EX-99.1 2 cpgye2017aif.htm EXHIBIT 99.1 Exhibit
 

Exhibit 99.1


cpg2017aifimage1a02.jpg
CRESCENT POINT ENERGY CORP.
ANNUAL INFORMATION FORM
For the Year Ended December 31, 2017
Dated February 28, 2018



 
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
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 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;
•
our hedging strategy, including its expected outcomes, and our approval to managing physical delivery contracts;
•
our risk mitigation strategy and the expected outcomes from same;
•
the potential impact of competition and our working relationships with industry partners and joint operators on our business;
•
business prospects;
•
the performance characteristics of Crescent Point's oil and natural gas properties, including but not limited to oil and natural gas production levels;
•
anticipated future cash flows and oil and natural gas production levels;
•
projected returns and exploration potential of our assets;
•
the potential of Crescent Point’s plays;
•
future development plans;
•
forecast costs and expenses associated with Crescent Point's business, including capital expenditure programs and how they will be funded;
•
our leverage objectives for 2018;
•
corporate and asset acquisitions and dispositions;
•
drilling programs;
•
expected location inventory development timing;
•
the expected ongoing transition to horizontal wells in Utah and its impact on well bookings;
•
our expected production breakdown by area on a Proved and Proved plus Probable production basis;
•
the quantity of oil and natural gas reserves;
•
projections of commodity prices and costs;
•
our future waterflood programs;
•
treatment of DRIP and SDP participants if either plan is reinstated;
•
the final terms of the Stock Option Plan and the approval of same by the Shareholders;
•
expected decommissioning, abandonment, remediation and reclamation costs;
•
our tax horizon;
•
the potential impact of NAFTA re-negotiations;


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•
expected trends in environmental regulation, including the anticipated impact the trends will have on our operations and our costs to comply;
•
the impact, and projected long-term impacts, of carbon taxes;
•
payment of monthly dividends;
•
supply and demand for oil and natural gas;
•
expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; and
•
treatment under governmental regulatory regimes, including royalty regimes applicable to natural resources.
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, 2017, under the headings "Risk Factors" and "Forward-Looking Information". The material assumptions and factors in making forward-looking statement are disclosed in the Management's Discussion and Analysis for the year ended December 31, 2017, under the headings "Capital Expenditures", "Liquidity and Capital Resources", "Critical Accounting Estimates", "Risk Factors", "Changes in Accounting Policies" and "Outlook".
This information contains certain forward-looking estimates that involve substantial known and unknown risks and uncertainties, certain of which are beyond Crescent Point's control. Such risks and uncertainties include, but are not limited to: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas; delays in business operations, pipeline restrictions and blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions, including changes in laws and regulations, the adoption of new environmental laws and regulations, and changes in how environmental laws and regulations are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; risks and uncertainties related to oil and gas interests and operations on tribal lands; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; fluctuations in foreign exchange and interest rates; stock market volatility; failure to realize the anticipated benefits of acquisitions and dispositions; general economic, market and business conditions; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry; and other factors, many of which are outside the control of Crescent Point. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as each of these are interdependent and Crescent Point's future course of action depends on management’s assessment of all information available at the relevant time.
Statements relating to "reserves" and "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. Actual reserve values may be greater than or less than the estimates provided herein.


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There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only. In general, estimates of economically recoverable crude oil, natural gas and natural gas liquids reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For these reasons, estimates of the economically recoverable crude oil, natural gas liquids and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. Crescent Point's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. In addition, the discounted and undiscounted net present value of future net revenues attributable to reserves do not represent fair market value; and the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Therefore, Crescent Point's actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking estimates and if such actual results, performance or achievements transpire or occur, or if any of them do so, there can be no certainty as to what benefits Crescent Point will derive therefrom.
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 is calculated on a per boe basis as oil and gas sales, less royalties, operating and transportation expenses and realized derivative gains and losses. Netback is a common metric used in the oil and gas industry and 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 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 AIF, 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 US standards of reporting reserves, see "Risk Factors — Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States".


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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.
"AIF" means this annual information form of the Corporation dated February 28, 2018 for the year ended December 31, 2017.
"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.
"Coral Hill" means Coral Hill Energy Ltd.
"Coral Hill Arrangement" means the plan of arrangement under Section 193 of the ABCA involving Coral Hill and the Corporation, completed on August 14, 2015, as more particularly described under the heading "General Development of the Business of the Corporation – History – 2015".
"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.
"Legacy" means Legacy Oil + Gas Inc.
"Legacy Arrangement" means the plan of arrangement under Section 193 of the ABCA involving Legacy and the Corporation, completed on June 30, 2015, as more particularly described under the heading "General Development of the Business of the Corporation – History – 2015".
"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, 2017.


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"NI 51-101" means "National Instrument 51-101 – Standards for Disclosure for Oil and Gas Activities".
"NYSE" means the New York Stock Exchange.
"OPEC" means Organization of the Petroleum Exporting Countries.
"Partnership" means Crescent Point Resources Partnership, a general partnership formed under the laws of the Province of Alberta, having CPHI and the Corporation as partners.
"PSU Plan" means the Performance Share Unit Plan of the Corporation.
"Restricted Share Bonus Plan" means the Restricted Share Bonus Plan of the Corporation.
"SDP" means the Share Dividend Plan of the Corporation.
"SEC" means the U.S. Securities and Exchange Commission.
"Shareholders" means the holders from time to time of Common Shares.
"Shelter Bay" means Shelter Bay Energy Inc.
"Sproule" means Sproule Associates Limited.
"Stock Option Plan" means the Stock Option Plan of the Corporation.
"Tax Act" means the Income Tax Act (Canada), R.S.C. 1985, c. 1 (5th Supp.), and the regulations promulgated thereunder, each as amended from time to time.
"Tribe" means the Ute Indian Tribe of the Uintah and Ouray Reservation.
"Trust" means Crescent Point Energy Trust, an unincorporated open ended investment trust governed by the laws of the Province of Alberta that was dissolved pursuant to the Conversion Arrangement.
"Trust Units" means the trust units of the Trust.
"TSX" means the Toronto Stock Exchange.
"Unitholders" means holders of Trust Units.
"U.S." means the United States of America.
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
barrel of oil equivalent of natural gas and crude oil on the basis of 1 boe for 6 (unless otherwise stated) Mcf of natural gas (this conversion factor is an industry accepted norm and is not based on either energy content or current prices)
boe/d
barrel of oil equivalent per day
m³
cubic metres
M$
thousand dollars
Mboe
thousand barrels of oil equivalent
MMboe
million barrels of oil equivalent
MM$
million dollars
MW
megawatt
MW/h
megawatt per hour
WTI
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade



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CURRENCY OF INFORMATION
The information set out in this AIF is stated as at December 31, 2017 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 oil and natural gas reserves in Western Canada and the United States.
We make monthly cash dividends to Shareholders from our net cash flow. Our primary source of cash flow is distributions from the Partnership.
Partnership
The Partnership is a general partnership governed by the laws of the Province of Alberta. As set forth in the diagram below under "Organizational Structure of the Corporation", the partners of the Partnership are CPHI and the Corporation.
The existing business of the Corporation is carried on through the Partnership and through CPEUS. The Partnership holds all of the Corporation's Canadian operating assets and CPEUS holds all of the Corporation’s U.S. operating assets.
CPHI
CPHI is a wholly-owned subsidiary of the Corporation. CPHI is a partner of the Partnership.


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



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Organizational Structure of the Corporation
The following diagram describes the intercorporate relationships among the Corporation and its material direct and indirect subsidiaries described above as at February 28, 2018. Reference should be made to the appropriate sections of this AIF for a complete description of the structure of the Corporation.
organizationstructurea02.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.
2015
On March 10, 2015, the total amount available under the Corporation’s syndicated credit facility and operating credit facility was increased to a total of $3.6 billion and the term was extended to June 8, 2018.
On April 22, 2015, the Corporation closed an offering of senior guaranteed notes in the United States and Canada on a private placement basis in aggregate principal amounts of US$250.0 million and $65.0 million, respectively. The terms of the U.S. notes range from 10 to 12 years with a weighted average term of 10.2 years and coupon rates ranging from 4.08% to 4.18% and the terms of the Canadian notes are 10 years with a coupon rate of 3.94%.
On June 16, 2015, the Corporation completed an equity offering of 23,160,000 Common Shares at $28.50 per Common Share for aggregate gross proceeds of approximately $660 million.
On June 30, 2015, the Corporation closed the Legacy Arrangement for total consideration of approximately $1.5 billion, comprised of 18,229,428 Crescent Point Common Shares, cash consideration of $19.4 million and assumed debt. See "Description of Our Business – Reorganizations".
On July 20, 2015, the Corporation filed a short form base shelf prospectus for an aggregate offering amount not to exceed $2.5 billion. The prospectus allows Crescent Point to offer and issue common shares, subscription receipts, warrants, options and debt securities in Canada and the U.S. at any time during the 25-month period that the prospectus remains in place.


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On August 12, 2015, the Corporation reduced its monthly dividend to $0.10 per share, effective with the August dividend payable on September 15, 2015. In addition, effective with the August dividend, the Corporation suspended the SDP and DRIP. See "Additional Information Respecting Crescent Point – Share Dividend Plan".
On August 14, 2015, the Corporation closed the Coral Hill Arrangement pursuant to which the Corporation acquired all of the remaining issued and outstanding shares of Coral Hill not already owned by the Corporation (as at August 14, 2015, Crescent Point had an 8.7% equity interest in Coral Hill) for total consideration of $243.8 million, comprised of 4,283,680 Crescent Point Common Shares, assumed debt and the historical cost of Crescent Point’s previously held equity investment of $42.0 million. See "Description of Our Business – Reorganizations".
On November 5, 2015, Gregory T. Tisdale announced that he was stepping down from his role as Chief Financial Officer of the Corporation. Ken Lamont, then Crescent Point’s Vice President, Finance and Treasurer, was appointed Chief Financial Officer effective January 1, 2016.
2016
On March 8, 2016, Barbara Munroe was appointed as a director of the Corporation. See "Additional Information Respecting Crescent Point – Directors and Officers".
On March 8, 2016, the Corporation reduced its monthly dividend to $0.03 per share, effective with the March dividend payable on April 15, 2016.
On August 10, 2016, the terms of the Corporation’s syndicated credit facility and operating credit facility were each extended to June 10, 2019.
On September 20, 2016, the Corporation completed an equity offering of 33,700,000 Common Shares at a price of $19.30 per Common Share for aggregate gross proceeds of approximately $650 million.
In the third quarter of 2016, the Corporation completed a strategic core consolidation acquisition in its emerging-growth Flat Lake resource play and an acquisition of low-decline, conventional waterflood assets, both in the Canadian portion of the Williston basin. The Corporation also disposed of non-core assets in the Peace River Arch area of northwest Alberta for $31.0 million.  Total net consideration for the acquisitions, net of the disposition was $211.7 million.
On November 9, 2016, Mike Jackson was appointed as a director of the Corporation. See "Additional Information Respecting Crescent Point – Directors and Officers".
2017
In the first quarter of 2017, Crescent Point completed the acquisition of approximately 8,500 net acres in North Dakota for total cash consideration of US$100.0 million. The acquired lands were contiguous to the Corporation's current acreage.
Crescent Point also acquired approximately 80,000 net acres of undeveloped land in the Uinta Basin in the second quarter of 2017, for total cash consideration of US$72.5 million. The lands include 1,700 boe/d of production and provided the opportunity to expand the Corporation’s horizontal drilling expertise to an area with multi-zone potential.
In the second quarter of 2017, the Corporation sold 1,100 boe/d of non-operated conventional assets in Manitoba for total cash consideration of $93.2 million.
On May 24, 2017, Ted Goldthorpe was elected as a director of the Corporation. See "Additional Information Respecting Crescent Point - Directors and Officers".


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On June 26, 2017, Crescent Point renewed its unsecured, covenant-based credit facilities totaling $3.6 billion. The renewal extended the maturity date of the credit facilities to June 10, 2020. See “Additional Information Respecting Crescent Point - Long-Term Debt”.
During the third quarter of 2017, the Corporation completed or entered into agreements to dispose of non-core assets representing approximately 3,000 boe/d for total value of over $190 million.
In the fourth quarter of 2017, Crescent Point entered into agreements to dispose of non-core assets for total value of approximately $40 million, of which approximately $20 million are expected to close during the first quarter of 2018.

DESCRIPTION OF OUR BUSINESS
General
The Corporation is an oil and gas exploration, development and production company. The Corporation is a conventional oil and gas producer with assets strategically focused in properties comprised of high quality, long life, operated, light and medium oil and natural gas reserves in Western Canada and the United States. The primary assets of the Corporation are currently its interest in the Partnership, shares in CPHI, shares in CPUSH and, indirectly, shares in CPEUS.
The crude oil and natural gas properties and related assets generating income for the benefit of the Corporation are located in the provinces of Saskatchewan, Alberta, British Columbia and Manitoba and in the states of North Dakota, Montana and Utah. The properties and assets consist of producing crude oil and natural gas reserves and Proved plus Probable (as defined herein) crude oil and natural gas reserves not yet on production and land.
We pay monthly cash dividends to Shareholders from our net cash flow in accordance with our dividend policy. Our primary sources of cash flow are distributions from the Partnership. See "Dividends".
Strategy
We strive to create sustainable, value-added growth in reserves, production and cash flow through the execution of management's integrated strategy of acquiring, exploiting and developing high quality, long life, light and medium oil and natural gas properties.
We develop our properties through a detailed technical analysis of information including reservoir characteristics, petroleum initially in place, recovery factors and the applicability of enhanced recovery techniques. Our goal is to increase reserves and production in a cost effective manner through a number of techniques, including drilling infill and step-out wells, fracture stimulation of horizontal wells, re-completing existing wells and implementing waterflood or pressure support schemes.
Risk Management and Marketing
Factors outside our control impact, to varying degrees, the prices we receive for production and the associated operating expenses we incur. These include but are not limited to:
(a)
world market forces, including world supply and consumption levels and the ability of the OPEC to set and maintain production levels and prices for crude oil;
(b)
political conditions, including the risk of hostilities in the Middle East and other regions throughout the world;
(c)
increases or decreases in crude oil differentials and their implications for prices received by us;
(d)
the impact of changes in the exchange rate between Canadian and U.S. dollars on prices received by us for our crude oil and natural gas;


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(e)
North American market forces, most notably shifts in the balance between supply and demand for crude oil and natural gas and the implications for the prices of crude oil and natural gas;
(f)
availability, proximity and capacity of oil and gas gathering systems, pipeline and processing facilities, railcars and railcar loading facilities;
(g)
global and domestic economic and weather conditions;
(h)
price and availability of alternative fuels;
(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 existing net of royalty production on 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 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 US dollars and benchmark natural gas prices are hedged using financial AECO-based instruments transacted in Canadian dollars. Total financial oil and gas hedges in 2017 amounted to approximately 42% of annual production, net of royalties, consisting of approximately 42% of annual liquids production and approximately 42% of annual natural gas production, net of royalties. The primary objective of this strategy is to be well positioned to maximize shareholder return with long-term growth plus dividend income. The Corporation recorded a realized derivative gain on oil and gas hedge contracts of $101.2 million in 2017.
Refer to the annual financial statements for our commitments under all hedging agreements as at December 31, 2017.
In addition to hedging benchmark crude oil and natural gas prices with financial instruments, we have also mitigated crude oil basis risk by delivering a portion of our crude oil production into diversified refinery markets using rail transportation. Crescent Point operates four railcar loading facilities, serving its key producing areas of southeast Saskatchewan, southwest Saskatchewan, central Alberta and Utah. Crude oil volumes loaded at these facilities are sold at the loading facilities and our buyers are responsible for providing railcars and managing transportation logistics from that point until delivery at the refinery gate. By utilizing rail transportation, we have been able to access refining markets over the past several years that are not pipeline connected to western Canada or Utah, which diversifies price and market risk.
Crescent Point also enters into physical delivery and derivative WTI price differential contracts which manage the spread between US$ WTI and various stream prices. The Corporation manages physical delivery contracts on a month-to-month spot and term contract basis. From January to December 2017, approximately 22,000 bbls/d of liquids production was contracted with fixed price differentials off WTI. As of December 31, 2017, approximately 13,600 bbls/d of liquids production for calendar 2018, 8,600 bbls/d of liquids production for calendar 2019, 5,000 bbls/d of oil production for calendar 2020 and 2021 and 2,000 bbls/d of oil production for calendar 2022 to 2028 was contracted with fixed priced differentials off WTI. By locking in the price differential on these volumes, we have been able to reduce our exposure to volatility in crude oil differentials.


- 14 -    

We also mitigate risk by having a well-diversified marketing portfolio for 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 and mitigated by Crescent Point's Risk Management Committee and is governed by a Board-approved Risk Management and Counterparty Credit Policy that is reviewed by the board of directors on no less than an annual basis. 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 100 purchasers and its financial hedging portfolio consists of 16 counterparties. The Corporation's portfolio of counterparty exposures is reviewed monthly and approved by the Chief Financial Officer and/or a Vice President, Finance and the Vice President, Marketing and Innovation. Counterparty exposures are also reviewed on a quarterly basis by both the Risk Management Committee and the Audit Committee.
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.
Our oil and natural gas volumes are sold in the U.S., Alberta, British Columbia, Manitoba and Saskatchewan. Approximately 77% of our liquids volumes are sold in Saskatchewan, 14% in the U.S., 7% in Alberta, 2% in Manitoba and less than 1% in British Columbia. Approximately 56% of our natural gas volumes are sold in Saskatchewan, 23% in the U.S., 21% in Alberta and less than 1% in Manitoba.
Revenue Sources
For 2017, our commodity production mix was approximately 90% oil and NGLs and 10% natural gas.
The following table summarizes our revenue sources by product before hedging and royalties:
For Year Ended
Crude Oil and NGLs
Natural Gas
2017
97%
3%
2016
97%
3%
2015
96%
4%


Competition
We actively compete for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial resources than we do. Our competitors include major integrated oil and natural gas companies, numerous other independent oil and natural gas entities and individual producers and operators.
Certain of our customers and potential customers are themselves exploring for oil and natural gas, and the results of such exploration efforts could affect our ability to sell or supply oil or gas to these customers in the future. Our ability to successfully bid on and acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers 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 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.


- 15 -    

Personnel
As of December 31, 2017, the Corporation had 1,085 full-time permanent employees: 462 employees at our head office in Calgary, 84 employees at our Denver office, 469 field employees in Canada and 70 field employees in the U.S.
Reorganizations
On June 30, 2015, the Corporation closed the Legacy Arrangement for total consideration of approximately $1.5 billion, comprised of 18,229,428 Crescent Point Common Shares, cash consideration of $19.4 million and assumed debt. The assets acquired under the Legacy Arrangement increased the Corporation’s position in southeast Saskatchewan.
On August 14, 2015, the Corporation closed the Coral Hill Arrangement, pursuant to which the Corporation acquired all of the remaining issued and outstanding shares of Coral Hill not already owned by the Corporation. Total consideration for the acquisition was $243.8 million, comprised of 4,283,680 Crescent Point Common Shares, assumed debt and the historical cost of Crescent Point’s previously held equity investment of $42.0 million. The Coral Hill Arrangement consolidated the Corporation’s position in the Swan Hills Beaverhill Lake resource play and provided the Corporation with full operatorship, control over pace of development and an increased position in the core of the play.
Voluntary Reclamation Fund
The Corporation has a voluntary reclamation fund to fund future decommissioning costs and environmental emissions reduction costs. From April 1, 2015 to December 31, 2015, the Corporation allocated $0.60 per boe of production. From January 1, 2017 to December 31, 2017, the Corporation allocated $0.35 per boe of production. Additional contributions can be made at the discretion of management.
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
Disclosure of Reserves Data
In accordance with NI 51-101, the reserves data of the Corporation set forth below (the "Reserves Data") is based upon evaluations by GLJ and Sproule with an effective date of December 31, 2017 contained in the consolidated report of GLJ dated February 15, 2018 (the "Crescent Point Reserve Report"). The Crescent Point Reserve Report evaluated, as at December 31, 2017, and summarizes our crude oil, NGL and natural gas reserves. The tables below are a combined summary of our crude oil, NGL and natural gas reserves and the net present value of future net revenue attributable to such reserves as evaluated in the Crescent Point Reserve Report based on Sproule’s December 31, 2017 forecast price and cost assumptions. GLJ evaluated approximately 46 percent of the assigned total Proved plus Probable reserves and 35 percent of the total Proved plus Probable value discounted at 10 percent. Sproule evaluated approximately 54 percent of the assigned total Proved plus Probable reserves and 65 percent of the total Proved plus Probable value discounted at 10 percent. Sproule evaluated a majority of our Canadian Williston basin assets including the Viewfield Bakken and Flat Lake Torquay properties in southeast Saskatchewan as well as southwest Saskatchewan assets including the Shaunavon and Saskatchewan Viking properties. Sproule evaluated their portion of the reserves using the Sproule forecast price and cost escalation assumptions. GLJ evaluated the Corporation’s Alberta, British Columbia and a portion of the Canadian Williston basin assets in southeast Saskatchewan and Manitoba. GLJ also performed the evaluation of the Corporation's U.S. assets in the Williston basin including properties in North Dakota and Montana, as well as assets in the Uinta basin in Utah. These assets were all evaluated using the Sproule forecast price and cost escalation assumptions. GLJ prepared the total Crescent Point Reserve Report by consolidating the GLJ Canadian and U.S. evaluated properties with the Sproule evaluation using the Sproule pricing and cost escalation assumptions. The tables summarize the data contained in the Crescent Point Reserve Report and, as a result, may contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly.


- 16 -    

The net present value of future net revenue attributable to our reserves is stated without provision for interest costs, and general and administrative costs, but after providing for estimated royalties, production costs, capital taxes, development costs, other income, future capital expenditures, projected carbon tax costs, and well and location abandonment costs for only those entities assigned reserves by GLJ and Sproule. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to our reserves estimated by GLJ and Sproule represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of our crude oil, NGL and natural 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 any legislative impact of greenhouse gas emissions regarding carbon pricing of our ongoing and future operations. We have adopted a strategy to reduce these impacts on the environment which will in turn minimize any potential financial impacts. Crescent Point has modelled financial impacts based on current carbon pricing levels as adopted in existing and proposed legislation, and reflected these within the reserves evaluation as of December 31, 2017 as an operating cost per unit volume of production. The Corporation has assessed these carbon pricing levels at provincial levels using the current models for British Columbia, Alberta and Manitoba. As legislation was not finalized as of December 31, 2017, it was assumed that Saskatchewan would fall under the current Federal program starting in January 2019. It is further anticipated that the ongoing efforts by Crescent Point to limit and reduce the Corporation’s greenhouse gas emissions on existing and future operations will result in reductions of overall costs into the future. As a result, the economic model capped these unit operating carbon pricing at various times into the future. The total impact of the carbon pricing in the reserve report as prepared by GLJ and Sproule, reflects a negative impact of 1,255.3 Mboe and $169.6 MM discounted at 10% before tax for total proved plus probable reserves.
The Crescent Point Reserve Report is based on certain factual data supplied by us as well as GLJ and Sproule's opinion of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to our petroleum properties and contracts (except for certain information residing in the public domain) were supplied by the Corporation to GLJ and Sproule, and were accepted without any further investigation. GLJ and Sproule accepted this data as presented and neither title searches nor field inspections were conducted.


- 17 -    

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
101,900

90,305

24,167

19,075

141,069

131,090

38,951

35,657

110,917

104,562

89,849

83,447

339,547

307,462

United States
1,043

852

—

—

38,179

31,663

5,073

4,149

56,277

47,297

293

271

53,724

44,592

Total
102,943

91,157

24,167

19,075

179,248

162,754

44,023

39,805

167,194

151,859

90,142

83,718

393,271

352,054

Proved Developed Non-Producing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
2,955

2,700

177

160

3,094

2,846

641

587

1,951

1,844

2,316

2,045

7,578

6,941

United States
6

5

—

—

869

716

115

94

3,050

2,495

3

2

1,499

1,231

Total
2,961

2,705

177

160

3,963

3,562

756

681

5,001

4,339

2,319

2,048

9,077

8,172

Proved Undeveloped
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
37,676

34,622

1,991

1,631

78,513

73,774

15,769

14,505

56,600

52,985

18,679

16,939

146,495

136,187

United States
—

—

—

—

61,974

50,579

8,542

6,939

71,464

58,370

—

—

82,426

67,246

Total
37,676

34,622

1,991

1,631

140,487

124,353

24,311

21,444

128,064

111,354

18,679

16,939

228,922

203,433

Total Proved
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
142,531

127,627

26,335

20,866

222,676

207,711

55,361

50,749

169,468

159,391

110,844

102,431

493,621

450,590

United States
1,049

857

—

—

101,023

82,959

13,729

11,182

130,791

108,162

296

273

137,649

113,070

Total
143,580

128,484

26,335

20,866

323,698

290,669

69,090

61,931

300,259

267,552

111,140

102,704

631,270

563,659

Total Probable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
79,797

71,492

7,237

5,753

129,610

119,133

29,298

26,664

87,940

82,071

54,593

49,384

269,698

244,952

United States
4,382

3,604

—

—

74,641

61,076

9,741

7,918

87,083

71,398

102

93

103,295

84,514

Total
84,179

75,096

7,237

5,753

204,252

180,209

39,039

34,583

175,023

153,469

54,695

49,477

372,993

329,466

Total Proved Plus Probable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
222,328

199,120

33,571

26,619

352,286

326,843

84,659

77,413

257,408

241,461

165,437

151,815

763,318

695,542

United States
5,431

4,461

—

—

175,664

144,035

23,470

19,100

217,873

179,560

397

366

240,944

197,583

Total
227,759

203,580

33,571

26,619

527,950

470,878

108,129

96,514

475,281

421,021

165,834

152,181

1,004,262

893,125

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



- 18 -    

Net Present Value of Future Net Revenue of Oil and Gas Reserves(1) 
 
Before Income Taxes Discounted at
(%/year)
 
 
After Income Taxes Discounted at
(%/year)
Reserves Category
0%
(MM$)
5%
(MM$)
8%
(MM$)
10%
(MM$)
15%
(MM$)
20%
(MM$)
 
0%
(MM$)
5%
(MM$)
8%
(MM$)
10%
(MM$)
15%
(MM$)
20%
(MM$)
Proved Developed Producing
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
11,270

8,364

7,269

6,696

5,617

4,864

 
10,555

7,957

6,969

6,447

5,458

4,758

United States
1,569

1,217

1,074

997

849

744

 
1,528

1,190

1,053

979

836

734

Total
12,839

9,581

8,343

7,693

6,467

5,609

 
12,083

9,147

8,021

7,426

6,294

5,492

Proved Developed Non-Producing
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
223

176

155

143

120

104

 
162

132

119

111

97

86

United States
33

25

22

20

16

14

 
31

24

21

19

16

13

Total
256

200

176

163

137

117

 
194

156

139

130

112

99

Proved Undeveloped
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
3,792

2,592

2,091

1,821

1,307

949

 
2,753

1,842

1,463

1,259

871

603

United States
1,552

848

593

464

239

98

 
1,299

715

498

388

192

68

Total
5,344

3,441

2,684

2,286

1,545

1,047

 
4,052

2,557

1,961

1,647

1,064

672

Total Proved
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
15,286

11,132

9,515

8,660

7,044

5,917

 
13,470

9,931

8,550

7,818

6,426

5,447

United States
3,153

2,090

1,688

1,481

1,104

856

 
2,858

1,929

1,571

1,386

1,044

816

Total
18,439

13,222

11,203

10,141

8,149

6,773

 
16,328

11,860

10,122

9,203

7,470

6,262

Total Probable
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
10,821

6,248

4,847

4,180

3,046

2,344

 
7,868

4,522

3,492

3,001

2,168

1,655

United States
3,416

1,847

1,377

1,158

797

582

 
2,571

1,389

1,037

873

604

444

Total
14,237

8,095

6,224

5,338

3,843

2,926

 
10,439

5,911

4,528

3,874

2,773

2,100

Total Proved Plus Probable
 
 
 
 
 
 
 
 
 
 
 
 
 
Canada
26,107

17,379

14,362

12,840

10,091

8,261

 
21,338

14,453

12,042

10,819

8,594

7,102

United States
6,569

3,937

3,065

2,639

1,901

1,438

 
5,429

3,318

2,608

2,259

1,648

1,260

Total
32,676

21,317

17,427

15,479

11,992

9,699

 
26,767

17,771

14,650

13,078

10,243

8,362

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


Additional Information Concerning Future Net Revenue – (Undiscounted)(1) 
Reserves Category
Revenue
(MM$)
Royalties & Burdens(2)
(MM$)
Operating
Costs
(MM$)
Development
Costs
(MM$)
Abandonment and Reclamation
Costs
(MM$)
Future Net
Revenue Before
Income Taxes
(MM$)
Income Tax
(MM$)
Future Net
Revenue After
Income Taxes
(MM$)
Proved
 
 
 
 
 
 
 
 
Canada
36,039

3,941

13,159

2,773

880

15,286

1,816

13,470

United States
9,944

2,304

2,789

1,578

120

3,153

296

2,858

Total
45,983

6,245

15,948

4,351

1,000

18,439

2,111

16,328

Proved Plus Probable
 
 
 
 
 
 
 
 
Canada
58,709

6,475

20,521

4,499

1,107

26,107

4,769

21,338

United States
18,613

4,358

5,109

2,409

169

6,569

1,141

5,429

Total
77,322

10,833

25,630

6,908

1,275

32,676

5,909

26,767

Notes:
(1)
Numbers may not add due to rounding.
(2)
Saskatchewan Capital Resource Surcharge in Canada and Ad Valorem and Severance payable in the United States have been included under the royalties and burdens column.




- 19 -    

Future Net Revenue by Production Type(6) 
 
Future Net Revenue
Before Income Taxes(5)
(Discounted at 10% per year)
Percentage
Unit Value
 
(MM$)
(%)
($/boe)
($/Mcfe)
Proved
 
 
 
 
CANADA
 
 
 
 
Light and Medium Crude Oil(1)
2,641

30.5

$18.39
$3.06
Heavy Crude Oil(1)
331

3.8

$15.73
$2.62
Tight Oil(3)
5,584

64.5

$20.53
$3.42
Natural Gas Liquids
—

—

—

—

Shale Gas(4)
—

—

—

—

Conventional Natural Gas(2)
103

1.2

$7.45
$1.24
Total Canada
8,660

100.0

$19.22
$3.20
UNITED STATES
 
 
 
 
Light and Medium Crude Oil(1)
13

0.9

$15.01
$2.50
Heavy Crude Oil(1)
—

—

—

—

Tight Oil(3)
1,460

98.6

$13.17
$2.20
Natural Gas Liquids
—

—

—

—

Shale Gas(2)
8

0.5

$6.08
$1.01
Conventional Natural Gas(2)
<1

<0.1

$3.79
$0.63
Total United States
1,481

100.0

$13.10
$2.18
TOTAL
 
 
 
 
Light and Medium Crude Oil(1)
2,654

26.2

$18.37
$3.06
Heavy Crude Oil(1)
331

3.3

$15.73
$2.62
Tight Oil(3)
7,044

69.5

$18.40
$3.07
Natural Gas Liquids
—

—

—

—

Shale Gas(2)(4)
8

<0.1

$6.08
$1.01
Conventional Natural Gas(2)
104

1.0

$7.44
$1.24
Total Proved
10,141

100.0

$17.99
$3.00
Notes:
(1)
Including solution gas and other by-products.
(2)
Including by-products, but excluding solution gas.
(3)
Including solution gas (categorized as “Shale Gas”) and other by-products.
(4)
Volumes of Shale Natural Gas have been included in “Tight Oil” as it is solution gas relating to oil production.
(5)
Other company revenue and costs not related to a specific production type have been allocated proportionately to production types. Unit values are based on Company Net Reserves.
(6)
Numbers may not add due to rounding.



- 20 -    

 
Future Net Revenue
Before Income Taxes(5)
(Discounted at 10% per year)
Percentage
Unit Value
 
(MM$)
(%)
($/boe)
($/Mcfe)
Proved Plus Probable
 
 
 
 
CANADA
 
 
 
 
Light and Medium Crude Oil(1)
3,973

30.9

$17.44
$2.91
Heavy Crude Oil(1)
394

3.1

$14.68
$2.45
Tight Oil(3)
8,355

65.1

$19.72
$3.29
Natural Gas Liquids
—

—

—

—

Shale Gas(4)
—

—

—

—

Conventional Natural Gas(2)
118

0.9

$6.87
$1.14
Total Canada
12,840

100.0

$18.46
$3.08
UNITED STATES
 
 
 
 
Light and Medium Crude Oil(1)
25

0.9

$5.58
$0.93
Heavy Crude Oil(1)
—

—

—

—

Tight Oil(3)
2,604

98.7

$13.60
$2.27
Natural Gas Liquids
—

—

—

—

Shale Gas(2)
9

0.4

$5.83
$0.97
Conventional Natural Gas(2)
<1

<0.1

$3.71
$0.62
Total United States
2,639

100.0

$13.36
$2.23
TOTAL
 
 
 
 
Light and Medium Crude Oil(1)
3,998

25.8

$17.21
$2.87
Heavy Crude Oil(1)
394

2.5

$14.68
$2.45
Tight Oil(3)
10,959

70.8

$17.82
$2.97
Natural Gas Liquids
—

—

—

—

Shale Gas(2)(4)
9

0.1

$5.83
$0.97
Conventional Natural Gas(2)
118

0.8

$6.86
$1.14
Total Proved Plus Probable
15,479

100.0

$17.33
$2.89
Notes:
(1)
Including solution gas and other by-products.
(2)
Including by-products, but excluding solution gas.
(3)
Including solution gas (categorized as “Shale Gas”) and other by-products.
(4)
Volumes of Shale Natural Gas have been included in “Tight Oil” as it is solution gas relating to oil production.
(5)
Other company revenue and costs not related to a specific production type have been allocated proportionately to production types. Unit values are based on Company Net Reserves.
(6)
Numbers may not add due to rounding.


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


- 21 -    

(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.
(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.


- 22 -    

(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" 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".


- 23 -    

(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.
(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.


- 24 -    

(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".
(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 reclaiming the site to original conditions. They do not include costs of abandoning the gathering system.


- 25 -    

Pricing Assumptions – Forecast Prices and Costs
GLJ and Sproule employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2017 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
 
 
 
 
 
 
 
 
 
 
2018
3.25
2.85
55.00
65.44
67.72
48.73
26.06
0.0%
0.0%
0.790
2019
3.50
3.11
65.00
74.51
75.61
55.49
32.84
2.0%
2.0%
0.820
2020
4.00
3.65
70.00
78.24
78.82
57.65
35.41
2.0%
2.0%
0.850
2021
4.08
3.80
73.00
82.45
82.35
60.12
37.85
2.0%
2.0%
0.850
2022
4.16
3.95
74.46
84.10
84.07
61.32
39.29
2.0%
2.0%
0.850
2023
4.24
4.05
75.95
85.78
85.82
62.55
40.25
2.0%
2.0%
0.850
2024
4.33
4.15
77.47
87.49
87.61
63.80
41.23
2.0%
2.0%
0.850
2025
4.42
4.25
79.02
89.24
89.43
65.07
42.23
2.0%
2.0%
0.850
2026
4.50
4.36
80.60
91.03
91.29
66.37
43.26
2.0%
2.0%
0.850
2027
4.59
4.46
82.21
92.85
93.19
67.70
44.30
2.0%
2.0%
0.850
2028
4.69
4.57
83.85
94.71
95.12
69.06
45.36
2.0%
2.0%
0.850
2029+
+2%/yr
+2%/yr
+2%/yr
+2%/yr
+2%/yr
+2%/yr
+2%/yr
2.0%
2.0%
0.850

For the year ended December 31, 2017, the average realized sales prices before hedging were $58.65/bbl for light and medium crude oil, $51.02/bbl for heavy crude oil, $59.68/bbl for tight crude oil, $27.82/bbl for NGLs, $2.68/mcf for shale gas and $2.42/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, 2017 against such reserves as at December 31, 2016 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, 2016
158,179

94,499

252,677

22,816

7,329

30,145

221,705

130,906

352,611

46,665

25,288

71,952

Discoveries
—

—

—

—

—

—

—

—

—

—

—

—

Extensions and Improved Recovery (2)
6,345

3,395

9,740

132

(132
)
1

22,938

14,687

37,624

4,951

2,779

7,730

Technical Revisions (3)
6,226

(14,870
)
(8,644
)
5,136

75

5,211

2,177

(16,367
)
(14,190
)
9,212

497

9,709

Acquisitions (8)
585

1,436

2,020

42

8

51

1,045

396

1,440

434

752

1,186

Dispositions (6)
(12,810
)
(5,423
)
(18,233
)
(21
)
(63
)
(84
)
(273
)
(357
)
(630
)
(108
)
(103
)
(211
)
Economic Factors
387

759

1,146

30

19

50

520

347

866

41

85

127

Production
(16,380
)
—

(16,380
)
(1,801
)
—

(1,801
)
(25,435
)
—

(25,435
)
(5,834
)
—

(5,834
)
December 31, 2017
142,531

79,797

222,328

26,335

7,237

33,571

222,676

129,610

352,286

55,361

29,298

84,659




- 26 -    

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, 2016
147,009

78,289

225,299

127,092

67,368

194,460

495,048

282,297

777,345

Discoveries
—

—

—

—

—

—

—

—

—

Extensions and Improved Recovery (2)
16,118

8,493

24,612

859

1,399

2,257

37,196

22,378

59,574

Technical Revisions (3)
24,266

1,384

25,651

(3,506
)
(16,512
)
(20,018
)
26,210

(33,186
)
(6,976
)
Acquisitions (8)
904

339

1,243

437

1,477

1,914

2,329

2,895

5,224

Dispositions (6)
(459
)
(701
)
(1,160
)
(936
)
(579
)
(1,515
)
(13,444
)
(6,160
)
(19,604
)
Economic Factors
324

135

459

(2,002
)
1,441

(562
)
699

1,473

2,172

Production
(18,695
)
—

(18,695
)
(11,100
)
—

(11,100
)
(54,416
)
—

(54,416
)
December 31, 2017
169,468

87,940

257,408

110,844

54,593

165,437

493,621

269,698

763,318


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, 2016
1,119

5,535

6,654

—

—

—

76,822

53,908

130,730

10,434

6,426

16,860

Discoveries
—

—

—

—

—

—

—

—

—

—

—

—

Extensions and Improved Recovery (7)
—

—

—

—

—

—

16,384

17,299

33,683

1,550

2,300

3,850

Technical Revisions
796

388

1,184

—

—

—

2,068

(3,488
)
(1,420
)
929

65

995

Acquisitions (8)
—

—

—

—

—

—

14,615

5,681

20,295

1,870

813

2,683

Dispositions (6) (9)
(526
)
(159
)
(685
)
—

—

—

(125
)
(143
)
(267
)
(99
)
(48
)
(148
)
Economic Factors
(29
)
(1,382
)
(1,411
)
—

—

—

(1,570
)
1,384

(186
)
(127
)
184

57

Production
(311
)
-

(311
)
—

—

—

(7,171
)
—

(7,171
)
(827
)
—

(827
)
December 31, 2017
1,049

4,382

5,431

—

—

—

101,023

74,641

175,664

13,729

9,741

23,470


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, 2016
100,492

60,664

161,156

169

73

242

105,151

75,992

181,144

Discoveries
—

—

—

—

—

—

—

—

—

Extensions and Improved Recovery (7)
14,573

17,018

31,592

—

—

—

20,363

22,436

42,799

Technical Revisions
4,946

(1,993
)
2,953

2,222

208

2,430

4,988

(3,331
)
1,656

Acquisitions (8)
21,237

9,200

30,437

—

—

—

20,024

8,027

28,051

Dispositions (6) (9)
(77
)
(105
)
(182
)
(664
)
(202
)
(865
)
(873
)
(401
)
(1,274
)
Economic Factors
(2,678
)
2,298

(380
)
(20
)
22

2

(2,176
)
573

(1,603
)
Production
(7,703
)
—

(7,703
)
(1,411
)
—

(1,411
)
(9,829
)
—

(9,829
)
December 31, 2017
130,791

87,083

217,873

296

102

397

137,649

103,295

240,944




- 27 -    

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, 2016
159,298

100,034

259,331

22,816

7,329

30,145

298,527

184,814

483,341

57,099

31,714

88,813

Discoveries
—

—

—

—

—

—

—

—

—

—

—

—

Extensions and Improved Recovery (2) (7)
6,345

3,395

9,740

132

(132
)
1

39,322

31,986

71,307

6,501

5,080

11,581

Technical Revisions (3)
7,021

(14,481
)
(7,460
)
5,136

75

5,211

4,245

(19,855
)
(15,610
)
10,141

562

10,703

Acquisitions (8)
585

1,436

2,020

42

8

51

15,659

6,077

21,736

2,304

1,565

3,869

Dispositions (6) (9)
(13,335
)
(5,582
)
(18,917
)
(21
)
(63
)
(84
)
(398
)
(500
)
(898
)
(207
)
(152
)
(359
)
Economic Factors
358

(623
)
(265
)
30

19

50

(1,050
)
1,731

680

(86
)
269

184

Production
(16,691
)
—

(16,691
)
(1,801
)
—

(1,801
)
(32,607
)
—

(32,607
)
(6,661
)
—

(6,661
)
December 31, 2017
143,580

84,179

227,759

26,335

7,237

33,571

323,698

204,252

527,950

69,090

39,039

108,129


TOTAL
Shale Gas (5)
(Natural Gas) (MMcf)
Conventional Natural Gas (5)
(Natural Gas) (MMcf)
Total BOE
(Mboe)
Factors
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
Proved
Probable
Proved
+
Probable
December 31, 2016
247,501

138,953

386,455

127,261

67,441

194,702

600,199

358,289

958,489

Discoveries
—

—

—

—

—

—

—

—

—

Extensions and Improved Recovery (2) (7)
30,692

25,512

56,203

859

1,399

2,257

57,559

44,814

102,373

Technical Revisions (3)
29,212

(608
)
28,604

(1,284
)
(16,304
)
(17,588
)
31,198

(36,517
)
(5,320
)
Acquisitions (8)
22,142

9,539

31,681

437

1,477

1,914

22,352

10,922

33,275

Dispositions (6) (9)
(536
)
(806
)
(1,342
)
(1,600
)
(781
)
(2,380
)
(14,317
)
(6,561
)
(20,878
)
Economic Factors
(2,354
)
2,433

79

(2,022
)
1,463

(560
)
(1,477
)
2,046

569

Production
(26,398
)
—

(26,398
)
(12,511
)
—

(12,511
)
(64,245
)
—

(64,245
)
December 31, 2017
300,259

175,023

475,281

111,140

54,695

165,834

631,270

372,993

1,004,262

Notes:
(1)
Numbers may not add due to rounding.
(2)
The Corporation’s development strategy in 2017 included both step-out and in-pool development drilling, mostly in the Bakken and Torquay resource plays in the Williston Basin; as well as the Upper and Lower Shaunavon resource plays in southwest Saskatchewan. These activities represented the majority of capital expenditures during the year. A portion of this growth also relates to Improved Recovery volumes being recognized by the qualified reserve evaluators due to ongoing waterflood activities.
(3)
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.
(4)
Negative Tight Oil Technical Revisions on total proved plus probable reserves were recorded mostly in the Bakken and Torquay resource plays in the Williston Basin due to certain wells modestly underperforming the prior years’ forecast, representing 1.8% of total Proved plus Probable Canadian reserves at December 31, 2016.
(5)
Both Shale Gas and Natural Gas Liquids saw increases due to the qualified reserve evaluators recognizing increased gas volumes in their forecasts mostly in the Bakken and Torquay resource plays in the Williston Basin.
(6)
Miscellaneous non-core dispositions were completed including conventional assets in the Williston Basin and minor assets in Southwest Saskatchewan.
(7)
The Corporation’s development strategy in 2017 included both step-out and in-pool development drilling, mostly in the Bakken and Three Forks resource plays in the Williston Basin; as well as a focus on horizontal well development of the Uinta Basin.
(8)
Crescent Point completed multiple acquisitions in the Williston Basin and the Uinta Basin that included both top-up and areal expansion acquisitions that will support future organic growth.
(9)
The Corporation disposed of all its assets in the DJ Basin of Colorado.


Undeveloped Reserves
The following discussion generally describes the basis on which we attribute Proved and Probable undeveloped reserves. Our near-term plans for developing our undeveloped reserves are described in the section "Major Oil and Gas Properties".
Proved Undeveloped Reserves
Proved Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. These reserves represent a high degree of certainty to be recoverable, and may relate to planned infill drilling, lease-line as well as offset locations to current producing entities.


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The Corporation has extensive Proved development opportunities that are prioritized based on a disciplined set of criteria including, but not limited to time for payout, rate of return, maturity of land tenure, reserve booking opportunities, proximity to transportation and marketing, as well as anticipated production rates. With this extensive portfolio of opportunities, it would be unrealistic both from a cash flow as well as physical ability, to completely execute on the entire portfolio of booked opportunities within two years.
The development of these reserves have been based on recent and current capital activity levels, with no material deferrals of development opportunities beyond these normal budgetary constraints. The majority of these reserves are planned to be on stream within a three year timeframe, which represents approximately 80% of the net undeveloped location count, as well as 80% of the net total future development capital.
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
2015
8,793

45,641

—

2,104

11,854

129,664

2,590

18,740

13,891

91,605

7,949

27,061

26,877

215,926

2016
3,164

43,998

—

2,006

9,944

132,529

1,406

19,813

5,535

108,708

1,866

24,915

15,748

220,617

2017
1,745

37,676

—

1,991

24,359

140,487

3,968

24,311

18,569

128,064

118

18,679

33,187

228,922

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-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 timeframe, representing approximately 72% of the net undeveloped location count, as well as 73% of the total net future development costs. Other than for normal budgetary constraints, the Corporation has no plans to defer development of probable undeveloped reserves. 
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