EX-99.1 2 cpgye2019aif.htm EXHIBIT 99.1 Exhibit
 

Exhibit 99.1



cplogo2018a01.jpg

CRESCENT POINT ENERGY CORP.
ANNUAL INFORMATION FORM
For the Year Ended December 31, 2019
Dated March 4, 2020



 

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




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SPECIAL NOTES TO READER
Any "financial outlook" or "future oriented financial information" in this annual information form, as defined by applicable securities legislation has been approved by management of Crescent Point (as defined herein). Such financial outlook or future oriented financial information is provided for the purpose of providing information about management’s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.
This annual information form and other reports and filings made with the securities regulatory authorities include certain statements that constitute "forward-looking statements" within the meaning of section 27A of the Securities Act of 1933, section 21E of the Securities Exchange Act of 1934 and the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" for the purposes of Canadian securities regulation (collectively, "forward-looking statements"). All forward-looking statements are based on our beliefs and assumptions based on information available at the time the assumption was made. Crescent Point has tried to identify such forward-looking statements by use of such words as "could", "should", "can", "anticipate", "expect", "believe", "will", "may", "intend", "projected", "sustain", "continues", "strategy", "potential", "projects", "grow", "take advantage", "estimate", "well-positioned" and similar expressions, but these words are not the exclusive means of identifying such statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Crescent Point believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. These statements speak only as of the date of this AIF or, if applicable, as of the date specified in this AIF.
In particular, this AIF contains forward-looking statements pertaining, among other things, to the following:
corporate strategy and anticipated financial and operational performance;
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;
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 waterflood programs;
treatment of DRIP and SDP participants if either plan is reinstated;
the impacts of the Orphan Well Association v Grant Thornton Ltd. court decision;
expected decommissioning, abandonment, remediation and reclamation costs;
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;



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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 regulatory changes and implementations and change in 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; 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, 2019, 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, 2019, under the headings "Capital Expenditures", "Liquidity and Capital Resources", "Critical Accounting Estimates", "Risk Factors", "Changes in Accounting Policies" and "Outlook".
This information contains certain forward-looking estimates that involve substantial known and unknown risks and uncertainties, certain of which are beyond Crescent Point's control. Such risks and uncertainties include, but are not limited to: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas; delays in business operations, pipeline restrictions and blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions, including changes in laws and regulations, the adoption of new environmental laws and regulations, and changes in how environmental laws and regulations are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; risks and uncertainties related to oil and gas interests and operations on tribal lands; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs 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; 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.
There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only. In general, estimates of economically recoverable crude oil, natural gas and natural gas liquids reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For these reasons, estimates of the economically recoverable crude oil, natural gas liquids and natural gas reserves attributable to any particular



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group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. Crescent Point's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. In addition, the discounted and undiscounted net present value of future net revenues attributable to reserves do not represent fair market value; and the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. 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.
Operating netback is calculated on a per boe basis as oil and gas sales, less royalties, operating and transportation expenses. Netback is calculated on a per boe basis as operating netback plus realized derivative gains and losses. Operating netback and netback are common metrics used in the oil and gas industry and are used by management to measure operating results on a per boe basis to better analyze performance against prior periods on a comparable basis. The calculation of netback is shown in the Production History section of this AIF.
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for the year.
Additional information on these and other factors that could affect Crescent Point's operations or financial results are included in Crescent Point's reports on file with Canadian and U.S. securities regulatory authorities (including our Annual Report on Form 40-F and Management's Discussion and Analysis). Readers are cautioned not to place undue reliance on the forward-looking information, which is given as of the date it is expressed in this AIF or otherwise. We do not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required pursuant to applicable securities laws. All subsequent forward-looking statements, whether written or oral, attributable to Crescent Point or persons acting on the Corporation’s behalf are expressly qualified in their entirety by these cautionary statements.
Presentation of our Reserve and Resource Information
Current SEC reporting requirements permit oil and gas companies to disclose Probable reserves (as defined herein), in addition to the required disclosure of Proved reserves. Under current SEC requirements, net quantities of reserves are required to be disclosed, which requires disclosure on an after royalties basis and does not include reserves relating to the interests of others. For a description of these and additional differences between Canadian and U.S. standards of reporting reserves, see "Risk Factors — Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States".
New York Stock Exchange
As a Canadian corporation listed on the NYSE, we are not required to comply with most of the NYSE's corporate governance standards and, instead, may comply with Canadian corporate governance practices. We are, however, required to disclose the significant differences between our corporate governance practices and the requirements applicable to U.S. domestic companies listed on the NYSE. Except as summarized on our website at www.crescentpointenergy.com, we are in compliance with the NYSE corporate governance standards in all significant respects.



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GLOSSARY
In this AIF, the capitalized terms set forth below have the following meanings:
"ABCA" means the Business Corporations Act, R.S.A. 2000, c. B-9, as amended, including the regulations promulgated thereunder.
"AEP" means Alberta Environment and Parks.
"AER" means the Alberta Energy Regulator.
"AIF" means this annual information form of the Corporation dated March 4, 2020 for the year ended December 31, 2019.
"Board" or "Board of Directors" means the board of directors of the Corporation.
"Common Shares" means common shares in the capital of the Corporation.
"Conversion Arrangement" means the plan of arrangement under Section 193 of the ABCA, completed on July 2, 2009 pursuant to which the Trust effectively converted from an income trust to a corporate structure.
"CPEUS" means Crescent Point Energy U.S. Corp.
"CPHI" means Crescent Point Holdings Inc.
"CPLux" means Crescent Point Energy Lux S.à r.l.
"CPUSH" means Crescent Point U.S. Holdings Corp.
"Crescent Point" or the "Corporation" means Crescent Point Energy Corp., formerly Wild River Resources Ltd., a corporation amalgamated under the ABCA and, where applicable, includes its subsidiaries and affiliates.
"DRIP" means the Premium DividendTM and Dividend Reinvestment Plan of the Corporation.
"DSU Plan" means the Deferred Share Unit Plan of the Corporation.
"FAST Act" means the Fixing America’s Surface Transportation Act.
"GLJ" means GLJ Petroleum Consultants Ltd.
"Greenhouse Gases" or "GHGs" means any or all of, including but not limited to, carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulphur hexafluoride (SF6).
"IFRS" means International Financial Reporting Standards as adopted by the Canadian Accounting Standards Board for periods beginning on and after January 1, 2011.
"MD&A" means the management's discussion and analysis of financial condition and results of operations of the Corporation for the year ended December 31, 2019.
"NCIB" means normal course issuer bid.
"NI 51-101" means "National Instrument 51-101 – Standards for Disclosure for Oil and Gas Activities".
"NYSE" means the New York Stock Exchange.



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"OPEC" means the Organization of the Petroleum Exporting Countries.
"Partnership" means Crescent Point Resources Partnership, a general partnership formed under the laws of the Province of Alberta, having CPHI and the Corporation as partners.
"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.
"Sproule" means Sproule Associates Limited.
"Stock Option Plan" means the Stock Option Plan of the Corporation.
"Tax Act" means the Income Tax Act (Canada), R.S.C. 1985, c. 1 (5th Supp.), and the regulations promulgated thereunder, each as amended from time to time.
"Trust" means Crescent Point Energy Trust, an unincorporated open ended investment trust governed by the laws of the Province of Alberta that was dissolved pursuant to the Conversion Arrangement.
"Trust Units" means the trust units of the Trust.
"TSX" means the Toronto Stock Exchange.
"Unitholders" means holders of Trust Units.
"U.S." means the United States of America.
For additional definitions used in this AIF, please see "Statement of Reserves Data and Other Oil and Gas Information - Notes and Definitions".
In this AIF, references to "dollars" and "$" are to the currency of Canada, unless otherwise indicated.



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SELECTED ABBREVIATIONS
In this AIF, the abbreviations set forth below have the following meanings:
Oil and Natural Gas Liquids
Natural Gas
bbl
barrel
Mcf
thousand cubic feet
bbls
barrels
Mcf/d
thousand cubic feet per day
bbls/d
barrels per day
Mcfe
thousand cubic feet of gas equivalent converting one barrel of oil to 6 Mcf of natural gas equivalent
Mbbls
thousand barrels
NGLs
natural gas liquids
 
 
MMcf
million cubic feet
 
 
MMcf/d
million cubic feet per day
 
 
MMBTU
million British Thermal Units
 
 
GJ
gigajoule

Other
 
AECO
the natural gas storage facility located at Suffield, Alberta
boe or BOE
barrels 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/d
barrel of oil equivalent per day
cubic metres
M$
thousand dollars
Mboe
thousand barrels of oil equivalent
MMboe
million barrels of oil equivalent
MM$
million dollars
MW
megawatt
MW/h
megawatt per hour
tCO2e
tonnes of carbon dioxide equivalent
WTI
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade




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CURRENCY OF INFORMATION
The information set out in this AIF is stated as at December 31, 2019, unless otherwise indicated. Capitalized terms used but not defined in the text are defined in the Glossary.
OUR ORGANIZATIONAL STRUCTURE
The Corporation
Crescent Point Energy Corp. ("Crescent Point" or the "Corporation" and, together with its direct and indirect subsidiaries and partnerships, where appropriate, "we", "our" or "us") is the successor to the Trust, following the completion of the "conversion" of the Trust from an income trust to a corporate structure under the Conversion Arrangement. Pursuant to the Conversion Arrangement, Unitholders of the Trust exchanged their Trust Units for Common Shares of the Corporation on a one-for-one basis.
The Corporation was originally incorporated pursuant to the provisions of the Company Act (British Columbia) on April 20, 1994 as 471253 British Columbia Ltd. 471253 British Columbia Ltd. changed its name to Westport Research Inc. ("Westport") on August 12, 1994. On August 1, 2006, Westport was continued into Alberta under the ABCA. On October 11, 2006, Westport changed its name to 1259126 Alberta Ltd. ("1259126"). On February 8, 2007, 1259126 amended its articles to change its name to Wild River Resources Ltd. ("Wild River"), to add a class of non-voting common shares, to change the number of authorized Common Shares from 1,000,000 to unlimited and to change the rights, privileges, restrictions and conditions attaching to such shares, to reorganize its share structure, to change the number of Wild River's issued and outstanding shares on a pro rata basis to an aggregate of 5,000,000 Common Shares, to remove the restrictions on share transfer and to amend the "other provisions" section of the articles. On June 29, 2009, Wild River amended its articles to cancel the non-voting common shares and to change the rights, privileges, restrictions and conditions of the Common Shares to remove the references to the non-voting common shares. On July 2, 2009, in connection with the Conversion Arrangement, Wild River filed Articles of Amendment to give effect to the consolidation of the Common Shares on the basis of 0.1512 of a post-consolidation Common Share for each pre-consolidation Common Share and subsequent Articles of Amendment to change its name to Crescent Point Energy Corp. On January 1, 2011, the Corporation amalgamated with Ryland Oil ULC, Darian Resources Ltd. and Shelter Bay Energy ULC.
The head and principal office of the Corporation is located at Suite 2000, 585 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1 and its registered office is located at Suite 3700, 400 – 3rd Avenue S.W., Calgary, Alberta, T2P 4H2.
The Corporation is a conventional oil and gas producer with assets strategically focused in properties comprised of high quality, long life, operated, light and medium crude oil and natural gas reserves in Western Canada and the United States.
We make regular cash dividends to Shareholders from our net cash flow. Our primary source of cash flow is distributions from the Partnership.
Partnership
The Partnership is a general partnership governed by the laws of the Province of Alberta. As set forth in the diagram below under "Organizational Structure of the Corporation", the partners of the Partnership are CPHI and the Corporation.
The existing business of the Corporation is carried on through the Partnership and through CPEUS. The Partnership holds all of the Corporation's Canadian operating assets and CPEUS holds all of the Corporation’s U.S. operating assets.
CPHI
CPHI is a wholly-owned subsidiary of the Corporation. CPHI is a partner of the Partnership.



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CPLux
CPLux is a wholly-owned indirect subsidiary of the Corporation.
CPUSH
Crescent Point U.S. Holdings Corp. is a wholly-owned direct subsidiary of the Corporation.
CPEUS
Crescent Point Energy U.S. Corp. is a wholly-owned indirect subsidiary of the Corporation. CPEUS holds the Corporation's operating assets in the United States.
Relationships
The following table provides the name, the percentage of voting securities owned by the Corporation and the jurisdiction of incorporation, continuance or formation of the Corporation's material subsidiaries as at the date hereof.
 
Percentage of Voting Securities (Directly or Indirectly)
Jurisdiction of Incorporation/Formation
CPHI
100%
Alberta
Partnership
100%
Alberta
CPUSH
100%
Nevada
CPEUS
100%
Delaware
CPLux
100%
Luxembourg




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Organizational Structure of the Corporation
The following diagram describes the inter-corporate relationships among the Corporation and its material direct and indirect subsidiaries described above as at March 4, 2020. Reference should be made to the appropriate sections of this AIF for a complete description of the structure of the Corporation.
organizationstructurea10.jpg

 
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.
2017
In the first quarter of 2017, Crescent Point completed the acquisition of approximately 8,500 net acres in North Dakota for total cash consideration of US$100.0 million. The acquired lands were contiguous to the Corporation's current acreage.
Crescent Point also acquired approximately 80,000 net acres of undeveloped land in the Uinta Basin in the second quarter of 2017, for total cash consideration of US$72.5 million.
In the second quarter of 2017, the Corporation sold 1,100 boe/d of non-operated conventional assets in Manitoba for total cash consideration of $93.2 million.
On May 24, 2017, Ted Goldthorpe was elected as a director of the Corporation. See "Additional Information Respecting Crescent Point - Directors and Officers".
On June 26, 2017, Crescent Point renewed its unsecured, covenant-based credit facilities totaling $3.6 billion. The renewal extended the maturity date of the credit facilities to June 10, 2020. See "Additional Information Respecting Crescent Point - Long-Term Debt".
During the third quarter of 2017, the Corporation completed or entered into agreements to dispose of non-core assets representing approximately 3,000 boe/d for total value of over $190 million.



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In the fourth quarter of 2017, Crescent Point entered into agreements to dispose of non-core assets for total value of approximately $40 million.
2018
In the second quarter of 2018, Crescent Point completed the disposition of non-core assets mostly in southeast Saskatchewan, for proceeds of approximately $280 million. The assets sold represented operated and non-operated production of approximately 4,800 boe/d.
Early in the second quarter of 2018, the Corporation completed a private placement of senior unsecured, guaranteed notes for total gross proceeds of US$143.5 million and CDN$80.0 million. Three separate series of notes were issued as part of the private placement, with maturities ranging from five to seven years and interest rates ranging from 3.58% to 3.98%. Proceeds from the issuance of the notes were used to repay a portion of the Corporation’s outstanding bank debt and other senior guaranteed notes with near-term maturities.
On May 4, 2018, François Langlois was elected as a new director of the Corporation. See "Additional Information Respecting Crescent Point - Directors and Officers".
On May 29, 2018, Scott Saxberg stepped down as President and Chief Executive Officer of Crescent Point, and Craig Bryksa was appointed interim President and Chief Executive Officer and to the Board. Mr. Bryksa was subsequently appointed as Crescent Point’s President and Chief Executive Officer on September 5, 2018.
On June 19, 2018, Neil Smith, Chief Operating Officer, stepped down as an officer of the Corporation, and Ryan Gritzfeldt was promoted from Vice President, Marketing and Innovation to the position of Chief Operating Officer.
On June 22, 2018, Crescent Point renewed its unsecured credit facilities totaling $3.6 billion with a new maturity date of June 10, 2021.
On September 5, 2018, Robert Heinemann was appointed as the new Chairman of the Board of Directors, replacing Peter Bannister, who has announced his intention to retire from the Board at the Corporation’s 2019 annual meeting of shareholders.
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. 26,238,600 Common Shares were purchased under the NCIB.
On February 19, 2019, Crescent Point announced the appointment of John P. Dielwart to the Board, effective March 7, 2019. See "Additional Information Respecting Crescent Point - Directors and Officers".
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 as the new Chair of the Board, replacing Robert Heinemann, who retired from the Board.



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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.
DESCRIPTION OF OUR BUSINESS
General
The Corporation is an oil and gas exploration, development and production company. The Corporation is a conventional oil and gas producer with assets strategically focused in properties comprised of high quality, long life, operated, light and medium crude oil and natural gas reserves in Western Canada and the United States. The primary assets of the Corporation are currently its interest in the Partnership, shares in CPHI, shares in CPUSH and, indirectly, shares in CPEUS.
The crude oil and natural gas properties and related assets generating income for the benefit of the Corporation are located in the provinces of Saskatchewan, Alberta, British Columbia and Manitoba and in the states of North Dakota and Montana. The properties and assets consist of producing crude oil and natural gas reserves and Proved plus Probable (as defined herein) crude oil and natural gas reserves not yet on production, and land holdings.
We pay regular cash dividends to Shareholders from our net cash flow in accordance with our dividend policy. Our primary sources of cash flow are distributions from the Partnership. During the year ended December 31, 2019, we paid quarterly dividends of $0.01 per Common Share. See "Dividends".
Strategy
We strive to enhance shareholder returns by cost effectively developing a focused asset base in a responsible and sustainable manner. Through the development of our assets, we aim to create sustainable, profitable and returns-based growth in reserves, production and cash flow.
We strategically develop our properties through detailed technical analysis including reservoir characteristics, petroleum initially in place, recovery factors and the applicability of enhanced recovery techniques. Our development strategies include, infill and step-out wells, multi-stage fracture stimulation of horizontal wells, re-completion of existing wells and secondary recovery techniques such as waterflood programs.
Risk Management and Marketing
Factors outside our control impact, to varying degrees, the prices we receive for production. These include, but are not limited to:
(a)
world market forces, including world supply and consumption levels and the ability of OPEC and others to set and maintain production levels and prices for crude oil;
(b)
political conditions, including the risk of hostilities in the Middle East, South America 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;



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(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 fuels;
(i)
the effect of energy conservation measures and government regulations; and
(j)
U.S. and Canada tax policy.
Fluctuations in commodity prices, differentials and foreign exchange and interest rates, among other factors, are outside of our control and yet can have a significant impact on the level of cash we have available for payment of dividends to Shareholders.
To mitigate a portion of these risks, we actively initiate, manage and disclose the effects of our hedging activities. Our strategy for crude oil and natural gas production is to hedge up to 65%, or as otherwise approved by the Board of Directors, of our net of royalty production up to a rolling three and a half year basis, at the discretion of management. The Corporation also uses a combination of financial derivatives and fixed-differential physical contracts to hedge price differentials. For differential hedging, Crescent Point's risk management program allows for hedging a forward profile of up to three and a half years, and up to 35% net of royalty production. All hedging activities are governed by our Risk Management and Counterparty Credit Policy and are regularly reviewed by the Board of Directors.
As part of our risk management program, benchmark oil prices are hedged using financial WTI-based instruments transacted in Canadian and U.S. dollars and benchmark natural gas prices are hedged using financial AECO-based instruments transacted in Canadian dollars. Total financial oil and gas hedges in 2019 amounted to approximately 47% of annual production, net of royalties, consisting of approximately 50% of annual liquids production and approximately 22% of annual natural gas production, net of royalties. The Corporation recorded a realized derivative loss on crude oil and natural gas hedge contracts of $43.4 million in 2019.
Crescent Point also enters into physical delivery and derivative WTI price differential contracts which manage the spread between US$ 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 2019, approximately 18,300 bbls/d of liquids production was contracted with fixed price differentials off WTI.
Refer to the annual financial statements for our commitments under all hedging agreements as at December 31, 2019.
In addition to hedging benchmark crude oil and natural gas prices with financial instruments, we also mitigate crude oil basis risk by delivering a portion of our crude oil production into diversified refinery markets using rail transportation. Crescent Point operates two railcar loading facilities, serving its key producing areas of southeast Saskatchewan and southwest Saskatchewan. Crude oil volumes loaded at these facilities are sold at the loading facilities and our buyers are responsible for providing railcars and managing transportation logistics from that point until delivery at the refinery gate. By utilizing rail transportation, we have been able to access refining markets over the past several years that are not pipeline connected to western Canada, 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 107 purchasers and its financial hedging portfolio consists of 15 counterparties. The Corporation's portfolio of counterparty exposures is monitored on a monthly basis.



- 13 -    

To further mitigate credit risk associated with its physical sales portfolio, Crescent Point obtains financial assurances such as parental guarantees, letters of credit and third party credit insurance. Including these assurances, approximately 95% of the Corporation’s oil and gas sales are with entities considered investment grade.
Revenue Sources
Our crude oil and natural gas volumes are sold in the United States, Saskatchewan, Alberta, Manitoba and British Columbia. Approximately 72% of our liquids volumes are sold in Saskatchewan, 22% in the U.S., 6% in Alberta, and less than 1% in Manitoba and British Columbia. Approximately 62% of our natural gas volumes are sold in Saskatchewan, 25% in the United States, 12% in Alberta and less than 1% in Manitoba and British Columbia.
For 2019, our commodity production mix was approximately 91% crude oil and NGLs and 9% natural gas.
The following table summarizes our revenue sources by product before hedging and royalties:
For Year Ended
Crude Oil and NGLs
Natural Gas
2019
97%
3%
2018
98%
2%
2017
97%
3%

Competition
We actively compete for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial resources than we do. Our competitors include major integrated oil and natural gas companies, numerous other independent oil and natural gas entities and individual producers and operators. Similarly, we face a competitive market when we attempt to divest of non-core assets.
Certain of our customers and potential customers are themselves exploring for crude oil and natural gas, and the results of such exploration efforts could affect our ability to sell or supply crude oil or natural gas to these customers in the future. Our ability to successfully bid on and acquire additional property rights, divest property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers is dependent upon developing and maintaining close working relationships with our industry partners and joint operators, our ability to select and evaluate suitable properties, and our ability to consummate transactions in a highly competitive environment.
Seasonal Factors
The production of crude oil and natural gas is dependent on access to areas where development of reserves is to be conducted. Seasonal weather variations, including freeze-up and break-up, affect access in certain circumstances.
Personnel
As of December 31, 2019, the Corporation had 864 permanent employees: 393 employees at the head office in Calgary, 50 employees at the Denver office, 407 field employees in Canada and 14 field employees in the U.S.
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
Disclosure of Reserves Data
In accordance with NI 51-101, the reserves data of the Corporation set forth below (the "Reserves Data") is based upon evaluations conducted by GLJ and Sproule with an effective date of December 31, 2019, and contained in the consolidated report of GLJ dated February 14, 2020 (the "Crescent Point Reserve Report"). The tables below are a combined summary



- 14 -    

of our crude oil, NGL and natural gas reserves and the net present value of future net revenue attributable to such reserves as evaluated in the Crescent Point Reserve Report based on Sproule’s December 31, 2019 forecast price and cost assumptions. GLJ evaluated approximately 40% of the assigned total Proved plus Probable reserves and 29% of the total Proved plus Probable value discounted at 10%. Sproule evaluated approximately 60% of the assigned total Proved plus Probable reserves and 71% of the total Proved plus Probable value discounted at 10%. Sproule evaluated a majority of the southeast Saskatchewan assets including the Viewfield Bakken and Flat Lake Torquay properties, as well as southwest Saskatchewan assets including the Shaunavon and Saskatchewan Viking properties. Sproule evaluated their portion of the reserves using the Sproule forecast price and cost escalation assumptions. GLJ evaluated the Corporation’s Alberta and British Columbia assets, as well as a portion of the assets in southeast Saskatchewan. GLJ also performed the evaluation of the Corporation's U.S. assets in North Dakota and Montana. These assets were all evaluated using the Sproule forecast price and cost escalation assumptions. GLJ prepared the total Crescent Point Reserve Report by consolidating the GLJ Canadian and U.S. evaluated properties with the Sproule evaluation using the Sproule pricing and cost escalation assumptions. The tables below summarize the data contained in the Crescent Point Reserve Report and, as a result, may contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly.
The net present value of future net revenue attributable to our reserves is stated without provision for interest costs, and general and administrative costs, but after providing for estimated royalties, production costs, capital taxes, development costs, other income, future capital expenditures, projected carbon emission costs, and well and location abandonment costs for those entities assigned reserves by GLJ and Sproule. 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 GLJ and Sproule represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of our crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.
The Corporation continuously monitors and reviews legislation concerning greenhouse gas emissions and the impact on operations. New legislation that was 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 anticipated negative financial impact of carbon emission costs to Total Proved plus Probable reserves evaluation as of December 31, 2019 as a result of the implementation of these new programs is $9.5 MM discounted at 10% before tax, with no impact on reserve level bookings.
The Crescent Point Reserve Report is based on certain factual data supplied by Crescent Point as well as GLJ and Sproule's opinion of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to Crescent Point's petroleum properties and contracts (except for certain information residing in the public domain) were supplied by the Corporation to GLJ and Sproule, and were accepted without any further investigation. GLJ and Sproule accepted this data as presented and neither title searches nor field inspections were conducted.



- 15 -    

Reserves Data – Forecast Prices and Costs
Summary of Oil and Gas Reserves(1) 
 
Light and Medium Crude Oil
Heavy Crude Oil

Tight Oil
Natural Gas Liquids

Shale Gas
Conventional
Natural Gas
Total
Reserves Category
Company Gross
(Mbbls)
Company
Net
(Mbbls)
Company
Gross
(Mbbls)
Company
Net
(Mbbls)
Company
Gross
(Mbbls)
Company
Net
(Mbbls)
Company
Gross
(Mbbls)
Company
Net
(Mbbls)
Company Gross
(MMcf)
Company
Net
(MMcf)
Company Gross
(MMcf)
Company
Net
(MMcf)
Company
Gross
(Mboe)
Company
Net
(Mboe)
Proved Developed Producing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
71,484

63,986

24,175

20,066

116,743

109,581

36,450

33,775

91,829

85,575

60,040

55,970

274,163

250,998

United States




21,059

17,057

6,335

5,131

19,664

15,926



30,672

24,843

Total
71,484

63,986

24,175

20,066

137,803

126,638

42,785

38,906

111,492

101,501

60,040

55,970

304,836

275,841

Proved Developed Non-Producing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
1,341

1,246

1,979

1,731

1,313

1,209

618

570

1,216

1,060

1,297

1,073

5,669

5,111

United States




6

5



3

2



6

5

Total
1,341

1,246

1,979

1,731

1,318

1,213

618

570

1,219

1,062

1,297

1,073

5,675

5,116

Proved Undeveloped
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
28,122

26,013

1,645

1,419

58,096

55,040

13,239

12,365

45,407

41,860

10,750

9,743

110,462

103,439

United States




37,825

30,638

6,421

5,201

21,206

17,177



47,780

38,702

Total
28,122

26,013

1,645

1,419

95,922

85,679

19,659

17,566

66,614

59,038

10,750

9,743

158,242

142,141

Total Proved
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
100,947

91,245

27,799

23,216

176,152

165,831

50,306

46,710

138,452

128,496

72,086

66,787

390,294

359,548

United States




58,890

47,700

12,756

10,332

40,873

33,105



78,459

63,550

Total
100,947

91,245

27,799

23,216

235,043

213,531

63,062

57,042

179,325

161,601

72,086

66,787

468,753

423,098

Total Probable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
58,348

52,860

6,894

5,508

112,932

105,681

26,302

24,511

80,222

74,407

33,640

31,003

223,452

206,129

United States




37,120

30,086

7,013

5,684

22,942

18,598



47,956

38,870

Total
58,348

52,860

6,894

5,508

150,052

135,767

33,315

30,195

103,163

93,005

33,640

31,003

271,409

244,998

Total Proved Plus Probable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
159,295

144,104

34,693

28,724

289,084

271,512

76,608

71,221

218,674

202,903

105,726

97,790

613,747

565,677

United States




96,010

77,786

19,769

16,016

63,815

51,703



126,415

102,419

Total
159,295

144,104

34,693

28,724

385,094

349,298

96,377

87,237

282,488

254,606

105,726

97,790

740,161

668,096

Note:
(1)    Numbers may not add due to rounding.




- 16 -    

Net Present Value of Future Net Revenue of Oil and Gas Reserves(1) 
 
Before Income Taxes Discounted at
(%/year)
 
After Income Taxes Discounted at
(%/year)
Reserves Category
0%
(MM$)
5%
(MM$)
8%
(MM$)
10%
(MM$)
15%
(MM$)
20%
(MM$)
 
0%
(MM$)
5%
(MM$)
8%
(MM$)
10%
(MM$)
15%
(MM$)
20%
(MM$)
Proved Developed Producing
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
8,406

6,697

5,922

5,500

4,681

4,096

 
8,093

6,526

5,801

5,402

4,624

4,060

United States
977

735

640

590

497

433

 
944

717

627

579

490

428

Total
9,383

7,432

6,563

6,090

5,179

4,529

 
9,037

7,242

6,428

5,982

5,114

4,489

Proved Developed Non-Producing
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
257

177

151

138

115

98

 
196

140

122

114

99

88

United States






 






Total
257

177

151

138

115

99

 
197

140

123

114

99

88

Proved Undeveloped
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
2,623

1,808

1,461

1,272

911

659

 
1,896

1,309

1,054

916

648

461

United States
772

368

226

156

37

(33
)
 
709

334

201

136

25

(41
)
Total
3,395

2,176

1,687

1,428

948

626

 
2,605

1,643

1,256

1,052

673

420

Total Proved
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
11,287

8,682

7,535

6,910

5,707

4,854

 
10,185

7,974

6,978

6,432

5,371

4,609

United States
1,749

1,103

866

746

534

400

 
1,653

1,051

828

716

515

388

Total
13,036

9,785

8,401

7,657

6,242

5,254

 
11,838

9,025

7,806

7,148

5,886

4,997

Total Probable
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
9,319

5,298

4,082

3,510

2,549

1,965

 
6,898

3,903

2,999

2,576

1,869

1,444

United States
1,918

999

738

621

432

324

 
1,648

891

668

566

400

302

Total
11,238

6,297

4,820

4,130

2,981

2,289

 
8,546

4,794

3,667

3,142

2,269

1,746

Total Proved Plus Probable
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
20,606

13,980

11,617

10,420

8,256

6,819

 
17,083

11,877

9,977

9,008

7,240

6,053

United States
3,667

2,102

1,604

1,367

967

724

 
3,301

1,941

1,496

1,282

915

690

Total
24,273

16,082

13,221

11,787

9,223

7,543

 
20,384

13,818

11,474

10,289

8,155

6,743

Note:
(1)    Numbers may not add due to rounding.





- 17 -    

Additional Information Concerning Future Net Revenue – (Undiscounted)(1) 
Reserves Category
Revenue
(MM$)
Royalties & Burdens(2)
(MM$)
Operating
Costs
(MM$)
Development
Costs
(MM$)
Abandonment and Reclamation
Costs(3)
(MM$)
Future Net
Revenue Before
Income Taxes
(MM$)
Income Tax
(MM$)
Future Net
Revenue After
Income Taxes
(MM$)
Proved
 
 
 
 
 
 
 
 
Canada
27,873

2,770

9,657

2,393

1,767

11,287

1,102

10,185

United States
5,938

1,559

1,546

1,048

36

1,749

96

1,653

Total
33,811

4,328

11,203

3,441

1,803

13,036

1,197

11,838

Proved Plus Probable
 
 
 
 
 
 
 
 
Canada
46,465

4,508

15,515

3,862

1,974

20,606

3,523

17,083

United States
10,331

2,714

2,671

1,232

47

3,667

366

3,301

Total
56,796

7,222

18,185

5,094

2,021

24,273

3,889

20,384

Notes:
(1)
Numbers may not add due to rounding.
(2)
Saskatchewan Capital Resource Surcharge, as well as Ad Valorem, and Severance payable in the United States have been included under the royalties and burdens column.
(3) Abandonment and Reclamation costs now include active costs from wells and locations included in the Crescent Point Reserve Report as well as inactive costs including suspended wells, pipelines and facilities, as specified in COGEH update of October 2019.

In 2018, the Crescent Point Reserve Report included abandonment and reclamation costs for active wells and locations only. As recommended in the October 2019 COGEH updated guidance, the Corporation has now also included abandonment, decommissioning and reclamation costs for all inactive assets including non-producing and suspended wells, facilities and pipelines. The impact on the Crescent Point Reserve Report from these additional burdens on total Proved plus Probable reserves is estimated at $261 million of value discounted at 10%, which will differ from the discounted values carried in our financial reporting, due to differences in abandonment activity timing and different inflation and discount values.



- 18 -    

Future Net Revenue by Production Type(1) 
 
Future Net Revenue
Before Income Taxes(6)
(Discounted at 10% per year)
Percentage
Unit Value
 
(MM$)
(%)
($/boe)
($/Mcfe)
Proved
 
 
 
 
CANADA
 
 
 
 
Light and Medium Crude Oil(2)
1,916

27.7

18.41

3.07

Heavy Crude Oil(2)
376

5.4

16.09

2.68

Tight Oil(4)
4,585

66.3

20.71

3.45

Natural Gas Liquids




Shale Gas(5)




Conventional Natural Gas(3)
33

0.5

3.11

0.52

Total Canada
6,910

100

19.22

3.20

UNITED STATES
 
 
 
 
Light and Medium Crude Oil(2)




Heavy Crude Oil(2)




Tight Oil(4)
746

100

11.74

1.96

Natural Gas Liquids




Shale Gas(3)




Conventional Natural Gas(3)




Total United States
746

100

11.74

1.96

TOTAL
 
 
 
 
Light and Medium Crude Oil(2)
1,916

25.0

18.41

3.07

Heavy Crude Oil(2)
376

4.9

16.09

2.68

Tight Oil(4)
5,331

69.6

18.71

3.12

Natural Gas Liquids




Shale Gas(3)(5)




Conventional Natural Gas(3)
33

0.4

3.11

0.52

Total Proved
7,657

100

18.10

3.02

Notes:
(1)
Numbers may not add due to rounding.
(2)
Including solution gas and other by-products.
(3)
Including by-products, but excluding solution gas.
(4)
Including solution gas (categorized as “Shale Gas”) and other by-products.
(5)
Volumes of Shale Natural Gas have been included in “Tight Oil” as it is solution gas relating to oil production.
(6)
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.




- 19 -    

 
Future Net Revenue
Before Income Taxes
(6)
(Discounted at 10% per year)
Percentage
Unit Value
 
(MM$)
(%)
($/boe)
($/Mcfe)
Proved Plus Probable
 
 
 
 
CANADA
 
 
 
 
Light and Medium Crude Oil(2)
2,961

28.4

17.70

2.95

Heavy Crude Oil()
456

4.4

15.76

2.63

Tight Oil(4)
6,965

66.8

19.53

3.26

Natural Gas Liquids




Shale Gas(5)




Conventional Natural Gas(3)
39

0.4

3.01

0.50

Total Canada
10,420

100

18.42

3.07

UNITED STATES
 
 
 
 
Light and Medium Crude Oil(2)




Heavy Crude Oil(2)




Tight Oil(4)
1,367

100

13.35

2.22

Natural Gas Liquids




Shale Gas(3)




Conventional Natural Gas(3)




Total United States
1,367

100

13.35

2.22

TOTAL
 
 
 
 
Light and Medium Crude Oil(2)
2,961

25.1

17.70

2.95

Heavy Crude Oil(2)
456

3.9

15.76

2.63

Tight Oil(4)
8,332

70.7

18.15

3.03

Natural Gas Liquids




Shale Gas(3)(5)




Conventional Natural Gas(3)
39

0.3

3.01

0.50

Total Proved Plus Probable
11,787

100

17.64

2.94

Notes:
(1)
Numbers may not add due to rounding.
(2)
Including solution gas and other by-products.
(3)
Including by-products, but excluding solution gas.
(4)
Including solution gas (categorized as “Shale Gas”) and other by-products.
(5)
Volumes of Shale Natural Gas have been included in “Tight Oil” as it is solution gas relating to oil production.
(6)
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.


Notes and Definitions
In the tables set forth above in "Disclosure of Reserves Data" and elsewhere in this AIF, the following notes and other definitions are applicable.
Reserve Categories
The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of Proved and Probable reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery.
The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions.



- 20 -    

(a)
"Reserves" are estimated remaining economic quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.
(b)
"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
(c)
"Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
(d)
"Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.
(e)
"Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned. In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to sub-divide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.
(f)
"Probable" reserves are those additional reserves that are less certain to be recovered than Proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable reserves.
Levels of Certainty for Reported Reserves
The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:
At least a 90% probability that the quantities actually recovered will equal or exceed the estimated Proved reserves; and
At least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable reserves.
A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.
Additional Definitions
The following terms, used in the preparation of the Crescent Point Reserve Report and this AIF, have the following meanings:
(a)
"associated gas" means the gas cap overlying a crude oil accumulation in a reservoir.



- 21 -    

(b)
"crude oil" or "oil" means a mixture that consists mainly of pentanes and heavier hydrocarbons, which may contain small amounts of sulphur and other non-hydrocarbons, that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. It does not include liquids obtained from the processing of natural gas.
(c)
"development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from the reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
(i)
gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves;
(ii)
drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and the wellhead assembly;
(iii)
acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds measuring devices and production storage, natural gas cycling and processing plants, and central utility and waste disposal system; and
(iv)
provide improved recovery systems.
(d)
"development well" means a well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.
(e)
"exploration costs" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as "prospecting costs") and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
(i)
costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies (collectively sometimes referred to as "geological and geophysical costs");
(ii)
costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;
(iii)
dry hole contributions and bottom hole contributions;
(iv)
costs of drilling and equipping exploratory wells; and
(v)
costs of drilling exploratory type stratigraphic test wells.
(f)
"exploratory well" means a well that is not a development well, a service well or a development type stratigraphic test well.
(g)
"field" means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata or laterally by local geologic barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature"



- 22 -    

and "stratigraphic condition" are intended to denote localized geological features, in contrast to broader terms such as "basin", "trend", "province", "play" or "area of interest".
(h)
"future prices and costs" means future prices and costs that are:
(i)
generally accepted as being a reasonable outlook of the future;
(ii)
if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Corporation is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (i).
(i)
"future income tax expenses" means future income tax expenses estimated (generally, year-by-year):
(i)
making appropriate allocations of estimated unclaimed costs and losses carried forward for tax purposes, between oil and gas activities and other business activities;
(ii)
without deducting estimated future costs that are not deductible in computing taxable income;
(iii)
taking into account estimated tax credits and allowances (for example, royalty tax credits); and
(iv)
applying to the future pre-tax net cash flows relating to the Corporation's oil and gas activities the appropriate year end statutory tax rates, taking into account future tax rates already legislated.
(j)
"future net revenue" means the estimated net amount to be received with respect to the anticipated development and production of reserves (including synthetic oil, coal bed methane and other non-conventional reserves) estimated using future prices and costs.
(k)
"gross" means:
(i)
in relation to the Corporation's interest in production or reserves, its "company gross reserves", which are its working interest (operated or non-operated) share before deduction of royalties and without including any royalty interests of the Corporation;
(ii)
in relation to wells, the total number of wells in which the Corporation has an interest; and
(iii)
in relation to properties, the total area of properties in which the Corporation has an interest.
(l)
"natural gas" means a naturally occurring mixture of hydrocarbon gases and other gases.
(m)
"natural gas liquids" means those hydrocarbon components that can be recovered from natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes plus, condensate and small quantities of non-hydrocarbons.
(n)
"net" means:
(i)
in relation to the Corporation's interest in production or reserves, its working interest (operated or non-operated) share after deduction of royalty obligations, plus its royalty interests in production or reserves;
(ii)
in relation to the Corporation's interest in wells, the number of wells obtained by aggregating the Corporation's working interest in each of its gross wells; and
(iii)
in relation to the Corporation's interest in a property, the total area in which the Corporation has an interest multiplied by the working interest owned by the Corporation.
(o)
"non-associated gas" means an accumulation of natural gas in a reservoir where there is no crude oil.



- 23 -    

(p)
"operating costs" or "production costs" means costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment and facilities as well as other costs of operating and maintaining those wells and related equipment and facilities.
(q)
"production" means recovering, gathering, treating, field or plant processing (for example, processing gas to extract natural gas liquids) and field storage of oil and gas.
(r)
"property" includes:
(i)
fee ownership or a lease, concession, agreement, permit, licence or other interest representing the right to extract oil or gas subject to such terms as may be imposed by the conveyance of that interest;
(ii)
royalty interests, production payments payable in oil or gas, and other non-operated interests in properties operated by others; and
(iii)
an agreement with a foreign government or authority under which the Corporation participates in the operation of properties or otherwise serves as "producer" of the underlying reserves (in contrast to being an independent purchaser, broker, dealer or importer).
A property does not include supply agreements, or contracts that represent a right to purchase, rather than extract, oil or gas.
(s)
"property acquisition costs" means costs incurred to acquire a property (directly by purchase or lease, or indirectly by acquiring another corporate entity with an interest in the property), including:
(i)
costs of lease bonuses and options to purchase or lease a property;
(ii)
the portion of the costs applicable to hydrocarbons when land including rights to hydrocarbons is purchased in fee; and
(iii)
brokers' fees, recording and registration fees, legal costs and other costs incurred in acquiring properties.
(t)
"proved property" means a property or part of a property to which reserves have been specifically attributed.
(u)
"reservoir" means a subsurface rock unit that contains an accumulation of petroleum.
(v)
"service well" means a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for combustion.
(w)
"solution gas" means natural gas dissolved in crude oil.
(x)
"stratigraphic test well" means a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Ordinarily, such wells are drilled without the intention of being completed for hydrocarbon production. They include wells for the purpose of core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (i) "exploratory type" if not drilled into a proved property; or (ii) "development type", if drilled into a proved property. Development type stratigraphic wells are also referred to as "evaluation wells".
(y)
"support equipment and facilities" means equipment and facilities used in oil and gas activities, including seismic equipment, drilling equipment, construction and grading equipment, vehicles, repair shops, warehouses, supply points, camps, and division, district or field offices.
(z)
"unproved property" means a property or part of a property to which no reserves have been specifically attributed.



- 24 -    

(aa)
"well abandonment and reclamation costs" means costs of abandoning a well (net of salvage value) and of disconnecting the well from the surface gathering system and remediating and reclaiming the site to original conditions. They do not include costs of abandoning the gathering system.
Pricing Assumptions – Forecast Prices and Costs
GLJ and Sproule employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2019 in estimating our reserves data using forecast prices and costs.
Year
Conventional Natural Gas
Crude Oil
NGLs
 
 
 
 
Henry Hub
NYMEX
($US/MMBTU)
AECO/NIT
Spot
($Cdn/MMBTU)
WTI at
Cushing
Oklahoma
($US/bbl)
Edmonton
($Cdn/bbl)
Pentanes
Plus
Edmonton
($Cdn/bbl)
Butanes
Edmonton
($Cdn/bbl)
Propane
Edmonton
($Cdn/bbl)
Operating Cost Inflation Rate
(%/yr)
Capital Cost Inflation Rate
(%/yr)
Exchange
Rate
($US/$Cdn)
Forecast
 
 
 
 
 
 
 
 
 
 
2020
2.80

2.04

61.00

73.84

76.32

37.72

25.07

0.0%
0.0%
0.760
2021
3.00

2.27

65.00

78.51

80.52

43.90

31.84

1.0%
1.0%
0.770
2022
3.25

2.81

67.00

78.73

80.00

47.74

32.43

2.0%
2.0%
0.800
2023
3.32

2.89

68.34

80.30

81.68

48.69

33.26

2.0%
2.0%
0.800
2024
3.38

2.98

69.71

81.91

83.38

49.67

34.12

2.0%
2.0%
0.800
2025
3.45

3.06

71.10

83.54

85.13

50.66

34.99

2.0%
2.0%
0.800
2026
3.52

3.15

72.52

85.21

86.90

51.67

35.88

2.0%
2.0%
0.800
2027
3.59

3.24

73.97

86.92

88.72

52.71

36.78

2.0%
2.0%
0.800
2028
3.66

3.33

75.45

88.66

90.57

53.76

37.71

2.0%
2.0%
0.800
2029
3.73

3.42

76.96

90.43

92.45

54.84

38.65

2.0%
2.0%
0.800
2030
3.81

3.51

78.50

92.24

94.38

55.93

39.61

2.0%
2.0%
0.800
2031+
+2%/yr

+2%/yr

+2%/yr

+2%/yr

+2%/yr

+2%/yr

+2%/yr

2.0%
2.0%
0.800

For the year ended December 31, 2019, the average realized sales prices before hedging were $66.50/bbl for light and medium crude oil, $60.95/bbl for heavy crude oil, $67.67/bbl for tight oil, $19.94/bbl for NGLs, $2.87/mcf for shale gas and $2.29/mcf for conventional natural gas.
Reconciliations of Changes in Reserves(1) 
The following table sets forth a reconciliation of the Corporation's Company Gross reserves by total Proved, total Probable and total Proved plus Probable reserves as at December 31, 2019 against such reserves as at December 31, 2018 based on forecast price and cost assumptions.
CANADA
Light and Medium Crude Oil (Mbbls)
Heavy Crude Oil
(Mbbls)
Tight Oil
(Mbbls)
Natural Gas Liquids
(Mbbls)
Factors
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
December 31, 2018
127,356

71,928

199,284

29,015

7,903

36,918

219,734

130,667

350,400

59,824

31,789

91,613

Discoveries
85

29

114




494

171

664

27

9

36

Extensions and Improved Recovery (2)
3,658

2,016

5,674

133

10

143

11,669

8,865

20,534

1,282

875

2,156

Technical Revisions (4)
(638
)
(5,633
)
(6,270
)
670

(951
)
(281
)
(21,578
)
(20,512
)
(42,090
)
(1,885
)
(4,122
)
(6,007
)
Acquisitions
2,403

590

2,993




2

47

49


17

17

Dispositions (5)
(18,827
)
(9,959
)
(28,786
)



(9,186
)
(6,707
)
(15,893
)
(2,321
)
(2,080
)
(4,401
)
Economic Factors
(2,107
)
(622
)
(2,729
)
(285
)
(69
)
(354
)
(1,761
)
402

(1,360
)
(691
)
(186
)
(877
)
Production (7)
(10,984
)

(10,984
)
(1,733
)

(1,733
)
(23,220
)

(23,220
)
(5,931
)

(5,931
)
December 31, 2019
100,947

58,348

159,295

27,799

6,894

34,693

176,152

112,932

289,084

50,306

26,302

76,608





- 25 -    

CANADA
Shale Gas
(Natural Gas)
(MMcf)
Conventional Natural Gas
(Natural Gas)
(MMcf)
Total BOE
(Mboe)
Factors
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
December 31, 2018
178,930

105,297

284,228

85,259

39,953

125,212

479,960

266,495

746,455

Discoveries
518

179

698




692

239

931

Extensions and Improved Recovery (2)
7,787

6,216

14,003

572

442

1,014

18,134

12,876

31,010

Technical Revisions (4)
(8,946
)
(12,913
)
(21,858
)
(2,100
)
(4,342
)
(6,442
)
(25,271
)
(34,093
)
(59,365
)
Acquisitions
1

44

45

1

1

1

2,406

661

3,067

Dispositions (5)
(21,651
)
(18,399
)
(40,050
)
(544
)
(1,032
)
(1,576
)
(34,033
)
(21,985
)
(56,018
)
Economic Factors
(453
)
(203
)
(656
)
(3,858
)
(1,382
)
(5,240
)
(5,563
)
(740
)
(6,302
)
Production (7)
(17,735
)

(17,735
)
(7,243
)

(7,243
)
(46,031
)

(46,031
)
December 31, 2019
138,452

80,222

218,674

72,086

33,640

105,726

390,294

223,452

613,747


UNITED STATES
Light and Medium Crude Oil (Mbbls)
Heavy Crude Oil
(Mbbls)
Tight Oil
(Mbbls)
Natural Gas Liquids
(Mbbls)
Factors
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
December 31, 2018
68

31

99




105,613

78,820

184,433

15,976

10,513

26,489

Discoveries












Extensions and Improved Recovery (3)






11,517

5,987

17,504

2,090

1,084

3,174

Technical Revisions (4)
(11
)
(4
)
(14
)



2,726

(1,465
)
1,262

1,668

(611
)
1,057

Acquisitions






376

218

595

74

43

117

Dispositions (6)
(58
)
(27
)
(85
)



(50,875
)
(44,394
)
(95,268
)
(5,335
)
(3,618
)
(8,954
)
Economic Factors






(336
)
(2,047
)
(2,383
)
(74
)
(397
)
(471
)
Production (7)






(10,132
)

(10,132
)
(1,642
)

(1,642
)
December 31, 2019






58,890

37,120

96,010

12,756

7,013

19,769


UNITED STATES
Shale Gas
(Natural Gas)
(MMcf)
Conventional Natural Gas
(Natural Gas)
(MMcf)
Total BOE
(Mboe)
Factors
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
December 31, 2018
107,585

73,380

180,965

5

2

8

139,589

101,594

241,183

Discoveries









Extensions and Improved Recovery (3)
6,401

3,338

9,739




14,673

7,628

22,301

Technical Revisions (5)
8,260

663

8,923

(4
)
(2
)
(6
)
5,759

(1,969
)
3,790

Acquisitions
214

125

339




486

282

769

Dispositions (6)
(72,919
)
(53,414
)
(126,333
)
(1
)
(1
)
(2
)
(68,421
)
(56,942
)
(125,363
)
Economic Factors
(215
)
(1,150
)
(1,365
)



(446
)
(2,636
)
(3,082
)
Production (7)
(8,453
)

(8,453
)



(13,183
)

(13,183
)
December 31, 2019
40,873

22,942

63,815




78,459

47,956

126,415





- 26 -    

TOTAL
Light and Medium Crude Oil  (Mbbls)
Heavy Crude Oil
(Mbbls)
Tight Oil (4)
(Mbbls)
Natural Gas Liquids
(Mbbls)
Factors
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
December 31, 2018
127,424

71,959

199,383

29,015

7,903

36,918

325,347

209,486

534,833

75,800

42,302

118,102

Discoveries
85

29

114




494

171

664

27

9

36

Extensions and Improved Recovery (2) (3)
3,658

2,016

5,674

133

10

143

23,186

14,852

38,038

3,371

1,959

5,330

Technical Revisions (4)
(648
)
(5,637
)
(6,285
)
670

(951
)
(281
)
(18,852
)
(21,977
)
(40,828
)
(217
)
(4,733
)
(4,950
)
Acquisitions
2,403

590

2,993




379

266

644

74

60

134

Dispositions (5) (6)
(18,884
)
(9,986
)
(28,871
)



(60,061
)
(51,101
)
(111,162
)
(7,656
)
(5,699
)
(13,355
)
Economic Factors
(2,107
)
(622
)
(2,729
)
(285
)
(69
)
(354
)
(2,098
)
(1,646
)
(3,743
)
(765
)
(583
)
(1,348
)
Production (7)
(10,984
)

(10,984
)
(1,733
)

(1,733
)
(33,352
)

(33,352
)
(7,573
)

(7,573
)
December 31, 2019
100,947

58,348

159,295

27,799

6,894

34,693

235,043

150,052

385,094

63,062

33,315

96,377


TOTAL
Shale Gas (5)
(Natural Gas) (MMcf)
Conventional Natural Gas
(Natural Gas)
(MMcf)
Total BOE
(Mboe)
Factors
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
December 31, 2018
286,515

178,677

465,193

85,264

39,955

125,219

619,549

368,089

987,638

Discoveries
518

179

698




692

239

931

Extensions and Improved Recovery (2) (3)
14,188

9,554

23,743

572

442

1,014

32,808

20,503

53,311

Technical Revisions (4)
(686
)
(12,250
)
(12,936
)
(2,104
)
(4,344
)
(6,448
)
(19,512
)
(36,063
)
(55,574
)
Acquisitions
216

168

384

1

1

1

2,892

944

3,836

Dispositions (5) (6)
(94,570
)
(71,813
)
(166,383
)
(546
)
(1,032
)
(1,578
)
(102,454
)
(78,927
)
(181,381
)
Economic Factors
(668
)
(1,354
)
(2,021
)
(3,858
)
(1,382
)
(5,240
)
(6,009
)
(3,376
)
(9,385
)
Production (7)
(26,188
)

(26,188
)
(7,243
)

(7,243
)
(59,214
)

(59,214
)
December 31, 2019
179,325

103,163

282,488

72,086

33,640

105,726

468,753

271,409

740,161

Notes:
(1)
Numbers may not add due to rounding.
(2)
The Corporation’s Canadian development strategy in 2019 focused on in-fill and development drilling, mostly in the Viewfield Bakken and Flat Lake Torquay resource plays in southeast Saskatchewan as well as the Shaunavon area.
(3)
The Corporation’s United States development strategy in 2019 focused on in-fill and development drilling, mostly in the Bakken and Three Forks resource plays in Williams, North Dakota.
(4)
Negative technical revisions on Probable volumes are reflective of reserve volumes being transferred to Proven reserves categories as reserve confidence grows and locations are converted from Probable reserves to Proved plus Probable reserves, through either offset drilling increasing confidence in location bookings, or actual conversion of the location to developed (well) reserves.
       
Performance-based negative revisions were observed on existing primary (non-waterflood) Tight Oil assets including the Viewfield Bakken, Flat Lake Torquay and the Shaunavon area resource assets, representing a large portion of the revisions in this category. These revisions were primarily due to a reassessment of the resource basins, which resulted in recognition of performance deviations from early forecasts. The reassessment of the Corporation’s producing assets has also resulted in a corresponding negative technical revision on some of the associated area locations, which has in turn been reflected in the Corporation’s reserves reported. Additionally, these technical revisions impacted the corresponding Shale Gas and NGL reserves.
     
Increased gas-oil ratios from early forecasts in Williams, North Dakota resulted in increases of both Shale Gas and NGL volumes.
       
Light and Medium volumes realized negative technical revisions in Proved as well as Proved plus Probable reserves, spread across several plays including Flat Lake Ratcliffe, Provost Viking and Turner Valley Rundle.
(5)
The Corporation’s southeast Saskatchewan Light and Medium Crude Oil disposition program represents the majority of values presented. These dispositions closed in the third quarter of 2019.
(6)
The Corporation's disposition of all assets in the Uinta basin of Utah represent most of these volumes, which closed on October 18, 2019.
(7)
The Corporation produced an average of 126,113 boe per day in Canada, 36,117 boe per day in the United States for a total of 162,230 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.



- 27 -    

The Corporation has extensive Proved development opportunities that are prioritized based on a disciplined set of criteria including, but not limited to, time for payout, rate of return, maturity of land tenure, reserve booking opportunities, proximity to transportation and marketing, as well as anticipated production rates. With this extensive portfolio of opportunities, it would be unrealistic, both from a cash flow as well as physical ability, to completely execute on the entire portfolio of booked opportunities within two years, however approximately 50% of the development spending occurs within this timeframe.
The development of these reserves have been based on recent and current capital activity levels, with no material deferrals of development opportunities beyond these normal budgetary constraints. The majority of these reserves are planned to be on stream within a three-year timeframe, which represents approximately 81% of the net undeveloped location count, as well as 74% of the net total future development capital. These development activities are directed mostly to the Corporation's core focus areas of Viewfield Bakken, Flat Lake Torquay and Shaunavon resource plays in Canada and the North Dakota Three Forks play in the U.S.
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)