Exhibit 99.1

CRESCENT POINT ENERGY CORP.

ANNUAL INFORMATION FORM

For the Year Ended December 31, 2018

Dated March 6, 2019

Contents

Section	Page
SPECIAL NOTES TO READER	1
GLOSSARY	4
SELECTED ABBREVIATIONS	6
CURRENCY OF INFORMATION	7
OUR ORGANIZATIONAL STRUCTURE	7
GENERAL DEVELOPMENT OF THE BUSINESS OF THE CORPORATION	9
DESCRIPTION OF OUR BUSINESS	11
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	13
ADDITIONAL INFORMATION RESPECTING CRESCENT POINT	38
INDUSTRY CONDITIONS	48
RISK FACTORS	63
DIVIDENDS AND SHARE REPURCHASES	78
MARKET FOR SECURITIES	80
CONFLICTS OF INTEREST	81
LEGAL PROCEEDINGS	81
AUDIT COMMITTEE	81
TRANSFER AGENT AND REGISTRARS	83
AUDITOR	83
MATERIAL CONTRACTS	84
INTERESTS OF EXPERTS	84
ADDITIONAL INFORMATION	85

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

Any "financial outlook" or "future oriented financial information" in this annual information form, as defined by applicable securities legislation has been approved by management of Crescent Point (as defined herein). 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.

This annual information form and other reports and filings made with the securities regulatory authorities include certain statements that constitute "forward-looking statements" within the meaning of section 27A of the Securities Act of 1933, section 21E of the Securities Exchange Act of 1934 and the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" for the purposes of Canadian securities regulation (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. Crescent Point has tried to identify such forward-looking statements by use of such words as "could", "should", "can", "anticipate", "expect", "believe", "will", "may", "intend", "projected", "sustain", "continues", "strategy", "potential", "projects", "grow", "take advantage", "estimate", "well-positioned" and similar expressions, but these words are not the exclusive means of identifying such statements. These forward-looking 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 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 AIF contains forward-looking statements pertaining, among other things, to the following:

• corporate strategy and anticipated financial and operational performance;

• expected director tenure and the timing and effectiveness of director appointments;

• forecast prices and the expected impact of commodity price fluctuations on cash available to pay dividends;

• our hedging strategy, including its expected outcomes, and our approval to managing physical delivery contracts;

• our risk mitigation strategy and the expected outcomes from same;

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

• business prospects;

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

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

• projected returns and exploration potential of our assets;

• the potential of Crescent Point’s plays;

• future development plans;

• forecast costs and expenses associated with Crescent Point's business, including capital expenditure programs and how they will be funded;

• our leverage objectives for 2019;

• corporate and asset acquisitions and dispositions;

• drilling programs;

• expected location inventory development timing;

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

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

• the quantity of oil and natural gas reserves;

• projections of commodity prices and costs;

• our future waterflood programs;

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

• the impacts of the Orphan Well Association v Grant Thornton Ltd. court decision;

• expected decommissioning, abandonment, remediation and reclamation costs;

• our tax horizon;

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• the impact of the Canada-United States-Mexico Agreement;

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

• the impact, and projected long-term impacts, of the pricing of carbon and greenhouse gases;

• payment of dividends and the repurchase of Common Shares by the Corporation, including pursuant to its ongoing normal course issuer bid;

• 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;

• treatment under governmental regulatory regimes, including royalty regimes applicable to natural resources; and

• risks related to the regulatory, social and market efforts to address climate change.

By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements, including those material risks discussed in our Management's Discussion and Analysis for the year ended December 31, 2018, under the headings "Risk Factors" and "Forward-Looking Information". The material assumptions and factors in making forward-looking statement are disclosed in the Management's Discussion and Analysis for the year ended December 31, 2018, under the headings "Capital Expenditures", "Liquidity and Capital Resources", "Critical Accounting Estimates", "Risk Factors", "Changes in Accounting Policies" and "Outlook".

This information contains certain forward-looking estimates that involve substantial known and unknown risks and uncertainties, certain of which are beyond Crescent Point's control. Such risks and uncertainties include, but are 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 and blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions, including changes in laws and regulations, the adoption of new environmental laws and regulations, and changes in how environmental laws and regulations 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 and dispositions; 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; tax laws and changes thereto, crown royalty rates and incentive programs relating to the oil and gas industry; and other factors, many of which are outside the control of Crescent Point. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as each of these are interdependent and Crescent Point's future course of action depends on management’s assessment of all information available at the relevant time.

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 described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. Actual reserve values may be greater than or less than the estimates provided herein.

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

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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.

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.

Operating netback is calculated on a per boe basis as oil and gas sales, less royalties, operating and transportation expenses. Netback is calculated on a per boe basis as operating netback plus realized derivative gains and losses. Operating netback and netback are common metrics used in the oil and gas industry and are used by management to measure operating results on a per boe basis to better analyze performance against prior periods on a comparable basis. The calculation of netback is shown in the Production History section of this AIF.

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.

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

Presentation of our Reserve and Resource Information

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

"AEP" means Alberta Environment and Parks.

"AER" means the Alberta Energy Regulator.

"AIF" means this annual information form of the Corporation dated March 6, 2019 for the year ended December 31, 2018.

"Board" or "Board of Directors" means the board of directors of the Corporation.

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

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

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

"CPHI" means Crescent Point Holdings Inc.

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

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

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

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

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

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

"GLJ" means GLJ Petroleum Consultants Ltd.

"Greenhouse Gases" or "GHGs" means any or all of, including but not limited to, carbon dioxide (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, 2018.

"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 the Organization of the Petroleum Exporting Countries.

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"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.

"PSU Plan" means the Performance Share Unit Plan of the Corporation.

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

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

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

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

"Shelter Bay" means Shelter Bay Energy Inc.

"Sproule" means Sproule Associates Limited.

"Stock Option Plan" means the Stock Option Plan of the Corporation.

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

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

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

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

"TSX" means the Toronto Stock Exchange.

"Unitholders" means holders of Trust Units.

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

For additional definitions used in this AIF, please see "Statement of Reserves Data and Other Oil and Gas Information - Notes and Definitions".

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
bbls/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
NGLs	natural gas liquids
		MMcf	million cubic feet
		MMcf/d	million cubic feet per day
		MMBTU	million British Thermal Units
		GJ	gigajoule

Other
AECO	the natural gas storage facility located at Suffield, Alberta
boe or 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
MM$	million dollars
MW	megawatt
MW/h	megawatt 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, 2018 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. ("Crescent Point" or the "Corporation" and, together with its direct and indirect subsidiaries and partnerships, where appropriate, "we", "our" or "us") is the successor to the Trust, following the completion of the "conversion" of the Trust from an income trust to a corporate structure under the Conversion Arrangement. Pursuant to the Conversion Arrangement, Unitholders of the Trust exchanged their Trust Units for Common Shares of the Corporation on a one-for-one basis.

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

The 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 crude oil and natural gas reserves in Western Canada and the United States.

We make regular 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 the Corporation’s U.S. operating assets.

CPHI

CPHI is a wholly-owned subsidiary of the Corporation. CPHI is a partner of the Partnership.

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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 6, 2019. 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.

2016

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

On March 8, 2016, the Corporation reduced its monthly dividend to $0.03 per share, effective with the March dividend payable on April 15, 2016.

On August 10, 2016, the terms of the Corporation’s syndicated credit facility and operating credit facility were each extended to June 10, 2019.

On September 20, 2016, the Corporation completed an equity offering of 33,700,000 Common Shares at a price of $19.30 per Common Share for aggregate gross proceeds of approximately $650 million.

In the third quarter of 2016, the Corporation completed a strategic core consolidation acquisition in its emerging-growth Flat Lake resource play and an acquisition of low-decline, conventional waterflood assets, both in southeast Saskatchewan. The Corporation also disposed of non-core assets in the Peace River Arch area of northwest Alberta for $31.0 million.  Total net consideration for the acquisitions, net of the disposition was $211.7 million.

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

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2017

In the first quarter of 2017, Crescent Point completed the acquisition of approximately 8,500 net acres in North Dakota for total cash consideration of US$100.0 million. The acquired lands were contiguous to the Corporation's current acreage.

Crescent Point also acquired approximately 80,000 net acres of undeveloped land in the Uinta Basin in the second quarter of 2017, for total cash consideration of US$72.5 million. The lands include 1,700 boe/d of production and provided the opportunity to expand the Corporation’s horizontal drilling expertise to an area with multi-zone potential.

In the second quarter of 2017, the Corporation sold 1,100 boe/d of non-operated conventional assets in Manitoba for total cash consideration of $93.2 million.

On May 24, 2017, Ted Goldthorpe was elected as a director of the Corporation. See "Additional Information Respecting Crescent Point - Directors and Officers".

On June 26, 2017, Crescent Point renewed its unsecured, covenant-based credit facilities totaling $3.6 billion. The renewal extended the maturity date of the credit facilities to June 10, 2020. See "Additional Information Respecting Crescent Point - Long-Term Debt".

During the third quarter of 2017, the Corporation completed or entered into agreements to dispose of non-core assets representing approximately 3,000 boe/d for total value of over $190 million.

In the fourth quarter of 2017, Crescent Point entered into agreements to dispose of non-core assets for total value of approximately $40 million, of which approximately $20 million closed during the first quarter of 2018.

2018

In the second quarter of 2018, Crescent Point completed the disposition of non-core assets mostly in southeast Saskatchewan, for proceeds of approximately $280 million. The assets sold represented operated and non-operated production of approximately 4,800 boe/d.

Early in the second quarter of 2018, the Corporation completed a private placement of senior unsecured, guaranteed notes for total gross proceeds of US$143.5 million and CDN$80.0 million. Three separate series of notes were issued as part of the private placement, with maturities ranging from five to seven years and interest rates ranging from 3.58% to 3.98%. Proceeds from the issuance of the notes were used to repay a portion of the Corporation’s outstanding bank debt and other senior guaranteed notes with near-term maturities.

On May4, 2018, François Langlois was elected as a new director of the Corporation. See "Additional Information Respecting Crescent Point - Directors and Officers".

On May 29, 2018, Scott Saxberg stepped down as President and Chief Executive Officer of Crescent Point, and Craig Bryksa was appointed Interim President and Chief Executive Officer and to the Board. Mr. Bryksa was subsequently appointed as Crescent Point’s President and Chief Executive Officer on September 5, 2018.

On June19, 2018, Neil Smith, Chief Operating Officer, stepped down as an officer of the Corporation, and Ryan Gritzfeldt was promoted from Vice President, Marketing and Innovation to the position of Chief Operating Officer.

On June 22, 2018, Crescent Point renewed its unsecured credit facilities totaling $3.6 billion with a new maturity date of June 10, 2021.

On September5, 2018, Robert Heinemann was appointed as the new Chairman of the Board of Directors, replacing Peter Bannister, who has announced his intention to retire from the Board at the Corporation’s 2019 annual meeting of shareholders.

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2019

On February 19, 2019, Crescent Point announced the appointment of John P. Dielwart to the Board, effective March 7, 2019. See "Additional Information Respecting Crescent Point - Directors and Officers".

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 crude oil and natural gas reserves in Western Canada and the United States. The primary assets of the Corporation are currently its interest in the Partnership, shares in CPHI, shares in CPUSH and, indirectly, shares 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, British Columbia and Manitoba and in the states of North Dakota, Montana and Utah. The properties and assets consist of producing crude oil and natural gas reserves and Proved plus Probable (as defined herein) crude oil and natural gas reserves not yet on production, and land holdings.

We pay regular 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. During the year ended December 31, 2018, we paid monthly dividends of $0.03 per Common Share. Commencing in 2019, we expect to pay a quarterly dividend of $0.01 per share. See "Dividends".

Strategy

We strive to enhance shareholder returns by cost effectively developing a focused asset base in a responsible and sustainable manner. Through the development of our assets, we aim to create sustainable, profitable and returns-based growth in reserves, production and cash flow.

We strategically develop our properties through detailed technical analysis including reservoir characteristics, petroleum initially in place, recovery factors and the applicability of enhanced recovery techniques. Our development strategies include, infill and step-out wells, multi-stage fracture stimulation of horizontal wells, re-completion of existing wells and secondary recovery techniques such as waterflood programs.

Risk Management and Marketing

Factors outside our control impact, to varying degrees, the prices we receive for production. These include but are not limited to:

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

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

(c) availability, proximity and capacity of take-away alternatives, including oil and gas gathering systems, pipelines, processing facilities, railcars and railcar loading facilities;

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

(e) 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;

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

(g) global and domestic economic and weather conditions;

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(h) price and availability of alternative fuels;

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

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

Fluctuations in commodity prices, 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 net of royalty production up to a rolling three and a half year basis, at the discretion of management. The Corporation also uses a combination of financial derivatives and fixed-differential physical contracts to hedge price differentials. For differential hedging, Crescent Point's risk management program allows for hedging a forward profile of up to three and a half 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 and U.S. dollars and benchmark natural gas prices are hedged using financial AECO-based instruments transacted in Canadian dollars. Total financial oil and gas hedges in 2018 amounted to approximately 56% of annual production, net of royalties, consisting of approximately 58% of annual liquids production and approximately 32% of annual natural gas production, net of royalties. The Corporation recorded a realized derivative loss on crude oil and natural gas hedge contracts of $259.8 million in 2018.

Crescent Point also enters into physical delivery and derivative WTI price differential contracts which manage the spread between US$ WTI and various stream prices on a portion of its production. The Corporation manages physical delivery contracts on a month-to-month spot and term contract basis. From January to December 2018, approximately 15,600 bbls/d of liquids production was contracted with fixed price differentials off WTI.

Refer to the annual financial statements for our commitments under all hedging agreements as at December 31, 2018.

In addition to hedging benchmark crude oil and natural gas prices with financial instruments, we also mitigate crude oil basis risk by delivering a portion of our crude oil production into diversified refinery markets using rail transportation. Crescent Point operates three railcar loading facilities, serving its key producing areas of southeast Saskatchewan, southwest Saskatchewan 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 over the past several years that are not pipeline connected to western Canada or Utah, which diversifies price and market risk.

We mitigate credit risk by having a well-diversified marketing portfolio for crude oil and natural gas. 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 by Crescent Point's Risk Management Committee and is governed by a board-approved Risk Management and Counterparty Credit Policy that is reviewed annually by the Board of Directors. The Policy requires annual credit reviews of all trade counterparties. 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 104 purchasers and its financial hedging portfolio consists of 16 counterparties. The Corporation's portfolio of counterparty exposures is monitored on a monthly basis.

To further mitigate credit risk associated with its physical sales portfolio, Crescent Point obtains financial assurances such as parental guarantees, letters of credit and third party credit insurance. Including these assurances, approximately 95% of the Corporation’s oil and gas sales are with entities considered investment grade.

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Revenue Sources

Our crude oil and natural gas volumes are sold in the U.S., Alberta, British Columbia, Manitoba and Saskatchewan. Approximately 71% of our liquids volumes are sold in Saskatchewan, 21% in the U.S., 7% in Alberta, 1% in Manitoba and less than 1% in British Columbia. Approximately 59% of our natural gas volumes are sold in Saskatchewan, 24% in the U.S., 17% in Alberta and less than 1% in British Columbia.

For 2018, our commodity production mix was approximately 90% crude oil and NGLs and 10% natural gas.

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

For Year Ended	Crude Oil and NGLs	Natural Gas
2018	98%	2%
2017	97%	3%
2016	97%	3%

Competition

We actively compete for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial resources than we do. Our competitors include major integrated oil and natural gas companies, numerous other independent oil and natural gas entities and individual producers and operators. Similarly, we face a competitive market when we attempt to divest of non-core assets.

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

Seasonal Factors

The production of crude 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 of December 31, 2018, the Corporation had 1,004 permanent employees: 416 employees at our head office in Calgary, 90 employees at our Denver office, 419 field employees in Canada and 79 field employees in the U.S.

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, 2018, and contained in the consolidated report of GLJ dated February 13, 2019 (the "Crescent Point Reserve Report"). The tables below are a combined summary of our crude oil, NGL and natural gas reserves and the net present value of future net revenue attributable to such reserves as evaluated in the Crescent Point Reserve Report based on Sproule’s December 31, 2018 forecast price and cost assumptions. GLJ evaluated approximately 45% of the assigned total Proved plus Probable reserves and 34% of the total Proved plus Probable value discounted at 10%. Sproule evaluated approximately 55% of the assigned total Proved plus

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Probable reserves and 66% of the total Proved plus Probable value discounted at 10%. Sproule evaluated a majority of our southeast Saskatchewan assets including the Viewfield Bakken and Flat Lake Torquay properties in southeast Saskatchewan as well as southwest Saskatchewan assets including the Shaunavon and Saskatchewan Viking properties. Sproule evaluated their portion of the reserves using the Sproule forecast price and cost escalation assumptions. GLJ evaluated the Corporation’s Alberta, British Columbia and Manitoba assets, as well as a portion of the assets in southeast Saskatchewan. GLJ also performed the evaluation of the Corporation's U.S. assets in North Dakota and Montana, as well as assets in the Uinta basin in Utah. These assets were all evaluated using the Sproule forecast price and cost escalation assumptions. GLJ prepared the total Crescent Point Reserve Report by consolidating the GLJ Canadian and U.S. evaluated properties with the Sproule evaluation using the Sproule pricing and cost escalation assumptions. The tables summarize the data contained in the Crescent Point Reserve Report and, as a result, may contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly.

The net present value of future net revenue attributable to our reserves is stated without provision for interest costs, and general and administrative costs, but after providing for estimated royalties, production costs, capital taxes, development costs, other income, future capital expenditures, projected carbon tax costs, and well and location abandonment costs for only those entities assigned reserves by GLJ and Sproule. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to our reserves estimated by GLJ and Sproule represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of our crude oil, NGL and natural gasreserves 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.

The Corporation continuously monitors and reviews legislation concerning greenhouse gas emissions and the impact on our operations. Crescent Point has estimated financial impacts based on current carbon pricing levels as adopted in existing and proposed legislation, and reflected these within the reserves evaluation as of December 31, 2018 as an operating cost per unit volume of production. No U.S. jurisdictions that we operate in have legislated or proposed costs associated with carbon, or greenhouse gases. The total impact of the carbon pricing in the Crescent Point Reserve Report reflects a negative impact of 940 Mboe and $161.7 MM discounted at 10% before tax for total proved plus probable reserves.

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.

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Reserves Data – Forecast Prices and Costs

Summary of Oil and Gas Reserves⁽¹⁾ 

	Light and Medium Crude Oil		Heavy Crude Oil		Tight Oil		Natural Gas Liquids		Shale Gas		Conventional Natural Gas		Total
Reserves Category	Company Gross (Mbbls)	Company Net (Mbbls)	Company Gross (Mbbls)	Company Net (Mbbls)	Company Gross (Mbbls)	Company Net (Mbbls)	Company Gross (Mbbls)	Company Net (Mbbls)	Company Gross (MMcf)	Company Net (MMcf)	Company Gross (MMcf)	Company Net (MMcf)	Company Gross (Mboe)	Company Net (Mboe)
Proved Developed Producing
Canada	91,754	81,711	24,625	20,295	137,025	127,961	42,290	39,023	115,594	109,379	71,226	66,717	326,831	298,339
United States	63	55	—	—	45,300	37,078	6,964	5,663	46,466	38,536	3	2	60,072	49,219
Total	91,817	81,766	24,625	20,295	182,326	165,038	49,254	44,686	162,060	147,915	71,229	66,719	386,903	347,558
Proved Developed Non-Producing
Canada	1,784	1,625	2,619	2,293	4,439	4,133	1,075	990	3,243	3,025	1,151	928	10,649	9,700
United States	6	5	—	—	485	396	114	92	2,044	1,661	3	2	946	770
Total	1,789	1,629	2,619	2,293	4,925	4,529	1,189	1,082	5,287	4,686	1,154	930	11,595	10,470
Proved Undeveloped
Canada	33,819	31,420	1,771	1,545	78,269	73,523	16,459	15,183	60,093	56,368	12,882	11,927	142,479	133,054
United States	—	—	—	—	59,828	48,770	8,898	7,225	59,076	48,184	—	—	78,572	64,025
Total	33,819	31,420	1,771	1,545	138,096	122,293	25,357	22,408	119,169	104,552	12,882	11,927	221,051	197,079
Total Proved
Canada	127,356	114,756	29,015	24,133	219,734	205,617	59,824	55,196	178,930	168,773	85,259	79,572	479,960	441,093
United States	68	59	—	—	105,613	86,244	15,976	12,980	107,585	88,381	5	4	139,589	114,014
Total	127,424	114,815	29,015	24,133	325,347	291,861	75,800	68,176	286,515	257,154	85,264	79,576	619,549	555,107
Total Probable
Canada	71,928	64,927	7,903	6,370	130,667	120,978	31,789	29,361	105,297	98,488	39,953	36,978	266,495	244,213
United States	31	27	—	—	78,820	64,376	10,513	8,544	73,380	60,060	2	2	101,594	82,957
Total	71,959	64,954	7,903	6,370	209,486	185,354	42,302	37,904	178,677	158,549	39,955	36,980	368,089	327,169
Total Proved Plus Probable
Canada	199,284	179,683	36,918	30,502	350,400	326,595	91,613	84,556	284,228	267,261	125,212	116,550	746,455	685,305
United States	99	86	—	—	184,433	150,619	26,489	21,524	180,965	148,441	8	6	241,183	196,971
Total	199,383	179,769	36,918	30,502	534,833	477,215	118,102	106,080	465,193	415,702	125,219	116,557	987,638	882,276

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% (MM$)	5% (MM$)	8% (MM$)	10% (MM$)	15% (MM$)	20% (MM$)	0% (MM$)	5% (MM$)	8% (MM$)	10% (MM$)	15% (MM$)	20% (MM$)
Proved Developed Producing
Canada	11,993	8,873	7,701	7,090	5,947	5,152	10,994	8,300	7,274	6,734	5,713	4,992
United States	1,925	1,520	1,356	1,267	1,098	976	1,893	1,500	1,340	1,254	1,088	969
Total	13,918	10,392	9,057	8,358	7,044	6,128	12,887	9,800	8,615	7,989	6,801	5,961
Proved Developed Non-Producing
Canada	444	304	257	234	191	162	324	227	195	179	150	131
United States	20	15	13	12	10	8	19	14	13	12	10	8
Total	463	319	270	246	201	170	343	241	208	191	160	139
Proved Undeveloped
Canada	3,946	2,748	2,243	1,971	1,451	1,090	2,879	1,955	1,569	1,362	969	698
United States	1,566	860	606	479	257	119	1,440	799	564	446	237	107
Total	5,512	3,608	2,849	2,450	1,708	1,210	4,320	2,754	2,134	1,808	1,206	805
Total Proved
Canada	16,383	11,924	10,202	9,295	7,589	6,404	14,197	10,482	9,039	8,276	6,832	5,821
United States	3,511	2,395	1,975	1,759	1,365	1,104	3,352	2,314	1,917	1,712	1,336	1,084
Total	19,894	14,319	12,177	11,053	8,953	7,508	17,550	12,796	10,956	9,988	8,167	6,905
Total Probable
Canada	11,693	6,564	5,052	4,343	3,157	2,434	8,504	4,753	3,638	3,116	2,243	1,714
United States	3,696	1,949	1,435	1,199	814	590	2,781	1,500	1,123	949	663	491
Total	15,390	8,513	6,487	5,542	3,971	3,024	11,284	6,253	4,761	4,065	2,906	2,206
Total Proved Plus Probable
Canada	28,076	18,488	15,253	13,638	10,745	8,838	22,701	15,235	12,677	11,392	9,075	7,535
United States	7,207	4,344	3,410	2,958	2,179	1,694	6,133	3,814	3,040	2,661	1,998	1,576
Total	35,283	22,832	18,663	16,596	12,925	10,532	28,834	19,049	15,718	14,053	11,073	9,111

Note:

(1)    Numbers may not add due to rounding.

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

Reserves Category	Revenue (MM$)	Royalties & Burdens(2) (MM$)	Operating Costs (MM$)	Development Costs (MM$)	Abandonment and Reclamation Costs (MM$)	Future Net Revenue Before Income Taxes (MM$)	Income Tax (MM$)	Future Net Revenue After Income Taxes (MM$)
Proved
Canada	36,499	3,711	12,672	2,812	922	16,383	2,186	14,197
United States	10,690	2,557	2,876	1,635	111	3,511	158	3,352
Total	47,189	6,269	15,547	4,447	1,033	19,894	2,344	17,550
Proved Plus Probable
Canada	59,885	6,052	20,093	4,513	1,151	28,076	5,375	22,701
United States	19,883	4,748	5,267	2,510	151	7,207	1,074	6,133
Total	79,768	10,801	25,359	7,023	1,302	35,283	6,450	28,834

Notes:

(1) Numbers may not add due to rounding.

(2) Saskatchewan Capital Resource Surcharge, as well as Ad Valorem, and Severance payable in the United States have been included under the royalties and burdens column.

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Future Net Revenue by Production Type⁽⁶⁾ 

	Future Net Revenue Before Income Taxes(5) (Discounted at 10% per year)	Percentage	Unit Value
	(MM$)	(%)	($/boe)	($/Mcfe)
Proved
CANADA
Light and Medium Crude Oil(1)	2,594	27.9	20.10	3.35
Heavy Crude Oil(1)	453	4.9	18.60	3.10
Tight Oil(3)	6,164	66.3	22.45	3.74
Natural Gas Liquids	—	—	—	—
Shale Gas(4)	—	—	—	—
Conventional Natural Gas(2)	84	0.9	6.40	1.07
Total Canada	9,295	100	21.07	3.51
UNITED STATES
Light and Medium Crude Oil(1)	1	0.1	19.24	3.21
Heavy Crude Oil(1)	—	—	—	—
Tight Oil(3)	1,754	99.7	15.47	2.58
Natural Gas Liquids	—	—	—	—
Shale Gas(2)	3	0.2	5.79	0.96
Conventional Natural Gas(2)	—	—	—	—
Total United States	1,759	100	15.43	2.57
TOTAL
Light and Medium Crude Oil(1)	2,595	23.5	20.10	3.35
Heavy Crude Oil(1)	453	4.1	18.60	3.10
Tight Oil(3)	7,918	71.6	20.41	3.40
Natural Gas Liquids	—	—	—	—
Shale Gas(2)(4)	3	—	5.79	0.96
Conventional Natural Gas(2)	84	0.8	6.40	1.07
Total Proved	11,053	100	19.91	3.32

Notes:

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

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

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

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

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

(6) Numbers may not add due to rounding.

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	Future Net Revenue Before Income Taxes(5) (Discounted at 10% per year)	Percentage	Unit Value
	(MM$)	(%)	($/boe)	($/Mcfe)
Proved Plus Probable
CANADA
Light and Medium Crude Oil(1)	3,885	28.5	18.88	3.15
Heavy Crude Oil(1)	545	4.0	17.73	2.96
Tight Oil(3)	9,115	66.8	21.04	3.51
Natural Gas Liquids	—	—	—	—
Shale Gas(4)	—	—	—	—
Conventional Natural Gas(2)	93	0.7	5.96	0.99
Total Canada	13,638	100	19.90	3.32
UNITED STATES
Light and Medium Crude Oil(1)	2	0.1	17.94	2.99
Heavy Crude Oil(1)	—	—	—	—
Tight Oil(3)	2,952	99.8	15.05	2.51
Natural Gas Liquids	—	—	—	—
Shale Gas(2)	4	0.1	5.56	0.93
Conventional Natural Gas(2)	—	—	—	—
Total United States	2,958	100	15.02	2.50
TOTAL
Light and Medium Crude Oil(1)	3,887	23.4	18.88	3.15
Heavy Crude Oil(1)	545	3.3	17.73	2.96
Tight Oil(3)	12,067	72.7	19.17	3.20
Natural Gas Liquids	—	—	—	—
Shale Gas(2)(4)	4	—	5.56	0.93
Conventional Natural Gas(2)	93	0.6	5.96	0.99
Total Proved Plus Probable	16,596	100	18.81	3.13

Notes:

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

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

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

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

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

(6) Numbers may not add due to rounding.

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 and Probable reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery.

The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions.

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

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

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

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

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

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

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.

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

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

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

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

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

(iv) provide improved recovery systems.

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

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

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

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

(iii) dry hole contributions and bottom hole contributions;

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

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

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

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

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and "stratigraphic condition" are intended to denote localized geological features, in contrast to broader terms such as "basin", "trend", "province", "play" or "area of interest".

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

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

(ii) if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Corporation is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (i).

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

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

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

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

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

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

(k) "gross" means:

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

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

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

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

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

(n) "net" means:

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

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

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

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

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

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

(r) "property" includes:

(i) fee ownership or a lease, concession, agreement, permit, licence 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.

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

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

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

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

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

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

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

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

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

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

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

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

Pricing Assumptions – Forecast Prices and Costs

GLJ and Sproule employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2018 in estimating our reserves data using forecast prices and costs.

Year	Conventional 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 ($Cdn/bbl)	Operating Cost Inflation Rate (%/yr)	Capital Cost Inflation Rate (%/yr)	Exchange Rate ($US/$Cdn)
Forecast
2019	3.00	1.95	63.00	75.27	75.32	40.91	30.27	0.0%	0.0%	0.770
2020	3.25	2.44	67.00	77.89	80.00	50.25	34.51	2.0%	2.0%	0.800
2021	3.50	3.00	70.00	82.25	83.75	56.88	38.15	2.0%	2.0%	0.800
2022	3.57	3.21	71.40	84.79	85.50	58.01	39.64	2.0%	2.0%	0.800
2023	3.64	3.30	72.83	87.39	87.29	59.17	40.62	2.0%	2.0%	0.800
2024	3.71	3.39	74.28	89.14	89.11	60.36	41.62	2.0%	2.0%	0.800
2025	3.79	3.49	75.77	90.92	90.96	61.56	42.64	2.0%	2.0%	0.800
2026	3.86	3.58	77.29	92.74	92.86	62.79	43.68	2.0%	2.0%	0.800
2027	3.94	3.68	78.83	94.60	94.79	64.05	44.75	2.0%	2.0%	0.800
2028	4.02	3.78	80.41	96.49	96.76	65.33	45.83	2.0%	2.0%	0.800
2029	4.10	3.88	82.02	98.42	98.77	66.64	46.94	2.0%	2.0%	0.800
2030+	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	2.0%	2.0%	0.800

For the year ended December 31, 2018, the average realized sales prices before hedging were $69.17/bbl for light and medium crude oil, $57.30/bbl for heavy crude oil, $70.14/bbl for tight oil, $33.66/bbl for NGLs, $2.35/mcf for shale gas and $2.00/mcf for conventional natural gas.

Reconciliations of Changes in Reserves⁽¹⁾ 

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, 2018 against such reserves as at December 31, 2017 based on forecast price and cost assumptions.

CANADA	Light and Medium Crude Oil (Mbbls)						Heavy Crude Oil (Mbbls)						Tight Oil (Mbbls)						Natural Gas Liquids (Mbbls)
Factors	Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable
December 31, 2017	142,531		79,797		222,328		26,335		7,237		33,571		222,676		129,610		352,286		55,361		29,298		84,659
Discoveries	—		—		—		—		—		—		—		—		—		—		—		—
Extensions and Improved Recovery (2)	14,731		8,858		23,590		1,613		710		2,323		24,335		15,552		39,887		5,027		3,452		8,479
Technical Revisions (4)	(832	)	(7,796	)	(8,628	)	2,732		(37	)	2,696		(4,001	)	(14,374	)	(18,375	)	7,016		(103	)	6,913
Acquisitions	22		51		73		—		—		—		499		62		561		9		1		10
Dispositions (6)	(16,587	)	(9,738	)	(26,325	)	—		—		—		(296	)	(567	)	(863	)	(1,377	)	(936	)	(2,313	)
Economic Factors	1,336		756		2,093		115		(7	)	108		818		384		1,202		(24	)	77		53
Production (8)	(13,846	)	—		(13,846	)	(1,780	)	—		(1,780	)	(24,298	)	—		(24,298	)	(6,189	)	—		(6,189	)
December 31, 2018	127,356		71,928		199,284		29,015		7,903		36,918		219,734		130,667		350,400		59,824		31,789		91,613

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CANADA	Shale Gas (Natural Gas) (MMcf)						Conventional Natural Gas (Natural Gas) (MMcf)						Total BOE (Mboe)
Factors	Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable
December 31, 2017	169,468		87,940		257,408		110,844		54,593		165,437		493,621		269,698		763,318
Discoveries	—		—		—		—		—		—		—		—		—
Extensions and Improved Recovery (2)	19,376		19,280		38,657		3,810		2,437		6,247		49,570		32,192		81,762
Technical Revisions (4)	9,551		(2,127	)	7,424		2,945		(2,754	)	191		6,999		(23,123	)	(16,124	)
Acquisitions	285		34		319		—		—		—		577		120		697
Dispositions (6)	—		—		—		(16,725	)	(12,754	)	(29,479	)	(21,047	)	(13,367	)	(34,414	)
Economic Factors	416		170		586		(5,793	)	(1,569	)	(7,362	)	1,349		976		2,326
Production (8)	(20,166	)	—		(20,166	)	(9,823	)	—		(9,823	)	(51,110	)	—		(51,110	)
December 31, 2018	178,930		105,297		284,228		85,259		39,953		125,212		479,960		266,495		746,455

UNITED STATES	Light and Medium Crude Oil(Mbbls)						Heavy Crude Oil (Mbbls)			Tight Oil (Mbbls)						Natural Gas Liquids (Mbbls)
Factors	Proved		Probable		Proved + Probable		Proved	Probable	Proved + Probable	Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable
December 31, 2017	1,049		4,382		5,431		—	—	—	101,023		74,641		175,664		13,729		9,741		23,470
Discoveries	—		—		—		—	—	—	—		—		—		—		—		—
Extensions and Improved Recovery (3)	—		—		—		—	—	—	24,561		16,816		41,377		3,034		1,534		4,569
Technical Revisions (5)	125		28		153		—	—	—	(5,292	)	(11,855	)	(17,147	)	937		(548	)	390
Acquisitions	—		—		—		—	—	—	97		44		141		4		1		6
Dispositions (7)	(792	)	(4,342	)	(5,134	)	—	—	—	(2,743	)	(936	)	(3,679	)	(557	)	(186	)	(743	)
Economic Factors	(18	)	(38	)	(56	)	—	—	—	(1,041	)	109		(933	)	(132	)	(30	)	(162	)
Production (8)	(296	)	—		(296	)	—	—	—	(10,990	)	—		(10,990	)	(1,040	)	—		(1,040	)
December 31, 2018	68		31		99		—	—	—	105,613		78,820		184,433		15,976		10,513		26,489

UNITED STATES	Shale Gas (Natural Gas) (MMcf)						Conventional Natural Gas (Natural Gas) (MMcf)						Total BOE (Mboe)
Factors	Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable
December 31, 2017	130,791		87,083		217,873		296		102		397		137,649		103,295		240,944
Discoveries	—		—		—		—		—		—		—		—		—
Extensions and Improved Recovery (3)	14,182		11,957		26,139		—		—		—		29,959		20,343		50,302
Technical Revisions (5)	(23,100	)	(25,516	)	(48,616	)	1,511		(136	)	1,376		(7,827	)	(16,650	)	(24,478	)
Acquisitions	178		89		267		—		—		—		131		61		192
Dispositions (7)	(3,147	)	(1,025	)	(4,172	)	—		—		—		(4,617	)	(5,634	)	(10,251	)
Economic Factors	(3,420	)	792		(2,628	)	(131	)	36		(96	)	(1,784	)	179		(1,605	)
Production (8)	(7,899	)	—		(7,899	)	(1,670	)	—		(1,670	)	(13,921	)	—		(13,921	)
December 31, 2018	107,585		73,380		180,965		5		2		8		139,589		101,594		241,183

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TOTAL	Light and Medium Crude Oil(Mbbls)						Heavy Crude Oil (Mbbls)						Tight Oil (4) (Mbbls)						Natural Gas Liquids (Mbbls)
Factors	Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable
December 31, 2017	143,580		84,179		227,759		26,335		7,237		33,571		323,698		204,252		527,950		69,090		39,039		108,129
Discoveries	—		—		—		—		—		—		—		—		—		—		—		—
Extensions and Improved Recovery (2) (3)	14,731		8,858		23,590		1,613		710		2,323		48,896		32,368		81,264		8,061		4,986		13,047
Technical Revisions (4)(5)	(707	)	(7,768	)	(8,474	)	2,732		(37	)	2,696		(9,293	)	(26,229	)	(35,522	)	7,954		(651	)	7,303
Acquisitions	22		51		73		—		—		—		596		107		702		13		3		16
Dispositions (6)(7)	(17,379	)	(14,080	)	(31,459	)	—		—		—		(3,039	)	(1,503	)	(4,542	)	(1,934	)	(1,122	)	(3,056	)
Economic Factors	1,318		718		2,036		115		(7	)	108		(223	)	492		269		(156	)	47		(109	)
Production (8)	(14,141	)	—		(14,141	)	(1,780	)	—		(1,780	)	(35,288	)	—		(35,288	)	(7,229	)	—		(7,229	)
December 31, 2018	127,424		71,959		199,383		29,015		7,903		36,918		325,347		209,486		534,833		75,800		42,302		118,102

TOTAL	Shale Gas (5) (Natural Gas) (MMcf)						Conventional Natural Gas (5) (Natural Gas) (MMcf)						Total BOE (Mboe)
Factors	Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable
December 31, 2017	300,259		175,023		475,281		111,140		54,695		165,834		631,270		372,993		1,004,262
Discoveries	—		—		—		—		—		—		—		—		—
Extensions and Improved Recovery (2) (3)	33,558		31,237		64,795		3,810		2,437		6,247		79,529		52,535		132,064
Technical Revisions (4)(5)	(13,549	)	(27,643	)	(41,192	)	4,456		(2,889	)	1,567		(829	)	(39,773	)	(40,602	)
Acquisitions	463		122		586		—		—		—		708		180		889
Dispositions (6)(7)	(3,147	)	(1,025	)	(4,172	)	(16,725	)	(12,754	)	(29,479	)	(25,664	)	(19,001	)	(44,665	)
Economic Factors	(3,004	)	962		(2,042	)	(5,924	)	(1,534	)	(7,458	)	(434	)	1,155		721
Production (8)	(28,064	)	—		(28,064	)	(11,493	)	—		(11,493	)	(65,031	)	—		(65,031	)
December 31, 2018	286,515		178,677		465,193		85,264		39,955		125,219		619,549		368,089		987,638

Notes:

(1) Numbers may not add due to rounding.

(2) The Corporation’s Canadian development strategy in 2018 included both step-out and in-fill development drilling, mostly in the Bakken and Torquay resource plays in southeast Saskatchewan; the Lower Shaunavon resource play in southwest Saskatchewan; and the emerging Duvernay resource play in Alberta. The Corporation also received 21.5 MMboe additional Total Proved plus Probable Improved Recovery bookings from the qualified reserve evaluators due to ongoing waterflood development activities.

(3) The Corporation’s United States development strategy in 2018 included both step-out and in-fill development drilling, mostly in the Bakken and Three Forks resource plays in North Dakota; as well as a focus on horizontal well development in the Uinta basin resource play in Utah.

(4) Negative technical revisions on Probable volumes are reflective of reserve volumes being transferred to Proven reserves categories as reserve confidence grows and locations are converted from Probable reserves to Proved plus Probable reserves, through either offset drilling increasing confidence in location bookings, or actual conversion of the location to developed (well) reserves.

Performance-based negative revisions were observed on existing primary (non-waterflood) Tight Oil assets including Viewfield Bakken, Flat Lake Torquay and Shaunavon resource assets, representing a large portion of the revisions in this category. The net Total Proved plus Probable impact represented here is only 1.6% of the prior year Corporate Total Proved plus Probable reserves.

Negative Technical Revisions were observed in the Corporations conventional assets in southeast Saskatchewan due to a full reassessment of the location inventory, which resulted in removal of a number of prior booked locations, many of which were replaced by locations in adjacent lands reflected as Extensions and Improved Recovery.

(5) In Utah, the Corporation reduced its vertical location inventory by 111 (81.8 net) locations in Total Proved reserves for a total of 6.9 MMboe; and 294 (129.1 net) locations in Total Proved plus Probable reserves for a total of 14.2 MMboe. These locations were both economic and technically feasible, however, due to a low likelihood of development within five years, are more appropriate to be considered as Contingent Resources.

(6)    Various Light and Medium Crude Oil assets in southeast Saskatchewan and Viking assets in Alberta were disposed during the year.

(7)    Non-core assets operated and non-operated were disposed in North Dakota.

(8) The Corporation produced an average of 140,027 boe per day in Canada, 38,139 boe per day in the United States for a total of 178,166 boe per day.

Undeveloped Reserves

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

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. These reserves represent a high degree of certainty to be recoverable, and may relate to planned infill drilling, lease-line as well as offset locations to current producing entities.

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The Corporation has extensive Proved development opportunities that are prioritized based on a disciplined set of criteria including, but not limited to time for payout, rate of return, maturity of land tenure, reserve booking opportunities, proximity to transportation and marketing, as well as anticipated production rates. With this extensive portfolio of opportunities, it would be unrealistic both from a cash flow as well as physical ability, to completely execute on the entire portfolio of booked opportunities within two years.

The development of these reserves have been based on recent and current capital activity levels, with no material deferrals of development opportunities beyond these normal budgetary constraints. The majority of these reserves are planned to be on stream within a three year timeframe, which represents approximately 75% of the net undeveloped location count, as well as 74% of the net total future development capital. These development activities are directed mostly to the Corporation's focus areas of Southeast Saskatchewan, Southwest Saskatchewan and Utah regions.

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 Crude Oil (Mbbl)

Heavy Crude Oil (Mbbl)

Tight Oil (Mbbl)

Natural Gas Liquids (Mbbl)

Shale Gas (MMcf)

Conventional Natural Gas (MMcf)

Oil Equivalent (Mboe)

First Attributed(1)

Total at Year-End

First Attributed(1)

Total at Year-End

First Attributed(1)

Total at Year-End

First Attributed(1)

Total at Year-End

First Attributed(1)

Total at Year-End

First Attributed(1)

Total at Year-End

First Attributed(1)

Total at Year-End

2016

3,164

43,999

—

2,006

9,944

132,528

1,406

19,813

5,535

108,708

1,866

24,915