollars and references to "US$" are to United States dollars. All financial information contained in this Annual Information Form has been presented in Canadian dollars in accordance with Canadian GAAP. Words importing the singular number only include the plural, and vice versa, and words importing any gender include all genders. All operational information contained in this Annual Information Form relates to our consolidated operations unless the context otherwise requires.


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SPECIAL NOTES TO READER
Forward-Looking Statements
In the interest of providing our Shareholders and potential investors with information about us, including management's assessment of our future plans and operations, certain statements in this Annual Information Form are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 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 Annual Information Form speak only as of the date hereof and are expressly qualified by this cautionary statement.
Specifically, this Annual Information Form contains forward-looking statements relating to, but not limited to: our business strategies, plans and objectives; our petroleum and natural gas reserves; the development plans for our undeveloped reserves; our future abandonment and reclamation liabilities; the future development costs associated with our reserves; funding sources for development capital expenditures; our goal of building value through exploration and development activities complemented by selective acquisitions; development plans for our properties; the wide range of heavy oil investment opportunities in our Lloydminster Business Unit; our ability to reactivate our Cliffdale project at minimal expense when commodity prices warrant; our expectations regarding undeveloped lease expiries; our expectation regarding the payment of cash income taxes; our working interest production volume for 2017 based on the future net revenue disclosed in our reserves; the existence, operation and strategy of our risk management program; that we expect Edward D. LaFehr to succeed James L. Bowzer as Chief Executive Officer in May of 2017; our dividend policy; our assessment of our tax filing position for the years 2011 through 2015; and the impact of existing and proposed governmental and environmental regulation.
In addition, there are forward-looking statements in this Annual Information Form under the heading "Description of Our Business and Operations - Statement of Reserves Data and Other Oil and Gas Information" as to our reserves, including with respect thereto, the future net revenues from our reserves, pricing and inflation rates, future development costs, the development of our proved undeveloped reserves, probable undeveloped reserves and possible reserves, future development costs, reclamation and abandonment obligations, tax horizon, exploration and development activities and production estimates. There are also forward-looking statements in this Annual Information Form within "Appendix A - Contingent Resource Estimates" as to our contingent resources, including with respect thereto, the chance of development, risked volume, risked net present value of future net revenue, capital to reach commercial production and timing of first production. Information and statements relating to reserves and contingent resources are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves and contingent resources described exist in quantities predicted or estimated, and that the reserves and contingent resources can be profitably produced in the future.
These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; our ability to borrow under our credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for our operating activities; the availability and cost of labour and other industry services; 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 in the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.
Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the volatility of oil and natural gas prices; a decline or an extended period of the currently low oil and natural gas prices; uncertainties in the capital


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markets that may restrict or increase our cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated with a third-party operating our Eagle Ford properties; changes in government regulations that affect the oil and gas industry; changes in environmental, health and safety regulations; restrictions or costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; the cost of developing and operating our assets; availability and cost of gathering, processing and pipeline systems; depletion of our reserves; risks associated with the exploitation of our properties and our ability to acquire reserves; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum and natural gas reserves; our inability to fully insure against all risks; risks of counterparty default; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects; risks related to our thermal heavy oil projects; we may lose access to our information technology systems; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control.
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. Readers should also carefully consider the matters discussed under the heading "Risk Factors" in this Annual Information Form.
The above summary of assumptions and risks related to forward-looking statements in this Annual Information Form has been provided in order to provide Shareholders and potential investors with a more complete perspective on our current and future operations and such information may not be appropriate for other purposes. There is no representation by us that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements and 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 Annual Information Form are expressly qualified by this cautionary statement.
Description of Funds from Operations
This Annual Information Form contains references to funds from operations, which does not have any standardized meaning prescribed by Canadian GAAP and may not be comparable to similar measures used by other companies. We define funds from operations as cash flow from operating activities adjusted for changes in non-cash operating working capital and other operating items. We believe that this measure provides a more complete understanding of our results of operations and financial performance, including our ability to generate funds for capital investment and potential future dividends to shareholders. However, funds from operations should not be construed as an alternative to performance measures determined in accordance with Canadian GAAP, such as cash flow from operating activities and net income (loss).
For a reconciliation of funds from operations to cash flow from operating activities, see our MD&A for the year ended December 31, 2016 which is accessible on the SEDAR website at www.sedar.com.
New York Stock Exchange
As a Canadian foreign private issuer listed on the New York Stock Exchange (the "NYSE"), we are not required to comply with most of the NYSE's corporate governance rules and listing standards and instead may comply with domestic corporate governance requirements. The NYSE requires that we disclose any significant ways in which our corporate governance practices differ from those followed by U.S. domestic issuers. We have reviewed the NYSE corporate governance and listing standards applicable to U.S. domestic issuers and confirm that our corporate governance practices do not differ from such standards in any significant way.


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Access to Documents
Any document referred to in this Annual Information Form and described as being accessible on the SEDAR website at www.sedar.com (including those documents referred to as being incorporated by reference in this Annual Information Form) may be obtained free of charge from us at Suite 2800, Centennial Place, East Tower, 520 - 3rd Avenue S.W., Calgary, Alberta, Canada, T2P 0R3.
CORPORATE STRUCTURE
General
Baytex Energy Corp. was incorporated on October 22, 2010 pursuant to the provisions of the ABCA, as an indirect wholly-owned subsidiary of Baytex Energy Trust, for the purpose of participating in a plan of arrangement under the ABCA to effect a conversion of the legal structure from that of a trust to a corporation, such that the Corporation would be the successor to Baytex Energy Trust. The conversion took place on December 31, 2010, following which Baytex Energy Trust was terminated.
Our head and principal office is located at Suite 2800, Centennial Place, East Tower, 520 – 3rd Avenue S.W., Calgary, Alberta, Canada, T2P 0R3. Our registered office is located at 2400, 525 – 8th Avenue S.W., Calgary, Alberta, Canada, T2P 1G1.
Inter-Corporate Relationships
The following table provides the name, the percentage of voting securities owned by us and the jurisdiction of incorporation, continuance, formation or organization of our material subsidiaries either, direct and indirect, as at the date hereof.
 
Percentage of voting securities
(directly or indirectly)
 
Jurisdiction of Incorporation/
Formation
Baytex Energy Ltd.
100%
 
Alberta
Baytex Energy USA, Inc.
100%
 
Delaware
Baytex Energy Partnership
100%
 
Alberta



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Our Organizational Structure
The following simplified diagram shows the inter-corporate relationships among us and our material subsidiaries as of the date hereof.
image1a03.jpg
GENERAL DEVELOPMENT OF OUR BUSINESS
Developments in the Past Three Years
2014
On June 11, 2014, we acquired all of the ordinary shares of Aurora Oil & Gas Limited ("Aurora") for $4.20 (Australian dollars) per share by way of a scheme of arrangement under the Corporations Act 2001 (Australia) (the "Arrangement"). The total purchase price for Aurora was approximately $2.8 billion, including the assumption of $955 million of indebtedness and $54.6 million of cash. Aurora's primary asset consisted of 22,200 net contiguous acres in the Sugarkane area located in South Texas in the core of the liquids-rich Eagle Ford shale. The acquisition added an estimated 166.6 MMboe of proved and probable reserves. Aurora's gross production during the three months ended March 31, 2014 was approximately 28,600 boe/d of predominantly light, high-quality crude oil.
To finance the acquisition of Aurora, we issued 38,433,000 subscription receipts at $38.90 each on February 24, 2014, raising gross proceeds of approximately $1.5 billion. The subscription receipts were converted to an equivalent number of Common Shares on June 11, 2014. We also entered into an agreement with a Canadian chartered bank for the provision of credit facilities, which provided unsecured revolving credit facilities of approximately $1.2 billion (to replace the $850 million revolving credit facilities of Baytex Energy), and a new two-year $200 million unsecured term loan. The credit facilities became available upon closing of the Arrangement and were used to finance a portion of the purchase price.
On June 6, 2014, we completed a private placement of US$800 million of senior unsecured notes, comprised of   US$400 million of 5.125% notes due June 1, 2021 and US$400 million of 5.625% notes due June 1, 2024. Approximately US$730 million of the net proceeds of the offering were used to finance the purchase and cancellation of US$650.7 million principal amount of senior unsecured notes of Aurora with the remainder used for general corporate purposes.


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In September 2014, we completed the sale of our assets in North Dakota for US$330.5 million. The disposed assets produced approximately 3,200 boe/d in the second quarter of 2014 and included 53.5 MMboe of proved plus probable reserves (81% oil and NGL) as at December 31, 2013. A portion of the sale proceeds were used to repay the $200 million unsecured term loan that had been drawn to partially finance the acquisition of Aurora and such loan was cancelled.
In the fourth quarter of 2014, we disposed of certain non-core assets in Canada with associated production of approximately 1,250 boe/d realizing net proceeds of approximately $45.7 million.
2015
On April 2, 2015, we completed a bought deal financing by issuing 36,455,000 Common Shares at a price of $17.35 per Common Share for aggregate gross proceeds of approximately $632.5 million. The net proceeds of the financing were used to reduce bank indebtedness.
2016
On March 31, 2016, we made significant amendments to our Credit Facilities. The amendments included reducing our Credit Facilities to US$575 million, granting our bank lending syndicate first priority security with respect to our assets and restructuring our financial covenants.
In July 2016, we disposed of our operated assets in Texas with associated production of approximately 1,000 boe/d realizing net proceeds of approximately $54.2 million.
On November 22, 2016, we entered into an asset acquisition agreement to acquire heavy oil assets in the Peace River Area for approximately $65 million. The lands are adjacent to our existing Peace River lands, added approximately 3,000 boe/d of production and more than doubled our land base in the area. The acquisition was financed through a concurrently announced bought deal financing, pursuant to which we issued 21,907,500 Common Shares at a price of $5.25 per Common Share for aggregate gross proceeds of approximately $115 million. The financing closed on December 12, 2016 and the asset acquisition closed on January 20, 2017.
RISK FACTORS
You should carefully consider the following risk factors, as well as the other information contained in this Annual Information Form and our other public filings before making an investment decision. If any of the risks described below materialize, our business, reputation, financial condition, results of operations and cash flow could be materially and adversely affected, which may materially affect the market price of our securities. Additional risks and uncertainties not currently known to us that we currently view as immaterial may also materially and adversely affect us. Residents of the United States and other non-residents of Canada should have additional regard to the risk factors under the heading "Certain Risks for United States and other non-resident Shareholders".

The information set forth below contains forward-looking statements, which are qualified by the information contained in the section of this Annual Information Form entitled "Special Notes to Reader - Forward-Looking Statements".

Risks Relating to Our Business and Operations

Oil and natural gas prices are volatile; a substantial decline or an extended period of the currently low prices for oil and natural gas prices will adversely affect us

Our financial condition is substantially dependent on, and highly sensitive to, the prevailing prices of crude oil and natural gas. If crude oil and natural gas prices decline or fail to increase from their current levels it could have a material adverse effect on our operations, financial condition and the value and amount of our reserves.

Prices for crude oil and natural gas fluctuate in response to changes in the supply of, and demand for, crude oil and natural gas, market uncertainty and a variety of additional factors beyond our control. Crude oil prices are primarily


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determined by international supply and demand. Factors which affect crude oil prices include the actions of OPEC, the condition of the Canadian, United States, European and Asian economies, government regulation, political stability in the Middle East and elsewhere, the foreign supply of crude oil, the price of foreign imports, the ability to secure adequate transportation for products, the availability of alternate fuel sources and weather conditions. Natural gas prices realized by us are affected primarily in North America by supply and demand, weather conditions, industrial demand, prices of alternate sources of energy and developments related to the market for liquefied natural gas. All of these factors are beyond our control and can result in a high degree of price volatility. Fluctuations in currency exchange rates further compound this volatility when commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars.

Our financial performance also depends on revenues from the sale of commodities which differ in quality and location from underlying commodity prices quoted on financial exchanges. Of particular importance are the price differentials between our light/medium oil and heavy oil (in particular the light/heavy differential) and quoted market prices. Not only are these discounts influenced by regional supply and demand factors, they are also influenced by other factors such as transportation costs, capacity and interruptions, refining demand, the availability and cost of diluents used to blend and transport product and the quality of the oil produced, all of which are beyond our control. The supply of Canadian crude oil with demand from the refinery complex and access to those markets through various transportation outlets is currently finely balanced and, therefore, very sensitive to pipeline and refinery outages, which contributes to this volatility.

Decreases to or a prolonged period of low commodity prices, particularly for oil, may negatively impact our ability to meet guidance targets, maintain our business and meet all of our financial obligations as they come due. It could also result in the shut-in of currently producing wells, a delay or cancellation of existing or future drilling, development or construction programs, unutilized long-term transportation commitments and a reduction in the value and amount of our reserves.

Our reserves as at December 31, 2016 are estimated using forecast prices and costs as set forth under "Description of Our Business and Operations - Statement of Reserves Data and Other Oil and Natural Gas Information - Pricing Assumptions". These prices are above current market prices for crude oil and natural gas. If crude oil and natural gas prices stay at current levels, our reserves may be substantially reduced as economic limits of developed reserves are reached earlier and undeveloped reserves become uneconomic at such prices. Even if some reserves remain economic at lower price levels, sustained low prices may compel us to re-evaluate our development plans and reduce or eliminate various projects with marginal economics.

We conduct assessments of the carrying value of our assets in accordance with Canadian GAAP. If crude oil and natural gas forecast prices decline further, it could result in downward revisions to the carrying value of our assets and our net earnings could be adversely affected.

Uncertainty in the capital markets may restrict the availability or increase the cost of capital or borrowing required for future development and acquisitions

The future development of our business may be dependent on our ability to obtain additional capital including, but not limited to, debt and equity financing. Unpredictable financial markets and the associated credit impacts may impede our ability to secure and maintain cost effective financing and limit our ability to achieve timely access to capital markets on acceptable terms and conditions. If external sources of capital become limited or unavailable, our ability to make capital investments, continue our business plan, meet all of our financial obligations as they come due and maintain existing properties may be impaired. Should a lack of financing and uncertainty in the capital markets adversely impact our ability to refinance debt, additional equity may be issued which could have a dilutive effect on Shareholders.

Our ability to obtain additional capital is dependent on, among other things, a general interest in energy industry investments and, in particular, interest in our securities along with our ability to maintain our credit ratings. If we are unable to maintain our indebtedness and financial ratios at levels acceptable to our credit rating agencies, or should our business prospects deteriorate, our credit ratings could be downgraded, which would adversely affect the value of our outstanding securities and existing debt and our ability to obtain new financing and may increase our borrowing costs.


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From time to time we may enter into transactions which may be financed in whole or in part with debt. The level of our indebtedness from time to time could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

Our Credit Facilities may not provide sufficient liquidity and a failure to renew our Credit Facilities could adversely affect our financial condition

Our existing Credit Facilities and any replacement credit facilities may not provide sufficient liquidity. The amounts available under our existing Credit Facilities may not be sufficient for future operations, or we may not be able to obtain additional financing on economic terms attractive to us, if at all. There can be no assurance that the amount of our Credit Facilities will be adequate for our future financial obligations, including our future capital expenditure program, or that we will be able to obtain additional funds. In the event we are unable to refinance our debt obligations, it may impact our ability to fund our ongoing operations. In the event that the Credit Facilities are not extended before June 2019, indebtedness under the Credit Facilities will be repayable at that time. There is also a risk that the Credit Facilities will not be renewed for the same amount or on the same terms. In addition, we are required to repay the Senior Notes and the 2020 Aurora Notes on maturity. See "Description of Capital Structure".

Failure to comply with the covenants in the agreements governing our debt could adversely affect our financial condition

We are required to comply with the covenants in our Credit Facilities and the Senior Notes. If we fail to comply with our debt covenants, are unable to pay the debt service charges or otherwise commit an event of default, such as bankruptcy, it could result in the seizure and/or sale of our assets by our secured creditors. The proceeds from any sale of our assets would be applied to satisfy amounts owed to the secured creditors and then unsecured creditors. Only after the proceeds of that sale were applied towards our debt would the remainder, if any, be available for the benefit of our Shareholders.

We are not the operator of our drilling locations in our Eagle Ford acreage and, therefore, we will not be able to control the timing of development, associated costs or the rate of production of that acreage

Marathon Oil EF LLC ("Marathon Oil"), a wholly-owned subsidiary of Marathon Oil Corporation (NYSE: MRO), is the operator of our Eagle Ford acreage and we will be reliant upon Marathon Oil to operate successfully. Marathon Oil will make decisions based on its own best interest and the collective best interest of all of the working interest owners of this acreage, which may not be in our best interest. We have a limited ability to exercise influence over the operational decisions of Marathon Oil, including the setting of capital expenditure budgets and determination of drilling locations and schedules. The success and timing of development activities, operated by Marathon Oil, will depend on a number of factors that will largely be outside of our control, including:
•
the timing and amount of capital expenditures;
•
Marathon Oil's expertise and financial resources;
•
approval of other participants in drilling wells;
•
selection of technology; and
•
the rate of production of reserves, if any.
To the extent that the capital expenditure requirements related to our Eagle Ford acreage exceeds our budgeted amounts, it may reduce the amount of capital we have available to invest in our other assets. We have the ability to elect whether or not to participate in well locations proposed by Marathon Oil on an individual basis. If we elect to not participate in a well location, we forgo any revenue from such well until Marathon Oil has recouped, from our working interest share of production from such well, 300% to 500% of our working interest share of the cost of such operation.



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Changes in government controls, legislation or regulations that affect the oil and gas industry, or failing to comply with such controls, legislation or regulations, could adversely affect us

The oil and gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation, and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta, Saskatchewan, the United States and Texas, all of which should be carefully considered by investors in the oil and gas industry. All such controls, regulations and legislation are subject to revocation, amendment or administrative change, some of which have historically been material and in some cases materially adverse and there can be no assurance that there will not be further revocation, amendment or administrative change which will be materially adverse to our assets, reserves, financial condition or results of operations or prospects.

At present, the newly elected President of the United States has indicated a desire to re-negotiate or withdraw from the North American Free Trade Agreement ("NAFTA") and a proposal has been made in the United States House of Representatives to re-write the United States tax code to include a 20% tax on all goods entering the United States. While these proposals may benefit the United States portion of our business, they would likely have a negative impact on the Canadian portion or our business. We can not anticipate what the overall impact might be. Due to the tightly integrated nature of the oil and gas industry in North America, the impact of these proposals, if acted upon, could be materially adverse to our business.

The oil and gas industry is also subject to regulation by governments in such matters as the awarding or acquisition of exploration and production rights, oil sands or other interests, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields (including restrictions on production) and possibly expropriation or cancellation of contract rights.

Other government controls, legislation or regulations may change from time to time in response to economic or political conditions. The exercise of discretion by governmental authorities under existing controls, legislation or regulations, the implementation of new controls, legislation or regulations or the modification of existing controls, legislation or regulations affecting the oil and gas industry could reduce demand for crude oil and natural gas, increase our costs, or delay or restrict our operations, all of which would have a material adverse effect on us. In addition, failure to comply with government controls, legislation or regulations may result in the suspension, curtailment or termination of operations and subject us to liabilities and administrative, civil and criminal penalties. Compliance costs can be significant. See "Industry Conditions".

The oil and gas industry is highly regulated and changes in environmental, health and safety controls, legislation or regulations may impose restrictions, costs or other liabilities which may have an adverse affect on our business

All phases of our operations are subject to environmental, health and safety regulation pursuant to a variety of Canadian, U.S. and other federal, provincial, state and municipal laws and regulations (collectively, "environmental regulations") governing occupational health and safety aspects of our operations, the spill, release or emission of materials into the environment or otherwise relating to environmental protection. Environmental regulations require that wells, facility sites and other properties associated with our operations be constructed, operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications. Environmental regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment. It also imposes restrictions, liabilities and obligations in connection with the management of fresh or potable water sources that are being used, or whose use is contemplated, in connection with oil and gas operations. The provinces of Alberta and Saskatchewan have developed liability management programs designed to prevent taxpayers from incurring costs associated with suspension, abandonment, remediation and reclamation of wells, facilities and pipelines in the event that a licensee or permit holder becomes defunct. These programs generally involve an assessment of the ratio of a licensee's deemed assets to deemed liabilities. If a licensee's deemed liabilities exceed its deemed assets, a security deposit is required. Changes in the ratio of our deemed assets to deemed liabilities or


14

changes to the requirements of liability management programs may result in significant increases to the security that must be posted.

Compliance with environmental regulations can require significant expenditures, including expenditures for clean-up costs and damages arising out of contaminated properties. Failure to comply with environmental regulations may result in the imposition of administrative, civil and criminal penalties or issuance of clean up orders in respect of us or our properties, some of which may be material. We may also be exposed to civil liability for environmental matters or for the conduct of third parties, including private parties commencing actions and new theories of liability, regardless of negligence or fault. Although it is not expected that the costs of complying with environmental regulations will have a material adverse effect on our financial condition or results of operations, no assurance can be made that the costs of complying with environmental regulations in the future will not have such an effect. The implementation of new environmental regulations or the modification of existing environmental regulations affecting the oil and gas industry generally could reduce demand for crude oil and natural gas, resulting in stricter standards and enforcement, larger penalties and liability and increased capital expenditures and operating costs, which could have a material adverse effect on our financial condition or results of operations and prospects. See "Industry Conditions - Environmental and Occupational Safety and Health Regulation".

In addition to regulatory requirements pertaining to the production, marketing and sale of oil and natural gas mentioned above, our business and financial condition could be influenced by federal legislation affecting, in particular, foreign investment, through legislation such as the Competition Act (Canada) and the Investment Canada Act (Canada).

Climate change initiatives may impose restrictions or costs on our business which have a material adverse affect on our business

Our exploration and production facilities and other operational activities emit greenhouse gases ("GHG"). As such, it is highly likely that any GHG emissions regulation enacted in jurisdictions where we operate will impact us.
Negative consequences which could result from new GHG emissions regulation include, but are not limited to: increased operating costs; increased construction and development costs; additional monitoring and compliance costs; a requirement to redesign or retrofit current facilities; permitting delays; additional costs associated with the purchase of emission credits or allowances; and reduced demand for crude oil. Additionally, if GHG emissions regulation differs by region or type of production, all or part of our production could be subject to costs which are disproportionately higher than those of other producers.

The direct or indirect costs of compliance with GHG emissions regulation may have a material adverse affect on our business, financial condition, results of operations and prospects. At this time, it is not possible to predict whether compliance costs will have a material adverse affect on our business.
Although we provide for the necessary amounts in our annual capital budget to fund our currently estimated obligations, there can be no assurance that we will be able to satisfy our actual future obligations associated with GHG emissions from such funds. For more information on the evolution and status of climate change and related environmental legislation, see "Industry Conditions - Climate Change Regulation".

Variations in interest rates and foreign exchange rates could adversely affect our financial condition

There is a risk that the interest rates will increase given the current historical low level of interest rates. An increase in interest rates could result in a significant increase in the amount we pay to service debt and could have an adverse effect on our financial condition, results of operations and future growth, potentially resulting in a decrease to the market price of our Common Shares.

World oil prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the Canada/U.S. foreign exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar may negatively impact our revenues. A substantial portion of our operations and production are in the United States and, as such, we are exposed to foreign currency risk on both revenues and costs to the extent the value of the


15

Canadian dollar decreases relative to the U.S. dollar. In addition, we are exposed to foreign currency risk as our Credit Facility and a large portion of our Senior Notes are denominated in U.S. dollars and the interest payable thereon is payable in U.S. dollars. Future Canada/U.S. foreign exchange rates could also impact the future value of our reserves as determined by our independent evaluator.

A decline in the value of the Canadian dollar relative to the United States dollar provides a competitive advantage to United States companies acquiring Canadian oil and gas properties and may make it more difficult for us to replace reserves through acquisitions.

Our hedging activities may negatively impact our income and our financial condition

In response to fluctuations in commodity prices, foreign exchange and interest rates, we may utilize various derivative financial instruments and physical sales contracts to manage our exposure under a hedging program. We also use derivative instruments in various operational markets to optimize our supply or production chain. The terms of these arrangements may limit the benefit to us of favourable changes in these factors, including receiving less than the market price for our production, and may also result in royalties being paid on a reference price which is higher than the hedged price. We may also suffer financial loss due to hedging arrangements if we are unable to produce oil or natural gas to fulfill our delivery obligations. There is also increased exposure to counterparty credit risk. To the extent that our current hedging agreements are beneficial to us, these benefits will only be realized for the period and for the commodity quantities in those contracts. In addition, there is no certainty that we will be able to obtain additional hedges at prices that have an equivalent benefit to us, which will adversely impact our revenues. For more information in relation to our commodity hedging program, see "Description of Our Business and Operations - Statement of Reserves Data and Other Oil and Natural Gas Information - Other Oil and Gas Information - Forward Contracts".

Our financial performance is significantly affected by the cost of developing and operating our assets

Our development and operating costs are affected by a number of factors including, but not limited to: inflationary price pressure; scheduling delays; failure to maintain quality construction standards; and supply chain disruptions, including access to skilled labour. Natural gas, electricity, water, diluent, chemicals, supplies, reclamation, abandonment and labour costs are examples of operating and other costs that are susceptible to significant fluctuation.

The amount of oil and natural gas that we can produce and sell is subject to the availability and cost of gathering, processing and pipeline systems

We deliver our products through gathering, processing and pipeline systems which we do not own and purchasers of our products rely on third party infrastructure to deliver our products to market. The lack of access to capacity in any of the gathering, processing and pipeline systems could result in our inability to realize the full economic potential of our production or in a reduction of the price offered for our production. Alternately, a substantial decrease in the use of such systems can increase the cost we incur to use them. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could harm our business and, in turn, our financial condition.

Access to the pipeline capacity for the transport of crude oil into the United States has become inadequate for the amount of Canadian production being exported to the United States and has resulted in significantly lower prices being realized by Canadian producers compared with the WTI price for crude oil. Although pipeline expansions are ongoing, the lack of pipeline capacity continues to affect the oil and natural gas industry in Canada and limit the ability to produce and to market oil and natural gas production. In addition, the pro-rationing of capacity on inter-provincial pipeline systems also continues to affect the ability to export oil and natural gas from Canada. There can be no certainty that investment in pipelines which would result in additional long-term take-away capacity will be made by applicable third party pipeline providers or that any requisite applications will receive regulatory approval. There is also no certainty that short-term operational constraints on pipeline systems, arising from pipeline interruption and/or increased supply of crude oil, will not occur.



16

There is also no certainty that crude-by-rail transportation and other alternative types of transportation for our production will be sufficient to address any gaps caused by operational constraints on pipeline systems. In addition, our crude-by-rail shipments may be impacted by service delays, inclement weather or derailment and could adversely impact our crude oil sales volumes or the price received for our product. Crude oil produced and sold by us may be involved in a derailment or incident that results in legal liability or reputational harm.

A portion of our production may, from time to time, be processed through facilities owned by third parties and which we do not have control of. From time to time these facilities may discontinue or decrease operations either as a result of normal servicing requirements or as a result of unexpected events. A discontinuance or decrease of operations could materially adversely affect our ability to process our production and to deliver the same for sale.

Our oil and natural gas reserves are a depleting resource and decline as such reserves are produced

Our future oil and natural gas reserves and production, and therefore our funds from operations, will be highly dependent on our success in exploiting our reserves base and acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive. If external sources of capital become limited or unavailable on commercially reasonable terms, our ability to make the necessary capital investments to maintain or expand our oil and natural gas reserves may be impaired.

There is no assurance we will be successful in developing additional reserves or acquiring additional reserves at acceptable costs. Without these reserves additions, our reserves will deplete and as a consequence production from and the average reserves life of our properties will decline, which may result in a reduction in the value of our Common Shares.

Our ability to add to our oil and natural gas reserves is highly dependent on our success in exploiting existing properties and acquiring additional reserves

Our long-term commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves. Future oil and natural gas exploration may involve unprofitable efforts, not only from unsuccessful wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit. Completion of a well does not assure a profit on the investment. Drilling hazards or environmental liabilities or damages could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays or failure in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees. New wells we drill or participate in may not become productive and we may not recover all or any portion of our investment in wells we drill or participate in.

Income tax laws or other laws or government incentive programs or regulations relating to our industry may in the future be changed or interpreted in a manner that adversely affects us and our Shareholders

We file all required income tax returns and believe that we are in full compliance with the applicable tax legislation. However, such returns are subject to audit and reassessment by the applicable taxation authority. Any such reassessment may have an impact on current and future taxes payable. At present, the Canadian tax authorities have reassessed the returns of certain of our subsidiaries. For further details see "Legal Proceedings and Regulatory Actions".

Income tax laws, other laws or government incentive programs relating to the oil and gas industry may in the future be changed or interpreted in a manner that adversely affects us and our Shareholders. Tax authorities having jurisdiction over us or our Shareholders may disagree with the manner in which we calculate our income for tax purposes or could change their administrative practices to our detriment or the detriment of our Shareholders.



17

Income tax laws and government incentive programs relating to the oil and gas industry may change in a manner that adversely affects the market price of the Common Shares.

There are numerous uncertainties inherent in estimating quantities of recoverable oil and natural gas reserves and contingent resources, including many factors beyond our control

The reserves estimates included in this Annual Information Form are estimates only. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. In general, estimates of economically recoverable oil and natural gas reserves and the future net revenues therefrom are based upon a number of factors and assumptions made as of the date on which the reserves estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of regulation by governmental agencies, historical production from the properties, initial production rates, production decline rates, the availability, proximity and capacity of oil and gas gathering systems, pipelines and processing facilities and estimates of future commodity prices and capital costs, all of which may vary considerably from actual results.

All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Our actual production, revenues, royalties, taxes and development, abandonment and operating expenditures with respect to our reserves will likely vary from such estimates, and such variances could be material.

Estimates of reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations in the previously estimated reserves and such variances could be material.

The contingent resources estimates included as Appendix A to this Annual Information Form are estimates only. The same uncertainties inherent in estimating quantities of reserves apply to estimating quantities of contingent resources. In addition, there are contingencies that prevent contingent resources from being classified as reserves. There is no certainty that it will be commercially viable to produce any portion of the contingent resources. Actual results may vary significantly from these estimates and such variances could be material.

Acquiring, developing and exploring for oil and natural gas involves many hazards. We have not insured and cannot fully insure against all risks related to our operations

Our crude oil and natural gas operations are subject to all of the risks normally incidental to the: (i) storing, transporting, processing, refining and marketing of crude oil, natural gas and other related products; (ii) drilling and completion of crude oil and natural gas wells; and (iii) operation and development of crude oil and natural gas properties, including, but not limited to: encountering unexpected formations or pressures; premature declines of reservoir pressure or productivity; blowouts; fires; explosions; equipment failures and other accidents; gaseous leaks; uncontrollable or unauthorized flows of crude oil, natural gas or well fluids; migration of harmful substances; oil spills; corrosion; adverse weather conditions; pollution; acts of vandalism and terrorism; and other adverse risks to the environment.

Although we maintain insurance in accordance with customary industry practice, we are not fully insured against all of these risks nor are all such risks insurable and in certain circumstances we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. In addition, the nature of these risks is such that liabilities could exceed policy limits, in which event we could incur significant costs that could have a material adverse effect on our business, financial condition, results of operations and prospects.



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We are subject to risk of default by the counterparties to our contracts and our counterparties may deem us to be a default risk

We are subject to the risk that counterparties to our risk management contracts, marketing arrangements and operating agreements and other suppliers of products and services may default on their obligations under such agreements or arrangements, including as a result of liquidity requirements or insolvency. Furthermore, low oil and natural gas prices increase the risk of bad debts related to our joint venture and industry partners. A failure by such counterparties to make payments or perform their operational or other obligations to us may adversely affect our results of operations, cash flows and financial position. Conversely, our counterparties may deem us to be at risk of defaulting on our contractual obligations. These counterparties may require that we provide additional credit assurances by prepaying anticipated expenses or posting letters of credit, which would decrease our available liquidity.

We are subject to a number of additional business risks which could adversely affect our income and financial condition

Our business involves many operating risks related to acquiring, developing and exploring for oil and natural gas which even a combination of experience, knowledge and careful evaluation may not be able to overcome. Our operational risks include, but are not limited to: operational and safety considerations; pipeline transportation and interruptions; reservoir performance and technical challenges; partner risks; competition; technology; land claims; our ability to hire and retain necessary skilled personnel; the availability of drilling and related equipment; information systems; seasonality and access restrictions; timing and success of integrating the business and operations of acquired assets and companies; phased growth execution; risk of litigation, regulatory issues, increases in government taxes and changes to royalty or mineral/severance tax regimes; and risk to our reputation resulting from operational activities that may cause personal injury, property damage or environmental damage.

We may participate in larger projects and may have more concentrated risk in certain areas of our operations

We have a variety of exploration, development and construction projects underway at any given time. Project delays may result in delayed revenue receipts and cost overruns may result in projects being uneconomic. Our ability to complete projects is dependent on general business and market conditions as well as other factors beyond our control, including the availability of skilled labour and manpower, the availability and proximity of pipeline capacity and rail terminals, weather, environmental and regulatory matters, ability to access lands, availability of drilling and other equipment and supplies, and availability of processing capacity.

Our thermal heavy oil projects face additional risks compared to conventional oil and gas production

Our thermal heavy oil projects are capital intensive projects which rely on specialized production technologies. Certain current technologies for the recovery of heavy oil, such as CSS and SAGD, are energy intensive, requiring significant consumption of natural gas and other fuels in the production of steam that is used in the recovery process. The amount of steam required in the production process varies and therefore impacts costs. The performance of the reservoir can also affect the timing and levels of production using new technologies. A large increase in recovery costs could cause certain projects that rely on CSS, SAGD or other new technologies to become uneconomic, which could have an adverse effect on our financial condition. There are risks associated with growth and other capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations. The success of projects incorporating new technologies cannot be assured.

Project economics and our overall earnings may be reduced if increases in operating costs are incurred. Factors which could affect operating costs include, without limitation: labour costs; the cost of catalysts and chemicals; the cost of natural gas and electricity; power outages; produced sand causing issues of erosion, hot spots and corrosion; reliability of facilities; maintenance costs; the cost to transport sales products; and the cost to dispose of certain by-products.



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Our information technology systems are subject to certain risks

We utilize a number of information technology systems for the administration and management of our business. If our ability to access and use these systems is interrupted and cannot be quickly and easily restored then such event could have a material adverse effect on us. Furthermore, although our information technology systems are considered to be secure, if an unauthorized third party is able to access the systems then such unauthorized access may compromise our business in a materially adverse manner.

Risks Relating to Ownership of our Securities

Changes in market-based factors may adversely affect the trading price of the Common Shares

The market price of our Common Shares is sensitive to a variety of market-based factors including, but not limited to, commodity prices, interest rates, foreign exchange rates and the comparability of the Common Shares to other securities. Any changes in these market-based factors may adversely affect the trading price of the Common Shares.

Certain Risks for United States and other non-resident Shareholders

The ability of investors resident in the United States to enforce civil remedies is limited

We are a corporation incorporated under the laws of the Province of Alberta, Canada, our principal office is located in Calgary, Alberta and a substantial portion of our assets are located outside the United States. Most of our directors and officers and the representatives of the experts who provide services to us (such as our auditors and our independent qualified reserves evaluators), and all or a substantial portion of their 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 such directors, officers and representatives of experts who are not residents of the United States or to enforce against them judgments of the 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. There is doubt as to the enforceability in Canada against us or any of our directors, officers or representatives of experts who are not residents of the United States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the United States federal securities laws or securities laws of any state within the United States.

Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States

We report our production and reserves quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.

We incorporate additional information with respect to production and reserves which is either not required to be included or prohibited under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes (before deduction of Crown and other royalties); however, we also follow the United States practice of separately reporting reserves volumes on a net basis (after the deduction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves, whereas the SEC rules require that a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, be utilized.

We have included in this Annual Information Form estimates of proved, proved plus probable reserves and proved plus probable plus possible reserves. Probable reserves have a lower certainty of recovery than proved reserves and possible reserves have a lower certainty of recovery than probable reserves. The SEC requires oil and gas issuers in their filings with the SEC to disclose only proved reserves but permits the optional disclosure of probable reserves and possible reserves. The SEC definitions of proved reserves, probable reserves and possible reserves are different than NI 51-101;


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therefore, proved, probable, proved plus probable and proved plus probable plus possible reserves disclosed in this Annual Information Form may not be comparable to United States standards.

As a consequence of the foregoing, our reserves estimates and production volumes in this Annual Information Form may not be comparable to those made by companies utilizing United States reporting and disclosure standards.

We also included estimates of contingent resources as Appendix A to this Annual Information Form. Contingent resources represent the quantity of oil and natural gas estimated to be potentially recoverable from known accumulations using established technology or technology under development, but which do not currently qualify as reserves or commercially recoverable due to one or more contingencies. The SEC does not permit the inclusion of estimates of resources in reports filed with it by United States companies.

There is additional taxation applicable to non-residents

Tax legislation in Canada may impose withholding or other taxes on the cash dividends, stock dividends or other property transferred by us to non-resident shareholders. These taxes may be reduced pursuant to tax treaties between Canada and the non-resident shareholder's jurisdiction of residence. Evidence of eligibility for a reduced withholding rate must be filed by the non-resident shareholder in prescribed form with their broker (or in the case of registered shareholders, with the transfer agent). In addition, the country in which the non-resident shareholder is resident may impose additional taxes on such dividends. Any of these taxes may change from time to time.

There is a foreign exchange risk for non-resident Shareholders

Any dividends will be declared in Canadian dollars and converted to foreign denominated currencies at the spot exchange rate at the time of payment. As a consequence, investors may be subject to foreign exchange risk. To the extent that the Canadian dollar strengthens with respect to their currency, the amount of any dividend will be reduced when converted to their home currency.

DESCRIPTION OF OUR BUSINESS AND OPERATIONS
Overview
We are engaged in the business of acquiring, developing, exploiting and holding interests in petroleum and natural gas properties and related assets in Canada (in Alberta and Saskatchewan) and in the United States (in Texas).
Baytex Energy Ltd.
Baytex Energy is a corporation amalgamated under the ABCA and is actively engaged in the business of oil and natural gas exploration, exploitation, development, acquisition and production in Canada. Baytex Energy acts as the managing partner of Baytex Partnership. Baytex Energy is a wholly-owned subsidiary of Baytex.
Baytex Energy Partnership
Baytex Partnership is a general partnership governed by the laws of the Province of Alberta. As at the date of this Annual Information Form, the partners of Baytex Partnership are Baytex Energy and Baytex Holdings Limited Partnership. Baytex Partnership holds the material operating assets in Canada from which we generate cash flow.
Baytex Energy USA, Inc.
Baytex USA is a corporation incorporated under the laws of the State of Delaware and is actively engaged in the business of oil and natural gas exploration, exploitation, development, acquisition and production in the United States. Baytex USA holds all of the operating assets in the United States from which we generate cash flow. Baytex USA is an indirect, wholly-owned subsidiary of Baytex.


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Personnel
As at December 31, 2016, we had 147 employees in our Calgary head office, 22 employees in our Houston office and 83 employees in our field operations.
STATEMENT OF RESERVES DATA
The Baytex Reserves Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserves definitions contained in NI 51‑101. The statement of reserves data and other oil and natural gas information set forth below is dated February 23, 2017, with an effective date of December 31, 2016. The preparation date of the statement is January 30, 2017, in the case of Sproule, and February 1, 2017, in the case of Ryder Scott. Sproule prepared the Baytex Reserves Report by consolidating the Canadian properties evaluated by Sproule with the United States properties evaluated by Ryder Scott, in each case using Sproule's December 31, 2016 forecast price and cost assumptions.
Disclosure of Reserves Data
The tables below are a combined summary as at December 31, 2016 of our proved, probable and possible heavy oil, bitumen, light and medium oil, tight oil, NGL, conventional natural gas and shale gas reserves and the net present value of future net revenue attributable to such reserves evaluated in the Baytex Reserves Report. Our reserves are located in Canada (in Alberta and Saskatchewan) and the United States (in Texas).
All evaluations of future net revenue are after the deduction of future income tax expenses (unless otherwise noted in the tables), royalties, development costs, production costs and well abandonment costs but before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future net revenue contained in the following tables does not necessarily represent the fair market value of our reserves. There is no assurance that the forecast price and cost assumptions contained in the Baytex Reserves Report will be attained and variations could be material. The tables summarize the data contained in the Baytex Reserve Report and, as a result, may contain slightly different numbers and columns in the tables may not add due to rounding. Other assumptions and qualifications relating to costs and other matters are summarized in the notes to or following the tables below.

The recovery and reserves estimates described herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Readers should review the definitions and information contained in "Selected Terms - Reserves Definitions", "- Reserves and Reserve Categories" and "- Development and Production Status" in conjunction with the following tables and notes. For more information as to the risks involved, see "Risk Factors".
SUMMARY OF OIL AND NATURAL GAS RESERVES
AS OF DECEMBER 31, 2016
FORECAST PRICES AND COSTS
CANADA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIGHT AND MEDIUM OIL
 
HEAVY OIL
 
BITUMEN
RESERVES CATEGORY
 
Gross
(Mbbl)
 
Net
(Mbbl)
 
Gross
(Mbbl)
 
Net
(Mbbl)
 
Gross
(Mbbl)
 
Net
(Mbbl)
PROVED:
 
 
 
 
 
 
 
 
 
 
 
 
   Developed Producing
 
1,985

 
1,858

 
25,923

 
19,717

 
382

 
347

   Developed Non‑Producing
 
—

 
—

 
2,609

 
2,223

 
7,655

 
7,072

   Undeveloped
 
308

 
316

 
18,343

 
16,172

 
5,428

 
4,357

TOTAL PROVED
 
2,293

 
2,174

 
46,875

 
38,112

 
13,465

 
11,776

PROBABLE
 
1,794

 
1,598

 
29,325

 
23,955

 
55,835

 
44,311

TOTAL PROVED PLUS PROBABLE
 
4,087

 
3,773

 
76,199

 
62,068

 
69,300

 
56,086



22

 
 
 
 
 
 
 
 
 
 
 
 
 
CANADA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CONVENTIONAL NATURAL GAS (1)
 
NATURAL GAS LIQUIDS (2)
 
TOTAL RESERVES
RESERVES CATEGORY
 
Gross
(MMcf)
 
Net(MMcf)
 
Gross
(Mbbl)
 
Net
(Mbbl)
 
Gross
(Mboe)
 
Net
(Mboe)
PROVED:
 
 
 
 
 
 
 
 
 
 
 
 
   Developed Producing
 
49,201

 
43,294

 
1,246

 
925

 
37,735

 
30,063

   Developed Non‑Producing
 
22

 
35

 
—

 
1

 
10,267

 
9,302

   Undeveloped
 
66,711

 
60,907

 
1,345

 
1,114

 
36,542

 
32,110

TOTAL PROVED
 
115,933

 
104,236

 
2,590

 
2,039

 
84,544

 
71,475

PROBABLE
 
89,206

 
76,579

 
3,198

 
2,479

 
105,019

 
85,106

TOTAL PROVED PLUS PROBABLE
 
205,139

 
180,816

 
5,788

 
4,518

 
189,564

 
156,581

 
 
 
 
 
 
 
 
 
 
 
 
 
UNITED STATES
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TIGHT OIL
 
SHALE GAS
 
CONVENTIONAL NATURAL GAS (1)
RESERVES CATEGORY
 
Gross
(Mbbl)
 
Net
(Mbbl)
 
Gross
(MMcf)
 
Net
(MMcf)
 
Gross
(MMcf)
 
Net
(MMcf)
PROVED:
 
 
 
 
 
 
 
 
 
 
 
 
   Developed Producing
 
19,242

 
14,101

 
60,929

 
45,025

 
27,530

 
20,206

   Developed Non‑Producing
 
—

 
—

 
—

 
—

 
—

 
—

   Undeveloped
 
30,472

 
22,344

 
112,899

 
83,277

 
28,553

 
20,950

TOTAL PROVED
 
49,714

 
36,444

 
173,828

 
128,302

 
56,083

 
41,156

PROBABLE
 
8,399

 
6,161

 
59,075

 
43,371

 
8,906

 
6,543

TOTAL PROVED PLUS PROBABLE
 
58,113

 
42,605

 
232,903

 
171,674

 
64,988

 
47,699

POSSIBLE (3)
 
19,269

 
14,160

 
81,346

 
59,866

 
18,327

 
13,477

TOTAL PROVED PLUS PROBABLE
    PLUS POSSIBLE (3)
 
77,381

 
56,765

 
314,249

 
231,540

 
83,315

 
61,176

 
 
 
 
 
 
 
 
 
 
 
 
 
UNITED STATES
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NATURAL GAS LIQUIDS (2)
 
TOTAL RESERVES
 
 
 
 
RESERVES CATEGORY
 
Gross
(Mbbl)
 
Net
(Mbbl)
 
Gross
(Mboe)
 
Net
(Mboe)
 
 
 
 
PROVED:
 
 
 
 
 
 
 
 
 
 
 
 
   Developed Producing
 
26,907

 
19,861

 
60,892


44,833

 
 
 
 
   Developed Non‑Producing
 
—

 
—

 
—


—

 
 
 
 
   Undeveloped
 
53,194

 
39,199

 
107,242


78,914

 
 
 
 
TOTAL PROVED
 
80,102

 
59,059

 
168,134


123,747

 
 
 
 
PROBABLE
 
28,627

 
21,025

 
48,355


35,505

 
 
 
 
TOTAL PROVED PLUS PROBABLE
 
108,728

 
80,084

 
216,490


159,252

 


 


POSSIBLE (3)
 
37,430

 
27,545

 
73,310

 
53,928

 
 
 
 
TOTAL PROVED PLUS PROBABLE
    PLUS POSSIBLE (3)
 
146,158

 
107,629

 
289,800

 
213,180

 
 
 
 








23

TOTAL
 
 
 
 
TIGHT OIL
 
LIGHT AND MEDIUM OIL
 
HEAVY OIL
RESERVES CATEGORY
 
Gross
(Mbbl)
 
Net
(Mbbl)
 
Gross
(Mbbl)
 
Net
(Mbbl)
 
Gross
(Mbbl)
 
Net
(Mbbl)
PROVED:
 
 
 
 
 
 
 
 
 
 
 
 
   Developed Producing
 
19,242

 
14,101

 
1,985

 
1,858

 
25,923

 
19,717

   Developed Non‑Producing
 
—

 
—

 
—

 
—

 
2,609

 
2,223

   Undeveloped
 
30,472

 
22,344

 
308

 
316

 
18,343

 
16,172

TOTAL PROVED
 
49,714

 
36,444

 
2,293

 
2,174

 
46,875

 
38,112

PROBABLE
 
8,399

 
6,161

 
1,794

 
1,598

 
29,325

 
23,955

TOTAL PROVED PLUS PROBABLE
 
58,113

 
42,605

 
4,087

 
3,773

 
76,199

 
62,068

POSSIBLE (3)(4)
 
19,269

 
14,160

 
—

 
—

 
—

 
—

TOTAL PROVED PLUS PROBABLE
    PLUS POSSIBLE (3)(4)
 
77,381

 
56,765

 
4,087

 
3,773

 
76,199

 
62,068

 
 
 
TOTAL
 
 
 
 
BITUMEN
 
SHALE GAS
 
CONVENTIONAL NATURAL GAS (1)
RESERVES CATEGORY
 
Gross
(Mbbl)
 
Net
(Mbbl)
 
Gross
(MMcf)
 
Net
(MMcf)
 
Gross
(MMcf)
 
Net
(MMcf)
PROVED:
 
 
 
 
 
 
 
 
 
 
 
 
   Developed Producing
 
382

 
347

 
60,929

 
45,025

 
76,731

 
63,501

   Developed Non‑Producing
 
7,655

 
7,072

 
—

 
—

 
21

 
35

   Undeveloped
 
5,428

 
4,357

 
112,899

 
83,277

 
95,264

 
81,857

TOTAL PROVED
 
13,465

 
11,776

 
173,828

 
128,302

 
172,016

 
145,393

PROBABLE
 
55,835

 
44,311

 
59,075

 
43,371

 
98,112

 
83,123

TOTAL PROVED PLUS PROBABLE
 
69,300

 
56,086

 
232,903

 
171,674

 
270,127

 
228,515

POSSIBLE (3)(4)
 
—

 
—

 
81,346

 
59,866

 
18,327

 
13,477

TOTAL PROVED PLUS PROBABLE
    PLUS POSSIBLE (3)(4)
 
69,300

 
56,086

 
314,249

 
231,540

 
288,455

 
241,992

 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NATURAL GAS LIQUIDS (2)
 
TOTAL RESERVES
 
 
RESERVES CATEGORY
 
Gross
(Mbbl)
 
Net
(Mbbl)
 
Gross
(Mboe)
 
Net
(Mboe)
 
 
 
 
PROVED:
 
 
 
 
 
 
 
 
 
 
 
 
   Developed Producing
 
28,153

 
20,786

 
98,627

 
74,896

 


 


   Developed Non‑Producing
 
—

 
1

 
10,267

 
9,303

 


 


   Undeveloped
 
54,539

 
40,312

 
143,784

 
111,024

 


 


TOTAL PROVED
 
82,692

 
61,099

 
252,678

 
195,223

 


 


PROBABLE
 
31,825

 
23,504

 
153,375

 
120,611

 


 


TOTAL PROVED PLUS PROBABLE
 
114,516

 
84,602

 
406,053

 
315,833

 


 


POSSIBLE (3)(4)
 
37,430

 
27,544

 
73,310

 
53,928

 

 

TOTAL PROVED PLUS PROBABLE
    PLUS POSSIBLE (3)(4)
 
151,946

 
112,147

 
479,364

 
369,761

 


 


 
 
 
 
 
 
 
 
 
 
 
 
Notes:
(1)
Conventional natural gas includes associated, non-associated and solution gas.
(2)
Natural gas liquids includes condensate.
(3)
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.
(4)
The total possible reserves include only possible reserves from the Eagle Ford properties. The possible reserves associated with the Canadian properties have not been evaluated.



24

SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF DECEMBER 31, 2016
FORECAST PRICES AND COSTS
 
 
CANADA
 

BEFORE INCOME TAXES DISCOUNTED AT (%/year)
 
UNIT VALUE BEFORE TAX
RESERVES CATEGORY
 
0%
($000s)

 
5%
($000s)

 
10%
($000s)

 
15%
($000s)

 
20%
($000s)

 
10%
$/boe

PROVED:
 
 
 
 
 
 
 
 
 
 
 
 
   Developed Producing
 
523,531

 
467,725

 
420,445

 
381,377

 
349,129

 
13.99

   Developed Non‑Producing
 
243,337

 
168,403

 
121,209

 
90,363

 
69,485

 
13.03

   Undeveloped
 
534,063

 
386,333

 
283,491

 
210,063

 
156,424

 
8.83

   TOTAL PROVED
 
1,300,931

 
1,022,460

 
825,145

 
681,804

 
575,038

 
11.54

PROBABLE
 
2,182,301

 
1,195,885

 
723,254

 
467,328

 
314,943

 
8.50

TOTAL PROVED PLUS PROBABLE
 
3,483,233

 
2,218,345

 
1,548,399

 
1,149,132

 
889,981

 
9.89

 
 
 
 
 
 
 
 
 
 
 
 
 
UNITED STATES
 

BEFORE INCOME TAXES DISCOUNTED AT (%/year)
 
UNIT VALUE BEFORE TAX
RESERVES CATEGORY
 
0%
($000s)

 
5%
($000s)

 
10%
($000s)

 
15%
($000s)

 
20%
($000s)

 
10%
$/boe

PROVED:
 
 
 
 
 
 
 
 
 
 
 
 
   Developed Producing
 
1,674,035

 
1,286,547

 
1,047,642

 
888,644

 
776,258

 
23.37

   Developed Non‑Producing
 
—

 
—

 
—

 
—

 
—

 
—

   Undeveloped
 
2,328,597

 
1,416,589

 
914,698

 
615,838

 
426,453

 
11.59

   TOTAL PROVED
 
4,002,633

 
2,703,136

 
1,962,340

 
1,504,482

 
1,202,712

 
15.86

PROBABLE
 
1,053,807

 
604,633

 
376,915

 
249,067

 
171,338

 
10.62

TOTAL PROVED PLUS PROBABLE
 
5,056,440

 
3,307,769

 
2,339,255

 
1,753,549

 
1,374,049

 
14.69

POSSIBLE (1)
 
2,370,364

 
1,417,370

 
938,108

 
668,947

 
504,293

 
17.40

TOTAL PROVED PLUS PROBABLE PLUS POSSIBLE (1)
 
7,426,804

 
4,725,138

 
3,277,363

 
2,422,496

 
1,878,343

 
15.37

 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL
 

BEFORE INCOME TAXES DISCOUNTED AT (%/year)
 
UNIT VALUE BEFORE TAX
RESERVES CATEGORY
 
0%
($000s)

 
5%
($000s)

 
10%
($000s)

 
15%
($000s)

 
20%
($000s)

 
10%
$/boe

PROVED:
 
 
 
 
 
 
 
 
 
 
 
 
   Developed Producing
 
2,197,567


1,754,271


1,468,087


1,270,022


1,125,387

 
19.60

   Developed Non‑Producing
 
243,337


168,403


121,209


90,363


69,485

 
13.03

   Undeveloped
 
2,862,660


1,802,922


1,198,190


825,901


582,878

 
10.79

   TOTAL PROVED
 
5,303,564


3,725,596


2,787,485


2,186,286


1,777,750

 
14.28

PROBABLE
 
3,236,109


1,800,518


1,100,168


716,395


486,281

 
9.12

TOTAL PROVED PLUS PROBABLE
 
8,539,673


5,526,114


3,887,653


2,902,681


2,264,031

 
12.31

POSSIBLE (1)(2)
 
2,370,364


1,417,370


938,108


668,947


504,293

 
17.40

TOTAL PROVED PLUS PROBABLE PLUS POSSIBLE (1)(2)
 
10,910,037


6,943,484


4,825,762


3,571,628


2,768,324

 
13.05

Notes:
(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.
(2)
The total possible reserves include only possible reserves from the Eagle Ford properties. The possible reserves associated with the Canadian properties have not been evaluated.




25

SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF DECEMBER 31, 2016
FORECAST PRICES AND COSTS
CANADA
 

AFTER INCOME TAXES DISCOUNTED AT (%/year)(1)
RESERVES CATEGORY
 
0%
($000s)

 
5%
($000s)

 
10%
($000s)

 
15%
($000s)

 
20%
($000s)

PROVED:
 
 
 
 
 
 
 
 
 
 
   Developed Producing
 
523,531

 
467,725

 
420,445

 
381,377

 
349,129

   Developed Non‑Producing
 
243,337

 
168,403

 
121,209

 
90,363

 
69,485

   Undeveloped
 
412,218

 
297,083

 
216,492

 
158,688

 
116,297

   TOTAL PROVED
 
1,179,087

 
933,210

 
758,145

 
630,429

 
534,910

PROBABLE
 
1,604,045

 
858,335

 
502,476

 
311,126

 
198,261

   TOTAL PROVED PLUS PROBABLE
 
2,783,132

 
1,791,545

 
1,260,621

 
941,555

 
733,171

 
 
 
 
 
 
 
 
 
 
 
UNITED STATES
 

AFTER INCOME TAXES DISCOUNTED AT (%/year)(1)
RESERVES CATEGORY
 
0%
($000s)

 
5%
($000s)

 
10%
($000s)

 
15%
($000s)

 
20%
($000s)

PROVED:
 
 
 
 
 
 
 
 
 
 
   Developed Producing
 
1,589,270

 
1,236,432

 
1,016,310

 
868,054

 
762,105

   Developed Non‑Producing
 
—

 
—

 
—

 
—

 
—

   Undeveloped
 
1,604,389

 
986,329

 
641,333

 
432,827

 
298,765

   TOTAL PROVED
 
3,193,659

 
2,222,760

 
1,657,644

 
1,300,882

 
1,060,870

PROBABLE
 
679,043

 
387,921

 
241,254

 
158,997

 
108,813

   TOTAL PROVED PLUS PROBABLE
 
3,872,702

 
2,610,681

 
1,898,897

 
1,459,878

 
1,169,682

POSSIBLE (2)
 
1,528,085

 
922,585

 
621,008

 
452,503

 
349,451

TOTAL PROVED PLUS PROBABLE PLUS POSSIBLE (2)
 
5,400,787

 
3,533,266

 
2,519,905

 
1,912,382

 
1,519,133

 
 
 
 
 
 
 
 
 
 
 
TOTAL
 

AFTER INCOME TAXES DISCOUNTED AT (%/year)(1)
RESERVES CATEGORY
 
0%
($000s)

 
5%
($000s)

 
10%
($000s)

 
15%
($000s)

 
20%
($000s)

PROVED:
 
 
 
 
 
 
 
 
 
 
   Developed Producing
 
2,112,801

 
1,704,156

 
1,436,755

 
1,249,432

 
1,111,233

   Developed Non‑Producing
 
243,337

 
168,403

 
121,209

 
90,363

 
69,485

   Undeveloped
 
2,016,607

 
1,283,412

 
857,825

 
591,516

 
415,062

   TOTAL PROVED
 
4,372,746

 
3,155,971

 
2,415,789

 
1,931,311

 
1,595,780

PROBABLE
 
2,283,088

 
1,246,255

 
743,730

 
470,123

 
307,074

   TOTAL PROVED PLUS PROBABLE
 
6,655,834

 
4,402,226

 
3,159,519

 
2,401,434

 
1,902,854

POSSIBLE (2)(3)
 
1,528,085

 
922,585

 
621,008

 
452,503

 
349,451

TOTAL PROVED PLUS PROBABLE PLUS POSSIBLE (2)(3)
 
8,183,919

 
5,324,811

 
3,780,526

 
2,853,937

 
2,252,305

Notes:
(1)
The after-tax net present value of future net revenue from our oil and gas properties reflects the tax burden on the properties on a theoretical stand-alone basis.  It does not consider our corporate structure or any tax planning and therefore does not provide an estimate of the cumulative after-tax value of our consolidated business entities, which may be significantly different. 
(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.
(3)
The total possible reserves include only possible reserves from the Eagle Ford properties. The possible reserves associated with the Canadian properties have not been evaluated.



26

TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
AS OF DECEMBER 31, 2016
FORECAST PRICES AND COSTS
($000s)
REVENUE
 
ROYALTIES
 
OPERAT-ING COSTS
 
DEVELOP-MENT COSTS
 
WELL ABANDON-MENT COSTS(1)
 
FUTURE NET REVENUE BEFORE INCOME TAXES
 
INCOME TAXES
 
FUTURE NET REVENUE
AFTER INCOME TAXES
TOTAL PROVED RESERVES
 
 
 
 
 
 
 
 
 
 
 
 
Canada
3,746,370

 
594,279

 
1,323,625
 
432,275
 
95,259
 
1,300,931
 
121,845
 
1,179,087
United States
10,791,104

 
3,378,708

 
2,015,800
 
1,342,613
 
51,351
 
4,002,633
 
808,974
 
3,193,659
Total
14,537,475

 
3,972,988

 
3,339,425
 
1,774,888
 
146,610
 
5,303,564
 
930,818
 
4,372,746
TOTAL PROVED PLUS PROBABLE RESERVES
 
 
 
 
 
 
 
 
 
 
Canada
10,203,618

 
1,848,010

 
3,498,590
 
1,239,406
 
134,378
 
3,483,233
 
700,101
 
2,783,132
United States
14,045,481

 
4,402,316

 
2,674,949
 
1,847,182
 
64,594
 
5,056,440
 
1,183,738
 
3,872,702
Total
24,249,099

 
6,250,327

 
6,173,539
 
3,086,588
 
198,972
 
8,539,673
 
1,883,839
 
6,655,834
TOTAL PROVED PLUS PROBABLE PLUS POSSIBLE RESERVES (2)(3)
 
 
 
 
 
 
 
 
Canada
10,203,618

 
1,848,010

 
3,498,590
 
1,239,406
 
134,378
 
3,483,233
 
700,101
 
2,783,132
United States
19,149,972

 
6,000,174

 
3,400,342
 
2,247,724
 
74,928
 
7,426,804
 
2,026,017
 
5,400,787
Total
29,353,590

 
7,848,184

 
6,898,933
 
3,487,130
 
209,306
 
10,910,037
 
2,726,118
 
8,183,919
Notes:
(1)
Includes well abandonment and reclamation based on estimates by the Corporation for all reserves wells, producing and undeveloped, but does not include abandonment and surface reclamation costs for any existing facilities.
(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.
(3)
The total possible reserves include only possible reserves from the Eagle Ford properties. The possible reserves associated with the Canadian properties have not been evaluated.



27

FUTURE NET REVENUE BY PRODUCT TYPE
AS OF DECEMBER 31, 2016
FORECAST PRICES AND COSTS
RESERVES CATEGORY
PRODUCT TYPE
FUTURE NET REVENUE BEFORE INCOME TAXES (discounted at 10%/year)
($000s)

UNIT VALUE
($/boe) (1)

 
 
 
 
Proved
Light and Medium Crude Oil (including solution gas and associated byproducts)
37,342

15.93

 
Heavy Oil (including solution gas and associated byproducts)
524,619

11.44

 
Bitumen (including solution gas and associated byproducts)
174,684

14.83

 
Tight Oil (including solution gas and associated byproducts)
936,996

18.70

 
Natural Gas (associated and non-associated) (including associated byproducts)
88,499

7.71

 
Shale Gas (including associated byproducts)
1,025,344

13.92

 
Total
2,787,484

 
 
 
 
 
Proved plus
Probable
Light and Medium Crude Oil (including solution gas and associated byproducts)
50,399

11.02

Heavy Oil (including solution gas and associated byproducts)
827,505

11.79

 
Bitumen (including solution gas and associated byproducts)
489,051

8.72

 
Tight Oil (including solution gas and associated byproducts)
1,058,387

18.12

 
Natural Gas (associated and non-associated) (including associated byproducts)
181,443

7.05

 
Shale Gas (including associated byproducts)
1,280,868

12.70

 
Total
3,887,653

 
 
 
 
 
Proved plus Probable plus Possible (2)(3)
Light and Medium Crude Oil (including solution gas and associated byproducts)
50,399

11.02

Heavy Oil (including solution gas and associated byproducts)
827,505

11.79

 
Bitumen (including solution gas and associated byproducts)
489,051

8.72

 
Tight Oil (including solution gas and associated byproducts)
1,439,811

18.68

 
Natural Gas (associated and non-associated) (including associated byproducts)
181,443

7.05

 
Shale Gas (including associated byproducts)
1,837,552

13.50

 
Total
4,825,762

 

Notes:
(1)
Unit values are based on net reserves 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.
(3)
The total possible reserves include only possible reserves from the Eagle Ford properties. The possible reserves associated with the Canadian properties have not been evaluated.



28

Pricing Assumptions
The forecast cost and price assumptions include increases in actual wellhead selling prices and take into account inflation with respect to future operating and capital costs. The reference pricing used in the Baytex Reserves Report is as follows:
 
 
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
FORECAST PRICES AND COSTS AS AT DECEMBER 31, 2016(1)
Year
 
Oil
 
Natural Gas
 
Operating Cost Inflation Rate(7)
(%/Yr)
 
Capital Cost Inflation Rate(7)
(%/Yr)
 
Exchange Rate(8)
($US/$Cdn)
 
WTI Cushing Oklahoma(2) ($US/bbl)
 
Canada Light Sweet Crude 40° API(3)
($Cdn/bbl)
 
Western Canadian Select
20.5° API(4)
($Cdn/bbl)
 
Henry Hub(5)
($US/Mmbtu)
 
AECO-C Spot(6)
($Cdn/MMbtu)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Historical
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2012
 
94.19
 
86.57
 
73.08
 
2.79
 
2.43
 
1.0
 
4.5
 
1.001
2013
 
97.98
 
93.27
 
74.93
 
3.68
 
3.13
 
1.0
 
0.7
 
0.971
2014
 
93.00
 
93.99
 
81.06
 
4.28
 
4.50
 
2.0
 
(1.0)
 
0.905
2015
 
48.80
 
57.45
 
44.83
 
2.63
 
2.70
 
1.8
 
(23.2)
 
0.783
2016
 
43.32
 
52.80
 
38.30
 
2.55
 
2.18
 
1.6
 
(3.3)
 
0.755
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

Forecast(9)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2017
 
55.00
 
65.58
 
53.12
 
3.50
 
3.44
 
—
 
—
 
0.780
2018
 
65.00
 
74.51
 
61.85
 
3.50
 
3.27
 
2.0
 
2.0
 
0.820
2019
 
70.00
 
78.24
 
64.94
 
3.50
 
3.22
 
2.0
 
2.0
 
0.850
2020
 
71.40
 
80.64
 
66.93
 
4.00
 
3.91
 
2.0
 
2.0
 
0.850
2021
 
72.83
 
82.25
 
68.27
 
4.08
 
4.00
 
2.0
 
2.0
 
0.850
2022
 
74.28
 
83.90
 
69.64
 
4.16
 
4.10
 
2.0
 
2.0
 
0.850
2023
 
75.77
 
85.58
 
71.03
 
4.24
 
4.19
 
2.0
 
2.0
 
0.850
2024
 
77.29
 
87.29
 
72.45
 
4.33
 
4.29
 
2.0
 
2.0
 
0.850
2025
 
78.83
 
89.03
 
73.90
 
4.42
 
4.40
 
2.0
 
2.0
 
0.850
2026
 
80.41
 
90.81
 
75.38
 
4.50
 
4.50
 
2.0
 
2.0
 
0.850
2027
 
82.02
 
92.63
 
76.88
 
4.59
 
4.61
 
2.0
 
2.0
 
0.850
Notes:
(1)
Each price from the Sproule forecast was adjusted for quality differentials and transportation costs applicable to the specified product and evaluation area.
(2)
Price used in the preparation of tight oil reserves in the United States.
(3)
Price used in the preparation of light and medium crude oil and natural gas liquids reserves in Canada.
(4)
Price used in the preparation of heavy oil and bitumen reserves in Canada.
(5)
Price used in the preparation of shale gas reserves in the United States.
(6)
Price used in the preparation of natural gas reserves in Canada.
(7)
Inflation rates for forecasting prices and costs.
(8)
Exchange rate used to generate the benchmark reference prices in this table.
(9)
After 2027 prices and costs escalate at 2.0% annually and the exchange rate remains 0.850.

Weighted average prices realized by us for the year ended December 31, 2016, excluding hedging activities, were $26.41/bbl for heavy oil, $27.20/bbl for bitumen, $46.21/bbl for light oil, $50.60/bbl for tight oil, $17.16/bbl for NGL, $3.21/Mcf for shale gas and $2.01/Mcf for natural gas.



29

RECONCILIATION OF
GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE
FORECAST PRICES AND COSTS
 
CANADA
 
HEAVY OIL (1)
 
BITUMEN
 
 
Proved
(Mbbl)

 
Probable
(Mbbl)

 
Proved Plus Probable
(Mbbl)

 
Proved
(Mbbl)

 
Probable
(Mbbl)

 
Proved Plus Probable
(Mbbl)

December 31, 2015
 
65,030

 
37,883

 
102,913

 
13,758

 
55,882

 
69,640

Extensions
 
227

 
1,255

 
1,482

 
—

 
—

 
—

Infill Drilling
 
1,037

 
1,024

 
2,062

 
—

 
—

 
—

Improved Recovery
 
—

 
0

 
0

 
—

 
—

 
—

Technical Revisions
 
(8,004
)
 
(9,862
)
 
(17,866
)
 
476

 
(216
)
 
260

Discoveries
 
—

 
—

 
—

 
—

 
—

 
—

Acquisitions
 
34

 
13

 
48

 
—

 
—

 
—

Dispositions
 
(685
)
 
(804
)
 
(1,489
)
 
—

 
—

 
—

Economic Factors
 
(2,700
)
 
(185
)
 
(2,885
)
 
(204
)
 
170

 
(35
)
Production
 
(8,065
)
 
—

 
(8,065
)
 
(565
)
 
—

 
(565
)
December 31, 2016
 
46,875

 
29,325

 
76,199

 
13,465

 
55,835

 
69,300


CANADA
 
LIGHT AND MEDIUM OIL
 
CONVENTIONAL NATURAL GAS (2)
 
 
Proved
(Mbbl)

 
Probable
(Mbbl)

 
Proved Plus Probable
(Mbbl)

 
Proved
(MMcf)

 
Probable
(MMcf)

 
Proved Plus Probable
(MMcf)

December 31, 2015
 
2,902

 
2,420

 
5,323

 
92,000

 
85,538

 
177,538

Extensions
 
—

 
—

 
—

 
11

 
3,682

 
3,693

Infill Drilling
 
—

 
—

 
—

 
94

 
52

 
146

Improved Recovery
 
 
 
—

 
—

 
—

 
—

 
—

Technical Revisions
 
141

 
(425
)
 
(284
)
 
39,373

 
2,693

 
42,066

Discoveries
 
—

 
—

 
—

 
—

 
—

 
—

Acquisitions
 
—

 
—

 
—

 
2,531

 
641

 
3,172

Dispositions
 
(25
)
 
(8
)
 
(32
)
 
(1,998
)
 
(568
)
 
(2,565
)
Economic Factors
 
(214
)
 
(194
)
 
(408
)
 
(1,432
)
 
(2,833
)
 
(4,265
)
Production
 
(511
)
 
—

 
(511
)
 
(14,645
)
 
—

 
(14,645
)
December 31, 2016
 
2,293

 
1,794

 
4,087

 
115,933

 
89,206

 
205,139


CANADA
 
NATURAL GAS LIQUIDS (3)
 
OIL EQUIVALENT
 
 
Proved
(Mbbl)

 
Probable
(Mbbl)

 
Proved Plus Probable
(Mbbl)

 
Proved (Mboe)

 
Probable
(Mboe)

 
Proved Plus Probable
(Mboe)

December 31, 2015
 
2,745

 
3,081

 
5,826

 
99,768

 
113,522

 
213,290

Extensions
 
—

 
148

 
148

 
229

 
2,017

 
2,245

Infill Drilling
 
—

 
—

 
—

 
1,053

 
1,033

 
2,086

Improved Recovery
 
—

 
—

 
—

 
—

 
—

 
—

Technical Revisions
 
290

 
6

 
296

 
(535
)
 
(10,048
)
 
(10,583
)
Discoveries
 
—

 
—

 
—

 
—

 
—

 
—

Acquisitions
 
106

 
27

 
133

 
562

 
147

 
709

Dispositions
 
(62
)
 
(18
)
 
(80
)
 
(1,105
)
 
(924
)
 
(2,029
)
Economic Factors
 
(25
)
 
(46
)
 
(71
)
 
(3,381
)
 
(729
)
 
(4,110
)
Production
 
(463
)
 
—

 
(463
)
 
(12,046
)
 
—

 
(12,046
)
December 31, 2016
 
2,590

 
3,198

 
5,788

 
84,544

 
105,019

 
189,564



30



UNITED STATES
 
TIGHT OIL (4)
 
SHALE GAS (4)
 
 
Proved
(Mbbl)

 
Probable
(Mbbl)

 
Proved Plus Probable
(Mbbl)

 
Proved
(MMcf)

 
Probable
(MMcf)

 
Proved Plus Probable
(MMcf)

December 31, 2015
 
49,215

 
4,551

 
53,765

 
194,767

 
40,038

 
234,805

Extensions
 
—

 
—

 
—

 
—

 
—

 
—

Infill Drilling
 
6,948

 
5,863

 
12,812

 
33,171

 
43,893

 
77,064

Improved Recovery
 
—

 
—

 
—

 
—

 
—

 
—

Technical Revisions
 
(1,723
)
 
(2,027
)
 
(3,750
)
 
(41,058
)
 
(25,187
)
 
(66,246
)
Discoveries
 
—

 
—

 
—

 
—

 
—

 
—

Acquisitions
 
—

 
—

 
—

 
—

 
—

 
—

Dispositions
 
(831
)
 
(52
)
 
(883
)
 
—

 
—

 
—

Economic Factors
 
3

 
63

 
67

 
334

 
331

 
665

Production
 
(3,898
)
 
—

 
(3,898
)
 
(13,386
)
 
—

 
(13,386
)
December 31, 2016
 
49,714

 
8,399

 
58,113

 
173,828

 
59,075

 
232,903

UNITED STATES
 
CONVENTIONAL NATURAL GAS (2)
 
NATURAL GAS LIQUIDS (3)(4)
 
 
Proved
(MMcf)

 
Probable
(MMcf)

 
Proved Plus Probable
(MMcf)

 
Proved
(Mbbl)

 
Probable
(Mbbl)

 
Proved Plus Probable
(Mbbl)

December 31, 2015
 
56,880

 
5,991

 
62,871

 
83,710

 
16,263

 
99,972

Extensions
 
—

 
—

 
—

 
—

 
—

 
—

Infill Drilling
 
7,656

 
5,041

 
12,697

 
15,692

 
21,905

 
37,597

Improved Recovery
 
—

 
—

 
—

 
—

 
—

 
—

Technical Revisions
 
(2,498
)
 
(2,173
)
 
(4,671
)
 
(12,966
)
 
(9,668
)
 
(22,634
)
Discoveries
 
—

 
—

 
—

 
—

 
—

 
—

Acquisitions
 
—

 
—

 
—

 
—

 
—

 
—

Dispositions
 
(618
)
 
(52
)
 
(669
)
 
(87
)
 
(7
)
 
(94
)
Economic Factors
 
4

 
97

 
101

 
120

 
134

 
254

Production
 
(5,341
)
 
—

 
(5,341
)
 
(6,367
)
 
—

 
(6,367
)
December 31, 2016
 
56,083

 
8,906

 
64,988

 
80,102

 
28,627

 
108,728

UNITED STATES
 
OIL EQUIVALENT
 
 
Proved
(Mboe)

 
Probable
(Mboe)

 
Proved Plus Probable
(Mboe)

December 31, 2015
 
174,865

 
28,485

 
203,350

Extensions
 
—

 
—

 
—

Infill Drilling
 
29,445

 
35,924

 
65,369

Improved Recovery
 
—

 
—

 
—

Technical Revisions
 
(21,948
)
 
(16,255
)
 
(38,203
)
Discoveries
 
—

 
—

 
—

Acquisitions
 
—

 
—

 
—

Dispositions
 
(1,021
)
 
(67
)
 
(1,088
)
Economic Factors
 
179

 
269

 
448

Production
 
(13,386
)
 
—

 
(13,386
)
December 31, 2016
 
168,134

 
48,356

 
216,490




31

TOTAL
 
HEAVY OIL (1)
 
BITUMEN
 
 
Proved
(Mbbl)

 
Probable
(Mbbl)

 
Proved Plus Probable
(Mbbl)

 
Proved
(Mbbl)

 
Probable
(Mbbl)

 
Proved Plus Probable
(Mbbl)

December 31, 2015
 
65,030

 
37,883

 
102,913

 
13,758

 
55,882

 
69,640

Extensions
 
227

 
1,255

 
1,482

 
—

 
—

 
—

Infill Drilling
 
1,037

 
1,024

 
2,062

 
—

 
—

 
—

Improved Recovery
 
—

 
—

 
—

 
—

 
—

 
—

Technical Revisions
 
(8,004
)
 
(9,862
)
 
(17,866
)
 
476

 
(216
)
 
260

Discoveries
 
—

 
—

 
—

 
—

 
—

 
—

Acquisitions
 
34

 
13

 
48

 
—

 
—

 
—

Dispositions
 
(685
)
 
(804
)
 
(1,489
)
 
—

 
—

 
—

Economic Factors
 
(2,700
)
 
(185
)
 
(2,885
)
 
(204
)
 
170

 
(35
)
Production
 
(8,065
)
 
—

 
(8,065
)
 
(565
)
 
—

 
(565
)
December 31, 2016
 
46,875

 
29,325

 
76,199

 
13,465

 
55,835

 
69,300


TOTAL
 
LIGHT AND MEDIUM OIL
 
TIGHT OIL (4)
 
 
Proved
(Mbbl)

 
Probable
(Mbbl)

 
Proved Plus Probable
(Mbbl)

 
Proved
(Mbbl)

 
Probable
(Mbbl)

 
Proved Plus Probable
(Mbbl)

December 31, 2015
 
2,902

 
2,420

 
5,323

 
49,215

 
4,551

 
53,765

Extensions
 
—

 
—

 
—

 
—

 
—

 
—

Infill Drilling
 
—

 
—

 
—

 
6,948

 
5,863

 
12,812

Improved Recovery
 
—

 
—

 
—

 
—

 
—

 
—

Technical Revisions
 
141

 
(425
)
 
(284
)
 
(1,723
)
 
(2,027
)
 
(3,750
)
Discoveries
 
—

 
—

 
—

 
—

 
—

 
—

Acquisitions
 
—

 
—

 
—

 
—

 
—

 
—

Dispositions
 
(25
)
 
(8
)
 
(32
)
 
(831
)
 
(52
)
 
(883
)
Economic Factors
 
(214
)
 
(194
)
 
(408
)
 
3

 
63

 
67

Production
 
(511
)
 
—

 
(511
)
 
(3,898
)
 
—

 
(3,898
)
December 31, 2016
 
2,293

 
1,794

 
4,087

 
49,714

 
8,399

 
58,113

TOTAL
 
NATURAL GAS LIQUIDS (3)(4)
 
SHALE GAS (4)
 
 
Proved
(Mbbl)

 
Probable
(Mbbl)

 
Proved Plus Probable
(Mbbl)

 
Proved
(MMcf)

 
Probable
(MMcf)

 
Proved Plus Probable
(MMcf)

December 31, 2015
 
86,454

 
19,344

 
105,798

 
194,767

 
40,038

 
234,805

Extensions
 
—

 
148

 
148

 
—

 
—

 
—

Infill Drilling
 
15,692

 
21,905

 
37,597

 
33,171

 
43,893

 
77,064

Improved Recovery
 
—

 
—

 
—

 
—

 
—

 
—

Technical Revisions
 
(12,676
)
 
(9,662
)
 
(22,338
)
 
(41,058
)
 
(25,187
)
 
(66,246
)
Discoveries
 
—

 
—

 
—

 
—

 
—

 
—

Acquisitions
 
106

 
27

 
133

 
—

 
—

 
—

Dispositions
 
(149
)
 
(24
)
 
(174
)
 
—

 
—

 
—

Economic Factors
 
95

 
88

 
183

 
334

 
331

 
665

Production
 
(6,830
)
 
—

 
(6,830
)
 
(13,386
)
 
—

 
(13,386
)
December 31, 2016
 
82,692

 
31,825

 
114,516

 
173,828

 
59,075

 
232,903




32

TOTAL
 
CONVENTIONAL NATURAL GAS (2)
 
OIL EQUIVALENT
 
 
Proved
(MMcf)

 
Probable
(MMcf)

 
Proved Plus Probable
(MMcf)

 
Proved
(Mboe)

 
Probable
(Mboe)

 
Proved Plus Probable
(Mboe)

December 31, 2015
 
148,880

 
91,529

 
240,409

 
274,633

 
142,008

 
416,640

Extensions
 
11

 
3,682

 
3,693

 
229

 
2,017

 
2,245

Infill Drilling
 
7,749

 
5,094

 
12,843

 
30,497

 
36,957

 
67,455

Improved Recovery
 
—

 
—

 
—

 
—

 
—

 
—

Technical Revisions
 
36,875

 
520

 
37,395

 
(22,483
)
 
(26,303
)
 
(48,786
)
Discoveries
 
—

 
—

 
—

 
—

 
—

 
—

Acquisitions
 
2,531

 
641

 
3,172

 
562

 
147

 
709

Dispositions
 
(2,615
)
 
(619
)
 
(3,235
)
 
(2,126
)
 
(992
)
 
(3,118
)
Economic Factors
 
(1,428
)
 
(2,735
)
 
(4,163
)
 
(3,202
)
 
(460
)
 
(3,661
)
Production
 
(19,987
)
 
—

 
(19,987
)
 
(25,431
)
 
—

 
(25,431
)
December 31, 2016
 
172,016

 
98,112

 
270,127

 
252,679

 
153,375

 
406,053

Note:
(1)
Technical revisions related to heavy oil are largely attributed to revised reservoir and mobility mapping and well performance.
(2)
Conventional natural gas includes associated, non-associated and solution gas.
(3)
Natural gas liquids includes condensate.
(4)
Technical revisions for tight oil, natural gas liquids and shale gas were largely the result of the development of additional horizons, primarily the Upper Eagle Ford. These new horizons are now proven and have producing wells and new locations, which reduced the expected recovery from a portion of the existing wells. These technical revisions were more than offset by reserve additions classified as “infill drilling”.
Additional Information Relating to Reserves Data
Undeveloped Reserves
Undeveloped reserves are attributed by Sproule and Ryder Scott in accordance with standards and procedures contained in the COGE Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Probable undeveloped reserves are those reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.
We allocate development capital to our assets annually. We reduce risk by technically assessing the prior year's results from our development programs before committing additional capital. Furthermore, planned activity levels vary each year due to factors such as prevailing commodity prices, capital availability, operational spacing considerations and regulatory processes. This approach means that in most cases it will take longer than three years to develop our proved undeveloped reserves and longer than five years to develop our proved plus probable undeveloped reserves. With the exception of the Gemini SAGD Project, we plan to develop the majority of our proved undeveloped reserves over the next five years and our probable undeveloped reserves over the next seven years.
At our Gemini SAGD project, steam generation represents a large proportion of the capital and operating costs, therefore, our development plans anticipate that in order to make the most efficient use of our steam generating and oil treating facilities, the drilling and steaming of wells would take place over the next 27 years. We have booked 0.5 Mbbls of proved undeveloped reserves and 43.4 Mbbls of probable undeveloped reserves to the Gemini SAGD project.


33

Proved Undeveloped Reserves
The following table discloses, for each product type, the volumes of proved undeveloped reserves that were attributed during, and the volume booked at year-end for, the three most recently completed financial years.
 
 
Light and Medium Oil
Gross (Mbbl)
 
Tight Oil
Gross (Mbbl)
 
Heavy Oil
Gross (Mbbl)
 
Bitumen
Gross (Mbbl)
Year
 
First Attributed
 
Booked at Year End
 
First Attributed
 
Booked at Year End
 
First Attributed
 
Booked at Year End
 
First Attributed
 
Booked at Year End
2014
 
—

 
307

 
28,077

 
28,077

 
4,490

 
29,367

 
—

 
8,295

2015
 
—

 
99

 
3,122

 
28,812

 
1,506

 
27,362

 
—

 
5,429

2016
 
—

 
308

 
4,561

 
30,472

 
1,215

 
18,343

 
—

 
5,428


 
 
Conventional Natural Gas
Gross (Mmcf)
 
Shale Gas
Gross (Mmcf)
 
Natural Gas Liquids
Gross (Mbbl)
Year
 
First Attributed
 
Booked at Year End
 
First Attributed
 
Booked at Year End
 
First Attributed
 
Booked at Year End
2014
 
29,412

 
51,407

 
139,352

 
139,352

 
56,850

 
57,802

2015
 
7,346

 
64,275

 
17,555

 
138,014

 
8,540

 
59,273

2016
 
5,038

 
95,264

 
20,050

 
112,899

 
9,817

 
54,539


Probable Undeveloped Reserves
The following table discloses, for each product type, the volumes of probable undeveloped reserves that were attributed during, and the volume booked at year-end for, the three most recently completed financial years.
 
 
Light and Medium Oil
Gross (Mbbl)
 
Tight Oil
Gross (Mbbl)
 
Heavy Oil
Gross (Mbbl)
 
Bitumen
Gross (Mbbl)
Year
 
First Attributed
 
Booked at Year End
 
First Attributed
 
Booked at Year End
 
First Attributed
 
Booked at Year End
 
First Attributed
 
Booked at Year End
2014
 
—

 
1,532

 
2,415

 
2,415

 
3,884

 
21,824

 
26,904

 
63,989

2015
 
—

 
1,703

 
287

 
1,877

 
4,265

 
24,383

 
—

 
47,218

2016
 
—

 
1,120

 
5,789

 
5,808

 
2,268

 
20,256

 
—

 
47,219


 
 
Conventional Natural Gas
Gross (Mmcf)
 
Shale Gas
Gross (Mmcf)
 
Natural Gas Liquids
Gross (Mbbl)
Year
 
First Attributed
 
Booked at Year End
 
First Attributed
 
Booked at Year End
 
First Attributed
 
Booked at Year End
2014
 
26,941
 
54,060
 
16,714
 
16,714
 
8,347
 
9,572
2015
 
11,069
 
75,819
 
21,447
 
33,122
 
9,068
 
15,796
2016
 
8,687
 
81,161
 
43,066
 
51,955
 
21,703
 
28,214

Significant Factors or Uncertainties
In the event that prices for oil and gas are not consistent with those used to prepare the Baytex Reserves Report, the volume of our reserves, their net present value and our expected revenues will differ, perhaps materially so, from those stated in the Baytex Reserves Report.


34

We have a significant amount of proved non-producing and proved undeveloped reserves assigned to our Canadian heavy oil properties located in the Province of Saskatchewan, at our Peace River, Ardmore and Cold Lake bitumen and heavy oil properties located in the Province of Alberta, and at our conventional light oil and natural gas properties in Pembina, Alberta. Our Eagle Ford property in Texas, USA also contains a significant quantity of proved non-producing and proved undeveloped reserves. As well, we have a significant amount of probable non-producing and probable undeveloped reserves assigned to these same properties. At the forecast prices and costs used in the Baytex Reserves Report, these development activities are expected to be economic. However, should oil and natural gas prices fall below those used to prepare the Baytex Reserves Report, these activities may not be economic and we could defer their implementation. In addition, reserves can be affected significantly by fluctuations in capital expenditures, operating costs, royalty regimes, and well performance that are beyond our control and which could impact our development decisions. See "Risk Factors".
In connection with our operations, we will be liable for our share of ongoing environmental obligations and for the ultimate reclamation of those surface leases, wells and facilities held by us which have not been included in the calculation of future net revenue as they are not associated with our reserves. The additional liability associated with these existing surface leases, wells and facilities which was not included when estimating future net revenue, is estimated to be $499.4 million ($68.9 million discounted at 10 percent).
Future Development Costs

The following table sets forth development costs deducted in the estimation of the future net revenue attributable to the reserve categories noted below (using forecast prices and costs).
FUTURE DEVELOPMENT COSTS
AS OF DECEMBER 31, 2016
FORECAST PRICES AND COSTS
($000s)
 
 
CANADA
 
 
UNITED STATES
 
 
TOTAL
 
 
Proved Reserves
 
Proved plus Probable Reserves
 
 
Proved Reserves
 
Proved plus Probable Reserves
 
 
Proved Reserves
 
Proved plus Probable Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2017
 
68,851
 
82,101
 
 
171,137
 
252,541
 
 
239,989
 
334,642
2018
 
130,105
 
273,039
 
 
192,088
 
247,526
 
 
322,193
 
520,564
2019
 
118,115
 
279,336
 
 
200,143
 
267,560
 
 
318,258
 
546,896
2020
 
63,573
 
162,254
 
 
168,708
 
245,334
 
 
232,280
 
407,588
2021
 
36,081
 
138,682
 
 
215,465
 
282,523
 
 
251,546
 
421,204
Remaining
 
15,550
 
303,996
 
 
395,073
 
551,698
 
 
410,623
 
855,693
Total (undiscounted)
 
432,275
 
1,239,406
 
 
1,342,613
 
1,847,182
 
 
1,774,888
 
3,086,588
We expect to fund the development costs of our reserves through a combination of internally generated funds from operations, debt and equity financings. Planned activity levels vary each year due to factors such as capital availability, prevailing commodity prices, operational spacing considerations and regulatory processes.
There can be no guarantee that funds will be available or that our Board of Directors will allocate funding to develop all of the reserves attributed in the Baytex Reserves Report. Failure to develop those reserves could have a negative impact on our future funds from operations.
The interest or other costs of external funding are not included in the reserves and future net revenue estimates set forth herein and would reduce reserves and future net revenue to some degree depending upon the funding sources utilized and the costs thereof. We do not anticipate that interest or other funding costs would make development of any of these properties uneconomic.


35

Possible Reserves
We commissioned Ryder Scott to evaluate our possible reserves effective December 31, 2016 in the Eagle Ford property. The possible reserves reflect the significant upside potential of the Austin Chalk, Upper Eagle Ford and Lower Eagle Ford formations. 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.
Contingent Resources
We commissioned Sproule to conduct an evaluation effective December 31, 2016 of our contingent resources in Alberta and Saskatchewan. We commissioned Ryder Scott to audit our internal assessment of our contingent resources in the Eagle Ford play in Texas, effective December 31, 2016. A summary of these contingent resources estimates is provided in Appendix A.
OTHER OIL AND GAS INFORMATION
Oil and Natural Gas Properties

The following is a description of our principal oil and natural gas properties on production or under development as at December 31, 2016. Unless otherwise specified, gross and net acres and well count information are as at December 31, 2016. Well counts indicate gross wells, except where otherwise indicated. Production information represents average working interest production for the year ended December 31, 2016, except where otherwise indicated.

Our crude oil and natural gas operations are organized into four business units: Lloydminster, Peace River, Conventional and United States. These business units have a portfolio of mineral leases, with operated and/or non-operated properties and development prospects. Within these business units, Baytex has established geographically-organized teams with a full complement of technical professionals (engineers, geoscientists and landmen). This comprehensive technical approach is intended to result in thorough identification and evaluation of exploration, development and acquisition opportunities and cost-efficient execution of those opportunities.

We endeavour to add value through internal property development and selective acquisitions. Future heavy oil development will focus both on the Peace River oil sands area within the Peace River Business Unit and our historical area of emphasis around west-central Saskatchewan and northeast Alberta within the Lloydminster Business Unit. Tight gas development in Canada is focused on the Pembina area in west-central Alberta within the Conventional Business Unit and light oil and gas development will focus on the Sugarkane area located in the core of the liquids-rich Eagle Ford shale within the United States Business Unit.


    


36

Principal Properties
The map below highlights the geographic location of our principal properties.
a2017327baytexmapfeb2017.jpg
Lloydminster Business Unit
The Lloydminster Business Unit accounted for approximately 15% of total production in 2016. The Lloydminster Business Unit's heavy oil operations include primary and thermal production. In some cases, Baytex's heavy oil reservoirs are waterflooded, occasionally with hot water. Baytex's heavy oil fields often have multiple productive zones, some of which can be commingled within the same producing wellbore. Production is generated from vertical, directional/slant and horizontal wells using progressive cavity pumps capable of handling large volumes of heavy oil combined with gas, water and sand. Initial production from these wells averages between 30 and 150 bbl/d of crude oil with gravities ranging from 10 to 16 degrees API. Once produced, the oil is delivered to markets in Canada and the United States via pipelines, tanker trucks or railways. Heavy crude is usually blended with light-hydrocarbon diluents prior to being introduced into a sales pipeline. The heavy crude Baytex delivers to rail for transport is not blended with diluents. The blended (pipeline) and non-blended (rail) crude oil is then sold by Baytex and may be upgraded into lighter grades of crude or refined into petroleum products such as fuel oil, lubricants and asphalt by the crude purchasers. All production rates reported are for heavy crude oil, before the addition of diluents.
In 2016, production in the Lloydminster Business Unit averaged approximately 10,170 boe/d, which was comprised of 8,391 bbl/d of heavy oil, 1,544 bbl/d of bitumen, and 1,382 Mcf/d of natural gas. Our net undeveloped lands in the Lloydminster Business Unit totaled approximately 193,087 acres at year-end 2016.


37

The Lloydminster Business Unit possesses a large inventory of development projects within the operating areas of west-central Saskatchewan and Cold Lake/Ardmore in Alberta. Our ability to generate relatively low-cost replacement production through conventional cold production and enhanced recovery methods has historically been key to maintaining our overall production rate. Our inventory of heavy oil projects allows us to select from a wide range of investment opportunities as economic conditions warrant.
Listed below are brief descriptions of the principal properties within the Lloydminster Business Unit:
Cold Lake/Ardmore, Alberta: The majority of the Cold Lake and Ardmore assets were acquired in 2001 and 2002, respectively, and have been developed extensively for primary production in the General Petroleum, Sparky, McLaren and Colony formations. Average production from the primary assets during 2016 was approximately 608 bbl/d of heavy oil and 365 Mcf/d of natural gas (669 boe/d).
On October 3, 2012, Baytex acquired a 100% working interest in 46 sections of undeveloped oil sands leases in the Angling Lake (Cold Lake) area of northern Alberta.  Regulatory approval has been obtained for the construction and operation of a two-stage bitumen recovery scheme using SAGD, which we refer to as the Gemini SAGD project.  The first stage, being a single SAGD well pair with a 600 meter horizontal lateral, was completed with steam circulation into the injector and producer commencing on January 24, 2014.  The producing well was converted to production in May 2014 and produced until April 2015, when an electrical fire at the facility resulted in damage to equipment and resulted in the project being suspended. During the 11-month production phase, the well produced over 200,000 bbls of oil at an average rate of approximately 590 bopd and a steam-oil ratio of 2.42 barrels of steam per barrel of oil.
In December 2014, Baytex submitted a scheme amendment application to the Alberta Energy Regulator to modify the facility size from 10,000 bbl/d to 5,000 bbl/d, change the produced water treatment design, utilize self-power generation and add two additional resource areas to the existing development approval.  This scheme amendment application was approved by the Alberta Energy Regulator on September 30, 2016.
At year-end 2016, Baytex had 76,981 net undeveloped acres in the Cold Lake/Ardmore area.
Soda Lake, Saskatchewan: The Soda Lake property was acquired by Baytex in 1997. This property consists of separate "North" and "South" oil pools in the Cummings formation. Average production in 2016 was approximately 2,095 bbl/d of heavy oil and 108 Mcf/d of natural gas (2,113 boe/d). At year-end 2016, Baytex had 8,488 net undeveloped acres in this area.
Celtic, Saskatchewan: This property was acquired by Baytex in 2005. Celtic is a key asset for Baytex because, like the adjacent Tangleflags property, it contains a large resource base with multiple prospective horizons within the Mannville Group. As a result, the Celtic property provides a multi-year inventory of drilling locations and re-completion opportunities. Average production in 2016 was approximately 1,377 bbl/d of heavy oil. At year-end 2016, Baytex had 7,702 net undeveloped acres in this area.
Kerrobert/Hoosier, Saskatchewan: Baytex acquired most of its assets in the Kerrobert and Hoosier areas of Saskatchewan in 2009. These properties provide numerous opportunities for cold infill drilling and SAGD optimization. Production from the cold primary and thermal assets averaged approximately 858 bbl/d of heavy oil, 1,544 bbl/d of bitumen, 5 bbl/d of light oil and NGL and 20 Mcf/d of natural gas (2,410 boe/d). At year-end 2016, Baytex had 37,240 net undeveloped acres in this area.
Tangleflags, Saskatchewan:  Baytex acquired the Tangleflags property in 2000. Tangleflags is characterized by multiple-zone reservoirs with production from the McLaren, Waseca, Sparky, General Petroleum and Lloydminster formations. Average production during 2016 was approximately 1,858 bbl/d of heavy oil and 464 Mcf/d of natural gas (1,935  boe/d). At year-end 2016, Baytex had 5,288 net undeveloped acres in this area.


38

Peace River Business Unit
The Peace River Business Unit produces heavy gravity crude oil, bitumen, and natural gas mainly from the Bluesky formation in the Peace River region of north west Alberta. This production accounted for approximately 21% of total Baytex production in 2016. The following is a brief description of the principal property in the Peace River Business Unit:

Peace River, Alberta: Baytex holds a total of 338 net sections of oil sands leases in the Peace River area, which includes the legacy Harmon Valley area and the Reno area. During 2016, production from the Peace River area averaged 13,651 bbl/d of heavy oil, and 4,180 Mcf/d of natural gas (14,348 boe/d). At year-end 2016, Baytex had 180,199 net undeveloped acres of oil sands leases in this area.
In certain parts of the Peace River land base, heavy oil can be produced using multi-lateral horizontal wells at initial production rates of approximately 300 bbl/d per well without employing more cost-intensive secondary and tertiary recovery methods. The majority of Baytex's development activity is focused on primary production through this multi-lateral well strategy. However, in some portions of the land base, the reservoir characteristics require thermal stimulation to achieve production. Baytex has demonstrated that CSS can be utilized to extract reserves which are not producible through primary production techniques. If supported by commodity prices, our Cliffdale CSS project, which was suspended in Q3 2015, could be reactivated with minimal expenditure.
Subsequent to year-end 2016, Baytex completed the acquisition of an additional 392 net sections of oil sands leases adjacent to our current oil sands leases, including 219,520 net acres of undeveloped land, along with associated production of approximately 3,000 boe/d.
Conventional Business Unit
The Conventional Business Unit produces light oil, natural gas and natural gas liquids from various fields in northern, southeast and central Alberta. This production accounted for approximately 12% of total Baytex production in 2016. During 2016, production from this business unit averaged 8,419 boe/d which was comprised of 2,675 bbl/d of light oil and NGL and 34,453 Mcf/d of natural gas. At year-end 2016, we had 139,313 net acres of undeveloped land in this business unit
The following is a brief description of the principal property within the Conventional Business Unit:
Pembina, Alberta: Baytex acquired its initial position in Pembina in 2007 and further expanded its presence in the area through the acquisition of Burmis Energy Inc. in 2008. Production is primarily from the Cretaceous and Jurassic age formations, including the Cardium, Notikewin, Falher, Ellerslie, Glauconite, Rock Creek and Nordegg. Baytex's oil production in this area is treated at third party-operated oil batteries. Natural gas production is delivered to a combination of four mid-stream gas processing facilities and two producer-operated gas processing facilities. Baytex owns a working interest in one of the midstream-operated gas processing facilities. Production from this area during 2016 averaged 1,367 bbl/d of light oil and NGL and 26,799 Mcf/d of natural gas (5,834 boe/d). Baytex participated in the drilling of one (1.0 net) well in this area in 2016, resulting in one (1.0 net) natural gas well. This well was completed with multi-stage fracture stimulations. At year-end 2016, Baytex had 29,187 net undeveloped acres in this area.
United States Business Unit

On June 11, 2014, Baytex acquired an interest in approximately 80,200 (22,200 net) acres in the Sugarkane area located in South Texas in the core of the liquids-rich Eagle Ford shale through the acquisition of Aurora. In July 2016, we disposed of substantially all of our operated acreage, such that our assets now include non-operated working interests in approximately 79,000 (20,100 net) acres within the Eagle Ford, comprising four areas of mutual interest (Sugarloaf, Longhorn, Ipanema and Excelsior) in the Sugarkane area, together with interests in wells, field infrastructure and related assets. These assets are operated by Marathon Oil EF LLC, a wholly-owned subsidiary of Marathon Oil Corporation (NYSE: MRO), pursuant to the terms of industry-standard joint operating agreements.



39

Additional leasehold held in East Texas (2,327 net acres) does not meet Baytex’s development or economic criteria but will remain in inventory until the leases expire as their terms come due.

The following table sets forth our gross and net acreage for our United States assets as at December 31, 2016:
 
Gross Acreage
 
Net Acreage
Sugarloaf AMI
24,145

 
6,768

Longhorn AMI
31,034

 
9,886

Ipanema AMI
4,771

 
1,737

Excelsior AMI
19,085

 
1,745

Sugarkane area total:
79,035

 
20,136

Other Eagle Ford
87

 
87

East Texas (operated)
2,384

 
2,327

Total
81,506

 
22,550


The map below highlights the geographic location of our Eagle Ford properties and areas of mutual interest in the Sugarkane area:
eaglefordacreagenovember2016.jpg


40

Production from the non-operated assets is processed at 13 centralized processing facilities across the Sugarkane area, which provide the following capability:
•
infield gathering systems between well locations and these centralized facilities;
•
processing equipment for the treatment of natural gas and compression allowing injection into the transportation system that moves the product to gas processing plants where NGLs are separated from the gas;
•
processing equipment for oil treatment and on site storage in preparation for either injection into oil pipelines that have contracted volumes or for export via trucks to refineries;
•
saline water wells, centralized ponds, and a buried distribution network allowing water to be sent to fracture locations throughout our leasehold interests in the Sugarkane area; and
•
gas lift capability and distribution network to sustain production once wells no longer flow via natural reservoir energy.
During 2016, production from the United States Business Unit averaged approximately 28,046 bbl/d of tight oil and NGL and 51,167 Mcf/d of shale gas (36,573 boe/d). During this period, Baytex participated in the drilling of 127 (36.9 net) wells in the Sugarkane area, resulting in 43 (12.8 net) oil wells and 84 (24.1 net) natural gas wells for a success rate of 100%.
Average Production
The following table indicates our average daily production from our principal properties for the year ended December 31, 2016.
 
Heavy Oil
(bbl/d)

 
Bitumen
(bbl/d)

 
Light and Medium Oil
(bbl/d)

 
Tight Oil
(bbl/d)

 
NGL
(bbl/d)

 
Shale Gas
(Mcf/d)

 
Natural Gas
(Mcf/d)

 
Oil Equivalent
(boe/d)

Lloydminster Business Unit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cold Lake / Ardmore
608

 
—

 
—

 
—

 
—

 
—

 
365

 
669

Soda Lake
2,095

 
—

 
—

 
—

 
—

 
—

 
108

 
2,113

Celtic
1,377

 
—

 
—

 
—

 
—

 
—

 
—

 
1,377

Kerrobert / Hoosier
858

 
1,544

 
5

 
—

 
—

 
—

 
20

 
2,410

Tangleflags
1,858

 
—

 
—

 
—

 
—

 
—

 
464

 
1,935

Remaining properties
1,595

 
 
 
—

 
—

 
—

 
—

 
425

 
1,666

Total
8,391

 
1,544

 
5

 
—

 
—

 
—

 
1,382

 
10,170

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Peace River Business Unit
13,651

 
—

 
—

 
—

 
—

 
—

 
4,180

 
14,348

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Conventional Business Unit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pembina
—

 
—

 
186

 
—

 
1,181

 
 
 
26,799

 
5,834

Remaining properties
—

 
—

 
1,216

 
—

 
93

 
—

 
7,654

 
2,585

Total
—

 
—

 
1,402

 
—

 
1,274

 
—

 
34,453

 
8,419

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Business Unit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sugarkane (non-operated)
—

 
—

 
—

 
19,497

 
8,013

 
50,720

 
—

 
35,963

Sugarkane (operated)(1)
—

 
—

 
—

 
473

 
62

 
447

 
—

 
610

Total
—

 
—

 
—

 
19,970

 
8,075

 
51,167

 
—

 
36,573

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Grand Total
22,042

 
1,544

 
1,407

 
19,970

 
9,349

 
51,167

 
40,015

 
69,510

Note:
(1)
This property was sold in July of 2016.


41



Costs Incurred
The following table summarizes the property acquisition, exploration and development costs by country for the year ended December 31, 2016:
($000s)
 
Canada

 
United States

 
Total

 
 
 
 
 
 
 
Property acquisition costs
 
 
 
 
 
 
Proved properties
 
54

 
—

 
54

Unproved properties
 
102

 
—

 
102

Property disposition
 
(9,039
)
 
(54,237
)
 
(63,276
)
Total Property acquisition costs, net
 
(8,883
)
 
(54,237
)
 
(63,120
)
 
 
 
 
 
 
 
Development Costs(1)
 
21,184

 
198,910

 
220,094

Exploration Costs(2)
 
4,689

 
—

 
4,689

Total
 
16,990

 
144,673

 
161,663

Notes:

(1)
Development and facilities expenditures.
(2)
Cost of geological and geophysical capital expenditures and drilling costs for 2016 exploratory wells drilled.
Oil and Gas Wells
The following table sets forth the number and status of wells in which we have a working interest as at December 31, 2016.
 
Oil Wells
 
Natural Gas Wells
 
Producing
 
Non-Producing
 
Producing
 
Non-Producing
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alberta
855

 
566.1

 
1,037

 
590.4

 
354

 
276.8

 
496

 
387.6

Saskatchewan
577

 
559.8

 
1,374

 
1,312.0

 
16

 
13.2

 
128

 
115.2

Texas
550

 
126.0

 
19

 
3.9

 
320

 
87.0

 
43

 
13.0

Total
1,982

 
1,251.9

 
2,430

 
1,906.3

 
690

 
377.0

 
667

 
515.8

Undeveloped Land Holdings
The following table sets forth our undeveloped land holdings as at December 31, 2016.
 
Undeveloped Acres
 
Gross
 
Net
Canada
 
 
 
Alberta
554,178

 
489,669

Saskatchewan
119,004

 
113,439

Total Canada
673,182

 
603,108

 
 
 
 
United States
 
 
 
Texas (Eagle Ford)
654

 
208

Texas (East Texas)
2,384

 
2,327

Total United States
3,038

 
2,535

 
 
 
 
Grand Total
676,220

 
605,643



42


We estimate the value of our net undeveloped land holdings at December 31, 2016 to be approximately $67.1 million, as compared to $110.3 million at December 31, 2015. This internal evaluation generally represents the estimated replacement cost of our undeveloped land. In determining replacement cost, we analyzed land sale prices paid at Provincial Crown and State land sales for properties in the vicinity of our undeveloped land holdings, less an allowance for near-term expiries.
We expect that rights to explore, develop and exploit approximately 12,655 net acres of our undeveloped land holdings (comprised of 1,474 net acres in the United States and 11,181 net acres in Canada) will expire on or before December 31, 2017. There are no reserves associated with the land holdings expected to expire by December 31, 2017. None of these undeveloped properties have high expected development or operating costs or contractual sales obligations to produce and sell at substantially lower prices than could be realized.
Exploration and Development Activities
The following table sets forth the gross and net exploratory and development wells in which we participated during the year ended December 31, 2016.
 
Exploratory Wells
 
Development Wells
 
Total Wells
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
 
 
 
 
 
 
 
 
 
 
 
Oil
—

 
—

 
57

 
15.8

 
57

15.78

15.8

Natural Gas
—

 
—

 
85

 
25.1

 
85

 
25.1

Evaluation
—

 
—

 
—

 
—

 
—

 
—

Service
—

 
—

 
—

 
—

 
—

 
—

Dry
—

 
—

 
—

 
—

 
—

 
—

Total
—

 
—

 
142

 
40.9

 
142

 
40.9


Tax Horizon
Baytex does not expect to pay any material cash income taxes prior to 2020. This estimate and any amount of income tax we may be required to pay in the future is highly sensitive to assumptions regarding commodity prices, production, funds from operations, capital expenditure levels and changes in governing tax laws. For additional information, see Note 15 of our audited consolidated financial statements for the year ended December 31, 2016 and the information under the headings "Income Taxes" and "Tax Pools" in our MD&A for the year ended December 31, 2016.
Production Estimates
The following table sets out the volumes of our working interest production estimated for the year ending December 31, 2016, which is reflected in the estimate of future net revenue disclosed in the forecast price tables contained under "Description of Our Business and Operations - Statement of Reserves Data and Other Oil and Gas Information - Disclosure of Reserves Data and Oil and Natural Gas Information".


43

 
Heavy Oil
(bbl/d)
 
Bitumen
(bbl/d)
 
Light and Medium Oil
(bbl/d)
 
Tight Oil
(bbl/d)
 
NGL
(bbl/d)
 
Shale Gas
(Mcf/d)
 
Natural Gas
(Mcf/d)
 
Oil Equivalent
(boe/d)
CANADA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Proved
18,971

 
734

 
996

 
—

 
1,033

 
—

 
33,132

 
27,257

Total Proved plus Probable
20,462

 
879

 
1,083

 
—

 
1,274

 
—

 
38,678

 
30,144

UNITED STATES
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Proved
—

 
—

 
—

 
10,566

 
17,752

 
36,708

 
13,816

 
36,739

Total Proved plus Probable
—

 
—

 
—

 
11,325

 
20,819

 
41,951

 
14,539

 
41,559

TOTAL
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Proved
18,971

 
734

 
996

 
10,566

 
18,786

 
36,708

 
46,948

 
63,996

Total Proved plus Probable
20,462

 
879

 
1,083

 
11,325

 
22,093

 
41,951

 
53,217

 
71,703


The two properties that account for 20% or more of the estimated 2017 production volumes are the Eagle Ford and Peace River (cold primary production). Estimated 2017 production volumes for Eagle Ford are 36,739 boe/d on a total proved basis and 41,559 boe/d on a total proved plus probable basis. Estimated 2017 production volumes for Peace River (cold primary production) are 13,327 boe/d on a total proved basis and 13,878 boe/d on a total proved plus probable basis.

Production History
The following table summarizes certain information in respect of the production, product prices received, royalties paid, production costs and resulting netback associated with our reserves data for the periods indicated below.
 
Three Months Ended
 
Year Ended

 
Dec. 31, 2016

 
Sept 30, 2016

 
June 30, 2016

 
Mar. 31, 2016

 
Dec. 31, 2016

 
 
 
 
 
 
 
 
 
 
Average Sales Volume (1)
 
 
 
 
 
 
 
 
 
  Heavy Oil (bbl/d)
21,696

 
22,663

 
20,768

 
23,040

 
22,042

  Bitumen (bbl/d)
1,286

 
1,469

 
1,655

 
1,767

 
1,544

  Light Oil (bbl/d)
1,281

 
1,321

 
1,461

 
1,566

 
1,406

  NGL (bbl/d)
8,319

 
9,149

 
9,834

 
10,109

 
9,349

  Tight Oil (bbl/d)
18,882

 
17,680

 
20,433

 
22,923

 
19,970

  Shale Gas (Mcf/d)
45,228

 
47,468

 
55,859

 
56,217

 
51,167

  Natural Gas (Mcf/d)
36,804

 
41,846

 
39,422

 
42,003

 
40,015

Total (boe/d)
65,136

 
67,167

 
70,031

 
75,776

 
69,509

 
 
 
 
 
 
 
 
 
 
Average Net Production Prices Received
 
 
 
 
 
 
 
 
  Heavy Oil ($/bbl)
34.19

 
29.65

 
30.00

 
12.55

 
26.41

  Bitumen ($/bbl)
36.80

 
31.90

 
31.19

 
12.46

 
27.20

  Light Oil ($/bbl)
55.16

 
48.51

 
47.24

 
35.89

 
46.21

  NGL ($/bbl)
22.64

 
14.96

 
13.28

 
18.38

 
17.16

  Tight Oil ($/bbl)
60.45

 
53.60

 
52.79

 
38.11

 
50.60

  Shale Gas ($/Mcf)
4.28

 
3.70

 
2.39

 
2.76

 
3.21

  Natural Gas ($/Mcf)
2.78

 
2.11

 
1.30

 
1.91

 
2.01

Total ($/boe)
38.16

 
31.73

 
30.52

 
21.93

 
30.29

 


44

Royalties Paid
 
 
 
 
 
 
 
 
 
  Heavy Oil ($/bbl)
6.51

 
5.05

 
3.44

 
1.10

 
4.01

  Bitumen ($/bbl)
2.54

 
2.20

 
0.78

 
0.59

 
1.43

  Light Oil and NGL ($/bbl) (2)
4.48

 
3.99

 
4.69

 
4.10

 
4.32

  Tight Oil ($/bbl)
14.53

 
11.61

 
11.21

 
8.84

 
11.41

  Shale Gas ($/Mcf)
1.67

 
1.43

 
0.96

 
1.03

 
1.24

  Natural Gas ($/Mcf)
(0.13
)
 
0.02

 
0.02

 
0.09

 
—

Total ($/boe)
9.28

 
7.37

 
6.65

 
5.02

 
7.00

 
 
 
 
 
 
 
 
 
 
Operating Expenses (3)
 
 
 
 
 
 
 
 
 
  Heavy Oil ($/bbl)
13.42

 
12.40

 
10.60

 
11.02

 
11.87

  Bitumen ($/bbl)
18.53

 
16.83

 
14.59

 
14.70

 
15.98

  Light Oil and NGL ($/bbl) (2)
11.57

 
11.59

 
10.80

 
10.27

 
11.04

  Tight Oil ($/bbl) (4)
6.98

 
5.82

 
6.88

 
9.38

 
7.36

  Shale Gas ($/Mcf) (4)
1.16

 
0.97

 
1.15

 
1.56

 
1.23

  Natural Gas ($/Mcf)
1.91

 
1.90

 
1.77

 
1.69

 
1.82

Total ($/boe)
9.96

 
9.07

 
8.67

 
10.11

 
9.46

 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Year Ended

 
Dec. 31, 2016

 
Sept 30, 2016

 
June 30, 2016

 
Mar. 31, 2016

 
Dec. 31, 2016

Transportation Expenses
 
 
 
 
 
 
 
 
 
  Heavy Oil ($/bbl)
3.27

 
3.43

 
2.02

 
2.64

 
2.86

  Bitumen ($/bbl)
1.49

 
1.73

 
1.72

 
0.24

 
1.25

  Light Oil and NGL ($/bbl) (2)
1.11

 
1.08

 
1.19

 
1.18

 
1.14

  Tight Oil ($/bbl) (4)
—

 
—

 
—

 
—

 
—

  Shale Gas ($/Mcf) (4)
—

 
—

 
—

 
—

 
—

  Natural Gas ($/Mcf)
1.47

 
1.41

 
1.29

 
1.38

 
1.39

Total ($/boe)
1.30

 
1.38

 
0.81

 
0.98

 
1.11

 
 
 
 
 
 
 
 
 
 
Netback Received (5)
 
 
 
 
 
 
 
 
 
  Heavy Oil ($/bbl)
10.99

 
8.77

 
13.94

 
(2.21
)
 
7.67

  Bitumen ($/bbl)
14.24

 
11.14

 
14.10

 
(3.07
)
 
8.54

  Light Oil and NGL ($/bbl) (2)
19.49

 
16.97

 
17.24

 
11.60

 
16.19

  Tight Oil ($/bbl)
38.94

 
36.17

 
34.70

 
19.89

 
31.83

  Shale Gas ($/Mcf)
1.45

 
1.30

 
0.28

 
0.17

 
0.74

  Natural Gas ($/Mcf)
(0.47
)
 
(1.22
)
 
(1.78
)
 
(1.25
)
 
(1.20
)
Total ($/boe)
17.62

 
13.91

 
14.39

 
5.82

 
12.72

Other income ($/boe)
—

 
—

 
—

 
—

 
—

Financial Derivatives gain (loss) ($/boe)
1.62

 
3.04

 
3.74

 
6.47

 
3.81

Netback Received after hedging ($/boe)
19.24

 
16.95

 
18.13

 
12.29

 
16.53

Notes:
(1)
Before deduction of royalties.
(2)
All NGL volumes are grouped with Canadian light oil for royalties paid and operating expenses for reporting purposes.
(3)
Operating expenses are composed of direct costs incurred to operate both oil and gas wells. A number of assumptions are required to allocate these costs between oil, natural gas and NGL production.
(4)
Transportation expenses split for costs between tight oil and shale gas are not available for Eagle Ford.
(5)
Netback is calculated by subtracting royalties, operating expenses and transportation expenses from revenues.


45

Marketing Arrangements

Baytex markets its oil and natural gas production with attention to maximizing value and counterparty performance. We maintain a portfolio of sales contracts with a variety of pricing mechanisms, term commitments and customers. We engage a number of reputable counterparties in our bid process to ensure competitiveness, while also managing counterparty credit exposure.
Oil and NGL
For the year ended December 31, 2016, the prompt price settlements of West Texas Intermediate crude oil fluctuated from a low of US$26.21/bbl in February to a high of US$54.06/bbl in late December, with an average price of US$43.33/bbl. The volatile price range seen in 2016 was driven by an ongoing global overhang of crude oil and petroleum product inventories as OPEC continued to favor a market share strategy for the majority of the year before coming to a new production quota agreement on November 30, 2016.

The discount for Canadian heavy oil, as measured by the Western Canadian Select ("WCS") price differential to WTI, averaged 32% for the year ended December 31, 2016, as compared to an average of 28% for the year ended December 31, 2015. The WCS nominal differential averaged US$13.84/bbl in 2016 as compared to US$13.52 in 2015.

For 2016, Baytex's heavy oil sales prices averaged $26.46/bbl, while light oil and condensate prices averaged $50.32/ bbl. In contrast, for 2015 Baytex averaged $32.23/bbl for heavy oil sales and $55.75/bbl for light oil and condensate sales. Baytex's NGL price in 2016 was $17.16/bbl, as compared with $16.91/bbl in 2015. In 2016, Baytex's U.S. light oil and condensate price realizations averaged $50.60/bbl, as compared to $55.99/bbl in 2015, as the average annual price for the WTI benchmark decreased by 11% from US$48.79/bbl in 2015 to US$43.33/bbl in 2016.

Natural Gas
For the year ended December 31, 2016, the average AECO natural gas price was $2.09/Mcf, as compared to $2.74/Mcf in the same period of 2015. The decrease in the natural gas price was due to high natural gas production growth in Canada and the U.S. For 2016, Baytex's average realized natural gas sales price was $2.69/Mcf, as compared to $3.08/Mcf in 2015.
Forward Contracts
For details on our contractual commitments to sell natural gas and crude oil which were outstanding at December 31, 2016, see Note 18 to our audited consolidated financial statements for the year ended December 31, 2016.
Environmental Policies
We have an active program to monitor and comply with all environmental laws, rules and regulations applicable to our operations. Our policies require that all employees and contractors report all breaches or potential breaches of environmental laws, rules and regulations to our senior management and all applicable governmental authorities. Any material breaches of environmental law, rules and regulations must be reported to the Board of Directors.




46

DIRECTORS AND OFFICERS
The following table sets forth the name, municipality of residence, age as at December 31, 2016, position held with Baytex and principal occupation of each of the directors and officers of Baytex.
Name and Municipality
of Residence
 
Age
 
Position with Baytex
 
Principal Occupation
 
 
 
 
 
 
 
James L. Bowzer(1)
Calgary, Alberta

 
56
 
Director and Chief Executive Officer
 
Chief Executive Officer of Baytex
John A. Brussa (4) (5)
Calgary, Alberta

 
59
 
Director
 
Vice Chairman of Burnet, Duckworth & Palmer LLP
Raymond T. Chan
Calgary, Alberta

 
61
 
Director and Chairman of the Board
 
Chairman of the Board of Baytex
Edward Chwyl (3) (4)
Victoria, B.C.

 
73
 
Director
 
Independent Businessman
Trudy M. Curran (2) (5)
Calgary, Alberta

 
54
 
Director
 
Corporate Director
Naveen Dargan (2) (3)
Calgary, Alberta

 
59
 
Director
 
Independent Businessman
R.E.T. (Rusty) Goepel (5)
Vancouver, B.C.

 
74
 
Director
 
Senior Vice President of Raymond James Ltd.
Gregory K. Melchin (2)(5)
Calgary, Alberta
 
63
 
Director
 
Independent Businessman
Mary Ellen Peters (2) (3)
Sarasota, Florida
 
60
 
Director
 
Independent Businesswoman
Dale O. Shwed (4)
Calgary, Alberta

 
58
 
Director
 
President and Chief Executive Officer of Crew Energy Inc.
Kendall D. Arthur(7)
Calgary, Alberta

 
36
 
Vice President, Lloydminster and Conventional Business Units

 
Vice President, Lloydminster and Conventional Business Units of Baytex
Geoffrey J. Darcy
Calgary, Alberta

 
54
 
Senior Vice President, Marketing
 
Senior Vice President, Marketing of Baytex
Murray J. Desrosiers
Calgary, Alberta
 
47
 
Vice President, General Counsel and Corporate Secretary
 
Vice President, General Counsel and Corporate Secretary of Baytex
Brian G. Ector
Calgary, Alberta

 
48
 
Senior Vice President, Capital Markets and Public Affairs

 
Senior Vice President, Capital Markets and Public Affairs of Baytex
Rodney D. Gray
Calgary, Alberta

 
45
 
Chief Financial Officer
 
Chief Financial Officer of Baytex
Cameron A. Hercus
Calgary, Alberta

 
47
 
Vice President, Corporate Development
 
Vice President, Corporate Development of Baytex
Ryan M. Johnson(7)
Calgary, Alberta

 
40
 
Vice President, Peace River Business Unit
 
Vice President, Peace River Business Unit of Baytex


47

Name and Municipality
of Residence
 
Age
 
Position with Baytex
 
Principal Occupation
Chad L. Kalmakoff
Calgary, Alberta

 
40
 
Vice President, Finance
 
Vice President, Finance of Baytex
Edward D. LaFehr(1)
Calgary, Alberta
 
57
 
President
 
President of Baytex
Richard P. Ramsay
Calgary, Alberta

 
53
 
Chief Operating Officer
 
Chief Operating Officer of Baytex
Gregory A. Sawchenko
Calgary, Alberta

 
44
 
Vice President, Land
 
Vice President, Land of Baytex
Gregory M. Zimmerman
Houston, Texas
 
58
 
Vice President, U.S. Business Unit
 
Vice President, U.S. Business Unit of Baytex
Notes:
(1)
On December 12, 2016, the Corporation announced that effective May 2017 James L. Bowzer will resign as Chief Executive Office and be succeeded by Edward D. LaFehr.
(2)    Member of our Audit Committee.
(3)    Member of our Compensation Committee.
(4)    Member of our Reserves Committee.
(5)    Member of our Nominating and Governance Committee.
(6)
Baytex's directors hold office until the next annual general meeting of Shareholders or until each director's successor is appointed or elected pursuant to the Business Corporations Act (Alberta).
(7)
Effective January 20, 2017, Kendall D. Arthur was given responsibility for the Conventional Business Unit which had previously been the responsibility of Ryan M. Johnson and Mr. Arthur's title was changed to Vice President, Lloydminster and Conventional Business Units and Mr. Johnson's title was changed to Vice President, Peace River Business Unit.
Listed below is a biographical description for each of our directors and officers, including their principal occupations during the five preceding years.
James L. Bowzer has served as Chief Executive Officer and as a director of Baytex since September 4, 2012. He also served as President from September 2012 to July 2016. Mr. Bowzer has over 30 years of global experience leading large organizations, directing new projects and developing successful leaders. From November 2008 to August 2012, he was Vice President, North American Production Operations for Marathon Oil Corporation ("Marathon") in Houston, Texas. In this role he was responsible for Marathon's expansive domestic portfolio, which included unconventional plays in the Bakken, Eagle Ford, Niobrara and Anadarko Woodford in the United States and heavy oil in Canada, and conventional plays in Alaska, Colorado, Louisiana, Oklahoma, Texas and Wyoming. From May 2006 to November 2008, Mr. Bowzer was Regional Vice President, International Production at Marathon where he was responsible for a diverse mix of significant businesses in Norway, the United Kingdom, Ireland and Africa. Prior thereto, he held senior positions at Marathon in strategic planning and business development. Mr. Bowzer has a Bachelor of Science degree in Petroleum Engineering from the University of Wyoming and completed the Advanced Management Program at the Graduate School of Business at Indiana University. He has served on the board of directors of several industry and professional associations, including a term on the Board of Directors for the University of Wyoming, School of Energy Resources.
John A. Brussa became a Director of Baytex on December 31, 2010 and served as a director of Baytex Energy from October 1997 to December 2014. He is the Vice Chairman of Burnet, Duckworth & Palmer LLP and focuses on tax law. He was admitted to the Alberta bar in 1982. He holds a Bachelor of Laws degree and a Bachelor of Arts, History and Economics degree from the University of Windsor.
Raymond T. Chan was appointed Chairman of the Board of Baytex on June 1, 2014. He originally joined Baytex in October 1998 and has held the following positions: Senior Vice President and Chief Financial Officer (October 1998 to August 2003); President (September 2003 to November 2007); Chief Executive Officer (September 2003 to December 2008); Interim Chief Executive Officer (May 2012 to September 2012) and Executive Chairman (January 2009 to May 2014). Mr. Chan served as a director of Baytex Energy from October 1998 to December 2014. Mr. Chan has held senior executive positions in the Canadian oil and gas industry since 1982, including chief financial officer titles at Tarragon Oil and Gas Limited, American Eagle Petroleums Ltd. and Gane Energy Corporation. Mr. Chan holds a Bachelor of Commerce degree and is a Chartered Accountant.


48

Edward Chwyl became a Director of Baytex on December 31, 2010 and served as a director of Baytex Energy from May 2003 to December 2014. Mr. Chwyl was Chairman of the Board of Directors of Baytex Energy from September 2003 to December 2008. He was appointed Lead Independent Director of Baytex on January 11, 2011 and held the same position with Baytex Energy from February 17, 2009 to December 19, 2014. He holds a Bachelor of Science degree in Chemical Engineering and a Master of Science degree in Petroleum Engineering. He is a retired businessman with over 35 years of experience in the oil and gas industry in North America, most notably as President and Chief Executive Officer of Tarragon Oil and Gas Limited from 1989 to 1998. Prior thereto, he held various technical and executive positions within the oil and gas industry in Canada and the United States.
Trudy M. Curran became a Director of Baytex on July 27, 2016 and is a retired businesswoman with extensive experience in executive compensation, mergers and acquisitions, financing and governance. She served as an officer of Canadian Oil Sands Limited from September 2002 to the time of its sale in February 2016. As Senior Vice President, General Counsel & Corporate Secretary of Canadian Oil Sands Limited, she was responsible for legal, human resources and administration and a member of the executive team focused on strategy and risk management. From 2003 to 2016, she was a director of Syncrude Canada Ltd., where she served as chair of the Human Resources and Compensation Committee and as a member of the Pension Committee. Ms. Curran is a director of Dominion Diamond Corporation and serves on the Executive Committee of the Calgary chapter of the Institute of Corporate Directors and is a member of the board and the Finance and Audit Committee of Kids Cancer Care Foundation of Alberta. Ms.Curran holds a Bachelor of Arts degree in English and a Bachelor of Laws degree (both with distinction) from the University of Saskatchewan and the ICD.D designation from the Institute of Corporate Directors.
Naveen Dargan became a Director of Baytex on December 31, 2010 and served as a director of Baytex Energy from September 2003 to December 2014. He has been an independent businessman since June 2003. Prior thereto, he worked for over 20 years in the investment banking business, finishing his investment banking career as Senior Managing Director and Head of Energy Investment Banking at Raymond James Ltd. Mr. Dargan is a director of Tervita Corporation. He holds a Bachelor of Arts (Honours) degree in Mathematics and Economics from Queen's University, a Master of Business Administration degree from the Schulich School of Business at York University and a Chartered Business Valuator designation.
R.E.T. (Rusty) Goepel became a Director of Baytex on December 31, 2010 and served as a director of Baytex Energy from May 2005 to December 2014. He is currently Senior Vice President for Raymond James Ltd. He commenced his career in investment banking in 1968 and was President and co-founder of Goepel Shields & Partners, which later became Goepel McDermid Ltd. and was acquired by Raymond James Ltd. in 2001. Mr. Goepel is a director of Telus Corporation. He is past Chairman of the Vancouver 2010 Winter Olympics and The Business Council of British Columbia. He is a recipient of the Queen's Gold and Diamond Jubilee Medals for service to the community, financial industry and business. Mr. Goepel holds a Bachelor of Commerce (Honours) degree from the University of British Columbia.
Gregory K. Melchin became a director of Baytex on December 31, 2010 and served as a director of Baytex Energy from May 2008 to December 2014. He is currently the Chairperson of the board of directors of Enmax Corporation, a municipally-owned utility. He was a member of the Legislative Assembly of Alberta from March 1997 to March 2008. Among his various assignments with the Government of Alberta, he was Minister of Energy, Minister of Seniors and Community Supports and Minister of Revenue. Prior to being elected to the Legislative Assembly of Alberta, he served in various management positions for 20 years in the Calgary business community. He holds a Bachelor of Science degree (major in accounting) and a Fellow Chartered Accountant designation from the Institute of Chartered Accountants of Alberta. He has also completed the Directors Education Program with the Institute of Corporate Directors.
Mary Ellen Peters became a Director of Baytex on July 1, 2013. She is a retired businesswoman with over 30 years of experience in the petroleum industry, most notably as Senior Vice President, Transportation and Logistics (2009-2010) and Senior Vice President, Marketing (1998-2009) at Marathon Petroleum Company, LP. Prior thereto, she held various technical and management positions with Marathon. Her previous board experience includes acting as Chairman of the Board of Managers for Louisiana Offshore Oil Port and as a director of Colonial Pipeline Company. She holds a Bachelor of Science degree (major in finance) and a Master of Business Administration degree. She has also completed executive management programs at Penn State University and Indiana University and the Oxford Energy Seminar
Dale O. Shwed became a Director of Baytex on December 31, 2010 and served as a director of Baytex Energy from June 1993 to December 2014. He has held the position of President and Chief Executive Officer of Crew Energy Inc., a public oil and gas company, since September 2003. Prior thereto, he was President and Chief Executive Officer of Baytex Energy from 1993 to August 2003. Mr. Shwed holds a Bachelor of Science degree specializing in Geology.


49

Kendall D. Arthur was appointed Vice President, Lloydminster Business Unit of Baytex on March 4, 2015 and became Vice President, Lloydminster and Conventional Business Units on February 20, 2017. Mr. Arthur has over 10 years of experience in the Canadian oil and gas industry.  He joined Baytex Energy in 2006 as a Production Engineer in the Heavy Oil Business Unit and held the position of Vice President, Saskatchewan Business Unit from January 2012 to March 2015.  Prior to joining Baytex, he held various technical production, completions and operations roles with Husky Energy.  Mr. Arthur received a Bachelor of Science degree in Mechanical Engineering from the University of Saskatchewan and is a practicing member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta.
Geoffrey J. Darcy was appointed Senior Vice President, Marketing of Baytex on May 21, 2014 and is responsible for maximizing the value of our products and managing our commodity price risk exposures. He joined Baytex in September 2011 and held the position of Vice President, Marketing from September 2011 to May 2014. Prior thereto, he was Director of North American Physical Crude Oil Trading for Barclays Bank. Mr. Darcy has over 25 years of experience in marketing, trading and crude oil supply in both Canada and the U.S. He was formerly Vice President of North American Crude Oil Marketing with Nexen Inc., and worked in crude oil supply for United Refining Company and Petro-Canada earlier in his career. Mr. Darcy holds a Bachelor of Commerce degree with Honours in Economics with Distinction from Concordia University and a Master of Business Administration from the University of Calgary.
Murray J. Desrosiers was appointed Vice President, General Counsel and Corporate Secretary of Baytex on October 22, 2010 and has held the same position with Baytex Energy since May 20, 2009. Mr. Desrosiers is a corporate lawyer with over 20 years of experience advising energy companies in the areas of corporate finance, mergers and acquisitions, corporate governance and securities compliance matters. He joined Baytex Energy in July 2008 and held the position of General Counsel from August 2008 to May 2009. Prior to joining Baytex Energy, he held senior legal positions with PrimeWest Energy Inc. (the operating company of PrimeWest Energy Trust), Shiningbank Energy Ltd. (the operating company of Shiningbank Energy Income Fund), Enbridge Inc. and Enbridge Management Services Inc. (the manager of Enbridge Income Fund). Mr. Desrosiers holds a Bachelor of Laws from the University of Alberta and a Bachelor of Commerce (Finance) from the University of Calgary and is a member of the Law Society of Alberta.
Brian G. Ector was appointed Senior Vice President, Capital Markets and Public Affairs of Baytex on May 21, 2014 and is responsible for Baytex's equity capital markets, investor relations and public affairs functions. He joined Baytex in November 2009 and has held the following positions: Director of Investor Relations (November 2009 to June 2011), Vice President, Investor Relations (June 2011 to March 2014) and Vice President, Capital Markets (April 2014 to May 2014). Prior to joining Baytex, Mr. Ector spent 15 years as a sell-side research analyst covering both energy trusts and exploration and production corporations. Mr. Ector received a Bachelor of Commerce degree with a concentration in finance from the University of Calgary and received his Chartered Financial Analyst designation in 1996. He is a national board member of the Canadian Investor Relations Institute as well as a member of the National Investor Relations Institute, the CFA Institute and the Calgary CFA Society.
Rodney D. Gray was appointed Chief Financial Officer of Baytex on April 7, 2014. Mr. Gray has over 20 years of experience in the oil and gas industry. Prior to joining Baytex, Mr. Gray held the position of Chief Financial Officer for CEDA International since July, 2013. Prior thereto, he spent eleven years with Enerplus Corporation, including the last eight as Vice President, Finance where he was responsible for corporate reporting, treasury and capital markets, operational accounting, business analysis, risk management and insurance. Mr. Gray is a Chartered Accountant and has a Bachelor of Commerce degree with Honours from Queen's University.
Cameron A. Hercus was appointed Vice President, Corporate Development of Baytex on May 21, 2013 and is responsible for evaluating acquisition opportunities and developing our long range growth plans. Mr. Hercus is a Petroleum Engineer with over 20 years of experience in the Canadian and European oil and gas industry. Prior to joining Baytex, he spent five years working with Vermilion Energy Inc. in business development, new ventures and exploitation roles evaluating and developing opportunities in Western Canada and Europe. Prior thereto, he worked with Marathon, Shell and Paladin Resources where he developed a strong background in reservoir engineering and field development while working in the UK North Sea. Mr. Hercus has a Bachelor of Science degree in Geology and Petroleum Geology (Honours) from the University of Aberdeen and completed a Master of Science degree in Petroleum Engineering from Heriot-Watt University in 1995.
Ryan M. Johnson was appointed Vice President, Peace River Business Unit of Baytex on February 20, 2017. Mr. Johnson joined Baytex in 2007 focusing on technical responsibilities in northeast Alberta and southern Saskatchewan, including the planning and execution of Baytex's thermal SAGD project at Kerrobert. In January 2011, he was appointed Senior Geologist of the Peace River region and has been an integral member of the team responsible for the planning, coordination and execution of multi-lateral exploitation and thermal development of this resource. In mid-2013, Mr. Johnson was appointed Lead Geologist and charged with managing all key activities across the entire Alberta/B.C. Business Unit. In May 2014,


50

Mr. Johnson was appointed Vice President, Alberta/B.C. Business Unit. Mr. Johnson has over 15 years of extensive technical and managerial roles in oil and gas exploration, development, operations and prospect identification. Mr. Johnson has a Bachelor of Science Degree (Honours) in Geology and Oceanography from the University of British Columbia and is a practicing member of the Association of Professional Engineers and Geoscientists of Alberta.
Chad L. Kalmakoff was appointed Vice President, Finance of Baytex on September 1, 2015. Mr. Kalmakoff has 15 years of experience in the oil and gas industry. Prior to joining Baytex, Mr. Kalmakoff was Vice President, Finance and Chief Financial Officer at Kicking Horse Energy Inc. from October 2014 to August 2015. From October 2013 to July 2014, he was Vice President, Finance and Chief Financial Officer at Corinthian Exploration Ltd. Prior thereto, he was Chief Financial Officer (March 2012 to March 2013) and Vice President, Finance (June 2006 to March 2012) at Pace Oil & Gas Ltd. and its predecessor, Midnight Oil Exploration Ltd. Mr. Kalmakoff is a Chartered Accountant and holds a Bachelor of Commerce from Dalhousie University.
Edward D. LaFehr joined Baytex as President on July 18, 2016 and has been an integral member of the executive leadership team holding responsibility for the Canadian and U.S. business operations and corporate development.  Mr. LaFehr will succeed Mr. Bowzer as Chief Executive Officer upon his expected retirement in May 2017.  Mr. LaFehr has nearly 35 years of experience in the oil and gas industry working with Amoco, BP, Talisman and the Abu Dhabi National Energy Company (“TAQA”) in various geographies.  Before joining Baytex, Mr. LaFehr was President of TAQA’s North American oil and gas business which led to his subsequent role as Chief Operating Officer of TAQA, globally.  Prior to this, he served as Senior Vice President for Talisman Energy, accountable for its Canadian business.  Mr. LaFehr has a long track record of success in the oil and gas industry leading organizations, growing assets and joint ventures and driving capital and cost efficiencies.  Mr. LaFehr holds Master’s degrees in geophysics and mineral economics from Stanford University and the Colorado School of Mines, respectively.
Richard P. Ramsay was appointed Chief Operating Officer of Baytex on May 21, 2014. He originally joined Baytex in January 2010 and has held the following positions: Vice President, Heavy Oil (January 2010 to January 2012) and Vice President, Alberta/B.C. Business Unit (January 2012 to May 2014). Mr. Ramsay has over 25 years of experience in the Canadian oil and gas industry and was formerly Chief Operating Officer of TAQA North Ltd. He previously held a variety of technical and management positions with Northrock Resources Ltd., Fletcher Challenge Energy Canada Inc., Amoco Canada Petroleum Ltd. and Dome Petroleum Ltd. Mr. Ramsay has a Bachelor of Science degree with Distinction in Mechanical Engineering from the University of Saskatchewan and is a practicing member of the Association of Professional Engineers and Geoscientists of Alberta.
Gregory A. Sawchenko was appointed Vice President, Land of Baytex on August 12, 2013. Mr. Sawchenko has over 15 years of experience in oil and gas land management and negotiations. Prior to joining Baytex, he was most recently the Land Manager for Crescent Point Energy Corp. At Crescent Point, Mr. Sawchenko was an instrumental member in many key transactions and contributed to the growth of the company. Early in his career, he held positions with successive levels of responsibility at Numac Energy Inc., Anderson Exploration Ltd., Devon Canada Corporation and EnCana Corporation. Mr. Sawchenko holds a Bachelor of Commerce degree from the University of Calgary with a designation in Petroleum Land Management and is a member of the Canadian Association of Petroleum Landmen.
Gregory M. Zimmerman was appointed Vice President, U.S. Business Unit of Baytex on November 16, 2015. In this role he is also President of Baytex's primary U.S. operating entity, Baytex Energy USA, Inc., which is based in Houston, Texas. Mr. Zimmerman has over 30 years of experience in the oil and gas industry all with Marathon Oil Corporation. At Marathon, he held a number of positions of increasing responsibility in production, operations, reservoir and business development. His most recent positions included Director of Corporate Reserves in Houston, Texas and Vice President, Oil Sands Development in Calgary, Alberta. His primary area of focus over the last 20 years of his career with Marathon has been asset management, reservoir development and project execution. Mr. Zimmerman has a Bachelor of Science degree in Mechanical Engineering from Texas A&I University.
Ownership of Securities by Management
As at March 1, 2017, the directors and officers of Baytex, as a group, beneficially owned, or controlled or directed, directly or indirectly, 3,362,038 Common Shares, representing approximately 1.436 percent of the issued and outstanding Common Shares and $80,000 principal amount of 2022 Debentures.


51

Corporate Cease Trade Orders, Bankruptcies or Penalties or Sanctions
Other than as disclosed below, no director or executive officer of Baytex (nor any personal holding company of any of such persons) is, as of the date of this Annual Information Form, or was within ten years before the date of this Annual Information Form, a director, chief executive officer or chief financial officer of any company (including Baytex), that was subject to a cease trade order (including a management cease trade order), an order similar to a cease trade order or an order that denied the relevant company access to any exemption under securities legislation, in each case that was in effect for a period of more than 30 consecutive days (collectively, an "Order") that was issued while the director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer or was subject to an order that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer.
Mr. Brussa, a director of Baytex, was formerly a director of Calmena Energy Services Inc. (a public oilfield service company) which was placed in receivership on January 20, 2015, Enseco Energy Service Corp. (a public oilfield equipment supplier) which was placed in receivership on October 14, 2015, Argent Energy Ltd., the administrator of Argent Energy Trust (a public trust holding investments in oil and gas exploration and production companies) which received protection from its creditors pursuant the Companies' Creditors Arrangement Act in Canada and Chapter 15 of the United States Bankruptcy Code on March 19, 2016 and Twin Butte Energy Ltd. (a public oil and gas exploration and production company) which was placed in receivership on September 1, 2016.  Mr. Brussa resigned as a director of Calmena on June 30, 2014, Enseco on October 14, 2015, Argent on June 30, 2016 and Twin Butte on September 1, 2016.
Mr. Dargan, a director of Baytex, was formerly a director of Tervita Corporation (a private environmental solutions company). Tervita made a proposal under the Canada Business Corporations Act on September 14, 2016 and a voluntary filing under Chapter 15 of the United States Bankruptcy Code on October 20, 2016, which resulted in a plan of arrangement under the Canada Business Corporations Act. Mr. Dargan resigned as a director of Tervita on December 13, 2016.
No director or executive officer of Baytex (nor any personal holding company of any of such persons), or shareholder holding a sufficient number of our securities to materially affect control of us, is, as of the date of this Annual Information Form, or has been within the ten years before the date of this Annual Information Form, a director or executive officer of any company (including Baytex) that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver-manager or trustee appointed to hold its assets or has, within the ten years before the date of this Annual Information Form, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver-manager or trustee appointed to hold the assets of the director, executive officer or shareholder.
In addition, no director or executive officer of Baytex (nor any personal holding company of any of such persons), or shareholder holding a sufficient number of our securities to materially affect control of us, has been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority or any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.
Conflicts
There are potential conflicts of interest to which the directors and officers of Baytex will be subject in connection with the operations of Baytex. In particular, certain of the directors and officers of Baytex are involved in managerial or director positions with other oil and gas companies whose operations may, from time to time, be in direct competition with those of Baytex or with entities which may, from time to time, provide financing to, or make equity investments in, competitors of Baytex. Conflicts, if any, will be subject to the procedures and remedies available under the Business Corporations Act (Alberta). The Business Corporations Act (Alberta) provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director will disclose his interest in such contract or agreement and will refrain from voting on any matter in respect of such contract or agreement unless otherwise provided in the Business Corporations Act (Alberta).




52

AUDIT COMMITTEE INFORMATION
Audit Committee Mandate and Terms of Reference
The text of the Audit Committee’s Mandate and Terms of Reference is attached as Appendix D.
Composition of the Audit Committee
The members of our Audit Committee are Trudy M. Curran, Naveen Dargan, Gregory K. Melchin and Mary Ellen Peters, each of whom is "independent" and "financially literate", with the meaning of National Instrument 52-110 "Audit Committees". The relevant education and experience of each Audit Committee member is outlined below:
Name
 
Independent
 
Financially Literate
 
Relevant Education and Experience
Trudy M. Curran
 
Yes
 
Yes
 
Bachelor of Arts degree in English and a Bachelor of Laws degree (both with distinction) from the University of Saskatchewan and the ICD.D designation from the Institute of Corporate Directors. Independent businesswoman since February 2016; prior thereto, Senior Vice President, General Counsel and Corporate Secretary of Canadian Oil Sands Limited since September 2002.
 
Naveen Dargan 
 
Yes
 
Yes
 
Bachelor of Arts (Honours) degree in Mathematics and Economics, Master of Business Administration degree and Chartered Business Valuator designation. Independent businessman since June 2003; prior thereto Senior Managing Director and Head of Energy Investment Banking of Raymond James Ltd.
 
Gregory K. Melchin
 
Yes
 
Yes
 
Bachelor of Science degree (major in accounting) and a Fellow Chartered Accountant designation from the Institute of Chartered Accountants of Alberta. Also completed the Directors Education Program with the Institute of Corporate Directors. Member of the Legislative Assembly of Alberta from March 1997 to March 2008. Prior to being elected to the Legislative Assembly of Alberta, served in various management positions for 20 years in the Calgary business community.
 
Mary Ellen Peters
 
Yes
 
Yes
 
Bachelor of Science degree (major in finance) and a Master of Business Administration degree. Also completed the Penn State Executive Leadership Program. Retired businesswoman with over 30 years of experience in the petroleum industry, most notably as Senior Vice President, Transportation and Logistics (2009-2010) and Senior Vice President, Marketing (1998-2009) at Marathon Petroleum Company, LP.
 

Pre-Approval of Policies and Procedures
Although the Audit Committee has not adopted specific policies and procedures for the engagement of non-audit services by our auditors, it does pre-approve all non-audit services to be provided to us and our subsidiaries by the external auditors. The pre-approval for recurring services, such as preliminary work on the integrated audit, securities filings, translation of our financial statements and related MD&A into the French language and tax and tax-related services, is provided on an annual basis and other services are subject to pre-approval as required.


53

External Auditor Service Fees
The following table provides information about the fees billed to us and our subsidiaries for professional services rendered by our external auditors, during fiscal 2016 and 2015:
 
Aggregate fees billed ($000s)
 
2016
 
2015
Audit Fees
$
662

 
$
1,018

Audit-Related Fees
115

 
201

Tax Fees
13

 
-

All Other Fees
-

 
-

Total
$
790

 
$
1,219


Audit Fees: Audit fees consist of fees for the audit of our annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements. In addition to the fees for annual audits of financial statements and review of quarterly financial statements, services in this category for fiscal 2016 and 2015 also include amounts for audit work performed in relation to the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 relating to internal control over financial reporting.
Audit-Related Fees: Audit-related fees consist of fees for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements (including fees paid to the Canadian Public Accountability Board) and are not reported as Audit Fees. Audit-related fees also include reviews of prospectuses related to two public offerings of common shares, one in 2016 and the other in 2015.
Tax Fees: Tax fees included tax planning and various taxation matters.
DIVIDENDS
Dividend Policy
We do not currently pay a dividend and do not currently have any plans to resume the payment of cash dividends. Any dividends declared in the future will be subject to review by the Board of Directors taking into account our prevailing financial circumstances at the relevant time and any amount distributed in the future will depend on numerous factors, including profitability, debt covenants and obligations, fluctuations in working capital, the timing and amount of capital expenditures, applicable law and other factors beyond our control.
In addition, the payment of dividends by us is governed by the liquidity and insolvency tests described in the ABCA. 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.  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 our ability to fulfill our obligations under the Credit Facilities or under any hedge agreements with lenders (or their affiliates) under the Credit Facilities. The indentures governing our Senior Notes also contain certain limitations on restricted payments. Restricted payments include the declaration or payment of any dividend or distribution by us. For full particulars of the covenants, reference should be made to the indentures governing our Senior Notes and to our Credit Facilities, copies of which are accessible on the SEDAR website, see "Material Contracts" for further details.


54

Record of Dividends and Distributions
We did not pay any dividends in 2016. In 2015, we paid a monthly dividend on our Common Shares of $0.10 from January until August, for an aggregate dividend per Common Share of $0.80. In 2014, we paid a monthly dividend on our Common Shares of $0.22 from January until May, $0.24 from June until November and $0.10 for December, for an aggregate dividend per Common Share of $2.64. Unless otherwise indicated, all dividends paid on our Common Shares were designated as "eligible dividends" for Canadian income tax purposes.
DESCRIPTION OF CAPITAL STRUCTURE
Share Capital
Baytex is authorized to issue 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. As at the date of this Annual Information Form, there were no preferred shares outstanding.
The following is a summary of certain provisions of the share capital of Baytex. For a complete description of the share provisions, reference should be made to the Articles of Incorporation of Baytex, a copy of which is accessible on the SEDAR website at www. sedar.com (filed on January 10, 2011).
Common Shares
Holders of Common Shares are entitled to notice of, to attend and to one vote per share held at any meeting of the shareholders of the Corporation (other than meetings of a class or series of shares of the Corporation 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 shares of the Corporation 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 the Corporation, whether voluntary or involuntary, or any other distribution of the assets of the Corporation among its shareholders for the purpose of winding-up its affairs, and subject to prior satisfaction of all preferential rights to return of capital on dissolution attached to all shares of other classes of shares of the Corporation ranking in priority to the Common Shares in respect of return of capital on dissolution, to share rateably, together with the holders of shares of any other class of shares of the Corporation ranking equally with the Common Shares in respect of return of capital on dissolution, in such assets of the Corporation as are available for distribution.
Preferred Shares
The preferred shares may be issued in one or more series, at any time or from time to time. Before any shares of a particular series are issued, the Board of Directors will fix the number of shares that will form such series and will, subject to the limitations set out in the preferred share terms described below, fix the designation, rights, privileges, restrictions and conditions to be attached to the preferred shares of such series, including, but without in any way limiting or restricting the generality of the foregoing, the rate, amount or method of calculation of dividends thereon, the time and place of payment of dividends, the consideration for and the terms and conditions of any purchase for cancellation, retraction or redemption thereof, conversion or exchange rights (if any), and whether into or for securities of Baytex or otherwise, voting rights attached thereto (if any), the terms and conditions of any share purchase or retirement plan or sinking fund, and restrictions on the payment of dividends on any shares other than preferred shares or payment in respect of capital on any shares in the capital of Baytex or creation or issue of debt or equity securities; the whole subject to filing of Articles of Amendment setting forth a description of such series including the designation, rights, privileges, restrictions and conditions attached to the shares of such series. Notwithstanding the foregoing: (a) the Board of Directors may at any time or from time to time change the rights, privileges, restrictions and conditions attached to unissued shares of any series of preferred shares; and (b) other than in the case of a failure to declare or pay


55

dividends specified in any series of the Preferred Share, the voting rights attached to the preferred shares will be limited to one vote per Preferred Share at any meeting where the preferred shares and Common Shares vote together as a single class.
The preferred shares of each series will rank equally with the preferred shares of every other series with respect to accumulated dividends and return of capital. The preferred shares will be entitled to a preference over the Common Shares and over any other shares of Baytex ranking junior to the preferred shares with respect to priority in the payment of dividends and in the distribution of assets in the event of the liquidation, dissolution or winding-up of Baytex, whether voluntary or involuntary, or any other distribution of the assets of Baytex among its shareholders for the purpose of winding-up its affairs. If any cumulative dividends or amounts payable on a return of capital are not paid in full, the preferred shares of all series will participate rateably in respect of such dividends, including accumulations, if any, in accordance with the sums that would be payable on such shares if all such dividends were declared and paid in full, and in respect of any repayment of capital in accordance with the sums that would be payable on such repayment of capital if all sums so payable were paid in full; provided, however, that in the event of there being insufficient assets to satisfy in full all such claims as aforesaid, the claims of the holders of the preferred shares with respect to repayment of capital will first be paid and satisfied and any assets remaining thereafter shall be applied towards the payment in satisfaction of claims in respect of dividends. The preferred shares of any series may also be given such other preferences not inconsistent with the terms of the preferred shares over the Common Shares and any other shares ranking junior to the preferred shares as may be determined in the case of each such series of preferred shares.
The rights, privileges, restrictions and conditions attaching to the preferred shares may be repealed, altered, modified, amended or amplified or otherwise varied only with the sanction of the holders of the preferred shares given in such manner as may then be required by law, subject to a minimum requirement that such approval be given by resolution passed by the affirmative vote of at least two-thirds of the votes cast at a meeting of holders of preferred shares duly called for such purpose and held upon at least 21 days' notice at which a quorum is present comprising at least two persons present, holding or representing by proxy at least 10 percent of the outstanding preferred shares or by a resolution in writing of all holders of the outstanding preferred shares. If any such quorum is not present within half an hour after the time appointed for the meeting, then the meeting shall be adjourned to a date being not less than seven days later and at such time and place as may be appointed by the chairman and at such meeting a quorum will consist of that number of shareholders present in person or represented by proxy. The formalities to be observed with respect to the giving of notice of any such meeting or adjourned meeting and the conduct thereof shall be those which may from time to time be prescribed in the by-laws of Baytex with respect to meetings of Shareholders. On every vote taken at every such meeting or adjourned meeting each holder of a Preferred Share shall be entitled to one vote in respect of each one dollar of stated value of preferred shares held.
Senior Notes
On February 17, 2011, we issued US$150 million principal amount of 6.75% series B senior unsecured debentures due February 21, 2021. The 2021 Debentures pay interest semi-annually and are redeemable at the Company's option, in whole or in part, commencing on February 17, 2016 at the redemption prices specified in Debt Indenture #1.
On July 19, 2012, we issued $300 million principal amount of 6.625% series C senior unsecured debentures due July 19, 2022. The 2022 Debentures pay interest semi-annually and are redeemable at the Company's option, in whole or in part, commencing on July 19, 2017 at the redemption prices specified in Debt Indenture #1.
On June 6, 2014, we issued US$800 million of senior unsecured notes, comprised of US$400 million of 5.125% notes due June 1, 2021 and US$400 million of 5.625% notes due June 1, 2024. The 2021 Notes and the 2024 Notes pay interest semi-annually and are redeemable at the Company's option, in whole or in part, commencing on June 1, 2017 (in the case of the 2021 Notes) and June 1, 2019 (in the case of the 2024 Notes) at the redemption prices specified in Debt Indenture #2.
For a complete description of the Senior Notes, reference should be made to the applicable debt indenture, copies of which are accessible on the SEDAR website at www.sedar.com. See "Material Contracts".


56

Credit Facilities
Our Credit Facilities consist of: (i) a US$25 million operating loan and a US$350 million syndicated loan for Baytex and (ii) a US$200 million syndicated loan for Baytex USA. The Credit Facilities are secured and have an extendible four-year term that, unless extended by the lenders, will mature on June 4, 2019. For additional details regarding the covenants in our Credit Facilities and our compliance therewith, see our MD&A for the year ended December 31, 2016. Also see "Material Contracts".
MARKET FOR SECURITIES
The Common Shares are listed and posted for trading on the TSX and the NYSE under the trading symbol "BTE". The following table outlines the share price trading range and volume of shares traded by month in 2016.
 
Canada Composite Trading
 
United States Composite Trading
 
Price Range
 
 
 
Price Range
 
 
 
High
($)
 
Low
($)
 
Volume
Traded
 
High
(US$)
 
Low
(US$)
 
Volume
Traded
 
 
 
 
 
 
 
 
 
 
 
 
2016
 
 
 
 
 
 
 
 
 
 
 
January
4.75
 
1.57
 
242,626,409
 
3.42
 
1.08
 
50,460,811
February
3.19
 
2.21
 
205,306,028
 
2.35
 
1.59
 
36,854,592
March
5.39
 
3.03
 
321,616,827
 
4.15
 
2.24
 
66,736,803
April
6.80
 
4.84
 
239,995,241
 
5.41
 
3.67
 
56,168,254
May
6.50
 
5.71
 
213,423,776
 
5.12
 
4.42
 
58,435,698
June
9.04
 
6.15
 
268,665,034
 
7.14
 
4.68
 
83,910,507
July
7.72
 
5.57
 
180,268,166
 
6.18
 
4.25
 
55,682,798
August
7.24
 
5.52
 
208,458,282
 
5.64
 
4.19
 
55,119,223
September
6.37
 
4.76
 
222,134,067
 
4.95
 
4.70
 
58,181,674
October
6.09
 
5.12
 
175,777,649
 
4.61
 
3.81
 
46,036,356
November
5.80
 
4.84
 
220,330,400
 
4.33
 
3.60
 
70,199,063
December
7.35
 
5.78
 
195,005,636
 
5.61
 
4.35
 
70,187,329

RATINGS
The following information relating to our credit ratings is provided as it relates to our financing costs, liquidity and operations. Specifically, credit ratings affect our ability to obtain short-term and long-term financing and the cost of such financing.  A reduction in our current credit ratings by the rating agencies, particularly a downgrade below the current ratings or a negative change in the ratings outlook, could adversely affect our cost of financing and our access to sources of liquidity and capital. In addition, changes in credit ratings may affect our ability and the associated costs to (i) enter into ordinary course derivative or hedging transactions and may require us to post additional collateral under certain of our contracts, and (ii) enter into and maintain ordinary course contracts with customers and suppliers on acceptable terms.
Baytex has been assigned a corporate credit rating of BB- with a negative outlook and our Senior Notes have been assigned a credit rating of BB- by Standard and Poor's Rating Services, a division of McGraw-Hill Companies (Canada) Corporation ("S&P"). S&P's credit ratings are on a long-term debt rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. According to the S&P rating system, debt rated ''BB'' is considered less vulnerable to non-payment than other speculative issues, however it faces ongoing uncertainties or exposure to adverse business, financial, or economic conditions which could lead to the obligor's inability to meet its financial obligations. The ratings from AA to CCC may be modified by the addition of a plus (+) or a minus (-) sign to show relative standing within the major rating categories. In addition, S&P may add a rating


57

outlook of "positive", "negative" or "stable" which assesses the potential direction of a long-term credit rating over the intermediate term (typically six months to two years).
Moody's Investor Service Inc. ("Moody's") has assigned Baytex a corporate family credit rating of Caa1, assigned our Senior Notes a credit rating of Caa1 and stated that our rating outlook is negative. Moody's credit ratings are on a long-term debt rating scale that ranges from Aaa to C, which represents the range from highest to lowest quality of such securities rated. According to the Moody's rating system, securities rated ''Caa'' are rated as being poor quality and a very high credit risk. Moody's appends numerical modifiers 1, 2 and 3 to each generic rating classification from Aa through C. The modifier 1 indicates that the security ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of its generic rating category. In addition, Moody's may add a rating outlook of "positive", "negative", "stable" or "developing" which assess the likely direction of an issuers rating over the medium term.
The credit ratings accorded to Baytex by S&P and Moody's are not recommendations to purchase, hold or sell any of our securities inasmuch as such ratings do not comment as to market price or suitability for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.
We have made payments to S&P and Moody's in connection with the assignment of ratings to our long-term debt and may make payments to S&P and Moody's in the future in connection with the confirmation of such ratings for purposes of the offering of debt securities.
LEGAL PROCEEDINGS AND REGULATORY ACTIONS
In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency (CRA) that deny non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. These reassessments follow the previously disclosed letter which we received in November 2014 from the CRA, proposing to issue such reassessments.

We remain confident that the tax filings of the affected entities are correct and are vigorously defending our tax filing positions. The reassessments do not require us to pay any amounts in order to participate in the appeals process.

We have filed a notice of objection for each notice of reassessment received. These notices of objection will be reviewed by the Appeals Division of the CRA; a process that we estimate could take up to two years. If the Appeals Division upholds the notices of reassessment, we have the right to appeal to the Tax Court of Canada; a process that we estimate could take a further two years. Should we be unsuccessful at the Tax Court of Canada, additional appeals are available; a process that we estimate could take another two years and potentially longer.

By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of $591 million (Losses). The Losses were subsequently used to reduce the taxable income of those trusts. The reassessments disallow the deduction of the Losses under the general anti-avoidance rule of the Income Tax Act (Canada). If, after exhausting available appeals, the deduction of Losses continues to be disallowed, we will owe cash taxes for the years 2012 through 2015 and an additional amount for late payment interest. The amount of cash taxes owing and the late payment interest are dependent upon the amount of unused tax shelter available to offset the reassessed income, including tax shelter from future years available for “carry back” to the years 2012 through 2015.

Other than the foregoing, there are no legal proceedings that we are or were a party to, or that any of our property is or was the subject of, during our most recently completed financial year, that were or are material to us, and there are no such material legal proceedings that we are currently aware of that are contemplated.


58

There were no: (i) penalties or sanctions imposed against us by a court relating to securities legislation or by a securities regulatory authority during our most recently completed financial year; (ii) other penalties or sanctions imposed by a court or regulatory body against us that would likely be considered important to a reasonable investor in making an investment decision; or (iii) settlement agreements we entered into with a court relating to securities legislation or with a securities regulatory authority during our most recently completed financial year.
INTEREST OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS
There were no material interests, direct or indirect, of our directors and executive officers, any holder of Common Shares who beneficially owns or controls or directs, directly of indirectly, more than 10 percent of the outstanding Common Shares, or any known associate or affiliate of such persons, in any transactions within the three most recently completed financial years or since the beginning of our last completed financial year which has materially affected or is reasonably expected to materially affect us.
AUDITORS, TRANSFER AGENT AND REGISTRAR
Deloitte LLP was our auditor until their resignation on June 23, 2016, at which time they were replaced by KPMG LLP. Both are independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.
Computershare Trust Company of Canada, at its principal offices in Calgary, Alberta and Toronto, Ontario, is the transfer agent and registrar for the Common Shares in Canada, the 2021 Debentures and the 2022 Debentures.  Computershare Trust Company, N.A., at its principal office in Canton, Massachusetts, is the transfer agent and registrar for the Common Shares in the United States, the 2021 Notes and the 2024 Notes.  U.S. National Bank Association, at its principal office in Houston, Texas, is the transfer agent and registrar for the 2020 Aurora Notes.

INTERESTS OF EXPERTS
There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a report, valuation, statement or opinion described or included in a filing, or referred to in a filing, made under National Instrument 51-102 "Continuous Disclosure Obligations" by us during, or related to, our most recently completed financial year other than Sproule and Ryder Scott, our independent qualified reserves evaluators. None of the designated professionals of Sproule or Ryder Scott have any registered or beneficial interests, direct or indirect, in any of our securities or other property or of our associates or affiliates either at the time they prepared a report, valuation, statement or opinion, at any time thereafter or to be received by them.
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 Baytex or of any associate or affiliate of Baytex, except for John Brussa, a director of Baytex, who is a partner at Burnet, Duckworth & Palmer LLP, a law firm that renders legal services to us.
MATERIAL CONTRACTS
Except for contracts entered into in the ordinary course of business, the only material contracts entered into by us within the most recently completed financial year, or before the most recently completed financial year but are still material and are still in effect, are the following:
(a)
the credit agreement in respect of the Credit Facilities (filed on SEDAR on April 13, 2016);


59

(b)
Debt Indenture #1 (filed on SEDAR on January 10, 2011) and supplemental indentures thereto (filed on SEDAR on February 22, 2011, July 19, 2012, January 14, 2013, August 13, 2014, September 9, 2014 and March 9, 2015);
(c)
Debt Indenture #2 (filed on SEDAR on June 20, 2014) and supplemental indentures thereto (filed on SEDAR on August 13, 2014 and September 9, 2014); and
(d)
our share award incentive plan (filed on SEDAR on April 18, 2016).
Copies of each of these contracts are accessible on the SEDAR website at www.sedar.com.
INDUSTRY CONDITIONS
Companies operating in the oil and natural gas industry are subject to extensive controls and regulation in respect of operations (including land tenure, exploration, development, production, refining and upgrading, transportation, and marketing) as a result of legislation enacted by various levels of government. The oil and gas industry is also subject to agreements among the governments of Canada, Alberta, Saskatchewan, the United States and Texas with respect to pricing and taxation of oil and natural gas. All current legislation is a matter of public record and we are unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry in western Canada and the United States.
Pricing and Marketing
Oil
In Canada and the United States, producers of oil are entitled to negotiate sales contracts directly with oil purchasers. Worldwide supply and demand factors primarily determine oil prices; however, prices are also influenced by regional markets and transportation issues. The specific price depends in part on oil quality, prices of competing fuels, distance to market, availability of transportation, value of refined products, the supply/demand balance and contractual terms of sale.
Oil can be exported from Canada provided that an order approving such export has been obtained from the National Energy Board of Canada (the "NEB") and the term of the export contract does not exceed one year in the case of light crude oil and two years in the case of heavy crude oil. Any Canadian oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB. Oil exports from the United States are controlled by the United States Department of Commerce. On December 21, 2015, the Government of the United States repealed its ban on crude oil exports to the international market.
Natural Gas
In Canada and the United States, producers of natural gas are entitled to negotiate sales contracts directly with purchasers. Supply and demand determine the price of natural gas and price is calculated at the sale point, being the wellhead, the outlet of a gas processing plant, on a gas transmission system, at a storage facility, at the inlet to a utility system or at the point of receipt by the consumer. Accordingly, the price for natural gas is dependent upon such producer's own arrangements (whether long or short-term contracts and the specific point of sale). As natural gas is also traded on trading platforms such as the Natural Gas Exchange (NGX), Intercontinental Exchange or the New York Mercantile Exchange (NYMEX) in the United States, spot and future prices can also be influenced by supply and demand fundamentals on these platforms.
Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000  m3/day) must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or for a larger quantity requires an export licence from the NEB.


60

Natural gas exported from the United States is regulated principally by the Federal Energy Regulatory Commission ("FERC") and the United States Department of Energy ("DOE"). U.S. law provides for very limited regulation of exports to and imports from any country that has entered into a free trade agreement with the United States that provides for national treatment of trade in natural gas; however, the DOE regulation of imports and exports from and to countries without such free trade agreements is more comprehensive.
The FERC regulates rates and service conditions for the transportation of natural gas in interstate commerce. The prices and terms of access to intrastate pipeline transportation are subject to state regulation. In Texas, the primary regulator is the Texas Railroad Commission. Facilities used in the production or gathering of natural gas in interstate commerce are generally exempt from FERC jurisdiction. However, the distinction between FERC-regulated transmission pipelines and unregulated gathering systems is made by the FERC on a case-by-case basis and has been subject to extensive litigation.
The North American Free Trade Agreement
The North American Free Trade Agreement ("NAFTA") among the governments of Canada, the United States and Mexico came into force on January 1, 1994. In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of goods of the party maintaining the restriction as compared to the proportion prevailing in the most recent 36-month period; (ii) impose an export price higher than the domestic price (subject to an exception with respect to certain measures which only restrict the volume of exports); and (iii) disrupt normal channels of supply.
All three signatory countries are prohibited from imposing a minimum or maximum export price requirement in any circumstance where any other form of quantitative restriction is prohibited. The signatory countries are also prohibited from imposing a minimum or maximum import price requirement, except as permitted in enforcement of countervailing and anti-dumping orders and undertakings. NAFTA requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of those changes will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, all of which are important for Canadian oil and natural gas exports.
Royalties and Incentives
In addition to federal regulation, each province in Canada and each state in the United States has legislation and regulations that govern royalties, production rates and other matters. The royalty regime is a significant factor in the profitability of hydrocarbon production. Royalties payable on production from lands other than Crown lands in Canada and federal and state lands in the United States are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain taxes and royalties. Royalties from production on Crown lands in Canada and federal and state lands in the United States are determined by governmental regulation and are generally calculated as a percentage of the value of gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced. The Government of Alberta recently announced that it would be implementing a new royalty regime applicable to production from wells drilled after 2017 and, as of January 1, 2027, to wells drilled during or prior to 2017. The new royalty structure is to have three phases: pre-payout, mid-life and mature, with a higher royalty rate applicable during the mid-life phase. Details of the new royalty regime are expected to be released by March 31, 2016.
From time to time the federal and provincial governments in Canada and the federal and state governments in the United States create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays or royalty tax credits and are generally introduced to encourage specific types of exploration and development activity.


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Land Tenure
In western Canada, the rights to crude oil and natural gas are predominantly owned by the provincial government. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms, and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments. In the United States, private ownership of the rights to crude oil and natural gas is predominant. Where mineral rights are privately owned, the rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated. Private ownership of oil and natural gas also exists in western Canada. Government and private leases are generally granted for an initial fixed term but may generally be continued provided certain minimum levels of drilling operations or production have been achieved and all lease rentals have been timely paid, subject to certain exceptions.
To develop minerals, including oil and gas, it is necessary for the mineral estate owner(s) to have access to the surface estate. Under common law in Canada and the United States, the mineral estate is considered the "dominant" estate with the right to extract minerals subject to reasonable use of the surface. Each province and state has developed and adopted their own statutes that operators must follow both prior to drilling and following drilling, including notification requirements and the provision of compensation for lost land use and surface damages. The surface rights required for pipelines and facilities are generally governed by leases, easements, rights-of-way, permits or licenses granted by landowners or governmental authorities.
Liability Management Rating Programs
The Provinces of Alberta, British Columbia and Saskatchewan have each implemented similar liability management programs in respect of most conventional upstream oil and gas wells, facilities and pipelines. These programs require a licensee whose deemed liabilities exceed its deemed assets within the jurisdiction to provide a security deposit. In Texas, each operator of a well must file a bond, letter of credit, or cash deposit with the Railroad Commission of Texas ("RRC"). The amount of the bond, letter of credit or deposit varies by number and type of wells, but is not dependent upon the financial capacity of the operator.
Environmental and Occupational Safety and Health Regulation
The oil and natural gas industry is currently subject to stringent environmental, health and safety regulation pursuant to a variety of municipal, provincial, state and federal controls, laws, and regulations governing occupational health and safety aspects of our operations, the spill, release or emission of materials into the environment, or otherwise relating to environmental protection, all of which is subject to governmental review and revision from time to time. Such controls, laws and regulations, among other things, require the acquisition of permits or other approvals to conduct drilling and other regulated activities; restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; impose specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from drilling and production operations. In addition, controls, laws and regulations set out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. Compliance with such controls, laws and regulations can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, remedial obligations, civil liability and the imposition of material administrative, civil and criminal penalties.
Environmental legislation in the Province of Alberta is, for the most part, set out in the Environmental Protection and Enhancement Act and the Oil and Gas Conservation Act, which impose strict environmental standards with respect to releases of effluents and emissions, including monitoring and reporting obligations, and impose significant penalties for non-compliance. Environmental legislation in the Province of Saskatchewan is, for the most part, set out in the Environmental Management and Protection Act, 2002 and the Oil and Gas Conservation Act, which regulate harmful or potentially harmful activities and substances, any release of such substances, and remediation obligations.
In the United States, occupational safety and health, environmental conservation, cultural and natural resources protection are administered by numerous agencies under multiple statutes, as amended from time to time. The environmental and occupational health and safety agencies that most significantly affect our operations include the


62

Federal Occupational Safety and Health Administration ("OSHA"), Federal Environmental Protection Agency ("EPA"), Texas Commission on Environmental Quality ("TCEQ") and RRC.
The OSHA regulates working conditions by setting and enforcing safety and health standards through multiple federal Acts of Congress, most notably the Occupational Safety and Health Act of 1970. OSHA frequently amends/updates regulations, and has recently increased its attention given to the oil and gas industry. For example, OSHA issued a proposed rule on September 12, 2013 to enforce stricter standards to prevent worker exposure to crystalline silica, particularly during hydraulic fracturing. This rule is expected to be formally issued sometime in 2016. Additionally, on December 9, 2013, OSHA began to enhance the regulation and enforcement of oil and gas operations under its Process Safety Management Standard by issuing a series of memoranda, requests for information, and guidance documents to the public. The EPA regulates activities that could affect human health and the environment. It derives its authority from a long list of Acts of Congress, including the Clean Water Act, the Clean Air Act, the Oil Pollution Act of 1990, the Comprehensive Environmental Response, Compensation and Liability Act of 1980 and the Resource Conservation and Recovery Act. The EPA establishes and strictly enforces standards for environmental pollution. In the recent past, the EPA exempted much of the oil and gas industry from its regulations. However, over the past several years, the EPA’s focus has shifted, resulting in a rapid increase in regulation for the industry, especially regarding pollutive air emissions, and including previously unregulated greenhouse gasses. At the state level in Texas, the TCEQ regulates public health and natural resources including air, water and waste and the RCC regulates the stewardship of oil and natural gas resources, along with some aspects of environmental protection and safety related to extraction of those resources. In a similar manner to the efforts of the EPA mentioned above, the TCEQ has recently increased its regulation and enforcement relating to the oil and gas industry, especially regarding air emissions. The RRC regulations establish environmental remediation and reporting criteria for cleanup of oil and produced water spills.
Climate Change Regulation
Both Canada and the United States are signatories to the United Nations Framework Convention on Climate Change (the "UNFCCC") and are participants in the Copenhagen Accord (a non-binding agreement created by the UNFCCC which represents a broad political consensus and reinforces commitments to reducing GHG emissions. Both governments agreed to an economy-wide target of a 17% reduction of GHG emissions from 2005 levels. Both governments also signed the Paris Agreement in December of 2015, which included a commitment to keep any increase in global temperatures below two degrees Celsius. Additionally, Canada pledged to reduce GHG emissions by 30% by 2030 from 2005 levels and the United States pledged to reduce GHG emissions by 26% to 28% by 2025 from 2005 levels.
The United States has not yet announced or enacted any mechanisms or legislation to implement the Paris Agreement. The Government of Canada has announced that it intends to implement a carbon tax in 2018 starting at $10/tonne rising by $10/tonne a year to $50/tonne by 2022. This federal carbon tax is intended to be implemented in concert with the Provinces and territories and would only be implemented in those Provinces and territories that do not have their own carbon tax.
The Province of Alberta announced and implemented a broad range of plans targeting GHG emissions, that include: a carbon levy of $20/tonne that became effective January 1, 2017 that will increase to $30/tonne in 2018, a cap on GHG emissions from the oil sands of 100 Mt per year and a plan to introduce regulations that will reduce methane emissions from oil and gas operations by 45% by 2025. The Province of Saskatchewan has set forth similar legislation that is not yet in force for facilities that emit more than 50,000 tonnes of GHGs. At present, we do not operate any facilities in Alberta or Saskatchewan that exceed these thresholds.
General
Implementation of more stringent environmental regulations on our operations could affect the capital and operating expenditures and plans for our operations. In addition to the agencies that directly regulate oil and gas operations, there are other state and local conservation and environmental protection agencies that regulate air quality, water quality, fish, wildlife, visual quality, transportation, noise, spills, incidents and transportation.
We believe that, in all material respects, we are in compliance with, and have complied with, all applicable environmental laws and regulations. We have made and will continue to make expenditures in our efforts to comply with all environmental regulations and requirements. We consider these a normal, recurring cost of our ongoing operations and


63

not an extraordinary cost of compliance with governmental regulations. We believe that our continued compliance with existing requirements has been accounted for and will not have a material and adverse impact on our financial condition, results of operations and operating cash flows. However, we cannot predict the passage of or quantify the potential impact of any more stringent future laws and regulations at this time.
ADDITIONAL INFORMATION
Additional information relating to us can be found on our website and on the SEDAR website at www.sedar.com. Further information, including directors' and officers' remuneration and indebtedness, principal holders of our securities and securities issued and authorized for issuance under our equity compensation plans will be contained in our Information Circular - Proxy Statement for the annual meeting of Shareholders to be held on May 4, 2017. Additional financial information is contained in our consolidated financial statements for the year ended December 31, 2016 and the related MD&A which are accessible on the SEDAR website at www.sedar.com.

For additional copies of this Annual Information Form and the materials listed in the preceding paragraphs, please contact:

Baytex Energy Corp.
Suite 2800, Centennial Place, East Tower
520 – 3rd Avenue S.W.
Calgary, Alberta T2P 0R3
Phone: (587) 952-3000
Fax: (587) 952-3029
Website: www.baytexenergy.com





APPENDIX A
CONTINGENT RESOURCE ESTIMATES

We commissioned Sproule to conduct an evaluation of our contingent resources in Lloydminster, Peace River, Northeast Alberta and Pembina in Canada. We commissioned Ryder Scott to audit our internal evaluation of our contingent resources in the Eagle Ford area of Texas. Both assessments were effective December 31, 2016, prepared in accordance with the Canadian definitions, standards and procedures contained in the COGE Handbook and based on the Sproule December 31, 2016 forecast prices and costs set forth under "Statement of Reserves Data and Other Oil and Gas Information - Forecast Prices and Costs" in the body of this Annual Information Form.

Contingent resources represent the quantity of oil and natural gas estimated to be potentially recoverable from known accumulations using established technology or technology under development, but which do not currently qualify as reserves or commercially recoverable due to one or more contingencies. There is no certainty that it will be commercially viable to produce any portion of our contingent resources or that we will produce any portion of the volumes currently classified as contingent resources. The recovery and resource estimates provided are estimates. Actual contingent resources (and any volumes that may be reclassified as reserves) and future production from such contingent resources may be greater than or less than the estimates provided.

The contingent resources described below represent our gross interests (unless otherwise indicated) and are a best estimate. A "best estimate" is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual quantities recovered will be greater or less than the best estimate. Those resources identified in the best estimate have a 50% probability that the actual quantities recovered will equal or exceed the estimate. The contingent resources herein are presented as deterministic cumulative best estimate volumes.

Contingent resources should not be confused with reserves and readers should review the definitions and notes set forth herein. Actual crude oil, natural gas, and natural gas liquids resources may be greater than or less than the estimates provided. There is uncertainty that it will be commercially viable to produce any portion of the resources.
Our contingent resources fall within the development pending and development unclarified sub-classes, which are defined as follows:
•
Development Pending - are economic contingent resources that have a high chance of development. Contingencies are directly influenced by the developer, are actively being pursued and resolution is expected in a reasonable time period.
•
Development Unclarified - are contingent resources that have a chance of development which is difficult to assess, and have an economic status which is undetermined. Projects are currently under evaluation and therefore contingencies are not clearly defined. Progress is expected within a reasonable time period.

2

Projects for which Resources are Being Attributed
Development Pending Project Maturity Sub-Class
Summary of Risked Petroleum and Natural Gas Contingent Resources
as of December 31, 2016 Forecast Prices and Costs (1)
Heavy Crude Oil
 
Bitumen
 
Light & Medium Crude
 
Conventional Natural Gas
Gross
(Mbbl)
 
Net
(Mbbl)
 
Gross
(Mbbl)
 
Net
(Mbbl)
 
Gross
(Mbbl)
 
Net
(Mbbl)
 
Gross
(MMcf)
 
Net
(MMcf)
5,202
 
4,695
 
15,715
 
12,529
 
15
 
11
 
8,963
 
7,407
 
Tight Oil
 
Natural Gas Liquids
 
Shale Gas
 
Oil Equivalent
Gross
(Mbbl)
 
Net
(Mbbl)
 
Gross
(Mbbl)
 
Net
(Mbbl)
 
Gross
(MMcf)
 
Net
(MMcf)
 
Gross
(Mboe)
 
Net
(Mboe)
7,345
 
5,419
 
2,571
 
1,896
 
10,321
 
7,585
 
34,061
 
27,049
Note:
(1)
Based on the reports prepared by Sproule and Ryder Scott effective December 31, 2016.

Summary of Risked Net Present Value of Future Net Revenue (Contingent Resources)
as of December 31, 2016 Forecast Prices and Costs (1)(2)

($ millions)
 
Before Income Taxes
Discounted at (% / year)
After Income Taxes
Discounted at (% / year)
Resources Project Maturity Sub-Class
 
0%
 
5%
 
10%
 
15%
 
20%
0%
 
5%
 
10%
 
15%
 
20%
Development Pending
 
768
 
392
 
211
 
116
 
64
517
 
260
 
135
 
70
 
34
Notes:
(1)
An estimate of risked net present value of future net revenue of contingent resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the company proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is no certainty that the estimate of risked net present value of future net revenue will be realized.
(2)
Based on the reports prepared by Sproule and Ryder Scott effective December 31, 2016.
The following table summarizes the status of our development pending contingent resources.
Development Pending - Project Status
Area
 
Product Type
 
Project Status
 
Future Development Costs ($ millions)(1)
 
Timing of First Commercial Production
 
Recovery Technology
Peace River
 
Bitumen
 
Development Study
 
$129
 
2019-2021
 
Cyclic steam stimulation
Peace River, Lloydminster and North East Alberta
 
Heavy Oil
 
Development Study
 
$94
 
2017-2023
 
Horizontal, vertical and multilateral well development
Pembina
 
Light & Medium Oil, Natural Gas
 
Development Study
 
$13
 
2,022
 
Horizontal well development with multi-stage fracturing completion
Eagle Ford
 
Tight Oil, Shale Gas and NGL
 
Pre-Development
 
$152
 
2017-2028
 
Horizontal well development with multi-stage fracturing completion
Note:
(1)    Undiscounted and unrisked.

3

The following table presents a summary of the quantitative risk of the chance of development we have applied to our development pending contingent resources.
Development Pending - Chance of Development Risk (1)
Area
 
Product Type
 
Unrisked
(MMboe)
 
Chance of Development
 
Risked
(MMboe)
 
Risked NPV (2)
Discounted at 10% (before tax)
($ millions)
Peace River
 
Bitumen
 
19
 
81%
 
16
 
70
Peace River, Lloydminster and North East Alberta
 
Heavy Oil
 
6
 
86%
 
5
 
23
Pembina
 
Light & Medium Oil, Natural Gas
 
2
 
90%
 
2
 
11
Eagle Ford
 
Tight Oil, Shale Gas and NGL
 
14
 
80%
 
11
 
107
Total
 
 
 
41
 
 
 
34
 
211
Notes:
(1)
Numbers may not add due to rounding.
(2)
An estimate of risked net present value of future net revenue of contingent resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the company proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is no certainty that the estimate of risked net present value of future net revenue will be realized.
The development pending contingent resources attributed to the Peace River area consist of bitumen volumes allocated to the CSS project at Cliffdale in the Bluesky formation. Using the volumetric data obtained from a geological review, an estimation of the original-bitumen-in-place (OBIP) was calculated. The recovery was estimated based on the performance of our Cliffdale CSS project in the area. CSS is an established technology, which involves injecting steam into a well and then producing heated bitumen and water from the same well bore. Alternating injection and production cycles are repeated a number of times unique to each well bore until economics are no longer justified.
Heavy oil development pending contingent resources in the Lloydminster and Northeast Alberta areas represent the horizontal and vertical well development of the Lower Cretaceous Mannville Group using cold production recovery methods. Heavy oil development pending contingent resources in the Peace River Area represent the horizontal, multi-lateral development of the Bluesky Formation using cold production recovery methods, similar to the development of our existing reserves. These contingent resources volumes were evaluated deterministically by analogy to producing wells utilizing decline analysis to create an expected type well recoverable volume. The expected type well recoverable volume was then compared to an estimated original-oil-in-place (OOIP) to estimate a recovery factor. All areas have analogous wells or reservoirs which employ the same recovery methods and these recovery methods are considered to be established technologies.
The development pending contingent resources in the Pembina Area are attributed to the Falher, Notikewan, Wilrich, Cardium and commingled (Cardium, Viking, Mannville, Rock Creek) formations. These volumes were estimated deterministically based on volumetric analysis and by performance of analogous offsetting wells and are expected to be developed will horizontal wells and multi-stage fracturing completions. Contingent resources for the vertical commingled wells are based on a statistical analysis of offsetting analogous wells. These development technologies are similar to those we are using to develop our existing reserves.
The development pending contingent resources in the Eagle Ford area consist of tight oil, shale gas and natural gas liquids from the Lower Eagle Ford, Upper Eagle Ford, Upper/Lower Eagle Ford and Austin chalk zones. These contingent resources were evaluated internally and were independently audited by Ryder Scott. These volumes are expected to be developed utilizing horizontal wells and multi-stage fracturing completions, similar to the development

4

of our existing reserves. These contingent resources volumes were estimated deterministically by analogy to producing wells using decline analysis.
Development Unclarified Project Maturity Sub-Class
Our development unclarified contingent resources are conceptual project scenarios with no specific company defined development plan in the near-term. The following table presents a summary of the quantitative risk of the chance of development we have applied to our development unclarified contingent resources.
Development Unclarified - Chance of Development Risk (1)
Area
 
Product Type
 
Unrisked
(MMboe)
 
Chance of Development
 
Risked
(MMboe)
Peace River and North East Alberta
 
Bitumen
 
943
 
58%
 
551
Peace River, Lloydminster and North East Alberta
 
Heavy Oil
 
29
 
56%
 
16
Pembina
 
Light & Medium Oil, Natural Gas
 
12
 
55%
 
7
Eagle Ford
 
Tight Oil, Shale Gas and NGL
 
120
 
50%
 
60
Total
 
 
 
1,103
 
 
 
634
Note:
(1)    Numbers may not add due to rounding.

Development unclarified contingent resources have been attributed to bitumen volumes in place in the greater Peace River area. They include projects to expand our Cliffdale project with further horizontal CSS development and several smaller vertical and horizontal CSS projects and a SAGD project.
Development unclarified contingent resources have also been assigned to bitumen volumes in the Northeast Alberta area that are expected to be recovered through thermal recovery projects including a vertical CSS project, a SAGD project and an expansion of the Gemini SAGD project. Using volumetric data obtained from a geological review, an estimation of the OBIP was calculated. Different recovery factors were determined to account for reservoir complications such as the presence of bottom water and/or shale intervals.
Development unclarified contingent resources in the Lloydminster and Northeast Alberta areas have been assigned to heavy oil volumes which are expected to be recovered through horizontal and vertical well development and produced using cold production methods. All areas have analogous wells or reservoirs which employ the same recovery methods which are considered to be established technologies.
The development unclarified contingent resources volumes in the Eagle Ford area are associated with further development of the Austin Chalk and Upper Eagle Ford zones. These are expected to be developed utilizing horizontal well completions.
Chance of Discovery and Development Risk
The principal risks that would influence the development of the Lloydminster, Northeast Alberta, Peace River and Pembina development pending contingent resources are: the timing of regulatory approvals to expand the project areas; the results of delineation drilling and seismic activity necessary for project development; the ability of these projects to compete for capital against our other projects; our corporate commitment to the timing of development; and the

5

commodity price levels affecting the economic viability bitumen and heavy oil production in Alberta. The principal risks specific to the development of the Eagle Ford development pending contingent resources are: our reliance on the operator’s capital commitment and development timing; the ability of these projects to compete for capital against our other projects; and the possibility of inter-well communication from infill drilling.
In addition to the risks identified for the development pending sub-class, the projects in the Lloydminster, Northeast Alberta, Peace River and Pembina areas development unclarified sub-class are also subject to risks pertaining to commercial productivity of the reservoirs. The geological complexity and variability in these reservoirs may require the implementation of pilot projects to test the viability of CSS and SAGD recovery technologies. The risks outlined for the contingent resources in the Eagle Ford development pending sub-class also apply to the development unclarified sub-class but are greater in magnitude.
Contingencies
Continuous development through multi-year exploration and development programs and significant levels of future capital expenditures are required in order for contingent resources to be recovered in the future. The primary contingencies which currently prevent the classification of the contingent resources as reserves consist of: preparation of firm development plans, including determination of the specific scope and timing of the project; project sanction; 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.
For more information, see "Risk Factors" in the Annual Information Form to which this Appendix A is attached.




APPENDIX B
REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE
Form 51‑101F3
Management of Baytex Energy Corp. ("Baytex") is responsible for the preparation and disclosure of information with respect to Baytex's oil and natural gas activities in accordance with securities regulatory requirements. This information includes reserves data and other information such as contingent resources data.
Independent qualified reserves evaluators have evaluated Baytex's reserves data and have evaluated and audited Baytex's contingent resources data. The report of the independent qualified reserves evaluators is presented below.
The Reserves Committee of the Board of Directors of Baytex (the "Reserves Committee") has:
a.
reviewed Baytex's procedures for providing information to the independent qualified reserves evaluators;
b.
met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and
c.
reviewed the reserves data with management and the independent qualified reserves evaluator.
The Reserves Committee has reviewed Baytex's procedures for assembling and reporting other information associated with oil and natural gas activities and has reviewed that information with management. The Board of Directors of Baytex has, on the recommendation of the Reserves Committee, approved:
a.
the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data, contingent resources data and other oil and gas information;
b.
the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluators on the reserves data; and
c.
the content and filing of this report.
Because the reserves data and contingent resources data are based on judgments regarding future events, actual results will vary and the variations may be material.
(signed) "James L. Bowzer"
(signed) "Rodney D. Gray"
James L. Bowzer
Rodney D. Gray
Chief Executive Officer
Chief Financial Officer
 
 
(signed) "Dale O. Shwed"
(signed) "John A. Brussa"
Dale O. Shwed
John A. Brussa
Director and Chairperson of the Reserves Committee
Director and Member of the Reserves Committee
March 7, 2017
 




APPENDIX C
REPORT ON RESERVES DATA AND CONTINGENT RESOURCES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR
Form 51‑101F2
To the Board of Directors of Baytex Energy Corp. ("Baytex"):
1.
We have evaluated Baytex's reserves data and contingent resources data as at December 31, 2016. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2016, estimated using forecast prices and costs. The contingent resources data are risked estimates of volume of contingent resources and related risked net present value of future net revenue as at December 31, 2016, estimated using forecast prices and costs
2.
The reserves data and contingent resources data are the responsibility of Baytex's management. Our responsibility is to express an opinion on the reserves data and contingent resources data based on our evaluation.
3.
We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended form time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).
4.
Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data and contingent resources data are in accordance with principles and definitions presented in the COGE Handbook.
5.
The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of Baytex evaluated by us for the year ended December 31, 2016, and identifies the respective portions thereof that we have evaluated and reported on to the management and Board of Directors of Baytex:
Independent Qualified Reserves Evaluator or Auditor
 
Description and Preparation Date of Evaluation Report
 
Location of Reserves
 
Net Present Value of Future Net Revenue
Before income taxes
 (10% discount rate – $ thousands)
 
Audited
 
Evaluated
 
Reviewed
 
Total
Sproule Unconventional Limited
 
Evaluation of the P&NG Reserves of Baytex Energy Corp. (As of December 31, 2016). Prepared: August 2016 to February 2017
 
Canada
 
Nil
 

$1,548,399

 
Nil
 
$1,548,399
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6.
The following table sets forth the risked volume and risked net present value of future net revenue of contingent resources (before deduction of income taxes) attributed to contingent resources, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in Baytex's statement prepared in accordance with Form 51-101F1 and identifies the respective portions of the contingent resources data that we have evaluated and reported on to the management and Board of Directors of Baytex:


2

Classification
 
Independent Qualified Reserves Evaluator or Auditor
 
Effective Date of Evaluation Report
 
Location of Resources Other than Reserves
 
Risked Volume (Mboe)
 
Net Present Value of Future Net Revenue
Before income taxes
 (10% discount rate – $ thousands)
 
 
Audited
 
Evaluated
 
Total
Development Pending Contingent Resources
 
Sproule Unconventional Limited
 
December 31, 2016
 
Canada
 
22,814
 
Nil
 
$103,899
 
$103,899
Classification
 
Independent Qualified Reserves Evaluator or Auditor
 
Effective Date of Evaluation Report
 
Location of Resources Other than Reserves
 
Risked Volume (Mboe)
 
Development Unclarified Contingent Resources
 
Sproule Unconventional Limited
 
December 31, 2016
 
Canada
 
573,850
7.
In our opinion, the reserves data and contingent resources data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data and contingent resources data that we reviewed but did not evaluate.
8.
We have no responsibility to update the report referred to in paragraphs 5 and 6 for events and circumstances occurring after its preparation date.
9.
Because the reserves data and contingent resources data are based on judgments regarding future events, actual results will vary and the variations may be material.
Executed as to our report referred to above on March 7, 2017.
Sproule Unconventional Limited
(signed) "Cameron P. Six"
(signed) "Alec Kovaltchouk"
Cameron P. Six, P.Eng.
Alec Kovaltchouk, P.Geol
President, CEO and Director
Manager, Geoscience and Partner
 
 
(signed) "Stephanie D. Brunt"
 
Stephanie D. Brunt, P. Eng
 
Petroleum Engineer
 



3

REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR
Form 51‑101F2
To the Board of Directors of Baytex Energy Corp. ("Baytex"):
1.
We have evaluated Baytex's reserves data and audited Baytex's internal evaluation of the contingent resources data as at December 31, 2016. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2016, estimated using forecast prices and costs. The contingent resources data are risked estimates of volume of contingent resources and related risked net present value of future net revenue as at December 31, 2016, estimated using forecast prices and costs
2.
The reserves data and contingent resources data are the responsibility of Baytex's management. Our responsibility is to express an opinion on the reserves data and contingent resources data based on our evaluation.
3.
We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended form time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).
4.
Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data and contingent resources data are in accordance with principles and definitions presented in the COGE Handbook.
5.
The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of Baytex evaluated by us for the year ended December 31, 2016, and identifies the respective portions thereof that we have evaluated and reported on to the management and Board of Directors of Baytex:
Independent Qualified Reserves Evaluator or Auditor
 
Description and Preparation Date of Evaluation Report
 
Location of Reserves
 
Net Present Value of Future Net Revenue
Before income taxes
 (10% discount rate – $ thousands)
 
Audited
 
Evaluated
 
Reviewed
 
Total
Ryder Scott Company, L.P.
 
Evaluation of the P&NG Reserves of Baytex Energy Corp. (As of December 31, 2016). Prepared: August 2016 to February 2017
 
United States of America
 
Nil
 

$2,339,255

 
Nil
 

$2,339,255

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6.
The following table sets forth the risked volume and risked net present value of future net revenue of contingent resources (before deduction of income taxes) attributed to contingent resources, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in Baytex's statement prepared in accordance with Form 51-101F1 and identifies the respective portions of the contingent resources data that we have audited and reported on to the management and Board of Directors of Baytex:
Classification
 
Independent Qualified Reserves Evaluator or Auditor
 
Effective Date of Evaluation Report
 
Location of Resources Other than Reserves
 
Risked Volume
(Mboe)
 
Net Present Value of Future Net Revenue
Before income taxes
 (10% discount rate – $ thousands)
 
 
Audited
 
Evaluated
 
Total
Development Pending Contingent Resources
 
Ryder Scott Company, L.P.
 
December 31, 2016
 
United States of America

 
11,247
 

$107,115

 
Nil
 
$107,115


4

Classification
 
Independent Qualified Reserves Evaluator or Auditor
 
Effective Date of Evaluation Report
 
Location of Resources Other than Reserves
 
Risked Volume (Mboe)
 
Development Unclarified Contingent Resources
 
Ryder Scott Company, L.P.

 
December 31, 2016
 
United States of America

 
59,903
7.
In our opinion, the reserves data evaluated by us and the contingent resources data audited by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data and contingent resources data that we reviewed but did not evaluate or audit.
8.
We have no responsibility to update the report referred to in paragraphs 5 and 6 for events and circumstances occurring after its preparation date.
9.
Because the reserves data and contingent resources data are based on judgments regarding future events, actual results will vary and the variations may be material.
Executed as to our report referred to above on March 7, 2017.

Ryder Scott Company, L.P.
Texas Registered Engineering Firm F-1580
Houston, Texas, USA
(signed) "Ryder Scott Company, L.P."






APPENDIX D

BAYTEX ENERGY CORP.
AUDIT COMMITTEE
MANDATE AND TERMS OF REFERENCE
ROLE AND OBJECTIVE
The Audit Committee (the "Committee") is a committee of the board of directors (the "Board") of Baytex Energy Corp. (the "Corporation") to which the Board has delegated certain of its responsibilities. The primary responsibility of the Committee is to review the interim and annual financial statements of the Corporation and to recommend their approval or otherwise to the Board. The Committee is also responsible for reviewing and recommending to the Board the appointment and compensation of the external auditors of the Corporation, overseeing the work of the external auditors, including the nature and scope of the audit of the annual financial statements of the Corporation, pre-approving services to be provided by the external auditors and reviewing the assessments prepared by management and the external auditors on the effectiveness of the Corporation's internal controls over financial reporting.
The objectives of the Committee are to:
1.
assist directors in meeting their responsibilities in respect of the preparation and disclosure of the financial statements of the Corporation and related matters;
2.
facilitate communication between directors and the external auditors;
3.
enhance the external auditors' independence;
4.
increase the credibility and objectivity of financial reports; and
5.
strengthen the role of the independent directors by facilitating in depth discussions between the Committee, management and the external auditors.
MEMBERSHIP OF THE COMMITTEE
1.
The Committee shall be comprised of not less than three members all of whom are "independent" directors and "financially literate" (within the meaning of National Instrument 52-110 "Audit Committees"). The members of the Committee shall be appointed by the Board from time to time.
2.
The Board shall appoint a Chair of the Committee, who shall be an independent director.
3.
Any member of the Committee may be removed or replaced at any time by the Board and shall cease to be a member of the Committee as soon as such member ceases to be a director. The Board may fill vacancies on the Committee by appointment from among its members. If and whenever a vacancy shall exist on the Committee, the remaining members may exercise all its powers so long as a quorum remains. Subject to the foregoing, each member of the Committee shall hold such office until the close of the next annual meeting of shareholders of the Corporation following appointment as a member of the Committee.
MANDATE AND RESPONSIBILITIES OF THE COMMITTEE
1.
It is the responsibility of the Committee to oversee the work of the external auditors, including resolution of disagreements between management and the external auditors regarding financial reporting. The external auditors shall report directly to the Committee.


2

2.
It is the responsibility of the Committee to satisfy itself on behalf of the Board with respect to the Corporation's internal control systems by:
•
identifying, monitoring and mitigating business risks; and
•
ensuring compliance with legal, ethical and regulatory requirements.
3.
It is a primary responsibility of the Committee to review the interim and annual financial statements of the Corporation prior to their submission to the Board for approval. The review process should include, without limitation:
•
reviewing changes in accounting principles, or in their application, which may have a material impact on the current or future years' financial statements;
•
reviewing significant accruals, reserves or other estimates such as the ceiling test calculation;
•
reviewing accounting treatment of unusual or non-recurring transactions;
•
ascertaining compliance with covenants under loan agreements;
•
reviewing disclosure requirements for commitments and contingencies;
•
reviewing adjustments raised by the external auditors, whether or not included in the financial statements;
•
reviewing unresolved differences between management and the external auditors;
•
obtaining explanations of significant variances with comparative reporting periods; and
•
determining through inquiry if there are any related party transactions and ensuring that the nature and extent of such transactions are properly disclosed.
4.
The Committee is to review all public disclosure of audited or unaudited financial information by the Corporation before its release (and, if applicable, prior to its submission to the Board for approval), including the interim and annual financial statements of the Corporation, management's discussion and analysis of results of operations and financial condition, press releases and the annual information form. The Committee must be satisfied that adequate procedures are in place for the review of the Corporation's disclosure of financial information and shall periodically assess the accuracy of those procedures.
5.
With respect to the external auditors of the Corporation, the Committee shall:
•
recommend to the Board the appointment of the external auditors, including the terms of their engagement for the integrated audit;
•
review and approve any other services to be provided by the external auditors (including the fee for such services); and
•
when there is to be a change in the external auditors, review the issues related to the change and the information to be included in the required notice to securities regulators of such change.
6.
Review with the external auditors (and the internal auditor if one is appointed by the Corporation) their assessment of the internal controls of the Corporation, their written reports containing recommendations for improvement, and management's response and follow-up to any identified weaknesses. The Committee shall also review annually with the external auditors their plan for the audit and, upon completion of the audit, their reports upon the financial statements of the Corporation and its subsidiaries.


3

7.
The Committee must pre-approve all services to be provided to the Corporation or its subsidiaries by the external auditors. In pre-approving any service, the Committee shall consider the impact that the provision of such service may have on the external auditors' independence. The Committee may delegate to one or more of its members the authority to pre-approve services, provided that the member report to the Committee at the next scheduled meeting such pre-approval and the member comply with such other procedures as may be established by the Committee from time to time.
8.
The Committee shall review the risk management policies and procedures of the Corporation (i.e., hedging, litigation and insurance).
9.
The Committee shall establish procedures for the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls or auditing matters and the confidential, anonymous submission by employees of the Corporation and its subsidiary entities of concerns regarding questionable accounting or auditing matters.
10.
The Committee shall review and approve the Corporation's hiring policies regarding employees and former employees of the present and former external auditors of the Corporation.
11.
The Committee shall have the authority to investigate any financial activity of the Corporation. All employees of the Corporation and its subsidiary entities are to cooperate as requested by the Committee.
12.
The Committee shall forthwith report the results of meetings and reviews undertaken and any associated recommendations to the Board.
13.
The Committee shall meet with the external auditors at least four times per year (in connection with their review of the interim and annual financial statements) and at such other times as the external auditors and the Committee consider appropriate.
MEETINGS AND ADMINISTRATIVE MATTERS
1.
At all meetings of the Committee every question shall be decided by a majority of the votes cast. In case of an equality of votes, the chairman of the meeting shall be entitled to a second or casting vote.
2.
The Chair shall preside at all meetings of the Committee, unless the Chair is not present, in which case the members of the Committee present shall designate from among the members present a chairman for purposes of the meeting.
3.
A quorum for meetings of the Committee shall be a majority of its members, and the rules for calling, holding, conducting and adjourning meetings of the Committee shall be the same as those governing the Board unless otherwise determined by the Committee or the Board.
4.
Meetings of the Committee should be scheduled to take place at least four times per year and at such other times as the Chair may determine.
5.
Agendas, approved by the Chair, shall be circulated to Committee members along with background information on a timely basis prior to the Committee meetings.
6.
The Committee may invite those officers, directors and employees of the Corporation and its subsidiary entities as it may see fit from time to time to attend at meetings of the Committee and assist thereat in the discussion and consideration of the matters being considered by the Committee, provided that the Chief Financial Officer of the Corporation shall attend all meetings of the Committee, unless otherwise excused from all or part of any such meeting by the chairman of the meeting.


4

7.
Minutes of the Committee's meetings will be recorded and maintained and made available to any director who is not a member of the Committee upon request.
8.
The Committee may retain persons having special expertise and/or obtain independent professional advice to assist in fulfilling its responsibilities at the expense of the Corporation.
9.
Any issues arising from the Committee's meetings that bear on the relationship between the Board and management should be communicated to the Executive Chairman or the Lead Independent Director, as applicable, by the Committee Chair.

Approved by the Board of Directors on February 28, 2011