EX-99.1 2 cpgye2021aif.htm EX-99.1 Document
Exhibit 99.1



cplogo2018a01a.jpg

CRESCENT POINT ENERGY CORP.
ANNUAL INFORMATION FORM
For the Year Ended December 31, 2021
Dated March 2, 2022



Contents

        
Section
Page
SPECIAL NOTES TO READER
GLOSSARY
SELECTED ABBREVIATIONS
CURRENCY OF INFORMATION
OUR ORGANIZATIONAL STRUCTURE
GENERAL DEVELOPMENT OF THE BUSINESS OF THE CORPORATION
DESCRIPTION OF OUR BUSINESS
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
ADDITIONAL INFORMATION RESPECTING CRESCENT POINT
INDUSTRY CONDITIONS
RISK FACTORS
DIVIDENDS AND SHARE REPURCHASES
MARKET FOR SECURITIES
CONFLICTS OF INTEREST
LEGAL PROCEEDINGS
AUDIT COMMITTEE
TRANSFER AGENT AND REGISTRARS
AUDITOR
MATERIAL CONTRACTS
INTERESTS OF EXPERTS
ADDITIONAL INFORMATION
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 AIF 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;
forecast prices and the expected impact of commodity price fluctuations on cash available to pay dividends;
hedging strategy, including expected outcomes, and the approach to managing physical delivery contracts;
risk mitigation strategy and the expected outcomes;
the potential impact of competition and our working relationships with industry partners and joint operators on Crescent Point's 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, including focus areas;
forecast costs and expenses associated with Crescent Point's business, including capital expenditure programs and how they will be funded;
leverage objectives;
corporate and asset acquisitions and dispositions;
drilling programs;
expected location inventory development timing;
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;
future enhanced oil recovery and waterflood programs;
the possible impacts of curtailment on Crescent Point;
the impacts of the Redwater decision;
expected decommissioning, abandonment, remediation and reclamation costs;


    - 1 -    
Crescent Point's tax horizon;
the impact of the Canada-United States-Mexico Agreement;
expected trends in environmental regulation, including the anticipated impact the trends may have on operations and compliance costs;
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 normal course issuer bid;
supply and demand for oil and natural gas;
expectations of legal and regulatory changes and implementations and change in governmental and regulatory bodies;
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;
the impacts of COVID-19; 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, 2021, under the headings "Risk Factors" and "Forward-Looking Information" and as disclosed in this AIF. The material assumptions and factors in making forward-looking statements are disclosed in the Management's Discussion and Analysis for the year ended December 31, 2021, under the headings "Capital Expenditures", "Commodity Derivatives", "Liquidity and Capital Resources", "Critical Accounting Estimates", "Risk Factors", "Changes in Accounting Policies" and "Guidance".
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 impacts of COVID-19; 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; 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 and of dispositions and monetization; 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; inflation; 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, including those listed under "Risk Factors" in this AIF. 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.


    - 2 -    
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. 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, if any, 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.
Netback received is calculated on a per boe basis as oil and gas sales, less royalties, operating and transportation expenses. Netback received excludes realized commodity derivative gains and losses. Netback received is 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 received 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 law. 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.
Currency Presentation
All references to "dollars" and "$" are to the currency of Canada, unless otherwise indicated. The daily rate of exchange on December 31, 2021, as reported by the Bank of Canada for the conversion of Canadian dollars into United States dollars was Cdn.$1.00 equals U.S.$0.7888 and for the conversion of United States dollars into Canadian dollars was U.S.$1.00 equals Cdn.$1.2678. The following table sets forth, for 2021 and 2020, the high, low and average of the daily exchange rates for that year, each for one U.S. dollar expressed in Canadian dollars as reported by the Bank of Canada.


    - 3 -    
Year ended December 31, 2021 (Cdn$/Usd)
Year ended December 31, 2020 (Cdn$/Usd)
High
0.83060.7863
Low
0.77270.6898
Average
0.79800.7461
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.


    - 4 -    
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 2, 2022 for the year ended December 31, 2021.
"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.

"CPHL" means Crescent Point Holdings Ltd.
"CP Lux" 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 DividendTM and Dividend Reinvestment Plan of the Corporation.
"DSU Plan" means the Deferred Share Unit Plan of the Corporation.
"ESVP" means the Employee Share Value Plan of the Corporation.
"FAST Act" means the Fixing America’s Surface Transportation Act.
"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.
"McDaniel" means McDaniel & Associates Consultants Ltd.

"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, 2021.
"NCIB" means normal course issuer bid.


    - 5 -    
"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 and cooperating oil-exporting nations.
"Partnership" means Crescent Point Resources Partnership, a general partnership formed under the laws of the Province of Alberta, having CPHL 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.
"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.
"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".


    - 6 -    
SELECTED ABBREVIATIONS
In this AIF, the abbreviations set forth below have the following meanings:
Oil and Natural Gas LiquidsNatural Gas
bblbarrelMcfthousand cubic feet
bblsbarrelsMcf/dthousand cubic feet per day
bbls/dbarrels per dayMcfethousand cubic feet of gas equivalent converting one barrel of oil to 6 Mcf of natural gas equivalent
Mbblsthousand barrels
NGLsnatural gas liquids
MMcfmillion cubic feet
MMcf/dmillion cubic feet per day
MMBTUmillion British Thermal Units
Other
AECOthe natural gas storage facility located at Suffield, Alberta
boe or BOEbarrels of oil equivalent 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.
boe/dbarrel of oil equivalent per day
cubic metres
M$thousand dollars
Mboethousand barrels of oil equivalent
MMboemillion barrels of oil equivalent
MM$million dollars
NYMEXNew York Mercantile Exchange natural gas price
tCO2e/boetonnes of carbon dioxide equivalent per barrel of oil equivalent
WTIWest Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade



    - 7 -    
CURRENCY OF INFORMATION
The information set out in this AIF is stated as at December 31, 2021, 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, natural gas liquids 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 CPHL 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.
CPHL
CPHL is a wholly-owned subsidiary of the Corporation. CPHL is a partner of the Partnership.


    - 8 -    
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
CPHL
100%
Alberta
Partnership
100%
Alberta
CPUSH
100%
Nevada
CPEUS
100%
Delaware
Organizational Structure of the Corporation
The following diagram describes the inter-corporate relationships among the Corporation and its material direct and indirect subsidiaries described above as at December 31, 2021 and current to March 2, 2022. Reference should be made to the appropriate sections of this AIF for a complete description of the structure of the Corporation.
orgcharta.jpg


    - 9 -    
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.
2019
On January 25, 2019, the Corporation commenced its NCIB to purchase, for cancellation, up to 38,424,678 Common Shares, or seven percent of the Corporation’s public float, as at January 14, 2019. The NCIB expired on January 24, 2020. The Company purchased 26,238,600 Common Shares under the NCIB.
On March 7, 2019, John P. Dielwart was appointed to the Board. See "Additional Information Respecting Crescent Point - Directors and Officers".
On June 14, 2019, James Craddock and Jennifer Koury were appointed to the Board. See "Additional Information Respecting Crescent Point - Directors and Officers".
In September 2019, Crescent Point disposed of certain conventional assets in southeast Saskatchewan for consideration of $196.9 million, representing approximately 7,000 boe/d of production.
On October 18, 2019, Crescent Point sold the entirety of its Utah assets for approximately $700 million.
On October 25, 2019, Crescent Point elected to reduce its covenant-based credit facilities from $3.6 billion to $3.0 billion and extended the maturity dates to October 2023.
On October 30, 2019, Barbara Munroe was appointed Chair of the Board, replacing Robert Heinemann, who retired from the Board.
2020
On January 20, 2020, Crescent Point sold certain associated gas infrastructure assets in Saskatchewan to Steel Reef Infrastructure Corp. ("Steel Reef") for total cash consideration of $500 million. Through the sale of these assets, Crescent Point monetized nine natural gas gathering and processing facilities and two gas sales pipelines currently in operation within Saskatchewan. These gas processing facilities and associated sales gas lines have a total throughput capacity of more than 90 MMcf/d. The assets did not include any oil-related infrastructure. Concurrently, Crescent Point entered into certain long-term take-or-pay commitments with Steel Reef in exchange for Steel Reef granting Crescent Point processing rights at the facilities.
On March 5, 2020, the Corporation announced the approval by the Toronto Stock Exchange of its notice to implement an NCIB to purchase, for cancellation, 36,884,438 common shares, or seven percent of the Company's public float, as at February 28, 2020. The 2020 NCIB commenced on March 9, 2020 and expired on March 8, 2021. No purchases were made under the NCIB.

On March 16, 2020, Crescent Point announced that (i) it had revised its 2020 capital expenditures budget to $700 to $800 million, which was expected to generate annual average production of 130,000 to 134,000 boe/d; and (ii) it had revised its dividend from $0.01 per share payable every quarter to $0.0025 payable every quarter commencing in the second quarter of 2020; and (iii) all purchases under the NCIB had been deferred.

On April 20, 2020, Crescent Point announced that it had further revised its capital expenditures budget to approximately $650 to $700 million and lowered its production guidance for the year 2020 by 15%, primarily due to the voluntary shut-in of higher cost production.



    - 10 -    
On June 30, 2020, CPHI transferred its interest in the Partnership to CPHL, a newly incorporated and wholly-owned subsidiary of Crescent Point. CP Lux was dissolved effective July 13, 2020.

On July 30, 2020, Myron Stadnyk was appointed to the Board. See "Additional Information Respecting Crescent Point - Directors and Officers".

On September 1, 2020, Crescent Point announced that it had reactivated shut-in volumes, which reactivation resulted in expected second half 2020 production increasing by approximately 20 percent to 119,000 to 121,000 boe/d.

2021

On February 17, 2021, the Company entered into an agreement with Shell Canada Energy (“Shell”), an affiliate of Royal Dutch Shell plc, to acquire Shell’s Kaybob Duvernay assets in Alberta for $900 million. The total consideration consisted of $700 million in cash and 50 million common shares of Crescent Point. The acquisition closed in April 2021.

On March 5, 2021, the Company announced the approval by the Toronto Stock Exchange of its notice to implement an NCIB to purchase, for cancellation, 26,462,509 common shares, or five percent of the Company's public float, as at February 26, 2021. The NCIB commenced on March 9, 2021 and is due to expire on March 8, 2022. As of December 31, 2021, the Company had repurchased 2,817,000 common shares under the NCIB. As of February 28, 2022, the Company had repurchased 7,837,300 common shares under the NCIB.

On June 7, 2021 the Company completed the disposition of its remaining non-core southeast Saskatchewan conventional assets, which were previously identified as disposition candidates, for cash proceeds of $93 million. As a result of the transaction, Crescent Point also reduced its asset retirement obligations by approximately $220 million, or nearly 25 percent of its asset retirement obligations balance as at March 31, 2021.

On September 13, 2021, the Company announced that it was increasing its quarterly dividend from $0.0025 per share payable every quarter to $0.03 per share payable every quarter, commencing with the fourth quarter of 2021.

On December 6, 2021, the Company announced that it was increasing its quarterly dividend from $0.03 per share payable every quarter to $0.045 per share payable every quarter, commencing with the first quarter of 2022.

CPHI, a former partner of the Partnership, was dissolved effective December 31, 2021.
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, natural gas liquids 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 CPHL, 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 and Montana. The properties and assets consist of producing crude oil, natural gas liquids and natural gas reserves and Proved plus Probable (as defined herein) crude oil, natural gas liquids 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, 2021, total dividends declared to shareholders were $0.0825 per Common Share. See "Dividends".


    - 11 -    
Strategy
Our strategy is to deliver lasting market-leading value to our stakeholders as a trusted, ethical and environmentally responsible source for energy. We will maintain a resilient, balanced and sustainable portfolio, and apply our agile, diverse, learning mindset to optimize all aspects of our business.
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, multi-stage fracture stimulation of horizontal wells, infill and step-out wells, re-completion of existing wells along with the application of secondary and enhanced oil recovery techniques, including 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 America, Eastern Europe 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 and changes in demand as a result of outbreaks or other health emergencies;
(h)    price and availability of alternative energy sources;
(i)    the effect of energy conservation measures and government regulations;
(j)    U.S. and Canada tax policy; and
(k)     pandemics, such as the COVID-19 health emergency.

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, benchmark natural gas prices are hedged using financial AECO-based instruments transacted in Canadian dollars. Total financial oil and gas hedges in 2021 amounted to approximately


    - 12 -    
46% of annual production, net of royalties, consisting of approximately 49% of annual liquids production and approximately 30% of annual natural gas production, net of royalties. The Corporation recorded a realized derivative loss on crude oil, NGL and natural gas hedge contracts of $360.8 million in 2021.
Crescent Point also enters into physical delivery and derivative WTI price differential contracts which manage the spread between US$ 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 2021, approximately 23,000 bbls/d of liquids production was contracted with fixed price differentials off WTI. Crescent Point also enters into derivative NYMEX price differential contracts which manage the spread between US$ NYMEX and AECO-based pricing on a portion of its natural gas production.
Refer to the annual financial statements for our commitments under all hedging agreements as at December 31, 2021.
In addition to hedging benchmark crude oil and natural gas prices with financial instruments, we also have the ability to mitigate crude oil basis risk by delivering a portion of our crude oil production into diversified refinery markets using rail transportation when it is economically beneficial to do so. Crescent Point operates two railcar loading facilities, serving its key producing areas of southeast Saskatchewan and southwest Saskatchewan. Crude oil and NGL 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. By utilizing rail transportation, we have been able to access markets over the past several years that are not pipeline connected to western Canada, which helps diversify 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 83 purchasers and its financial hedging portfolio consists of 10 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, obtains prepayments, letters of credit and third party credit insurance. Including these assurances, approximately 96% of the Corporation’s oil and gas sales are with entities considered investment grade.
Revenue Sources
Our crude oil and natural gas volumes are sold in the United States, Saskatchewan, Alberta and British Columbia. Approximately 66% of our liquids volumes are sold in Saskatchewan, 18% in Alberta, 15% in the U.S. and less than 1% in British Columbia. Approximately 54% of our natural gas volumes are sold in Alberta, 34% in Saskatchewan, 11% in the United States and less than 1% in British Columbia.
For 2021, our commodity production mix was approximately 48% tight oil, 22% NGLs, 13% light and medium oil, 13% shale gas, 3% heavy oil and 1% conventional natural gas.


    - 13 -    
The following table summarizes our revenue sources by product before hedging and royalties:
For Year EndedLight and Medium Crude OilHeavy
Crude Oil
 Tight OilNGLsShale GasConventional Natural Gas
202115.4%3.4%55.8%19.6%5.3%0.5%
202019.8%3.6%66.8%5.4%3.6%0.8%
201921.9%3.2%67.7%4.5%2.2%0.5%

Competition
We actively compete for reserve acquisitions, exploration leases, licenses 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.
COVID-19 Pandemic

In response to the COVID-19 pandemic, the Corporation has implemented additional health and safety protocols within its Calgary office and field operations and continues to monitor the situation and make adjustments to its health and safety protocols as required.
Crude oil and natural gas prices strengthened in 2021, compared to 2020, as the global recovery from the COVID-19 pandemic and vaccine roll outs facilitated increased mobility, resulting in higher demand for crude oil and crude oil products and lower inventory levels.

Personnel
As of December 31, 2021, the Corporation had 748 permanent employees: 385 employees at the head office in Calgary, 13 employees working remotely in the U.S., 331 field employees in Canada and 19 field employees in the U.S.


    - 14 -    
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 conducted by McDaniel with an effective date of December 31, 2021 (the "Crescent Point Reserve Report"). The tables below are a combined summary of our crude oil, natural gas liquids, 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 December 31, 2021 forecast price and cost assumptions using the average of three Independent Reserve Evaluators (McDaniel, GLJ Ltd. and Sproule Associates Ltd.). McDaniel evaluated the Corporation’s total Proved plus Probable reserves and total Proved plus Probable value discounted at 10% and evaluated all of the Company’s properties to prepare the Crescent Point Reserve Report. The tables below summarize the data contained in the Crescent Point Reserve Report.

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 emission costs, and well and location abandonment costs. The reserve assessments also include costs associated with wells that have not been assessed values in the reserve reports and facilities and gathering systems associated with the ongoing production for the Corporation. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to our reserves estimated by McDaniel 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.
The Corporation continuously monitors and reviews legislation concerning greenhouse gas emissions and the impact on operations. Legislation adopted in 2019 has allowed Crescent Point to reduce anticipated negative financial impacts from the production of oil and gas products through the Output-Based Performance Standard ("OBPS") program in Saskatchewan and the Technology Innovation and Emission Reduction ("TIER") program in Alberta. The carbon emission costs related to government programs are fully integrated into the operating costs and capital unit costs in the reserve evaluation.
The Crescent Point Reserve Report includes the abandonment, decommissioning, and reclamation costs for both the active and inactive locations, including all non-producing and suspended wells, facilities and pipelines. The incremental liabilities from the inactive locations on the total Proved plus Probable reserves is estimated at $202 million of value discounted at 10%. The total impact in the Crescent Point Reserve Report from the combined active and inactive liabilities on total Proved plus Probable reserves is estimated at $297 million of value discounted at 10%.
The Crescent Point Reserve Report is based on certain factual data supplied by Crescent Point as well as McDaniel's opinion of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to Crescent Point's petroleum properties and contracts were supplied by the Corporation to McDaniel, and were accepted without any further investigation. McDaniel accepted this data as presented and neither title searches nor field inspections were conducted.


    - 15 -    
Reserves Data – Forecast Prices and Costs
Summary of Oil and Gas Reserves(1)
Light and Medium Crude OilHeavy 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
Canada46,241 41,857 20,230 16,839 103,654 97,632 65,945 58,994 240,743 226,502 39,979 36,719 282,856 259,192 
United States— — — — 14,374 11,642 6,004 4,864 19,062 15,443 — — 23,556 19,081 
Total46,241 41,857 20,230 16,839 118,028 109,274 71,949 63,859 259,805 241,945 39,979 36,719 306,412 278,273 
Proved Developed Non-Producing
Canada528 505 2,352 2,136 246 235 84 78 173 161 165 148 3,267 3,004 
United States— — — — 1,515 1,227 419 340 1,331 1,078 — — 2,156 1,746 
Total528 505 2,352 2,136 1,761 1,462 504 418 1,504 1,239 165 148 5,423 4,751 
Proved Undeveloped
Canada14,353 13,561 1,677 1,460 44,029 41,575 52,610 47,172 167,807 156,512 3,468 3,223 141,215 130,390 
United States— — — — 17,726 14,358 4,967 4,023 15,769 12,773 — — 25,321 20,510 
Total14,353 13,561 1,677 1,460 61,755 55,934 57,577 51,195 183,576 169,285 3,468 3,223 166,536 150,900 
Total Proved
Canada61,122 55,922 24,259 20,434 147,930 139,442 118,638 106,244 408,722 383,175 43,612 40,090 427,338 392,586 
United States— — — — 33,615 27,228 11,391 9,227 36,162 29,294 — — 51,033 41,337 
Total61,122 55,922 24,259 20,434 181,545 166,669 130,029 115,471 444,884 412,469 43,612 40,090 478,371 433,924 
Total Probable
Canada40,574 36,729 7,255 6,091 81,170 76,583 39,126 33,120 131,140 121,900 25,077 23,108 194,161 176,691 
United States— — — — 26,698 21,652 8,616 6,988 27,353 22,185 — — 39,873 32,338 
Total40,574 36,729 7,255 6,091 107,868 98,235 47,742 40,108 158,493 144,084 25,077 23,108 234,035 209,029 
Total Proved Plus Probable
Canada101,696 92,651 31,514 26,525 229,100 216,025 157,764 139,364 539,862 505,075 68,690 63,198 621,500 569,278 
United States— — — — 60,314 48,879 20,007 16,216 63,515 51,478 — — 90,907 73,675 
Total101,696 92,651 31,514 26,525 289,413 264,905 177,772 155,579 603,377 556,553 68,690 63,198 712,406 642,952 
Note:
(1)    Numbers may not add due to rounding.



    - 16 -    
Net Present Value of Future Net Revenue of Oil and Gas Reserves(1)
Before Income Taxes Discounted at
(%/year)
After Income Taxes Discounted at
(%/year)
Reserves Category0%
(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
Canada8,086 6,643 5,953 5,571 4,822 4,279 7,660 6,372 5,740 5,387 4,689 4,177 
United States542 476 444 425 385 354 540 473 440 421 380 348 
Total
8,628 7,119 6,397 5,995 5,207 4,633 8,200 6,845 6,180 5,808 5,069 4,524 
Proved Developed Non-Producing
Canada106 69 56 50 38 30 82 55 45 40 31 25 
United States70 63 60 58 54 51 69 63 59 57 53 50 
Total
175 132 116 108 92 81 152 117 104 97 85 76 
Proved Undeveloped
Canada3,322 2,344 1,930 1,706 1,273 969 2,445 1,692 1,374 1,202 874 645 
United States475 354 300 269 209 164 472 354 302 272 213 170 
Total
3,797 2,697 2,230 1,975 1,482 1,133 2,917 2,046 1,676 1,474 1,087 815 
Total Proved
Canada11,513 9,056 7,940 7,326 6,133 5,279 10,188 8,119 7,159 6,629 5,594 4,847 
United States1,087 893 803 752 648 569 1,081 890 801 750 647 568 
Total
12,600 9,948 8,743 8,078 6,781 5,848 11,269 9,008 7,960 7,379 6,240 5,415 
Total Probable
Canada7,095 4,063 3,089 2,625 1,846 1,380 5,351 3,017 2,279 1,930 1,350 1,007 
United States1,019 711 590 527 409 329 931 657 550 493 387 315 
Total
8,114 4,774 3,680 3,152 2,255 1,709 6,282 3,675 2,829 2,423 1,737 1,322 
Total Proved Plus Probable
Canada18,608 13,119 11,029 9,951 7,980 6,659 15,539 11,136 9,438 8,559 6,944 5,854 
United States2,106 1,604 1,394 1,279 1,057 898 2,012 1,547 1,351 1,243 1,034 883 
Total
20,714 14,723 12,422 11,230 9,037 7,557 17,551 12,683 10,789 9,803 7,978 6,737 
Note:
(1)    Numbers may not add due to rounding.




    - 17 -    
Additional Information Concerning Future Net Revenue – (Undiscounted)(1)
Reserves CategoryRevenue
(MM$)
Royalties & Burdens(2)
(MM$)
Operating
Costs
(MM$)
Development
Costs
(MM$)
Abandonment and Reclamation
Costs(3)
(MM$)
Future Net
Revenue Before
Income Taxes
(MM$)
Income Tax
(MM$)
Future Net
Revenue After
Income Taxes
(MM$)
Proved
Canada28,483 2,797 10,111 2,627 1,434 11,513 1,325 10,188 
United States3,320 861 951 390 31 1,087 1,081 
Total31,802 3,658 11,062 3,017 1,465 12,600 1,331 11,269 
Proved Plus Probable
Canada43,534 4,376 15,088 3,878 1,584 18,608 3,069 15,539 
United States6,080 1,577 1,659 699 40 2,106 94 2,012 
Total49,614 5,953 16,747 4,577 1,624 20,714 3,163 17,551 
Notes:
(1)    Numbers may not add due to rounding.
(2)    Saskatchewan Capital Resource Surcharge, as well as Ad Valorem, have been included under the royalties and burdens column.
(3) In accordance with COGEH, abandonment and reclamation costs include: (i) active costs from wells and locations included in the Crescent Point Reserve Report; and (ii) inactive costs that include wells with no reserves assigned, suspended wells, pipeline, and facilities. The undiscounted abandonment and reclamation costs associated with those wells and locations included in the Crescent Point Reserve Report amounts to $788 million and $947 million for Proved and Proved plus Probable, respectively.
Future Net Revenue by Production Type(1)
Future Net Revenue
Before Income Taxes(2)
(Discounted at 10% per year)
PercentageUnit Value
(MM$)(%)($/boe)($/Mcfe)
Proved
CANADA
Light and Medium Crude Oil(3)
1,195 16.3 18.70 3.12 
Heavy Crude Oil(3)
352 4.8 17.13 2.85 
Tight Oil(5)
3,432 46.8 18.38 3.06 
Shale Gas(6)
2,288 31.2 20.15 3.36 
Conventional Natural Gas(4)
59 0.8 7.53 1.26 
Total Canada7,326 100 18.66 3.11 
UNITED STATES
Light and Medium Crude Oil(3)
— — — — 
Heavy Crude Oil(3)
— — — — 
Tight Oil(5)
752 100 18.19 3.03 
Shale Gas(4)(6)
— — — — 
Conventional Natural Gas(4)
— — — — 
Total United States752 100 18.19 3.03 
TOTAL
Light and Medium Crude Oil(3)
1,195 14.8 18.70 3.12 
Heavy Crude Oil(3)
352 4.4 17.13 2.85 
Tight Oil(5)
4,184 51.8 18.34 3.06 
Shale Gas(4)(6)
2,288 28.3 20.15 3.36 
Conventional Natural Gas(4)
59 0.7 7.53 1.26 
Total Proved8,078 100 18.62 3.10 
Notes:
(1)    Numbers may not add due to rounding.
(2)    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.
(3)    Including solution gas and other by-products.
(4)    Including by-products, but excluding solution gas.
(5)    Including solution gas (categorized as “Shale Gas”) and other by-products.
(6)    Shale Gas includes the majority of Natural Gas Liquids.


    - 18 -    
Future Net Revenue
Before Income Taxes
(2)
(Discounted at 10% per year)
PercentageUnit Value
(MM$)(%)($/boe)($/Mcfe)
Proved Plus Probable
CANADA
Light and Medium Crude Oil(3)
1,838 18.5 16.64 2.77 
Heavy Crude Oil(3)
428 4.3 16.02 2.67 
Tight Oil(5)
4,932 49.6 17.41 2.90 
Shale Gas(6)
2,687 27.0 19.30 3.22 
Conventional Natural Gas(4)
66 0.7 6.94 1.16 
Total Canada9,951 100 17.48 2.91 
UNITED STATES
Light and Medium Crude Oil(3)
— — — — 
Heavy Crude Oil(3)
— — — — 
Tight Oil(5)
1,279 100 17.36 2.89 
Shale Gas(4)(6)
— — — — 
Conventional Natural Gas(4)
— — — — 
Total United States1,279 100 17.36 2.89 
TOTAL
Light and Medium Crude Oil(3)
1,838 16.4 16.64 2.77 
Heavy Crude Oil(3)
428 3.8 16.02 2.67 
Tight Oil(5)
6,211 55.3 17.40 2.90 
Shale Gas(4)(6)
2,687 23.9 19.30 3.22 
Conventional Natural Gas(4)
66 0.6 6.94 1.16 
Total Proved Plus Probable11,230 100 17.47 2.91 
Notes:
(1)    Numbers may not add due to rounding.
(2)    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.
(3)    Including solution gas and other by-products.
(4)    Including by-products, but excluding solution gas.
(5)    Including solution gas (categorized as “Shale Gas”) and other by-products.
(6)    Shale Gas includes the majority of Natural Gas Liquids.


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 in accordance with NI 51-101 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 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.


    - 19 -    
(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.
(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.


    - 20 -    
(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 defense, 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" 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".


    - 21 -    
(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.


    - 22 -    
(o)    "non-associated gas" means an accumulation of natural gas in a reservoir where there is no crude oil.
(p)    "operating costs" or "production costs" means costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment and facilities as well as other costs of operating and maintaining those wells and related equipment and facilities.
(q)    "production" means recovering, gathering, treating, field or plant processing (for example, processing gas to extract natural gas liquids) and field storage of oil and gas.
(r)    "property" includes:
(i)    fee ownership or a lease, concession, agreement, permit, license or other interest representing the right to extract oil or gas subject to such terms as may be imposed by the conveyance of that interest;
(ii)    royalty interests, production payments payable in oil or gas, and other non-operated interests in properties operated by others; and
(iii)    an agreement with a foreign government or authority under which the Corporation participates in the operation of properties or otherwise serves as "producer" of the underlying reserves (in contrast to being an independent purchaser, broker, dealer or importer).
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".


    - 23 -    
(y)    "support equipment and facilities" means equipment and facilities used in oil and gas activities, including seismic equipment, drilling equipment, construction and grading equipment, vehicles, repair shops, warehouses, supply points, camps, and division, district or field offices.
(z)    "unproved property" means a property or part of a property to which no reserves have been specifically attributed.
(aa)    "well abandonment and reclamation costs" means costs of abandoning a well (net of salvage value) and of disconnecting the well from the surface gathering system and remediating and reclaiming the site to original conditions. They do not include costs of abandoning the gathering system.
Pricing Assumptions – Forecast Prices and Costs
McDaniel employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2021 in estimating our reserves data using forecast prices and costs.
YearCrude OilConventional Natural GasNGLs
WTI at
Cushing
Oklahoma
($US/bbl)
Edmonton
($Cdn/bbl)
Henry Hub
NYMEX
($US/MMBTU)
AECO/NIT
Spot
($Cdn/MMBTU)
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
202272.83 86.82 3.85 3.56 91.85 57.49 43.38 0.0%0.0%0.797
202368.7880.733.443.2185.5350.1735.922.3%2.3%0.797
202466.76 78.01 3.17 3.05 82.98 48.53 34.62 2.0%2.0%0.797
202568.0979.573.243.1184.6349.5035.312.0%2.0%0.797
202669.45 81.16 3.30 3.17 86.33 50.49 36.02 2.0%2.0%0.797
202770.8482.783.373.2388.0551.5036.742.0%2.0%0.797
202872.26 84.44 3.44 3.30 89.82 52.53 37.47 2.0%2.0%0.797
202973.7086.133.503.3691.6153.5838.222.0%2.0%0.797
203075.18 87.85 3.58 3.43 93.44 54.65 38.99 2.0%2.0%0.797
203176.6889.613.653.5095.3255.7439.772.0%2.0%0.797
203278.21 91.40 3.72 3.57 97.22 56.86 40.56 2.0%2.0%0.797
2033++2%/yr+2%/yr+2%/yr+2%/yr+2%/yr+2%/yr+2%/yr2.0%2.0%0.797




    - 24 -    
Reconciliations of Changes in Reserves(1)
The following table sets forth a reconciliation of the Corporation's working interest reserves by total Proved, total Probable and total Proved plus Probable reserves as at December 31, 2021, against such reserves as at December 31, 2020, 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)
FactorsProvedProbableProved
+
Probable
ProvedProbableProved
+
Probable
ProvedProbableProved
+
Probable
ProvedProbableProved
+
Probable
December 31, 202083,454 53,678 137,131 24,935 6,665 31,600 151,399 107,971 259,370 43,135 25,745 68,880 
Discoveries— — — — — — — — — — — — 
Extensions and Improved Recovery (2)
6,786 1,753 8,539 1,810 1,362 3,173 10,834 134 10,968 30,987 6,087 37,074 
Technical Revisions (4)
(3,267)(2,184)(5,451)(1,863)(939)(2,802)2,583 (24,125)(21,542)(1,015)(4,371)(5,386)
Acquisitions (5)
24 30 — — — — — — 54,314 12,326 66,641 
Dispositions (6)
(23,463)(14,422)(37,885)— — — (1,943)(3,393)(5,336)(1,396)(1,159)(2,554)
Economic Factors (7)
4,107 1,744 5,851 911 167 1,078 2,973 583 3,556 1,617 498 2,115 
Production (8)
(6,519)— (6,519)(1,534)— (1,534)(17,917)— (17,917)(9,005)— (9,005)
December 31, 202161,122 40,574 101,696 24,259 7,255 31,514 147,930 81,170 229,100 118,638 39,126 157,764 

CANADA
Shale Gas
(Natural Gas)
(MMcf)
Conventional Natural Gas
(Natural Gas)
(MMcf)
Total BOE
(Mboe)
FactorsProvedProbableProved
+
Probable
ProvedProbableProved
+
Probable
ProvedProbableProved
+
Probable
December 31, 2020122,717 78,924 201,641 52,042 29,381 81,423 332,049 212,110 544,159 
Discoveries— — — — — — — — — 
Extensions and Improved Recovery (2)
112,599 20,170 132,769 1,581 820 2,402 69,448 12,834 82,282 
Technical Revisions (4)
2,749 (11,430)(8,681)(1,970)(1,940)(3,910)(3,432)(33,847)(37,279)
Acquisitions (5)
203,901 48,064 251,966 — — — 88,322 20,343 108,665 
Dispositions (6)
(3,188)(5,272)(8,460)(7,728)(4,712)(12,440)(28,621)(20,638)(49,259)
Economic Factors (7)
2,627 683 3,310 3,822 1,527 5,350 10,683 3,360 14,043 
Production (8)
(32,682)— (32,682)(4,135)— (4,135)(41,110)— (41,110)
December 31, 2021408,722 131,140 539,862 43,612 25,077 68,690 427,338 194,161 621,500 

UNITED STATES
Light and Medium Crude Oil (Mbbls)
Heavy Crude Oil
(Mbbls)
Tight Oil
(Mbbls)
Natural Gas Liquids
(Mbbls)
FactorsProvedProbableProved
+
Probable
ProvedProbableProved
+
Probable
ProvedProbableProved
+
Probable
ProvedProbableProved
+
Probable
December 31, 2020— — — — — — 54,862 28,952 83,815 14,947 8,087 23,034 
Discoveries— — — — — — — — — — — — 
Extensions and Improved Recovery (3)
— — — — — — 1,304 82 1,386 417 154 571 
Technical Revisions (4)
— — — — — — (20,260)(3,283)(23,543)(3,370)27 (3,343)
Acquisitions— — — — — — — — — — — — 
Dispositions— — — — — — — — — — — — 
Economic Factors (7)
— — — — — — 2,602 946 3,549 997 348 1,345 
Production (8)
— — — — — — (4,893)— (4,893)(1,600)— (1,600)
December 31, 2021— — — — — — 33,615 26,698 60,314 11,391 8,616 20,007 



    - 25 -    
UNITED STATES
Shale Gas
(Natural Gas)
(MMcf)
Conventional Natural Gas
(Natural Gas)
(MMcf)
Total BOE
(Mboe)
FactorsProvedProbableProved
+
Probable
ProvedProbableProved
+
Probable
ProvedProbableProved
+
Probable
December 31, 202054,021 31,956 85,977 — — — 78,813 42,366 121,179 
Discoveries— — — — — — — — — 
Extensions and Improved Recovery (3)
1,323 489 1,813 — — — 1,941 318 2,259 
Technical Revisions (5)
(17,390)(6,196)(23,585)— — — (26,529)(4,288)(30,817)
Acquisitions— — — — — — — — — 
Dispositions— — — — — — — — — 
Economic Factors (7)
3,166 1,103 4,269 — — — 4,127 1,478 5,605 
Production (8)
(4,958)— (4,958)— — — (7,319)— (7,319)
December 31, 202136,162 27,353 63,515 — — — 51,033 39,873 90,907 

TOTAL
Light and Medium Crude Oil (Mbbls)
Heavy Crude Oil
(Mbbls)
Tight Oil (4)
(Mbbls)
Natural Gas Liquids
(Mbbls)
FactorsProvedProbableProved
+
Probable
ProvedProbableProved
+
Probable
ProvedProbableProved
+
Probable
ProvedProbableProved
+
Probable
December 31, 202083,454 53,678 137,131 24,935 6,665 31,600 206,262 136,923 343,185 58,082 33,832 91,914 
Discoveries— — — — — — — — — — — — 
Extensions and Improved Recovery (2) (3)
6,786 1,753 8,539 1,810 1,362 3,173 12,139 216 12,355 31,404 6,241 37,645 
Technical Revisions (4)
(3,267)(2,184)(5,451)(1,863)(939)(2,802)(17,677)(27,407)(45,085)(4,385)(4,344)(8,729)
Acquisitions (5)
24 30 — — — — — — 54,314 12,327 66,641 
Dispositions (6)
(23,463)(14,422)(37,885)— — — (1,943)(3,393)(5,336)(1,396)(1,159)(2,554)
Economic Factors (7)
4,107 1,744 5,851 911 167 1,078 5,575 1,530 7,104 2,615 845 3,460 
Production (8)
(6,519)— (6,519)(1,534)— (1,534)(22,810)— (22,810)(10,605)— (10,605)
December 31, 202161,122 40,574 101,696 24,259 7,255 31,514 181,545 107,868 289,413 130,029 47,742 177,772 


    - 26 -    
TOTAL
Shale Gas (5)
(Natural Gas) (MMcf)
Conventional Natural Gas
(Natural Gas)
(MMcf)
Total BOE
(Mboe)
FactorsProvedProbableProved
+
Probable
ProvedProbableProved
+
Probable
ProvedProbableProved
+
Probable
December 31, 2020176,738 110,880 287,618 52,042 29,381 81,423 410,862 254,476 665,338 
Discoveries— — — — — — — — — 
Extensions and Improved Recovery (2) (3)
113,922 20,659 134,581 1,581 820 2,402 71,389 13,151 84,541 
Technical Revisions (4)
(14,641)(17,625)(32,266)(1,970)(1,940)(3,910)(29,961)(38,135)(68,096)
Acquisitions (5)
203,901 48,064 251,966 — — — 88,322 20,343 108,665 
Dispositions (6)
(3,188)(5,272)(8,460)(7,728)(4,712)(12,440)(28,621)(20,638)(49,259)
Economic Factors (7)
5,793 1,786 7,579 3,822 1,527 5,350 14,810 4,838 19,648 
Production (8)
(37,640)— (37,640)(4,135)— (4,135)(48,429)— (48,429)
December 31, 2021444,884 158,493 603,377 43,612 25,077 68,690 478,371 234,035 712,406 
Notes:
(1)    Numbers may not add due to rounding.
(2)    The Corporation’s Canadian development strategy focused on low risk, infill and development drilling, primarily in the Viewfield, Flat Lake, and Shaunavon resource plays, as well as, continued implementation of waterflood development within these assets. Following its acquisition, the Kaybob Duvernay, is a focus area for development.
(3)    The Corporation’s United States development strategy focused on development drilling in the North Dakota Bakken resource play.
(4)    Negative revisions in the United States relate to performance-based revisions and a change in the related development plan to maximize asset value, which now focuses on the Middle Bakken zone, where previously the Three Forks zone had also been targeted. Future locations targeting the Three Forks have been removed from near term development plans, and thus reserves. Negative revisions in Canada were due in part to performance-based negative revisions on existing Tight Oil assets primarily in the Viewfield Bakken, Shaunavon and Flat Lake resource plays, representing a majority of the revisions in this category, and also due in part to a changing development plan. As the Corporation’s portfolio of opportunities has significantly changed with the acquisition of the Kaybob Duvernay asset, some of the previously booked locations have been removed from the near term development plans. The Corporation also realized positive, performance related revisions in secondary production relating to its Flat Lake Oungre, and Viewfield Bakken waterflood projects.
(5)    The Corporation completed a major acquisition in the Kaybob Duvernay, which will be a significant focus area moving forward.
(6)    The Corporation completed dispositions of non-core Southeast Saskatchewan conventional assets, as well as non-operated portions of its East Shale Basin Duvernay asset.
(7)     Increases in reserves are due to increases in forecast commodity prices, determined by prior year end reserves calculated on current year end price forecasts.
(8)    The Corporation produced an average of 112,632 boe per day in Canada, 20,051 boe per day in the United States for a total of 132,683 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 mostly relate to planned infill drilling, lease-line and proximal offset locations to current producing entities.
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 a physical ability, to completely execute on the entire portfolio of booked opportunities within two years, however, approximately 44% of the development spending occurs within this time frame.
The development of these reserves have been based on current and planned 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 time frame, which represents approximately 66% of the net undeveloped location count, as well as 69% of the net total future development capital. These development activities are directed mostly to the Corporation's core focus areas of Kaybob Duvernay, Viewfield Bakken, Flat Lake Torquay and Shaunavon resource plays in Canada and the North Dakota Bakken play in the U.S. The current market environment has resulted in long term sustainability. When combined with an extensive location inventory, this results in an extended time period for full development.


    - 27 -    
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
20193,829 28,122 — 1,645 16,482 95,922 2,144 19,659 10,262 66,614 169 10,750 24,194 158,242 
2020120 22,242 — 1,420 1,377 79,190 98 19,422 170 70,873 148 10,224 1,647 135,790 
20214,784 14,353 404 1,677 8,960 61,755 44,358 57,577 137,175 183,576 987 3,468 81,533 166,536 
Note:
(1)    "First attributed" refers to reserves first attributed at year-end to corresponding fiscal year.

Probable Undeveloped Reserves
Probable Undeveloped reserves are generally those reserves tested or indicated by analogy to be productive, and lands contiguous to production. These reserves represent quantities that are less certain to be recovered than Proved reserves.
In the reserve evaluation, development of these reserves is balanced across a five to seven year time-frame to closely match the aggregate internal development schedule and represent a practicable development program. The majority of these reserves are planned to be on stream within a three year time frame, representing approximately 48% of the net undeveloped location count, as well as 52% of the total net future development costs. The current market environment has resulted in long term sustainability. When combined with extensive location inventory, this results in an extended full development time period.
This broader distribution of development activities continues to focus on the Corporation's core areas, while reclassifying current Probable locations to Proved locations during the early years of development. These development activities are directed mostly to the Corporation's core focus areas of Kaybob Duvernay, Viewfield Bakken, Flat Lake Torquay and Shaunavon resource plays in Canada and the North Dakota Bakken play in the U.S.
The following table provides the timing of the initial reserve assignments for the Corporation's Probable Undeveloped reserves.
Timing of Initial Probable Undeveloped Reserves 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
20191,990 33,955 — 1,161 12,405 91,941 1,522 19,066 8,090 58,496 319 18,126 17,318 158,893 
2020217 31,681 — 1,065 3,753 82,972 437 19,951 1,725 68,679 313 16,844 4,746 149,923 
20211,190 24,862 693 1,447 1,466 66,758 9,084 27,067 26,750 80,377 640 14,767 16,998 135,991 
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 McDaniel, an independent engineering firm. Different reserve engineers may make different estimates of reserve quantities based on the same data.


    - 28 -    
As circumstances change and additional data becomes 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 and judgments, new geological or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from numerous factors including, but not limited to, additional development activity, evolving production history, continual reassessment of the viability of production under varying economic conditions, changes in forecast prices, and reservoir performance. Such revisions can be substantial and 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).
Company Annual Capital Expenditures (MM$)
Canada (2)
United States (3)
Total (1)
YearTotal ProvedTotal Proved
Plus Probable
Total ProvedTotal Proved Plus ProbableTotal
Proved
Total Proved Plus Probable
2022608 612 130 130 738 742 
2023551 607 51 128 602 736 
2024606 742 121 141 727 883 
2025550 727 81 137 631 864 
2026284 505 138 290 643 
2027399 — 24 424 
2028265 — — 265 
2029— — 
2030— — 
2031— — 
2032— — 
2033— — 
Subtotal(1)
2,624 3,870 390 699 3,014 4,568 
Remainder— — 
Total(1)
2,627 3,878 390 699 3,017 4,577 
10% Discounted2,134 2,941 331 558 2,465 3,499 
Notes:
(1)    Numbers may not add due to rounding.
(2)    In Canada, the Corporation drilled 194 (184.7 net) wells in 2021. For 2022, the Corporation has budgeted the drilling of 238 (233.7 net) wells. Due to the nature of the resource style plays that Crescent Point is focused on, with large contiguous blocks of land, a large number of Proved as well as Proved plus Probable locations have been booked. The scheduling of locations by the qualified reserve evaluators have a similar drilling timing as the Corporation’s long-term development plan, with development drilling scheduled to occur within a five year period for Proved reserves, extending up to seven year for Probable reserves.
(3)     In the United States, Crescent Point drilled 17 (14.7 net) wells in 2021. For 2022, the Corporation has budgeted the drilling of 19 (16.9 net) wells. As in Canada, a large number of Proved as well as Proved plus Probable locations have been booked. The scheduling of locations by the qualified reserve evaluators have a similar drilling timing as the Corporation’s long-term development plan, with development drilling scheduled to occur within a five year period for Proved reserves, extending up to seven years for Probable reserves.

We estimate that our internally generated cash flow will be sufficient to fund the future development costs ("FDC") disclosed above. In addition, we have access to debt financing through our bank credit facilities and through debt capital markets, if available on terms acceptable to us.


    - 29 -    
Major Oil and Gas Properties
The following is a description of the major oil and natural gas producing properties in which Crescent Point has an interest and that are material to the Corporation’s operations and activities. All of the Corporation’s assets are located onshore within North America. The Corporation holds no interests in any plants, facilities or installations that are significant beyond normal oil and gas operating practices. Unless otherwise noted, reserve amounts are Company Gross, based on escalating cost and price assumptions as evaluated in the Crescent Point Reserve Report as at December 31, 2021.
Kaybob Area
In 2021, the Corporation acquired a significant new core asset in Kaybob Duvernay in northern Alberta from Shell Canada Energy.
Production in Kaybob is a combination of natural gas liquids and natural gas, weighted approximately 65% to natural gas liquids. The play is being developed using multi-staged fractured horizontal wells. Working interest production averaged approximately 30,000 boe per day, after closing the acquisition on April 1, 2021.
In Kaybob, the Corporation spent $124.5 million, representing 20% of its 2021 capital program, drilling one pad of horizontal wells. In addition, the Corporation also completed two pads as part of a joint operating and farm-out agreement with another company in the play.
At year-end 2021, the Corporation's Total Proved plus Probable reserves in Kaybob were 154.3 MMboe, with 91 (90.3 net) drilling locations booked, representing approximately 22% of the Corporation’s total Proved plus Probable reserves. It is expected the Total Proved as well as the Total Proved plus Probable locations will be developed within four years.
As of December 31, 2021, Crescent Point has allocated approximately 26% of the Corporation's 2022 capital budget to developing the Duvernay resource play in Kaybob.
Viewfield Area
Crescent Point is the largest Canadian producer in the Viewfield area of southeastern Saskatchewan, which has development in the Bakken resource play, as well as conventional plays including the Frobisher and Midale. In 2021, Crescent Point's production averaged approximately 37,000 boe per day in the area. The majority of production is from the Bakken resource which is a high quality light oil and is exploited using multi-fractured horizontal wells. The core area of the Bakken resource has mostly been unitized, in order to expand various waterflood projects. The Bakken play in this area has continued to be a major driver in the Corporation’s portfolio, maturing from early development and delineation drilling activities to the current focus on enhanced oil recovery through infill drilling and waterflood.
Crescent Point spent $128.9 million, representing approximately 20% of its 2021 capital development program, in the Viewfield area including drilling 63 (60.1 net) additional oil wells. The Corporation also continued to focus on waterflood development expansion.
At year-end 2021, the Corporation's total Proved plus Probable reserves in the Viewfield area were 192.2 MMboe, with 659 (607 net) locations booked to these reserves. This represents approximately 27% of the Corporation’s total Proved plus Probable reserves. Crescent Point expects to fully develop this location inventory within five years for Proved reserves, extending to six years for Probable reserves.
As of December 31, 2021, Crescent Point has allocated approximately 18% of the Corporation's 2022 capital budget to development of the Viewfield area, primarily focused on infill drilling, as well as additional waterflood development.
Shaunavon Area

The Shaunavon resource area, located in southwest Saskatchewan, has development occurring in the Upper and Lower Shaunavon resource zones, as well as conventional Upper Shaunavon pools, all of which are medium quality oil. The Upper and Lower Shaunavon resource play and other conventional zones exist both individually and together as


    - 30 -    
stratified pools. The tight oil Upper and Lower resource plays have been developed using fracture stimulated horizontal wells and, more recently, by advancing waterflood techniques that have continued to grow waterflood production in the area. In 2021, Crescent Point's production averaged approximately 20,000 boe per day in the area.
In 2021, the Corporation continued to develop the Shaunavon area by drilling 50 (46.5 net) wells, and expanding waterflood to enhance recoveries. Total capital spent on these activities in 2021 was $112.6 million, representing approximately 18% of the Corporation's capital budget.
As of year-end 2021, Crescent Point has booked total Proved plus Probable reserves of 111.0 MMboe in the Shaunavon area, representing approximately 16% of the total Proved plus Probable reserves. The Corporation has 549 (533.6 net) locations booked to total Proved plus Probable reserves as of year-end 2021. Crescent Point expects to fully develop this location inventory within five years for Proved reserves, extending to seven years for Probable reserves.
As of December 31, 2021, Crescent Point has allocated approximately 19% of the Corporation's 2022 capital budget to development of the Shaunavon area. The Corporation plans to continue to advance waterflood optimization in the Lower and Upper Shaunavon zones, as well as advance enhanced oil recovery projects in the conventional areas.
North Dakota Area
The Corporation is developing the Middle Bakken resource play in North Dakota. Production is a high quality light oil and is developed using multi-staged fractured horizontal wells, with 2021 average working interest production of approximately 20,000 boe per day.
In North Dakota, the Corporation spent $109.1 million representing 17% of its 2021 capital program, drilling 17 (14.7 net) horizontal wells focusing on pad drilling these assets.
At year-end 2021, the Corporation's Total Proved plus Probable reserves in North Dakota were 90.9 MMboe, with 149 (104.6 net) locations booked, representing approximately 13% of the Corporation’s total Proved plus Probable reserves. It is expected the Total Proved as well as the Total Proved plus Probable locations will be developed within five years for Proved reserves, extending to six years for Probable reserves.
As of December 31, 2021, Crescent Point has allocated approximately 17% of the Corporation's 2022 capital budget to developing the Middle Bakken resource play in North Dakota.
Oil and Gas Wells
Producing Wells
AreaOilGas
GrossNetGrossNet
CANADA
Saskatchewan6,679 5,937 252 30 
Alberta377 329 133 110 
British Columbia— — 
TOTAL CANADA7,065 6,272 385 140 
U.S.
North Dakota207 164 — — 
TOTAL U.S.207 164 — — 
Total7,272 6,436 385 140 



    - 31 -    
Non-Producing Wells
Area
Oil
Gas
Gross
Net
Gross
Net
CANADA
Saskatchewan
2,790 2,285 508 375 
Alberta
395 298 287 237 
British Columbia
— — 
TOTAL CANADA
3,185 2,583 796 613 
U.S.
North Dakota
14 11 — — 
TOTAL U.S.
14 11 — — 
Total
3,199 2,594 796 613 
Note:
(1)    Gross and net producing and non-producing oil and gas counts include both reserve assigned and non-reserve assigned wells.


All of the Corporation's oil and gas wells are onshore. Non-producing wells are generally situated within defined developed areas and include recent drills awaiting final preparation prior to being placed on production; existing wells that may be waiting on improved economic conditions to restart; wells currently in use for observation or monitoring; wells awaiting recompletion in secondary zones or as injectors; or wells scheduled for abandonment. These non-producing entities include wells with reserve assignments as well as currently non-booked wells, which will have various terms of being non-producing from recent to longer-term.
Developed non-producing reserves represent only 1% of the Total Proved reserve category, and 1% of the Total Proved plus Probable reserve category. Wells in the developed non-producing category exist across most of the Corporation’s areas and mostly represent wells awaiting final preparation for production, plus those awaiting well reactivation.
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, 2021
Gross AcresNet AcresNet Acres Expiring
Within One Year
CANADA
Alberta543,887 511,655 202,494 
Saskatchewan613,484 572,154 67,606 
Manitoba2,475 2,475 — 
British Columbia30,610 18,429 — 
   Total1,190,456 1,104,713 270,100 
U.S.
North Dakota8,377 6,509 16 
   Total8,377 6,509 16 
Total1,198,833 1,111,222 270,116 

The Corporation has no material drilling commitments relating to unproved properties.


    - 32 -    
Drilling Activity
The following table summarizes the gross and net exploration and development wells in which we participated during the year ended December 31, 2021, in each of Canada and the United States.
Development Wells
Exploration Wells (2)
Total Wells
GrossNetGrossNetGrossNet
CANADA
Oil wells187178187178
Natural Gas wells6666
Service wells1111
Stratigraphic test
Dry Holes
Total (1)
194185194185

Development Wells
Exploration Wells (2)
Total Wells
GrossNetGrossNetGrossNet
U.S.
Oil wells17151715
Natural Gas wells
Service wells
Stratigraphic Test
Dry Holes
Total (1)
171517