exh99_1.htm

CRESCENT POINT ENERGY CORP.

ANNUAL INFORMATION FORM

For the Year Ended December 31, 2014

Dated March 10, 2015

TABLE OF CONTENTS 

SPECIAL NOTES TO READER	1

GLOSSARY	3

SELECTED ABBREVIATIONS	6

CURRENCY OF INFORMATION	7

OUR ORGANIZATIONAL STRUCTURE	7

GENERAL DEVELOPMENT OF THE BUSINESS OF THE CORPORATION	9

DESCRIPTION OF OUR BUSINESS	12

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	17

ADDITIONAL INFORMATION RESPECTING CRESCENT POINT	39

INDUSTRY CONDITIONS	48

RISK FACTORS	61

DIVIDENDS	74

MARKET FOR SECURITIES	75

CONFLICTS OF INTEREST	76

LEGAL PROCEEDINGS	76

AUDIT COMMITTEE	76

TRANSFER AGENT AND REGISTRARS	79

MATERIAL CONTRACTS	79

INTERESTS OF EXPERTS	79

ADDITIONAL INFORMATION	79

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, within the meaning of the United States Private Securities Litigation Reform Act of 1995 and forward-looking information within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). 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;

·	long-term target 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", "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.

Presentation of our Reserve and Resource Information

Current SEC reporting requirements permit oil and gas companies to disclose Probable Reserves, in addition to the required disclosure of Proved Reserves. Under current SEC requirements, net quantities of reserves are required to be disclosed, which requires disclosure on an after royalties basis and does not include reserves relating to the interests of others. For a description of these and additional differences between Canadian and US standards of reporting reserves, see "Risk Factors — Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States".

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 10, 2015 for the year ended December 31, 2014.

"Alston" means Alston Energy Inc.

"CanEra" means CanEra Energy Corp.

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

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

"Conversion Arrangement" means the plan of arrangement 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.

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"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, 2014.

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

"NYSE" means the New York Stock Exchange.

"OPEC" means Organization of the Petroleum Exporting Countries.

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

"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.

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

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

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

"Shelter Bay" means Shelter Bay Energy Inc.

"Sproule" means Sproule Associates Limited.

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

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

"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.

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

"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 Gas
bbl	barrel	Mcf	thousand cubic feet
bbls	barrels	Mcf/d	thousand cubic feet per day
bbl/d	barrels per day	Mcfe	thousand cubic feet of gas equivalent converting one barrel of oil to 6 Mcf of natural gas equivalent
Mbbls	thousand barrels	MMcf MMcf/d	million cubic feet million cubic feet per day
NGLs	natural gas liquids	MMBTU	million British Thermal Units
		GJ	gigajoule

Other
AECO	the natural gas storage facility located at Suffield, Alberta
boe	barrel of oil equivalent of natural gas and crude oil on the basis of 1 boe for 6 (unless otherwise stated) Mcf of natural gas (this conversion factor is an industry accepted norm and is not based on either energy content or current prices)
boe/d	barrel of oil equivalent per day
m³	cubic metres
M$	thousand dollars
Mboe	thousand barrels of oil equivalent
MMboe	million barrels of oil equivalent
MW	mega watt
MW/h	mega watt per hour
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade

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CURRENCY OF INFORMATION

The information set out in this AIF is stated as at December 31, 2014 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 2000, 585 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1 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 of the 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/Formation
CPHI	100%	Alberta

Partnership	100%	Alberta

CPUSH	100%	Nevada

CPEUS	100%	Delaware

CPLux	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 10, 2015. 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.

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 Crescent Point 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.

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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 1,672,109 Crescent Point Common 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 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.

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.

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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".

On March 17, 2014, Robert Heinemann was appointed as a director of the Corporation.

On May 9, 2014, the Corporation adopted a share dividend plan. See "Share Dividend Plan".

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

On June 12, 2014, the Corporation completed the acquisition of the Viking Assets in Saskatchewan for total consideration of approximately $331.7 million comprised of approximately 7.6 million Crescent Point Common Shares less net cash received on customary closing adjustments of $12.0 million.

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

On July 30, 2014, the Corporation completed the acquisition of certain assets in the Viewfield Bakken and Flat Lake resource plays in southeast Saskatchewan for cash consideration of $99.1 million.

On August 12, 2014, the total amount available under the Company’s syndicated credit facility and operating credit facility was increased to a total of $2.6 billion and the term was extended to June 10, 2017.

On August 13, 2014, the Corporation closed the acquisition of all issued and outstanding common shares of T. Bird, a private oil and gas company with properties in southeast Saskatchewan and Manitoba. Total consideration was approximately $85.7 million, comprised of 1,482,477 Crescent Point Common Shares, cash consideration of $0.3 million and assumed debt.

On September 23, 2014, the Corporation announced the closing of its equity offering of 18,435,000 Common Shares at $43.40 per Common Share for aggregate gross proceeds of approximately $800 million.

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On September 30, 2014, the Corporation completed the acquisition of approximately 3,300 boe/d of conventional oil production and 76 net sections of land that are contiguous to Crescent Point’s existing land base in southeast Saskatchewan and Manitoba. Total consideration for the assets included certain Crescent Point assets in Creelman, Saskatchewan and net cash consideration of $374.3 million.

On November 4, 2014, Laura Cillis was appointed as a director of the Corporation.

On November 4, 2014, the Corporation announced the passing of Ken Cugnet. Mr. Cugnet served as a director of the Corporation since 2003.

2015

On March 10, 2015, the total amount available under the Company’s syndicated credit facility and operating credit facility was increased to a total of $3.6 billion and the term was extended to June 8, 2018.

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 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. The primary assets of the Corporation are currently the shares in CPHI, interest in the Partnership and shares in CPUSH and, indirectly, in CPEUS.

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 and Manitoba and the states of North Dakota, Montana, Colorado 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.

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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.

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 3½ 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 2014 amounted to approximately 59% of annual production, net of royalties, consisting of approximately 61% of annual crude oil production and approximately 32% 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 $104.8 million in 2014.

The following table summarizes our commitments under all hedging agreements as at December 31, 2014.

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Financial WTI Crude Oil Derivative Contracts – Canadian Dollar

Term	Volume (bbls/d)	Average Swap Price (Cdn$/bbl)	Average Collar Sold Call Price (Cdn$/bbl)	Average Collar Bought Put Price (Cdn$/bbl)
2015 Weighted Average(1)	57,816	90.69	98.18	87.69
2016 Weighted Average(2)	25,981	86.68	-	-
January - June 2017 Weighted Average	4,492	82.87	-	-

Note:

(1)	Includes 500 bbls/d which can be extended at the option of the counterparty for calendar 2016 at an average swap price of $95.00/bbl.

(2)	Includes 1,500 bbls/d which can be extended at the option of the counterparty for calendar 2017 at an average swap price of $95.27/bbl.

Financial AECO Natural Gas Derivative Contracts – Canadian Dollar

Term	Contract	Volume (GJ/d)	Average Swap Price (Cdn$/GJ)
2015 Weighted Average	Swap	32,767	3.60
2016 Weighted Average	Swap	32,005	3.57
2017 Weighted Average	Swap	16,425	3.55
January - March 2018 Weighted Average	Swap	11,000	3.55

Financial Power Derivative Contracts – Canadian Dollar

Term	Contract	Volume (MW/h)	Fixed Rate (Cdn$/MW/h)
2015	Swap	3.0	49.50
2016	Swap	3.0	50.00
2017	Swap	3.0	52.50

Financial Interest Rate Derivative Contracts – Canadian Dollar

Term	Contract	Notional Principal (Cdn$)	Fixed Annual Rate (%)
January 2015 - May 2015	Swap	25,000,000	2.90
January 2015 - May 2015	Swap	25,000,000	3.50
January 2015 - May 2015	Swap	50,000,000	3.09
January 2015 - June 2015	Swap	50,000,000	3.78
January 2015 - July 2015	Swap	50,000,000	3.63

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 2015 - March 2015	Swap	37,500,000	4.71	38,287,500	5.24
January 2015 - April 2016	Swap	52,000,000	3.93	50,128,000	4.84
January 2015 - March 2017	Swap	67,500,000	5.48	68,917,500	5.89
January 2015 - April 2018	Swap	31,000,000	4.58	29,884,000	5.32
January 2015 - June 2018	Swap	20,000,000	2.65	20,350,000	3.52
January 2015 - May 2019	Swap	68,000,000	3.39	66,742,000	4.53
January 2015 - March 2020	Swap	155,000,000	6.03	158,255,000	6.45
January 2015 - April 2021	Swap	82,000,000	5.13	79,048,000	5.83
January 2015 - June 2021	Swap	52,500,000	3.29	56,348,250	3.59
January 2015 - May 2022	Swap	170,000,000	4.00	166,855,000	5.03
January 2015 - June 2023	Swap	270,000,000	3.78	274,725,000	4.32
January 2015 - June 2024	Swap	257,500,000	3.75	276,374,750	4.03

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

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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. Crescent Point owns and operates four 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.

Crescent Point also enters into physical delivery and derivative WTI price differential contracts which manage the spread between US$ WTI and various stream prices. The Corporation manages physical delivery contracts on a month-to-month spot and term contract basis. From January to December 2014, approximately 18,400 bbls/d of oil production was contracted with fixed price differentials off WTI. As of December 31, 2014, approximately 8,600 bbls/d of oil production from January to December 2015 and approximately 2,500 bbls/d of oil production from January 2016 to December 2019 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 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 80 purchasers and its financial hedging portfolio consists of 17 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.

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 35 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 81% of our oil volumes are sold in Saskatchewan, 12% in the U.S. and 7% in Alberta. Approximately 56% of our natural gas volumes are sold in Saskatchewan, 25% in Alberta and 19% in the U.S.

Revenue Sources

For 2014, our commodity production mix was approximately 91% oil and NGLs and 9% natural gas.

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

For Year Ended	Crude Oil and NGLs	Natural Gas
2014	97%	3%
2013	97%	3%
2012	98%	2%

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, 2014, the Corporation had 433 employees and 91 consultants at our head office in Calgary and 69 employees and 13 consultants at our Denver office. In the field we had 448 field employees and 110 consultants in Canada and 57 field employees and 2 consultants in the US.

Reorganizations

On March 15, 2012, the Corporation closed the Wild Stream Arrangement for total consideration of $610.2 million, comprised of 12,082,012 Crescent Point 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 Crescent Point 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.

On June 20, 2012, the Corporation closed the Cutpick Arrangement for total consideration of approximately $398.3 million, comprised of 7,556,960 Crescent Point 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.

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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.

On May 15, 2014, the Corporation closed the CanEra Arrangement for total consideration of approximately $1.1 billion, comprised of 12,928,091 Crescent Point Common Shares, cash consideration of approximately $191.8 million and assumed debt. The acquisition increased the Corporation's Torquay land position in southeast Saskatchewan.

Social and Environmental Policies

The Corporation has a voluntary reclamation fund to fund future decommissioning costs and environmental emissions reduction costs. 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. From January 1, 2014 to March 31, 2014, we allocated $1.10 per boe of production. From April 1, 2014 to December 31, 2014, we allocated $1.00 per boe of production and made an additional lump sum contribution of $7.8 million. 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, 2014 contained in the consolidated report of GLJ dated March 9, 2015 (the "Crescent Point Reserve Report"). The Crescent Point Reserve Report evaluated, as at December 31, 2014, 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, 2015 forecast price and cost assumptions. GLJ evaluated approximately 38 percent of the assigned total Proved plus Probable reserves and 29 percent of the total Proved plus Probable value discounted at 10 percent. Sproule evaluated approximately 62 percent of the assigned total Proved plus Probable reserves and 71 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 as well as the Shaunavon and Saskatchewan Viking 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.

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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				Total
Reserves 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 Producing
Canada		240,900		214,518		515		519		17,781		16,543		101,195		94,791		276,061		247,379
United States		25,246		20,683		-		-		1,656		1,360		21,775		18,042		30,530		25,051
Total		266,145		235,201		515		519		19,436		17,904		122,970		112,833		306,591		272,430
Proved Developed Non-Producing
Canada		9,845		8,883		367		347		737		665		7,592		6,830		12,214		11,033
United States		904		765		-		-		78		67		953		870		1,141		977
Total		10,749		9,648		367		347		815		732		8,545		7,700		13,355		12,011
Proved Undeveloped
Canada		140,082		129,244		132		119		13,647		12,469		59,460		55,642		163,772		151,105
United States		35,742		29,256		-		-		2,695		2,205		35,813		29,467		44,406		36,372
Total		175,824		158,500		132		119		16,343		14,673		95,273		85,109		208,178		187,476
Total Proved
Canada		390,827		352,644		1,014		985		32,165		29,677		168,247		157,263		452,047		409,517
United States		61,891		50,704		-		-		4,429		3,632		58,540		48,379		76,077		62,400
Total		452,719		403,349		1,014		985		36,594		33,309		226,788		205,642		528,124		471,917
Total Probable
Canada		197,710		175,663		739		673		15,973		14,504		89,906		83,331		229,406		204,729
United States		41,158		33,503		-		-		2,741		2,226		35,744		29,228		49,856		40,601
Total		238,868		209,166		739		673		18,713		16,730		125,650		112,560		279,262		245,329
Total Proved Plus Probable
Canada		588,537		528,307		1,753		1,659		48,137		44,181		258,153		240,595		681,453		614,246
United States		103,050		84,207		-		-		7,169		5,859		94,284		77,607		125,933		103,000
Total		691,587		612,514		1,753		1,659		55,307		50,040		352,437		318,202		807,386		717,246

Note:

(1)	Numbers may not add due to rounding.

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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 Producing
Canada	12,548,106	9,009,167	7,091,149	5,881,998	5,048,598	10,786,101	7,800,752	6,179,074	5,153,480	4,444,004
United States	636,887	658,180	565,695	485,356	424,201	636,887	658,180	565,695	485,356	424,201
Total	13,184,993	9,667,348	7,656,844	6,367,353	5,472,799	11,422,988	8,458,933	6,744,769	5,638,836	4,868,205
Proved Developed Non-Producing
Canada	504,862	384,276	308,232	256,641	219,646	372,174	281,728	224,791	186,194	158,540
United States	33,722	23,855	17,815	13,853	11,103	33,722	23,855	17,815	13,853	11,103
Total	538,585	408,131	326,047	270,494	230,749	405,897	305,583	242,606	200,047	169,643
Proved Undeveloped
Canada	5,501,085	3,569,425	2,421,538	1,688,174	1,194,406	3,978,028	2,475,748	1,587,208	1,023,177	646,819
United States	1,100,064	589,940	320,124	164,373	68,449	1,078,959	581,906	316,915	163,034	67,868
Total	6,601,149	4,159,365	2,741,662	1,852,547	1,262,855	5,056,987	3,057,654	1,904,123	1,186,211	714,687
Total Proved
Canada	18,554,053	12,962,869	9,820,919	7,826,812	6,462,649	15,136,303	10,558,228	7,991,074	6,362,851	5,249,363
United States	1,770,674	1,271,975	903,634	663,582	503,753	1,749,569	1,263,941	900,425	662,243	503,172
Total	20,324,727	14,234,844	10,724,553	8,490,394	6,966,402	16,885,872	11,822,170	8,891,498	7,025,094	5,752,535
Total Probable
Canada	12,061,013	7,111,756	4,800,540	3,507,910	2,700,440	8,932,723	5,217,582	3,481,591	2,511,432	1,906,794
United States	2,046,363	1,073,240	653,243	437,219	311,525	1,274,929	680,407	434,916	307,611	230,585
Total	14,107,376	8,184,996	5,453,782	3,945,129	3,011,965	10,207,652	5,897,990	3,916,507	2,819,042	2,137,379
Total Proved Plus Probable
Canada	30,615,066	20,074,624	14,621,458	11,334,723	9,163,089	24,069,026	15,775,811	11,472,664	8,874,283	7,156,157
United States	3,817,037	2,345,216	1,556,877	1,100,801	815,278	3,024,497	1,944,348	1,335,340	969,854	733,757
Total	34,432,103	22,419,840	16,178,335	12,435,523	9,978,368	27,093,523	17,720,159	12,808,005	9,844,137	7,889,914

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$)	Future Net Revenue After Income Taxes (M$)
Proved
Canada	38,748,064	3,976,169	11,891,845	3,843,436	482,561	18,554,053	3,417,750	15,136,303
United States	6,464,830	1,586,551	2,100,052	958,553	48,999	1,770,674	21,105	1,749,569
Total	45,212,893	5,562,721	13,991,897	4,801,989	531,560	20,324,727	3,438,855	16,885,872
Proved Plus Probable
Canada	61,130,468	6,497,012	17,966,906	5,461,109	590,375	30,615,066	6,546,040	24,069,026
United States	11,485,016	2,851,236	3,316,282	1,433,018	67,443	3,817,037	792,540	3,024,497
Total	72,615,484	9,348,249	21,283,188	6,894,127	657,817	34,432,103	7,338,579	27,093,523

Note:

(1)	Numbers may not add due to rounding.

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Future Net Revenue by Production Group

	Future Net Revenue Before Income Taxes(3) (Discounted at 10% per year)	Percentage	Unit Value
	(M$)	(%)	($/boe)	($/Mcfe)
Proved
CANADA
Light and Medium Oil(1)	9,785,421	99.6	24.18	4.03
Heavy Oil(1)	15,614	<1	15.29	2.55
Natural Gas(2)	19,884	<1	5.31	0.88
Total Canada	9,820,919	100	23.98	4.00
UNITED STATES
Light and Medium Oil(1)	903,634	100	14.48	2.41
Heavy Oil(1)	-	-	-	-
Natural Gas(2)	-	-	-	-
Total United States	903,634	100	14.48	2.41
TOTAL
Light and Medium Oil(1)	10,689,055	99.7	23.36	3.89
Heavy Oil(1)	15,614	<1	15.29	2.55
Natural Gas(2)	19,884	<1	5.31	0.88
Total Proved	10,724,553	100	22.73	3.79

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 Probable
CANADA
Light and Medium Oil(1)	14,559,460	99.6	23.98	4.00
Heavy Oil(1)	29,438	<1	16.74	2.79
Natural Gas(2)	32,561	<1	5.98	1.00
Total	14,621,458	100	23.80	3.97
UNITED STATES
Light and Medium Oil(1)	1,556,877	100	15.12	2.52
Heavy Oil(1)	-	-	-	-
Natural Gas(2)	-	-	-	-
Total	1,556,877	100	15.12	2.52
TOTAL
Light and Medium Oil(1)	16,116,336	99.6	23.12	3.85
Heavy Oil(1)	29,438	<1	16.74	2.79
Natural Gas(2)	32,561	<1	5.98	1.00
Total Proved Plus Probable	16,178,335	100	22.56	3.76

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, 99.7% 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, 99.6% of the revenue is from light and medium oil, less than 1% from heavy oil, and less than 1% from natural gas.

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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.

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.

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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

·	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.

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

(e)

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

(i)

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

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

(iii)

dry hole contributions and bottom hole contributions;

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

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

(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):

- 23 -

(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.

(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.

- 24 -

(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:

(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.

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(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.

(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, 2014 in estimating our reserves data using forecast prices and costs.

Year	Natural Gas		Crude Oil			NGLs
	Henry 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)
Forecast
2015	3.31	3.31	62.50	64.71	69.24	52.91	19.63	2.0	0.850
2016	3.75	3.77	75.00	80.00	85.60	60.80	32.00	2.0	0.875
2017	4.00	4.02	80.00	85.71	91.71	65.14	38.57	2.0	0.875
2018	4.25	4.27	85.00	91.43	97.83	69.49	41.14	2.0	0.875
2019	4.50	4.53	90.00	97.14	103.94	73.83	43.71	2.0	0.875
2020	4.75	4.78	95.00	102.86	110.06	78.17	46.29	2.0	0.875
2021	5.00	5.03	98.54	106.18	113.62	80.70	47.78	2.0	0.875
2022	5.25	5.28	100.51	108.31	115.89	82.31	48.74	2.0	0.875
2023	5.50	5.53	102.52	110.47	118.20	83.96	49.71	2.0	0.875
2024	5.68	5.71	104.57	112.67	120.56	85.63	50.70	2.0	0.875
2025+	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	2.0	0.875

For the year ended December 31, 2014, the average realized sales prices before hedging were $89.29/bbl for light and medium oil, $82.39/bbl for heavy oil, $46.07/bbl for NGLs and $4.95/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, 2014 against such reserves as at January 1, 2014 based on forecast price and cost assumptions.

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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 + Probable
January 1, 2014(1)	324,675	167,553	492,228	1,274	672	1,947	15,522	6,903	22,425
Discoveries	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	34,984	19,671	54,654	-	-	-	2,655	2,191	4,846
Technical Revisions	11,905	(20,801)	(8,896)	(160)	64	(96)	15,479	6,381	21,860
Acquisitions	56,986	30,379	87,365	-	-	-	725	505	1,230
Dispositions	(53)	(25)	(78)	-	-	-	(6)	(3)	(8)
Economic Factors	1,217	934	2,150	-	2	2	(14)	(6)	(20)
Production	(38,886)	-	(38,886)	(100)	-	(100)	(2,194)	-	(2,194)
December 31, 2014(2)	390,827	197,710	588,537	1,014	739	1,753	32,165	15,973	48,137

CANADA	Associated and Non-Associated Gas (Natural Gas) (MMcf)			BOE (Mboe)
Factors	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
January 1, 2014(1)	172,040	89,661	261,701	370,145	190,072	560,217
Discoveries	-	-	-	-	-	-
Extensions and Improved Recovery	11,264	7,787	19,049	39,516	23,158	62,674
Technical Revisions	(2,006)	(12,597)	(14,602)	26,888	(16,454)	10,434
Acquisitions	9,977	5,689	15,666	59,373	31,832	91,206
Dispositions	(32)	(15)	(47)	(64)	(30)	(94)
Economic Factors	(1,092)	(619)	(1,711)	1,020	827	1,847
Production	(21,903)	-	(21,903)	(44,831)	-	(44,831)
December 31, 2014(2)	168,247	89,906	258,153	452,047	229,406	681,453

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 + Probable
January 1, 2014(1)	52,008	34,343	86,351	-	-	-	3,513	2,318	5,832
Discoveries	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	10,843	5,344	16,187	-	-	-	646	349	994
Technical Revisions	2,921	(2,351)	570	-	-	-	658	30	688
Acquisitions	3,281	3,241	6,522	-	-	-	44	47	92
Dispositions	-	-	-	-	-	-	-	-	-
Economic Factors	(1,794)	581	(1,213)	-	-	-	(93)	(5)	(98)
Production	(5,368)	-	(5,368)	-	-	-	(339)	-	(339)
December 31, 2014(2)	61,891	41,158	103,050	-	-	-	4,429	2,741	7,169

UNITED STATES	Associated and Non-Associated Gas (Natural Gas) (MMcf)			BOE (Mboe)
Factors	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
January 1, 2014(1)	42,608	25,539	68,147	62,623	40,918	103,541
Discoveries	-	-	-	-	-	-
Extensions and Improved Recovery	8,521	4,547	13,068	12,908	6,451	19,359
Technical Revisions	13,307	5,066	18,374	5,797	(1,475)	4,321
Acquisitions	637	677	1,313	3,432	3,401	6,833
Dispositions	-	-	-	-	-	-
Economic Factors	(1,400)	(86)	(1,486)	(2,120)	561	(1,559)
Production	(5,132)	-	(5,132)	(6,562)	-	(6,562)
December 31, 2014(2)	58,540	35,744	94,284	76,077	49,856	125,933

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TOTAL	Light and Medium Oil (Mbbls)			Heavy Oil (Mbbls)			Natural Gas Liquids (Mbbls)
Factors	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
January 1, 2014(1)	376,683	201,896	578,580	1,274	672	1,947	19,035	9,222	28,257
Discoveries	-	-	-	-	-	-	-	-	-
Extensions and Improved Recovery	45,827	25,014	70,840	-	-	-	3,299	2,541	5,839
Technical Revisions	14,826	(23,152)	(8,326)	(160)	64	(96)	16,137	6,411	22,548
Acquisitions	60,267	33,621	93,887	-	-	-	769	553	1,322
Dispositions	(53)	(25)	(78)	-	-	-	(6)	(3)	(8)
Economic Factors	(577)	1,514	937	-	2	2	(107)	(10)	(117)
Production	(44,254)	-	(44,254)	(100)	-	(100)	(2,533)	-	(2,533)
December 31, 2014(2)	452,719	238,868	691,587	1,014	739	1,753	36,594	18,713	55,307

TOTAL	Associated and Non-Associated Gas (Natural Gas) (MMcf)			BOE (Mboe)
Factors	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
January 1, 2014(1)	214,647	115,200	329,848	432,767	230,990	663,758
Discoveries	-	-	-	-	-	-
Extensions and Improved Recovery	19,783	12,334	32,117	52,424	29,609	82,033
Technical Revisions	11,302	(7,530)	3,771	32,685	(17,930)	14,755
Acquisitions	10,614	6,366	16,979	62,805	35,233	98,039
Dispositions	(32)	(15)	(47)	(64)	(30)	(94)
Economic Factors	(2,492)	(705)	(3,197)	(1,100)	1,388	288
Production	(27,036)	-	(27,036)	(51,393)	-	(51,393)
December 31, 2014(2)	226,788	125,650	352,437	528,124	279,262	807,386

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".

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-End
2011	27,772	108,221	145	226	15,260	51,273	1,201	5,407	31,662	122,399
2012	49,472	152,248	183	347	33,277	87,807	1,636	7,640	56,836	174,869
2013	37,482	157,511	39	146	25,491	88,495	1,481	8,867	43,250	181,272
2014	31,264	175,824	-	132	14,771	95,273	5,406	16,343	39,133	208,178

Note:

(1) "First attributed" refers to reserves first attributed at year-end to corresponding fiscal year.

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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-End
2011	22,493	73,204	137	295	11,870	32,184	673	2,726	25,281	81,589
2012	42,350	109,275	63	322	26,525	60,957	1,341	4,432	48,175	124,188
2013	42,447	118,895	8	214	23,412	64,916	1,482	4,985	47,839	134,913
2014	41,979	135,421	-	267	18,753	73,398	5,198	9,602	50,303	157,522

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.

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).

- 29 -

Company Annual Capital Expenditures (M$)
Canada			US		Total
Year	Total Proved	Total Proved Plus Probable	Total Proved	Total Proved Plus Probable	Total Proved	Total Proved Plus Probable
2015	936,906	1,279,597	242,026	270,570	1,178,932	1,550,167
2016	1,014,256	1,328,495	205,378	346,298	1,219,635	1,674,793
2017	748,570	1,134,659	167,161	300,271	915,731	1,434,930
2018	690,288	1,023,317	196,956	266,350	887,244	1,289,667
2019	344,888	540,023	133,566	209,335	478,454	749,358
2020	24,905	55,061	12,749	25,757	37,653	80,819
2021	6,739	6,775	-	13,269	6,739	20,044
2022	6,527	12,487	-	451	6,527	12,938
2023	5,342	6,511	-	-	5,342	6,511
2024	10,518	6,942	717	717	11,235	7,659
2025	3,644	4,613	-	-	3,644	4,613
2026	3,190	4,241	-	-	3,190	4,241
Subtotal(1) Remainder	3,795,773 47,663	5,402,721 58,388	958,553 -	1,433,018 -	4,754,326 47,663	6,835,739 58,388
Total(1) 10% Discounted	3,843,436 3,120,120	5,461,109 4,412,065	958,553 776,411	1,433,018 1,144,779	4,801,989 3,896,531	6,894,127 5,556,843

Note:

(1) Numbers may not add due to rounding.

Company Annual Abandonment Costs (M$)
Canada			US		Total
Year	Total Proved	Total Proved Plus Probable	Total Proved	Total Proved Plus Probable	Total Proved	Total Proved Plus Probable
2015	8,503	7,510	2,561	1,908	11,063	9,419
2016	2,471	1,552	71	28	2,542	1,580
2017	3,688	2,170	206	94	3,894	2,263
2018	5,554	3,728	84	42	5,638	3,770
2019	5,620	2,417	121	32	5,741	2,450
2020	8,188	5,686	395	261	8,583	5,947
2021	7,367	4,911	487	612	7,854	5,524
2022	9,390	4,739	365	321	9,755	5,060
2023	10,298	5,326	394	149	10,692	5,474
2024	12,374	6,221	584	443	12,958	6,664
2025	12,752	9,467	697	376	13,449	9,843
2026	13,894	8,654	924	394	14,818	9,048
Subtotal(1) Remainder	100,098 382,463	62,381 527,993	6,890 42,109	4,660 62,782	106,988 424,572	67,042 590,776
Total(1) 10% Discounted	482,561 107,820	590,375 88,425	48,999 9,271	67,443 7,145	531,560 117,091	657,817 95,571

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 3.55% per annum. We expect to fund our total 2015 capital program with internally generated cash flow and increased debt and, although quarterly fluctuations in funding levels are expected, our objective is to minimize the increase in leverage throughout 2015. Our long-term 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, 2014.

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Crescent Point has continued to focus on the development of large resource play assets in Canada and the United States through improved technology, waterflood implementation and strategic acquisitions. The properties and assets discussed below account for a majority of the reserve bookings prepared by GLJ and Sproule for year-end 2014, 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, accretive and strategic acquisition opportunities, and proved waterflood performance.

Crescent Point spent $539.8 million, or 26 percent, of its 2014 capital development program on its Viewfield Bakken light oil resource property. Crescent Point commissioned the expanded Viewfield gas facility in the second quarter of 2014. The Corporation committed gas volumes from this expanded gas facility to the Mistral Energy Inc. deep-cut facility, which is expected to improve both reserves and financial results of gas production in the area. In Viewfield, the Corporation has the ability to ship more than 45,000 bbls/d by rail representing almost 30 percent of the Corporation's yearly average production guidance for 2015.

At December 31, 2014, the Corporation had converted a total of 96 producing wells to water injection wells in 36 waterflood sections in the Viewfield Bakken oil resource play. Total incremental Proved plus Probable reserve additions attributed to Improved Recovery from waterflood was 4.3 MMboe for 2014. As more injection patterns are established, the waterflood is expected to continue to add Proved reserves, with the potential to also reduce our future overall corporate decline rate. These bookings represent a small portion of the future upside potential reflected in the independent waterflood evaluation performed in 2013.

Crescent Point is now very close to completing the formation of the first unit in the play which will allow the implementation of a more comprehensive waterflood program. Progress continues towards future unitization of the remaining three proposed units.

In 2014, total Proved plus Probable reserves in the Viewfield Bakken resource play grew from 221.4 MMboe to 237.3 MMboe, representing a 7 percent increase over year-end 2013. Technical and development Proved plus Probable reserve additions totalled 27.2 MMboe in 2014. The Corporation has 864 net locations booked to total Proved plus Probable reserves in the Viewfield Bakken resource play as of year-end 2014.

Crescent Point expects to continue to spend significant capital in 2015 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 $408 million for 2015, including drilling approximately 208 (185 net) wells. As in prior years, this program is designed to expand and diversify our facilities, expand waterflood development and develop our large drilling inventory.

Flat Lake Torquay and Bakken Resource Play

The Flat Lake Torquay and Bakken light oil resource play area in southeast Saskatchewan experienced significant growth in reserves and production during 2014 through the drilling of the core assets as well as step-out delineation and successful exploratory drilling. The Corporation’s assets were further enhanced through several successful strategic acquisitions that secured Crescent Point’s position as the predominant owner in the Torquay play.

In 2014, the Corporation spent $328.4 million of its capital program on development and exploration activities in the Flat Lake Torquay and Bakken resource plays. Crescent Point drilled a total of 4 (4.0 net) vertical exploratory stratigraphic wells in order to delineate the resource extent. An additional 58 (57.0 net) horizontal production wells were drilled into the play. The corporation was successful in several strategic acquisitions of both assets and corporate interests focused in the Flat Lake area.

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At year-end 2014, Total Proved plus Probable reserves in the Flat Lake Torquay and Bakken resource plays totalled 33.6 MMboe, up 93 percent from the 17.4 MMboe at year-end 2013. Technical and development Proved plus Probable reserve additions totaled 15.8 MMboe on the combined Torquay and Bakken resource plays. The Corporation has 122 net locations booked to total Proved plus Probable reserves as of year-end 2014.

Crescent Point is planning on spending approximately $188 million in 2015 in the Flat Lake Torquay and Bakken resource play, including drilling approximately 44 (44 net) wells. The Corporation also plans to initiate its first waterflood pilot in the area targeting the Torquay zone.

Shaunavon Resource Play

In 2014, the Corporation continued to develop the medium gravity Upper and Lower Shaunavon oil resource plays through development and infill drilling, as well as using improved technologies and waterflood activities to enhance recoveries. The Corporation is continuing its focus on unitization activities in the area.

Crescent Point spent $473.8 million of its 2014 capital development program in the Shaunavon area representing the largest Shaunavon drilling program to-date. The Corporation continued to experience success using cemented liner completions compared to prior packer completion techniques for horizontal wells. Enhanced efficiencies as well as reduced environmental footprints were recognized due to the introduction of pad locations that allow the Corporation to drill up to three wells per pad, as opposed to one well. Additional emphasis was placed on expansion of waterflood pilots in both the Lower and Upper Shaunavon resource plays. The large oil storage tanks were commissioned in the first quarter of 2014 with total storage capacities of up to 120,000 bbl of marketable crude. This facility provided additional marketing flexibility to the area production. Crescent Point also constructed and commissioned a new oil battery with a processing capacity greater than 9,400 bbls/d, to further facilitate and improve production within the newly created Leitchville North Shaunavon Voluntary Unit.

In 2014, Crescent Point continued to focus on waterflood implementation by increasing the number of water injection wells in the play. By year-end 2014, the Corporation expanded its water injection well count in the Upper and Lower Shaunavon resource plays to 61 injection wells, including 38 active horizontal injection wells.

As of year-end 2014, Crescent Point had booked total Proved plus Probable reserves of 164.4 MMboe in the Shaunavon area, an increase of 7 percent from 153.4 MMboe in 2013, including approximately 19.4 MMboe due to technical and development reserve additions in 2014. The Corporation has 801 net locations booked to total Proved plus Probable reserves as of year-end 2014. The Corporation’s independent evaluator has recognized improved recovery due to waterflood of 0.5 MMboe of total Proved plus Probable reserves for the year.

In 2015, Crescent Point expects to spend approximately $301 million of its capital budget in the Shaunavon area and expects to drill approximately 109 (109 net) wells primarily using the improved cemented liner completion technique. The Corporation plans to continue to expand the waterflood projects within the Lower and Upper Shaunavon zones during the year.

Saskatchewan Viking Light Oil Resource Play

The Viking light oil resource play is a shallow formation that exists in west-central Saskatchewan containing high-quality light oil. Crescent Point is continuing to expand its footprint in the Saskatchewan Viking light oil resource play area through both horizontal drilling and acquisition activities.

The Corporation completed a strategic acquisition of Saskatchewan Viking light oil assets in June, and followed-up with the initiation of a horizontal drilling program in the area. Crescent Point drilled 61 (32.8 net) horizontal wells during 2014 at 100% success. Crescent Point spent $35.6 million of its 2014 capital development program on the Saskatchewan Viking light oil resource play.

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As of year-end 2014, Crescent Point had booked total Proved plus Probable reserves of 21.1 MMboe in the Saskatchewan Viking light oil resource play, an increase from 5.1 MMboe at year-end 2013, including 3.6 MMboe positive technical and development reserve additions in 2014, representing a 314 percent total increase from year-end 2013. The Corporation has 402 net locations booked to total Proved plus Probable reserves as of year-end 2014.

In 2015, Crescent Point expects to spend approximately $135 million of its capital budget in the Saskatchewan Viking light oil resource play, including drilling approximately 149 (137 net) wells.

UNITED STATES

Utah Uinta Basin Resource Play

In 2014 the Corporation continued its development of 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 using both vertical and horizontal drilling techniques. Further resources will be accessed through completing bypassed pay in existing wells and by applying new technologies to the completion designs. Crescent Point is continuing to investigate enhanced recovery techniques and is advancing marketing opportunities for the waxy crude produced from the basin.

In 2014, Crescent Point spent $307.6 million of its capital development program in the area, including 158 (88.5 net) vertical wells and 14 (3.0 net) horizontal wells. The permanent rail-loading site became fully operational during the year, with capacity of approximately 10,000 bbls/d and the capability to expand in the future. This site has expanded the market for the Uinta crude beyond the Salt Lake City refining market. The Corporation also completed a 3-D seismic program covering a large portion of the operated lands in the Randlett area.

Future plans include additional horizontal well tests, 20-acre downspacing pilots and reservoir studies to address the potential for waterflood in the stacked pay zone. It is expected the two currently approved waterflood pilots will commence operations in early 2016.

Since the Ute acquisition, the total Proved plus Probable reserves in the Uinta Basin have grown 60 percent from 55.1 MMboe to 88.4 MMboe in just over two years of ownership. Technical and development Proved plus Probable reserve additions totalled 16.7 MMboe in 2014. The Corporation has 371 net locations booked to total Proved plus Probable reserves as of year-end 2014.

In 2015, Crescent Point expects to spend approximately $154 million in the area, including drilling 72 (36 net) vertical and horizontal wells. Crescent Point continues to advance this early-stage play with vertical drilling, horizontal drilling and waterflood initiatives.

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Oil and Gas Wells

Producing Wells
Area	Oil		Gas
	Gross	Net	Gross	Net
CANADA
Southeast Saskatchewan and Manitoba	5,811	3,815	-	-
Southwest Saskatchewan	1,537	1,194	394	158
Alberta and West Central Saskatchewan	978	724	328	219
TOTAL CANADA	8,326	5,733	722	377
U.S.
North Dakota and Montana	262	57	4	3
Utah	837	415	7	3
TOTAL U.S.	1,099	472	11	6
Total	9,425	6,205	733	383

Non-Producing Wells
Area		Oil	Gas
	Gross	Net	Gross	Net
CANADA
Southeast Saskatchewan and Manitoba	158	124	-	-
Southwest Saskatchewan	13	12	-	-
Alberta and West Central Saskatchewan	17	13	7	6
TOTAL CANADA	188	149	7	6
U.S.
North Dakota and Montana	-	-	-	-
Utah	-	-	-	-
TOTAL U.S.	-	-	-	-
Total	188	149	7	6

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, 2014
	Gross Acres	Net Acres	Net Acres Expiring Within One Year
CANADA
Alberta	499,347	354,282	176,976
Saskatchewan	1,566,030	1,482,873	428,948
Manitoba	173,484	167,477	45,424
Total	2,238,861	2,004,632	651,348
U.S.
Montana	195,906	160,873	49,575
North Dakota	65,783	59,837	17,664
Utah	327,838	132,864	7,468
Colorado	3,966	3,833	-
Total	593,493	357,407	74,707
Total	2,832,354	2,362,039	726,055

The Corporation has no drilling commitments relating to unproved properties.

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Drilling Activity

The following table summarizes the gross and net exploration and development wells in which we participated during the year ended December 31, 2014, in each of Canada and the United States.

	Development Wells		Exploration Wells		Total Wells
	Gross	Net	Gross	Net	Gross	Net
CANADA
Oil wells	619	503	83	75	702	578
Natural Gas wells	-	-	-	-	-	-
Service wells	7	7	-	-	7	7
Stratigraphic test	-	-	6	6	6	6
Dry Holes	-	-	-	-	-	-
Total	626	510	89	81	715	591

	Development Wells		Exploration Wells		Total Wells
	Gross	Net	Gross	Net	Gross	Net
U.S.
Oil wells	149	69	50	31	199	100
Natural Gas wells	-	-	-	-	-	-
Service wells	-	-	-	-	-	-
Stratigraphic test	-	-	-	-	-	-
Dry Holes	-	-	-	-	-	-
Total	149	69	50	31	199	100

For details on the most important current and likely exploration and development activities during 2014, 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	2015	2016	2017
Canada	-	-	-	-
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 9,326 net wells and locations under the Proved reserves category is $531.6 million undiscounted ($117.1 million discounted at 10%), of which a total of $17.5 million is estimated to be incurred in 2015, 2016 and 2017.

Tax Horizon

Crescent Point has tax pools of approximately $9.98 billion at December 31, 2014 to shelter future taxable income. Including the impact of income from the Partnership for the year ended December 31, 2014, the net tax pools remaining are approximately $9.6 billion. Based on this pool balance and the forecast of cash flows using approximately US$54.50 WTI in 2015, approximately US$61.75 in 2016, a 0.79 US$/Cdn$ exchange rate, with a 2015 development capital budget of $1.45 billion, Crescent Point does not expect to be taxable until 2016.

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Costs Incurred(1)

The following table summarizes our property acquisition costs, exploration costs and development costs for the year ended December 31, 2014. The total capital costs were approximately $4.3 billion in 2014.

($000's) Acquisition Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Canada	2,036,290	40,069	243,725	1,445,311
U.S.	91,672	24,960	84,212	322,362
Total	2,127,962	65,029	327,937	1,767,673

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 2015 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
	(bbls/d)	(bbls/d)	(Mcf/d)	(bbls/d)	(boe/d)
CANADA
Southeast Saskatchewan and Manitoba	78,336	-	32,371	8,037	91,768
Southwest Saskatchewan	32,866	-	8,048	198	34,405
Alberta and West Central Saskatchewan	10,547	324	20,297	919	15,174
Total CANADA(1)	121,750	324	60,717	9,154	141,348
U.S.
North Dakota and Montana	3,929	-	2,470	346	4,687
Utah	11,798	-	12,175	699	14,526
Total U.S.(1)	15,726	-	14,645	1,046	19,213
Total(1)	137,476	324	75,362	10,200	160,560

Note:

(1) Numbers may not add due to rounding.

Production in southeast Saskatchewan/Manitoba and southwest Saskatchewan accounts for 57% and 21%, respectively, of the Corporation's Proved production estimate in 2015.

The following table discloses for each product type the gross volume of production estimated by GLJ and Sproule for 2015 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
	(bbls/d)	(bbls/d)	(Mcf/d)	(bbls/d)	(boe/d)
CANADA
Southeast Saskatchewan and Manitoba	89,563	-	36,579	9,190	104,851
Southwest Saskatchewan	39,643	-	9,677	240	41,496
Alberta and West Central Saskatchewan	12,889	342	22,899	1,276	18,323
Total CANADA(1)	142,095	342	69,156	10,706	164,669
U.S.
North Dakota and Montana	4,439	-	2,775	392	5,295
Utah	13,831	-	13,589	771	16,868
Total U.S.(1)	18,270	-	16,364	1,164	22,161
Total(1)	160,365	342	85,520	11,870	186,831

Note:

(1) Numbers may not add due to rounding

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Production in southeast Saskatchewan/Manitoba and southwest Saskatchewan accounts for 56% and 22%, respectively, of the Corporation's total Proved plus Probable production estimate in 2015.

Production History

The following table discloses, on a quarterly and annual basis for the year ended December 31, 2014, 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 Ended
	March 31, 2014	June 30, 2014	Sept. 30, 2014	Dec. 31, 2014	2014
CANADA
Light and Medium Crude Oil (bbls/d)	99,958	104,686	105,424	115,913	106,537
Heavy Crude Oil (bbls/d)	291	297	274	235	274
NGLs (bbls/d)	4,891	5,981	6,550	6,603	6,012
Natural gas (Mcf/d)	56,193	60,553	60,661	62,550	60,009
Total (boe/d)	114,506	121,056	122,358	133,176	122,825
U.S.
Light and Medium Crude Oil (bbls/d)	12,691	13,468	15,544	17,067	14,706
Heavy Crude Oil (bbls/d)	-	-	-	-	-
NGLs (bbls/d)	1,156	912	703	949	929
Natural gas (Mcf/d)	13,365	11,590	15,465	15,782	14,061
Total (boe/d)	16,075	16,312	18,825	20,646	17,979
TOTAL
Light and Medium Crude Oil (bbls/d)	112,650	118,154	120,968	132,979	121,243
Heavy Crude Oil (bbls/d)	291	297	274	235	274
NGLs (bbls/d)	6,046	6,893	7,253	7,553	6,941
Natural gas (Mcf/d)	69,558	72,143	76,126	78,332	74,070
Total (boe/d)	130,580	137,368	141,183	153,822	140,803

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, 2014	June 30, 2014	Sept. 30, 2014	Dec. 31, 2014	2014
CANADA
Prices Received – net of hedging	89.01	94.17	90.09	78.24	87.59
Royalties	(16.57)	(17.34)	(17.02)	(12.33)	(15.72)
Production Costs	(12.67)	(13.45)	(13.94)	(13.84)	(13.50)
Transportation Costs	(2.31)	(2.63)	(2.51)	(2.52)	(2.49)
Netback	57.46	60.75	56.62	49.55	55.88
U.S.
Prices Received – net of hedging	89.54	93.32	88.52	65.11	82.99
Royalties	(21.69)	(23.19)	(22.83)	(15.91)	(20.65)
Production Costs	(17.63)	(14.66)	(11.51)	(11.58)	(13.55)
Transportation Costs	(0.51)	(1.60)	(1.09)	(1.22)	(1.12)
Netback	49.71	53.87	53.09	36.40	47.67
TOTAL
Prices Received – net of hedging	89.07	94.07	89.89	76.56	87.03
Royalties	(17.15)	(18.01)	(17.77)	(12.79)	(16.31)
Production Costs	(13.23)	(13.59)	(13.63)	(13.55)	(13.51)
Transportation Costs	(2.10)	(2.51)	(2.33)	(2.35)	(2.33)
Netback	56.59	59.96	56.16	47.87	54.88

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Prices Received, Royalties, Production Costs and Transportation Costs Incurred – Heavy Crude Oil

	Three Months Ended				Year Ended
($ per bbl)	March 31, 2014	June 30, 2014	Sept. 30, 2014	Dec. 31, 2014	2014
CANADA
Prices Received – net of hedging	68.80	81.80	85.34	84.41	79.88
Royalties	(9.72)	(15.59)	(12.88)	(9.37)	(12.03)
Production Costs	(9.79)	(11.68)	(13.21)	(14.93)	(12.28)
Transportation Costs	(1.78)	(2.28)	(2.38)	(2.71)	(2.27)
Netback	47.51	52.25	56.87	57.40	53.30
U.S.
Prices Received – net of hedging	-	-	-	-	-
Royalties	-	-	-	-	-
Production Costs	-	-	-	-	-
Transportation Costs	-	-	-	-	-
Netback	-	-	-	-	-
TOTAL
Prices Received – net of hedging	68.80	81.80	85.34	84.41	79.88
Royalties	(9.72)	(15.59)	(12.88)	(9.37)	(12.03)
Production Costs	(9.79)	(11.68)	(13.21)	(14.93)	(12.28)
Transportation Costs	(1.78)	(2.28)	(2.38)	(2.71)	(2.27)
Netback	47.51	52.25	56.87	57.40	53.30

Prices Received, Royalties, Production Costs and Transportation Costs Incurred – NGLs

	Three Months Ended				Year Ended
($ per bbl)	March 31, 2014	June 30, 2014	Sept. 30, 2014	Dec. 31, 2014	2014
CANADA
Prices Received	65.05	44.47	46.68	36.90	47.11
Royalties	(4.91)	(3.82)	(3.65)	(2.49)	(3.62)
Production Costs	(9.26)	(6.35)	(7.22)	(6.53)	(7.22)
Transportation Costs	(1.69)	(1.24)	(1.30)	(1.19)	(1.33)
Netback	49.19	33.06	34.51	26.69	34.94
U.S.
Prices Received	40.00	45.70	36.40	34.62	39.32
Royalties	(8.30)	(12.05)	(7.57)	(8.79)	(9.20)
Production Costs	(7.88)	(7.18)	(4.73)	(6.16)	(6.66)
Transportation Costs	(0.23)	(0.78)	(0.45)	(0.65)	(0.51)
Netback	23.59	25.69	23.65	19.02	22.95
TOTAL
Prices Received	60.27	44.63	45.68	36.62	46.07
Royalties	(5.56)	(4.91)	(4.03)	(3.28)	(4.37)
Production Costs	(8.99)	(6.46)	(6.98)	(6.48)	(7.15)
Transportation Costs	(1.41)	(1.18)	(1.22)	(1.12)	(1.22)
Netback	44.31	32.08	33.45	25.74	33.33

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Prices Received, Royalties, Production Costs and Transportation Costs Incurred – Natural Gas

	Three Months Ended				Year Ended
($ per Mcf)	March 31, 2014	June 30, 2014	Sept. 30, 2014	Dec. 31, 2014	2014
CANADA
Prices Received - net of hedging	5.63	4.96	4.44	4.05	4.74
Royalties	(0.44)	(0.66)	(0.51)	(0.27)	(0.46)
Production Costs	(1.19)	(1.04)	(0.93)	(0.99)	(1.03)
Transportation Costs	(0.33)	(0.32)	(0.32)	(0.25)	(0.30)
Netback	3.67	2.94	2.68	2.54	2.95
U.S.
Prices Received - net of hedging	5.26	5.98	4.48	4.30	4.92
Royalties	(1.11)	(1.52)	(1.04)	(1.05)	(1.16)
Production Costs	(1.92)	(1.54)	(1.35)	(1.53)	(1.57)
Transportation Costs	(1.16)	(1.13)	(0.72)	(0.70)	(0.90)
Netback	1.07	1.79	1.37	1.02	1.29
TOTAL
Prices Received - net of hedging	5.56	5.13	4.45	4.09	4.77
Royalties	(0.57)	(0.80)	(0.62)	(0.43)	(0.59)
Production Costs	(1.33)	(1.12)	(1.02)	(1.10)	(1.13)
Transportation Costs	(0.50)	(0.45)	(0.40)	(0.34)	(0.42)
Netback	3.16	2.76	2.41	2.22	2.63

Production Volume by Field

The following table discloses for each important field, and in total, our production volumes for the year ended December 31, 2014 for each product type.

Region	Light and Medium Crude Oil	Heavy Crude Oil	NGLs	Natural Gas	Total
	(bbls/d)	(bbls/d)	(bbls/d)	(Mcf/d)	(boe/d)
CANADA
Southeast Saskatchewan & Manitoba	69,966	-	5,200	33,655	80,775
Southwest Saskatchewan	28,204	15	160	7,691	29,661
Alberta and West Central Saskatchewan	8,367	259	652	18,663	12,389
Total CANADA(1)	106,537	274	6,012	60,009	122,825
U.S.
North Dakota & Montana	3,777	-	254	1,967	4,359
Utah	10,929	-	675	12,094	13,620
Total U.S.(1)	14,706	-	929	14,061	17,979
Total(1)	121,243	274	6,941	74,070	140,803

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 eight 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 7, 2015.

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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 Director
Scott Saxberg (4) Calgary, Alberta	President, Chief Executive Officer and Director	2003

Gregory T. Tisdale Cochrane, Alberta	Chief Financial Officer	Not applicable

C. Neil Smith Calgary, Alberta	Chief Operating Officer	Not applicable

Brad Borggard Calgary, Alberta	Vice President, Corporate Planning	Not applicable

Derek Christie Calgary, Alberta	Vice President, Exploration & Geosciences	Not applicable

Ryan Gritzfeldt Calgary, Alberta	Vice President, Engineering and Business Development East	Not applicable

Kenneth R. Lamont Calgary, Alberta	Vice President, Finance and Treasurer	Not applicable

Tamara MacDonald Calgary, Alberta	Vice President, Land	Not applicable

Trent Stangl Calgary, Alberta	Vice President, Marketing and Investor Relations	Not applicable

Steven Toews Calgary, Alberta	Vice President, Engineering and Business Development West	Not applicable

Mark G. Eade Calgary, Alberta	Corporate Secretary	Not applicable

Peter Bannister (1), (3) Calgary, Alberta	Director and Chairman	2003

Rene Amirault (2), (4) Calgary, Alberta	Director	2014

Laura A. Cillis (1) Calgary, Alberta	Director	2014

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

Robert F. Heinemann (2), (3), (5) Plano, Texas	Director	2014

Gerald A. Romanzin (1), (2) Calgary, Alberta	Director	2004

Gregory G. Turnbull (3), (5) Calgary, Alberta	Director	2001

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 February 27, 2015, the directors and executive officers as a group beneficially owned, directly or indirectly, or exercised control or direction over 3,084,456 Common Shares, representing approximately 0.7% of the issued and outstanding Common Shares. Including restricted shares, ownership increased to 0.9% on a fully diluted basis.

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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"). Mr. Saxberg has 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 Association 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 APEGA. He is past 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.

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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 and Business Development East

Ryan Gritzfeldt is the Vice President, Engineering and Business Development 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 and a member of the Institute of Corporate Directors.

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 and 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.

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Steven Toews, Vice President, Engineering and Business Development West

Steven Toews is the Vice President, Engineering and Business Development 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.

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.

Rene Amirault, Director

Mr. Amirault was appointed as the President and Chief Executive Officer of Secure Energy Services in March 2007 and was elected a director and appointed as Chairman of the Board on June 1, 2007. From January 2006 to March 2007 he was an independent businessman. Mr. Amirault held various roles at Tervita Corporation from August 1994 to January 2006, including Vice President roles in Sales and Marketing, Business Development and Corporate Development. Mr. Amirault held various positions with Imperial Oil Ltd. from 1981 to 1994. Mr. Amirault received a Certified General Accountant designation in June 1985.

Laura A. Cillis, Director

Laura Cillis is an oil and gas executive with more than 25 years of financial experience in the oilfield services industry. Ms. Cillis joined the board of Crescent Point in November 2014. Most recently, she held the role of Senior Vice President, Finance and Chief Financial Officer of Calfrac Well Services Ltd. from 2008 until 2013, and Chief Financial Officer of Canadian Energy Services L.P. from 2006 to 2008. Prior thereto, she held various positions at Precision Drilling Corporation and Schlumberger Canada.

Ms. Cillis is also a director of Solium Capital Inc. She is a Chartered Accountant who holds the ICD.D designation granted by the Institute of Corporate Directors and a Bachelor of Commerce degree in accounting from the University of Alberta.

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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 chairman of the Calgary Zoological Society. He holds a Bachelor of Commerce degree from the University of Calgary and is a graduate of the Stanford Business School Executive Program.

Robert F. Heinemann, Director

Robert Heinemann is an oil and gas executive who brings more than 30 years of experience to the Crescent Point Board. Most recently, he served as President, Chief Executive Officer and director of Berry Petroleum Company ("Berry"), where he developed and executed that company’s growth and capital allocation strategies. He served as a director of Berry from 2002 until 2013, and as President and Chief Executive Officer from 2004 through 2013. Previously, Mr. Heinemann worked for Halliburton Company and Mobil Corporation in a number of operational, technology, management and executive roles of increasing responsibility.

Mr. Heinemann serves on the board of directors of QEP Resources, Inc. and he is the chairman of the board of Great Western Oil and Gas Company, LLC as well as C12 Energy, LLC. He is a member of the Society of Petroleum Engineers. He holds a Bachelor of Engineering and a Doctorate in chemical engineering from Vanderbilt University.

Gerald A. Romanzin, Director

Gerald Romanzin is an independent Calgary businessman who serves as a director of Petrowest Corporation, 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., Flowing Energy Corporation and Porto Energy Corp. 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.

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., Oyster Oil and Gas Ltd. and Marquee Energy 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.

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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 from Companies' 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.

Mr. Turnbull was a director of Sonde Resources Corp. until March 27, 2014. On February 2, 2015, Sonde Resources Corp. filed a voluntary assignment in bankruptcy.

Gerald A. Romanzin

Mr. Romanzin resigned from his position as a director of Porto Energy Corp. ("Porto"), a company that has subsequently become subject to cease trade orders for failure to file periodic disclosure (interim financial filings). Mr. Romanzin resigned as a director of Porto on May 30, 2014, following the decision by Porto’s directors and management to wind-down Porto’s operations due to capital constraints. Cease trade orders against Porto were subsequently issued by the Alberta, British Columbia, Manitoba and Ontario Securities Commissions and such cease trade orders remain in effect.

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.

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.

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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.

Share Dividend Plan

Under the SDP, eligible Shareholders may, at their option, elect to receive dividends declared on Common Shares as share dividends rather than cash dividends, where such share dividends are declared by the board of directors of the Corporation, to be payable in either cash or Common Shares at the election of the Shareholder. Share dividends are satisfied through the issuance of new Common Shares equal to the amount obtained by dividing the dollar amount of the dividend per Common Share by 95% of the average market price (as defined in the SDP) on the TSX. Generally, no commissions, service charges or brokerage fees will be payable by Shareholders who participate in the SDP. We have reserved the right to determine how much new equity is available under the SDP on any particular distribution date. Accordingly, participation in the SDP may be pro-rated in certain circumstances.

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Unlike the dividend reinvestment component of the DRIP, which gives only Shareholders resident in Canada the option to reinvest cash dividends into Common Shares at a 5% discount to market prices, the SDP provides all Shareholders with the option to receive dividends in the form of Common Shares at a 5% discount to current market prices.

The SDP has been in effect since May 9, 2014.

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, 2014, the Corporation is authorized to issue up to 11,841,332 Common Shares, of which the Corporation had 3,648,565 restricted shares outstanding at December 31, 2014.

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

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 closing 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.

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On March 10, 2015, the Board amended the DSU Plan to include provisions that govern U.S. citizens and residents in conformity with Section 409A of the U.S. Internal Revenue Code. This amendment was made to clarify and explicitly disclose certain tax consequences associated with participation in the DSU Plan by eligible U.S. citizens and U.S. residents.

Credit Facilities

At December 31, 2014, the Corporation had a $2.5 billion extendible revolving loan facility with a permitted increase (subject to certain conditions) to $3.0 billion (the "Syndicated Credit Facility") and a $100 million extendible operating loan facility (the "Bi-Lateral Credit Facility"). On March 10, 2015, the Syndicated Credit Facility was increased to a $3.5 billion extendible revolving loan facility with a permitted increase (subject to certain conditions) to $4.0 billion. 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 and Syndicated Credit Facility constitute revolving credit facilities for a three year term which are extendible annually. The Credit Facilities contain standard commercial covenants for facilities of this nature. Distributions to Shareholders are not permitted if the Corporation is in default of the Credit Facilities or if the making of such distribution would cause an event of default. The Corporation does not have a borrowing base restriction respecting its Credit Facilities.

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. However, since 1985 pursuant to a presidential finding, companies have been permitted to obtain licenses to ship crude oil to Canadian refineries. Further, in 2014, increasing pressure on the U.S. domestic crude oil market created by recent increases in domestic production have led to a small number of companies receiving permission to export minimally processed condensates.

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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.

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.

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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.

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. In respect of Freehold lands, taxes are payable to the Province of Alberta. The Government of Alberta's approach to the royalty and tax regime is regularly reviewed for compliance with the purpose of the regimes; to ensure that Albertans were receiving a fair share from energy development through royalties, taxes and fees. The most recent overhaul of the royalty regime was unveiled on October 25, 2007 (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. 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%.

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The Royalty Framework also introduced a new natural gas royalty formula which 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%.

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.

Incentive Programs

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

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.

With respect to the EOR Program, the Enhanced Oil Recovery Royalty Regulation, 2014 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, with producing intervals that are deeper than 2,000 metres.

The IETP is intended to promote producers' investment in research, technology and innovation for the purposes of improving environmental performance while creating commercial value. 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 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 on or after April 1, 2009. 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.

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In relation to conventional oil wells eligible for both the NWRR and the Deep Oil Exploratory Well Program, the date constraints under each program and the volume limits under the NWRR 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 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%.

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.

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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%. 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.

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 that does not qualify as new oil, third tier oil or holiday 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 vertical 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.

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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." Under the Program, a new well drilled or a well receiving workover incentive, after December 31, 2012 and before January 1, 2019 will be required to pay a minimum Crown royalty, or if the well is producing from freehold oil and gas rights, a minimum production tax while holiday oil is produced.

The Program consists of the following components:

Vertical Well Incentive provides licensees of a vertical development well or exploratory well drilled between December 31, 2013 and January 1, 2019 with 500 m3 of holiday oil volume. To qualify the well must be drilled less than 1.6 km from the nearest well cased for production form the same or a deeper zone.

Exploration and Deep Drilling Incentive provides licensees who drill an exploration well or a deep development well between December 31, 2013 and January 1, 2019 with a holiday oil volume as follows: (i) for a well drilled more than 1.6 km from a well cased for production from the same zone or a deeper zone, a holiday oil volume of 4,000 m3 is earned; (ii) for a well drilled below the Birdbear Formation, a holiday oil volume of 8,000 m3 is earned; and (iii) for a well completed for production in the Birdbear or deeper formation, a holiday oil volume of 8,000 m3 is earned.

·	Horizontal Well Initiative provides licensees of horizontal wells drilled between December 31, 2013 and January 1, 2019 with a holiday oil volume of 8,000 m3;

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

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

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·	Solution Gas Incentive provides an exemption from the payment of Crown royalties and production taxes for new solution gas projects effective until December 31, 2018 and subject to approval from the Director of Petroleum;

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 2,000 m³ 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 the Environmental Protection and Enhancement Act and the Oil and Gas Conservation Act, which impose strict environmental standards with respect to releases of effluents and emissions, including monitoring and reporting obligations, and impose significant penalties for non-compliance. 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 Environmental Assessment Act. Environmental Legislation in the Province of Manitoba is, for the most part, set out in the Environment Act and the Oil and Gas Act, which require certain advanced exploration projects to submit a proposal to Manitoba Conservation.

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, 2014, Crescent Point owned approximately 25,753 gross (16,628 net) wells, for which abandonment and reclamation costs are expected to be incurred. During the 2014 financial year, Crescent Point spent approximately $38.0 million on well abandonments and environmental remediation activities. Crescent Point estimates that it will spend approximately $52.3 million on well abandonments and environmental remediation and reclamation activities in 2015, and has budgeted accordingly. Crescent Point has estimated the net present value (discounted at approximately 2.25 percent per annum) of its total decommissioning liability (wells and facilities) to be approximately $1.0 billion as at December 31, 2014, based on a future liability (inflated at 2 percent per annum) of approximately $1.5 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.

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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.

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.

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

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

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

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

Some of our operations employ hydraulic fracturing techniques to stimulate oil and natural gas production from unconventional geological formations, which entails the injection of pressurized fracturing fluids into a well bore. The federal Energy Policy Act of 2005 amended the SDWA to exclude hydraulic fracturing from the definition of "underground injection" under certain circumstances. However, the repeal of this exclusion has been advocated by certain advocacy organizations and others in the public. Legislation to amend the SDWA to repeal this exemption and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, 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 early 2015.

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On May 16, 2013, the U.S. Bureau of Land Management ("BLM") published revised proposed rules to regulate hydraulic fracturing on federal public lands and Indian lands. The proposed rules would address well stimulation operations, including requiring agency approval for certain activities, and would require certain disclosures of well stimulation fluids and other information, as well as address issues relating to flowback water. In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, or that would impose higher taxes, fees or royalties on natural gas production. In July of 2013, the BLM extended the public comment period on the proposed rules to August of 2013. Since the close of the public comment period the BLM has been working with the White House Office of Management and Budget to vet the proposed rules. To date, the BLM has not published final rules or revised proposed rules in relation to hydraulic fracturing. Many states currently independently regulate hydraulic fracturing operations in the state, including Utah, North Dakota and Montana. 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.

Greenhouse Gas Emissions

In Alberta, GHG emissions are regulated under the Specified Gas Emitters Regulation pursuant to the Climate 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 - 2006 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.

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On May 11, 2009, the Government of Saskatchewan announced The Management and Reduction of Greenhouse Gases Act (the "MRGHGA") to regulate greenhouse gas emissions in the province. The MRGHGA has not yet come into force. Draft versions of the regulations under the MRGHGA indicate that Saskatchewan will adopt similar initiatives to the Alberta framework.

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 Regulatory Framework for Air Emissions, updated March 10, 2008 by Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions and has outlined a number of policies to reduce GHGs intensity of regulated facilities (the "Federal Plan"). The Federal Plan is expected to be implemented through legislation. However, such implementation has been delayed and the specific requirements on industry of the proposed legislation remains unclear. Under the proposed Federal Plan, facilities would face intensity reduction requirements with compliance options for facilities such as: 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 per tonne (on an escalating basis) 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.

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.

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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. From January 1, 2014 to March 31, 2014, $0.30 per produced boe was allocated to this fund. From April 1, 2014 to December 31, 2014, $0.20 per produced boe was allocated to this fund. As at December 31, 2014, $56.1 million has been allocated to the fund and $25.2 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:

·	Complying with government regulations and standards;

·	Conducting operations consistent with industry codes, practices and guidelines;

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

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

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

·	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:

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

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

·	initial production rates;

·	production decline rates;

·	ultimate recovery of reserves;

·	success of future development activities;

·	marketability of production;

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

·	effects of government regulation; and

·	other government levies that may be imposed over the producing life of reserves.

Reserve estimates are based on the relevant factors, assumptions and prices on the date the relevant evaluations were prepared. 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, Colorado, 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 Colorado, 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 us to 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, 2014, approximately 11% 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 wilful 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:

·	restrictions imposed by lenders;

·	delays in the sale or delivery of products;

·	delays in the connection of wells to a gathering system;

·	restrictions due to limited pipeline capacity;

·	blowouts or other accidents;

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·	accounting delays;

·	adjustments for prior periods;

·	recovery by the operator of expenses incurred in the operation of the properties; or

·	the establishment by the operator of reserves for these expenses.

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 $3.5 billion extendible revolving loan facility with a permitted increase to $4.0 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.

Aboriginal claims could have an adverse effect on us and our operations.

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 involve tribal trust minerals. 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 enjoy sovereign immunity from 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 EDAs with 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.

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We depend upon our management team and our operations require us to attract and retain experienced technical personnel.

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.

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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.

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 unfavourable 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.

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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.

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 GHG emissions 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.

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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.

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 favourable 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 February 2015, President Obama’s Administration released its proposed federal budget for fiscal year 2016 that would, if enacted into law, make significant changes to United States tax laws, including the elimination of numerous key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. 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.

We are affected by seasonal weather patterns.

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.

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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.

We incorporate additional information with respect to production and reserves which is not required to be included under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes; however, we also follow the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves. The SEC permits, but does not require, the disclosure of reserves based on forecast prices and costs.

Reserve information contained herein may include estimates of Proved and Proved plus Probable reserves. The SEC permits, but does not require, the inclusion of estimates of Probable reserves in filings made with it by United States oil and gas companies. The SEC does not permit the inclusion of estimates of resources in reports filed with it by United States companies.

Additional taxation applicable to non-residents

The Tax Act imposes a withholding tax at the rate of 25% on dividends paid by us to Shareholders who are non-residents of Canada, unless the rate is reduced under the provisions of a tax treaty between Canada and the non-resident Shareholder's jurisdiction of residence. These withholding tax rates may change from time to time. Where the non-resident Shareholder is a United States resident entitled to benefits under the Canada-United States Income Tax Convention, 1980 (the "Treaty") and is the beneficial owner of the dividend, the rate of Canadian withholding tax applicable to dividends is generally reduced to 15%. To qualify for this reduced rate, non-resident beneficial Shareholders must file certain documents with their broker (or, in the case of non-resident registered Shareholders, with our transfer agent) evidencing Treaty eligibility. Additionally, dividend income is subject to income tax under U.S. tax law. The American Taxpayer Relief Act, effective January 1, 2013, assigns a tax rate of 15% to qualified dividends received by taxpayers earning less than US$413,000 (individual), US$439,000 (head of household) and US$464,850 (married filing jointly). Taxpayers earning more than these amounts are subject to tax on qualified dividends at a rate of 20%.

Foreign exchange risk for non-resident Shareholders

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

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.

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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 2014, the Corporation's payout ratio on a per Common Share diluted basis was 48%.

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 Share
January 2012 - December 2012	$0.23
January 2013 - December 2013	$0.23
January 2014 - December 2014	$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.

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)
2014
January	41.14	37.85	24,709
February	39.59	37.32	20,533
March	40.75	38.60	25,612
April	44.79	40.16	29,605
May	44.99	42.36	22,322
June	48.68	44.02	25,955
July	47.46	43.05	21,713
August	45.04	42.75	18,744
September	45.00	39.10	39,043
October	40.66	33.57	42,531
November	37.39	29.43	37,572
December	30.33	21.20	78,772
2015
January	31.66	24.68	57,388
February	33.85	30.16	44,325

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NYSE	High (US$)	Low (US$)	Volume (000's)
2014
January (22-31)	38.36	34.18	461
February	35.92	33.72	956
March	36.79	34.81	245
April	40.94	36.49	346
May	41.35	38.88	309
June	44.78	40.27	503
July	44.72	40.02	531
August	41.49	39.18	446
September	41.44	35.25	624
October	36.46	29.85	1,212
November	33.25	25.77	895
December	26.70	18.39	2,427
2015
January	25.53	21.06	2,359
February	27.30	23.96	2,271

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.

AUDIT COMMITTEE

General

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

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.

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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.

Name of Audit Committee Member	Relevant Education and Experience
Gerald A. Romanzin	Gerald Romanzin is an independent Calgary businessman who serves as a director of Petrowest Corporation, 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., Flowing Energy Corporation and Porto Energy Corp. 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.

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.

Laura A. Cillis	Laura Cillis has more than twenty-five years of financial experience in the oilfield services industry. She joined the board of Crescent Point in November 2014. Most recently, she held the role of Senior Vice President, Finance and Chief Financial Officer of Calfrac Well Services Ltd. from 2008 until 2013, and Chief Financial Officer of Canadian Energy Services L.P. from 2006 to 2008. Prior thereto, she held various positions at Precision Drilling Corporation and Schlumberger Canada.

	Ms. Cillis is a Chartered Accountant and holds a Bachelor of Commerce degree in accounting from the University of Alberta. She also holds the ICD.D designation granted by the Institute of Corporate Directors.

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Name of Audit Committee Member	Relevant Education and Experience

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 chairman of the Calgary Zoological Society.

	He holds a Bachelor of Commerce degree from the University of Calgary and is a graduate of the Stanford Business School Executive Program.

External Auditor Services Fees

For services provided to the Corporation and its subsidiaries the years ended December 31, 2014 and 2013 PricewaterhouseCoopers LLP billed approximately $1,171,181 and $812,281, respectively, as detailed below:

	Year ended December 31
	2014		2013
PricewaterhouseCoopers
Audit fees	$	917,696	$	772,418
Audit-related fees(1)	$	130,985	$	20,300
Tax Fees	$	24,500	$	-
All other fees	$	98,000	$	19,563
Total	$	1,171,181	$	812,281

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.

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 the quarterly financial statements, as well as services 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 and short form prospectus filed in 2014. 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.

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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 Computershare Trust Company of Canada 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, 2014, 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 meeting of Shareholders held on May 7, 2015. 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, 2014.

For additional copies of this AIF please contact:

Crescent Point Energy Corp.

2000, 585 – 8th Avenue, S.W.

Calgary, Alberta

T2P 1G1

Attention: Investor Relations

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APPENDIX A

AUDIT COMMITTEE TERMS OF REFERENCE

Corporate Policies & Procedures

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

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;

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(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:

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(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.

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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.

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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.

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Minutes

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:

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

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

(iii)

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

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

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

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

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

(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.

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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

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(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:

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(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.

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;

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(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.

Appendix C

FORM 51-101F2

REPORT ON RESERVES DATA

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, 2014. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2014, 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).

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.

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, 2014, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's board of directors:

			Net Present Value of Future Net Revenue (before income taxes, 10% discount rate - $M)
Independent Qualified Reserves Evaluator	Description and Preparation Date of Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Audited	Evaluated	Reviewed	Total
GLJ Petroleum Consultants	Corporate Summary February 3, 2015	Canada	-	3,086,165	-	3,086,165

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 9, 2015

ORIGINALLY SIGNED BY

Bryan M. Joa, P.Eng.

Vice President

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FORM 51-101F2

REPORT ON RESERVES DATA

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, 2014. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2014, 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.

			Net Present Value of Future Net Revenue (before income taxes, 10% discount rate - Cdn. $M)
Independent Qualified Reserves Evaluator	Description and Preparation Date of Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Audited	Evaluated	Reviewed	Total
GLJ Petroleum Consultants	U.S.A. Summary February 3, 2015	U.S.A.	-	1,556,877	-	1,556,877

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 9, 2015

ORIGINALLY SIGNED BY

Bryan M. Joa, P. Eng.

Vice President

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FORM 51-101F2

REPORT ON RESERVES DATA

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, 2014. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2014, estimated using forecast prices and costs.

2.	The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

3.	We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the "COGE Handbook"), maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).

The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated for the year ended December 31, 2014, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's management and Board of Directors:

			Net Present Value of Future Net Revenue (before income taxes, 10% discount rate - Cdn. $M)
Independent Qualified Reserves Evaluator or Auditor	Description and Preparation Date of Evaluation Report	Location of Reserves (Country)	Audited (M$)	Evaluated (M$)	Reviewed (M$)	Total (M$)
Sproule	Evaluation of Certain Saskatchewan P&NG Reserves of Crescent Point Energy Corp., As of December 31, 2014, prepared August 2014 to February 2015	Canada
Total			Nil	11,535,293	Nil	11,535,293

6.	In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.

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

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

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Executed as to our report referred to above:

Sproule Associates Limited, Calgary, Alberta February 12, 2015

ORIGINALLY SIGNED BY

Richard A. Brekke, P. Eng.

Manager, Engineering and Partner

Steven J. Golko, P. Eng.

Supervisor, Engineering and Partner

Vincent K. Hui, P. Eng.

Petroleum Engineer and Partner

Ian K. Kirkland, P.Geol.

Senior Petroleum Geologist and Partner

Alec Kovaltchouk, P.Geo.

Manager, Geoscience and Partner

Nora T. Stewart, P.Eng.

Senior Vice-President, Canada and Director

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, 2014 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 President and Chief Executive Officer		C. NEIL SMITH Chief Operating Officer

"Gerald A. Romanzin"		"Peter Bannister"
GERALD A. ROMANZIN Director		PETER BANNISTER Director

March 10, 2015