Exhibit 99.1




CRESCENT POINT ENERGY CORP.
  ANNUAL INFORMATION FORM
  For the Year Ended December 31, 2013
  Dated March 11, 2014
      
  TABLE OF CONTENTS
  SPECIAL NOTES TO READER
1
  GLOSSARY
3
  SELECTED ABBREVIATIONS
5
  CURRENCY OF INFORMATION
6
  OUR ORGANIZATIONAL STRUCTURE
6
  GENERAL DEVELOPMENT OF THE BUSINESS OF THE CORPORATION
8
  DESCRIPTION OF OUR BUSINESS
10
  STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
15
  ADDITIONAL INFORMATION RESPECTING CRESCENT POINT
36
  INDUSTRY CONDITIONS
44
  RISK FACTORS
57
  DIVIDENDS
70
  MARKET FOR SECURITIES
71
  CONFLICTS OF INTEREST
71
  LEGAL PROCEEDINGS
71
  AUDIT COMMITTEE
72
 TRANSFER AGENT AND REGISTRARS
74
  MATERIAL CONTRACTS
74
  INTERESTS OF EXPERTS
74
  ADDITIONAL INFORMATION
74
 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
  
  SPECIAL NOTES TO READER
  This annual information form, the documents incorporated by reference herein, and other reports and filings made with the securities regulatory authorities include forward-looking statements. All forward-looking statements are based on our beliefs and assumptions based on information available at the time the assumption was made. The use of any of the words "could", "should", "can", "anticipate", "expect", "believe", "will", "may", "projected", "sustain", "continues", "strategy", "potential", "projects", "grow", "take advantage", "estimate", "well-positioned" and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Crescent Point (as defined herein) believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. These statements speak only as of the date of this AIF or, if applicable, as of the date specified in this AIF.
  In particular, this annual information form contains forward-looking statements pertaining, among other things, to the following:
  •           anticipated financial performance;
 •           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;
 •           capital expenditure programs and how it will be funded;
 •           drilling programs;
 •           the quantity of the oil and natural gas reserves;
 •           projections of commodity prices and costs;
 •           our future waterflood programs;
 •           future downspacing;
 •           expected decommissioning, abandonment, remediation and reclamation costs;
 •           our tax horizon;
 •           expected trends in environmental regulation;
 •           payment of monthly dividends;
 •           maintenance of a net debt to cash flow ratio of 1.0 times estimated future annual cash flows;
 •           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.
  By its nature, such forward-looking information is subject to various risks, uncertainties and other factors, including those material risks discussed in the AIF (as defined herein) under "Risk Factors" and in the MD&A (as defined herein) under "Risk Factors" and "Forward-Looking Information", which could cause our actual results and experience to differ materially from the anticipated results or other expectations expressed. The material assumptions in making these forward-looking statements are disclosed in the MD&A under the headings "Dividends", "Capital Expenditures", "Decommissioning Liability", "Liquidity and Capital Resources", "Critical Accounting Estimates", "Future Changes in Accounting Policies" and "Outlook".
  This disclosure contains certain forward-looking estimates that involve substantial known and unknown risks and uncertainties, certain of which are beyond Crescent Point's control, including, but not limited to: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas; delays in business operations, pipeline restrictions, blowouts; the risk of carrying out operations with minimal environmental impact; inability to secure adequate production transportation including sufficient crude-by-rail or other alternate transportation; industry conditions including changes in laws and regulations (including the adoption of new environmental laws and regulations) and changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; risks and uncertainties related to oil and gas interests and operations on tribal lands; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; fluctuations in foreign exchange and interest rates; stock market volatility; failure to realize the anticipated benefits of acquisitions; general economic, market and business conditions; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry.
  
  Statements relating to "reserves" and "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves and/or resources described can be profitably produced in the future.
  There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only. In general, estimates of economically recoverable crude oil, natural gas and natural gas liquids reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For these reasons, estimates of the economically recoverable crude oil, natural gas liquids and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. Crescent Point's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. In addition, the discounted and undiscounted net present value of future net revenues attributable to reserves do not represent fair market value; and the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Therefore, Crescent Point's actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking estimates and if such actual results, performance or achievements transpire or occur, or if any of them do so, there can be no certainty as to what benefits Crescent Point will derive therefrom.
  Any financial outlook or future oriented financial information, as defined by applicable securities legislation, in this AIF has been approved by management of Crescent Point. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes. 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.
  The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for the year.
  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.
  New York Stock Exchange
  As a Canadian corporation listed on the NYSE, we are not required to comply with most of the NYSE’s corporate governance standards, and instead may comply with Canadian corporate governance practices. However, we are required to disclose the significant differences between our corporate governance practices and the requirements applicable to U.S. domestic companies listed on the NYSE. Except as summarized on our website at www.crescentpointenergy.com, we are in compliance with the NYSE corporate governance standards in all significant respects.
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  GLOSSARY
  In this annual information form, the capitalized terms set forth below have the following meanings:
  "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 March 11, 2014 for the year ended December 31, 2013.
  "Alston" means Alston Energy Inc.
  "Common Shares" means common shares in the capital of the Corporation.
  "Conversion Arrangement" means the plan of arrangement effected on July 2, 2009 under section 193 of the ABCA pursuant to which the Trust effectively converted from an income trust to a corporate structure.
  "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" or "Company" means Crescent Point Energy Corp., formerly Wild River Resources Ltd., a corporation amalgamated under the ABCA and, where applicable, includes its subsidiaries and affiliates.
  "Cutpick" means Cutpick Energy Inc.
  "Cutpick Arrangement" means the plan of arrangement under Section 193 of the ABCA involving Cutpick and the Corporation, completed on June 20, 2012, as more particularly described under the heading "General Development of the Business of the Corporation – History – 2012".
  "DRIP" means the Premium DividendTM and Dividend Reinvestment Plan of the Corporation.
  "DSU Plan" means a deferred share unit plan for eligible participants including non-employee directors.
  "GLJ" means GLJ Petroleum Consultants Ltd.
  "Greenhouse Gases" or "GHGs" means any or all of carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulphur hexafluoride (SF6).
  "IFRS" means International Financial Reporting Standards as adopted by the Canadian Accounting Standards Board for periods beginning on and after January 1, 2011;
  "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, 2013.
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  "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.
  "Painted Pony" means Painted Pony Petroleum Ltd.
  "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.
  "Reliable" means Reliable Energy Ltd.
  "Reliable Arrangement" means the plan of arrangement under Section 193 of the ABCA involving Reliable and the Corporation, completed on May 1, 2012, as more particularly described under the heading "General Development of the Business of the Corporation – History – 2012".
  "Restricted Share Bonus Plan" means an incentive bonus compensation plan for eligible participants including directors, officers, employees and consultants of the Corporation and its affiliates.
  "Shareholders" means the holders from time to time of Common Shares.
  "Shelter Bay" means Shelter Bay Energy Inc.
  "Sproule" means Sproule Associates Limited.
  "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.
  "Ute" means Ute Energy Upstream Holdings LLC, a limited liability company organized under the laws of the State of Delaware and amalgamated with CPEUS on November 29, 2012.
  "Ute Assets" means the assets of CPEUS owned by Ute prior to its amalgamation with CPEUS.
  "Wild Stream"means Wild Stream Exploration Ltd.
  "Wild Stream Arrangement" means the plan of arrangement under Section 193 of the ABCA involving Wild Stream and the Corporation, completed on March 15, 2012, as more particularly described under the heading "General Development of the Business of the Corporation – History – 2012".
  In this AIF, references to "dollars" and "$" are to the currency of Canada, unless otherwise indicated.
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  SELECTED ABBREVIATIONS
  In this AIF, the abbreviations set forth below have the following meanings:
  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 barrels
MMcf

MMcf/d
million cubic feet

million cubic feet per dayNGLs
natural gas liquids
MMBTU
million British Thermal UnitsGJ
gigajouleOtherAECO
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

m3
barrel of oil equivalent per day

cubic metresM$
thousand dollarsMboe
thousand barrels of oil equivalentMMboe

MW

MW/h
million barrels of oil equivalent

mega watt

mega watt per hourWTI
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade
  - 5 -
  CURRENCY OF INFORMATION
  The information set out in this AIF is stated as at December 31, 2013 unless otherwise indicated. Capitalized terms used but not defined in the text are defined in the Glossary.
  OUR ORGANIZATIONAL STRUCTURE
  The Corporation
  Crescent Point Energy Corp. (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 by way of a court-approved plan of arrangement under the ABCA on July 2, 2009. Pursuant to the Conversion Arrangement, on July 2, 2009, 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 head and principal office of the Corporation is located at Suite 2800, 111 – 5th Avenue S.W., Calgary, Alberta, T2P 3Y6 and its registered office is located at Suite 3700, 400 – 3rd Avenue S.W., Calgary, Alberta, T2P 4H2.
  The Corporation 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. In addition, we continually review and assess numerous corporate and asset acquisition opportunities as part of our ongoing acquisition program.
  We make monthly cash dividends to Shareholders from our net cash flow. Our primary source of cash flow is distributions from the Partnership.
  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.
  The existing business of the Corporation is carried on through the Partnership and through CPEUS. The Partnership holds all ofthe Corporation's Canadian operating assets and CPEUS holds all of our U.S. operating assets.
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  CPHI
  CPHI is a wholly-owned subsidiary of the Corporation. CPHI is a partner of the Partnership.
  CPLux
  CPLux is a wholly-owned indirect subsidiary of the Corporation.
  CPUSH
  Crescent Point U.S. Holdings Corp. is a wholly-owned direct subsidiary of the Corporation.
  CPEUS
  Crescent Point Energy U.S. Corp. is a wholly-owned indirect subsidiary of the Corporation. CPEUS holds the Corporation's operating assets in the United States.
  Relationships
  The following table provides the name, the percentage of voting securities owned by the Corporation and the jurisdiction of incorporation, continuance or formation of the Corporation's material subsidiaries as at the date hereof.
  Percentage of Voting Securities (Directly or Indirectly)
Jurisdiction of Incorporation/FormationCPHI
100%
AlbertaPartnership
100%
AlbertaCPUSH
100%
NevadaCPEUS
100%
DelawareCPLux
100%
Luxembourg
 
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 Organizational Structure of the Corporation
  The following diagram describes the intercorporate relationships among the Corporation and its material direct and indirect subsidiaries described above as at March 11, 2014. Reference should be made to the appropriate sections of this AIF for a complete description of the structure of the Corporation.
  
 
 GENERAL DEVELOPMENT OF THE BUSINESS OF THE CORPORATION
  History
  The following is a description of the general development of the business of Crescent Point over the past three years.
   2011
  On January 14, 2011, the Corporation announced the disposal of 5,861,200 Class A Shares of Painted Pony, representing 11.5% of the issued and outstanding Class A Shares of Painted Pony.
  On April 14, 2011, the Corporation closed an offering of senior unsecured notes in the United States and Canada on a private placement basis with an aggregate principal amount of US$165 million and $50 million. The terms of the U.S. notes range from 5 to 10 years with a weighted average term of 7.9 years and coupon rates ranging from 3.93% to 5.13% and the Canadian notes have a term of 10 years with a coupon rate of 5.53%.
  On June 10, 2011, the Corporation extended the term of the Syndicated Credit Facility by 1 year to June 10, 2014.
  On July 14, 2011, the Corporation announced its land position in the Beaverhill Lake light oil resource play at more than 380 (165 net) sections of land. The Corporation also announced that it had ownership and control of 16,750,000 common shares of Arcan Resources Ltd. ("Arcan"), a leading Beaverhill Lake producer, representing 19% of the issued and outstanding common shares of Arcan.
  On August 31, 2011, the Corporation announced that it had acquired approximately 750 boe/d of production and more than 78 net sections of lower-risk land in North Dakota, U.S., through two strategic acquisitions.
  On September 21, 2011 and September 30, 2011, the Corporation announced the closing of its equity offering of 8,625,000 Common Shares and the over-allotment of 400,000 Common Shares at $43.50 per Common Share for aggregate gross proceeds of approximately $392.6 million.
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  On October 11, 2011, the Corporation announced that it acquired 1,748,000 common shares of Arcan pursuant to Arcan's public offering. The Corporation owns a total of 18,498,000 Arcan common shares, representing approximately 19% of the issued and outstanding common shares of Arcan.
  2012
  On January 24, 2012, the Corporation announced that it had expanded its land position in the Beaverhill Lake light oil resource play in Alberta by more than 100 net sections through a series of acquisitions and Crown land sales.
  On January 25, 2012, the Corporation acquired approximately 940 boe/d of production in southwest Manitoba for cash consideration of $130.3 million.
  On March 8, 2012, the Corporation announced the closing of its equity offering of 13,351,500 Common Shares at $45.25 per Common Share for aggregate gross proceeds of approximately $604.2 million.
  On March 15, 2012, the Corporation closed the Wild Stream Arrangement for total estimated consideration of $610.2 million, comprised of 12,082,012 Common Shares and assumed debt. See "Description of Our Business - Reorganizations".
  On March 16, 2012, the Corporation closed its agreement with PetroBakken Energy Ltd. to acquire more than 2,900 boe/d of production and more than 25 net sections of land in the Viewfield Bakken resource play for cash consideration of $426.4 million.
  On April 16, 2012, the Corporation closed the sale to a private junior exploration and production company of approximately 900 boe/d of non-core Alberta assets, 80 percent of which was weighted to natural gas, and approximately 20 net sections of undeveloped land for total consideration of $35 million, comprised of $10 million of cash and $25 million of shares in the private company.
  On May 1, 2012, the Corporation closed the Reliable Arrangement, pursuant to which the Corporation acquired all of the remaining issued and outstanding shares of Reliable not already owned by the Corporation (as at May 1, 2012, Crescent Point had a 12.8% equity interest in Reliable). Total consideration for the acquisition was $100.7 million, comprised of 1,672,109Common Shares, assumed debt and the historical cost of Crescent Point’s previously held equity investment of $4.8 million. See "Description of Our Business - Reorganizations".
  On May 22, 2012, the Corporation closed an offering of senior guaranteed notes in the United States and Canada on a private placement basis with aggregate principal amounts of US$268 million and $32 million. The terms of the U.S. notes range from 7 to 10 years with a weighted average term of 9.2 years and coupon rates ranging from 3.39% to 4.00% and the terms of the Canadian notes range from 7 to 10 years with a weighted average term of 9.3 years and coupon rates ranging from 4.29% to 4.76%.
  On May 23, 2012, Crescent Point closed a $500.0 million increase and extension to its syndicated unsecured credit facility with a syndicate of Canadian and international banks, with a maturity date in June 2015. The syndicated unsecured credit facility also includes an accordion feature that allows the Corporation to increase the facility by up to $500 million, for a total of $2.5 billion. The Corporation also renewed and extended its unsecured revolving operating credit facility, with $100 million of credit available and a maturity date in June 2014. In total, the Corporation increased its bank lines from $1.6 billion to $2.1 billion.
  On June 1, 2012, Crescent Point acquired approximately 2,500 boe/d of production in the Shaunavon resource play in southwest Saskatchewan for cash consideration of $343.0 million.
  On June 20, 2012, the Corporation closed the Cutpick Arrangement for total consideration of approximately $398.3 million, comprised of 7,556,960Common Shares and assumed debt. See "Description of Our Business - Reorganizations".
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  On July 17, 2012, the Corporation acquired 21,666,667 common share units of Alston at an effective issue price of $0.15 per unit. Each unit was comprised of one common share of Alston and one-half of one common share purchase warrant of Alston. Each warrant entitles the Corporation to acquire one common share of Alston at a price of $0.20 per common share within the 18 month period beginning on July 17, 2012. The units were acquired in connection with a sale by the Corporation to Alston of certain natural gas properties near Alexander, Alberta, which included approximately 225 boe/d of primarily natural gas production.
  On August 30, 2012, the Corporation announced the closing of its equity offering of 15,433,000 Common Shares at $41.00 per Common Share for aggregate gross proceeds of approximately $632.8 million.
  On November 21, 2012, the Corporation announced the closing of its equity offering of 18,750,000 Common Shares at $40.00 per Common Share and on November 29, 2012 the Corporation announced the partial exercise of the over-allotment option granted to the underwriters to purchase an additional 1,250,000 Common Shares at the offering price of $40.00 per Common Share. Including the partial exercise of the over-allotment option, the Corporation issued 20,000,000 Common Shares for aggregate gross proceeds of $800.0 million.
  On November 29, 2012, the Corporation closed the acquisition of Ute for total consideration of approximately $867.6 million, comprised of cash consideration of approximately $783.9 million and assumed debt. See "Description of Our Business - Ute Acquisition".
  2013
  On April 25, 2013, the Corporation announced that its board of directors approved the adoption of an advanced notice by-law, which requires advance notice to the Corporation in circumstances where nominations of persons for election as a director of the Corporation are made by Shareholders other than pursuant to: (i) a requisition of a meeting made pursuant to the provisions of the ABCA; or (ii) a shareholder proposal made pursuant to the provisions of the ABCA.
  On June 6, 2013, Paul Colborne resigned from his role as director of the Corporation.
  On June 12, 2013, the Corporation closed an offering of senior guaranteed notes in the United States and Canada on a private placement basis with aggregate principal amounts of US$290 million and $10 million. The terms of the U.S. notes range from 5 to 10 years with a weighted average term of 9.7 years and coupon rates ranging from 2.65% to 3.78% and the terms of the Canadian note are 10 years with a coupon rate of 4.11%.
  On July 17, 2013 the Corporation renewed and extended the term of the Syndicated Credit Facility by 1 year to June 10, 2016.
  On October 15, 2013, the Corporation announced the suspension of the premium component of its DRIP effective with the October 2013 dividend which was paid on November 15, 2013. Effective with the suspension, Shareholders previously enrolled in the premium component of the DRIP received the regular cash dividend amount of $0.23 per share without the 2 percent premium.
  2014
  On January 22, 2014, the Common Shares began trading on the NYSE under the symbol "CPG".
  DESCRIPTION OF OUR BUSINESS
  General
  The Corporation is an oil and gas exploration, development and production company. The Corporation 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 Canadaand the United States. In addition, we continually review and assess numerous corporate and asset acquisition opportunities as part of our ongoing acquisition program. The primary assets of the Corporation are currently the shares in CPHI, units in the Partnership and shares in CPUSH and, indirectly, in CPEUS.
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  The crude oil and natural gas properties and related assets generating income for the benefit of the Corporation are located in the provinces of Saskatchewan, Alberta, British Columbia and Manitoba and the states of North Dakota, Montana and Utah. The properties and assets consist of producing crude oil and natural gas reserves and Proved plus Probable (as defined herein) crude oil and natural gas reserves not yet on production, land and possible reserves.
  We pay monthly cash dividends to Shareholders from our net cash flow in accordance with our dividend policy. Our primary sources of cash flow are distributions from the Partnership. See "Dividends".
  Strategy
  We strive to create 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 proved 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.
  We develop our properties through a detailed technical analysis of information including reservoir characteristics, petroleum initially in place, recovery factors and the applicability of enhanced recovery techniques. Our goal is to increase reserves and production in a cost effective manner through a number of techniques, including drilling infill and step-out wells, fracture stimulation of horizontal wells, re-completing existing wells and implementing waterflood or pressure support schemes.
  Risk Management and Marketing
  Factors outside our control impact, to varying degrees, the prices we receive for production and the associated operating expenses we incur. These include but are not limited to:
  (a)
world market forces, including 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 quality 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 price 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; and
 (i)
the effect of energy conservation measures and government regulations.
  Fluctuations in commodity prices, quality differentials and foreign exchange and interest rates, among other factors, are outside of our control and yet can have a significant impact on the level of cash we have available for payment of dividends to Shareholders.
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  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 2013 amounted to approximately 56% of annual production, net of royalties, consisting of approximately 60% of annual crude oil production and approximately 22% of annual natural gas production, net of royalties. The primary objective of this strategy is to enhance the stability of cash dividends. The Corporation recorded a realized derivative loss on oil and gas hedge contracts of $90.9 million in 2013.
  The following table summarizes our commitments under all hedging agreements as at December 31, 2013.
  Financial WTI Crude Oil Derivative Contracts – Canadian Dollar
  Term
Volume

(bbl/d)
Average

Swap Price

(Cdn$/bbl)
Average Collar

Sold Call Price

(Cdn$/bbl)
Average Collar Bought Put Price

(Cdn$/bbl)
Average Bought Put Price

(Cdn$/bbl)
Average Put Premium

(Cdn$/bbl)2014 Weighted Average
57,097
96.71
102.79
88.08
98.12
4.732015 Weighted Average
26,750
92.35
97.60
87.41
-
-2016 Weighted Average
18,000
90.34
-
-
-
-January to March 2017 Weighted Average
6,000
90.31
-
-
-
-
 
 Financial AECO Natural Gas Derivative Contracts – Canadian Dollar
  Term
Contract
Volume

(GJ/d)
Average Swap Price

(Cdn$/GJ)2014 Weighted Average
Swap
14,493
3.542015 Weighted Average
Swap
13,332
3.55January to October 2016 Weighted Average
Swap
5,790
3.67
 
 Financial Power Derivative Contracts – Canadian Dollar
  Term
Contract
Volume

(MW/h)
Fixed Rate

($/MW/h)2014
Swap
3.0
75.002015
Swap
3.0
49.50
 
 Financial Interest Rate Derivative Contracts – Canadian Dollar
  Term
Contract
Notional Principal (Cdn$)
Fixed Annual

Rate (%)January 2014 - May 2015
Swap
25,000,000
2.90January 2014 - May 2015
Swap
25,000,000
3.50January 2014 - May 2015
Swap
50,000,000
3.09January 2014 - June 2015
Swap
50,000,000
3.78January 2014 - July 2015
Swap
50,000,000
3.63
  - 12 -
 
 Financial Cross Currency Interest Rate Derivative Contracts
  Term
Contract
Receive Notional

Principal

(US$)
Fixed Annual Rate

(US%)
Pay Notional Principal (Cdn$)
Fixed Annual

Rate

(Cdn%)January 2014 - March 2015
Swap
37,500,000
4.71
38,287,500
5.24January 2014 - April 2016
Swap
52,000,000
3.93
50,128,000
4.84January 2014 - March 2017
Swap
67,500,000
5.48
68,917,500
5.89January 2014 - April 2018
Swap
31,000,000
4.58
29,884,000
5.32January 2014 - June 2018
Swap
20,000,000
2.65
20,350,000
3.52January 2014 - May 2019
Swap
68,000,000
3.39
66,742,000
4.53January 2014 - March 2020
Swap
155,000,000
6.03
158,255,000
6.45January 2014 - April 2021
Swap
82,000,000
5.13
79,048,000
5.83January 2014 - May 2022
Swap
170,000,000
4.00
166,855,000
5.03January 2014 - June 2023
Swap
270,000,000
3.78
274,725,000
4.32
 
 Financial Cross Currency Principal Derivative Contracts
  Settlement Date
Contract
Receive Notional

Principal

(US$)
Pay Notional Principal (Cdn$)May 22, 2022
Swap
30,000,000
32,241,000
  In addition to hedging benchmark crude oil and natural gas prices with financial instruments, we have also mitigated crude oil basis risk by delivering a portion of our crude oil production into diversified refinery markets using rail transportation. As of January 2014, Crescent Point owned and operatedfour railcar loading facilities, serving its key producing areas of southeast Saskatchewan, southwest Saskatchewan, central Alberta and Utah.
  Crude oil volumes loaded at these facilities are sold at the loading facilities and our buyers are responsible for providing railcars and managing transportation logistics from that point until delivery at the refinery gate. By utilizing rail transportation, we have been able to access refining markets that are not pipeline connected to western Canada or Utah, which significantly diversifies our price and market risk. In addition, we have been able to enter into term sales contracts on a portion of the volumes transported by rail, which set the price differential between benchmark WTI prices and our selling price at the loading terminals. From January to December 2013, approximately 17,400 bbl/d of oil production was contracted with fixed price differentials off WTI. As of early March 2014, approximately 14,200 bbl/d of oil production from January to December 2014 and approximately 2,500 bbl/d of oil production from January 2015 to March 2015 was contracted with fixed priced differentials off WTI. By locking in the price differential on these volumes, we have been able to reduce our exposure to volatility in Canadian crude oil differentials.
  We also mitigate risk by having a well-diversified marketing portfolio for oil and natural gas. As a result of our access to rail transportation, we have significantly increased and diversified the number of counterparties with which we transact. Credit risk associated with the Corporation's portfolio of physical crude oil and natural gas sales and with the Corporation's commodity hedging portfolio is managed and mitigated by Crescent Point's Risk Management Committee and is governed by a Board-approved Risk Management and Counterparty Credit Policy that is reviewed by the board of directors on an annual basis. The Policy requires annual credit reviews of all trade counterparties with which the Corporation has, or expects to have, exposures greater than 0.5% of the Corporation’s total aggregate monthly volumetric exposure. Credit limits are required to be set for all trade counterparties, which are based on either a fixed dollar amount which is set annually at a minimum or a percentage of the Corporation's portfolio calculated monthly. Crescent Point utilizes a diversified approach in both its physical sales portfolio and its financial hedging portfolio. The physical sales portfolio consists of more than 50 purchasers and its financial hedging portfolio consists of 12 counterparties. The Corporation's portfolio of counterparty exposures is reviewed monthly by the Chief Financial Officer, the Vice President, Finance and Treasurer, and the Vice President, Marketing and Investor Relations. Counterparty exposures are also reviewed on a quarterly basis by both the Risk Management Committee and the board of directors.
  - 13 -
  To further mitigate credit risk associated with its physical sales portfolio, Crescent Point has secured credit insurance from a leading global credit insurance provider. This policy provides credit coverage for approximately 30 percent of the Corporation's physical sales portfolio.
  The majority of our oil and natural gas volumes are sold in the U.S., Alberta and Saskatchewan. Approximately 79% of our oil volumes are sold in Saskatchewan, 8% in Alberta and 13% in the U.S. Approximately 51% of our natural gas volumes are sold in Saskatchewan, 34% in Alberta and 15% in the U.S.
  Revenue Sources
  For 2013, our commodity production mix was approximately 91% oil and NGLs and 9% natural gas.
  The following table summarizes our revenue sources by product before hedging and royalties:
  For Year Ended
Crude Oil and NGLs
Natural Gas2013
97%
3%2012
98%
2%2011
97%
3%
 
 Competition
  We actively 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.
  Certain of our customers and potential customers are themselves exploring for oil and natural gas, and the results of such exploration 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 will be dependent upon developing and maintaining close working relationships with our industry partners and joint operators, our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.
  Seasonal Factors
  The production of oil and natural gas is dependent on access to areas where development of reserves is to be conducted. Seasonal weather variations, including freeze-up and break-up, affect access in certain circumstances.
  Personnel
  As at December 31, 2013, we had 409full-time employees and 74 consultants at our Calgary and Denver offices. In the field we had 372 full-time field staff and 134consultants.
  Reorganizations
  On January 1, 2011, the Corporation amalgamated with Ryland Oil ULC, Darian Resources Ltd. and Shelter Bay ULC.
  On March 15,2012, the Corporation closedthe Wild Stream Arrangement for total consideration of $610.2 million, comprised of 12,082,012 Common Shares and assumed debt. The Wild Stream Arrangement further solidified the Corporation’s position as the largest player in the Shaunavon resource play in southwest Saskatchewan, in terms of production and land. Wild Stream’s assets also complemented the Corporation’s existing position in Alberta’s emerging Beaverhill Lake light oil resource play in the Swan Hills area.
  On May 1, 2012, the Corporation closed the Reliable Arrangement, pursuant to which the Corporation acquired all of the remaining issued and outstanding shares of Reliable not already owned by the Corporation. Total consideration for the acquisition was $100.7 million, comprised of 1,672,109 Common Shares, assumed debt and the historical cost of Crescent Point's previously held equity investment of $4.8 million. The Reliable Arrangement allowed the Corporation to consolidate the assets that were held through a joint venture with Reliable in the Bakken light oil play in southwest Manitoba.
  - 14 -
  On June 20, 2012, the Corporation closed the Cutpick Arrangement for total consideration of approximately $398.3 million, comprised of 7,556,960 Common Shares and assumed debt. The assets in the Viking light oil resource play near Provost, Alberta acquired from the Cutpick Arrangement complement and consolidate the Corporation’s existing position in the play.
  Ute Acquisition
  On November 29, 2012, the Corporation closed the acquisition of Ute for total consideration of approximately $867.6 million, comprised of cash consideration of approximately $783.9 million and assumed debt of approximately $83.7 million. The acquisition established a new core area for potential long-term growth in the Uinta Basin light oil resource play in northeast Utah.
  Social and Environmental Policies
  The Corporation has a voluntary reclamation fund to fund future decommissioning costs and environmental emissions reduction costs. From January 1, 2011 to December 31, 2011, we allocated $0.45 per boe of production. From January 1, 2012 to December 31, 2012, we allocated $0.50 per boe of production. From January 1, 2013 to December 31, 2013, we allocated $0.70 per boe of production. Additional contributions can be made at the discretion of management.
  STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
  Disclosure of Reserves Data
  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, 2013 contained in the consolidated report of GLJ dated March 11, 2014 (the "Crescent Point Reserve Report"). The Crescent Point Reserve Report evaluated, as at December 31, 2013, 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 GLJ's January 1, 2014 forecast price and cost assumptions. GLJ evaluated approximately 39 percent of the assigned total Proved plus Probable reserves and 30 percent of the total Proved plus Probable value discounted at 10 percent. Sproule evaluated approximately 61 percent of the assigned total Proved plus Probable reserves and 70 percent of the total Proved plus Probable value discounted at 10 percent. Sproule evaluated a majority of our Saskatchewan assets including the Viewfield Bakken properties in southeast Saskatchewan and the Shaunavon properties in southwest Saskatchewan. Sproule evaluated their portion of the reserves using the GLJ forecast price and cost escalation assumptions. GLJ evaluated the Corporation’s Alberta and Manitoba assets as well as a portion of the Saskatchewan assets in Canada. GLJ also performed the evaluation of the Corporation's US assets in North Dakota, Montana and Utah. These assets were all evaluated using the GLJ forecast price and cost escalation assumptions. GLJ prepared the total Crescent Point Reserve Report by consolidating the GLJ Canadian and US evaluated properties with the Sproule evaluation using the GLJ 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 abandonment costs for only those wells 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.
  - 15 -
  The Crescent Point Reserve Report is based on certain factual data supplied by us as well as GLJ and Sproule's opinion of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to our petroleum properties and contracts (except for certain information residing in the public domain) were supplied by the Corporation to GLJ and Sproule, and were accepted without any further investigation. GLJ and Sproule accepted this data as presented and neither title searches nor field inspections were conducted.
  Reserves Data – Forecast Prices and Costs
  Summary of Oil and Gas Reserves(1)
  Light and Medium Oil


Heavy Oil


Natural Gas Liquids


Natural Gas


TotalReserves Category

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

(Mboe)


Company

Net

(Mboe)Proved Developed ProducingCanada


191,029



168,272



639



626



8,206



7,516



99,292



92,276



216,422



191,794United States


18,783



15,316



-



-



1,405



1,140



16,811



13,794



22,990



18,755Total


209,811



183,588



639



626



9,611



8,656



116,104



106,070



239,413



210,549Proved Developed Non-ProducingCanada


8,476



7,698



490



462



499



454



9,436



8,704



11,037



10,065United States


886



731



-



-



58



48



612



522



1,046



866Total


9,361



8,429



490



462



557



502



10,049



9,226



12,082



10,931Proved UndevelopedCanada


125,171



114,925



146



131



6,817



6,287



63,311



59,013



142,686



131,179United States


32,339



26,248



-



-



2,050



1,660



25,184



20,537



38,587



31,330Total


157,511



141,172



146



131



8,867



7,947



88,495



79,550



181,272



162,509Total ProvedCanada


324,675



290,895



1,274



1,220



15,522



14,258



172,040



159,992



370,145



333,038United States


52,008



42,295



-



-



3,513



2,848



42,608



34,853



62,623



50,951Total


376,683



333,189



1,274



1,220



19,035



17,105



214,647



194,845



432,767



383,989Total ProbableCanada


167,553



148,562



672



614



6,903



6,241



89,661



82,359



190,072



169,143United States


34,343



27,801



-



-



2,318



1,869



25,539



20,730



40,918



33,124Total


201,896



176,362



672



614



9,222



8,110



115,200



103,089



230,990



202,267Total Proved Plus ProbableCanada


492,228



439,456



1,947



1,834



22,425



20,499



261,701



242,352



560,217



502,181United States


86,351



70,095



-



-



5,832



4,716



68,147



55,582



103,541



84,075Total


578,580



509,551



1,947



1,834



28,257



25,215



329,848



297,934



663,758



586,256
 
 Note:
 (1)             Numbers may not add due to rounding.
  - 16 -
  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%

(M$)
5%

(M$)
10%

(M$)
15%

(M$)
20%

(M$)

0%

(M$)
5%

(M$)
10%

(M$)
15%

(M$)
20%

(M$)Proved Developed ProducingCanada
10,903,288
8,173,562
6,677,268
5,713,876
5,034,143

9,364,224
7,037,406
5,759,091
4,934,690
4,352,119United States
870,459
696,588
585,568
509,237
453,692

870,459
696,588
585,568
509,237
453,692Total
11,773,748
8,870,150
7,262,836
6,223,113
5,487,836

10,234,683
7,733,994
6,344,659
5,443,927
4,805,811Proved Developed

Non-ProducingCanada
538,553
427,041
356,300
307,391
271,568

398,553
314,665
261,497
224,782
197,926United States
40,592
31,605
26,117
22,442
19,806

40,592
31,605
26,117
22,442
19,806Total
579,145
458,646
382,416
329,833
291,374

439,146
346,269
287,614
247,224
217,732Proved UndevelopedCanada
5,391,044
3,690,873
2,662,359
1,993,598
1,534,433

3,956,962
2,623,825
1,819,984
1,300,643
947,235United States
1,050,415
614,055
375,093
230,789
137,339

903,534
539,414
334,709
207,838
123,758Total
6,441,459
4,304,928
3,037,452
2,224,387
1,671,773

4,860,496
3,163,240
2,154,694
1,508,481
1,070,994Total ProvedCanada
16,832,885
12,291,476
9,695,927
8,014,865
6,840,144

13,719,740
9,975,896
7,840,572
6,460,115
5,497,280United States
1,961,467
1,342,248
986,777
762,469
610,838

1,814,586
1,267,607
946,394
739,517
597,257Total
18,794,352
13,633,724
10,682,704
8,777,333
7,450,982

15,534,325
11,243,503
8,786,966
7,199,633
6,094,537Total ProbableCanada
10,150,817
6,212,507
4,334,331
3,265,167
2,585,767

7,570,782
4,595,248
3,174,928
2,366,983
1,854,641United States
1,612,065
892,879
572,962
401,691
297,947

966,214
509,110
309,246
203,050
138,904Total
11,762,882
7,105,385
4,907,293
3,666,858
2,883,714

8,536,996
5,104,359
3,484,174
2,570,032
1,993,545Total Proved Plus ProbableCanada
26,983,702
18,503,983
14,030,257
11,280,032
9,425,911

21,290,522
14,571,144
11,015,500
8,827,098
7,351,920United States
3,573,532
2,235,126
1,559,740
1,164,160
908,785

2,780,799
1,776,717
1,255,640
942,567
736,161Total
30,557,234
20,739,109
15,589,997
12,444,192
10,334,697

24,071,321
16,347,861
12,271,140
9,769,665
8,088,082
 Note:
 (1)            Numbers may not add due to rounding.
  Additional Information Concerning Future Net Revenue – (Undiscounted)(1)
  Reserves Category
Revenue

(M$)
Royalties

(M$)
Operating

Costs

(M$)
Capital

Development

Costs

(M$)
Abandonment

Costs

(M$)
Future Net

Revenue Before

Income Taxes

(M$)
Income Tax

(M$)
Future Net

Revenue After

Income Taxes

(M$)ProvedCanada
33,867,010
4,120,189
9,245,403
3,375,725
292,808
16,832,885
3,113,145
13,719,740United States
5,425,517
1,366,785
1,247,782
804,460
45,023
1,961,467
146,881
1,814,586Total
39,292,527
5,486,974
10,493,186
4,180,185
337,831
18,794,352
3,260,026
15,534,325Proved Plus ProbableCanada
52,715,700
6,514,293
14,197,810
4,659,872
360,024
26,983,702
5,693,180
21,290,522United States
9,399,651
2,394,847
2,156,684
1,213,036
61,552
3,573,532
792,732
2,780,799Total
62,115,352
8,909,140
16,354,494
5,872,908
421,576
30,557,234
6,485,913
24,071,321
 Note:
 (1)           Numbers may not add due to rounding.
  - 17 -
  Future Net Revenue by Production Group
  Future Net Revenue

Before Income Taxes(3)

(Discounted at 10% per year)
Percentage
Unit Value(M$)
(%)
($/boe)
($/Mcfe)ProvedCANADALight and Medium Oil(1)
9,625,415
99
29.45
4.91Heavy Oil(1)
34,022
<1
22.22
3.70Natural Gas(2)
36,489
<1
7.85
1.31Total Canada
9,695,927
100
29.11
4.85UNITED STATESLight and Medium Oil(1)
986,777
100
19.37
3.23Heavy Oil(1)
-
-
-
-Natural Gas(2)
-
-
-
-Total United States
986,777
100
19.37
3.23TOTALLight and Medium Oil(1)
10,612,193
99
28.51
4.75Heavy Oil(1)
34,022
<1
22.22
3.70Natural Gas(2)
36,489
<1
7.85
1.31Total Proved
10,682,704
100
27.82
4.64
  Notes:
  (1)           Including solution gas and other by-products.
 (2)           Including by-products but excluding solution gas.
 (3)           Other company revenue and costs not related to a specific production group have been allocated proportionately to production groups.
 Unit values are based on Company Net Reserves.
 (4)           Numbers may not add due to rounding.
  Future Net Revenue

Before Income Taxes(3)

(Discounted at 10% per year)
Percentage
Unit Value(M$)
(%)
($/boe)
($/Mcfe)Proved Plus ProbableCANADALight and Medium Oil(1)
13,927,073
99
28.24
4.71Heavy Oil(1)
50,704
<1
22.04
3.67Natural Gas(2)
52,480
<1
7.82
1.30Total
14,030,257
100
27.94
4.66UNITED STATESLight and Medium Oil(1)
1,559,740
100
18.55
3.09Heavy Oil(1)
-
-
-
-Natural Gas(2)
-
-
-
-Total
1,559,740
100
18.55
3.09TOTALLight and Medium Oil(1)
15,486,813
99
27.26
4.54Heavy Oil(1)
50,704
<1
22.04
3.67Natural Gas(2)
52,480
<1
7.82
1.30Total Proved Plus Probable
15,589,997
100
26.59
4.43
 Notes:
 (1)           Including solution gas and other by-products.
 (2)           Including by-products but excluding solution gas.
 (3)           Other company revenue and costs not related to a specific production group have been allocated proportionately to production groups.
 Unit values are based on Company Net Reserves.
 (4)           Numbers may not add due to rounding.
  For future net revenue of the total Proved reserves for the total company, discounted at 10 percent, 99% of the revenue is from light and medium oil, less than 1% from heavy oil, and less than 1% from natural gas. For the total Proved plus Probable reserves for the total company, discounted at 10 percent, 99% of the revenue is from light and medium oil, less than 1% from heavy oil, and less than 1% from natural gas.
  Notes and Definitions
  In the tables set forth above in "Disclosure of Reserves Data" and elsewhere in this AIF, the following notes and other definitions are applicable.
  - 18 -
  Reserve Categories
  The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of Proved, Probable and possible reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery.
  The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions.
  (a)
"Reserves" are estimated remaining 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.
  Levels of Certainty for Reported Reserves
  The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:
  ·
At least a 90% probability that the quantities actually recovered will equal or exceed the estimated Proved reserves; and
  - 19 -
  ·
At least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable reserves.
  A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.
  Additional Definitions
  The following terms, used in the preparation of the Crescent Point Reserve Report and this AIF, have the following meanings:
  (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");
  - 20 -
  (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.
  (f)
"exploratory well" means a well that is not a development well, a service well or a stratigraphic test well.
  (g)
"F&D costs" means finding and development costs.
  (h)
"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".
  (i)
"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).
  (j)
"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.
  - 21 -
  (k)
"future net revenue" means the estimated net amount to be received with respect to the development and production of reserves (including synthetic oil, coal bed methane and other non-conventional reserves) estimated using forecast prices and costs.
  (l)
"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.
  (m)
"natural gas" means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain natural gas liquids. Natural gas can exist in a reservoir either dissolved in crude oil (solution gas) or in a gaseous phase (associated gas or non-associated gas). Non-hydrocarbon substances may include hydrogen sulphide, carbon dioxide and nitrogen.
  (n)
"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.
  (o)
"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.
  (p)
"non-associated gas" means an accumulation of natural gas in a reservoir where there is no crude oil.
  (q)
"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.
  (r)
"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.
  (s)
"property" includes:
  - 22 -
  (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).
  A property does not include supply agreements, or contracts that represent a right to purchase, rather than extract, oil or gas.
  (t)
"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.
  (u)
"proved property" means a property or part of a property to which reserves have been specifically attributed.
  (v)
"reservoir" means a porous and permeable subsurface rock formation that contains a separate accumulation of petroleum that is confined by impermeable rock or water barriers and is characterized by a single pressure system.
  (w)
"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.
  (x)
"solution gas" means natural gas dissolved in crude oil.
  (y)
"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".
  (z)
"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.
  (aa)
"unproved property" means a property or part of a property to which no reserves have been specifically attributed.
  - 23 -
  (bb)
"well abandonment costs" means costs of abandoning a well (net of salvage value) and of disconnecting the well from the surface gathering system. They do not include costs of abandoning the gathering system or reclaiming the wellsite.
  Pricing Assumptions – Forecast Prices and Costs
  GLJ and Sproule employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2013 in estimating our reserves data using forecast prices and costs.
  Year
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)
Inflation Rate

(%/yr)
Exchange

Rate

($US/$Cdn)Forecast2014
4.25
4.03
97.50
92.76
105.20
73.22
57.83
2.0
0.9502015
4.50
4.26
97.50
97.37
107.11
75.95
58.42
2.0
0.9502016
4.75
4.50
97.50
100.00
107.00
78.00
60.00
2.0
0.9502017
5.00
4.74
97.50
100.00
107.00
78.00
60.00
2.0
0.9502018
5.25
4.97
97.50
100.00
107.00
78.00
60.00
2.0
0.9502019
5.50
5.21
97.50
100.00
107.00
78.00
60.00
2.0
0.9502020
5.63
5.33
98.54
100.77
107.82
78.60
60.46
2.0
0.9502021
5.74
5.44
100.51
102.78
109.97
80.17
61.67
2.0
0.9502022
5.86
5.55
102.52
104.83
112.17
81.77
62.90
2.0
0.9502023
5.97
5.66
104.57
106.93
114.41
83.40
64.16
2.0
0.9502024+
+2.0%/yr
+2.0%/yr
+2.0%/yr
+2.0%/yr
+2.0%/yr
+2.0%/yr
+2.0%/yr
2.0
0.950
 
 For the year ended December 31, 2013, the average realized sales prices before hedging were $88.48/bbl for light and medium oil, $72.31/bbl for heavy oil, $48.45/bbl for NGLs and $3.61/mcf for natural gas.
  Reconciliations of Changes in Reserves and Future Net Revenue
   Reserves Reconciliation
  The following table sets forth a reconciliation of the Corporation's Company Gross reserves by total Proved, total Probable and total Proved plus Probable reserves as at December 31, 2013 against such reserves as at January 1, 2013 based on forecast price and cost assumptions.
  CANADA
Light and Medium Oil (Mbbls)
Heavy Oil (Mbbls)
Natural Gas Liquids (Mbbls)Factors
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

ProbableJanuary 1, 2013(1)
304,915
155,913
460,829
2,487
1,088
3,575
14,157
6,790
20,947Discoveries
-
-
-
-
-
-
-
-
-Extensions and Improved Recovery
23,853
18,252
42,106
-
-
-
506
458
963Technical Revisions
24,847
(7,930)
16,917
(576)
(264)
(840)
2,546
(379)
2,167Acquisitions
3,714
1,498
5,212
-
-
-
173
78
251Dispositions
(57)
(110)
(166)
-
-
-
(11)
(47)
(57)Economic Factors
85
(71)
14
(456)
(152)
(607)
2
3
5Production
(32,683)
-
(32,683)
(181)
-
(181)
(1,852)
-
(1,852)December 31, 2013(2)
324,675
167,553
492,228
1,274
672
1,947
15,522
6,903
22,425
 
 CANADA
Associated and Non-Associated Gas (Natural Gas) (MMcf)
BOE (Mboe)Factors
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

ProbableJanuary 1, 2013(1)
168,674
88,592
257,266
349,672
178,557
528,229Discoveries
-
-
-
-
-
-Extensions and Improved Recovery
9,709
6,273
15,982
25,977
19,757
45,734Technical Revisions
14,427
(4,225)
10,202
29,222
(9,278)
19,944Acquisitions
1,083
509
1,592
4,068
1,660
5,728Dispositions
(280)
(1,245)
(1,525)
(114)
(364)
(478)Economic Factors
(919)
(243)
(1,163)
(523)
(260)
(783)Production
(20,652)
-
(20,652)
(38,157)
-
(38,157)December 31, 2013(2)
172,040
89,661
261,701
370,145
190,072
560,217
  - 24 -
  UNITED STATES
Light and Medium Oil (Mbbls)
Heavy Oil (Mbbls)
Natural Gas Liquids (Mbbls)Factors
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

ProbableJanuary 1, 2013(1)
43,711
25,687
69,399
-
-
-
1,260
1,059
2,319Discoveries
-
-
-
-
-
-
-
-
-Extensions and Improved Recovery
14,499
11,420
25,918
-
-
-
887
602
1,488Technical Revisions
(903)
(1,861)
(2,763)
-
-
-
1,581
732
2,312Acquisitions
-
-
-
-
-
-
-
-
-Dispositions
-
-
-
-
-
-
-
-
-Economic Factors
(407)
(903)
(1,310)
-
-
-
11
(74)
(63)Production
(4,892)
-
(4,892)
-
-
-
(224)
-
(224)December 31, 2013(2)
52,008
34,343
86,351
-
-
-
3,513
2,318
5,832
 
 UNITED STATES
Associated and Non-Associated Gas (Natural Gas) (MMcf)
BOE (Mboe)Factors
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved +

ProbableJanuary 1, 2013(1)
34,380
18,727
53,107
50,701
29,867
80,568Discoveries
-
-
-
-
-
-Extensions and Improved Recovery
9,659
6,773
16,432
16,995
13,150
30,145Technical Revisions
2,692
933
3,625
1,127
(973)
154Acquisitions
-
-
-
-
-
-Dispositions
-
-
-
-
-
-Economic Factors
(338)
(894)
(1,232)
(453)
(1,125)
(1,578)Production
(3,785)
-
(3,785)
(5,748)
-
(5,748)December 31, 2013(2)
42,608
25,539
68,147
62,623
40,918
103,541TOTAL
Light and Medium Oil (Mbbls)
Heavy Oil (Mbbls)
Natural Gas Liquids (Mbbls)Factors
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

ProbableJanuary 1, 2013(1)
348,627
181,600
530,227
2,487
1,088
3,575
15,417
7,849
23,266Discoveries
-
-
-
-
-
-
-
-
-Extensions and Improved Recovery
38,352
29,672
68,024
-
-
-
1,394
1,059
2,451Technical Revisions
23,945
(9,791)
14,154
(576)
(264)
(840)
4,127
352
4,479Acquisitions
3,714
1,498
5,212
-
-
-
173
78
251Dispositions
(57)
(110)
(166)
-
-
-
(11)
(47)
(57)Economic Factors
(322)
(974)
(1,296)
(456)
(152)
(607)
12
(71)
(58)Production
(37,575)
-
(37,575)
(181)
-
(181)
(2,076)
-
(2,076)December 31, 2013(2)
376,683
201,896
578,580
1,274
672
1,947
19,035
9,222
28,257
 
 TOTAL
Associated and Non-Associated Gas (Natural Gas) (MMcf)
BOE (Mboe)Factors
Proved
Probable
Proved

+

Probable
Proved
Probable
Proved

+

ProbableJanuary 1, 2013(1)
203,053
107,319
310,373
400,373
208,424
608,797Discoveries
-
-
-
-
-
-Extensions and Improved Recovery
19,367
13,047
32,414
42,972
32,907
75,879Technical Revisions
17,119
(3,292)
13,827
30,348
(10,251)
20,097Acquisitions
1,083
509
1,592
4,068
1,660
5,728Dispositions
(280)
(1,245)
(1,525)
(114)
(364)
(478)Economic Factors
(1,257)
(1,137)
(2,395)
(976)
(1,385)
(2,361)Production
(24,437)
-
(24,437)
(43,905)
-
(43,905)December 31, 2013(2)
214,647
115,200
329,848
432,767
230,990
663,758
 
 Notes:
 (1)
The Corporation has no unconventional reserves (Bitumen, Synthetic Crude Oil, Natural Gas from Coal, Natural Gas from Hydrates, Shale Oil, Shale Gas, etc.).
 (2)
Numbers may not add due to rounding.
  Undeveloped Reserves
  The following discussion generally describes the basis on which we attribute Proved and Probable undeveloped reserves. Our plans for developing our undeveloped reserves are described in the section "Major Oil and Gas Properties".
  - 25 -
  Proved Undeveloped Reserves
  Proved undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. In addition, such reserves may relate to planned infill drilling locations. The majority of these reserves are planned to be on stream within a three year timeframe. The following table provides the timing of the initial reserve assignments for the Corporation's gross Proved undeveloped reserves.
   Timing of Initial Proved Undeveloped Reserve Assignment
  Light & Medium Oil

(Mbbl)
Heavy Oil (Mbbl)
Natural Gas (MMcf)
Natural Gas Liquids

(Mbbl)
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-End2010
18,581
96,980
-
125
19,269
44,347
1,317
4,885
23,110
109,3812011
27,772
108,221
145
226
15,260
51,273
1,201
5,407
31,662
122,3992012
49,472
152,248
183
347
33,277
87,807
1,636
7,640
56,836
174,8692013
37,482
157,511
39
146
25,491
88,495
1,481
8,867
43,250
181,272
 
 Note:
 (1)           "First attributed" refers to reserves first attributed at year-end to corresponding fiscal year.
  Probable Undeveloped Reserves
  Probable undeveloped reserves are generally those reserves tested or indicated by analogy to be productive, infill drilling locations and lands contiguous to production. The majority of these reserves are planned to be on stream within a five year timeframe. The following table provides the timing of the initial reserve assignments for the Corporation's Probable undeveloped gross reserves.
  Timing of Initial Probable Undeveloped Reserves Assignment
  Light & Medium Oil

(Mbbl)
Heavy Oil (Mbbl)
Natural Gas (MMcf)
Natural Gas Liquids

(Mbbl)
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-End2010
18,115
69,189
39
212
12,675
26,143
734
2,511
21,000
76,2702011
22,493
73,204
137
295
11,870
32,184
673
2,726
25,281
81,5892012
42,350
109,275
63
322
26,525
60,957
1,341
4,432
48,175
124,1882013
42,447
118,895
8
214
23,412
64,916
1,482
4,985
47,839
134,913
 
 Note:
 (1)           "First attributed" refers to reserves first attributed at year end of the corresponding fiscal year.
  Significant Factors or Uncertainties Affecting Reserves Data
  The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions. Our reserves are evaluated by GLJ and Sproule, each an independent engineering firm.
  As circumstances change and additional data become available, reserve estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental regulations.
  Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from changes in year end oil and gas prices, and reservoir performance. Such revisions can be either positive or negative.
  - 26 -
  Future Development Costs
  The table below sets out the development costs deducted in the estimation of future net revenue attributable to total Proved reserves and total Proved plus Probable reserves (using forecast prices and costs).
  Company Annual Capital Expenditures (M$)Canada
US
TotalYear
Total Proved
Total Proved

Plus Probable
Total Proved
Total Proved Plus Probable
Total

Proved
Total Proved Plus Probable2014
847,259
1,132,660
239,975
286,925
1,087,234
1,419,5852015
781,503
1,127,649
248,411
409,570
1,029,914
1,537,2192016
733,100
938,428
247,449
407,909
980,549
1,346,3372017
591,073
835,750
64,025
87,204
655,098
922,9532018
347,120
543,984
4,600
21,429
351,720
565,4132019
9,674
9,468
-
-
9,674
9,4682020
6,449
7,334
-
-
6,449
7,3342021
4,022
3,706
-
-
4,022
3,7062022
3,354
4,469
-
-
3,354
4,4692023
5,276
4,887
-
-
5,276
4,8872024
3,879
3,606
-
-
3,879
3,6062025
2,427
2,723
-
-
2,427
2,723Subtotal(1)

Remainder
3,335,135

40,589
4,614,665

45,207
804,460

-
1,213,036

-
4,139,595

40,589
5,827,701

45,207Total(1)

10% Discounted
3,375,725

2,735,739
4,659,872

3,774,524
804,460

687,972
1,213,036

1,026,431
4,180,185

3,423,711
5,872,908

4,800,955
 
 Note:
 (1)
Numbers may not add due to rounding.
 
 
 Company Annual Abandonment Costs (M$)Canada
US
TotalYear
Total Proved
Total Proved

Plus Probable
Total Proved
Total Proved Plus Probable
Total Proved
Total Proved Plus Probable2014
4,272
3,971
1,373
1,220
5,646
5,1912015
1,840
1,121
291
108
2,130
1,2292016
2,951
1,999
644
384
3,596
2,3832017
5,483
4,109
146
108
5,629
4,2172018
4,025
3,186
651
312
4,677
3,4982019
5,745
3,182
435
345
6,180
3,5272020
5,023
3,506
513
516
5,536
4,0222021
5,610
3,394
407
383
6,017
3,7762022
6,633
3,316
465
442
7,098
3,7582023
5,742
3,565
437
486
6,179
4,0512024
9,030
5,215
642
304
9,672
5,5192025
7,459
4,662
851
177
8,310
4,839Subtotal(1)

Remainder
63,813

228,995
41,227

318,797
6,856

38,167
4,785

56,767
70,669

267,162
46,012

375,564Total(1)

10% Discounted
292,808

65,870
360,024

54,110
45,023

8,559
61,552

6,727
337,831

74,429
421,576

60,837
  Note:
 (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 (including proceeds from our DRIP), 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 3.50% per annum. We expect to fund our total 2014 capital program with internally generated cash flow and, although quarterly fluctuations in funding levels are expected, our objective is to maintain our current leverage throughout 2014. Our objective is to maintain our net debt to cash flow ratio at 1.0 times estimated future annual cash flows.
  Major Oil and Gas Properties
  The following is a description of the Corporation's major oil and natural gas properties, plants, facilities and installations in which we have an interest and that are material to our operations and activities. Unless otherwise noted, reserve amounts are stated before deduction of royalties, based on escalating cost and price assumptions as evaluated in the Crescent Point Reserve Report as at December 31, 2013.
  - 27 -
  Crescent Point has continued to focus on the development of large resource play assets in Canada and the United States. The properties discussed below account for a majority of the reserve bookings prepared by GLJ and Sproule for year-end 2013, and are representative of the high quality assets in the Corporation’s portfolio.
  CANADA
  Viewfield Bakken Resource Play
  The Viewfield Bakken light oil resource play area in southeast Saskatchewan continues to experience production and reserve growth as a result of improved drilling and completion techniques, step-out and infill drilling, as well as waterflood performance.
  Crescent Point spent $563.5 million, or 33 percent, of its 2013 capital development program on its Viewfield Bakken light oil resource property. The continued success of Crescent Point’s development program in the Bakken play has resulted in the expansion of the Viewfield gas facility from 30 MMcf/d to 42 MMcf/d, which is expected to be completed in early 2014, and will have the potential to be expanded an additional 12 MMcf/d when required in the future. In Viewfield, the Corporation now has the ability to ship more than 45,000 bbl/d by rail representing more than 35 percent of the Corporation's yearly average production guidance for 2014.
  In 2013, the Corporation’s independent engineering evaluator completed a classic reservoir study on select existing waterflood patterns with sufficient history for analysis, and has found ultimate long-term recovery factors up to 30 percent maybe achievable in those areas. At December 31, 2013, the Corporation had converted a total of 66 producing wells to water injection wells in 29 waterflood sections in the Viewfield Bakken oil resource play. As more injection patterns are established, the waterflood is expected to add proven reserves, with the potential to also reduce our future overall corporate decline rate.
  Early in the third quarter of 2013, the Government of Saskatchewan provided technical approval for the first of four proposed units in the play. The Corporation is now in the process of finalizing the first Bakken unit and progress continues towards future unitization of the remaining three proposed units.
  In 2013, total Proved plus Probable reserves in the Viewfield Bakken resource play, excluding Flat Lake, grew from 206.5 MMboe to 221.4 MMboe, representing a 7 percent increase over year-end 2012. Technical and development Proved plus Probable reserve additions totalled 29.5 MMboe in 2013. Since acquiring the properties in early 2007, the Corporation has added approximately 205.8 MMboe of positive Proved plus Probable technical and development reserves in the Viewfield Bakken and Flat Lake resource plays through continual improvement of drilling and completion techniques, as well as successful step-out and infill drilling. Additionally in the Viewfield Bakken, waterflood patterns were assigned an incremental 3% recovery factor from the previous primary recoverable reserve levels. This is a small portion of the future upside potential reflected in the independent waterflood evaluation noted above. The Corporation has 970 net locations booked to total Proved plus Probable reserves as of year-end 2013.
  Crescent Point expects to continue to spend significant capital in 2014 in the Viewfield Bakken resource play, as a part of its ongoing strategic development of the play. The Corporation's total capital budget for the area is approximately $580 million for 2014, including drilling approximately 230 gross (215 net) wells and investing approximately $80 million for land, seismic and facilities. As in prior years, this program is designed to expand and  diversify our facilities, expand waterflood development and develop our large drilling inventory.
  Shaunavon Resource Play
  In 2013, the Corporation continued to develop the medium gravity Upper and Lower Shaunavon oil resource plays through development and infill drilling, using improved technologies and waterflood activities to enhance recoveries. The Corporation is maintaining its focus on unitization activities in the area as a follow-up to the recently approved Leitchville North Shaunavon Voluntary Unit No. 1 and associated 2013 waterflood approval.
  - 28 -
  Crescent Point spent $347.3 million of its 2013 capital budget in the Shaunavon area. The Corporation has experienced significant success in the past year as a result of converting to cemented liner completions from the prior packer completion techniques for horizontal wells. In 2013, Crescent Point continued to infill drill the Upper and Lower Shaunavon to eight wells per section, which continue to produce at rates similar to rates observed at the original offsets when they were originally placed on production. The 2012 constructed Dollard rail-loading facility has been expanded from an initial 4,000 bbl/d capacity to 12,000 bbl/d. In addition, two large oil storage tanks are expected to be commissioned in the first quarter of 2014 for total storage of up to 120,000 bbl of marketable crude.
  In 2013, Crescent Point continued to focus on waterflood implementation by increasing the number of water injection wells in the play. By year-end 2013, the Corporation expanded its water injection well count in the Upper and Lower Shaunavon resource plays through both acquisitions and additional conversions to 42 active injection wells, including 20 horizontal injection wells. The Government of Saskatchewan approved the application for creation of the Leitchville North Shaunavon Voluntary Unit No. 1, representing a significant milestone in the Lower Shaunavon resource play development. The Government subsequently approved a proposal for waterflood implementation in the unit. Crescent Point plans to apply for unitization for the second development area, adjacent to the first unit, in the second quarter of 2014.
  As of year-end 2013, Crescent Point had booked total Proved plus Probable reserves of 153.4 MMboe in the Shaunavon area, an increase of 5 percent from 145.9 MMboe in 2012, including approximately 13.2 MMboe due to positive technical and development reserve additions in 2013. Since the original Shaunavon acquisition in 2009, the Corporation has added approximately 61 MMboe of positive total Proved plus Probable technical and development reserves. The Corporation has 783 net locations booked to Shaunavon total Proved plus Probable reserves as of year-end 2013.
  In 2014, Crescent Point expects to spend $422 million of its capital budget in the Shaunavon area. The Corporation expects to drill approximately 145 gross (142 net) wells primarily using the improved cemented liner completion technique, as well as invest more than $80 million on land, seismic and facilities. The facility capital includes the continued development and expansion of crude oil gathering systems and the upgrading of key crude oil batteries. These facility expenditures are expected to accommodate both current and future growth in production volumes. The Corporation plans to continue to expand the waterflood projects within the Lower and Upper Shaunavon zones during the year.
  Battrum and Cantuar Regional Area
  The Battrum and Cantuar regions represent the continued success and growth of Crescent Point’s mature assets producing out of the Roseray and Success Sands. The Corporation has recorded cumulative positive reserve revisions in both of these legacy areas since the original property acquisition in early 2006.
  In 2013, Crescent Point spent $18.1 million of its capital budget in the Battrum and Cantuar regions, primarily in existing units on drilling, facilities projects and production optimization projects.
  Since acquiring the Battrum property in 2006, the Corporation has increased total Proved plus Probable reserves in the three area units from 5.6 MMboe to a total of 17.6 MMboe at year-end 2013. During this same period, Crescent Point has had similar success in Cantuar increasing total Proved plus Probable reserves in the Cantuar unit from 9.7 MMboe to a total of 14.6 MMboe at year-end 2013.
  The Corporation plans to continue to focus on production optimization projects and infill drilling in 2014, with plans to drill up to 12 gross (5 net) oil wells in Battrum and 15 gross (8 net) oil wells in Cantuar.
  - 29 -
  UNITED STATES
  Utah Uinta Basin Resource Play
  In late 2012, through the acquisition of Ute, the Corporation became active in the Uinta Basin in northeast Utah, a multi-zone, large oil-in-place light oil resource play. The Corporation considers the Uinta Basin a largely untapped resource, with significant growth opportunities through improved step-out and development drilling, new completion techniques, enhanced recovery techniques as well as advancing marketing opportunities.
  The central Uinta Basin is the intersection between two main oil-bearing plays within the basin: Monument Butte and Altamont-Bluebell, which have been producing for more than 50 years. Exploration and development agreements ("EDAs"), entered into under the authority of the Indian Mineral Development Act of 1982 and approved by the Bureau of Indian Affairs within the Department of the Interior, with the Ute Indian Tribe of the Uintah and Ouray Reservation (the "Tribe") govern more than 150 net sections of land in the central basin, of which the majority is undeveloped. The EDAs cover several core project areas including the Randlett, Horseshoe Bend, Rocky Point, Blacktail Ridge, North Monument Butte, Bridgeland and Lake Canyon properties. The EDAs create an operating interest in the Tribe’s minerals, requires payment of royalties and rentals to the Tribe and reserve the Tribe’s right to take royalty production in kind. The EDAs granted Crescent Point an interest in real property, which represents a recordable interest in real estate under Utah law. The lands governed by these EDAs were released for development less than 10 years ago. The EDAs have an initial five-year term, with the majority of the EDAs being issued in the last five years, and all of the EDAs contain extension provisions related to meeting certain drilling commitments which provisions, if met, allow for two additional five-year terms that have the potential to provide the Corporation with up to an initial 15-year term to develop the assets.
  In 2013, Crescent Point spent $235.3 million of its capital budget in the area, including the first application of horizontal drilling for the Corporation in the area. Development activities also included the installation of gas gathering facilities and the completion of a rail facility in December, which opened up additional markets for light crude oil produced in the Uinta Basin.
  The Corporation is utilizing successful completion techniques from both the US and Canada to improve well performance in the Uinta Basin. Future plans include additional horizontal well tests and pilot testing the reservoir potential for application of waterflood technology in the stacked pay zone.
  Since the acquisition, the total Proved plus Probable reserves in the Uinta Basin have grown 27 percent from 55.1 MMboe to 70.0 MMboe in thirteen months of ownership. Technical and development Proved plus Probable reserve additions totalled 16.5 MMboe in 2013. The Corporation increased the number of total Proved plus Probable net reserve locations at December 31, 2013 to 333 from 274 at December 31, 2012.
  In 2014, Crescent Point plans to spend approximately $172 million in the area, with $127 million allocated to drilling and completion operations throughout the basin. A total of 106 gross (53 net) wells are expected to be drilled in 2014.
  North Dakota
  The Bakken light oil resource play in North Dakota is one of the fastest growth areas for production anywhere in North America. In 2013, Crescent Point spent $138.5 million of its capital budget in the area, including drilling in the Bakken and Three Forks zones.
  In 2013, the Corporation focused on the implementation of drilling and completion techniques developed in the Corporation’s Viewfield Bakken resource play to the Corporation’s North Dakota assets, as well as reducing costs in the area.
  At year-end 2013 total Proved plus Probable reserves increased to 33.4 MMboe from 23.5 MMboe at year-end 2012, representing a 42 percent increase over year-end 2012. Technical and development Proved plus Probable reserve additions totalled 12.2 MMboe in 2013. The Corporation increased the number of total Proved plus Probable net reserve locations at December 31, 2013 to 56 from 43 at December 31, 2012.
  - 30 -
  In 2014, Crescent Point plans to spend approximately $24 million, including approximately $8 million for land to hold and expand its current operated position in Williams County.  The Corporation expects to drill 12 gross (2 net) wells in North Dakota in 2014.
  Oil and Gas Wells
  Producing WellsArea

Oil
GasGross
Net
Gross
NetCANADASoutheast Saskatchewan and  Manitoba
4,456
2,581
-
-Southwest Saskatchewan
1,407
1,060
488
240Alberta and West Central Saskatchewan
882
632
350
241TOTAL CANADA
6,745
4,273
838
481U.S.North Dakota and Montana
194
50
5
4Utah
711
331
7
2TOTAL U.S.
905
381
12
6Total
7,650
4,654
850
487
 
 
 Non-Producing WellsArea

Oil
GasGross
Net
Gross
NetCANADASoutheast Saskatchewan and  Manitoba
83
65
-
-Southwest Saskatchewan
48
44
1
1Alberta and West Central Saskatchewan
20
17
1
1TOTAL CANADA
151
126
2
2U.S.North Dakota and Montana
2
-
-
-Utah
2
1
-
-TOTAL U.S.
4
1
-
-Total
155
127
2
2
 
  All of the Corporation's oil and gas wells are onshore.
  Properties With No Attributed Reserves
  The following table summarizes the gross and net acres of unproved properties in which we have an interest and also the number of net acres for which our rights to develop or exploit will, absent further action, expire within one year.
  As of December 31, 2013Gross Acres
Net Acres
Net Acres Expiring

Within One YearCANADAAlberta
642,655
461,960
116,275Saskatchewan
1,313,099
1,193,402
236,870Manitoba
179,425
175,809
30,529Total
2,135,179
1,831,171
383,674U.S.Montana
231,067
177,615
10,944North Dakota
82,801
63,542
12,409Utah
306,904
121,775
12,524Total
620,772
362,932
35,877Total
2,755,951
2,194,103
419,551
 
 The Corporation has no drilling commitments relating to unproved properties.
  - 31 -
  Drilling Activity
  The following table summarizes the gross and net exploration and development wells in which we participated during the year ended December 31, 2013, in each of Canada and the United States.
  Development Wells
Exploration Wells
Total WellsGross
Net
Gross
Net
Gross
NetCANADAOil wells
467
391.4
82
70.2
549
461.6Natural Gas wells
-
-
-
-
-
-Service wells
4
3.1
-
-
4
3.1Stratigraphic test
1
1.0
-
-
1
1.0Dry Holes
1
1.0
-
-
1
1.0Total
473
396.5
82
70.2
555
466.7
 
 Development Wells
Exploration Wells
Total WellsGross
Net
Gross
Net
Gross
NetU.S.Oil wells
141
54.5
41
28.3
182
82.8Natural Gas wells
-
-
-
-
-
-Service wells
-
-
-
-
-
-Stratigraphic test
-
-
-
-
-
-Dry Holes
-
-
-
-
-
-Total
141
54.5
41
28.3
182
82.8
 
 For details on the most important current and likely exploration and development activities during 2013, see "Statement Of Reserves Data And Other Oil And Gas Information – Major Oil and Gas Properties".
  The Corporation's work commitments for its proved properties (including drilling commitments) and timing are as follows:
  ($000's)Total
2014
2015
2016Canada
-
-
-
-U.S.
-
-
-
-TOTAL
-
-
-
-
 
 Additional Information Concerning Abandonment and Reclamation Costs
  We estimate well abandonment costs area by area. Such costs are assigned to the reserve wells in the Crescent Point Reserve Report and are included as deductions in arriving at future net revenue. The expected total abandonment costs included in the Corporation's Engineering Report for an estimated 7,377 net wells under the Proved reserves category is $337.8 million undiscounted ($74.4 million discounted at 10%), of which a total of $11.4 million is estimated to be incurred in 2014, 2015 and 2016.
  Tax Horizon
  Crescent Point has tax pools of approximately $8.4 billion at December 31, 2013 to shelter future taxable income. Including the impact of income from the Partnership for the year ended December 31, 2013, the net tax pools remaining are approximately $7.9 billion. Based on this pool balance and the forecast of cash flows using approximately US$100.00 WTI in 2014, approximately US$102.00 in 2015, a 0.90 US$/Cdn$ exchange rate and 2% inflation, with a 2014 development capital budget of $1.75 billion, Crescent Point does not expect to be taxable until 2015.
  - 32 -
  Costs Incurred(1)
  The following table summarizes our property acquisition costs, exploration costs and development costs for the year ended December 31, 2013. The total capital costs were approximately $1.8 billion in 2013.
  ($000's)
Acquisition CostsProved Properties
Unproved Properties
Exploration Costs
Development CostsCanada
117,319
6,271
180,041
1,160,324U.S.
(3,659)
(1,664)
73,561
310,581Total
113,660
4,607
253,602
1,470,905
 Note:
 (1)           Costs incurred exclude capitalized administration.
 
 Production Estimates
  The following table discloses for each product type the gross volume of production estimated by GLJ and Sproule for 2014 in the estimates of future net revenue with forecast pricing from Proved reserves disclosed above under the heading "Reserves Data - Forecast Prices and Costs".
  Region
Light and Medium

Crude Oil
Heavy Crude Oil
Natural Gas
NGLs
Total(bbl/d)
(bbl/d)
(Mcf/d)
(bbl/d)
(boe/d)CANADASoutheast Saskatchewan and  Manitoba
67,272
-
30,759
5,192
77,590Southwest Saskatchewan
27,422
-
7,147
134
28,746Alberta and West Central Saskatchewan
8,018
341
23,610
411
12,705Total CANADA(1)
102,710
341
61,515
5,738
119,041U.S.North Dakota and Montana
3,651
-
2,150
390
4,400Utah
8,904
-
8,218
369
10,643Total U.S.(1)
12,555
-
10,368
760
15,043Total(1)
115,266
341
71,883
6,498
134,085
 Note:
 (1)           Numbers may not add due to rounding.
 
 Production in southeast Saskatchewan/Manitoba and southwest Saskatchewan accounts for 58% and 21%, respectively, of the Corporation's Proved production estimate in 2014.
  The following table discloses for each product type the gross volume of production estimated by GLJ and Sproule for 2014 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
Natural Gas
NGLs
Total(bbl/d)
(bbl/d)
(Mcf/d)
(bbl/d)
(boe/d)CANADASoutheast Saskatchewan and Manitoba
77,659
-
35,485
6,003
89,576Southwest Saskatchewan
32,251
-
8,626
160
33,849Alberta and West Central Saskatchewan
9,332
358
25,520
460
14,402Total CANADA(1)
119,241
358
69,632
6,623
137,826U.S.North Dakota and Montana
4,318
-
2,543
467
5,209Utah
10,489
-
9,119
412
12,421Total U.S.(1)
14,807
-
11,661
880
17,630Total(1)
134,048
358
81,293
7,502
155,456
 Note:
 (1)           Numbers may not add due to rounding
  Production in southeast Saskatchewan/Manitoba and southwest Saskatchewan accounts for 58% and 22%, respectively, of the Corporation's total Proved plus Probable production estimate in 2014.
  - 33 -
  Production History
  The following table discloses, on a quarterly and annual basis for the year ended December 31, 2013, our share of average daily production volume (prior to deducting royalties), and the prices received, royalties, production costs and transportation costs incurred and netbacks on a per unit of volume basis for each product type.
  Average Daily Production Volume(1)
  Three Months Ended
Year EndedMarch 31, 2013
June 30, 2013
Sept. 30, 2013
Dec. 31, 2013
2013CANADALight and Medium Crude Oil (bbl/d)
89,291
87,238
85,389
96,218
89,542Heavy Crude Oil(bbl/d)
575
490
453
464
495NGLs (bbl/d)
4,777
5,261
5,237
5,014
5,073Natural gas (Mcf/d)
59,135
57,728
53,659
55,874
56,582Total (boe/d)
104,499
102,610
100,022
111,008
104,540U.S.Light and Medium Crude Oil (bbl/d)
11,672
13,082
15,508
13,314
13,404Heavy Crude Oil(bbl/d)
-
-
-
-
-NGLs (bbl/d)
204
538
745
961
615Natural gas (Mcf/d)
7,730
9,414
10,126
14,143
10,370Total (boe/d)
13,164
15,189
17,941
16,632
15,747TOTALLight and Medium Crude Oil (bbl/d)
100,962
100,320
100,896
109,532
102,946Heavy Crude Oil(bbl/d)
575
490
453
464
495NGLs (bbl/d)
4,982
5,799
5,983
5,975
5,688Natural gas (Mcf/d)
66,865
67,142
63,785
70,017
66,952Total (boe/d)
117,663
117,799
117,963
127,641
120,288
 Note:
 (1)           Numbers may not add due to rounding.
   Prices Received, Royalties, Production Costs and Transportation Costs Incurred – Light and Medium Crude Oil
  Three Months Ended
Year Ended($ per bbl)
March 31, 2013
June 30, 2013
Sept. 30, 2013
Dec. 31, 2013
2013CANADAPrices Received – net of hedging
81.15
86.44
95.08
81.51
85.88Royalties
(15.09)
(13.76)
(19.59)
(14.82)
(15.78)Production Costs
(13.08)
(13.04)
(12.45)
(10.65)
(12.26)Transportation Costs
(2.18)
(2.44)
(2.58)
(2.29)
(2.37)Netback
50.80
57.20
60.46
53.75
55.47U.S.Prices Received – net of hedging
84.36
84.16
92.15
84.72
86.67Royalties
(22.40)
(22.42)
(22.24)
(21.04)
(22.02)Production Costs
(12.91)
(14.33)
(13.00)
(16.50)
(14.18)Transportation Costs
(1.71)
(1.32)
(0.59)
(0.72)
(1.04)Netback
47.34
46.09
56.32
46.46
49.43TOTALPrices Received – net of hedging
81.52
86.14
94.63
81.90
85.98Royalties
(15.93)
(14.89)
(20.00)
(15.58)
(16.59)Production Costs
(13.06)
(13.21)
(12.54)
(11.36)
(12.51)Transportation Costs
(2.12)
(2.30)
(2.27)
(2.10)
(2.20)Netback
50.41
55.74
59.82
52.86
54.68
  - 34 -
  Prices Received, Royalties, Production Costs and Transportation Costs Incurred – Heavy Crude Oil
  Three Months Ended
Year Ended($ per bbl)
March 31, 2013
June 30, 2013
Sept. 30, 2013
Dec. 31, 2013
2013CANADAPrices Received – net of hedging
58.93
72.09
79.66
71.83
70.02Royalties
(8.21)
(16.86)
(14.49)
(14.43)
(13.26)Production Costs
(9.50)
(10.87)
(10.43)
(9.39)
(10.03)Transportation Costs
(1.58)
(2.04)
(2.16)
(2.02)
(1.93)Netback
39.64
42.32
52.58
45.99
44.80U.S.Prices Received – net of hedging
-
-
-
-
-Royalties
-
-
-
-
-Production Costs
-
-
-
-
-Transportation Costs
-
-
-
-
-Netback
-
-
-
-
-TOTALPrices Received – net of hedging
58.93
72.09
79.66
71.83
70.02Royalties
(8.21)
(16.86)
(14.49)
(14.43)
(13.26)Production Costs
(9.50)
(10.87)
(10.43)
(9.39)
(10.03)Transportation Costs
(1.58)
(2.04)
(2.16)
(2.02)
(1.93)Netback
39.64
42.32
52.58
45.99
44.80
  Prices Received, Royalties, Production Costs and Transportation Costs Incurred – NGLs
  Three Months Ended
Year Ended($ per bbl)
March 31, 2013
June 30, 2013
Sept. 30, 2013
Dec. 31, 2013
2013CANADAPrices Received
46.91
43.18
51.47
53.89
48.87Royalties
(3.57)
(3.34)
(4.74)
(4.23)
(3.98)Production Costs
(7.56)
(6.51)
(6.74)
(7.04)
(6.95)Transportation Costs
(1.26)
(1.22)
(1.40)
(1.51)
(1.35)Netback
34.52
32.11
38.59
41.11
36.59U.S.Prices Received
51.74
48.04
46.63
40.57
44.96Royalties
(10.43)
(12.50)
(10.61)
(8.02)
(9.99)Production Costs
(7.92)
(8.18)
(6.58)
(7.90)
(7.56)Transportation Costs
(1.05)
(0.75)
(0.30)
(0.34)
(0.48)Netback
32.34
26.61
29.14
24.31
26.93TOTALPrices Received
47.10
43.64
50.87
51.74
48.45Royalties
(3.85)
(4.19)
(5.47)
(4.84)
(4.63)Production Costs
(7.58)
(6.67)
(6.72)
(7.18)
(7.01)Transportation Costs
(1.25)
(1.18)
(1.26)
(1.33)
(1.25)Netback
34.42
31.60
37.42
38.39
35.56
  - 35 -
  Prices Received, Royalties, Production Costs and Transportation Costs Incurred – Natural Gas
  Three Months Ended
Year Ended($ per Mcf)
March 31, 2013
June 30, 2013
Sept. 30, 2013
Dec. 31, 2013
2013CANADAPrices Received - net of hedging
3.73
3.91
3.15
4.10
3.73Royalties
(0.28)
(0.18)
(0.21)
(0.42)
(0.27)Production Costs
(0.93)
(0.87)
(0.71)
(0.82)
(0.83)Transportation Costs
(0.25)
(0.33)
(0.23)
(0.27)
(0.27)Netback
2.27
2.53
2.00
2.59
2.36U.S.Prices Received - net of hedging
3.61
4.23
3.76
3.80
3.85Royalties
(0.82)
(1.24)
(0.59)
(0.83)
(0.86)Production Costs
(0.47)
0.16
0.83
(1.48)
(0.36)Transportation Costs
(0.31)
(1.08)
(1.39)
(1.45)
(1.14)Netback
2.01
2.07
2.61
0.04
1.49TOTALPrices Received - net of hedging
3.72
3.95
3.24
4.04
3.74Royalties
(0.34)
(0.33)
(0.27)
(0.50)
(0.36)Production Costs
(0.88)
(0.73)
(0.46)
(0.95)
(0.76)Transportation Costs
(0.25)
(0.43)
(0.42)
(0.51)
(0.41)Netback
2.25
2.46
2.09
2.08
2.21
  Production Volume by Field
  The following table discloses for each important field, and in total, our production volumes for the year ended December 31, 2013 for each product type.
  Region
Light and Medium

Crude Oil
Heavy Crude Oil
NGLs
Natural Gas
Total(bbl/d)
(bbl/d)
(bbl/d)
(Mcf/d)
(boe/d)CANADASoutheast Saskatchewan & Manitoba
58,312
-
4,400
26,831
67,184Southwest Saskatchewan
23,555
176
118
7,047
25,024Alberta and West Central Saskatchewan
7,675
319
555
22,704
12,333Total CANADA(1)
89,542
495
5,073
56,582
104,540U.S.North Dakota & Montana
4,929
-
199
1,752
5,420Utah
8,475
-
416
8,618
10,327Total U.S.(1)
13,404
-
615
10,370
15,747Total(1)
102,946
495
5,688
66,952
120,288
 Note:
 (1)           Numbers may not add due to rounding
  ADDITIONAL INFORMATION RESPECTING CRESCENT POINT
  Directors and Officers
  Crescent Point has a board of directors currently consisting of six individuals. The directors are elected by the Corporation, at the direction of Shareholders by ordinary resolution, and hold office until the next annual meeting of the Corporation, which will be held on May 9, 2014.
  - 36 -
  The name, municipality of residence and principal occupation during the last five years of each of the directors and executive officers of the Corporation are as follows:
  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
2003Gregory T. Tisdale

Cochrane, Alberta
Chief Financial Officer
Not applicableC. Neil Smith

Calgary, Alberta
Chief Operating Officer
Not applicableBrad Borggard

Calgary, Alberta
Vice President, Corporate Planning
Not applicableDerek Christie

Calgary, Alberta
Vice President, Exploration & Geosciences
Not applicableRyan Gritzfeldt

Calgary, Alberta
Vice President, Engineering East
Not applicableKenneth R. Lamont

Calgary, Alberta
Vice President, Finance and Treasurer
Not applicableTamara MacDonald

Calgary, Alberta
Vice President, Land
Not applicableTrent Stangl

Calgary, Alberta
Vice President, Marketing and Investor Relations
Not applicableSteven Toews

Calgary, Alberta
Vice President, Engineering West
Not applicableMark G. Eade

Calgary, Alberta
Corporate Secretary
Not applicablePeter Bannister (1), (3),(4)

Calgary, Alberta
Director and Chairman
2003D. Hugh Gillard (1), (2), (5)

Calgary, Alberta
Director
2003Gregory G. Turnbull (2), (5)

Calgary, Alberta
Director
2001Kenney F. Cugnet (3), (4), (5)

Weyburn, Saskatchewan
Director
2003Gerald A. Romanzin (1), (2), (3)

Calgary, Alberta
Director
2004
 Notes:
 (1)           Member of the Audit Committee.
 (2)           Member of the Compensation Committee.
 (3)           Member of the Reserves Committee.
 (4)           Member of the Health, Safety and Environment Committee.
 (5)           Member of Corporate Governance and Nominating Committee.
  As at March 11, 2014, the directors and executive officers as a group beneficially owned, directly or indirectly, or exercised control or direction over 4,074,792 Common Shares, representing approximately 1.0% of the issued and outstanding Common Shares. Including restricted shares, ownership increased to 1.4% on a fully diluted basis.
  - 37 -
  Scott Saxberg, President, Chief Executive Officer and Director
  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.
  Mr. Saxberg is a member of the Association of Professional Engineers and Geoscientists of Alberta ("APEGA") and serves on the board of directors of Aston Hill Energy 2010 GP Inc. Mr. Saxberg also served on the board of directors of Bellamont Exploration Ltd., Catapult Energy 2008 Inc. and Wild Stream until the Wild Stream Arrangement was completed. He also serves on the Canadian Associations of Petroleum Producers ("CAPP") board of governors and on the CAPP Saskatchewan Executive Policy Group. Mr. Saxberg holds a Bachelor of Science degree in mechanical engineering from the University of Manitoba.
  Greg Tisdale, Chief Financial Officer
  Greg Tisdale is the Chief Financial Officer of Crescent Point, a role he has held with Crescent Point since 2004. He has worked in the oil and gas industry since 1995, having held a variety of roles with companies such as Direct Energy Marketing Ltd., AltaGas Services Inc., Shell Trading Gas and Power Canada Ltd. and Engage Energy Inc.
  Mr. Tisdale serves on the board of directors of Enseco Energy Services Corp. and Cardinal Energy Ltd, and served on the Board of Shelter Bay until 2010. He also serves on the board of trustees for the Alberta Cancer Foundation. He is a Chartered Accountant, a member of the Institute of Chartered Accountants of Alberta and a member of the Institute of Corporate Directors. Mr. Tisdale holds a Bachelor of Commerce degree (with distinction) from the University of Alberta.
  C. Neil Smith, Chief Operating Officer
  C. Neil Smith is the Chief Operating Officer of Crescent Point, a role he has held with Crescent Point since March 13, 2013. Prior to that, he was Vice President, Engineering and Business Development for Crescent Point. He has been with Crescent Point since 2003 and has worked in the oil and gas industry since 1986, having held a variety of roles with companies including President of Shelter Bay and engineering positions with Amoco Canada Petroleum Ltd. and Coles Gilbert Associates Ltd., the predecessor to Gilbert Laustsen Jung Associates Ltd.
  Mr. Smith is a member of the APEGA. He is Chair of the Explorers and Producers Association of Canada and a director of the Petroleum Acquisition and Disposition Association. Mr. Smith holds a Bachelor of Science degree in geological engineering from the University of British Columbia and a Master of Business Administration (Dean's List) from the University of Calgary.
  Brad Borggard, Vice President, Corporate Planning
  Brad Borggard is the Vice President, Corporate Planning of Crescent Point, a role he has held since January 2010. Prior to joining Crescent Point, Mr. Borggard was Managing Director, Institutional Equity Research at CIBC World Markets from 2004 until 2009. During that time, he was ranked as the top Canadian Royalty Trust analyst four times and the top Canadian E&P analyst twice.
  Mr. Borggard has worked in other oil and gas related roles, with companies such as Scotia Capital Inc. and Gulf Canada Resources Ltd. He holds a Bachelor of Commerce degree (with honours) in finance from the University of Calgary, as well as a Chartered Financial Analyst designation.
  Derek Christie, Vice President, Exploration & Geosciences
  Derek Christie is the Vice President, Exploration & Geosciences of Crescent Point, a role he has held with Crescent Point since November 2013. Prior to that, he was the Vice President, Geosciences for Crescent Point. He has been with Crescent Point since 2007 and has worked in the oil and gas industry since 1991, having held a variety of roles with companies such as Shelter Bay, Mission Oil and Gas Inc., StarPoint Energy Ltd., Vintage Petroleum Canada Inc. and Rio Alto Exploration Ltd.
  - 38 -
  Mr. Christie is a member of APEGA and holds a Bachelor of Science degree in Geology from the University of Calgary.
  Ryan Gritzfeldt, Vice President, Engineering East
  Ryan Gritzfeldt is the Vice President, Engineering East of Crescent Point, a role he has held since January 2010. Prior to that, he was Engineering Manager, Southeast Saskatchewan for Crescent Point, a role he held from 2006 until 2009. Mr. Gritzfeldt has worked in the oil and gas industry since 1998, having held a variety of roles with companies such as Shelter Bay and Talisman Energy Inc.
  Mr. Gritzfeldt is a member of APEGA. He holds a Bachelor of Applied Science degree in industrial systems engineering from the University of Regina.
  Ken Lamont, Vice President, Finance and Treasurer
  Ken Lamont is the Vice President, Finance and Treasurer of Crescent Point, a role he has held since January 2010. Prior to that, he was Controller and Treasurer for Crescent Point, a role he held from 2005 until 2009. Mr. Lamont has worked in the oil and gas industry since 2001, having held a variety of roles with companies such as Shelter Bay, Direct Energy Marketing Ltd. and Shell Trading Gas and Power Canada Ltd. Prior to 2001, he was a senior manager at PricewaterhouseCoopers LLP.
  Mr. Lamont holds a Bachelor of Commerce degree (with distinction) from the University of Alberta and is a Chartered Accountant, as well as a member of the Institute of Chartered Accountants of Alberta.
  Tamara MacDonald, Vice President, Land
  Tamara MacDonald is the Vice President, Land of Crescent Point, a role she has held with Crescent Point since 2004. She has worked in the oil and gas industry since 1992, having held a variety of roles with companies such as Shelter Bay, Petrofund Energy Trust, Merit Energy Ltd., Tarragon Oil and Gas Ltd. and Northstar Energy Corp.
  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 Women of Influence. She holds a Bachelor of Commerce degree, with a major in petroleum land management, from the University of Calgary.
  Trent Stangl, Vice President, Marketing & Investor Relations
  Trent Stangl is the Vice President, Marketing and Investor Relations of Crescent Point, a role he has held since 2008. Prior to that, he was Manager, Marketing and Investor Relations for Crescent Point, a role he held from 2006 until 2008. Mr. Stangl has worked in the oil and gas industry since 1991, having held a variety of roles with companies such as three dimes inc. and Wascana Energy Inc.
  Mr. Stangl is a member of the Canadian Investor Relations Institute and the CAPP Markets and Transportation Executive Policy Group. He holds a Bachelor of Arts degree (with honours) in economics from the University of Saskatchewan and a Master of Arts degree in economics from the University of Western Ontario.
  Steven Toews, Vice President, Engineering West
  Steven Toews is the Vice President, Engineering West of Crescent Point, a role he has held since January 2010. Prior to that, he was Engineering Manager for Crescent Point, a role he held from 2005 until 2009. Mr. Toews has worked in the oil and gas industry since 1989, including a number of years spent working internationally, with companies such as EnCana Corp., Talisman Energy Inc., International Colin Energy Corp. and Norcen Energy Resources Ltd.
  - 39 -
  Mr. Toews is a member of APEGA and holds a Bachelor of Science degree in mechanical engineering from the University of Saskatchewan.
  Mark Eade, Corporate Secretary
  Mark Eade is Corporate Secretary for Crescent Point and was appointed in 2004. He has been a partner with Norton Rose Fulbright Canada LLP (or its predecessor) since August 2011 and prior thereto was a partner at McCarthy Tétrault LLP. Mr. Eade practices in the area of corporate and securities law.
  Mr. Eade holds a Bachelor of Commerce degree (with distinction) from the University of Saskatchewan and was called to the Alberta bar in 1994. He is a member of the Law Society of Alberta and the Canadian Bar Association.
  Peter Bannister, Director and Chairman
  Peter Bannister is Chairman of Crescent Point's board of directors and is president of Destiny Energy Inc., a private oil and gas company. He has been on the board of Crescent Point and its predecessor since 2003. Mr. Bannister has worked in the oil and gas industry since 1982, having held a variety of roles with companies 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 board of directors of Cequence Energy Ltd. and New Star Energy Ltd. Formerly, he was a director of 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 Science degree in geology with a minor in economics.
  D. Hugh Gillard, Director
  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 of Crescent Point and its predecessor since 2003.
  Mr. Gillard has served as director of the board of Petrowest Energy Services Trust (chairman), 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 chairman of the board of Hospice Calgary and is currently a trustee of the Calgary Zoo. He holds a Bachelor of Commerce degree from the University of Calgary and is a graduate of the Stanford Business School Executive Program.
  Gregory G. Turnbull, QC, Director
  Greg Turnbull is a partner with McCarthy Tétrault LLP law firm in the Calgary office. He has worked as a lawyer since 1979, having held a variety of roles with firms such as Gowlings LLP, Donahue LLP and MacKimmie Matthews. He has been on the board of Crescent Point and its predecessor since 2001.
  Mr. Turnbull is also a director of Storm Resources Ltd., Heritage Oil plc, Hawk Exploration Ltd., Hyperion Exploration Corp., Porto Energy Corp., Sonde Resources Corp. and Sunshine Oilsands Ltd. Throughout his career, he has served as an officer or director of many public and private companies. Mr. Turnbull is a member of the Law Society of Alberta, the Canadian Bar Association and the Calgary Bar Association. He holds a Bachelor of Arts degree (with honours) from Queens University and a Bachelor of Law degree from the University of Toronto. He is also the past Chair of the Calgary Zoo.
  - 40 -
  Kenney F. Cugnet, Director
  Since 1963, Ken Cugnet has been the owner and operator of a farm in Weyburn, Saskatchewan, where he lives. He is the president of Valleyview Petroleum and Six Bits Resources Inc., both private oil and gas companies, and has worked in the oil and gas industry since 1962. He has been on the board of Crescent Point and its predecessor since 2003.
  Mr. Cugnet also serves as a director of Elkhorn Resources Inc. Formerly, he served as director of Tappit Resources Ltd., Starpoint Energy Inc., Mission Oil and Gas Inc., Medora Resources Inc. and Cypress Petroleum Corp. Also, from 1987 to 1992, Mr. Cugnet was a member of the Saskatchewan Surface Rights Arbitration Board.
  Gerald A. Romanzin
  Gerald Romanzin is an independent Calgary businessman who serves as a director of Petrowest Corporation, Porto Energy Corp. and of Trimac Transportation Ltd. 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 of Crescent Point and its predecessor since 2004.
  Formerly, Mr. Romanzin served as a director of FET Resources Ltd., Ketch Resources Ltd., Ketch Resources Trust, Cadence Energy Inc., Kereco Energy Ltd. and Flowing Energy Corporation. Mr. Romanzin is a Chartered Accountant and he is a member of the Institute of Chartered Accountants of Alberta and holds a Bachelor of Commerce degree from the University of Calgary.
  Bankruptcies and Cease Trade Orders
  Other than as described below, no director, executive officer or shareholder holding a sufficient number of securities to affect materially the control of the Corporation is, as of the date of this AIF, or has been, within the last 10 years, been a director or executive officer of any company (including the Corporation) that, while such person was acting in that capacity, was the subject of a cease trade or similar order or an order that denied the company access to any statutory exemption for a period of more than 30 consecutive days or was declared a bankrupt or made a voluntary assignment in bankruptcy, made a proposal under any legislation relating to bankruptcy or been subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver-manager or trustee appointed to hold the assets of that person.
  D. Hugh Gillard
  Mr. Gillard was a director of Point North Energy Ltd. ("Point North") from November 2, 2005 until November 22, 2006. In September 2006, Point North filed for, and the Court of Queen's Bench of Alberta granted an initial order to Point North for, creditor protection under the Companies' Creditors Arrangement Act due to circumstances arising from events that occurred prior to Mr. Gillard being appointed to the Point North board of directors. In September 2007, a successful plan of arrangement was approved by the creditor of Point North and as a result, Point North emerged fromCompanies' Creditors Arrangement Act protection.
  Gregory G. Turnbull
  Mr. Turnbull was a director of Action Energy Inc., a corporation engaged in the exploration, development and production of oil and gas in Western Canada. Action Energy Inc. was placed into receivership on October 28, 2009 by its major creditor and Mr. Turnbull resigned as a director immediately thereafter.
  Penalties or Sanctions
  No director, executive officer or shareholder holding a sufficient number of securities to affect materially the control of the Corporation, within the last 10 years, has been subject to any penalties or sanctions imposed by a court or securities regulatory authority relating to trading in securities, promotion or management of a publicly traded issuer or theft or fraud.
  - 41 -
  Personal Bankruptcies
  No director, executive officer or shareholder holding a sufficient number of securities to affect materially the control of the Corporation, or a personal holding company of any such persons, has, within the 10 years preceding the date of this AIF, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or being subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of the individual.
  Share Capital
  The Corporation is authorized to issue an unlimited number of Common Shares.
  Common Shares
  Each Common Share entitles its holder to receive notice of and to attend all meetings of the Shareholders of the Corporation and to one vote at such meetings. The holders of Common Shares are, at the discretion of the board of directors of the Corporation and subject to applicable legal restrictions, entitled to receive any dividends declared by the board of directors. The holders of Common Shares are entitled to share equally in any distribution of the assets of the Corporation upon the liquidation, dissolution, bankruptcy or winding up of the Corporation or other distribution of its assets among its Shareholders for the purpose of winding up its affairs. Such participation is subject to the rights, privileges, restrictions and conditions attaching to any other shares having priority over the Common Shares.
  Premium DividendTM and Dividend Reinvestment Plan
  Under the Corporation's DRIP, eligible Shareholders may, at their option, reinvest their cash dividends to purchase additional Common Shares at 95% of the average market price (as defined in the DRIP) of a Common Share on the applicable distribution date. The DRIP also provides an alternative where eligible Shareholders may elect, under the premium dividend component, to receive a premium cash distribution equal to 102% of the reinvested cash dividends that such Shareholders would have otherwise been entitled to receive on the applicable dividend date. Generally, no commissions, service charges or brokerage fees will be payable by Shareholders who participate in the DRIP. We have reserved the right to determine how much new equity is available under the Plan on any particular distribution date. Accordingly, participation in the DRIP may be pro-rated in certain circumstances.
  Registered and beneficial owners of Common Shares who are not resident in Canada are not eligible to participate in the DRIP.
  The DRIP has been in effect since 2010 and remains in effect. However, on October 15, 2013 the Corporation announced the suspension of the premium component of the DRIP effective with the October 2013 dividend, which was paid on November 15, 2013. Effective with the suspension, Shareholders previously enrolled in the premium component of the DRIP began to receive the regular cash dividend amount of $0.23 per share without the 2 percent premium. Shareholders that were enrolled in the premium component of the DRIP when the plan was suspended will remain enrolled at reinstatement and will automatically resume participation in the premium component if, and when, such component is reinstated. The dividend reinvestment portion of the plan remains in effect.
  Restricted Share Bonus Plan
  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, 2013, the Corporation is authorized to issue up to 5,728,512 Common Shares, of which the Corporation had 2,588,143 restricted shares outstanding at December 31, 2013.
  - 42 -
  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.
  DSU Plan
  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.
  Participants that are Directors must elect to receive Units in lieu of a cash retainer prior to the year in which the retainer will be earned, unless they are elected or appointed part way through a year, in which case they must elect within 30 days of being elected or appointed to receive Units for that year. Participants that are Designated Employees must elect to receive Units in lieu of all or a portion of their annual bonus entitlement or profit share for the year within 30 days after such Designated Employee has been notified by the Corporation of such individual's bonus entitlement or profit share for such year.
  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 trading 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.
  A Participant is not entitled to any payment of any amount in respect of Units until such Participant ceases to be an employee or director of the Corporation, as the case may be, for any reason whatsoever. Upon the Participant ceasing to be an employee or director of the Corporation, the Participant is entitled to receive a lump sum cash payment, net of applicable withholding taxes, equal to the product of (i) the number of Units in such Participant's account on the date the Participant ceased to be an employee or director and (ii) the five day weighted average trading price of the Common Shares on the TSX immediately prior to such date. The Corporation will make such lump sum cash payment by the end of the calendar year following the year in which the Participant ceased to be an employee or director.
  Credit Facilities
  The Corporation has a $2.0 billion extendible revolving loan facility with a permitted increase (subject to certain conditions) to $2.5 billion (the "Syndicated Credit Facility") and a $100 million extendible operating loan facility (the "Bi-Lateral Credit Facility"). 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 ("EBITDA") ratio. The Credit Facilities are guaranteed by certain material restricted subsidiaries currently being CPEUS, CPUSH, CPHI and the Partnership. The Credit Facilities are unsecured. 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 constitutes a revolving facility for a 364 day term which is extendible annually for a further 364 day revolving period, subject to a one year term out period should the lender not agree to an annual extension. The Syndicated Credit Facility constitutes a revolving credit facility for a three year term which is extendible annually. The Syndicated Credit Facility does not include a term-out feature. 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.
  - 43 -
  INDUSTRY CONDITIONS
  The oil and natural gas industry is subject to extensive controls and regulations imposed by various levels of government. It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and gas entities of similar size. All current legislation is a matter of public record, and we are unable to predict what additional legislation or amendments may be enacted.
  Pricing and Marketing – Oil
  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 2010, under the five-year re-determination, the FERC set an upward adjustment in the index and determined that the Producer Price Index for Finished Goods plus 2.65% should be the oil pricing index for the five-year period beginning July 1, 2011. 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. The United States Department of Commerce currently imposes export controls on domestically produced crude oil. A license is required for the export of crude oil to all destinations, including Canada. Only in limited circumstances will the Department of Commerce approve applications to export crude oil, consistent with the regulations of the Bureau of Industry and Security, the agency within the Department of Commerce which reviews such applications, and approval may require a presidential finding before the export can be authorized.
  Pricing and Marketing – Natural Gas
  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, etc. and, in Canada, may be obtained for a period that does not exceed 25 years. 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 m3/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.
  The North American Free Trade Agreement
  On January 1, 1994, the North American Free Trade Agreement ("NAFTA") among the governments of Canada, the U.S. and Mexico became effective. NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to restrict exports to the U.S. or Mexico provided that such export restrictions do not: (i) reduce the proportion of the energy resource exported relative to the total supply of that energy resource in Canada as compared to the proportion prevailing in the most recent 36-month period, (ii) impose an export price higher than the domestic price; and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements except in exceptional circumstances.
  NAFTA also requires the parties thereto to ensure that their respective energy regulators implement any energy regulatory measures in an orderly and equitable manner and in a manner which avoids disrupting contractual relationships to the maximum extent possible.
  Royalties and Incentives
  In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. In all Canadian jurisdictions where we operate, producers of oil and natural gas are required to pay annual rental payments in respect of Crown leases and royalties and freehold production taxes in respect of oil and natural gas produced from Crown and freehold lands, respectively. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.
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  From time to time, the governments of Canada, Alberta, British Columbia, Saskatchewan and Manitoba have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced planning projects. Such programs are generally introduced when commodity prices are low, and are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. These programs reduce the amount of Crown royalties otherwise payable.
  Alberta
  In terms of oil or natural gas production from Crown lands, royalties are payable to the Province of Alberta. On February 16, 2007, the Government of Alberta announced a review of the province's royalty and tax regime (including income tax and freehold mineral rights tax) pertaining to oil, natural gas and oil sands to be conducted by a panel of experts, with the assistance of individual Albertans and key stakeholders. The purpose of this process was to ensure that Albertans were receiving a fair share from energy development through royalties, taxes and fees.
  On October 25, 2007, the Government of Alberta unveiled a new royalty regime for determining Crown royalty rates in Alberta (the "Royalty Framework"), effective January 1, 2009. The Royalty Framework introduced new royalties applicable to all conventional oil and natural gas wells and bitumen production, with the exception of those subject to the transitional royalty rate discussed below.
  The Royalty Framework eliminated the previous tier system for conventional oil, which was based on the vintage or discovery date of the oil, and implemented a sliding rate formula based on both the commodity price of oil and well production. Subject to certain available incentives, effective from the January 2011 production month royalty rates for conventional oil production under the Royalty Framework range from a base rate of 0% to a cap of 40%. This represents an increase from the previous rate cap of 35% under the tier system, but a decrease from the rate cap of 50% under the Royalty Framework prior to January 2011. Actual royalty rates are determined on a monthly basis.
  The Royalty Framework also eliminated the previous tier system for natural gas, which was also based on the vintage or discovery date of the gas, and implemented a sliding rate formula based on both the commodity price of the gas and well production. This eliminated the option to use a corporate average reference price. The natural gas royalty formula also provides for a reduction based on the measured depth of the well below 2,000 metres (the "Depth Factor Adjustment"), as well as the acid gas content of the produced gas (the "Acid Gas Adjustment"). Subject to certain available incentives, effective from the January 2011 production month royalty rates for natural gas production under the Royalty Framework range from a base rate of 5% to a cap of 36%. This represents an increase from the previous rate cap of 35% under the tier system, but a decrease from the rate cap of 50% under the Royalty Framework prior to January 2011.
  Under the Royalty Framework, the royalty rate applicable to natural gas liquids is a flat rate of 40% for pentanes and 30% for butanes and propane.
  In terms of oil and natural gas production obtained from lands other than Crown lands, taxes are payable to the Province of Alberta. Approximately 19% of the mineral rights in the Province of Alberta are freehold mineral rights not owned by the Crown. The tax levied in respect of freehold oil and gas production in the Province of Alberta is calculated annually based on a rate dependent on the prescribed tax rate, the quantity of produced oil or gas, and the unit value of the produced oil or gas.
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  Transitional Incentive
  In late November 2008, the Alberta government announced details of an optional five-year transitional royalty program (the "Transitional Program") applicable to conventional oil and natural gas wells drilled to measured depths from 1,000 to 3,500 metres, with a spud date on or after November 19, 2008. For each eligible well, the producer could make a one-time election to produce the well under the Transitional Program royalty rates or the Royalty Framework rates. The Transitional Program royalty rates would only apply to production from January 1, 2009 until December 31, 2013. As of January 1, 2014, all production subject to the Transitional Programreverted to the Royalty Framework regime. Operators electing the Transitional Program rates are not eligible for the Depth Factor Adjustment or the Acid Gas Adjustment, which are specific to the Royalty Framework, but are otherwise not excluded from available incentive programs, subject to eligibility as discussed below. On March 11, 2010, the Government of Alberta announced that the Transitional Program would continue until its originally announced expiration, however, effective January 1, 2011, no new wells would be eligible for the selection of the Transitional Program royalty rates. Wells which had already opted for the Transitional Program royalty rates prior to January 1, 2011 had the option to continue under the Transitional Program royalty rates until the expiry of the Transitional Program, or to opt out of the Transitional Program by February 15, 2011 in favour of the Royalty Framework rates.
  Incentive Programs
  The Royalty Framework also eliminated some previously available incentives, and introduced certain revised or updated incentive programs.
  With respect to conventional oil, the Royalty Framework eliminated the Third Tier Exploratory Well Royalty Exemption, the Re-activated Well Royalty Reduction, the Low Productivity Well Royalty Reduction, the Horizontal Re-entry Well Royalty Program, and the Experimental Project Petroleum Royalty.
  With respect to natural gas, the Royalty Framework eliminated the Deep Gas Royalty Holiday and the Royalty Adjustment Program for Deep Marginal Gas Wells.
  Pursuant to the Royalty Framework, the Deep Oil Exploratory Well Program, the Enhanced Recovery of Oil Royalty Reduction Program ("EOR Program"), the Natural Gas Deep Drilling Program, and the Innovative Energy Technologies Program (the "IETP") were either created or retained.
  The Deep Oil Exploratory Well Regulation provides a limited royalty exemption for qualifying exploratory oil wells spudded or deepened between January 1, 2009 and December 31, 2013 that are deeper than 2,000 metres and have a producing interval below 2,000 metres. Existing oil wells approved under the discontinued Third Tier Exploratory Well Royalty Exemption and qualifying for the Deep Oil Exploratory Well Program were transitioned into the new program on January 1, 2009.
  With respect to the EOR Program, the Enhanced Recovery of Oil Royalty Reduction Regulation provides that Alberta Energy may approve royalty reductions for qualifying enhanced oil recovery projects.
  The Natural Gas Deep Drilling Regulation, 2010 provides a limited royalty reduction for qualifying exploratory and development natural gas wells spudded or deepened between May 1, 2010 and December 31, 2013 (inclusive), with producing intervals that are deeper than 2,000 metres.
  The IETP was originally intended to promote producers' investment in research, technology and innovation for the purposes of improving environmental performance while creating commercial value. This program had been retained under the Royalty Framework. The IETP provides royalty reductions to successful applicants. Alberta Energy determines which projects qualify for the IETP, as well as the level of support that will be provided.
  On March 3, 2009, the Government of Alberta announced an additional incentive program, the Drilling Royalty Credit (the "DRC"), in respect of conventional oil and gas wells drilled on Alberta Crown lands. On June 25, 2009, the Government of Alberta announced the extension of the DRC for one additional year, expiring on April 1, 2011. The Drilling Royalty Credit Regulation provided that for qualifying wells drilled for the purpose of extracting conventional oil or natural gas and with a spud date and finish drill date between April 1, 2009 and April 1, 2011, the operator would receive a royalty credit of $200 per metre drilled, up to a prescribed maximum percentage of the operator's royalties. The maximum percentage was determined on a sliding scale ranging from 10% to 50%, based on the operator's production, with a higher maximum percentage available to lower producing operators. The DRC was only available to companies that would be recognized as having royalty payment obligations pursuant to applicable regulation. Any DRC royalty credits not used prior to March 31, 2011 were forfeited.
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  On March 3, 2009, the Government of Alberta also announced the New Well Royalty Reduction (the "NWRR") incentive program. The New Well Royalty Reduction Regulation provided that the NWRR would be available to qualifying wells that commence or recommence producing conventional oil or natural gas between April 1, 2009 and April 30, 2010. Pursuant to the New Well Royalty Reduction Regulation, royalties on production from qualifying wells were reduced to a maximum royalty rate of 5% until the earlier of either 12 production months from the date of first production, the date that the production cap was met (for natural gas wells, 7,949 m3 of oil equivalent (500 MMcf of gas) and for conventional oil 7,949 m3 of oil or oil equivalent), the date the well becomes part of a Project under the Oil Sands Royalty Regulation, 2009, or March 31, 2012, whichever occurred first. On March 11, 2010, as part of a larger modification of royalty rates under the Royalty Framework, the Government of Alberta announced that the NWRR was to become a permanent feature of Alberta's royalty regime, and the New Well Royalty Regulation was enacted. Pursuant to the New Well Royalty Regulation, production from a qualifying well is calculated at royalty of 5% until either the end of the eligible production month cap of the well, the date that the volume cap is reached for that well or the date the well becomes part of a Project under the Oil Sands Royalty Regulation, 2009, whichever occurs first.
  In addition, on May 27, 2010 the Government of Alberta announced further initiatives to stimulate investment in emerging resources and technologies. In particular, the Horizontal Gas New Well Royalty Rate ("HGNWRR") reduces royalties on production from qualifying wells to a maximum royalty rate of 5% until the earlier of either 18 production months from date of first production or the date that the first 7,949 m3 of oil equivalent is produced. Finally, the Horizontal Oil New Well Royalty Rate ("HONWRR") reduces royalties on production from qualifying wells to a maximum royalty rate of 5% until the prescribed time or volume limit is met. The time and volume limits increase with the depth of metres drilled, from a minimum of 7,949 m3 of oil equivalent and 18 months for wells drilled to measured depths from 0 to 2,499 metres, to a maximum of 15,899 m3 of oil equivalent and 48 months for wells drilled to measured depths in excess of 4,500 metres. The NWRR applies retroactively to production produced on or after May 1, 2010. The HGNWRR and HONWRR apply retroactively to spud dates on or after May 1, 2010.
  Both the DRC and NWRR apply to wells under the Royalty Framework as well as those wells electing the Transitional Program rates. In relation to conventional oil wells eligible for both the NWRR and the Deep Oil Exploratory Well Program, the date constraints and volume limits under each program will run concurrently. In relation to natural gas wells eligible for both the NWRR and the NGDDP and any of the 5% royalty rates, including the HGNWRR, the Coal Bed Methane NWRR or the Shale Gas NWRR, the 5% royalty rate will be applied first, with the NGDDP benefits applied after the expiration of the 5% rate. However, the 60 calendar month benefit under the NGDDP begins on the well's finished drilling date, not with the expiry of the 5% royalty rate. In addition, the NWRR will reduce the royalty reduction that is available for wells under the EOR Program and the IETP.
  Saskatchewan
  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" (introduced October 1, 2002), "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 Energy and Resources ("SER"), the royalty reserved to the Crown ranges from 0% to 45%.
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  Similarly, the amount payable as a royalty in respect of natural gas in the Province of Saskatchewan depends on the vintage of the gas, the type of gas production, the quantity of gas produced in a month, and the price of the gas. For both Crown royalty and freehold production tax purposes, natural gas is categorized as either non-associated gas or associated gas, the former being produced from gas wells and the latter being produced from oil wells. Additionally, the gas is divided according to the royalty and production tax classifications as either "fourth tier gas" (introduced October 1, 2002), "third tier gas", "new gas", or "old gas". Depending on the categorization and classification of the natural gas, monthly production, and a reference price, the royalty reserved to the Crown ranges from 0% to 45%. Subject to certain restrictions, the operator may elect to use either a prescribed reference price determined monthly by SER, or a reference price based on the operator's average gas price in a month. As an incentive for the production and marketing of natural gas which may otherwise have been flared, the royalty rate on associated gas is less than on non-associated natural gas.
  Approximately one-fifth of the mineral rights in the Province of Saskatchewan are freehold mineral rights not owned by the Crown. With respect to production from freehold lands, the tax levied on oil and gas production in the Province of Saskatchewan will depend on the classification of the oil or gas and the relevant Crown royalty rate.
  On June 14, 2010 the SER released a letter outlining significant changes to the current administrative provisions under the government's Process Renewal and Infrastructure Management Enhancements ("PRIME") initiative. Among other changes, PRIME seeks to modernize Saskatchewan's well facility program, and to allow industry to electronically submit information and to access government services through a web-based self-serve application.
  Natural gas is generally bought and sold on an energy basis. To eliminate existing equity issues related to the current volumetric based royalty/tax calculation, the SER will be converting to an energy based calculation. Consequently, the price used to value natural gas production for royalty/tax purposes will be expressed in dollars per gigajoule. These new provisions were implemented in April, 2012.
  Incentives
  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%. Horizontal gas wells drilled between June 1, 2010 and March 31, 2013 inclusive are also classified as qualifying exploratory gas wells for royalty/tax purposes and 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 revenue 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 SER 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 a 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, depending on depth. The HWD is very similar to the VWD but, applies to non-exploratory horizontal wells 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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  In 1975, the Government of Saskatchewan introduced a Royalty Tax Rebate ("RTR") as a response to the federal government disallowing the deduction of crown royalties and similar taxes as a business expense for income tax purposes. As of January 1, 2007, the RTR was allowed to wind down as a result of the federal government's initiative to reintroduce the full deduction of crown royalties in computing income for federal and provincial income tax purposes in respect of taxation years commencing after 2006. Commencing January 1, 2007, the carry forward period for any outstanding RTR balance was limited to 7 years.
  Manitoba
  Provincial Crown Royalties and Freehold Production Tax
  Crown Royalties – Oil
  In Manitoba, the royalty amount payable on oil produced from Crown land depends on the classification of the oil produced. Production is divided into the following categories: (i) "old oil" (being oil produced from a well drilled prior to April 1, 1974 that does not qualify as new oil or third tier oil); (ii) "new oil" (being oil that is not third tier oil and is produced from a well drilled on or after April 1, 1974 and prior to April 1, 1999, from an abandoned well re-entered during that period, from an old oil well as a result of an enhanced recovery project implemented during that period, or from a horizontal well); (iii) "third tier oil" (being oil produced from a vertical well drilled after April 1, 1999, an abandoned well re-entered on or after that date, an inactive vertical well activated after that date, a marginal well that has undergone a major workover, or from an old oil well or a new oil well as a result of an enhanced recovery project implemented after that date); or (iv) "holiday oil" (being oil that is exempt from any royalty or tax payable).
  Royalty rates are calculated on a sliding scale and based on the monthly oil production from a spacing unit, or oil production allocated to a unit tract under a unit agreement or unit order from the Minister. For horizontal wells, the royalty on oil produced from Crown lands is calculated per spacing unit based on the amount of oil production allocated to the spacing units within the drainage unit of a well in accordance with the applicable regulations.
  Crown Royalties – Gas
  Royalties payable on natural gas production from Crown lands are equal to 12.5% of the volume of natural gas sold.
  Freehold Production Tax
  Manitoba legislation levies a tax on production from freehold oil and gas rights and provides that the operator of a well is responsible for the payment of such tax. The freehold production tax payable on oil is calculated on a sliding scale based on the monthly production volume and the classification of oil as old oil, new oil, third tier oil or holiday oil. Producers of natural gas from freehold lands in Manitoba are required to pay a monthly freehold production tax equal to 1.2% of the volume sold. There is no freehold production tax payable on gas consumed as lease fuel.
  Incentives
  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" pursuant to which no Crown royalties or freehold production taxes are payable until the holiday oil volume has been produced. Under the Program, wells drilled for purposes of injection (or wells converted to injection prior to producing predetermined volumes of oil) in an approved enhanced oil recovery project earn a one-year holiday for portions of the project area.
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  The Program consists of the following components:
  ·
New Well Incentive provides licensees of newly drilled, non-horizontal wells drilled prior to January 1, 2014 with a maximum holiday oil volume of 10,000 m3;
  ·
Deep Drilling Incentive provides licensees who drill a well to the base of the Devonian Duperow formation with a holiday oil volume of 20,000 m3, and licensees who drill a well deeper than the Devonian Three Forks formation can make a one-time assignment of up to 10,000 m3 of holiday oil volume earned through previous drilling or major workovers to such well's holiday oil volume;
  ·
Horizontal Well Initiative provides licensees of horizontal wells drilled on or after January 1, 2009 and prior to January 1, 2014 with a holiday oil volume of 10,000 m3, and a horizontal leg drilled from an existing horizontal well on or after January 1, 2009 and prior to January 1, 2014 will earn an additional holiday royalty volume of 3,000 m3;
  ·
Marginal Well Major Workover Incentive provides licensees of marginal wells where a major workover is completed on or after January 1, 2009 and prior to January 1, 2014 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 1 m3 per operating day;
  ·
Injection Well Incentive provides a one year exemption from the payment of Crown royalties or freehold production taxes on production allocated to a unit tract in which a well is drilled or converted to water injection;
  Further, holiday oil volumes earned by a newly drilled well, or a marginal well that has undergone a major workover can be transferred to a "holiday oil volume account" at the request of the licensee, the purpose of which is to optimize the value of holiday oil volumes earned by providing a company with the flexibility of allocating holiday oil volumes earned among new wells. However, effective January 1, 2015, holiday oil volume accounts will be eliminated by the Manitoba Ministry of Innovation, Energy and Mines. Until December 31, 2014, a holder of an account will be able to make a one-time transfer of 2,000m3 of holiday oil to a well drilled during the period January 1, 2014 to December 31, 2014. For the period of January 1, 2014 to January 1, 2015, holiday oil volume may not be transferred from individual wells to the account.
  Environmental Regulation and Protection Requirements
  All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to international conventions and national, provincial, territorial and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases, discharges, or emissions of various substances produced or used in association with oil and gas operations, as well requirements with respect to oilfield waste handling, storage and disposal, land reclamation, habitat protection, and minimum setbacks of oil and gas activities from surface water bodies.
  Environmental legislation in the Province of Alberta is, for the most part, set out in theEnvironmental Protection and Enhancement Act and theOil and Gas Conservation Act, which impose strict environmental standards with respect to releases of effluents and emissions, including monitoring and reporting obligations, and impose significant penalties for non-compliance. For example, regulations enacted thereunder target sulphur dioxide and nitrous oxide emissions from oil and gas operations. Environmental legislation in the Province of Saskatchewan is, for the most part, set out in the Environmental Management and Protection Act, 2002 and the Oil and Gas Conservation Act, which regulate harmful or potentially harmful activities and substances, any release of such substances, and remediation obligations in Saskatchewan. Certain development activities in Saskatchewan, depending on the location and potential environmental impact, may require a screening or an environmental impact assessment under the provincial EnvironmentalAssessment Act. Environmental Legislation in the Province of Manitoba is, for the most part, set out in the Environmental Actand theOil and Gas Act, which require certain advanced exploration projects to submit a proposal to Manitoba Conservation.
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  Environmental legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material, or in the suspension or revocation of necessary licences and approvals. Crescent Point may also be subject to civil liability for damage caused by pollution. Certain environmental protection legislation may subject Crescent Point to statutory strict liability in the event of an accidental spill or discharge from a facility, meaning that fault on the part of Crescent Point need not be established if such a spill or discharge is found to have occurred.
  As at December 31, 2013, Crescent Point owned approximately 19,498 gross (11,881 net) wells, for which abandonment and reclamation costs are expected to be incurred. During the 2013 financial year, Crescent Point spent approximately $11.4 million on well abandonments and environmental remediation activities. Crescent Point estimates that it will spend approximately $18.5 million on well abandonments and environmental remediation and reclamation activities in 2014, and has budgeted accordingly. Crescent Point has estimated the net present value (discounted at approximately 3.0 percent per annum) of its total decommissioning liability (wells and facilities) to be approximately $629.5 million as at December 31, 2013, based on a future liability (inflated at 2 percent per annum) of approximately $1.0 billion. Crescent Point estimates abandonment and reclamation costs by taking into consideration the costs associated with decommissioning, abandonment, remediation, and reclamation, all adjusted according to its working interest and discounted in accordance with NI 51-101. Decommissioning liability cost estimates are based on information published by the Alberta Energy Regulator ("AER") and the Saskatchewan Energy and Resources Ministry ("SER") Licensee Liability Rating Guidelines ("LLRG"). Crescent Point has a detailed environmental policies and procedures manual which addresses various topics including: spill prevention, response, notification, reporting and reclamation; environmental monitoring; government inspections; surface equipment spacing requirements; facility protection/security; vegetation management; surface water run-off/run-on management; groundwater; noise control; atmospheric emissions; wellsite reclamation; earthen pits; storage tanks; naturally occurring radioactive materials; disposal wells; suspended or shut-in wells; waste management and communications.
  Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability, and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas, or other pollutants into the air, soil or water may give rise to liabilities to third parties and may require Crescent Point to incur costs to remedy such a discharge in an event not covered by Crescent Point's insurance, which insurance is in line with industry practice. Furthermore, Crescent Point expects incremental future costs associated with compliance with increasingly complex environmental protection requirements with respect to GHG emissions or otherwise, some of which may require the installation of emissions monitoring and measuring devices, the verification and reporting of emissions data and additional financial expenditures to comply with GHG emissions reduction requirements.
  United States
  Our wholly-owned subsidiary, CPEUS, owns oil and natural gas properties and related assets in North Dakota, Montana and Utah in the United States. CPEUS' oil and natural gas operations in the United States are regulated by administrative agencies under statutory provisions of the states where such operations are conducted and by certain agencies of the federal government for operations on federal leases. These statutory provisions regulate matters such as the exploration for and production of crude oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements in order to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the abandonment of wells. CPEUS' operations in the United States are also subject to various conservation laws and regulations which regulate matters such as the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil and natural gas properties. In addition, state conservation laws sometimes establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the rateability or fair apportionment of production from fields and individual wells.
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  The following is a summary of the more significant existing environmental, health and safety laws and regulations in the United States to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
  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.
  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 willful 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.
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  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, was introduced during the previous session of Congress and may be reintroduced during the current session of Congress. In addition, the EPA at the request of Congress is currently conducting a national study examining the potential impacts of hydraulic fracturing on drinking water resources, with a draft of the final report expected to be released in 2014.
  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. If new federal or 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. On April 17, 2012, the EPA issued final rules under the Clean Air Act that subject oil and natural gas production, processing, transmission and storage operations within federal regulatory jurisdiction to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs. The EPA rules include New Source Performance Standards for completions of hydraulically fractured wells. The final rules establish a phase-in period that will ensure that manufacturers have time to make and broadly distribute the required emissions reduction technology.
  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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  Greenhouse Gas Emissions
  In Alberta, GHG emissions are regulated under the Specified Gas Emitters Regulationpursuant to theClimate Change and Emissions Management Act. These regulations require Alberta facilities that emit more than 100,000 tonnes of GHG per year to reduce emissions intensity by 12% below an average baseline taken from a facility's 2003 - 2005 emissions. Companies may meet requirements through improvements to their operations; by purchasing Alberta based emission reduction 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 Province of Alberta also published a climate change action plan in January of 2008 wherein it set an objective to deliver a 50% reduction in GHG emissions from business as usual by 2050 by employing: (a) mandatory carbon capture and storage ("CCS") for certain facilities; (b) energy efficiency and conservation; and (c) research and investment in clean energy technologies, including carbon separation technologies to assist CCS.
  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 received Royal Assent on May 20, 2010 and will come into force on proclamation. Draft versions of the regulations under the MRGHGA indicate that Saskatchewan will adopt similar initiatives to the Alberta framework. The Management and Reduction of Greenhouse Gases Act establishes the provinces' strategy to meet its target of reducing GHG emissions. Baseline emissions and reduction targets will be set by the Lieutenant Governor in Council. Crescent Point is involved in the re-development of the proposed Saskatchewan environmental protection legislation and is currently working with the Government of Saskatchewan. No financial and operational effects of the proposed legislation are currently known due to its preliminary nature.
  In British Columbia, GHG emissions are regulated under the Reporting Regulation enacted pursuant to the Greenhouse Gas Reduction (Cap and Trade) Act. Starting January 1, 2010, these regulations impose GHG emissions reporting requirements upon B.C. facilities emitting 10,000 tonnes or more of carbon dioxide equivalent emissions per year. In addition, facilities reporting operations with emissions of 25,000 tonnes or greater are required to have emissions reports verified by a third party. To date, Crescent Point does not operate any facilities that are regulated by the British Columbia GHG emissions regulations.
  Crescent Point's facilities and other operations emit GHG emissions, making it possible that Crescent Point will be subject to federal and provincial GHG emissions controls or reduction requirements if its facilities or operations are above applicable thresholds, particularly in B.C. where a cap and trade regime is pending. In the near term, Crescent Point does not expect to have any facilities subject to reporting based on these preliminary regulations.
  In December 2002, the Government of Canada ratified the Kyoto Protocol, which requires a reduction in GHG emissions by signatory countries between 2008 and 2012. The Kyoto Protocol officially came into force on February 16, 2005, although on December 12, 2011, Canada formally withdrew from the Kyoto Protocol. However, the Canadian federal government has indicated an intention to regulate the emissions of GHGs from a range of industries in its framework and has outlined a number of policies to reduce GHGs intensity of regulated facilities (the "Federal Plan"). New facilities (which are defined as those facilities whose first year of operation is 2004 or later) would face intensity reduction requirements beginning in their fourth year of commercial production, of 2% per year from their "baseline" emissions intensity (which baseline is the emissions intensity for such facility's third year of commercial production) until at least 2020. Compliance options for new facilities under the Federal Plan include making emissions intensity improvements; making investments in certified carbon capture and storage projects; buying offsets or emissions performance credits; and for a portion of each entity's emissions reduction obligations, making payments of $15 per tonne until 2012, $20 per tonne in 2013 and an escalating annual rate per tonne thereafter; to the federal technology fund.
  The Federal Plan also includes proposed requirements to be implemented by the Canadian federal government which would govern the emission of industrial air pollutants. Certain of the proposed requirements include fixed emissions caps, an emissions credit trading system, and several options from which companies can choose to meet their GHG emission reduction targets. At present, the status of its proposals is unclear. The Canadian federal government has repeatedly stated that it intends to align Canada's GHG emission reduction policies with those of the United States, and it is willing to wait until the United States has developed its framework before implementing any policies in Canada. As such, it is unclear when, or in what form, the Federal Plan will be implemented.
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  Several of the provinces and territories are working together with various American states to develop a cap and trade system. It remains to be seen whether the Canadian federal government would adopt such an approach, but given its statements regarding aligning policy with the United States, this will likely depend on whether the United States adopts a cap and trade system. No assurance can be given that either a modified Federal Plan or a North American cap and trade system will or will not be implemented, or what kinds of obligations may be imposed under such a system.
  At the July 2009 G8 Summit in Italy, Canada and the other G8 members agreed to work together toward achieving at least a 50% reduction of global GHG emissions by 2050. Canada reiterated its commitment to this goal at the June 2010 G8 Summit in Huntsville, Ontario.
  In December 2009, Canada participated in the Fifteenth session of the Conference of the Parties to the United Nations Framework Convention on Climate Change ("COP 15") in Denmark, the goal of which was to reach a new agreement for fighting global climate change. COP 15 resulted in the non-binding Copenhagen Accord, whereby Canada and the other participating countries committed to implementing quantified economy-wide emissions targets by 2020. Canada submitted its GHG emission reduction targets on January 30, 2010, noting that: (a) its target is a 17% reduction from a baseline of 2005 emission levels (which target is aligned with the final economy-wide emissions target and base year of the United States); and (b) its submission is dependent on the other parties to the Copenhagen Accord submitting emissions targets and mitigation actions in accordance with such Accord.
  There remains ongoing uncertainty regarding Canada's short-term and long-term emissions reduction targets and whether such targets will be absolute or intensity based. Facility owners across Canada await further information regarding Canada's approach to regulating GHG emissions. Although the timing and nature of federal GHG regulations are unknown at this time, Crescent Point anticipates that, based on current production levels, Government of Canada GHG regulations will apply to its operations in the future and as a result additional costs will be incurred to comply with reduction requirements and to perform necessary monitoring, measurement, verification, and reporting of GHG emissions.
  As part of its ongoing commitment to reduce GHG emissions, Crescent Point established an Environmental Emissions Reduction Fund in 2007. During 2013, $0.30 per produced boe was allocated to this fund. As at December 31, 2013, $44.6 million has been allocated to the fund and $24.5 million has been expended in order to reduce GHG emissions and to meet and exceed provincial and proposed federal targets.
  Crescent Point anticipates changes in environmental legislation may require reductions in emissions from its operations and result in increased capital expenditures. Further changes in environmental legislation could occur, which may result in stricter standards and enforcement, larger fines and liability and increased capital expenditures and operating costs, which could have a material adverse effect on our financial condition and results of operations.
  We are committed to meeting our responsibilities to protect the environment wherever we operate and anticipate making increased expenditures as a result of the increasingly stringent laws relating to the protection of the environment. Our internal procedures are designed to ensure that the environmental aspects of new developments are taken into account prior to proceeding.
  Health, Safety and Environment
  The health and safety of employees, contractors, visitors and the public, as well as the protection of the environment, is of utmost importance to Crescent Point. Crescent Point endeavours to conduct its operations in a manner that will minimize both adverse effects and consequences of emergency situations by:
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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;
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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.
  Crescent Point believes that it is in material compliance with environmental legislation in the jurisdictions in which it operates at this time. Crescent Point's practice is to do all that it reasonably can to ensure that it remains in material compliance with applicable environmental protection legislation. Crescent Point also believes that it is reasonably likely that the trend towards stricter standards in environmental regulation will continue. Crescent Point is committed to meeting its responsibilities to protect the environment wherever it operates and will take such steps as required to ensure compliance with environmental legislation. Crescent Point anticipates increased capital and operating expenditures as a result of increasingly stringent laws relating to the protection of the environment. No assurance can be given however that environmental laws will not result in a curtailment of production or a material increase in the costs of production, the development or exploration activities, or otherwise adversely affect Crescent Point's financial condition, capital expenditures, results of operations, competitive position or prospects.
  RISK FACTORS
  Each of the risks described below should be carefully considered, together with all of the other information contained herein, before making an investment decision with respect to our Common Shares. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially and adversely affected, and you could lose all or part of your investment.
  Risks Relating to Our Business
  Our estimated Proved and Proved plus Probable reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
  The reserve and recovery information contained in the Crescent Point Reserve Report are only estimates and the actual production and ultimate reserves from our properties may be greater or less than the estimates prepared by GLJ and Sproule. Ultimately, actual reserves attributable to our properties will vary from estimates, and those variations may be material. The reserve figures contained herein are only estimates. A number of factors are considered and a number of assumptions are made when estimating reserves. These factors and assumptions include, among others:
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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;
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initial production rates;
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production decline rates;
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ultimate recovery of reserves;
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success of future development activities;
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marketability of production;
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availability, proximity and capacity of oil and gas gathering systems, pipelines and processing facilities;
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effects of government regulation; and
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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. 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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  Reinvestment of Cash Flow to Fund Ongoing Operations
  Dividends may be reduced during periods in which we make capital expenditures or debt repayments using cash flow, which could also affect the market price of our Common Shares. To the extent that we use cash flow to finance acquisitions, development costs and other significant expenditures, the net cash flow the Corporation receives that is available for dividends to Shareholders will be reduced. Hence, the timing and amount of capital expenditures may affect the amount of net cash flow received by the Corporation and, as a consequence, the amount of cash available to distribute to Shareholders. Therefore, dividends may be reduced, or even eliminated, at times when significant capital or other expenditures are made.
  The board of directors of Crescent Point has the discretion to determine the extent to which cash flow from Crescent Point will be allocated to the payment of debt service charges as well as the repayment of outstanding debt, including under the Credit Facilities. As a consequence, the amount of funds used to pay debt service charges or reduce debt will reduce the amount of cash available for dividends to Shareholders during those periods in which funds are so retained.
  The amount of oil and natural gas that we can produce and sell is subject to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems.
  Our business depends in part upon the availability, proximity and capacity of oil and gas gathering systems, pipelines and processing facilities and rail loading facilities and railcars. Canadian federal and provincial, as well as U.S. federal and state, regulation of oil and gas production, processing and transportation, tax and energy policies, general economic conditions, and changes in supply and demand could adversely affect our ability to produce and market oil and natural gas. If market factors change and inhibit the marketing of our production, overall production or realized prices may decline, which could reduce dividends to our Shareholders.
  Our future performance depends on our ability to acquire additional natural gas and oil reserves that are economically recoverable.
  If we are unable to acquire additional reserves, the value of our Common Shares and payments of dividends to Shareholders may decline. We generally do not actively explore for oil and natural gas reserves. We add to our oil and natural gas reserves primarily through development, exploitation and acquisitions including those with large resource potential. As a result, future oil and natural gas reserves are highly dependent on our success in exploiting existing properties and acquiring additional reserves. We also distribute approximately 50% of our net cash flow to Shareholders rather than reinvesting it in reserve additions. Accordingly, if external sources of capital, including the issuance of additional Common Shares, become limited or unavailable on commercially reasonable terms, our ability to make the necessary capital investments to maintain or expand our oil and natural gas reserves will be impaired. To the extent that we are required to use cash flow to finance capital expenditures or property acquisitions, the level of cash flow available for payment of dividends to Shareholders will be reduced. Additionally, we cannot guarantee that we will be successful in developing additional reserves or acquiring additional reserves on terms that meet our investment objectives. Without these reserve additions, our reserves will deplete and as a consequence, either production from, or the average reserve life of, our properties will decline. Either decline may result in a reduction in the value of our Common Shares and in a reduction in cash available for dividends to Shareholders.
  We operate only in western Canada and the United States and expansion outside of these areas may increase our risk exposure.
  If we expand our operations beyond oil and natural gas production in western Canada, North Dakota, Montana and Utah, we may face new challenges and risks. If we were unsuccessful in managing these challenges and risks, our results of operations and financial condition could be adversely affected, which could affect the market price of our Common Shares and payment of dividends to Shareholders.
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  Our operations and expertise are currently focused on conventional oil and gas production and development in the Western Canadian Sedimentary Basin and in North Dakota, Montana and Utah. In the future, we may acquire oil and gas properties outside this geographic area. In addition, we could acquire other energy related assets, such as oil and natural gas processing plants or pipelines. Expansion of our activities into new areas may present challenges and risks that we have not faced in the past. If we do not manage these challenges and risks successfully, our results of operations and financial condition could be adversely affected.
  The properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the acquired properties or obtain protection from sellers against such liabilities.
  The properties we acquire may not produce as expected, may be in an unexpected condition and we may be subject to increased costs and liabilities, including environmental liabilities. Although we review properties prior to acquisition in a manner consistent with industry practices, such reviews are not capable of identifying all potential adverse conditions. Furthermore, we may not be able to subject the preparation of reserve estimates for acquired properties to the same internal controls we have for the preparation of reserve estimates for our existing properties. Generally, it is not feasible to review in depth every individual property involved in each acquisition. We focus our review efforts on the higher-value properties or properties with known adverse conditions and will sample the remainder. However, even a detailed review of records and properties and preparation of reserve reports in accordance with our internal controls may not necessarily reveal existing or potential problems or permit usto become sufficiently familiar with the properties to fully assess their condition, any deficiencies, and development potential.
  The operation of a portion of our properties is largely dependent on the ability of third party operators.
  Some of our properties are not operated by us and, therefore, results of operations may be adversely affected by the failure of third-party operators, which could affect the market price of our Common Shares and dividends to Shareholders.
  The continuing production from a property, and to some extent the marketing of that production, is dependent upon the ability of the operators of those properties. At December 31, 2013, approximately 15% of our daily production was from properties operated by third parties. To the extent a third-party operator fails to perform its functions efficiently or becomes insolvent, our revenue may be reduced. Third party operators also make estimates of future capital expenditures more difficult.
  Further, the operating agreements which govern the properties not operated by us typically require the operator to conduct operations in a good and "workmanlike" manner. These operating agreements generally provide, however, that the operator has no liability to the other non-operated working interest owners, such as Shareholders, for losses sustained or liabilities incurred, except for liabilities that may result from gross negligence or willful misconduct.
  Delays in business operations could adversely affect our income and financial condition.
  Delays in business operations could adversely affect dividends to Shareholders and the market price of our Common Shares. In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of our properties, and the delays of those operators in remitting payment to us, payments between any of these parties may also be delayed by:
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restrictions imposed by lenders;
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delays in the sale or delivery of products;
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delays in the connection of wells to a gathering system;
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restrictions due to limited pipeline capacity;
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blowouts or other accidents;
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accounting delays;
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adjustments for prior periods;
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recovery by the operator of expenses incurred in the operation of the properties; or
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the establishment by the operator of reserves for these expenses.
  Any of these or other delays in our business operations could reduce the amount of cash available for dividends to Shareholders in a given period and expose us to additional third party credit risks.
  Failure of third parties to meet their contractual obligations to us may have a material adverse effect on our financial condition.
  Although the Corporation monitors the credit worthiness of third parties it contracts with through a formal Risk Management and Counterparty Credit Policy and maintains third party credit insurance, there can be no assurance that the Corporation will not experience a loss for non-performance by any counterparty with whom it has a commercial relationship. Such events may result in material adverse consequences on the business of the Corporation and may limit the timing or amount of dividends that are paid to Shareholders and could affect the market price of our common shares.
  The Corporation maintains trade credit insurance to partially protect against credit risk with financial counterparties.
  Our debt level and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations, cash flows and business prospects.
  We may, from time to time, finance a significant portion of our operations through debt. Our indebtedness may limit the timing or amount of the dividends that are paid to Shareholders, and could affect the market price of our Common Shares.
  The payments of interest and principal, and other costs, expenses and disbursements to our lenders reduces amounts available for dividends to Shareholders. Variations in interest rates and scheduled principal repayments could result in significant changes to the amount of the cash flow required to be applied to the debt before payment of any amounts to the Shareholders. The agreements governing our Credit Facilities provide that if we are in default under the Credit Facilities or fail to comply with certain covenants, we must repay the indebtedness at an accelerated rate, and the ability to make payment of dividends to Shareholders may be restricted.
  If we are unable to pay the debt service charges or otherwise commit an event of default, such as bankruptcy, our lenders may receive a judgment and have an unsecured claim on the properties. The proceeds of any sale would be applied to satisfy amounts owed to the creditors. Only after the proceeds of that sale were applied towards the debt would the remainder, if any, be available for dividends to Shareholders.
  Our existing credit facilities and any replacement credit facilities may not provide sufficient liquidity.
  Our current credit facilities and any replacement credit facilities may not provide sufficient liquidity. The amounts available under our existing credit facilities may not be sufficient for future operations, or we may not be able to obtain additional financing on economic terms attractive to us, if at all. We currently have a syndicated $2.0 billion extendible revolving loan facility with a permitted increase to $2.5 billion (subject to certain conditions) (the "Syndicated Credit Facility") with certain banks and a $100 million operating loan facility with one Canadian chartered bank. The interest charged on the Syndicated Credit Facility is calculated based on a sliding scale ratio of the Corporation's senior debt to EBITDA ratio. Repayment of all outstanding amounts under the Syndicated Credit Facility may be demanded on relatively short notice if an event of default occurs and is continuing. If this occurs, we may need to obtain alternate financing. Any failure to obtain suitable replacement financing may have a material adverse effect on our business, and dividends to Shareholders may be materially reduced.
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  Failure to Realize Anticipated Benefits of Prior Acquisitions may have a material adverse effect on our business.
  The Corporation has completed a number of acquisitions in order to strengthen its position in the oil and natural gas industry and to create the opportunity to realize certain benefits, including, among other things, potential cost savings. In order to achieve the benefits of these and future acquisitions, the Corporation is dependent upon its ability to successfully consolidate functions and integrate operations, procedures and personnel in a timely and efficient manner and to realize the anticipated growth opportunities and synergies from combining the acquired assets and operations with those of the Corporation. The integration of acquired assets and operations requires the dedication of management effort, time and resources, which may divert management's focus and resources from other strategic opportunities and from operational matters during this process. The integration process may result in the disruption of ongoing business and customer relationships that may adversely affect the Corporation's ability to achieve the anticipated benefits of such prior acquisitions.
  We may incur losses as a result of title defects in the properties in which we invest.
  Unforeseen title defects may result in a loss of entitlement to production and reserves. Although we conduct title reviews in accordance with industry practice prior to any purchase of resource assets, such reviews do not guarantee that an unforeseen defect in the chain of title will not arise and defeat our title to the purchased assets. If such a defect were to occur, our entitlement to the production from such purchased assets could be jeopardized and, as a result, dividends to Shareholders may be reduced.
  Aboriginalclaims could have an adverse effect on us and ouroperations.
  The economic impact on us of claims of aboriginal title is unknown. Aboriginal people have claimed aboriginal title and rights to a substantial portion of western Canada and the U.S. We are unable to assess the effect, if any, that any such claim would have on our business and operations.
  Approximately 60% of Crescent Point's Utah assets are located on the Reservation. Operation of oil and gas interests on Native American tribal lands presents unique considerations and complexities that arise from the fact that Native American tribes are "dependent" sovereign nations located within states but are subject only to tribal laws and treaties with, and the laws and Constitution of, the United States. This creates an overlay of three jurisdictional regimes—Native American, federal and state. These considerations and complexities could arise around various aspects of Crescent Point's Utah operations, including real property considerations, permitting, employment practices, environmental matters and taxes.
  Furthermore, because tribal property is considered to be held in trust by the federal government, before Crescent Point can take actions such as drilling, pipeline installation or similar actions, Crescent Point is required to obtain approvals from various federal agencies, including the Bureau of Indian Affairs and the BLM. Crescent Point is also required to obtain approvals from the Tribe for surface use access on certain of its properties. Gaining these approvals could result in delays in implementation of, or otherwise prevent Crescent Point from implementing, its development program.
  Because of their sovereign status, Native American tribes also enjoysovereign immunityfrom suit and may not be sued in their own courts or in any other court absent Congressional abrogation or a valid tribal waiver of such immunity.
  Although the Tribe has sovereign immunity and generally may not be sued without its consent, a limited waiver of sovereign immunity and consent to suit has been granted in connection with the Tribe’s EDAswith Crescent Point.
  These waivers were subject to various United States governmental approvals, which Crescent Point believes have been obtained. An enforceable waiver of sovereign immunity should allow Crescent Point to enforce its rights under the EDAs in a federal court. If any waiver of sovereign immunity with Crescent Point is held to be ineffective, including as a result of failing to obtain appropriate federal governmental approvals, Crescent Point and CPEUS could be precluded from judicially enforcing its rights and remedies against the Tribe.
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  Obtaining jurisdiction over a Native American tribe, such as the Tribe, can be difficult. Often, a commercial dispute with a Native American tribe or tribal instrumentality cannot be heard in federal court because the typical requirements for federal jurisdiction are absent. It is possible that neither a federal nor a state court would accept jurisdiction to resolve a matter involving a commercial dispute between Crescent Point or CPEUS and the Tribe, and no legal recourse to a state or federal court may be available to Crescent Point. Pursuant to the waivers of sovereign immunity previously obtained from the Tribe, the Tribe has waived its rights to have certain matters resolved in any tribal court or other proceeding of the Tribe. The Tribe has a tribal court system, and a federal or state court may defer to such tribal courts if, contrary to the waivers of sovereign immunity by the Tribe, the Tribe seeks or alleges its right to seek tribal proceedings for resolution of a dispute. The tribal courts may not reach the same conclusions that would be reached in state or federal courts.
  Any state or federal court judgment requiring satisfaction or enforcement within tribal territories may require that an order for such enforcement be issued by tribal courts. Tribal courts do not have specific rules related to granting full faith and credit to judgments of courts of the United States or any state, except in limited circumstances.
  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.
  Increased costs of capital could adversely affect our business.
  Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
  Increases in operating costs could adversely affect our business, financial condition and results of operations.
  An increase in operating costs could have a material adverse effect on our results of operations and financial condition and, therefore, could reduce dividends to Shareholders as well as affect the market price of the Common Shares.
  Higher operating costs for our underlying properties will directly decrease the amount of cash flow received by the Corporation and, therefore, may reduce dividends to our Shareholders. Electricity, chemicals, supplies and labour costs are a few of the operating costs that are susceptible to material fluctuation.
  Hedging limits participation in commodity price increases and increases counterparty credit risk exposure.
  We periodically enter into hedging activities with respect to a portion of our production to manage our exposure to oil and gas price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts.
  We depend upon our management team and our operations require us to attract and retain experienced technical personnel.
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  Shareholders are entirely dependent on our management with respect to the acquisition of oil and gas properties and assets, the development and acquisition of additional reserves and the management and administration of all matters relating to our oil and natural gas properties. The loss of the services of key individuals who currently comprise the management team could have a detrimental effect on the Corporation. Investors should carefully consider whether they are willing to rely on the existing management before investing in the Common Shares.
  Risks Relating to the Oil and Gas Industry
  Natural gas and oil prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business.
  Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and oil. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results and could result in an impairment charge.
  Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include but are not limited to the following:
  ·
the levels and location of natural gas and oil supply and demand and expectations regarding supply and demand;
 ·
the level of consumer product demand;
 ·
weather conditions;
 ·
political conditions or hostilities in natural gas and oil producing regions, including the Middle East, Africa and South America;
 ·
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 natural gas and oil;
 ·
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.
  These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and crude oil. If natural gas and crude oil prices decline significantly for a sustained period of time, the lower prices may adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.
  Variations in interest rates and foreign exchange rates could adversely affect our financial condition.
  There is a risk that the interest rates will increase given the current historical low level of interest rates. An increase in interest rates could result in a significant increase in the amount we pay to service debt and could have an adverse effect on our financial condition, results of operations and future growth, potentially resulting in a decrease in dividends to Shareholders and/or the market price of the Common Shares.
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  Fluctuations in foreign currency exchange rates could adversely affect our business, and could affect the market price of our Common Shares and payments of dividends to Shareholders. The price that we receive for a majority of our oil and natural gas is based on U.S. dollar denominated benchmarks and, therefore, the price that we receive in Canadian dollars is affected by the exchange rate between the two currencies. A material increase in the value of the Canadian dollar relative to the U.S. dollar may negatively impact net production revenue by decreasing the Canadian dollars received for a given U.S. dollar price, negatively impacting future dividends and the future value of the Corporation's reserves as determined by independent evaluators. We could be subject to unfavorable exchange rate changes to the extent of our investment in U.S. subsidiaries and to the extent that we have engaged, or in the future engage, in risk management activities related to foreign exchange rates, through entry into forward foreign exchange contracts or otherwise.
  Competition in the oil and gas industry is intense, which may adversely affect our ability to compete.
  The oil and natural gas industry is highly competitive. We compete for capital, acquisitions of reserves, undeveloped lands, skilled personnel, access to drilling rigs, service rigs and other equipment, access to processing facilities, pipeline and refining capacity and in many other respects with a substantial number of other organizations, many of which may have greater technical and financial resources than we do. Some of these organizations not only explore for, develop and produce oil and natural gas but also carry on refining operations and market oil and other products on a worldwide basis. As a result of these complementary activities, some of our competitors may have greater and more diverse competitive resources to draw on than we do. Given the highly competitive nature of the oil and natural gas industry, this could adversely affect the market price of our Common Shares and dividends to Shareholders.
  Risks associated with the production, gathering, transportation and sale of oil and natural gas could adversely affect net income and cash flows. We may not be insured against all of the operating risks to which our business is exposed.
  The industry in which we operate exposes us to potential liabilities that may not be covered by insurance. Our operations are subject to all of the risks associated with the operation and development of oil and natural gas properties, including the drilling of oil and natural gas wells, and the production and transportation of oil and natural gas. These risks include encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, equipment failures and other accidents, cratering, sour gas releases, uncontrollable flows of oil, natural gas or well fluids, adverse weather conditions, pollution, other environmental risks, fires and spills. A number of these risks could result in personal injury, loss of life, or environmental and other damage to our property or the property of others and reputational loss. We cannot fully protect against all of these risks, nor are all of these risks insurable. We may become liable for damages arising from these events against which we cannot insure or against which we may elect not to insure because of high premium costs or other reasons. Any costs incurred to repair these damages or pay these liabilities would reduce funds available for payment of dividends to Shareholders.
  We are subject to complex laws that can affect the cost, manner or feasibility of doing business.
  Crescent Point is subject to extensive and complex regulations and laws enforced by various regulatory agencies. These regulatory agencies include the EPA, the U.S. Bureau of Indian Affairs, the BLM, Energy and Minerals, the Tribe and the Utah Division of Oil, Gas and Mining. Crescent Point is also subject to regulation by other federal, provincial, state and local agencies. Regulations affect almost every aspect of Crescent Point's business and limit its ability to make and implement independent management decisions, including about business combinations, disposing of operating assets and engaging in transactions between Crescent Point and its affiliates.
  Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that could substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our financial condition and results of operations.
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  Regulations and laws are subject to ongoing policy initiatives, and Crescent Point cannot predict the future course of regulations or legislation and their respective ultimate effects. Such changes could materially impact Crescent Point's business, financial position and results of operations.
  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".
  Our operations may incur substantial costs and liabilities to comply with environmental laws and regulations.
  Many aspects of the oil and natural gas business present environmental risks and hazards, including the risk that Crescent Point may be in non-compliance with an environmental law, regulation, permit, licence, or other regulatory approval, possibly unintentionally or without knowledge. Such risks may expose Crescent Point to fines or penalties, suspension or revocation of regulatory permits, third party liabilities or to the requirement to remediate, which could be material. The operational hazards associated with possible blowouts, accidents, oil spills, gas leaks, fires, or other damage to a well, pipeline or facility may require Crescent Point to incur costs and delays to undertake corrective actions, and could result in environmental damage or contamination for which Crescent Point could be liable. Oil and gas operations are also subject to specific operational risks which may have a material operational and financial impact on Crescent Point should they occur, such as drilling into unexpected formations or unexpected pressures, premature decline of reservoirs and water invasion into producing formations.
  Crescent Point may also be subject to associated liabilities, resulting from lawsuits alleging property damage or personal injury brought by private litigants related to the operation of Crescent Point's facilities or the land on which such facilities are located, regardless of whether Crescent Point leases or owns the facility, and regardless of whether such environmental conditions were created by Crescent Point or by a prior owner or tenant, or by a third party or a neighbouring facility whose operations may have affected Crescent Point's facility or land. Such liabilities could have a material adverse effect on Crescent Point's business, financial position, operations, assets or future prospects.
  Crescent Point also faces uncertainties related to future environmental laws and regulations affecting its business and operations. Existing environmental laws and regulations may be revised or interpreted more strictly, and new laws or regulations may be adopted or become applicable to Crescent Point, which may result in increased compliance costs or additional operating restrictions, each of which could reduce Crescent Point's earnings and adversely affect Crescent Point's business, financial position, operations, assets or future prospects.
  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 GHGemissions reduction requirements or other GHG emissions regulations compliance costs, if enacted. 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."
  Although we record a provision in our consolidated financial statements relating to our estimated future abandonment and reclamation obligations, we cannot guarantee that we will be able to satisfy our actual future abandonment and reclamation obligations. Although the Corporation maintains insurance consistent with prudent industry practice, we are not fully insured against certain environmental risks, either because such insurance is not available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic damages) is not available on economically reasonable terms.
  Accordingly, our properties may be subject to liability due to hazards that cannot be insured against, or that have not been insured against due to prohibitive premium costs or for other reasons. It is also possible that changing regulatory requirements or emerging jurisprudence could render such insurance of less benefit to Crescent Point. Any site reclamation or abandonment costs actually incurred in the ordinary course of business in a specific period will be funded out of our reclamation fund and, if required, out of cash flow and, therefore, will reduce the amounts available for payment of dividends to Shareholders. Should we be unable to fully fund the cost of remedying an environmental problem, we might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy.
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  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 Tribe Reservation lands.
  In addition, Crescent Point's oil and natural gas exploration and production operations in Utah, particularly those located outside the Reservation lands, may be subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to Crescent Point's Utah operations including the acquisition of a permit before conducting drilling or underground injection activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, and analogous state agencies, including in Utah, North Dakota and Montana, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of Crescent Point's operations.
  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.
  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. Further, facilities required to obtain PSD permits for their GHG emissions are required to reduce those emissions 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.
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  Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
  Some of Crescent Point's operations use hydraulic fracturing, which involves the high pressure injection of fluids and sand down a well to fracture the reservoir and thereby stimulate the increased flow of oil or gas into the well bore. Hydraulic fracturing has recently been the subject of greater regulatory scrutiny and regulation in certain jurisdictions of the world, including some of the areas in which Crescent Point operates. In a limited number of areas, hydraulic fracturing has been banned pending public review or is subject to moratoria while regulators study the practice. We may be required to expend additional costs to comply with future regulatory requirements with respect to hydraulic fracturing or, in the future, be unable to carry out hydraulic fracturing operations, thereby lessening the volume of oil and gas we could otherwise produce and this could have a material operational and financial impact on Crescent Point and adversely affect the market price of our Common Shares and dividends to Shareholders.
  New safety requirements involving rail transportation may adversely affect us and our Shareholders.
  In response to recent train derailments occurring in the United States and Canada in 2013, U.S. regulators are implementing or considering new rules to address the safety risks of transporting crude oil by rail. On January 23, 2014, the National Transportation Safety Board issued a series of recommendations to address safety risks, including (i) requiring expanded hazardous material route planning for railroads to avoid populated and other sensitive areas, (ii) to develop an audit program to ensure rail carriers that carry petroleum products have adequate response capabilities to address worst-case discharges of the entire quantity of product carried on a train, and (iii) to audit shippers and rail carriers to ensure they are properly classifying hazardous materials in transportation and that they have adequate safety and security plans in place. Additionally, on February 25, 2014 the U.S. Department of Transportation issued an emergency order requiring all persons, prior to offering petroleum crude oil into transportation, to ensure such product is properly tested and classed and to assure all shipments by rail of petroleum crude oil be handled as a Packing Group I or II hazardous material. Such tests help determine how likely the fuel is to ignite and dictate what type of rail car can be used for shipment. The introduction of these or other regulations that result in new requirements addressing the type, design, specifications or construction of rail cars used to transport crude oil could result in severe transportation capacity constraints during the period in which new rail cars are retrofitted or constructed to meet new specifications. On March 6, 2014, the U.S. Department of Transportation issued an amended emergency order, offering more details on testing requirements of oil transported by rail and cautioned companies against circumventing the rules. The amended emergency order offers new standards on how frequently testing of crude oil has to be done. Testing must now be conducted within the reasonable, recent past to determine the flash point and boiling point of crude oil. The amended emergency order also warns companies not to re-label crude as a more generic category of flammable liquid in an attempt to get around the testing.
  We do not currently own or operate rail transportation facilities or rail cars; however, the adoption of any regulations that impact the testing or rail transportation of crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at favorable prices at market centers throughout Canada and the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows.
  Income tax laws or other laws or government incentive programs or regulations relating to our industry may in the future be changed or interpreted in a manner that adversely affects us and our Shareholders.
  Changes in tax and other laws may adversely affect the trading price of our Common Shares and dividends to Shareholders. Tax authorities having jurisdiction over the Corporation or the Shareholders may disagree with the manner in which we calculate our income for tax purposes or could change their administrative practices to our detriment or the detriment of Shareholders.
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  The oil and gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation, and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, the United States, and the various states, all of which should be carefully considered by investors in the oil and gas industry. All of such controls, regulations and legislation are subject to revocation, amendment or administrative change, some of which have historically been material and in some cases materially adverse and there can be no assurance that there will not be further revocation, amendment or administrative change which will be materially adverse to our assets, reserves, financial condition or results of operations or prospects and our ability to maintain dividends to Shareholders.
  Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated or deferred as a result of future legislation.
  In April 2013, President Obama’s Administration released its proposed federal budget for fiscal year 2014 that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. Such changes include, but are not limited to:
  ·
the repeal of the percentage depletion allowance for oil and gas properties;
 ·
the elimination of current deductions for intangible drilling and development costs;
 ·
the elimination of the deduction for U.S. oil and gas production activities; and
 ·
an extension of the amortization period for certain geological and geophysical expenditures.
  It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective. The passage of any legislation containing these or similar changes in U.S. federal income tax law could eliminate or defer certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such changes could negatively affect our financial condition and results of operations.
  In connection with the passage of the Dodd-Frank Wall Street Reform and Consumer Protection Act, new regulations forthcoming in this area may result in increased costs and cash collateral requirements for the types of oil and gas derivative instruments we use to manage our risks related to oil and gas commodity price volatility.
  On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was enacted into law. This financial reform legislation includes provisions that require over-the-counter derivative transactions to be executed through an exchange or centrally cleared. In addition, the legislation provides an exemption from mandatory clearing requirements based on regulations to be developed by the Commodity Futures Trading Commission (the "CFTC") and the U.S. Securities and Exchange Commission ("SEC") for transactions by non-financial institutions to hedge or mitigate commercial risk. At the same time, the legislation includes provisions under which the CFTC may impose collateral requirements for transactions, including those that are used to hedge commercial risk. However, during drafting of the legislation, members of Congress adopted report language and issued a public letter stating that it was not their intention to impose margin and collateral requirements on counterparties that utilize transactions to hedge commercial risk. Final rules on major provisions in the legislation, like new margin requirements, will be established through rulemakings and will not take effect until 12 months after the date of enactment. Although we cannot predict the ultimate outcome of these rulemakings, new regulations in this area may result in increased costs and cash collateral requirements for the types of oil and gas derivative instruments we use to hedge and to otherwise manage our financial risks related to volatility in oil and gas commodity prices.
  We are affected by seasonal weather patterns.
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  The level of activity in the oil and gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities, provincial and state transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Also, certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and corresponding declines in the demand for crude oil and natural gas.
  Risks Relating to Ownership of our Common Shares
  Our Board of Directors has discretion in the payment of dividends and may choose not to maintain dividends in certain circumstances.
  Any future dividends will be reviewed by the board of directors and adjusted from time to time to reflect current business conditions. The ability of the Corporation to pay dividends and the actual amount of such dividends will be dependent upon, among other things, the financial performance of the Corporation and its subsidiaries, its debt covenants and obligations, its ability to refinance its debt obligations on similar terms and at similar interest rates, its working capital requirements, its future tax obligations and its future capital requirements. A reduction in the amount of cash distributed to Shareholders may negatively affect the market price of the Common Shares.
  Availability of Future Debt and Equity Financing
  The success of Crescent Point's business in the future is dependant on its ability to obtain debt and equity financing to maintain and grow its operations. As a growth oriented corporation, Crescent Point continues to invest in property, plant and equipment to grow its operations. This investment requires adequate financing that Crescent Point obtains through both internal operating cash flows and external debt and equity financings. There can be no assurance additional financing will be available in the future when needed or on terms acceptable to Crescent Point. The inability to access financing to support future growth opportunities could limit Crescent Point's future growth and have a material adverse impact on Crescent Point's liquidity position, including its ability to pay obligations as they come due.
  We have been historically reliant on external sources of capital, which may dilute Shareholders’ ownership interests.
  There may be future dilution to our Shareholders. One of our objectives is to continually add to our reserves through acquisitions and through development. Since we do not reinvest a material portion of our cash flow, our success is, in part, dependent on our ability to raise capital from time to time by selling additional Common Shares. Shareholders will suffer dilution as a result of these offerings if, for example, the cash flow, production or reserves from the acquired assets do not reflect the additional number of Common Shares issued to acquire those assets. Shareholders may also suffer dilution in connection with future issuances of Common Shares to effect acquisitions.
  Changes in market-based factors may adversely affect the trading price of the Common Shares.
  The market price of our Common Shares is sensitive to a variety of market based factors including, but not limited to, commodity prices, interest rates, foreign exchange rates and the comparability of the Common Shares to other yield-oriented securities. Any changes in these market-based factors may adversely affect the trading price of the Common Shares.
  Certain Risks for United States and other non-resident Shareholders
  The ability of investors resident in the United States to enforce civil remedies is limited.
  Most of our directors and officers and the representatives of the experts who provide services to us (such as our auditors and our independent reserve engineers), and all or a substantial portion of our assets and the assets of such persons are located outside the United States. As a result, it may be difficult for investors in the United States to effect service of process within the United States upon such directors, officers and representatives of experts who are not residents of the United States or to enforce against them judgments of the United States courts based upon civil liability under the United States federal securities laws or the securities laws of any state within the United States. There is doubt as to the enforceability in Canada against us or any of our directors, officers or representatives of experts who are not residents of the United States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the United States federal securities laws or securities laws of any state within the United States.
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  Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States.
  We report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.
  DIVIDENDS
  The Corporation has established a dividend policy of paying monthly dividends to Shareholders. An objective of the Corporation's dividend policy is to provide Shareholders with relatively stable and predictable monthly dividends. An additional objective is to retain a portion of cash flow to fund ongoing development and optimization projects designed to enhance the sustainability of the Corporation's cash flow.
  The amount of cash dividends to be paid on the Common Shares, if any, will be subject to the discretion of the board of directors and may vary depending on a variety of factors, including the prevailing economic and competitive environment, results of operations, fluctuations in working capital, the price of oil and gas, the taxability of Crescent Point, Crescent Point's ability to raise capital, the amount of capital expenditures and other conditions existing from time to time. There can be no guarantee that Crescent Point will maintain its dividend policy.
  Although the Corporation strives to provide Shareholders with stable and predictable cash flows, the percentage of cash flow from operations paid to Shareholders each month may vary according to a number of factors, including, fluctuations in resources prices, exchange rates and production rates, reserves growth, the size of development drilling programs and the portion thereof funded from cash flow and the overall level of debt of the Corporation.
  The agreements governing the Credit Facilities provide that distributions to Shareholders are not permitted if the Corporation is in default of such Credit Facilities or the payment of such distribution would cause an event of default.
  In 2013, the Corporation's payout ratio on a per Common Share diluted basis was 52%.
  The following table sets forth the amount of monthly cash dividends paid per Common Share by the Corporation for the periods indicated.
  Dividend per Common ShareJanuary 2011 - December 2011
$0.23January 2012 - December 2012
$0.23January 2013 - December 2013
$0.23
  The Corporation pays cash dividends on the 15th day of each month (or the first business day thereafter) to Shareholders of record on the immediately preceding dividend record date.
 
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  MARKET FOR SECURITIES
  The outstanding Common Shares are traded on the TSX and the NYSE under the trading symbol "CPG". The following tables set forth the price range and trading volume of the Common Shares as reported by the TSX and NYSE for the periods indicated.
  TSX
High ($)
Low ($)
Volume (000's)2013January
40.05
35.93
34,800February
39.60
38.06
20,044March
39.99
37.91
22,707April
38.74
34.53
26,709May
38.97
37.21
21,618June
37.50
35.25
24,935July
39.79
35.28
24,498August
39.85
37.73
23,466September
39.32
37.22
19,689October
40.98
37.93
19,784November
41.24
39.19
18,154December
41.60
39.73
20,3522014January
41.14
37.85
24,709February
39.59
37.32
20,533
 
 NYSE
High (US$)
Low (US$)
Volume (000's)2014January (22-31)
38.36
34.18
461February
35.92
33.72
956
 
  CONFLICTS OF INTEREST
  Circumstances may arise where members of the board of directors or officers of the Corporation are directors or officers of corporations which are in competition to the interests of the Corporation. No assurances can be given that opportunities identified by such board members or officers will be provided to the Corporation. In accordance with the ABCA, a director or officer who is a party to a material contract or proposed material contract with the Corporation or is a director or an officer of or has a material interest in any person who is a party to a material contract or proposed material contract with the Corporation shall disclose to the Corporation the nature and extent of the director's or officer's interest. In addition, a director shall not vote on any resolution to approve a contract of the nature described except in limited circumstances. Management of the Corporation is not aware of any existing or potential material conflicts of interest between the Corporation or a subsidiary of the Corporation and a director or officer of the Corporation or any other subsidiary of the Corporation.
  Mr. Greg Turnbull, a director of the Corporation, is a partner of McCarthy Tétrault LLP and Mr. Mark Eade, an officer of the Corporation, is a partner of Norton Rose Fulbright Canada LLP, both law firms that provide services to the Corporation and its subsidiaries. The board of directors of the Corporation do not believe that any of the activities undertaken by either of Messrs. Turnbull or Eade or by McCarthy Tétrault LLP or Norton Rose Fulbright Canada LLP interfere, or could be perceived to interfere, in any material way with their ability to act with a view to the best interests of the Corporation.
  LEGAL PROCEEDINGS
  There are no outstanding legal proceedings material to the Corporation to which we are a party or in respect of which any of our properties are subject, nor are any such proceedings known to be contemplated.
  - 71 -
  AUDIT COMMITTEE
  General
  The Corporation has established an Audit Committee (the "Audit Committee") comprised of three members: Gerald A. Romanzin (Chair), D. Hugh Gillard and Peter N. Bannister, each of whom is considered "independent" and "financially literate" within the meaning of Multilateral Instrument 52-110 – Audit Committees.
  Mandate of the Audit Committee
  The mandate of the Audit Committee is to assist the board or directors of the Corporation in its oversight of the integrity of the financial and related information of the Corporation and their subsidiaries and related entities, including the consolidated financial statements, internal controls and procedures for financial reporting and the processes for monitoring compliance with legal and regulatory requirements. In doing so, the Audit Committee oversees the audit efforts of our external auditors and, in that regard, is empowered to take such actions as it may deem necessary to satisfy itself that our external auditors are independent of us. It is the objective of the Audit Committee to have direct, open and frank communications throughout the year with management, other Committee chairmen, the external auditors, and other key committee advisors or the Corporation's staff members, as applicable.
  The Audit Committee's function is oversight. Management of the Corporation is responsible for the preparation, presentation and integrity of the consolidated financial statements of the Corporation. Management is responsible for maintaining appropriate accounting and financial reporting principles and policies and internal controls and procedures that provide for compliance with accounting standards and applicable laws and regulations.
  While the Audit Committee has the responsibilities and powers set forth above, it is not the duty of the Audit Committee to plan or conduct audits or to determine whether the consolidated financial statements of the Corporation are complete and accurate and are in accordance with generally accepted accounting principles. This is the responsibility of management and the external auditors, on whom the members of the Committee are entitled to rely upon in good faith.
  The Audit Committee Terms of Reference are attached hereto as Appendix A.
  Relevant Education and Experience of Audit Committee Members
  The following is a brief summary of the education or experience of each member of the Audit Committee that is relevant to the performance of his responsibilities as a member of the Audit Committee, including any education or experience that has provided the member with an understanding of the accounting principles used by us to prepare our annual and interim consolidated financial statements.
  - 72 -
  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, Porto Energy Corp. and of Trimac Transportation Ltd. 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 of Crescent Point since 2004.Formerly, Mr. Romanzin served as a director of FET Resources Ltd., Ketch Resources Ltd., Ketch Resources Trust, Cadence Energy Inc., Kereco Energy Ltd. and Flowing Energy Corporation. Mr. Romanzin is a chartered accountant has held a number of senior roles with the Alberta Stock Exchange and, subsequent to its conversion, with the TSX Venture Exchange.He is a member of the Institute of Chartered Accountants of Alberta and holds a Bachelor of Commerce degree from the University of Calgary.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 and Amoco Canada. Mr. Gillard has been on the board of Crescent Point since 2003.Mr. Gillard has served as director of the board of Petrowest Energy Services Trust (chairman), 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 chairman of the board of Hospice Calgary and is currently a trustee of the Calgary Zoo.He holds a Bachelor of Commerce degree from the University of Calgary and is a graduate of the Stanford Business School Executive Program.Peter N. Bannister

Peter Bannister is Chairman of Crescent Point's board of directors and is president of Destiny Energy Inc., a private oil and gas company. He has been on the board of Crescent Point and its predecessor since 2003. Mr. Bannister has worked in the oil and gas industry since 1982, having held a variety of roles with companies such as Mission Oil and Gas Inc., StarPoint Energy Inc., Impact Energy Inc., Startech Energy, Boomerang Resources Ltd., Laurasia Resources Ltd. and Sproule Associates Ltd.Mr. Bannister is a member of APEGA and serves on the board of directors of Cequence Energy Ltd. and New Star Energy Ltd. Formerly, he was a director of 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 Science degree in geology with a minor in economics.
  External Auditor Services Fees
  For services provided to the Corporation and its subsidiaries the years ended December 31, 2013 and 2012 PricewaterhouseCoopers LLP billed approximately $812,281 and $863,305, respectively, as detailed below:
  Year ended December 312013


2012PricewaterhouseCoopersAudit fees

$
772,418


$
584,805Audit-related fees(1)

$
20,300


$
278,500Tax Fees

$
-


$
-All other fees

$
19,563


$
-Total

$
812,281


$
863,305
  Note:
 (1)           Fees include the costs related to public financings and related reporting to regulators.
  The Chairman of the Audit Committee has the authority to pre-approve non-audit services which may be required from time to time.
  - 73 -
 Audit Fees were paid, or are payable, for professional services rendered by the auditors for the audit of the annual financial statements and reviews of thequarterly financial statements, as well asservices provided in connection with statutory and regulatory filings or engagements. Audit-Related Fees were paid for professional services rendered by the auditors for French translation of Crescent Point’s annual and quarterly financial statements and Management’s Discussion and Analysis. All Other Fees were for products or services provided by Crescent Point’s auditors other than those described as Audit Fees and Audit-Related Fees.All services described beside the captions "Audit Fees", "Audit-Related Fees", and "All Other Fees" were approved by the Audit Committee in compliance with paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X under the U.S. Securities and Exchange Act of 1934, as amended (the Exchange Act). None of the fees described above were approved by the Audit Committee pursuant to paragraph (c)(7)(i)(C) of Regulation S-X under the Exchange Act.
 Audit Committee Oversight
  At no time since the commencement of our most recently completed financial year, has a recommendation of the Audit Committee to nominate or compensate an external auditor not been adopted by the board of directors of the Corporation.
  TRANSFER AGENT AND REGISTRARS
  Our auditors are PricewaterhouseCoopers LLP, Chartered Accountants, 3100, 111 – 5th Avenue S.W., Calgary, Alberta, T2P 5L3. The transfer agent and registrar for our Common Shares is Olympia Trust Company in Calgary, Alberta.
  MATERIAL CONTRACTS
  Set out below is the only agreement that may be considered material to us:
  Premium Dividend and Dividend Reinvestment Plan. See "Additional Information Respecting Crescent Point – Premium Dividend and Dividend Reinvestment Plan".
  INTERESTS OF EXPERTS
  PricewaterhouseCoopers LLP, the auditors of the Corporation, has audited the consolidated financial statements of the Corporation for the year ended December 31, 2013, as set forth in the Annual Consolidated Financial Statements of the Corporation. PricewaterhouseCoopers LLP has confirmed that it is independent of the Corporation, in accordance with the relevant rules and related interpretation prescribed by the Institute of Chartered Accountants of Alberta and the rules of the SEC.
  Reserve estimates contained in this AIF are derived from reserve reports prepared by GLJ and Sproule. As of the date hereof, GLJ, as a group and Sproule, as a group, do not beneficially own, directly or indirectly, any Common Shares.
  ADDITIONAL INFORMATION
  Additional financial information is available on SEDAR at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml  and on our website at www.crescentpointenergy.com.
  Additional information including directors' and officers' remuneration and indebtedness, principal holders of the Corporation's securities, options to purchase securities and securities authorized for issuance under equity compensation plans, if applicable, is contained in our information circular in respect of the annual and special meeting of Shareholders held on May 9, 2014. Additional financial information is provided in our comparative consolidated financial statements and management's discussion and analysis for our most recently completed financial year ended December 31, 2013.
 - 74 -
 For additional copies of this AIF please contact:
  Crescent Point Energy Corp.
 2800, 111 – 5th Avenue, S.W.
 Calgary, Alberta
 T2P 3Y6
  Attention: Investor Relations
                          - 75 -
  APPENDIX A
  
  
 AUDIT COMMITTEE TERMS OF REFERENCE
  Corporate Policies & Procedures
 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 the Business 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.
  Public financial reporting and disclosure by the Corporation are fundamental to the Corporation's business and affairs and to its status as a publicly listed enterprise. The objective of the Board's monitoring of the Corporation's financial reporting and disclosure is to gain reasonable assurance of the following (including, where advisable in the achievement of this objective, through appropriate consultation with senior management and the Corporation's external auditors):
  (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.
  The Board is of the view that monitoring of the Corporation's financial reporting and disclosure policies and procedures cannot be reliably met unless the following activities (the "Fundamental Activities") are conducted effectively:
  (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;
  (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.
  To assist the Board in its monitoring of the Corporation's financial reporting and disclosure and to conform to applicable corporate and securities law, the Board has established the Audit Committee (the "Committee") of the Board.
  2.
Role of the Committee
  The role of the Committee is to assist the Board in its oversight of the integrity of the financial and related information of the Corporation, including its consolidated financial statements, the internal controls and procedures for financial reporting and the processes for monitoring compliance with legal and regulatory requirements and to review the independence, qualifications and performance of the external auditor of the Corporation. Management is responsible for establishing and maintaining those controls, procedures and processes and the Committee is appointed by the Board to review and monitor them.
  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
  In contributing to the Committee's discharging of its duties under this mandate, each Member of the Committee shall be entitled to rely in good faith upon:
  - 2 -
  (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
  (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
  In contributing to the Committee's discharging of its duties under Terms of Reference, each Member shall be obliged only to exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. Nothing in these Terms of Reference is intended, or may be construed, to impose on any Member a standard of care or diligence that is in any way more onerous or extensive than the standard to which all Board members are subject. The essence of the Committee's duties is monitoring and reviewing to gain reasonable assurance (but not to ensure) that the Fundamental Activities are being conducted effectively and that the objectives of the Corporation's financial reporting are being met and to enable the Committee to report thereon to the Board.
  II.           Audit Committee Terms of Reference
  These Terms of Reference outline how the Committee will satisfy the requirements set forth by the Board in its mandate.
  1.
Operating Principles
  The Committee shall fulfill its responsibilities within the context of the following principles.
  Committee Values
  The Committee expects the management of the Corporation to operate in compliance with corporate policies; reflecting laws and regulations governing the Corporation; and to maintain strong financial reporting and control processes.
  Communications
  The Committee and its Members expect to have direct, open and frank communications throughout the year with management, other Committee Chairmen, the external auditors, and other key Committee advisors or Company staff members as applicable.
  Delegation
  The Committee may delegate from time to time to any person or committee of persons any of the Committee's responsibilities that may be lawfully delegated.
  Annual Audit Committee Plan
  The Committee, in consultation with management and the external auditors, shall develop an annual Audit Committee plan responsive to the Committee's responsibilities as set out in these Terms of Reference. In addition, the Committee, in consultation with management and the external auditors, shall develop and participate in a process for review of important financial topics that have the potential to impact the Corporation's financial disclosure.
  - 3 -
  The plan will be focused primarily on the annual and interim consolidated financial statements and MD&A of the Corporation; however, the Committee may at its sole discretion, or the discretion of the Board, review such other matters as may be necessary to satisfy the Committee's Terms of Reference.
  Committee Expectations and Information Needs
  The Committee shall communicate its expectations to management and the external auditors with respect to the nature, timing and extent of its information needs. The Committee expects that written materials will be received from management and the external auditors at a reasonable time in advance of meeting dates.
  Access to Independent Advisors
  To assist the Committee in discharging its responsibilities, the Committee may at its discretion, in addition to the external auditors, at the expense of the Corporation, retain one or more persons, firms or corporations having special expertise.
  Reporting to the Board, Shareholders and Others
  The Committee, through its Chair, shall report after each Committee meeting to the Board at the Board's next regular meeting. In addition, the Committee shall prepare a report to shareholders or others, concerning the Committee's activities in the discharge of its responsibilities, when and as required by applicable laws, rules, policies or regulations.
  Evaluation
  The Committee will conduct and present to the Board an annual evaluation of the performance of the Committee and the adequacy of these Terms of Reference and recommend any proposed changes to the Board for approval.
  Access to the Committee
  Representatives of the Auditor and management of the Corporation shall have access to the Committee each in absence of the other.
  The External Auditors
  The Committee expects that, in discharging their responsibilities to the shareholders, the external auditors shall be accountable to the Board through the Committee. The external auditors shall report all material issues or potentially material issues, either specific to the Corporation or to the financial reporting environment in general, to the Committee.
  No Alteration
  No alteration to the roles and responsibilities of the Committee shall be effective without the approval of the Board.
  - 4 -
 
 2.
Operating Procedures
  Meetings
  The Committee shall meet at least four times annually, or more frequently as circumstances dictate. Meetings shall be held at the call of the Chair, upon the request of two (2) Members or at the request of the external auditors.
  Quorum
  A quorum shall be a majority of the Members.
  Notice of Meeting
  Notice of the time and place of every meeting shall be given in writing by any means of transmitted or recorded communication, including facsimile, email or other electronic means that produces a written copy, to each Member of the Committee at least 24 hours prior to the time fixed for such meeting; provided however, that a Member may in any manner waive a notice of the meeting. Attendance of a Member at a meeting constitutes waiver of notice of the meeting, except where a Member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting is not lawfully called.
  Meeting Agenda
  Committee meeting agendas shall be the responsibility of the Chair of the Committee in consultation with other Members, senior management and the external auditors.
  Procedure, Records and Reporting
  Subject to any statute or the articles and by-laws of the Corporation, the Committee shall fix its own procedures at meetings, keep records of its proceedings and report to the Board when the Committee may deem appropriate (but not later than the next regularly scheduled meeting of the Board).
  In Camera Meetings
  At the discretion of the Committee, the Members shall meet in private session with the external auditors and with management only.
  Referral to the Board
  Any matter the Committee does not unanimously approve will be referred to the Board for consideration.
  Secretary
  Unless the Committee otherwise specifies, the Corporate Secretary (or his or her deputee) of the Corporation shall act as Secretary of all meetings of the Committee.
  Acting Chair
  In the absence of the Chair of the Committee, the Members shall appoint an acting Chair.
  Minutes
  - 5 -
  A copy of the minutes of each meeting of the Committee shall be provided to each Member and to each director of the Corporation in a timely fashion.
  3.
Specific Responsibilities and Duties
  To fulfill its responsibilities and duties, the Committee shall:
  Financial Information and Reporting
  (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;
  (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.
  Accounting Policies
  (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.
  Risk and Uncertainty
  (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;
  - 6 -
  (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
  (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.
  Financial Controls and Control Deviations
  (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 Company 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.
  Compliance with Laws and Regulations
  (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.
  - 7 -
 
 Relationship and External Auditors
  (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;
  (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.
  Relationship with Internal Auditor
  (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
  - 8 -
  (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.
  Other Responsibilities and Procedures
  (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.
  III.           Hiring Guidelines for Independent Auditor Employees
  1.
Guidelines
  The Committee has adopted the following guidelines regarding the hiring of any partner, employee, reviewing tax professional or other person providing audit assurance to the external auditor of the Corporation on any aspect of its certification of the Corporation's consolidated financial statements:
  (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
  The Committee will ensure that the head audit partner assigned by the external auditor to the Corporation, as well as the audit partner charged with reviewing the audit of the Corporation, are changed at least every five years.
  3.
Process for Handling Complaints about Accounting Matters
  The Committee will establish the following procedures for the receipt and treatment of any complaint received by the Corporation, including confidential, anonymous submissions by employees of the Corporation, regarding accounting, internal accounting controls or auditing matters and create a summary of any significant investigations regarding such matters:
  - 9 -
  (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.
  - 10 -
  APPENDIX B
  
 
 RESERVES COMMITTEE TERMS OF REFERENCE
  Corporate Policies & Procedures
 1.
Reserves Committee Purpose
  The Reserves Committee (the "Committee") is appointed by the Board of Directors of Crescent Point Energy Corp. (the "Board") to assist the Board in fulfilling its responsibility for the stewardship of Crescent Point Energy Corp. ("Crescent Point") and its subsidiaries or related entities (collectively referred to herein as the "Corporation"). The Committee's primary duties and responsibilities are to assume responsibility for assisting the Board in respect of the annual independent review of Crescent Point's petroleum and natural gas reserves and reporting to the Board in respect thereof.
  2.
Reserves Committee Composition, Procedures and Organization
  The Committee shall consist of at least two directors as determined by the Board, the majority of whom shall be independent (as required by National Instrument 51-101 Standards and Disclosure for Oil and Gas Activities ("NI 51-101")). Committee members shall also meet the independence requirements of the regulatory bodies to which the Corporation may be subject to. The Board shall appoint the members of the Committee and may at any time remove or replace any member of the Committee and may fill any vacancy in the Committee. If a Committee Chair is not designated by the Board, or is not present at a meeting of the Committee, the members of the Committee may designate a chair by majority vote of the Committee membership. The Secretary of the Corporation, shall act as Secretary of the Committee. The quorum for meetings shall be a majority of the members of the Committee present in person or by telephone or other telecommunications device that permits all persons participating in the meeting to speak and to hear each other. The Committee shall meet at least annually at such times and at such locations as may be requested by the chair of the Committee and at such times as any member of the Committee may request.
  3.
Reserves Committee Responsibilities and Duties
  The overall duties and responsibilities of the Committee shall be as follows:
  (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;
  (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.
  - 2 -
 
 Appendix C
 FORM 51-101F2
 REPORT ON RESERVES DATA
 BY
 INDEPENDENT QUALIFIED RESERVES
 EVALUATOR OR AUDITOR
  To the board of directors of Crescent Point Energy Corp. (the "Company"):
  1.
We have evaluated the Company's reserves data as at December 31, 2013. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2013, 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.
  We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).
  3.
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.
  4.
The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2013, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's board of directors:
  Independent Qualified

Reserves Evaluator
Description and Preparation Date of Evaluation Report
Location of Reserves

(Country or Foreign

Geographic Area)Net Present Value of Future Net Revenue

(before income taxes, 10% discount rate - $M)Audited
Evaluated
Reviewed
TotalGLJ Petroleum Consultants
Corporate Evaluation

January 30, 2014
Canada
-
3,057,865
-
3,057,865
 
 5.
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.
  6.
We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.
  7.
Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.
  Executed as to our report referred to above:
  GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada                                                                                                March 11, 2014
  ORIGINALLY SIGNED BY
  Terry L. Aarsby, P. Eng.
 Vice President
  
 
 FORM 51-101F2
 REPORT ON RESERVES DATA
 BY
 INDEPENDENT QUALIFIED RESERVES
 EVALUATOR OR AUDITOR
  To the board of directors of Crescent Point Energy Corp. (the "Company"):
  1.
We have evaluated the Company's reserves data as at December 31, 2013. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2013, 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.
  We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).
  3.
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.
  4.
The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2013, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's board of directors:
  Independent Qualified

Reserves Evaluator
Description and Preparation Date of Evaluation Report
Location of Reserves

(Country or Foreign

Geographic Area)Net Present Value of Future Net Revenue

(before income taxes, 10% discount rate - Cdn. $M)Audited
Evaluated
Reviewed
TotalGLJ Petroleum Consultants
U.S.A. Summary

January 30, 2014
U.S.A.
-
1,559,740
-
1,559,740
 
 5.
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.
  6.
We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.
  7.
Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.
  Executed as to our report referred to above:
  GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada                                                                                                March 11, 2014
  ORIGINALLY SIGNED BY
  Terry L. Aarsby, P. Eng.
 Vice President
  
  FORM 51-101F2
 REPORT ON RESERVES DATA
 BY
 INDEPENDENT QUALIFIED RESERVES
 EVALUATOR OR AUDITOR
  To the board of directors of Crescent Point Energy Corp. (the "Company"):
  1.
We have evaluated the Company's reserves data as at December 31, 2013. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2013, 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.
  We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).
  3.
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.
  4.
The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2013, 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:
  Independent Qualified

Reserves Evaluator or Auditor
Description and Preparation Date of Evaluation Report
Location of Reserves

(Country)Net Present Value of Future Net Revenue

Before Income Taxes (10% Discount Rate)Audited (M$)
Evaluated (M$)
Reviewed (M$)
Total

(M$)Sproule
Evaluation of Certain Saskatchewan P&NG Reserves of Crescent Point Energy Corp., As of December 31, 2013, prepared August 2013 to February 2014
CanadaTotal


Nil
10,972,392
Nil
10,972,392
 
  5.
In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are presented 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.
  6.
We have no responsibility to update the report referred to in paragraph 4 for events and circumstances occurring afters its preparation date.
  7.
Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.
  
  Executed as to our report referred to above:
  Sproule Associates Limited, Calgary, Alberta                                                                                                Dated February 5, 2014
  ORIGINALLY SIGNED BY
  Richard A. Brekke, P. Eng.
 Manager, Engineering and Partner
 
 Vincent K. Hui, P. Eng.
 Petroleum Engineer and Partner
 
 Alec Kovaltchouk, P.Geo.
 Manager, Geoscience and Partner
 
 Ian K. Kirkland, P.Geol.
 Senior Petroleum Geologist and Partner
  Harry J. Helwerda, P. Eng., FEC, FGC (Hon.)
 President & Chief Operating Officer and Director
  - 2 -
  
  Appendix D
  REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
  Management of Crescent Point Energy Corp. (the "Corporation") are responsible for the preparation and disclosure of information with respect to the Corporation's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following:
  (a)
Proved and Proved plus Probable oil and gas reserves estimated as at December 31, 2013 using forecast prices and costs; and
  (b)
the related estimated future net revenue.
  GLJ Petroleum Consultants and Sproule Associates Limited, each an independent qualified reserves evaluator have evaluated the Corporation's reserves data. The reports of the independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report.
  The Reserves Committee of the board of directors of the Corporation has:
  (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.
  The Reserves Committee of the board of directors has reviewed the Corporation's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Reserves Committee, approved:
  (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.
  Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.
  "Scott Saxberg"

"C. Neil Smith"SCOTT SAXBERG

C. NEIL SMITHPresident and Chief Executive Officer

Chief Operating Officer"Gerald A. Romanzin"

"Peter Bannister"GERALD A. ROMANZIN

PETER BANNISTERDirector

Director
 
  March 11, 2014