---










Section
PageSPECIAL NOTES TO READER
1GLOSSARY
5SELECTED ABBREVIATIONS
7CURRENCY OF INFORMATION
8OUR ORGANIZATIONAL STRUCTURE
8GENERAL DEVELOPMENT OF THE BUSINESS OF THE CORPORATION
10DESCRIPTION OF OUR BUSINESS
12STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
17ADDITIONAL INFORMATION RESPECTING CRESCENT POINT
41INDUSTRY CONDITIONS
50RISK FACTORS
64DIVIDENDS
79MARKET FOR SECURITIES
80CONFLICTS OF INTEREST
81LEGAL PROCEEDINGS
81AUDIT COMMITTEE
81TRANSFER AGENT AND REGISTRARS
83AUDITOR
83MATERIAL CONTRACTS
83INTERESTS OF EXPERTS
83ADDITIONAL INFORMATION
84


|           |                                        
|---------- | ---------------------------------------
|APPENDIX A | -    AUDIT COMMITTEE TERMS OF REFERENCE

|           |                                           
|---------- | ------------------------------------------
|APPENDIX B | -    RESERVES COMMITTEE TERMS OF REFERENCE

|           |                                                                                     
|---------- | ------------------------------------------------------------------------------------
|APPENDIX C | -    REPORTS ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

|           |                                                                               
|---------- | ------------------------------------------------------------------------------
|APPENDIX D | -    REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
















---

















|  |                                                                          
|- | -------------------------------------------------------------------------
|• | corporate strategy and anticipated financial and operational performance;

|  |                                                                                        
|- | ---------------------------------------------------------------------------------------
|• | the expected impact of commodity price fluctuations on cash available to pay dividends;

|  |                                                                               
|- | ------------------------------------------------------------------------------
|• | our hedging strategy and our approval to managing physical delivery contracts;

|  |                              
|- | -----------------------------
|• | our risk mitigation strategy;

|  |                                                                                                                              
|- | -----------------------------------------------------------------------------------------------------------------------------
|• | the potential impact of competition and our working relationships with industry partners and joint operators on our business;

|  |                    
|- | -------------------
|• | business prospects;

|  |                                                                                                                                                        
|- | -------------------------------------------------------------------------------------------------------------------------------------------------------
|• | the performance characteristics of Crescent Point's oil and natural gas properties, including but not limited to oil and natural gas production levels;

|  |                                                                         
|- | ------------------------------------------------------------------------
|• | anticipated future cash flows and oil and natural gas production levels;

|  |                                                           
|- | ----------------------------------------------------------
|• | projected returns and exploration potential of our assets;

|  |                                         
|- | ----------------------------------------
|• | the potential of Crescent Point’s plays;

|  |                          
|- | -------------------------
|• | future development plans;

|  |                                                          
|- | ---------------------------------------------------------
|• | capital expenditure programs and how they will be funded;

|  |                                  
|- | ---------------------------------
|• | our leverage objectives for 2017;

|  |                                               
|- | ----------------------------------------------
|• | corporate and asset acquisition opportunities;

|  |                   
|- | ------------------
|• | drilling programs;

|  |                                                
|- | -----------------------------------------------
|• | expected location inventory development timing;

|  |                                                                                             
|- | --------------------------------------------------------------------------------------------
|• | the expected ongoing transition to horizontal wells in Utah and its impact on well bookings;

|  |                                                                                                 
|- | ------------------------------------------------------------------------------------------------
|• | our expected production breakdown by area on a Proved and Proved plus Probable production basis;

|  |                                              
|- | ---------------------------------------------
|• | the quantity of oil and natural gas reserves;

|  |                                           
|- | ------------------------------------------
|• | projections of commodity prices and costs;

|  |                                
|- | -------------------------------
|• | our future waterflood programs;

|  |                                                                     
|- | --------------------------------------------------------------------
|• | treatment of DRIP and SDP participants if either plan is reinstated;

|  |                                                                          
|- | -------------------------------------------------------------------------
|• | expected decommissioning, abandonment, remediation and reclamation costs;

|  |                 
|- | ----------------
|• | our tax horizon;

|  |                                                                       
|- | ----------------------------------------------------------------------
|• | the potential impact of U.S. border adjustment tax on the Corporation;

|  |                                                                                                                                              
|- | ---------------------------------------------------------------------------------------------------------------------------------------------
|• | expected trends in environmental regulation, including the anticipated impact the trends will have on our operations and our costs to comply;

|  |                              
|- | -----------------------------
|• | payment of monthly dividends;







---

- 2 -





|  |                                           
|- | ------------------------------------------
|• | supply and demand for oil and natural gas;

|  |                                                                                                                                 
|- | --------------------------------------------------------------------------------------------------------------------------------
|• | expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; and

|  |                                                 
|- | ------------------------------------------------
|• | treatment under governmental regulatory regimes.













---

- 3 -







Barrels of oil equivalent (" boe ") 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.






Additional information on these and other factors that could affect Crescent Point's operations or financial results are included in Crescent Point's reports on file with Canadian and U.S. securities regulatory authorities (including our AIF, Annu al Report on Form 40-F and Management's Discussion and Analysis). Readers are cautioned not to place undue reliance on the forward-looking information, which is given as of the date it is expressed in this AIF or otherwise. We do not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required pursuant to applicable securities laws. All subsequent forward-looking statements, whether written or oral, attributable to Crescent Point or persons acting on the Corporation’s behalf are expressly qualified in their entirety by these cautionary statements.




Current SEC reporting requirements permit oil and gas companies to disclose Probable reserves (as defined herein), in addition to the required disclosure of Proved reserves. Under current SEC requirements, net quantities of reserves are required to be disclosed, which requires disclosure on an after royalties basis and does not include reserves relating to the interests of others. For a description of these and additional differences between Canadian and US standards of reporting reserves, see " Risk Factors — 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 ".








---

- 4 -















---




- 5 -









" ABCA " means the Business Corporations Act, R.S.A. 2000, c. B-9, as amended, including the regulations promulgated thereunder.


" AIF " means this annual information form of the Corporation dated February 22, 2017 for the year ended December 31, 2016.


" CanEra " means CanEra Energy Corp.


" CanEra Arrangement " means the plan of arrangement under Section 193 of the ABCA involving CanEra and the Corporation, completed on May 15, 2014, as more particularly described under the heading " General Development of the Business of the Corporation – History – 2014 ".


" Common Shares " means common shares in the capital of the Corporation.


" Conversion Arrangement " means the plan of arrangement under Section 193 of the ABCA, completed on July 2, 2009 pursuant to which the Trust effectively converted from an income trust to a corporate structure.


" Coral Hill " means Coral Hill Energy Ltd.


" Coral Hill Arrangement " means the plan of arrangement under Section 193 of the ABCA involving Coral Hill and the Corporation, completed on August 14, 2015, as more particularly described under the heading " General Development of the Business of the Corporation – History – 2015 ".


" CPEUS " means Crescent Point Energy U.S. Corp.


" CPHI " means Crescent Point Holdings Inc.


" CPLux " means Crescent Point Energy Lux S.à r.l.


" CPUSH " means Crescent Point U.S. Holdings Corp.


" Crescent Point " or the " Corporation " means Crescent Point Energy Corp., formerly Wild River Resources Ltd., a corporation amalgamated under the ABCA and, where applicable, includes its subsidiaries and affiliates.


" DRIP " means the Premium Dividend TM and Dividend Reinvestment Plan of the Corporation.


" DSU Plan " means the Deferred Share Unit Plan of the Corporation.


" FAST Act " means the Fixing America’s Surface Transportation Act .


" GLJ " means GLJ Petroleum Consultants Ltd.


" Greenhouse Gases " or " GHGs " means any or all of, including but not limited to, carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulphur hexafluoride (SF 6 ).


" IFRS " means International Financial Reporting Standards as adopted by the Canadian Accounting Standards Board for periods beginning on and after January 1, 2011.


" Legacy " means Legacy Oil + Gas Inc.








---

- 6 -





" Legacy Arrangement " means the plan of arrangement under Section 193 of the ABCA involving Legacy and the Corporation, completed on June 30, 2015, as more particularly described under the heading " General Development of the Business of the Corporation – History – 2015 ".


" MD&A " means the management's discussion and analysis of financial condition and results of operations of the Corporation for the year ended December 31, 2016.


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


" NYSE " means the New York Stock Exchange.


" OPEC " means Organization of the Petroleum Exporting Countries.


" Partnership " means Crescent Point Resources Partnership, a general partnership formed under the laws of the Province of Alberta, having CPHI and the Corporation as partners.


" Restricted Share Bonus Plan " means the Restricted Share Bonus Plan of the Corporation.


" SDP " means the Share Dividend Plan of the Corporation.


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


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


" Shelter Bay " means Shelter Bay Energy Inc.


" Sproule " means Sproule Associates Limited.


" T. Bird " means T. Bird Oil Ltd.


" Tax Act " means the Income Tax Act (Canada), R.S.C. 1985, c. 1 (5th Supp.), and the regulations promulgated thereunder, each as amended from time to time.


" Tribe " means the Ute Indian Tribe of the Uintah and Ouray Reservation.


" Trust " means Crescent Point Energy Trust, an unincorporated open ended investment trust governed by the laws of the Province of Alberta that was dissolved pursuant to the Conversion Arrangement.


" Trust Units " means the trust units of the Trust.


" TSX " means the Toronto Stock Exchange.


" Unitholders " means holders of Trust Units.


" U.S. " means the United States of America.


" Viking Assets " means the Corporation's assets located in the Viking play at Dodsland, Saskatchewan, acquired from Polar Star Canadian Oil and Gas Inc.










---




- 7 -









Oil and Natural Gas Liquids
Natural Gasbbl
barrel
Mcf
thousand cubic feetbbls
barrels
Mcf/d
thousand cubic feet per daybbl/d
barrels per day
Mcfe
thousand cubic feet of gas equivalent converting one barrel of oil to 6 Mcf of natural gas equivalentMbbls
thousand barrelsNGLs
natural gas liquidsMMcf
million cubic feetMMcf/d
million cubic feet per dayMMBTU
million British Thermal UnitsGJ
gigajoule





OtherAECO
the natural gas storage facility located at Suffield, Albertaboe
barrel of oil equivalent of natural gas and crude oil on the basis of 1 boe for 6 (unless otherwise stated) Mcf of natural gas (this conversion factor is an industry accepted norm and is not based on either energy content or current prices)boe/d
barrel of oil equivalent per daym3
cubic metresM$
thousand dollarsMboe
thousand barrels of oil equivalentMMboe
million barrels of oil equivalentMM$
million dollarsMW
megawattMW/h
megawatt per hourWTI
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade











---




- 8 -
















Crescent Point Energy Corp. (" Crescent Point " or the " Corporation " and, together with its direct and indirect subsidiaries and partnerships, where appropriate, " we ", " our " or " us ") is the successor to the Trust, following the completion of the "conversion" of the Trust from an income trust to a corporate structure under the Conversion Arrangement. Pursuant to the Conversion Arrangement, Unitholders of the Trust exchanged their Trust Units for Common Shares of the Corporation on a one-for-one basis.


The Corporation was originally incorporated pursuant to the provisions of the Company Act (British Columbia) on April 20, 1994 as 471253 British Columbia Ltd. 471253 British Columbia Ltd. changed its name to Westport Research Inc. (" Westport ") on August 12, 1994. On August 1, 2006, Westport was continued into Alberta under the ABCA. On October 11, 2006, Westport changed its name to 1259126 Alberta Ltd. (" 1259126 "). On February 8, 2007, 1259126 amended its articles to change its name to Wild River Resources Ltd. (" Wild River "), to add a class of non-voting common shares, to change the number of authorized Common Shares from 1,000,000 to unlimited and to change the rights, privileges, restrictions and conditions attaching to such shares, to reorganize its share structure, to change the number of Wild River's issued and outstanding shares on a pro rata basis to an aggregate of 5,000,000 Common Shares, to remove the restrictions on share transfer and to amend the "other provisions" section of the articles. On June 29, 2009, Wild River amended its articles to cancel the non-voting common shares and to change the rights, privileges, restrictions and conditions of the Common Shares to remove the references to the non-voting common shares. On July 2, 2009, in connection with the Conversion Arrangement, Wild River filed Articles of Amendment to give effect to the consolidation of the Common Shares on the basis of 0.1512 of a post-consolidation Common Share for each pre-consolidation Common Share and subsequent Articles of Amendment to change its name to Crescent Point Energy Corp. On January 1, 2011, the Corporation amalgamated with Ryland Oil ULC, Darian Resources Ltd. and Shelter Bay Energy ULC.




The Corpora tion is a conventional oil and gas producer with assets strategically focused in properties comprised of high quality, long life, operated, light and medium oil and natural gas reserves in Western Canada and the United States.


We make mont hly cash dividends to Shareholders from our net cash flow. Our primary source of cash flow is distributions from the Partnership.




The Partnership is a general partnership governed by the laws of the Province of Alberta. As set forth in the diagram below under " Organizational Structure of the Corporation ", the partners of the Partnership are CPHI and the Corporation.














---

- 9 -





















Percentage of Voting Securities (Directly or Indirectly)
Jurisdiction of Incorporation/FormationCPHI
100%
AlbertaPartnership
100%
AlbertaCPUSH
100%
NevadaCPEUS
100%
DelawareCPLux
100%
Luxembourg











---

- 10 -
































On May 9, 2014, the Corporation adopted the SDP. See " Share Dividend Plan ".


On May 15, 2014, the Corporation closed the CanEra Arrangement for total consideration of approximately $1.1 billion, comprised of 12,928,091 Crescent Point Common Shares, cash consideration of approximately $191.8 million and assumed debt. See " Description of Our Business – Reorganizations ".




On June 24, 2014, the Corporation closed an offering of senior guaranteed notes in the United States and Canada on a private placement basis in aggregate principal amounts of US$310 million and $40 million, respectively. The terms of the U.S. notes range from 7 to 10 years with a weighted average term of 9.5 years and coupon rates ranging from 3.29% to 3.75% and the terms of the Canadian note are 10 years with a coupon rate of 3.85%.








---

- 11 -



























On June 30, 2015, the Corporation closed the Legacy Arrangement for total consideration of approximately $1.5 billion, comprised of 18,229,428 Crescent Point Common Shares, cash consideration of $19.4 million and assumed debt. See " Description of Our Business – Reorganizations ".




On August 12, 2015, the Corporation reduced its monthly dividend to $0.10 per share, effective with the August dividend payable on September 15, 2015. In addition, effective with the August dividend, the Corporation suspended the SDP and DRIP. See " Additional Information Respecting Crescent Point – Share Dividend Plan ".


On August 14, 2015, the Corporation closed the Coral Hill Arrangement pursuant to which the Corporation acquired all of the remaining issued and outstanding shares of Coral Hill not already owned by the Corporation (as at August 14, 2015, Crescent Point had an 8.7% equity interest in Coral Hill) for total consideration of $243.8 million, comprised of 4,283,680 Crescent Point Common Shares, assumed debt and the historical cost of Crescent Point’s previously held equity investment of $42.0 million. See " Description of Our Business – Reorganizations ".








---

- 12 -









On March 8, 2016, Barbara Munroe was appointed as a director of the Corporation. See " Additional Information Respecting Crescent Point – Directors and Officers" .










On November 9, 2016, Mike Jackson was appointed as a director of the Corporation. See " Additional Information Respecting Crescent Po int – Directors and Officers " .













We pay monthly cash dividends to Shareholders from our net cash flow in accordance with our dividend policy. Our prima ry sources of cash flow are distributions from the Partnership. See " Dividends ".




We strive to cr eate sustainable, value-added growth in reserves, production and cash flow through the execution of management's integrated strategy of acquiring, exploiting and developing high quality, long life, light and medium oil and natural gas properties.


We continually investigate and search out producing properties including those with large resource potential that we believe will result in meaningful reserve and production additions. We generally focus capital on higher-quality, longer-life reservoirs in prove n growth areas that offer existing infrastructure, low cost drilling and multi-zone potential. Our goal is to acquire operational control of properties that we believe offer significant exploitation and development potential.








|    |                                                                                                                                                               
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | world market forces, including world supply and consumption levels and the ability of the OPEC to set and maintain production levels and prices for crude oil;

|    |                                                                                                                   
|--- | ------------------------------------------------------------------------------------------------------------------
|(b) | political conditions, including the risk of hostilities in the Middle East and other regions throughout the world;

|    |                                                                                                    
|--- | ---------------------------------------------------------------------------------------------------
|(c) | increases or decreases in crude oil differentials and their implications for prices received by us;

|    |                                                                                                                                         
|--- | ----------------------------------------------------------------------------------------------------------------------------------------
|(d) | the impact of changes in the exchange rate between Canadian and U.S. dollars on prices received by us for our crude oil and natural gas;

|    |                                                                                                                                                                                           
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(e) | North American market forces, most notably shifts in the balance between supply and demand for crude oil and natural gas and the implications for the prices of crude oil and natural gas;

|    |                                                                                                                                                    
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------
|(f) | availability, proximity and capacity of oil and gas gathering systems, pipeline and processing facilities, railcars and railcar loading facilities;

|    |                                                     
|--- | ----------------------------------------------------
|(g) | global and domestic economic and weather conditions;

|    |                                             
|--- | --------------------------------------------
|(h) | price and availability of alternative fuels;

|    |                                                                           
|--- | --------------------------------------------------------------------------
|(i) | the effect of energy conservation measures and government regulations; and

|    |                            
|--- | ---------------------------
|(j) | U.S. and Canada tax policy.



To mitigate a portion of these risks, we actively initiate, manage and disclose the effects of our hedging activities. Our strategy for crude oil and natural gas production is to hedge up to 65%, or as otherwise approved by the board of directors, of our existing net of royalty production on a rolling three and a half year basis, at the discretion of management. With recent increases in the volatility of price differentials between WTI and western Canadian crude prices, Crescent Point has expanded its risk management programs to include the hedging of these differentials. The Corporation uses a combination of financial derivatives and fixed-differential physical contracts to hedge these price differentials. For differential hedging, Crescent Point's risk management program allows for hedging a forward profile of 31⁄2 years, and up to 35% net of royalty production. All hedging activities are governed by our Risk Management and Counterparty Credit Policy and are regularly reviewed by the board of directors.


As part of our risk management program, benchmark oil prices are hedged using financial WTI-based instruments transacted in Canadian dollars and benchmark natural gas prices are hedged using financial AECO-based instruments transacted in Canadian dollars. Total financial oil and gas hedges in 2016 amounted to approximately 41% of annual production, net of royalties, consisting of approximately 41% of annual liquids production and approximately 41% of annual natural gas production, net of royalties. The primary objective of this strategy is to be well positioned to maximize shareholder return with long-term growth plus dividend income. The Corporation recorded a realized derivative gain on oil and gas hedge contracts of $468.7  million in 2016.








---

- 13 -







Financial WTI Crude Oil Derivative Contracts – Canadian Dollar (1)


Swap

Three-way CollarTerm
Volume

(bbls/d)
Average
 Price

($/bbl)

Average
 Sold Call Price

($/bbl)
Average
 Bought Put Price

($/bbl)
Average
 Sold Put Price

($/bbl)2017(2)
46,800
71.35

79.78
67.93
60.212018 January - June
7,500
74.14

79.39
73.43
64.00




|    |                                                                                            
|--- | -------------------------------------------------------------------------------------------
|(1) | The volumes and prices reported are the weighted average volumes and prices for the period.

|    |                                                                                                                                               
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Includes4,000bbls/d which can be extended at the option of the counterparty for the first half of 2018 at an average swap price of $86.16/bbl.







Financial WTI Crude Oil Differential Derivative Contracts – Canadian Dollar (1)


Term
Volume

(bbls/d)
Contract
Basis
Fixed Differential 
 ($/bbl)2017
2,000
Basis Swap
MSW
(3.66)




|    |                                                                                            
|--- | -------------------------------------------------------------------------------------------
|(1) | The volumes and prices reported are the weighted average volumes and prices for the period.







Financial AECO Natural Gas Derivative Contracts – Canadian Dollar (1)


Term
Average Volume

(GJ/d)
Average Swap Price

($/GJ)2017
41,356
3.092018
33,973
2.832019
19,948
2.71




|    |                                                                                            
|--- | -------------------------------------------------------------------------------------------
|(1) | The volumes and prices reported are the weighted average volumes and prices for the period.









Term
Contract
Volume

(MW/h)
Fixed Rate

($/MW/h)2017
Swap
3.0
52.50







Term
Contract
Notional Principal

($ millions)
Fixed Annual

Rate (%)January 2017 - September 2018
Swap
50.0
0.90January 2017 - September 2018
Swap
50.0
0.87January 2017 - August 2020
Swap
50.0
1.16January 2017 - August 2020
Swap
50.0
1.16January 2017 - August 2020
Swap
100.0
1.15January 2017 - September 2020
Swap
50.0
1.14January 2017 - September 2020
Swap
50.0
1.11








---

- 14 -










Term
Contract
Receive Notional

Principal

(US$ millions)
Fixed Annual Rate

(US%)
Pay Notional Principal

(Cdn$ millions)
Fixed Annual Rate

(Cdn%)January 2017
Swap
90.0

2.77

120.9

2.46January 2017
Swap
105.0

2.77

141.1

2.43January 2017 - February 2017
Swap
95.0

2.80

126.1

2.41January 2017 - February 2017
Swap
190.0

2.80

252.1

2.41January 2017 - February 2017
Swap
190.0

2.80

252.2

2.40January 2017 - February 2017
Swap
205.0

2.80

272.1

2.39January 2017 - February 2017
Swap
150.0

2.89

200.4

2.41January 2017 - February 2017
Swap
180.0

2.89

240.8

2.43January 2017 - March 2017
Swap
67.5

5.48

68.9

5.89January 2017 - April 2018
Swap
31.0

4.58

29.9

5.32January 2017 - June 2018
Swap
20.0

2.65

20.4

3.52January 2017 - May 2019
Swap
68.0

3.39

66.7

4.53January 2017 - March 2020
Swap
155.0

6.03

158.3

6.45January 2017 - April 2021
Swap
82.0

5.13

79.0

5.83January 2017 - June 2021
Swap
52.5

3.29

56.3

3.59January 2017 - May 2022
Swap
170.0

4.00

166.9

5.03January 2017 - June 2023
Swap
270.0

3.78

274.7

4.32January 2017 - June 2024
Swap
257.5

3.75

276.4

4.03January 2017 - April 2025
Swap
230.0

4.08

291.1

4.13January 2017 - April 2027
Swap
20.0

4.18

25.3

4.25







Settlement Date
Contract
Receive Notional

Principal

(US$ millions)
Pay Notional Principal

(Cdn$ millions)January 2017
Swap
15.0
20.1May 2022
Swap
30.0
32.2













---

- 15 -











Our oil and natural gas volumes are sold in the U.S., Alberta, British Columbia, Manitoba and Saskatchewan. Approximately 79% of our liquids volumes are sold in Saskatchewan, 11% in the U.S., 8% in Alberta, 2% in Manitoba and less than  1% in British Columbia. Approximately  57% of our natural gas volumes are sold in Saskatchewan, 25% in Alberta, 18% in the U.S. and less than 1% in Manitoba.




For 2016 , our commodity production mix was approximately 90% oil and NGLs and 10% natural gas.


The follo wing table summarizes our revenue sources by product before hedging and royalties:


For Year Ended
Crude Oil and NGLs
Natural Gas2016
97%
3%2015
96%
4%2014
97%
3%







We activ ely compete for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial resources than we do. Our competitors include major integrated oil and natural gas companies, numerous other independent oil and natural gas entities and individual producers and operators.








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- 16 -





Certain of our customers and potential customers are themselves exploring for oil and natural gas, and the results of such explora tion efforts could affect our ability to sell or supply oil or gas to these customers in the future. Our ability to successfully bid on and acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers is dependent upon developing and maintaining close working relationships with our industry partners and joint operators, our ability to select and evaluate suitable properties and our ability to consummate transactions in a highly competitive environment.
















On June 30, 2015, the Corporation closed the Legacy Arrangement for total consideration of approximately $1.5 billion, compris ed of 18,229,428 Crescent Point Common Shares, cash consideration of $19.4 million and assumed debt. The assets increase the Corporation’s position in southeast Saskatchewan.


On August 14, 2015, the Corporation closed the Coral Hill Arrangement, pursuant to which the Corporation acquired all of the remaining issued and outstanding shares of Coral Hill not already owned by the Corporation. Total consideration for the acquisition was  $243.8 million, comprised of 4,283,680 Crescent Point Common Shares, assumed debt and the historical cost of Crescent Point’s previously held equity investment of $42.0 million.  The Coral Hill Arrangement consolidated the Corporation’s position in the Swan Hills Beaverhill Lake resource play and provided the Corporation with full operatorship, control over pace of development and an increased position in the core of the play.












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- 17 -









In accordance with NI 51-101, the reserves data of the Corporation set forth below (the " Reserves Data ") is based upon evaluations by GLJ and Sproule with an effective date of December 31, 2016 contained in the consolidated report of GLJ dated February 15, 2017 (the " Crescent Point Reserve Report "). The Crescent Point Reserve Report evaluated, as at December 31, 2016, and summarizes our crude oil, NGL and natural gas reserves. The tables below are a combined summary of our crude oil, NGL and natural gas reserves and the net present value of future net revenue attributable to such reserves as evaluated in the Crescent Point Reserve Report based on Sproule’s December 31, 2016 forecast price and cost assumptions. GLJ evaluated approximately 44 percent of the assigned total Proved plus Probable reserves and 33 percent of the total Proved plus Probable value discounted at 10 percent. Sproule evaluated approximately 56 percent of the assigned total Proved plus Probable reserves and 67 percent of the total Proved plus Probable value discounted at 10 percent. Sproule evaluated a majority of our Canadian Williston basin assets including the Viewfield Bakken and Flat Lake Torquay properties in southeast Saskatchewan as well as southwest Saskatchewan assets including the Shaunavon and Saskatchewan Viking properties. Sproule evaluated their portion of the reserves using the Sproule forecast price and cost escalation assumptions. GLJ evaluated the Corporation’s Alberta, British Columbia and a portion of the Canadian Williston basin assets in southeast Saskatchewan and Manitoba. GLJ also performed the evaluation of the Corporation's U.S. assets in the Williston basin including properties in North Dakota and Montana, as well as assets in the Uinta basin in Utah, and properties in Colorado. These assets were all evaluated using the Sproule forecast price and cost escalation assumptions. GLJ prepared the total Crescent Point Reserve Report by consolidating the GLJ Canadian and U.S. evaluated properties with the Sproule evaluation using the Sproule pricing and cost escalation assumptions. The tables summarize the data contained in the Crescent Point Reserve Report and, as a result, may contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly.


The net present value of future net revenue attributable to our reserves is stated without provision for interest costs, and general and administrative costs, but after providing for estimated royalties, production costs, capital taxes, development costs, other income, future capital expenditures, and well and location abandonment costs for only those entities assigned reserves by GLJ and Sproule. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to our reserves estimated by GLJ and Sproule represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of our crude oil, NGL and natural gas  reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.










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- 18 -







Summary of Oil and Gas Reserves (1)


Light and Medium Crude Oil
Heavy Crude Oil
Tight Oil
Natural Gas Liquids
Shale Gas
Conventional

Natural Gas
TotalReserves Category
Company Gross

(Mbbls)
Company

Net

(Mbbls)
Company

Gross

(Mbbls)
Company

Net

(Mbbls)
Company

Gross

(Mbbls)
Company

Net

(Mbbls)
Company

Gross

(Mbbls)
Company

Net

(Mbbls)
Company Gross

(MMcf)
Company

Net

(MMcf)
Company Gross

(MMcf)
Company

Net

(MMcf)
Company

Gross

(Mboe)
Company

Net

(Mboe)Proved Developed ProducingCanada
109,762

96,045

20,580

18,151

133,145

123,425

32,519

29,298

92,696

87,042

99,094

89,417

327,970

296,329United States
1,119

913

-

-

24,807

20,367

3,518

2,860

40,270

34,073

169

162

36,184

29,847Total
110,880

96,958

20,580

18,151

157,953

143,792

36,037

32,159

132,966

121,115

99,263

89,579

364,154

326,175Proved Developed Non-ProducingCanada
4,419

4,018

230

202

6,269

5,856

1,102

1,002

3,598

3,362

3,083

2,711

13,134

12,091United States
-

-

-

-

1,777

1,440

146

119

2,229

1,817

-

-

2,295

1,861Total
4,419

4,018

230

202

8,046

7,296

1,249

1,121

5,827

5,179

3,083

2,711

15,428

13,952Proved UndevelopedCanada
43,998

40,873

2,006

1,640

82,291

77,276

13,044

11,983

50,715

47,562

24,915

22,751

153,945

143,491United States
-

-

-

-

50,237

41,098

6,770

5,504

57,992

47,381

-

-

66,672

54,499Total
43,998

40,873

2,006

1,640

132,529

118,374

19,813

17,487

108,708

94,944

24,915

22,751

220,617

197,990Total ProvedCanada
158,179

140,937

22,816

19,993

221,705

206,556

46,665

42,284

147,009

137,967

127,092

114,879

495,048

451,911United States
1,119

913

-

-

76,822

62,905

10,434

8,483

100,492

83,271

169

162

105,151

86,206Total
159,298

141,850

22,816

19,993

298,527

269,461

57,099

50,767

247,501

221,238

127,261

115,041

600,199

538,117Total ProbableCanada
94,499

84,284

7,329

6,404

130,906

120,138

25,288

23,023

78,289

73,227

67,368

60,653

282,297

256,163United States
5,535

4,548

-

-

53,908

44,113

6,426

5,224

60,664

49,801

73

67

75,992

62,196Total
100,034

88,832

7,329

6,404

184,814

164,251

31,714

28,247

138,953

123,028

67,441

60,720

358,289

318,359Total Proved Plus ProbableCanada
252,677

225,221

30,145

26,397

352,611

326,694

71,952

65,307

225,299

211,194

194,460

175,532

777,345

708,074United States
6,654

5,461

-

-

130,730

107,018

16,860

13,707

161,156

133,072

242

229

181,144

148,402Total
259,331

230,682

30,145

26,397

483,341

433,712

88,813

79,014

386,455

344,266

194,702

175,761

958,489

856,476















---

- 19 -





Net Present Value of Future Net Revenue of Oil and Gas Reserves (1)


Before Income Taxes Discounted at

(%/year)



After Income Taxes Discounted at

(%/year)Reserves Category
0%

(MM$)
5%

(MM$)
10%

(MM$)
15%

(MM$)
20%

(MM$)

0%

(MM$)
5%

(MM$)
10%

(MM$)
15%

(MM$)
20%

(MM$)Proved Developed ProducingCanada
10,968

8,225

6,627

5,584

4,851


10,391

7,892

6,422

5,452

4,762United States
913

715

590

505

443


869

681

561

480

422Total
11,881

8,941

7,217

6,089

5,295


11,260

8,572

6,983

5,932

5,184Proved Developed Non-ProducingCanada
390

317

265

227

198


283

239

207

183

165United States
55

43

35

29

25


52

41

33

28

24Total
446

360

300

256

224


336

280

241

211

189Proved UndevelopedCanada
4,060

2,769

1,942

1,393

1,013


2,932

1,958

1,332

917

632United States
1,149

644

360

190

85


1,026

581

325

169

71Total
5,209

3,413

2,302

1,583

1,098


3,958

2,539

1,656

1,086

703Total ProvedCanada
15,418

11,312

8,834

7,204

6,063


13,607

10,089

7,961

6,552

5,559United States
2,118

1,402

984

725

554


1,947

1,303

919

678

517Total
17,536

12,713

9,819

7,929

6,616


15,554

11,392

8,880

7,230

6,076Total ProbableCanada
11,169

6,622

4,477

3,277

2,531


8,147

4,793

3,209

2,327

1,780United States
2,221

1,233

779

535

389


1,375

778

505

358

268Total
13,390

7,855

5,255

3,813

2,919


9,522

5,570

3,714

2,685

2,049Total Proved Plus ProbableCanada
26,587

17,934

13,311

10,482

8,593


21,754

14,882

11,169

8,878

7,339United States
4,339

2,635

1,763

1,260

942


3,323

2,080

1,425

1,036

785Total
30,926

20,569

15,074

11,741

9,535


25,076

16,962

12,594

9,915

8,125












Additional Information Concerning Future Net Revenue – (Undiscounted) (1)


Reserves Category
Revenue

(MM$)
Royalties(2)

(MM$)
Operating

Costs

(MM$)
Development

Costs

(MM$)
Abandonment and Reclamation

Costs

(MM$)
Future Net

Revenue Before

Income Taxes

(MM$)
Income Tax

(MM$)
Future Net

Revenue After

Income Taxes

(MM$)ProvedCanada
35,516

3,689

12,621

2,879

909

15,418

1,811

13,607United States
7,171

1,303

2,493

1,167

90

2,118

171

1,947Total
42,687

4,992

15,113

4,046

999

17,536

1,982

15,554Proved Plus ProbableCanada
58,568

6,116

19,960

4,758

1,147

26,587

4,833

21,754United States
13,208

2,403

4,556

1,780

131

4,339

1,016

3,323Total
71,776

8,519

24,516

6,537

1,277

30,926

5,850

25,076




|    |                                    
|--- | -----------------------------------
|(1) | Numbers may notadd due to rounding.

|    |                                                                                                                                                                              
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Ad Valorem and Severance payable in the United States have been included under operating costs and Saskatchewan Capital Resource Surcharge has been included under royalties.













---

- 20 -





Future Net Revenue by Production Type (6)


Future Net Revenue

Before Income Taxes(5)

(Discounted at 10% per year)
Percentage
Unit Value(MM$)
(%)
($/boe)
($/Mcfe)ProvedCANADALight and Medium Crude Oil(1)
2,948
33.4
18.53
3.09Heavy Crude Oil(1)
378
4.3
18.72
3.12Tight Oil(3)
5,426
61.4
20.90
3.48Natural Gas Liquids
-
-
-
-Shale Gas(4)
-
-
-
-Conventional Natural Gas(2)
82
0.9
6.36
1.06Total Canada
8,834
100.0
19.55
3.26UNITED STATESLight and Medium Crude Oil(1)
15
1.5
16.31
2.72Heavy Crude Oil(1)
-
-
-
-Tight Oil(3)
969
98.5
11.37
1.89Natural Gas Liquids
-
-
-
-Shale Gas(2)
<1
<0.1
8.58
1.43Conventional Natural Gas(2)
<1
<0.1
(3.44)
(0.57)Total United States
984
100.0
11.42
1.90TOTALLight and Medium Crude Oil(1)
2,963
30.2
18.52
3.09Heavy Crude Oil(1)
378
3.8
18.72
3.12Tight Oil(3)
6,395
65.1
18.54
3.09Natural Gas Liquids
-
-
-
-Shale Gas(2)(4)
<1
<0.1
8.58
1.43Conventional Natural Gas(2)
82
0.8
6.36
1.06Total Proved
9,819
100.0
18.25
3.04




|    |                                              
|--- | ---------------------------------------------
|(1) | Including solution gas and other by-products.

|    |                                                   
|--- | --------------------------------------------------
|(2) | Including by-products, but excluding solution gas.

|    |                                                                           
|--- | --------------------------------------------------------------------------
|(3) | Including solution gas (categorized as “Shale Gas”) and other by-products.

|    |                                                                                                                
|--- | ---------------------------------------------------------------------------------------------------------------
|(4) | Volumes of Shale Natural Gas has been included in “Tight Oil” as it is solution gas relating to oil production.

|    |                                                                                                                                                                                  
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(5) | Other company revenue and costs not related to a specific production type have been allocated proportionately to production types. Unit values are based on Company Net Reserves.

|    |                                    
|--- | -----------------------------------
|(6) | Numbers may notadd due to rounding.










---

- 21 -





Future Net Revenue 
 Before Income Taxes(5)

(Discounted at 10% per year)
Percentage
Unit Value(MM$)
(%)
($/boe)
($/Mcfe)Proved Plus ProbableCANADALight and Medium Crude Oil(1)
4,505
33.9
17.50
2.92Heavy Crude Oil(1)
450
3.4
16.89
2.81Tight Oil(3)
8,258
62.0
20.28
3.38Natural Gas Liquids
-
-
-
-Shale Gas(4)
-
-
-
-Conventional Natural Gas(2)
98
0.7
5.83
0.97Total Canada
13,311
100.0
18.80
3.13UNITED STATESLight and Medium Crude Oil(1)
26
1.5
4.69
0.78Heavy Crude Oil(1)
-
-
-
-Tight Oil(3)
1,737
98.5
12.16
2.03Natural Gas Liquids
-
-
-
-Shale Gas(2)
<1
<0.1
8.32
1.39Conventional Natural Gas(2)
<1
<0.1
(0.24)
(0.04)Total United States
1,763
100.0
11.88
1.98TOTALLight and Medium Crude Oil(1)
4,531
30.1
17.24
2.87Heavy Crude Oil(1)
450
3.0
16.89
2.81Tight Oil(3)
9,995
66.3
18.17
3.03Natural Gas Liquids
-
-
-
-Shale Gas(2)(4)
<1
<0.1
8.32
1.39Conventional Natural Gas(2)
98
0.6
5.83
0.97Total Proved Plus Probable
15,074
100.0
17.60
2.93




|    |                                              
|--- | ---------------------------------------------
|(1) | Including solution gas and other by-products.

|    |                                                   
|--- | --------------------------------------------------
|(2) | Including by-products, but excluding solution gas.

|    |                                                                           
|--- | --------------------------------------------------------------------------
|(3) | Including solution gas (categorized as “Shale Gas”) and other by-products.

|    |                                                                                                                
|--- | ---------------------------------------------------------------------------------------------------------------
|(4) | Volumes of Shale Natural Gas has been included in “Tight Oil” as it is solution gas relating to oil production.

|    |                                                                                                                                                                                  
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(5) | Other company revenue and costs not related to a specific production type have been allocated proportionately to production types. Unit values are based on Company Net Reserves.

|    |                                     
|--- | ------------------------------------
|(6) | Numbers may not add due to rounding.









In the tables set forth above in " Disclosure of Reserves Data " and elsewhere in this AIF, the following notes and other definitions are applicable.














---

- 22 -





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

|    |                                                                                                                                                                                                                     
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(b) | "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.

|    |                                                                                                                                                                                                                                                                                                                                          
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(c) | "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.

|    |                                                                                                                                                                                                            
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(d) | "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.

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

|    |                                                                                                                                                                                                                                                                       
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(f) | "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.





|  |                                                                                                                          
|- | -------------------------------------------------------------------------------------------------------------------------
|• | At least a 90% probability that the quantities actually recovered will equal or exceed the estimated Proved reserves; and

|  |                                                                                                                                               
|- | ----------------------------------------------------------------------------------------------------------------------------------------------
|• | At least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable reserves.









---

- 23 -









|    |                                                                                      
|--- | -------------------------------------------------------------------------------------
|(a) | "associated gas" means the gas cap overlying a crude oil accumulation in a reservoir.

|    |                                                                                                                                                                                                                                                                                                                                                          
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(b) | "crude oil" or "oil" means a mixture that consists mainly of pentanes and heavier hydrocarbons, which may contain small amounts of sulphur and other non-hydrocarbons, that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. It does not include liquids obtained from the processing of natural gas.

|    |                                                                                                                                                                                                                                                                                                                                                                    
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(c) | "development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from the reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

|    |                                                                                                                                                                                                                                                                                                                     
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(i) | gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves;

|     |                                                                                                                                                                                                                            
|---- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(ii) | drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and the wellhead assembly;

|      |                                                                                                                                                                                                                                                          
|----- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(iii) | acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds measuring devices and production storage, natural gas cycling and processing plants, and central utility and waste disposal system; and

|     |                                   
|---- | ----------------------------------
|(iv) | provide improved recovery systems.

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

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(e) | "exploration costs" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as "prospecting costs") and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

|    |                                                                                                                                                                                                                                                                                                                   
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(i) | costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies (collectively sometimes referred to as "geological and geophysical costs");

|     |                                                                                                                                                                                                                     
|---- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(ii) | costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;

|      |                                                      
|----- | -----------------------------------------------------
|(iii) | dry hole contributions and bottom hole contributions;

|     |                                                       
|---- | ------------------------------------------------------
|(iv) | costs of drilling and equipping exploratory wells; and

|    |                                                             
|--- | ------------------------------------------------------------
|(v) | costs of drilling exploratory type stratigraphic test wells.







---

- 24 -





|    |                                                                                                                              
|--- | -----------------------------------------------------------------------------------------------------------------------------
|(f) | "exploratory well" means a well that is not a development well, a service well or a development type stratigraphic test well.

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(g) | "field" means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata or laterally by local geologic barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to denote localized geological features, in contrast to broader terms such as "basin", "trend", "province", "play" or "area of interest".

|    |                                                                  
|--- | -----------------------------------------------------------------
|(h) | "future prices and costs" means future prices and costs that are:

|    |                                                                
|--- | ---------------------------------------------------------------
|(i) | generally accepted as being a reasonable outlook of the future;

|     |                                                                                                                                                                                                                                                                                                                                                                                         
|---- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(ii) | if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Corporation 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 (i).

|    |                                                                                                   
|--- | --------------------------------------------------------------------------------------------------
|(i) | "future income tax expenses" means future income tax expenses estimated (generally, year-by-year):

|    |                                                                                                                                                                       
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(i) | making appropriate allocations of estimated unclaimed costs and losses carried forward for tax purposes, between oil and gas activities and other business activities;

|     |                                                                                              
|---- | ---------------------------------------------------------------------------------------------
|(ii) | without deducting estimated future costs that are not deductible in computing taxable income;

|      |                                                                                                 
|----- | ------------------------------------------------------------------------------------------------
|(iii) | taking into account estimated tax credits and allowances (for example, royalty tax credits); and

|     |                                                                                                                                                                                                          
|---- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(iv) | applying to the future pre-tax net cash flows relating to the Corporation's oil and gas activities the appropriate year end statutory tax rates, taking into account future tax rates already legislated.

|    |                                                                                                                                                                                                                                                                   
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(j) | "future net revenue" means the estimated net amount to be received with respect to the anticipated development and production of reserves (including synthetic oil, coal bed methane and other non-conventional reserves) estimated using future prices and costs.

|    |               
|--- | --------------
|(k) | "gross" means:

|    |                                                                                                                                                                                                                                                                 
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(i) | in relation to the Corporation's interest in production or reserves, its "company gross reserves", which are its working interest (operated or non-operated) share before deduction of royalties and without including any royalty interests of the Corporation;

|     |                                                                                              
|---- | ---------------------------------------------------------------------------------------------
|(ii) | in relation to wells, the total number of wells in which the Corporation has an interest; and

|      |                                                                                                  
|----- | -------------------------------------------------------------------------------------------------
|(iii) | in relation to properties, the total area of properties in which the Corporation has an interest.

|    |                                                                                        
|--- | ---------------------------------------------------------------------------------------
|(l) | "natural gas" means a naturally occurring mixture of hydrocarbon gases and other gases.

|    |                                                                                                                                                                                                                                        
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(m) | "natural gas liquids" means those hydrocarbon components that can be recovered from natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes plus, condensate and small quantities of non-hydrocarbons.







---

- 25 -





|    |             
|--- | ------------
|(n) | "net" means:

|    |                                                                                                                                                                                                                         
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(i) | in relation to the Corporation's interest in production or reserves, its working interest (operated or non-operated) share after deduction of royalty obligations, plus its royalty interests in production or reserves;

|     |                                                                                                                                                                   
|---- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(ii) | in relation to the Corporation's interest in wells, the number of wells obtained by aggregating the Corporation's working interest in each of its gross wells; and

|      |                                                                                                                                                                              
|----- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(iii) | in relation to the Corporation's interest in a property, the total area in which the Corporation has an interest multiplied by the working interest owned by the Corporation.

|    |                                                                                                      
|--- | -----------------------------------------------------------------------------------------------------
|(o) | "non-associated gas" means an accumulation of natural gas in a reservoir where there is no crude oil.

|    |                                                                                                                                                                                                                                                                                                                
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(p) | "operating costs" or "production costs" means costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment and facilities as well as other costs of operating and maintaining those wells and related equipment and facilities.

|    |                                                                                                                                                                             
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(q) | "production" means recovering, gathering, treating, field or plant processing (for example, processing gas to extract natural gas liquids) and field storage of oil and gas.

|    |                     
|--- | --------------------
|(r) | "property" includes:

|    |                                                                                                                                                                                                            
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(i) | fee ownership or a lease, concession, agreement, permit, license or other interest representing the right to extract oil or gas subject to such terms as may be imposed by the conveyance of that interest;

|     |                                                                                                                                     
|---- | ------------------------------------------------------------------------------------------------------------------------------------
|(ii) | royalty interests, production payments payable in oil or gas, and other non-operated interests in properties operated by others; and

|      |                                                                                                                                                                                                                                                                      
|----- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(iii) | an agreement with a foreign government or authority under which the Corporation participates in the operation of properties or otherwise serves as "producer" of the underlying reserves (in contrast to being an independent purchaser, broker, dealer or importer).



|    |                                                                                                                                                                                                          
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(s) | "property acquisition costs" means costs incurred to acquire a property (directly by purchase or lease, or indirectly by acquiring another corporate entity with an interest in the property), including:

|    |                                                                    
|--- | -------------------------------------------------------------------
|(i) | costs of lease bonuses and options to purchase or lease a property;

|     |                                                                                                                        
|---- | -----------------------------------------------------------------------------------------------------------------------
|(ii) | the portion of the costs applicable to hydrocarbons when land including rights to hydrocarbons is purchased in fee; and

|      |                                                                                                              
|----- | -------------------------------------------------------------------------------------------------------------
|(iii) | brokers' fees, recording and registration fees, legal costs and other costs incurred in acquiring properties.

|    |                                                                                                              
|--- | -------------------------------------------------------------------------------------------------------------
|(t) | "proved property" means a property or part of a property to which reserves have been specifically attributed.

|    |                                                                                     
|--- | ------------------------------------------------------------------------------------
|(u) | "reservoir" means a subsurface rock unit that contains an accumulation of petroleum.







---

- 26 -





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

|    |                                                         
|--- | --------------------------------------------------------
|(w) | "solution gas" means natural gas dissolved in crude oil.

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(x) | "stratigraphic test well" means a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Ordinarily, such wells are drilled without the intention of being completed for hydrocarbon production. They include wells for the purpose of core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (i) "exploratory type" if not drilled into a proved property; or (ii) "development type", if drilled into a proved property. Development type stratigraphic wells are also referred to as "evaluation wells".

|    |                                                                                                                                                                                                                                                                                          
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(y) | "support equipment and facilities" means equipment and facilities used in oil and gas activities, including seismic equipment, drilling equipment, construction and grading equipment, vehicles, repair shops, warehouses, supply points, camps, and division, district or field offices.

|    |                                                                                                                   
|--- | ------------------------------------------------------------------------------------------------------------------
|(z) | "unproved property" means a property or part of a property to which no reserves have been specifically attributed.

|     |                                                                                                                                                                                                                                                                               
|---- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(aa) | "well abandonment and reclamation costs" means costs of abandoning a well (net of salvage value) and of disconnecting the well from the surface gathering system and reclaiming the site to original conditions. They do not include costs of abandoning the gathering system.





Year
Conventional Natural Gas
Crude Oil
NGLsHenry Hub

NYMEX

($US/MMBTU)
AECO/NIT

Spot

($Cdn/MMBTU)
WTI at

Cushing

Oklahoma

($US/bbl)
Edmonton

($Cdn/bbl)
Pentanes

Plus

Edmonton

($Cdn/bbl)
Butanes

Edmonton

($Cdn/bbl)
Propane

Edmonton

($Cdn/bbl)
Operating Cost Inflation Rate

(%/yr)
Capital Cost Inflation Rate

(%/yr)
Exchange

Rate

($US/$Cdn)Forecast2017
3.50
3.44
55.00
65.58
67.95
47.60
22.74
0.0
0.0
0.7802018
3.50
3.27
65.00
74.51
75.61
55.49
28.04
2.0
2.0
0.8202019
3.50
3.22
70.00
78.24
78.82
57.65
30.64
2.0
2.0
0.8502020
4.00
3.91
71.40
80.64
80.47
58.80
32.27
2.0
2.0
0.8502021
4.08
4.00
72.83
82.25
82.15
59.98
33.95
2.0
2.0
0.8502022
4.16
4.10
74.28
83.90
83.86
61.18
35.68
2.0
2.0
0.8502023
4.24
4.19
75.77
85.58
85.61
62.40
37.46
2.0
2.0
0.8502024
4.33
4.29
77.29
87.29
87.39
63.65
39.30
2.0
2.0
0.8502025
4.42
4.40
78.83
89.03
89.21
64.92
41.19
2.0
2.0
0.8502026
4.50
4.50
80.41
90.81
91.07
66.22
43.13
2.0
2.0
0.8502027
4.59
4.61
82.02
92.63
92.96
67.54
45.14
2.0
2.0
0.8502028+
+2%/yr
+2%/yr
+2%/yr
+2%/yr
+2%/yr
+2%/yr
+2%/yr
2.0
2.0
0.850





For the year ended December 31, 2016, the average realized sales prices before hedging were $47.95/bbl for light and medium crude oil, $39.76/bbl for heavy crude oil, $49.31/bbl for tight crude oil, $15.31/bbl for NGLs, $2.41/mcf for shale gas and $2.27/mcf for conventional natural gas.








---

- 27 -





Reconciliations of Changes in Reserves (1)




CANADA
Light and Medium Crude Oil(Mbbls)
Heavy Crude Oil

(Mbbls)
Tight Oil(7)

(Mbbls)
Natural Gas Liquids

(Mbbls)Factors
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

ProbableDecember 31, 2015
162,856

93,782

256,637

24,492

8,356

32,847

226,536

131,386

357,923

46,684

24,136

70,820Discoveries
-

-

-

-

-

-

-

-

-

-

-

-Extensions and Improved Recovery(8)
8,199

6,067

14,266

-

-

-

15,323

14,890

30,213

2,066

2,508

4,573Technical Revisions
6,254

(7,017
)
(762
)
797

(1,047
)
(251
)
4,091

(17,200
)
(13,109
)
4,293

(1,033
)
3,261Acquisitions(2)
5,803

4,232

10,035

-

-

-

3,760

2,897

6,657

11

5

15Dispositions(3)
(2,092
)
(1,061
)
(3,154
)
(74
)
(21
)
(95
)
-

-

-

(100
)
(58
)
(158
)Economic Factors(4)
(5,864
)
(1,504
)
(7,368
)
(530
)
42

(489
)
(3,338
)
(1,068
)
(4,406
)
(554
)
(269
)
(823
)Production
(16,977
)
-

(16,977
)
(1,868
)
-

(1,868
)
(24,666
)
-

(24,666
)
(5,736
)
-

(5,736
)December 31, 2016
158,179

94,499

252,677

22,816

7,329

30,145

221,705

130,906

352,611

46,665

25,288

71,952





CANADA
Shale Gas
 (Natural Gas)(MMcf)
Conventional Natural Gas
 (Natural Gas)(MMcf)
Total BOE

(Mboe)Factors
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

ProbableDecember 31, 2015
114,784

60,112

174,896

133,265

68,428

201,693

501,909

279,083

780,992Discoveries
-

-

-

-

-

-

-

-

-Extensions and Improved Recovery(8)
8,271

7,097

15,368

2,405

3,254

5,659

27,367

25,190

52,557Technical Revisions
42,945

11,631

54,575

15,403

1,314

16,717

25,160

(24,139
)
1,021Acquisitions(2)
28

11

39

125

32

157

9,599

7,141

16,740Dispositions(3)
-

-

-

(6,195
)
(3,545
)
(9,741
)
(3,299
)
(1,732
)
(5,030
)Economic Factors(4)
(1,142
)
(563
)
(1,704
)
(4,766
)
(2,115
)
(6,882
)
(11,271
)
(3,246
)
(14,517
)Production
(17,877
)
-

(17,877
)
(13,144
)
-

(13,144
)
(54,417
)
-

(54,417
)December 31, 2016
147,009

78,289

225,299

127,092

67,368

194,460

495,048

282,297

777,345





UNITED STATES
Light and Medium Crude Oil(Mbbls)
Heavy Crude Oil

(Mbbls)
Tight Oil(7)

(Mbbls)
Natural Gas Liquids

(Mbbls)Factors
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

ProbableDecember 31, 2015
1,271

5,448

6,719

-
-
-
68,685

46,680

115,365

7,426

4,510

11,936Discoveries
-

-

-

-
-
-
-

-

-

-

-

-Extensions and Improved Recovery
-

-

-

-
-
-
12,028

7,997

20,025

1,486

887

2,373Technical Revisions
385

1,180

1,565

-
-
-
1,400

(2,147
)
(747
)
2,105

863

2,968Acquisitions
-

-

-

-
-
-
2,245

1,827

4,072

278

240

518Dispositions
-

-

-

-
-
-
(5
)
(2
)
(7
)
(1
)
-

(1
)Economic Factors(4)
(135
)
(1,093
)
(1,228
)
-
-
-
(2,705
)
(447
)
(3,152
)
(237
)
(74
)
(311
)Production
(402
)
-

(402
)
-
-
-
(4,827
)
-

(4,827
)
(622
)
-

(622
)December 31, 2016
1,119

5,535

6,654

-
-
-
76,822

53,908

130,730

10,434

6,426

16,860











---

- 28 -





UNITED STATES
Shale Gas 
 (Natural Gas)(MMcf)
Conventional Natural Gas
 (Natural Gas)(MMcf)
Total BOE

(Mboe)Factors
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

ProbableDecember 31, 2015
76,581

47,165

123,746

13

104

117

90,148

64,516

154,664Discoveries
-

-

-

-

-

-

-

-

-Extensions and Improved Recovery
6,583

4,231

10,814

-

-

-

14,611

9,590

24,201Technical Revisions
20,100

7,871

27,970

176

34

210

7,270

1,214

8,483Acquisitions
7,054

2,085

9,139

-

-

-

3,699

2,415

6,113Dispositions
(4
)
(2
)
(6
)
-

-

-

(7
)
(3
)
(9
)Economic Factors(4)
(3,104
)
(686
)
(3,790
)
58

(65
)
(7
)
(3,585
)
(1,739
)
(5,324
)Production
(6,717
)
-

(6,717
)
(78
)
-

(78
)
(6,984
)
-

(6,984
)December 31, 2016
100,492

60,664

161,156

169

73

242

105,151

75,992

181,144





TOTAL
Light and Medium Crude Oil(Mbbls)
Heavy Crude Oil

(Mbbls)
Tight Oil(7)

(Mbbls)
Natural Gas Liquids

(Mbbls)Factors
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

ProbableDecember 31, 2015
164,127

99,230

263,356

24,492

8,356

32,847

295,222

178,066

473,288

54,109

28,646

82,755Discoveries
-

-

-

-

-

-

-

-

-

-

-

-Extensions and Improved Recovery(8)
8,199

6,067

14,266

-

-

-

27,351

22,887

50,238

3,551

3,395

6,946Technical Revisions
6,640

(5,837
)
803

797

(1,047
)
(251
)
5,491

(19,347
)
(13,856
)
6,399

(170
)
6,229Acquisitions(2)
5,803

4,232

10,035

-

-

-

6,005

4,724

10,729

289

245

534Dispositions(3)
(2,092
)
(1,061
)
(3,154
)
(74
)
(21
)
(95
)
(5
)
(2
)
(7
)
(101
)
(58
)
(159
)Economic Factors(4)
(5,999
)
(2,597
)
(8,596
)
(530
)
42

(489
)
(6,043
)
(1,515
)
(7,558
)
(791
)
(343
)
(1,134
)Production
(17,379
)
-

(17,379
)
(1,868
)
-

(1,868
)
(29,494
)
-

(29,494
)
(6,358
)
-

(6,358
)December 31, 2016
159,298

100,034

259,331

22,816

7,329

30,145

298,527

184,814

483,341

57,099

31,714

88,813





TOTAL
Shale Gas
 (Natural Gas)(MMcf)
Conventional Natural Gas
 (Natural Gas)(MMcf)
Total BOE(9)

(Mboe)Factors
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

ProbableDecember 31, 2015
191,365

107,277

298,642

133,278

68,532

201,810

592,056

343,599

935,656Discoveries
-

-

-

-

-

-

-

-

-Extensions and Improved Recovery(8)
14,854

11,328

26,182

2,405

3,254

5,659

41,978

34,779

76,757Technical Revisions
63,044

19,501

82,546

15,579

1,348

16,927

32,430

(22,926
)
9,505Acquisitions(2)
7,082

2,096

9,178

125

32

157

13,297

9,556

22,853Dispositions(3)
(4
)
(2
)
(6
)
(6,195
)
(3,545
)
(9,741
)
(3,305
)
(1,734
)
(5,039
)Economic Factors(4)
(4,246
)
(1,249
)
(5,494
)
(4,708
)
(2,180
)
(6,889
)
(14,856
)
(4,985
)
(19,841
)Production
(24,594
)
-

(24,594
)
(13,222
)
-

(13,222
)
(61,402
)
-

(61,402
)December 31, 2016
247,501

138,953

386,455

127,261

67,441

194,702

600,199

358,289

958,489




|    |                                     
|--- | ------------------------------------
|(1) | Numbers may not add due to rounding.

|    |                                                                                                                                                                                              
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Includes acquisition of assets primarily in the Torquay and Oungre (Ratcliffe) assets, and acquisition of conventional waterflood assets both in the Canadian portion of the Williston basin.

|    |                                                              
|--- | -------------------------------------------------------------
|(3) | Includes disposition of non-core assets in northwest Alberta.

|    |                                                                                                                                                                                                                                                                                           
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(4) | Sproule forecast oil and gas prices at December 31, 2016 were significantly lower than their forecast oil and gas prices at December 31, 2015.  This caused downward adjustments due to these lower prices, representing 2.1% of total Proved plus Probable reserves at December 31, 2015.

|    |                                                                                                                                                                                                                                                    
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(5) | A portion of the increase in total Proved plus Probable Shale Gas volumes recorded are the result of additional volumes being gathered from facility expansions and expenditures; as well as higher solution gas rates on some producing oil wells.

|    |                                                                                                                                    
|--- | -----------------------------------------------------------------------------------------------------------------------------------
|(6) | Negative technical revisions on Probable volumes are reflective of reserve volumes being transferred to Proven reserves categories.

|    |                                                                                                                                                                                                                                                   
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(7) | Negative technical revisions were observed on total Proved plus Probable Tight Oil volumes due to certain wells modestly underperforming the prior years’ forecast, representing 1.5% of total Proved plus Probable reserves at December 31, 2015.

|    |                                                                                                                            
|--- | ---------------------------------------------------------------------------------------------------------------------------
|(8) | Independent evaluators recognized 10.5 MMboe of additional waterflood reserves partially reflected in this change category.

|    |                                                                                                        
|--- | -------------------------------------------------------------------------------------------------------
|(9) | Overall technical revisions represent 1.0% of total Proved plus Probable reserves at December 31, 2015.







---

- 29 -













The following discussion generally describes the basis on which we attribute Proved and Probable undeveloped reserves. Our near-term plans for developing our undeveloped reserves are described in the section " Major Oil and Gas Properties ".










Light & Medium Crude Oil (Mbbl)
Heavy Crude Oil (Mbbl)
Tight Oil

(Mbbl)
Natural Gas Liquids

(Mbbl)
Shale Gas

(MMcf)
Conventional

Natural Gas (MMcf)
Oil Equivalent

(Mboe)First

Attributed(1)
Total at 
 Year-End
First 
 Attributed(1)
Total at 
 Year-End
First 
 Attributed(1)
Total at 
 Year-End
First 
 Attributed(1)
Total at

Year-End
First 
 Attributed(1)
Total at

Year-End
First 
 Attributed(1)
Total at 
 Year-End
First 
 Attributed(1)
Total at 
 Year-End2014
31,264

175,824

-
132

-

-

5,406

16,343

-

-

14,771

95,273

39,133

208,1782015
8,793

45,641

-
2,104

11,854

129,664

2,590

18,740

13,891

91,605

7,949

27,061

26,877

215,9262016
3,164

43,998

-
2,006

9,944

132,529

1,406

19,813

5,535

108,708

1,866

24,915

15,748

220,617




|    |                                                                                                                                                                                                                              
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | "First attributed" refers to reserves first attributed at year-end to corresponding fiscal year. 2014 Tight Oil and Shale Gas values are included with light and medium crude oil and conventional natural gas, respectively.









Probable Undeveloped reserves are generally those reserves tested or indicated by analogy to be productive and lands contiguous to production. The majority of these reserves are planned to be on stream within a five year timeframe. The following table provides the timing of the initial reserve assignments for the Corporation's Probable Undeveloped gross reserves.










---

- 30 -







Light & Medium Crude Oil (Mbbl)
Heavy Crude Oil (Mbbl)
Tight Oil

(Mbbl)
Natural Gas Liquids

(Mbbl)
Shale Gas

(MMcf)
Conventional

Natural Gas (MMcf)
Oil Equivalent

(Mboe)First

Attributed(1)
Total at 
 Year-End
First 
 Attributed(1)
Total at 
 Year-End
First 
 Attributed(1)
Total at 
 Year-End
First 
 Attributed(1)
Total at

Year-End
First 
 Attributed(1)
Total at

Year-End
First 
 Attributed(1)
Total at 
 Year-End
First 
 Attributed(1)
Total at 
 Year-End2014
41,979

135,421

-
267

-

-

5,198

9,602

-

-

18,753

73,398

50,303

157,5222015
14,585

58,775

-
1,803

16,008

106,175

2,906

14,524

13,363

64,188

7,930

34,032

37,048

197,6472016
5,993

62,440

-
1,813

21,649

111,208

2,804

16,710

10,751

78,493

1,457

37,182

32,481

211,449




|    |                                                                                                                                                                                                                                  
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | "First attributed" refers to reserves first attributed at year end of the corresponding fiscal year. 2014 Tight Oil and Shale Gas values are included with light and medium crude oil and conventional natural gas, respectively.





















---

- 31 -









Company Annual Capital Expenditures (MM$)Canada
US
TotalYear
Total Proved
Total Proved

Plus Probable
Total Proved
Total Proved Plus Probable
Total

Proved
Total Proved Plus Probable2017
733
965
119
212
852
1,1772018
902
1,169
366
504
1,268
1,6732019
636
1,083
315
443
951
1,5262020
450
797
223
366
673
1,1632021
74
652
71
156
145
8082022
6
8
73
99
79
1072023
6
5
-
-
6
52024
5
5
-
-
5
52025
5
5
-
-
5
52026
4
4
-
-
4
42027
3
4
-
-
3
42028
3
4
-
-
3
4Subtotal(1)
2,828
4,703
1,167
1,780
3,996
6,483Remainder
51
54
-
-
51
54Total(1)
2,879
4,758
1,167
1,780
4,046
6,53710% Discounted
2,376
3,808
929
1,411
3,305
5,219




|    |                                     
|--- | ------------------------------------
|(1) | Numbers may not add due to rounding.







We estimate that our internally generated cash flow will be sufficient to fund the future development costs (" FDC ") disclosed above. We typically have available three sources of funding to finance our capital expenditure program: Internally generated cash flow from operations, debt financing when appropriate and new equity issues, if available on favourable terms. Debt financing is available to us at market rate plus an applicable margin based on our debt to cash flow ratio. The current rate available to us under prime loan drawdowns, is 3 .75 % per annum. We expect to fund all of our 2017 capital program with internally generated cash flow and, although quarterly fluctuations in funding levels are expected, our objective is to manage leverage throughout 2017.














---

- 32 -

































---

- 33 -





















Producing WellsArea
Oil
GasGross
Net
Gross
NetCANADASoutheast Saskatchewan and Manitoba
6,410

4,606

-

-Southwest Saskatchewan
1,548

1,226

48

16Alberta and West Central Saskatchewan
1,313

1,033

222

165TOTAL CANADA
9,271

6,866

270

181U.S.North Dakota and Montana
369

155

2

1Utah
777

398

163

54TOTAL U.S.
1,146

553

165

55Total(1)
10,417

7,418

435

236











---

- 34 -





Non-Producing WellsArea
Oil
GasGross
Net
Gross
NetCANADASoutheast Saskatchewan and Manitoba
134

105

-

-Southwest Saskatchewan
57

53

-

-Alberta and West Central Saskatchewan
37

29

1

1TOTAL CANADA
228

187

1

1U.S.North Dakota and Montana
8

-

-

-Utah
19

8

-

-TOTAL U.S.
27

8

-

-Total(1)
255

195

1

1




|    |                                     
|--- | ------------------------------------
|(1) | Numbers may not add due to rounding.













As of December 31, 2016Gross Acres
Net Acres
Net Acres Expiring 
 Within One YearCANADAAlberta
449,917

397,995

65,104Saskatchewan
1,350,034

1,279,597

491,429Manitoba
148,086

144,085

81,160British Columbia
38,570

23,324

-Total
1,986,607

1,845,001

637,693U.S.Montana
92,125

66,058

5,387North Dakota
45,570

44,257

6,806Utah
307,821

132,916

12,340Colorado
7,098

6,113

1,858Total
452,614

249,344

26,391Total
2,439,221

2,094,345

664,084













---

- 35 -









Development Wells
Exploration Wells
Total WellsGross
Net
Gross
Net
Gross
NetCANADAOil wells
645
589
30
29
675
618Natural Gas wells
-
-
-
-
-
-Service wells
3
3
-
-
3
3Stratigraphic test
-
-
-
-
-
-Dry Holes
-
-
-
-
-
-Total
648
592
30
29
678
621





Development Wells
Exploration Wells
Total WellsGross
Net
Gross
Net
Gross
NetU.S.Oil wells
33
20
4
4
37
24Natural Gas wells
-
-
-
-
-
-Service wells
-
-
-
-
-
-Stratigraphic Test
-
-
-
-
-
-Dry Holes
-
-
-
-
-
-Total
33
20
4
4
37
24





For details on the most important current and likely exploration and development activities during 2016, see " Statement Of Reserves Data And Other Oil And Gas Information – Major Oil and Gas Properties ".








Costs Incurred (1)




($ millions)
Acquisition CostsProved Properties

Unproved Properties

Exploration Costs

Development CostsCanada
155.7

58.2

28.3

966.5U.S.
8.3

4.3

27.4

116.7Total
164.0

62.5

55.7

1,083.2




|    |                                                   
|--- | --------------------------------------------------
|(1) | Costs incurred exclude capitalized administration.













---

- 36 -







The following table discloses for each product type the gross volume of production estimated by GLJ and Sproule for 2017 in the estimates of future net revenue with forecast pricing from Proved reserves disclosed above under the heading " Reserves Data – Forecast Prices and Costs ".


Light and Medium 
 Crude Oil
Heavy Crude Oil
Tight Oil
NGLs
Shale Gas
Conventional Natural Gas
Total(bbls/d)
(bbls/d)
(bbls/d)
(bbls/d)
(Mcf/d)
(Mcf/d)
(boe/d)CANADAWilliston Basin
26,091

-

47,075

11,068

38,018

5,676

91,517Southwest Saskatchewan
12,100

4,644

21,759

423

7,641

5,885

41,180Alberta
7,426

-

-

2,568

-

20,988

13,492Total CANADA(1)
45,618

4,644

68,834

14,059

45,659

32,549

146,189U.S.Williston Basin
772

-

4,754

929

3,345

52

7,021Uinta Basin
-

-

9,005

667

16,517

32

12,430DJ Basin
-

-

89

4

38

-

99Total U.S.(1)
772

-

13,848

1,601

19,900

84

19,551Total(1)
46,389

4,644

82,682

15,659

65,559

32,633

165,739




|    |                                     
|--- | ------------------------------------
|(1) | Numbers may not add due to rounding.









The following table discloses for each product type the gross volume of production estimated by GLJ and Sproule for 2017 in the estimates of future net revenue with forecast pricing from Proved plus Probable reserves disclosed above under the heading " Reserves Data – Forecast Prices and Costs ".


Region
Light and Medium 
 Crude Oil
Heavy Crude Oil
Tight Oil
NGLs
Shale Gas
Conventional Natural Gas
Total(bbls/d)
(bbls/d)
(bbls/d)
(bbls/d)
(Mcf/d)
(Mcf/d)
(boe/d)CANADAWilliston Basin
29,424

-

56,478

12,829

44,989

6,036

107,235Southwest Saskatchewan
13,487

4,763

25,603

489

8,933

6,367

46,893Alberta
9,100

-

-

2,943

-

23,233

15,915Total CANADA(1)
52,011

4,763

82,081

16,261

53,922

35,636

170,043U.S.Williston Basin
805

-

5,454

1,054

3,806

56

7,957Uinta Basin
-

-

11,629

779

19,722

34

15,701DJ Basin
-

-

94

5

40

-

105Total U.S.(1)
805

-

17,178

1,837

23,568

90

23,763Total(1)
52,816

4,763

99,258

18,098

77,490

35,726

193,806




|    |                                    
|--- | -----------------------------------
|(1) | Numbers may not add due to rounding















---

- 37 -









Average Daily Production Volume (1)


Three Months Ended
Year EndedMarch 31, 2016
June 30, 2016
Sept. 30, 2016
Dec. 31, 2016
2016CANADALight and Medium Crude Oil (bbls/d)
47,607

44,902

45,834

47,194

46,385Heavy Crude Oil (bbls/d)
5,293

5,150

4,829

5,150

5,105Tight Oil (bbls/d)
74,332

68,859

61,984

64,492

67,394NGLs (bbls/d)
15,244

15,056

16,074

16,300

15,671Shale Gas (Mcf/d)
49,294

50,843

46,426

48,839

48,843Conventional Natural Gas (Mcf/d)
36,524

36,222

37,462

33,448

35,912Total (boe/d)
156,779

148,478

142,702

146,851

148,681U.S.Light and Medium Crude Oil (bbls/d)
1,286

1,173

1,003

937

1,099Heavy Crude Oil (bbls/d)
-

-

-

-

-Tight Oil (bbls/d)
15,453

12,646

12,063

12,613

13,189NGLs (bbls/d)
1,531

1,814

1,676

1,783

1,701Shale Gas (Mcf/d)
18,926

18,442

18,731

17,321

18,354Conventional Natural Gas (Mcf/d)
228

202

264

157

212Total (boe/d)
21,462

18,740

17,908

18,246

19,083TOTALLight and Medium Crude Oil (bbls/d)
48,893

46,075

46,837

48,131

47,484Heavy Crude Oil (bbls/d)
5,293

5,150

4,829

5,150

5,105Tight Oil (bbls/d)
89,785

81,505

74,047

77,105

80,583NGLs (bbls/d)
16,775

16,870

17,750

18,083

17,372Shale Gas (Mcf/d)
68,220

69,285

65,157

66,160

67,197Conventional Natural Gas (Mcf/d)
36,752

36,424

37,726

33,605

36,124Total (boe/d)
178,241

167,218

160,610

165,097

167,764




|    |                                     
|--- | ------------------------------------
|(1) | Numbers may not add due to rounding.













---

- 38 -







Three Months Ended
Year Ended($ per bbl)
March 31, 2016
June 30, 2016
Sept. 30, 2016
Dec. 31, 2016
2016CANADAPrices Received – net of hedging
54.32
58.59
60.00
60.90
58.44Royalties
(4.98)
(7.53)
(7.78)
(8.27)
(7.13)Production Costs(1)
(11.55)
(12.06)
(14.35)
(13.46)
(12.86)Transportation Costs(1)
(2.29)
(2.34)
(2.29)
(2.20)
(2.28)Netback
35.50
36.66
35.58
36.97
36.17U.S.Prices Received – net of hedging
30.98
45.45
46.18
52.51
42.92Royalties
(7.74)
(11.74)
(11.85)
(13.74)
(11.03)Production Costs(1)
(10.47)
(14.35)
(12.51)
(12.67)
(12.44)Transportation Costs(1)
-
(0.01)
-
(0.01)
(0.01)Netback
12.77
19.35
21.82
26.09
19.44TOTALPrices Received – net of hedging
53.71
58.25
59.70
60.74
58.08Royalties
(5.05)
(7.63)
(7.87)
(8.38)
(7.22)Production Costs(1)
(11.52)
(12.12)
(14.31)
(13.44)
(12.85)Transportation Costs(1)
(2.23)
(2.28)
(2.24)
(2.15)
(2.23)Netback
34.91
36.22
35.28
36.77
35.78




|    |                                                                                                                                                                                              
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Production costs and transportation costs consist of direct costs incurred to operate both oil and gas wells. Costs are allocated between all product types based on a number of assumptions.









Three Months Ended
Year Ended($ per bbl)
March 31, 2016
June 30, 2016
Sept. 30, 2016
Dec. 31, 2016
2016CANADAPrices Received – net of hedging
27.06
41.71
42.80
47.86
39.76Royalties
(5.55)
(11.27)
(10.99)
(12.74)
(10.10)Production Costs(1)
(8.71)
(10.34)
(11.88)
(11.47)
(10.57)Transportation Costs(1)
(1.71)
(1.74)
(1.76)
(1.75)
(1.74)Netback
11.09
18.36
18.17
21.90
17.35U.S.Prices Received – net of hedging
-
-
-
-
-Royalties
-
-
-
-
-Production Costs(1)
-
-
-
-
-Transportation Costs(1)
-
-
-
-
-Netback
-
-
-
-
-TOTALPrices Received – net of hedging
27.06
41.71
42.80
47.86
39.76Royalties
(5.55)
(11.27)
(10.99)
(12.74)
(10.10)Production Costs(1)
(8.71)
(10.34)
(11.88)
(11.47)
(10.57)Transportation Costs(1)
(1.71)
(1.74)
(1.76)
(1.75)
(1.74)Netback
11.09
18.36
18.17
21.90
17.35




|    |                                                                                                                                                                                              
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Production costs and transportation costs consist of direct costs incurred to operate both oil and gas wells. Costs are allocated between all product types based on a number of assumptions.













---

- 39 -







Three Months Ended
Year Ended($ per bbl)
March 31, 2016
June 30, 2016
Sept. 30, 2016
Dec. 31, 2016
2016CANADAPrices Received – net of hedging
55.70
63.18
60.89
63.26
60.62Royalties
(4.43)
(5.34)
(6.63)
(7.36)
(5.87)Production Costs(1)
(11.84)
(13.01)
(14.57)
(13.98)
(13.28)Transportation Costs(1)
(3.14)
(3.09)
(2.65)
(3.00)
(2.98)Netback
36.29
41.74
37.04
38.92
38.49U.S.Prices Received – net of hedging
38.58
48.56
50.10
56.70
47.96Royalties
(9.76)
(11.75)
(8.91)
(15.80)
(11.49)Production Costs(1)
(13.04)
(15.34)
(13.57)
(13.68)
(13.86)Transportation Costs(1)
0.08
(0.00)
(0.11)
(0.23)
(0.06)Netback
15.86
21.47
27.51
26.99
22.55TOTALPrices Received – net of hedging
52.75
60.91
59.13
62.19
58.55Royalties
(5.35)
(6.33)
(7.00)
(8.74)
(6.79)Production Costs(1)
(12.05)
(13.37)
(14.40)
(13.93)
(13.38)Transportation Costs(1)
(2.59)
(2.61)
(2.24)
(2.54)
(2.50)Netback
32.76
38.60
35.49
36.98
35.88




|    |                                                                                                                                                                                              
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Production costs and transportation costs consist of direct costs incurred to operate both oil and gas wells. Costs are allocated between all product types based on a number of assumptions.









Three Months Ended
Year Ended($ per bbl)
March 31, 2016
June 30, 2016
Sept. 30, 2016
Dec. 31, 2016
2016CANADAPrices Received
8.02
13.77
15.46
21.56
14.85Royalties
(1.20)
(1.20)
(1.17)
(1.50)
(1.27)Production Costs(1)
(2.58)
(3.41)
(4.29)
(5.17)
(3.90)Transportation Costs(1)
(0.51)
(0.45)
(0.19)
(0.41)
(0.39)Netback
3.73
8.71
9.81
14.48
9.29U.S.Prices Received
13.17
17.56
20.15
26.27
19.52Royalties
(2.11)
(4.03)
(4.93)
(4.95)
(4.07)Production Costs(1)
(4.43)
(5.56)
(5.45)
(6.35)
(5.49)Transportation Costs(1)
(0.69)
(0.44)
(0.53)
(0.42)
(0.51)Netback
5.94
7.53
9.24
14.55
9.45TOTALPrices Received
8.49
14.18
15.90
22.02
15.31Royalties
(1.28)
(1.50)
(1.52)
(1.84)
(1.54)Production Costs(1)
(2.75)
(3.64)
(4.40)
(5.28)
(4.05)Transportation Costs(1)
(0.52)
(0.45)
(0.23)
(0.41)
(0.40)Netback
3.94
8.59
9.75
14.49
9.32




|    |                                                                                                                                                                                              
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Production costs and transportation costs consist of direct costs incurred to operate both oil and gas wells. Costs are allocated between all product types based on a number of assumptions.













---

- 40 -







Three Months Ended
Year Ended($ per Mcf)
March 31, 2016
June 30, 2016
Sept. 30, 2016
Dec. 31, 2016
2016CANADAPrices Received - net of hedging
2.44
2.57
3.01
3.48
2.87Royalties
(0.29)
(0.15)
(0.30)
(0.44)
(0.29)Production Costs(1)
(0.76)
(0.49)
(0.81)
(0.87)
(0.73)Transportation Costs(1)
(0.23)
(0.18)
(0.22)
(0.19)
(0.20)Netback
1.16
1.75
1.68
1.98
1.65U.S.Prices Received - net of hedging
2.30
2.43
3.14
3.69
2.88Royalties
(0.47)
(0.56)
(0.72)
(0.67)
(0.61)Production Costs(1)
(0.75)
(0.75)
(0.87)
(0.90)
(0.82)Transportation Costs(1)
(0.47)
(0.67)
(0.65)
(0.59)
(0.59)Netback
0.61
0.45
0.90
1.53
0.86TOTALPrices Received - net of hedging
2.40
2.54
3.05
3.54
2.87Royalties
(0.34)
(0.26)
(0.42)
(0.50)
(0.38)Production Costs(1)
(0.76)
(0.56)
(0.83)
(0.88)
(0.75)Transportation Costs(1)
(0.30)
(0.31)
(0.34)
(0.29)
(0.31)Netback
1.00
1.41
1.46
1.87
1.43




|    |                                                                                                                                                                                              
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Production costs and transportation costs consist of direct costs incurred to operate both oil and gas wells. Costs are allocated between all product types based on a number of assumptions.









Three Months Ended
Year Ended($ per Mcf)
March 31, 2016
June 30, 2016
Sept. 30, 2016
Dec. 31, 2016
2016CANADAPrices Received - net of hedging
2.66
2.60
3.00
3.50
2.93Royalties
0.23
0.01
(0.24)
(0.03)
(0.01)Production Costs(1)
(0.83)
(0.50)
(0.81)
(0.88)
(0.75)Transportation Costs(1)
(0.44)
(0.25)
(0.26)
(0.28)
(0.31)Netback
1.62
1.86
1.69
2.31
1.86U.S.Prices Received - net of hedging
0.84
0.45
1.44
2.04
1.16Royalties
(0.19)
0.34
(0.68)
(0.52)
(0.28)Production Costs(1)
(0.27)
(0.14)
(0.40)
(0.50)
(0.32)Transportation Costs(1)
-
-
-
-
-Netback
0.38
0.65
0.36
1.02
0.56TOTALPrices Received - net of hedging
2.65
2.59
2.99
3.50
2.92Royalties
0.23
0.01
(0.24)
(0.03)
(0.01)Production Costs(1)
(0.83)
(0.49)
(0.80)
(0.88)
(0.75)Transportation Costs(1)
(0.44)
(0.25)
(0.26)
(0.28)
(0.31)Netback
1.61
1.86
1.69
2.31
1.85




|    |                                                                                                                                                                                              
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Production costs and transportation costs consist of direct costs incurred to operate both oil and gas wells. Costs are allocated between all product types based on a number of assumptions.













---

- 41 -









Region
Light and 
 Medium

Crude Oil
Heavy Crude Oil
Tight Oil
NGLs
Shale Gas
Conventional Natural Gas
Total(bbls/d)
(bbls/d)
(bbls/d)
(bbls/d)
(Mcf/d)
(Mcf/d)
(boe/d)CANADAWilliston Basin
26,390

-

49,191

13,277

42,057

4,374

96,597Southwest Saskatchewan
12,191

5,096

18,203

293

6,786

8,738

38,370Alberta
7,804

9

-

2,101

-

22,800

13,714Total CANADA(1)
46,385

5,105

67,394

15,671

48,843

35,912

148,681U.S.Williston Basin
1,099

-

4,211

803

2,952

212

6,640Uinta Basin
-

-

8,978

898

15,402

-

12,443DJ Basin
-

-

-

-

-

-

-Total U.S.(1)
1,099

-

13,189

1,701

18,354

212

19,083Total(1)
47,484

5,105

80,583

17,372

67,197

36,124

167,764




|    |                                     
|--- | ------------------------------------
|(1) | Numbers may not add due to rounding.



















---

- 42 -







Name and Municipality of Residence
Position Held with the Corporation
Date First Elected or Appointed as DirectorScott Saxberg(4)Calgary, Alberta
President, Chief Executive Officer and Director
2003Kenneth R. Lamont 
 Calgary, Alberta
Chief Financial Officer
Not applicableC. Neil Smith 
 Calgary, Alberta
Chief Operating Officer
Not applicableDerek Christie 
 Calgary, Alberta
Sr. Vice President, Exploration & Geosciences
Not applicableTamara MacDonald 
 Calgary, Alberta
Sr. Vice President, Corporate and Business Development
Not applicableBrad Borggard 
 Calgary, Alberta
Vice President, Corporate Planning and Investor Relations
Not applicableMark G. Eade 
 Calgary, Alberta
Vice President, General Counsel and Corporate Secretary
Not applicableRyan Gritzfeldt 
 Calgary, Alberta
Vice President, Marketing and Innovation
Not applicableSteven Toews 
 Calgary, Alberta
Vice President, Engineering and Operations
Not applicablePeter Bannister(1) (3)Calgary, Alberta
Director and Chairman
2003Rene Amirault(4) (5)Calgary, Alberta
Director
2014Laura A. Cillis(1) (2) (4)Calgary, Alberta
Director
2014D. Hugh Gillard(1) (2) (5)Calgary, Alberta
Director
2003Robert F. Heinemann(2) (3) (4)Plano, Texas
Director
2014Mike JacksonCalgary, Alberta
Director
2016Barbara Munroe(2) (5)Calgary, Alberta
Director
2016Gerald A. Romanzin(1) (3)Calgary, Alberta
Director
2004Gregory G. Turnbull, QC(3) (5)Calgary, Alberta
Director
2001




|    |                               
|--- | ------------------------------
|(1) | Member of the Audit Committee.

|    |                                      
|--- | -------------------------------------
|(2) | Member of the Compensation Committee.

|    |                                  
|--- | ---------------------------------
|(3) | Member of the Reserves Committee.

|    |                                                          
|--- | ---------------------------------------------------------
|(4) | Member of the Environmental, Health and Safety Committee.

|    |                                                         
|--- | --------------------------------------------------------
|(5) | Member of Corporate Governance and Nominating Committee.

|    |                                                                                                                                                                                                                                                                                                  
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(6) | Trent Stangl of Calgary, Alberta was the Sr. Vice President, Investor Relations and Communications of Crescent Point, a role he held from February 2016 to February 2017, when he stepped down from that position. From 2008 until 2016, he was Vice President, Marketing and Investor Relations.











Scott Saxberg is the President, Chief Executive Officer and a director of Crescent Point. He was a founder of Crescent Point Energy Ltd. (" CPEL ") in 2001 and has been president of Crescent Point since 2003. Mr. Saxberg has worked in the oil and gas industry since 1992, having held a variety of roles with companies such as Shelter Bay, Wascana Energy Inc., Numac Energy Inc. and Magin Energy Inc.








---

- 43 -



































---

- 44 -





Ms. MacDonald is a member of the Canadian Association of Petroleum Landmen, of the American Association of Petroleum Landmen, the Canadian Association of Petroleum and Land Administration, the Petroleum and Acquisition Divestment Association and is a member of the 25 th UNICEF Canada Team. She holds a Bachelor of Commerce degree, with a major in Petroleum Land Management, from the University of Calgary.
































---

- 45 -

































---

- 46 -





































---

- 47 -



















Gerald A.  Romanzin


















---

- 48 -













Premium Dividend TM and Dividend Reinvestment Plan






















---

- 49 -







Under the terms of the Corporation's Restricted Share Bonus Plan, any director, officer, consultant or employee of the Corporation who, in each case, in the opinion of the board of directors of the Corporation, hold an appropriate position with the Corporation to warrant participation in the Restricted Share Bonus Plan (collectively, the " Participants ") may be granted restricted shares (" Restricted Shares ") which vest over time and, upon vesting, can be redeemed by the holder for cash or Common Shares. The Restricted Share Bonus Plan is administered by the board of directors. Under the Restricted Share Bonus Plan at December 31, 2016 the Corporation is authorized to issue up to 16,665,451 Common Shares, of which the Corporation had 5,188,358 restricted shares outstanding at December 31, 2016.


The Restricted Shares vest on terms up to three years from the grant date as determined by the board of directors of the Corporation. Upon redemption, the Corporation will be required to pay to the Participant the fair market value of the redeemed Restricted Shares, based on the weighted average of the prices at which the Common Shares traded on the TSX for the five trading days immediately preceding the redemption date, plus any accrued but unpaid dividend amounts in respect of such Restricted Shares (the " Payout Amount "). The Payout Amount may be satisfied by the Corporation making a cash payment, the Corporation purchasing Common Shares in the market and delivering such Common Shares to the Participant or by issuing Common Shares from treasury.




In 2012, the Corporation established a deferred share unit plan (the " DSU Plan ") to enhance its ability to attract and retain key personnel (namely, selected officers and employees and non-employee directors) and reward significant performance achievements. Under the terms of the DSU Plan, Designated Employees and Directors (as defined in the DSU Plan), who, in the opinion of the Board of the Directors of the Corporation, warrant participation in the DSU Plan (the " Participants "), may be granted deferred share units (" Units "). As at the date hereof, only non-employee directors have been granted DSUs.




The Corporation establishes an account for each Participant and all Units are credited to the applicable account as of the award date. The number of Units to be credited to an account is determined by dividing the dollar amount elected by the Participant by the five day weighted average closing price of the Common Shares on the TSX immediately prior to the award date. On the last day of each fiscal quarter of the Corporation or as soon as possible thereafter, the Corporation determines whether any dividend has been paid on Common Shares during such fiscal quarter and, if so, the rate thereof per Common Share (the " Dividend Rate ") and, within 10 business days of the applicable fiscal month end, the Corporation credits each applicable account with an additional number of Units equal to (i) the number of Units in the applicable account on the record date for such dividend multiplied by (ii) the Dividend Rate. All Units vest immediately upon being credited to a Participant's account.










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At December 31, 2016, the Corporation had a $3.5 billion syndicated unsecured credit facility with a permitted increase (subject to certain conditions) to $4.0 billion (the " Syndicated Credit Facility ") and a $100 million unsecured operating credit facility with one Canadian chartered bank (the " Bi-Lateral Credit Facility "). The Syndicated Credit Facility is with sixteen banks and totals $3.5 billion until June 8, 2018, after which it reduces to thirteen banks and $3.08 billion through to a maturity date of June 10, 2019. The current maturity date of the Bi-Lateral Credit Facility is June 10, 2019. The Syndicated Credit Facility's interest rate is based on either Canadian prime rate, U.S. base rate, London Interbank Offer Rate or bankers acceptance rates at the Corporation's option subject to certain basis point or stamping fee adjustments ranging from 0.50% to 3.15% depending on the Corporation's senior debt to earnings before interest, taxes, depreciation and amortization, adjusted for certain non-cash items (" adjusted EBITDA ") ratio. The Credit Facilities are guaranteed by certain material restricted subsidiaries currently being CPEUS, CPUSH, CPHI and the Partnership. Various borrowing options are available under the Credit Facilities, including Canadian prime rate-based advances, U.S. base rate-based advances, London Interbank Offer Rate loans and bankers' acceptance loans. The Bi-Lateral Credit Facility and Syndicated Credit Facility constitute revolving credit facilities and are extendible annually. The Credit Facilities contain standard commercial covenants for facilities of this nature. Distributions to Shareholders are not permitted if the Corporation is in default of the Credit Facilities or if the making of such distribution would cause an event of default. The Corporation does not have a borrowing base restriction respecting its Credit Facilities. Concurrent with the drawdown of US$1.21 billion of LIBOR loans, the Company entered into various CCS to hedge its foreign exchange exposure. Under the terms of the CCS, the US dollar amounts of the LIBOR loans were fixed for purposes of interest and principal repayments at a notional amount of $1.61 billion.

















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In Canada and the United States, producers of oil negotiate sales contracts directly with oil purchasers. Oil prices are primarily based on worldwide and North American supply and demand. The specific price paid depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance. In the United States, transportation of crude oil is subject to rate and access regulation. The Federal Energy Regulatory Commission (the " FERC ") regulates interstate crude oil pipeline transportation rates under the Interstate Commerce Act of 1887 (the " ICA "). In general, such pipeline rates must be cost-based. The FERC requires that pipelines regulated under the ICA file tariffs setting forth the rates and terms and conditions of service. Such rates and terms and conditions may not be discriminatory or preferential. At the beginning of 1995, regulations adopted by FERC generally grandfathered all previously approved interstate transportation rates and established an indexing system for such rates permitting annual adjustments based on the rate of inflation, subject to certain limitations. Every five years, the FERC examines the annual change compared to the actual cost changes. In December 2015, under the five-year re-determination, the FERC adjusted the index level used to determine annual changes to oil pipeline rate ceilings and determined that the Producer Price Index for Finished Goods plus 1.23% should be the index level for the five-year period beginning July 1, 2016. A pipeline may also file cost-of-service based rates if rate indexing will be insufficient to allow the pipeline to recover its costs. Intrastate crude oil pipeline transportation rates may be subject to regulation by state regulatory commissions. The basis for intrastate pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state. Oil exports from Canada may be made pursuant to an export contract with a term not exceeding one year in the case of light crude oil, and not exceeding two years in the case of heavy crude oil, provided that an order approving any such export has been obtained from the National Energy Board (" NEB "). Any 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 and the issue of such a licence requires the approval of the Governor in Council. On December 18, 2015, the U.S. Congress passed and the President signed legislation into law which repealed the 40-year old ban on exports of crude oil produced in the United States. Accordingly, most exports of domestically-produced crude oil may be made without an export license. Only exports to embargoed or sanctioned countries continue to require authorization from the U.S. Department of Commerce.




In Canada, the price of natural gas sold intra-provincially or to the United States is determined by negotiation between buyers and sellers. In the United States, the price of sales inter-state or internationally is determined by negotiation between buyers and sellers based upon factors normally considered in the industry such as distance from well to pipeline, pressure, and quality. Natural gas exported from Canada is subject to regulation by the NEB and the government of Canada and in the United States is regulated principally by the FERC and the United States Department of Energy (" DOE "). The FERC, which has the authority under the Natural Gas Act of 1938 (" NGA ") to regulate prices, terms, and conditions for the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to FERC regulation, except interstate pipelines, to resell natural gas at market prices. In addition, under the provisions of the Energy Policy Act of 2005, the NGA was amended to prohibit market manipulation in connection with the purchase or sale of natural gas and the FERC established regulations to increase natural gas pricing transparency by requiring certain market participants to report their gas sales transactions annually to the FERC. Facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. However, the distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities is the subject of on-going litigation and, therefore, is subject to change based on future determinations. The FERC regulates interstate natural gas transportation rates and service conditions under the NGA and the Natural Gas Policy Act of 1978 (" NGPA "), which affects the marketing of natural gas, as well as revenues we may receive for sales of our natural gas. Intrastate natural gas transportation service is also subject to regulation by state regulatory agencies.








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In both Canada and the United States, exporters are free to negotiate prices and other terms with purchasers, provided that the export contract meets certain criteria prescribed by the NEB and the government of Canada or, in relation to United States exports, restrictions on export licenses imposed by the DOE. Natural gas may not be imported into Canada or exported from Canada without a licence or order from the NEB or imported into the United States or exported from the United States without a license from the DOE. Licences to export or import natural gas may include various terms and conditions with respect to duration, quantity, tolerance levels, points of exportation or importation, environmental requirements, among other factors and, in Canada, may be obtained for a period that does not exceed 40 years in the case of export and 25 years in the case of import. In Canada, the approval of the Governor in Council is required prior to the issuance of a licence by the NEB to import or export natural gas. Alternatively, natural gas can be imported into Canada or exported from Canada pursuant to an order from the NEB. Orders may be obtained for a period of 2 years or less or for a period greater than 2 years but less than 20 years, where the quantity is not more than 30,000 m 3 /day. Orders do not require the approval of the Governor in Council. In the United States, the DOE regulates the exportation and importation of natural gas, including liquefied natural gas. 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’s regulation of imports and exports from and to countries without such free trade agreements is more comprehensive. The FERC also regulates the construction and operation of import and export facilities.






















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Alberta has adopted a new, modernized Alberta royalty framework (the " Modernized Framework ") that applies to all wells drilled after January 1, 2017. The previous royalty framework (the " Old Framework ") will continue to apply to wells drilled prior to January 1, 2017 for a period of ten years ending on December 31, 2026. After the expiry of this ten-year period, these older wells will become subject to the Modernized Framework.


The Modernized Framework applies to all hydrocarbons other than oil sands which will remain subject to their existing royalty regime. Royalties on production from non-oil sands wells under the Modernized Framework is determined on a “revenue-minus-costs” basis with the cost component based on a Drilling and Completion Cost Allowance formula for each well, depending on its vertical depth and horizontal length. The formula is based on the industry’s average drilling and completion costs as determined by the Alberta Energy Regulator (" AER ") on an annual basis.




















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Pursuant to the Old Framework a number of incentive programs, such as the Deep Oil Exploratory Well Program, the Enhanced Oil Recovery Royalty Program (" EOR Program "), the Natural Gas Deep Drilling Program, and the Innovative Energy Technologies Program (the " IETP "), were created.












The new Enhanced Hydrocarbon Recovery Program (the " EHR Program ") began January 1, 2017 and replaced the existing EOR Program. The EHR Program is intended to promote incremental production through enhanced recovery methods and consists of two main components. The first component targets tertiary recovery schemes which enhance recovery of hydrocarbons from an oil or gas pool by miscible flooding, immiscible flooding, solvent flooding, chemical flooding or other approved methods. The second component targets secondary recovery schemes which enhance recovery of hydrocarbons from an oil or gas pool by water flooding, gas cycling, gas flooding, polymer flooding or other approved methods. Under both components of the program, a company pays a flat royalty of 5 per cent on crude oil, natural gas and natural gas liquids produced from wells in an approved scheme for a limited benefit period. After the benefit period ends, wells in these schemes are subject to normal royalty rates under the Modernized Framework.


The new Emerging Resources Program (the " ERP ") began January 1, 2017. The ERP is intended to encourage industry to open up new oil and gas resources in higher-risk and higher-cost areas that have large resource potential. For the purposes of the ERP, a project consists of a defined geographic area, target formation, set of wells and associated infrastructure. Wells that receive program benefits pay a flat royalty rate of 5 per cent until their combined revenue equals their combined program specific cost allowances established under the ERP, which will replace the standard Drilling and Completion Cost Allowance under the Modernized Framework in respect of such wells. After achieving payout of the specific cost allowance, wells are subject to normal royalty rates under the Modernized Framework.




With respect to production obtained from Crown lands in the Province of Saskatchewan, the amount payable as a royalty in respect of crude oil depends on the vintage of the oil, the type of oil, the quantity of oil produced in a month, and the price of the oil. For both Crown royalty and freehold production tax purposes, crude oil is categorized by oil type as either "heavy oil", "southwest designated oil", or "non-heavy oil other than southwest designated oil". Additionally, the oil in each category is subdivided according to the conventional royalty and production tax classifications as either "fourth tier oil", "third tier oil", "new oil", or "old oil". Depending on the categorization and classification of the oil, monthly production, and a prescribed reference price determined monthly by the Saskatchewan Ministry of Economy (" SME "), the royalty reserved to the Crown ranges from 0% to 45%.








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On October 1, 2002, a modified system of incentive volumes and maximum royalty/tax rates applicable to the initial production from qualifying oil wells and gas wells in the Province of Saskatchewan with a finished drilling date on or after October 1, 2002, was introduced. The incentive volumes are applicable to various well types and are subject to a maximum royalty rate of 2.5% and a freehold production tax rate of 0%. In addition, oil produced from Enhanced Oil Recovery (" EOR ") projects that commenced operation prior to April 1, 2005 are subject to a cost sensitive royalty regime determined by prescribed formulas which include a number of variables and which differentiate between pre and post project payout. EOR projects that commenced operation on or after April 1, 2005 are also subject to a cost sensitive royalty regime that provides a royalty of 1% of gross EOR revenues prior to project payout and 20% of EOR operating income after project payout and a freehold production tax rate of 0% prior to payout and 8% of EOR operating income after payout.


In April of 2013, the SME announced three new drilling incentives for wells drilled on or after October 1, 2002: the vertical well drilling incentive (" VWD "), the horizontal well drilling incentive (" HWD ") and the exploratory gas well drilling incentive (" EGWD "). The VWD provides a royalty reduction to 2.5% and a freehold production tax rate of 0% for fixed volumes drilled from exploratory vertical oil wells and deep development vertical oil wells. Exploratory vertical oil wells are wells that meet certain prescribed criteria showing the well produces oil from an area which has not generally seen production. The incentive for exploratory vertical oil wells applies to the produced volume up to 16,000 m3, depending on depth. Deep development vertical oil wells are deep or deepened wells, that are not exploratory oil wells, drilled to certain prescribed zones. The incentive for these wells applies to the produced volume up to 8,000 m3. The HWD is very similar to the VWD, but applies to non-exploratory horizontal wells drilled on or after October 1, 2002 and provides the incentive to produced volumes up to 16,000 m3, depending on depth. Finally, the EGWD provides a royalty reduction of the lesser of the fourth tier gas royalty rate (between 0%-5%) or 2.5% and a 0% freehold production tax rate. The incentive applies to wells that meet certain prescribed criteria showing the well produces gas from an area which has not generally been produced from. The incentive applies to the produced volume up to 25,000,000 m3.














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The Government of Manitoba maintains a Drilling Incentive Program (the " Program ") with the intent of promoting investment in the development of petroleum resources. The Program provides the licensee of newly drilled wells, or qualifying wells where a major workover has been completed, with a "holiday oil volume." Under the Program, a new well drilled or a well receiving workover incentive, after December 31, 2013 and before January 1, 2019 will be required to pay a minimum Crown royalty, or if the well is producing from freehold oil and gas rights, a minimum production tax while holiday oil is produced.




|  |                                                                                                                                                                                                                                                                                                                     
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | Vertical Well Incentiveprovides licensees of a vertical development well or exploratory well drilled between December 31, 2013 and January 1, 2019 with 500 m3of holiday oil volume. To qualify the well must be drilled less than 1.6 km from the nearest well cased for production from the same or a deeper zone.

|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | Exploration and Deep Well Incentiveprovides licensees who drill an exploration well or a deep development well between December 31, 2013 and January 1, 2019 with a holiday oil volume as follows: (i) for a well drilled more than 1.6 km from a well cased for production from the same zone or a deeper zone, a holiday oil volume of 4,000 m3is earned; (ii) for an exploratory well drilled below the Birdbear Formation, a holiday oil volume of 8,000 m3is earned; and (iii) for a development well completed for production in the Birdbear or deeper formation, a holiday oil volume of 8,000 m3is earned.

|  |                                                                                                                                                             
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | Horizontal Well Incentiveprovides licensees of horizontal wells drilled between December 31, 2013 and January 1, 2019 with a holiday oil volume of 8,000 m3.

|  |                                                                                                                                                                                                                                                                                                                                                                             
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | Marginal Well Major Workover Incentiveprovides licensees of marginal wells where a major workover is completed prior to January 1, 2019 with a holiday oil volume of 500 m3, with a marginal oil well defined as an abandoned well or a well that was either not operated over the previous 12 months or produced oil at an average rate of less than 3 m3per operating day.

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|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | Pressure Maintenance Project Incentiveprovides a one year exemption from the payment of Crown royalty or freehold production tax on production allocated to a unit tract in which an injection well is drilled or a well is converted to water injection. Wells eligible for the incentive include those wells drilled for the purpose of injection in an approved enhanced recovery project as well as vertical or horizontal wells that are converted to injection. For wells converted to injection between December 31, 2013 and January 1, 2019 the exemption period is extended to 18 months.







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|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | Solution Gas Incentiveprovides an exemption from the payment of Crown royalties and production taxes for new solution gas projects implemented after December 31, 2013 and effective until December 31, 2018 and subject to approval from the Director of Petroleum.











Environmental legislation in the Province of Alberta is, for the most part, set out in the Environmental Protection and Enhancement Act , the Oil and Gas Conservation Act , the Water Act and the Climate Change and Emissions Management 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 , 2010 and the Oil and Gas Conservation Act , which regulate harmful or potentially harmful activities and substances, any release of such substances, and remediation and abandonment obligations in Saskatchewan. Certain development activities in Saskatchewan, depending on the location and potential environmental impact, may require an environmental impact assessment under the provincial Environmental Assessment Act . Environmental Legislation in the Province of Manitoba is, for the most part, set out in the Environment Act and the Oil and Gas Act .












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The Comprehensive Environmental Response, Compensation, and Liability Act (the " CERCLA ") and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. It is not uncommon for the government to file claims requiring cleanup actions, demands for reimbursement for cleanup costs, or natural resource damages, or for neighbouring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. The CERCLA currently excludes petroleum from its definition of "hazardous substance."


The Federal Solid Waste Disposal Act (the " SWDA "), the Resource Conservation and Recovery Act (the " RCRA ") and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize the imposition of substantial fines and penalties for noncompliance, as well as requirements for corrective actions.


Other statutes relating to the storage and handling of pollutants include the Oil Pollution Act of 1990 (the " OPA "), which requires certain owners and operators of facilities that store or otherwise handle oil to prepare and implement spill response plans relating to the potential discharge of oil into surface waters. The OPA contains numerous requirements relating to prevention of, reporting of, and response to oil spills into waters of the United States. State laws mandate oil cleanup programs with respect to contaminated soil. A failure to comply with the OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions.








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The Endangered Species Act (the " ESA ") seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, or destroy or modify the critical habitat of such species. Under the ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. The ESA has been used to prevent or delay drilling activities and provides for criminal penalties for wilful violations of its provisions. Other statutes that provide protection to animal and plant species and that may apply to our operations include, without limitation, the Fish and Wildlife Coordination Act , the Fishery Conservation and Management Act , the Migratory Bird Treaty Act , and the Bald and Golden Eagle Protection Act .


The National Environmental Policy Act (the " NEPA ") requires a thorough review of the environmental impacts of "major federal actions" and a determination of whether proposed actions on federal and certain Indian lands would result in "significant impact" on the environment. For purposes of NEPA, "major federal action" can be something as basic as issuance of a required permit. For oil and gas operations on federal and certain Indian lands or requiring federal permits, NEPA review can increase the time for obtaining approval and impose additional regulatory burdens on the natural gas and oil industry, thereby increasing our costs of doing business and our profitability.


The Clean Water Act (the " CWA ") and comparable state statutes, impose restrictions and controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the Environmental Protection Agency (the " EPA ") or an analogous state agency. The CWA regulates storm water run-off from oil and natural gas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.


The Safe Drinking Water Act (the " SDWA ") and the Underground Injection Control (" UIC ") program promulgated thereunder, regulate the drilling and operation of subsurface injection wells. The EPA directly administers the UIC program in some states and in others the responsibility for the program has been delegated to the state. The program requires that a permit be obtained before drilling a disposal well. Violation of these regulations and/or contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.


Some of our operations employ hydraulic fracturing techniques to stimulate oil and natural gas production from unconventional geological formations, which entails the injection of pressurized fracturing fluids into a well bore. The federal Energy Policy Act of 2005 amended the SDWA to exclude hydraulic fracturing from the definition of "underground injection" under certain circumstances. However, the repeal of this exclusion has been advocated by certain advocacy organizations and others in the public. Legislation to amend the SDWA to repeal this exemption and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been introduced in Congress. In addition, the EPA at the request of Congress recently conducted a national study examining the potential impacts of hydraulic fracturing on drinking water resources. The final report, Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States , was issued in December 2016. The report raised some concerns regarding potential vulnerabilities in the process that could impact drinking water. However, the EPA noted that data gaps and uncertainties limited the agency's ability to draw conclusions about the impact of hydraulic fracturing activities on drinking water sources.








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On May 16, 2013, the U.S. Bureau of Land Management (" BLM ") published revised proposed rules to regulate hydraulic fracturing on federal public lands and Indian lands. The proposed rules would address well stimulation operations, including requiring agency approval for certain activities, and would require certain disclosures of well stimulation fluids and other information, as well as address issues relating to flowback water. In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, or that would impose higher taxes, fees or royalties on natural gas production. In July of 2013, the BLM extended the public comment period on the proposed rules to August of 2013. On May 20, 2015 the BLM published its finalized rules on hydraulic fracturing. Following passing of the finalized rules, several states and industry groups filed suit to prevent enforcement of the rules and on September 30, 2015, a United States federal court granted a motion for a preliminary injunction preventing enforcement of the BLM’s new rules. On June 21, 2016, the federal court set aside the BLM's new hydraulic fracturing rule. The federal government has filed an appeal of the court's decision, and arguments in the case are scheduled for March 2017. Many states currently independently regulate hydraulic fracturing operations in the state, including Utah, North Dakota and Montana. If the new federal rules or new state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business. It is also possible that our drilling and injection operations could adversely affect the environment, which could result in a requirement to perform investigations or clean-ups or in the incurrence of other unexpected material costs or liabilities.


The Clean Air Act , as amended, restricts the emission of air pollutants from many sources, including oil and gas operations. The Clean Air Act and regulations implemented thereunder regulate oil and natural gas production, processing, transmission and storage operations under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs. Clean Air Act regulations include New Source Performance Standards for completions of hydraulically fractured wells.




We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (the " OSHA ") and comparable state laws, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.


We are subject to federal and state laws and regulations relating to preservation and protection of historical and cultural resources. Such laws include the National Historic Preservation Act , the Native American Graves Protection and Repatriation Act , Archaeological Resources Protection Act , and the Paleontological Resources Preservation Act , and their state counterparts and similar statutes, which require certain assessments and mitigation activities if historical or cultural resources are impacted by our activities and provide for civil, criminal and administrative penalties and other sanctions for violation of their requirements.








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In Alberta, GHG emissions are regulated under the Specified Gas Reporting Regulation (" SGRR ") and the Specified Gas Emitters Regulation (" SGER ") pursuant to the Climate Change and Emissions Management Act . The SGRR requires facilities that emit 50,000 tonnes or more of GHGs per year annually to report their emissions to Alberta Environment and Parks (" AEP "). The SGER require Alberta facilities that emit more than 100,000 tonnes of GHGs per year to reduce emissions intensity by up to 20% below an average baseline taken from a facility's 2003 - 2005 emissions. Companies may meet these requirements through improvements to their operations; by purchasing Alberta-based emission reduction or offset credits; or by contributing to the provincial Climate Change and Emissions Management Fund. Crescent Point does not operate any facilities that are regulated by the Alberta GHG emissions regulations.




The Climate Change Leadership Panel recommended a new Carbon Competitiveness Regulation to amend or replace the SGER that will require distributors of transportation and heating fuels to annually do one or more of the following in recognition that GHG emissions are created when their fuel products are combusted by their customers: (i) acquire and then retire GHC emission performance credits or offset credits, or (ii) make payments to a technology fund at a rate of $20 per tonne of GHG emissions starting on January 1, 2017 and rising to $30 per tonne for transportation and heating fuels sold and distributed in the province. The distributors are expected to pass on the costs of complying with the proposed Carbon Competitiveness Regulation to their customers. The Panel estimates these costs will require non-agricultural customers to pay an additional 7  cents per litre for regular gasoline and $1.68 GJ for natural gas by 2018.
















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On May 11, 2009, the Government of Saskatchewan announced The Management and Reduction of Greenhouse Gases Act (the " MRGHGA ") to regulate greenhouse gas emissions in the province. The MRGHGA has not yet come into force.


In British Columbia, GHG emissions are regulated under the Greenhouse Gas Emission Reporting Regulation enacted pursuant to the Greenhouse Gas Industrial Reporting and Control Act which imposes GHG emissions reporting requirements upon B.C. facilities emitting 10,000 tonnes or more of carbon dioxide equivalent emissions per year. To date, Crescent Point does not operate any facilities that are regulated by the British Columbia GHG emissions regulations.






In November 2015, Canada participated in the twenty first session of the Conference of the Parties of the United Nations Framework Convention on Climate Change (" COP 21 ") in Paris, France, the goal of which was to reach a new agreement for fighting global climate change. COP 21 resulted in the adoption of the Paris Agreement which made several recommendations, including: a) holding the increase in the global average temperature to well below 2 °C above pre-industrial levels and pursuing efforts to limit the temperature increase to 1.5 °C above pre-industrial levels, recognizing that this would significantly reduce the risks and impacts of climate change; b) increasing the ability to adapt to the adverse impacts of climate change and foster climate resilience and low greenhouse gas emissions development, in a manner that does not threaten food production; and c) making finance flows consistent with a pathway towards low greenhouse gas emissions and climate-resilient development. The Paris Agreement came into force on November 4, 2016.












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|  |                                                     
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|• | Complying with government regulations and standards;

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|• | Conducting operations consistent with industry codes, practices and guidelines;

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|• | Ensuring prompt, effective response and repair to emergency situations and environmental incidents;

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|• | Providing training to employees and contractors to ensure compliance with Corporation safety and environmental rules and procedures;

|  |                                                                                                                                                 
|- | ------------------------------------------------------------------------------------------------------------------------------------------------
|• | Promoting the aspects of careful planning, good judgment, implementation of the Corporation's procedures, and monitoring Corporation activities;







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|• | Communicating openly with members of the public regarding our activities; and

|  |                                                                                         
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|• | Amending the Corporation's policies and procedures as may be required from time to time.
















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|• | historical production in the area compared with production rates from similar producing areas;

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|• | future commodity prices, production and development costs, royalties and capital expenditures;

|  |                          
|- | -------------------------
|• | initial production rates;

|  |                          
|- | -------------------------
|• | production decline rates;

|  |                               
|- | ------------------------------
|• | ultimate recovery of reserves;

|  |                                          
|- | -----------------------------------------
|• | success of future development activities;

|  |                             
|- | ----------------------------
|• | marketability of production;

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|• | availability, proximity and capacity of oil and gas gathering systems, pipelines and processing facilities;

|  |                                      
|- | -------------------------------------
|• | effects of government regulation; and

|  |                                                                                 
|- | --------------------------------------------------------------------------------
|• | other government levies that may be imposed over the producing life of reserves.

Reserve estimates are based on the relevant factors, assumptions and prices on the date the relevant evaluations were prepared. These estimates are expected to be revised upward or downward over time, as additional information such as reservoir performance becomes available, or as economic conditions change. See " Special Notes to Reader ". Many of these factors are subject to change and are beyond our control. If these factors, assumptions and prices prove to be inaccurate, actual results may vary materially from reserve estimates and such variations may affect the market price of our Common Shares and payments of dividends to Shareholders.








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- 65 -





























---

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|  |                                 
|- | --------------------------------
|• | restrictions imposed by lenders;

|  |                                            
|- | -------------------------------------------
|• | delays in the sale or delivery of products;

|  |                                                         
|- | --------------------------------------------------------
|• | delays in the connection of wells to a gathering system;

|  |                                               
|- | ----------------------------------------------
|• | restrictions due to limited pipeline capacity;

|  |                             
|- | ----------------------------
|• | blowouts or other accidents;

|  |                   
|- | ------------------
|• | accounting delays;

|  |                               
|- | ------------------------------
|• | adjustments for prior periods;

|  |                                                                                     
|- | ------------------------------------------------------------------------------------
|• | recovery by the operator of expenses incurred in the operation of the properties; or

|  |                                                                  
|- | -----------------------------------------------------------------
|• | the establishment by the operator of reserves for these expenses.









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---

- 68 -

































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Additionally, Crescent Point is subject to the Ute Tribal Employment Rights Ordinance (the " Employment Act "). The Employment Act requires that Crescent Point give preference in hiring to members of the Tribe meeting job description requirements. The Employment Act also requires Crescent Point to give preference to businesses owned by members of the Tribe when hiring contractors, provided they are market competitive (as defined in the Employment Act). These regulatory restrictions may negatively affect Crescent Point's ability to hire non-tribal employees and contractors.










Crescent Point relies heavily on information technology, such as computer hardware and software systems, in order to properly operate its business. In the event the Corporation is unable to regularly deploy software and hardware, effectively upgrade systems and network infrastructure, and take other steps to maintain or improve the efficiency and efficacy of systems, the operation of such systems could be interrupted or result in the loss, corruption, or release of data. In addition, information systems could be damaged or interrupted by natural disasters, force majeure events, telecommunications failures, power loss, acts of war or terrorism, computer viruses, malicious code, physical or electronic security breaches, intentional or inadvertent user misuse or error, or similar events or disruptions. Any of these or other events could cause interruptions, delays, loss of critical or sensitive data or similar effects, which could have a material adverse impact on the protection of intellectual property, and confidential and proprietary information, and on Crescent Point’s business, financial condition, results of operations and cash flows.








---

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|  |                                                                                                               
|- | --------------------------------------------------------------------------------------------------------------
|• | the levels and location of oil and natural gas supply and demand and expectations regarding supply and demand;

|  |                                      
|- | -------------------------------------
|• | the level of consumer product demand;

|  |                    
|- | -------------------
|• | weather conditions;

|  |                                                                                                                                   
|- | ----------------------------------------------------------------------------------------------------------------------------------
|• | political conditions or hostilities in oil and natural gas producing regions, including the Middle East, Africa and South America;







---

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|  |                                                                                                                                                                        
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | the ability of the members of the Organization of Petroleum Exporting Countries and other exporting nations to agree to and maintain oil price and production controls;

|  |                                    
|- | -----------------------------------
|• | the price level of foreign imports;

|  |                                     
|- | ------------------------------------
|• | actions of governmental authorities;

|  |                                                                                                                                                                                                        
|- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or localized areas that may affect the realized price for oil and natural gas;

|  |                          
|- | -------------------------
|• | inventory storage levels;

|  |                                                                                                                                            
|- | -------------------------------------------------------------------------------------------------------------------------------------------
|• | the nature and extent of domestic and foreign governmental regulations and taxation, including environmental and climate change regulation;

|  |                                                             
|- | ------------------------------------------------------------
|• | the price, availability and acceptance of alternative fuels;

|  |                                                     
|- | ----------------------------------------------------
|• | technological advances affecting energy consumption;

|  |                                                 
|- | ------------------------------------------------
|• | speculation by investors in oil and natural gas;

|  |                                                                                   
|- | ----------------------------------------------------------------------------------
|• | variations between product prices at sales points and applicable index prices; and

|  |                                                                                                        
|- | -------------------------------------------------------------------------------------------------------
|• | overall economic conditions, including the value of the U.S. dollar relative to other major currencies.























---

- 72 -

















For further discussion about the effect of environmental laws, see below " Our operations may incur substantial costs and liabilities to comply with environmental laws and regulations ".












---

- 73 -









Compliance with environmental laws and regulations could materially increase our costs. We may incur substantial capital and operating costs to comply with increasingly complex laws covering the protection of the environment and human health and safety. In particular, we may be required to incur significant costs to comply with future federal GHG emissions reduction requirements or other GHG emissions regulations. See below " Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for oil and gas that we produce ."






Crescent Point's oil and natural gas exploration and production operations in Utah occur on the Utah and Ouray Reservation (the " Reservation ") lands and federal, state or private lands located outside those Reservation lands. Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, the BLM and the Office of Natural Resources Revenue, may promulgate and enforce laws, regulations and/or other approval requirements addressing environmental conditions and pertaining to oil and natural gas operations on Reservation lands.








---

- 74 -





















---

- 75 -





In the United States, on December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. Based on these findings, the EPA has begun adopting and implementing regulations that restrict emissions of GHG under existing provisions of the Federal Clean Air Act (the " CAA "), including one rule that limits emissions of GHG from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger the CAA construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (" PSD ") and Title V permitting programs. This rule "tailors" these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. However, based on a decision of the U.S. Supreme Court, only facilities already required to obtain PSD permits for other criteria pollutants must also reduce GHG emissions that exceed certain thresholds consistent with guidance for determining "best available control technology" standards for GHG, which guidance was published by the EPA in November 2010. Also in November 2010, the EPA expanded its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis with reporting beginning in 2012 for emissions occurring in 2011. In addition, both houses of Congress have actively considered legislation to reduce emissions of GHG, and many states have already taken legal measures to reduce emissions of GHG, primarily through the development of GHG inventories, greenhouse gas permitting and/or regional GHG "cap and trade" programs. Most of these "cap and trade" programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. In the absence of new legislation, the EPA is issuing new regulations that limit emissions of GHG associated with our operations which will require us to incur costs to inventory and reduce emissions of GHG associated with our operations and which could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our assets and operations.
















---

- 76 -





In Canada, amendments have been made to the Transportation of Dangerous Goods Regulation which adopt a new class of tank car for flammable liquid dangerous goods service and which require all new rail tank cars destined for flammable liquid service to be built to the new specifications. Certain older tank cars used to transport crude oil have been phased out. Further, shippers of crude oil by rail now must have in place an Emergency Response Assistance Plan approved by the Minister of Transportation in order to be able to provide assistance to responders in the event of an accident. Other amendments require the consigner of a shipment of crude oil by rail to properly classify the crude oil and to certify that the classification is correct. Additionally, Transport Canada has introduced requirements for railway companies to reduce the speed of trains carrying dangerous goods such as crude oil and to implement various other safe operating practices.






















---

- 77 -

































---

- 78 -

























The Tax Act imposes a withholding tax at the rate of 25% on dividends paid by us to Shareholders who are non-residents of Canada, unless the rate is reduced under the provisions of a tax treaty between Canada and the non-resident Shareholder's jurisdiction of residence. These withholding tax rates may change from time to time. Where the non-resident Shareholder is a United States resident entitled to benefits under the Canada-United States Income Tax Convention, 1980 (the " Treaty ") and is the beneficial owner of the dividend, the rate of Canadian withholding tax applicable to dividends is generally reduced to 15%. Shareholders who are non-residents of Canada are encouraged to consult with their tax advisors for more information concerning additional taxation that may be applicable to them.








---

- 79 -


























Dividend per Common ShareJanuary 2014
–
December 2014
$0.23January 2015
–
August 2015
$0.23September 2015
–
December 2015
$0.10January 2016
–
March 2016
$0.10April 2016
–
December 2016
$0.03













---




- 80 -









TSX
High ($)
Low ($)
Volume (000's)2016January
16.53
11.42
85,107February
16.71
13.05
57,960March
19.44
16.41
76,623April
22.56
16.98
65,877May
22.85
19.11
53,879June
24.01
18.99
54,132July
21.12
18.75
31,741August
22.00
18.50
32,758September
20.34
16.06
80,433October
18.41
15.97
42,552November
17.21
14.39
63,432December
19.38
17.05
64,8962017January
18.92
14.98
43,165February 1 - 15
15.27
13.79
35,018





NYSE
High (US$)
Low (US$)
Volume (000's)2016January
11.89
7.82
23,773February
12.36
9.35
24,243March
14.98
12.17
30,944April
17.92
12.87
23,641May
17.65
14.84
22,216June
18.95
14.49
19,929July
16.04
14.21
11,717August
17.22
13.96
13,142September
15.75
12.11
21,949October
13.94
11.91
14,366November
12.81
10.64
26,331December
14.73
12.84
23,3672017January
14.08
11.50
17,622February 1 - 15
11.68
10.48
12,806








---




- 81 -



























The Corporation has established an Audit Committee (the " Audit Committee ") comprised of four members: Gerald A. Romanzin (Chair), Peter N. Bannister, Laura A. Cillis and D. Hugh Gillard, each of whom is considered "independent" and "financially literate" within the meaning of Multilateral Instrument 52-110 – Audit Committees.














---

- 82 -













Name of Audit 
 Committee Member
Relevant Education and ExperienceGerald A. Romanzin
Gerald Romanzin is an independent Calgary businessman who serves as a director of Petrowest Corporation and Athabasca Minerals Inc. Previously, he held a variety of senior roles with the TSX Venture Exchange, including Executive Vice President and Acting President, and was the Executive Vice President of the Alberta Stock Exchange, prior to its conversion. He has been on the Board and on the board of Crescent Point's predecessor since 2004.Formerly, Mr. Romanzin served as a director of Trimac Transportation Ltd., FET Resources Ltd., Ketch Resources Ltd., Ketch Resources Trust, Cadence Energy Inc., Kereco Energy Ltd., Flowing Energy Corporation and Porto Energy Corp. Mr. Romanzin is a Chartered Professional Accountant and a member of the Chartered Professional Accountants of Alberta and holds a Bachelor of Commerce degree from the University of Calgary.Peter N. Bannister
Peter Bannister is Chair of Crescent Point's Board andispresident of Destiny Energy Inc., a private oil and gas company. He has been on the Board and on the board of Crescent Point's predecessor since 2003. Mr.Bannister hasworkedin theoiland gas industry since 1982, having held a variety of senior executive roleswithcompanies such as Mission Oil and Gas Inc.,StarPoint Energy Inc.,Impact Energy Inc.,Startech Energy Ltd.,Boomerang Resources Ltd.,Laurasia Resources Ltd.and Sproule Associates Ltd. Mr. Bannister is a member of APEGA and serves on the boardofdirectorsofCequence Energy Ltd.Formerly,he was a director of New Star Energy Ltd.,Surge Energy Inc.,Shelter Bay Energy Inc.,Mission Oil and Gas Inc.,Breaker Energy Ltd., Impact Energy Inc., Boomerang Resources Ltd. and Laurasia Resources Ltd.Mr. Bannister holds a Bachelor of Sciencedegreein geologywitha minor in economics.Laura A. Cillis
Laura A. Cillis is an oil and gas executive with more than 25 years of financial experience in the oilfield services industry. Most recently she held the role of Senior Vice President, Finance and Chief Financial Officer of Calfrac Well Services Ltd. from 2008 until 2013 and Chief Financial Officer of Canadian Energy Services L.P. from 2006 to 2008. Prior thereto, she held various positions at Precision Drilling Corporation and Schlumberger Canada. Ms. Cillis joined the Board in November 2014.She is a Chartered Professional Accountant who holds the ICD.D designation granted by the Institute of Corporate Directors and a Bachelor of Commerce degree in accounting from the University of Alberta. Ms. Cillis is also a director of Solium Capital Inc., Enbridge Income Fund Holdings Inc., Enbridge Pipelines Inc. and a trustee of Enbridge Commercial Trust.D. Hugh Gillard
D. Hugh Gillard is the principal of Saddleback Resources Ltd., a private company involved in equity investments and advisory roles in the energy sector. He has worked in the oil and gas industry since 1972, having led companies such as Kelso Energy Inc., PrimeWest Energy Trust and CanWest Gas Marketing Inc. He has also held a number of senior roles with companies such as Ashland Oil Canada, Dome Petroleum Ltd. and Amoco Canada Resources Ltd. Mr. Gillard has been on the Board and on the board of Crescent Point's predecessor since 2003.Mr. Gillard has served as director of the board of Petrowest Energy Services Trust (chair), of Creststreet Power Income Fund and of Point North Energy Ltd. He is a past member of the Management Advisory Council for the University of Calgary, past chair of the board of Hospice Calgary and is past chair of the Calgary Zoological Society. He holds a Bachelor of Commerce degree from the University of Calgary and is a graduate of the Stanford Business School Executive Program.











---

- 83 -









Year ended December 312016
2015PricewaterhouseCoopersAudit fees(1)
$
1,102,751

$
1,098,698Audit-related fees(2)
$
139,104

$
164,550Tax fees(3)
$
31,133

$
51,975All other fees
-

$
85,050Total
$
1,272,988

$
1,400,273




|    |                                                                                                                                                                                                                                  
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Audit fees consist of the aggregate fees billed for the audit or review of the Company’s annual and quarterly financial statements that are normally provided in connection with statutory and regulatory filings or engagements.

|    |                                                                                                                                                                                                                                                                                                                                                                                                                    
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Audit-related fees consist of the aggregate fees billed for assurance and related services that are reasonably related to the performance of the audit or review of the Company’s financial statements and are not reported as Audit fees. The services in this category include costs related to a public financing, French translation and participation fees levied by the Canadian Public Accountability Board.

|    |                                                                  
|--- | -----------------------------------------------------------------
|(3) | Tax fees consist of the aggregate fees billed for tax compliance.










































Premium Dividend and Dividend Reinvestment Plan. See " Additional Information Respecting Crescent Point – Premium Dividend and Dividend Reinvestment Plan ".

















---




- 84 -
































---





















|   |                                                        
|-- | -------------------------------------------------------
|I. | The Board of Directors' Mandate for the Audit Committee

|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|-- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|1. | The Board of Directors("Board") has responsibility for the stewardship of Crescent Point Corp. ("Crescent Point") and its subsidiaries or related entities (collectively referred to herein as the "Corporation"). To discharge that responsibility, the Board is obligated by theBusiness Corporations Act(Alberta) to supervise the management of the business and affairs of the Corporation. The Board's supervisory function involves Board oversight or monitoring of all significant aspects of the management of the Corporation's business and affairs.



|    |                                                                                                                                                                                                                   
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | that the Corporation complies with all applicable laws, regulations, rules, policies and other requirement of governments, regulatory agencies and stock exchanges relating to financial reporting and disclosure;

|    |                                                                                                                                                                                                                           
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(b) | that the accounting principles, significant judgements and disclosures which underlie or are incorporated in the Corporation's consolidated financial statements are the most appropriate in the prevailing circumstances;

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                      
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(c) | that the Corporation's quarterly and annual consolidated financial statements and Annual Information Forms ("AIF") are accurate within a reasonable level of materiality and present fairly the Corporation's financial position and performance in accordance with the recognition and measurement principles of International Financial Reporting Standards as issued by the International Accounting Standards Board ("IFRS"); and

|    |                                                                                                                                                                                                                                        
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(d) | that appropriate information concerning the financial position and performance of the Corporation is disseminated to the public in a timely manner in accordance with corporate and securities law and with stock exchange regulations.



|    |                                                                                                                                                                                                                                               
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(i) | the Corporation's accounting functions are performed in accordance with a system of internal financial controls designed to capture and record properly and accurately all of the Corporation's financial transactions and properly certified;

|     |                                                                                         
|---- | ----------------------------------------------------------------------------------------
|(ii) | the internal financial controls are regularly assessed for effectiveness and efficiency;






---

- 2 -





|      |                                                                                                                                      
|----- | -------------------------------------------------------------------------------------------------------------------------------------
|(iii) | the Corporation's quarterly and annual consolidated financial statements are properly prepared by management to comply with IFRS; and

|     |                                                                                                                                                                                                                     
|---- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(iv) | the Corporation's quarterly and annual consolidated financial statements and Management Discussion and Analysis ("MD&A") are reported on by an external auditor appointed by the securityholders of the Corporation.



|   |                      
|-- | ---------------------
|2. | Role of the Committee



|   |                         
|-- | ------------------------
|3. | Composition of Committee

|    |                                                                                                                                                
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------
|(a) | Size. The Committee shall be appointed annually by the Board and consist of at least three members from among the directors of the Corporation.

|    |                                                                                                                                                                                                                                                                                     
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(b) | Qualifications – All members of the committee (the "Members") must be "independent" under Multilateral Instrument 52-110. All Members must be "financially literate" (i.e., have the ability to read and understand a balance sheet, an income statement and a cash flow statement).

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(c) | Committee members may not, other than in their respective capacities as members of the Committee, the Board or any other committee of the Board, accept directly or indirectly any consulting, advisory or other compensatory fee from the Corporation or any subsidiary of the Corporation, or be an “affiliated person” (as such term is defined in the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the rules, if any, adopted by the U.S. Securities and Exchange Commission (“SEC”) thereunder) of the Corporation or any subsidiary of the Corporation. For greater certainty, directors’ fees and fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the Corporation that are not contingent on continued service should be the only compensation a Committee member receives from the Corporation.

|    |                                                      
|--- | -----------------------------------------------------
|(d) | The Board shall designate the Chair of the Committee.

|    |                                                                                                                                                                                                             
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(e) | In the event of a vacancy arising in the Committee or a loss of independence of any Member, the Committee will fill the vacancy within six weeks or by the following annual shareholders' meeting if sooner.

|   |                    
|-- | -------------------
|4. | Reliance on Experts



|    |                                                                                                                                                                                                                                                  
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | consolidated financial statements of the Corporation represented to him by an officer of the Corporation or in a written report of the external auditors to present fairly the financial position of the Corporation in accordance with IFRS; and






---

- 3 -





|    |                                                                                                                                                   
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------
|(b) | any report of a lawyer, accountant, engineer, appraiser or other person whose profession lends credibility to a statement made by any such person.

|   |                                      
|-- | -------------------------------------
|5. | Limitations on The Committee's Duties



|    |                                   
|--- | ----------------------------------
|II. | Audit Committee Terms of Reference



|   |                     
|-- | --------------------
|1. | Operating Principles


























---

- 4 -

































|   |                     
|-- | --------------------
|2. | Operating Procedures














---

- 5 -





































|   |                                     
|-- | ------------------------------------
|3. | Specific Responsibilities and Duties





|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | Review, prior to public release, the Corporation's annual and quarterly consolidated financial statements with management and the external auditors to gain reasonable assurance that the statements are accurate within reasonable levels of materiality, complete, represent fairly the Corporation's financial position and performance and are in accordance with IFRS and report thereon to the Board before such consolidated financial statements are approved by the Board;






---

- 6 -





|    |                                                                                                                          
|--- | -------------------------------------------------------------------------------------------------------------------------
|(b) | Receive from the external auditors reports on their review of the annual and quarterly consolidated financial statements;

|    |                                                                                                                                                                                    
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(c) | Receive from management a copy of the representation letter provided to the external auditors and receive from management any additional representations required by the Committee;

|    |                                                                                                                                                                           
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(d) | Review, prior to public release, all news releases issued by the Corporation with respect to the Corporation's annual and quarterly consolidated financial statements; and

|    |                                                                                                                                                                                  
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(e) | Review prospectuses, material change disclosures of a financial nature, management discussion and analysis, AIF and similar disclosure documents to be issued by the Corporation.



|    |                                                                                                                                                                                                            
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | Review with management and the external auditors the appropriateness of the Corporation's accounting policies, disclosures, reserves, key estimates and judgments, including changes or variations thereto;

|    |                                                                                                                                                                                                                
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(b) | Obtain reasonable assurance that the accounting policies, disclosures, reserves, key estimates and judgments are in compliance with IFRS from management and external auditors and report thereon to the Board;

|    |                                                                                                                                                                                                                         
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(c) | Review with management and the external auditors the degree of conservatism of the Corporation's underlying accounting policies, key estimates and judgments and reserves along with quality of financial reporting; and

|    |                                                                                                            
|--- | -----------------------------------------------------------------------------------------------------------
|(d) | Participate, if requested, in the resolution of disagreements between management and the external auditors.



|    |                                                                                                                                                                                                                                                                                                                                                                                              
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | Acknowledging that it is the responsibility of the Board, in consultation with management, to identify the principal business risks facing the Corporation, determine the Corporation's tolerance for risk and approve risk management policies, the Committee shall focus on financial risk and gain reasonable assurance that financial risk is being effectively managed or controlled by:

|    |                                                                           
|--- | --------------------------------------------------------------------------
|(i) | reviewing with management the Corporation's tolerance for financial risks;

|     |                                                                                                    
|---- | ---------------------------------------------------------------------------------------------------
|(ii) | reviewing with management its assessment of the significant financial risks facing the Corporation;

|      |                                                                                                                                          
|----- | -----------------------------------------------------------------------------------------------------------------------------------------
|(iii) | reviewing with management the Corporation's policies and any proposed changes thereto for managing those significant financial risks; and

|     |                                                                                              
|---- | ---------------------------------------------------------------------------------------------
|(iv) | reviewing with management its plans, processes and programs to manage and control such risks.

|    |                                                                                                                                                                             
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(b) | Review policies and compliance therewith that require significant actual or potential liabilities, contingent or otherwise, to be reported to the Board in a timely fashion;

|    |                                                                                                                                              
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------
|(c) | Review foreign currency, interest rate and commodity price risk mitigation strategies, including the use of derivative financial instruments;

|    |                                                                              
|--- | -----------------------------------------------------------------------------
|(d) | Review the adequacy of insurance coverages maintained by the Corporation; and






---

- 7 -





|    |                                                                                                                                                                                                                                                                                                                                                                        
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(e) | Review regularly with management, the external auditors and the Corporation's legal counsel, any legal claim or other contingency, including tax assessments, that could have a material effect upon the financial position or operating results of the Corporation and the manner in which these matters have been disclosed in the consolidated financial statements.



|    |                                                                                                                                                                                        
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | Review the plans of the external auditors to gain reasonable assurance that the evaluation and testing of internal financial controls is comprehensive, coordinated and cost effective;

|    |                                                                                                                                                                                                                                                                
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(b) | Receive regular reports from management and the external auditors on all significant deviations from IFRS or other Corporation internal control processes or indications which may suggest fraud and the corrective activity undertaken in respect thereto; and

|    |                                                                                                                                                                                                                                                                                                                                                     
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(c) | Institute a procedure that will permit any employee, including management employees, to bring to the attention of the Board or the Committee concerns relating to financial controls and reporting which are material in scope and which cannot be addressed, in the employee's judgement, through existing reporting structures in the Corporation.



|    |                                                                                                                                                                                                                                           
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | Receive and review regular reports from management and others (e.g. external auditors) with respect to the Corporation's compliance with laws and regulations having a material impact on the consolidated financial statements including:

|    |                                                  
|--- | -------------------------------------------------
|(i) | tax and financial reporting laws and regulations;

|     |                                    
|---- | -----------------------------------
|(ii) | legal withholding requirements; and

|      |                                                                    
|----- | -------------------------------------------------------------------
|(iii) | other laws and regulations which expose directors to liability; and

|    |                                                                                                             
|--- | ------------------------------------------------------------------------------------------------------------
|(b) | Review the filing status of the Corporation's tax returns and those of its subsidiaries or related entities.



|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | Be directly responsible, in the Committee’s capacity as a committee of the Board and subject to the rights of shareholders and applicable law, for the appointment, compensation, retention and oversight of the work of the external auditors (including resolution of disagreements between management and the external auditors regarding financial reporting) for the purpose of preparing or issuing an audit report, or performing other audit, review or attest services for the Corporation. The external auditors shall report directly to the Committee;

|    |                                                                
|--- | ---------------------------------------------------------------
|(b) | Recommend to the Board the nomination of the external auditors;

|    |                                                                                                                                                                                                                                                        
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(c) | Pre approve the remuneration and the terms of engagement of the external auditors as set forth in the Engagement Letter. The Chair of the Committee hereby has the authority to pre approve non audit services which may be required from time to time;

|    |                                                                                         
|--- | ----------------------------------------------------------------------------------------
|(d) | Review the performance of the external auditors annually or more frequently as required;

|    |                                                                                                                                                                             
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(e) | Receive annually from the external auditors an acknowledgement in writing that the securityholders, as represented by the Board and the Committee, are their primary client;






---

- 8 -





|    |                                                                                                                                                                                                                      
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(f) | Receive a report annually from the external auditors with respect to their independence, such report to include a disclosure of all engagements (and fees related thereto) for non audit services by the Corporation;

|    |                                                                                                                                                                                                
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(g) | Review with the external auditors the scope of the audit, the areas of special emphasis to be addressed in the audit, and the materiality levels which the external auditors propose to employ;

|    |                                                                                                                                                                                                                                                                                             
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(h) | Meet with the external auditors at least once a year in the absence of management to determine, inter alia, that no management restrictions have been placed on the scope and extent of the audit examinations by the external auditors or the reporting of their findings to the Committee;

|    |                                                                                                                                                                                                                                                                    
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(i) | Establish effective communication processes with management and the Corporation's external auditors to assist the Committee to monitor objectively the quality and effectiveness of the relationship among the external auditors, management and the Committee; and

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(j) | Establish a reporting relationship between the external auditors and the Committee such that the external auditors can bring directly to the Committee matters that, in the judgement of the external auditors, merit the Committee's attention. In particular, the external auditors will advise the Committee of any disagreements between management and the external auditors regarding financial reporting and how such disagreements were resolved.



|    |                                                      
|--- | -----------------------------------------------------
|(a) | Review the internal audit staff functions, including:

|    |                                                           
|--- | ----------------------------------------------------------
|(i) | the purpose, authority and organizational reporting lines;

|     |                                                
|---- | -----------------------------------------------
|(ii) | the annual audit plan, budget and staffing; and

|      |                                                                                                   
|----- | --------------------------------------------------------------------------------------------------
|(iii) | the appointment and compensation of any person with the responsibility for the Internal Audit; and

|    |                                                                                                                                                                        
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(b) | Review, with the Chief Financial Officer, controller or others, as appropriate, the Corporation's internal system of audit controls and the results of internal audits.



|    |                                                                                                                                                                                                                                         
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | After consultation with the Chief Financial Officer and the external auditors, gain reasonable assurance, at least annually, of the quality and sufficiency of the Corporation's accounting and financial personnel and other resources;

|    |                                                                                                 
|--- | ------------------------------------------------------------------------------------------------
|(b) | Investigate any matters that, in the Committee's discretion, fall within the Committee's duties;

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(c) | Determine the appropriate funding for payment by the Corporation (i) of compensation to the external auditors for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the Corporation, (ii) of compensation to any advisors employed by the Committee, and (iii) of ordinary administrative expenses of the Committee that are necessary or appropriate in carrying out its duties; and

|    |                                                                                                 
|--- | ------------------------------------------------------------------------------------------------
|(d) | Perform such other functions as may from time to time be assigned to the Committee by the Board.






---

- 9 -





|     |                                                    
|---- | ---------------------------------------------------
|III. | Hiring Guidelines for Independent Auditor Employees

|   |           
|-- | ----------
|1. | Guidelines



|    |                                                                                                                                                                                                                   
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | No senior member of the audit team that is auditing a business of the Corporation can be hired into that business or into a position to which that business reports for a period of two years after the audit; and

|    |                                                                                                                                                                                          
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(b) | No former partner or employee of the external auditor may be made an officer of the Corporation or any of its subsidiaries for two years following association with the external auditor:

|    |                                                                                         
|--- | ----------------------------------------------------------------------------------------
|(i) | The Chief Executive Officer must approve all office hires from the external auditor; and

|     |                                                                                                                                  
|---- | ---------------------------------------------------------------------------------------------------------------------------------
|(ii) | The Chief Financial Officer must report annually to the Committee on any hires within these guidelines during the preceding year.

|   |                       
|-- | ----------------------
|2. | Audit Partner Rotation



|   |                                                         
|-- | --------------------------------------------------------
|3. | Process for Handling Complaints about Accounting Matters



|    |                                                                                                                                                                                                                
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | The Corporation will publish on its website special mail and e-mail addresses and a toll-free telephone number for receiving complaints regarding accounting, internal accounting controls or auditing matters;

|    |                                                                            
|--- | ---------------------------------------------------------------------------
|(b) | Copies of complaints received will be sent to the Members of the Committee;

|    |                                                                                                                                                                                                                                                     
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(c) | All complaints will be investigated by the Corporation's finance and legal staffs in the normal manner, except as otherwise directed by the Committee. The Committee may request that outside advisors be retained to investigate any complaint; and

|    |                                                                                                                                         
|--- | ----------------------------------------------------------------------------------------------------------------------------------------
|(d) | The status of each complaint will be reported on a quarterly basis to the Committee and, if the Committee so directs, to the full board.









---





















|   |                           
|-- | --------------------------
|1. | Reserves Committee Purpose



|   |                                                            
|-- | -----------------------------------------------------------
|2. | Reserves Committee Composition, Procedures and Organization



|   |                                               
|-- | ----------------------------------------------
|3. | Reserves Committee Responsibilities and Duties



|    |                                                                                                                                                                                                                                                                                                                                                                                                            
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | in conjunction with the Corporation's senior engineering management, meet with the independent evaluating engineers being considered for appointment to review their qualifications and independence to ensure the independent evaluating engineers being considered for appointment are technically qualified and competent, are independent of management and to establish the terms of their engagement;

|    |                                                                                                                                                                                                                                                  
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(b) | after consultation with the Corporation's senior engineering management, recommend to the Board the appointment of the independent evaluating engineers to assist the Corporation in the annual review of its petroleum and natural gas reserves;

|    |                                                                                                                                                                                                                                                     
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(c) | in consultation with the Corporation's senior engineering management determine the scope of the annual review of the petroleum and natural gas reserves by the independent evaluating engineers, having regard to regulatory reporting requirements;






---

- 2 -





|    |                                                                                                                                                                                                                                                                                                                                                                                                                                  
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(d) | review, with reasonable frequency, the Corporation's procedures for providing petroleum and natural gas reserves information to the qualified independent evaluating engineers who report on reserves data for the purposes of NI 51 - 101, and the information used by the independent evaluating engineers to enable the independent evaluating engineers to provide a report that will meet regulatory reporting requirements;

|    |                                                                                                               
|--- | --------------------------------------------------------------------------------------------------------------
|(e) | in consultation with the Corporation's senior engineering management and the independent evaluating engineers:

|  |                                                                                                                                                  
|- | -------------------------------------------------------------------------------------------------------------------------------------------------
|• | determine whether any restrictions affect the ability of the independent evaluating engineers to report on reserve data without reservations; and

|  |                                                                                 
|- | --------------------------------------------------------------------------------
|• | review the reserves data and the report of the independent evaluating engineers.

|    |                                                                                                                                           
|--- | ------------------------------------------------------------------------------------------------------------------------------------------
|(f) | ensure the disclosure to the public on the Corporation's petroleum and natural gas reserves is in compliance with regulatory requirements:

|  |                                                                                                                                                               
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | review any proposal to change the independent evaluating engineers and/or resolve any differences between the independent evaluating engineers and management;

|  |                                                                                                                                                                                                                                           
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | meet on an annual basis with the Corporation's senior engineering management and/or the independent evaluating engineers of the Corporation to review and consider the evaluation of the Corporation's petroleum and natural gas reserves;

|  |                                                                                                                                                                                          
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | meet separately with the independent evaluating engineers and/or senior engineering management when the Committee deems it desirable and advise the Board on the results of such meeting;

|  |                                                                                                                                                                                                                                                                                                   
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | coordinate meetings with the Audit Committee of the Corporation, the Corporation's senior engineering management, independent evaluating engineers and auditors as required to address matters of mutual concern in respect of the Corporation's evaluation of petroleum and natural gas reserves;

|  |                                                                                  
|- | ---------------------------------------------------------------------------------
|• | review annually the Committee charter and recommend any changes to the Board; and

|  |                                                                                                                         
|- | ------------------------------------------------------------------------------------------------------------------------
|• | to maintain minutes of meetings and periodically report to the Board on significant results of the foregoing activities.









---

















|   |                                                                                                                                                                                                                                                   
|-- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|1. | We have evaluated the Company's reserves 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.

|   |                                                                                                                                                                
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------
|2. | The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves 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 from 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 are in accordance with principles and definitions presented in the COGE Handbook.

|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|5. | The following table shows the net present value of 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 the Company evaluated for the year ended December 31, 2016, and identifies the respective portions thereof that we have evaluated and reported on to the Company's board of directors:

Net Present Value of Future Net Revenue 
 (before income taxes, 10% discount rate - $M)Independent Qualified Reserves Evaluator or Auditor
Effective Date of Evaluation Report
Location of Reserves (Country or Foreign Geographic Area)
Audited
Evaluated
Reviewed
TotalGLJ Petroleum Consultants
December 31, 2016
Canada
-
3,284,844
-
3,284,844





|   |                                                                                                                                                                                                                                                                 
|-- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|6. | In our opinion, the reserves data 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 that we reviewed but did not audit or evaluate.

|   |                                                                                                                                                          
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------
|7. | We have no responsibility to update our report referred to in paragraph 5 for events and circumstances occurring after the effective date of our reports.

|   |                                                                                                                                        
|-- | ---------------------------------------------------------------------------------------------------------------------------------------
|8. | Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.
















---

- 2 -










|   |                                                                                                                                                                                                                                                   
|-- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|1. | We have evaluated the Company's reserves 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.

|   |                                                                                                                                                                
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------
|2. | The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves 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 from 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 are in accordance with principles and definitions presented in the COGE Handbook.

|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|5. | The following table shows the net present value of 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 the Company evaluated for the year ended December 31, 2016, and identifies the respective portions thereof that we have evaluated and reported on to the Company's board of directors:

Net Present Value of Future Net Revenue 
 (before income taxes, 10% discount rate - Cdn. $M)Independent Qualified Reserves Evaluator or Auditor
Effective Date of Evaluation Report
Location of Reserves (Country or Foreign Geographic Area)
Audited
Evaluated
Reviewed
TotalGLJ Petroleum Consultants
December 31, 2016
U.S.A.
-
1,763,091
-
1,763,091





|   |                                                                                                                                                                                                                                                                 
|-- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|6. | In our opinion, the reserves data 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 that we reviewed but did not audit or evaluate.

|   |                                                                                                                                                          
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------
|7. | We have no responsibility to update our report referred to in paragraph 5 for events and circumstances occurring after the effective date of our reports.

|   |                                                                                                                                        
|-- | ---------------------------------------------------------------------------------------------------------------------------------------
|8. | Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.



GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, February 15 , 2017













---

- 3 -













|   |                                                                                                                                                                                                                                                   
|-- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|1. | We have evaluated the Company's reserves 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.

|   |                                                                                                                                                                
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------
|2. | The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves 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 from 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 are in accordance with principles and definitions presented in the COGE Handbook.

|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|-- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|5. | The following table shows the net present value of 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 the Company evaluated for the year ended December 31, 2016, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's management and Board of Directors:

Net Present Value of Future Net Revenue 
 (before income taxes, 10% discount rate - Cdn. $M)Independent Qualified Reserves Evaluator 
 or Auditor
Effective Date of Evaluation Report
Location of Reserves 
 (Country)
Audited 
 (M$)
Evaluated 
 (M$)
Reviewed 
 (M$)
Total 
 (M$)Sproule
December 31, 2016
CanadaTotal


Nil
10,026,162
Nil
10,026,162





|   |                                                                                                                                                                                                                                                                              
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|6. | In our opinion, the reserves 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 that we reviewed but did not audit or evaluate.

|   |                                                                                                                                                                                                                                                                               
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|7. | We have no responsibility to update our report referred to in paragraph 5 for events and circumstances occurring after the effective date of our report, entitled “Evaluation of Certain Saskatchewan P&NG Reserves of Crescent Point Energy Corp. (As of December 31, 2016)”.






---

- 4 -





|   |                                                                                                                                       
|-- | --------------------------------------------------------------------------------------------------------------------------------------
|8. | Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.



































---




















|    |                                                                                                                  
|--- | -----------------------------------------------------------------------------------------------------------------
|(a) | reviewed the Corporation'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 evaluators.



|    |                                                                                                                                               
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------
|(a) | the content and filing with securities regulatory authorities of Form 51-101F1 containing the reserves 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.



"Scott Saxberg"

"C. Neil Smith"SCOTT SAXBERG 
 President and Chief Executive Officer

C. NEIL SMITH 
 Chief Operating Officer"Gerald A. Romanzin"

"Peter Bannister"Gerald A. Romanzin 
 Director

Peter Bannister 
 Director