EX-99.1 2 e611720_ex99-1.htm Unassociated Document
 
Exhibit 99.1
 


 
CRESCENT POINT ENERGY CORP.
 
ANNUAL INFORMATION FORM
 
For the Year Ended December 31, 2012
 
Dated March 13, 2013
 
 
 

 
 
TABLE OF CONTENTS
 
NOTE REGARDING FORWARD-LOOKING STATEMENTS
1
   
GLOSSARY
3
   
SELECTED ABBREVIATIONS
5
   
CURRENCY OF INFORMATION
6
   
OUR ORGANIZATIONAL STRUCTURE
6
   
GENERAL DEVELOPMENT OF THE BUSINESS OF THE CORPORATION
8
   
DESCRIPTION OF OUR BUSINESS
11
   
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
16
   
ADDITIONAL INFORMATION RESPECTING CRESCENT POINT
37
   
INDUSTRY CONDITIONS
45
   
RISK FACTORS
58
   
DIVIDENDS
67
   
MARKET FOR SECURITIES
68
   
CONFLICTS OF INTEREST
68
   
LEGAL PROCEEDINGS
68
   
AUDIT COMMITTEE
69
   
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
71
   
TRANSFER AGENT AND REGISTRARS
71
   
MATERIAL CONTRACTS
71
   
INTERESTS OF EXPERTS
71
   
ADDITIONAL INFORMATION
71
 
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
 
 
 

 
 
NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
This annual information form, the documents incorporated by reference herein, and other reports and filings made with the securities regulatory authorities include forward-looking statements. All forward-looking statements are based on our beliefs and assumptions based on information available at the time the assumption was made. The use of any of the words "could", "should", "can", "anticipate", "expect", "believe", "will", "may", "projected", "sustain", "continues", "strategy", "potential", "projects", "grow", "take advantage", "estimate", "well-positioned" and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Crescent Point (as defined herein) believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. These statements speak only as of the date of this AIF or, if applicable, as of the date specified in this AIF.
 
In particular, this annual information form contains forward-looking statements pertaining, among other things, to the following:
 
anticipated financial performance;
• 
business prospects;
the performance characteristics of Crescent Point's oil and natural gas properties, including but not limited to oil and natural gas production levels;
capital expenditure programs;
drilling programs;
the quantity of the oil and natural gas reserves;
• 
projections of commodity prices and costs;
our future waterflood programs;
future downspacing;
expected decommissioning, abandonment, remediation and reclamation costs;
our tax horizon;
expected trends in environmental regulation;
payment of monthly dividends;
supply and demand for oil and natural gas;
expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; and
treatment under governmental regulatory regimes.
 
By its nature, such forward-looking information is subject to various risks, uncertainties and other factors, including those material risks discussed in the AIF (as defined herein) under "Risk Factors" and in the MD&A (as defined herein) under "Risk Factors" and "Forward-Looking Information", which could cause our actual results and experience to differ materially from the anticipated results or other expectations expressed. The material assumptions in making these forward-looking statements are disclosed in the MD&A under the headings "Dividends", "Capital Expenditures", "Decommissioning Liability", "Liquidity and Capital Resources", "Critical Accounting Estimates", "Future Changes in Accounting Policies" and "Outlook".
 
This disclosure contains certain forward-looking estimates that involve substantial known and unknown risks and uncertainties, certain of which are beyond Crescent Point's control, including, but not limited to: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas; delays in business operations, pipeline restrictions, blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; risks and uncertainties related to oil and gas interests and operations on tribal lands; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; fluctuations in foreign exchange and interest rates; stock market volatility; failure to realize the anticipated benefits of acquisitions; general economic, market and business conditions; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry.
 
 
 

 
 
Statements relating to "reserves" and "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves and/or resources described can be profitably produced in the future.
 
There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only. In general, estimates of economically recoverable crude oil, natural gas and natural gas liquids reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For these reasons, estimates of the economically recoverable crude oil, natural gas liquids and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. Crescent Point's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. In addition, the discounted and undiscounted net present value of future net revenues attributable to reserves do not represent fair market value; and the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Therefore, Crescent Point's actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking estimates and if such actual results, performance or achievements transpire or occur, or if any of them do so, there can be no certainty as to what benefits Crescent Point will derive therefrom.
 
Any financial outlook or future oriented financial information, as defined by applicable securities legislation, in this AIF has been approved by management of Crescent Point. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes. Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
 
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for the year.
 
Readers are cautioned not to place undue reliance on the forward-looking information, which is given as of the date it is expressed in this AIF or otherwise. We do not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required pursuant to applicable securities laws.
 
 
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GLOSSARY
 
In this annual information form, the capitalized terms set forth below have the following meanings:
 
"ABCA" means the Business Corporations Act, R.S.A. 2000, c. B-9, as amended, including the regulations promulgated thereunder.
 
"AIF" means this annual information form of the Corporation dated March 13, 2013 for the year ended December 31, 2012.
 
"Alston" means Alston Energy Inc.
 
"Canadian GAAP" means Canadian generally accepted accounting principles as contemplated by the Handbook of the Canadian Institute of Chartered Accountants, applied on a consistent basis, which incorporates IFRS.
 
"Common Shares" means common shares in the capital of the Corporation.
 
"Conversion Arrangement" means the plan of arrangement effected on July 2, 2009 under section 193 of the ABCA pursuant to which the Trust effectively converted from an income trust to a corporate structure.
 
"CPEUS" means Crescent Point Energy U.S. Corp.
 
"CPHI" means Crescent Point Holdings Inc., a corporation incorporated under the ABCA.
 
"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.
 
"Cutpick" means Cutpick Energy Inc.
 
"Cutpick Arrangement" means the plan of arrangement under Section 193 of the ABCA involving Cutpick and the Corporation, completed on June 20, 2012, as more particularly described under the heading "General Development of the Business of the Corporation – History – 2012".
 
"DRIP" means the Premium Dividend and Dividend Reinvestment Plan of the Corporation.
 
"DSU Plan" means a deferred share unit plan for eligible participants including non-employee directors.
 
"GLJ" means GLJ Petroleum Consultants Ltd.
 
"Greenhouse Gases" or "GHGs" means any or all of carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulphur hexafluoride (SF6).
 
"IFRS" means International Financial Reporting Standards as adopted by the Canadian Accounting Standards Board for periods beginning on and after January 1, 2011;
 
"MD&A" means the management's discussion and analysis of financial condition and results of operations of the Corporation for the year ended December 31, 2012.
 
"NI 51-101" means "National Instrument 51-101 – Standards for Disclosure for Oil and Gas Activities".
 
"OPEC" means Organization of the Petroleum Exporting Countries.
 
 
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"Painted Pony" means Painted Pony Petroleum Ltd.
 
"Partnership" means Crescent Point Resources Partnership, a general partnership formed under the laws of the Province of Alberta, having CPHI and the Corporation as partners.
 
"Reliable" means Reliable Energy Ltd.
 
"Reliable Arrangement" means the plan of arrangement under Section 193 of the ABCA involving Reliable and the Corporation, completed on May 1, 2012, as more particularly described under the heading "General Development of the Business of the Corporation – History – 2012".
 
"Restricted Share Bonus Plan" means an incentive bonus compensation plan for eligible participants including directors, officers, employees and consultants of the Corporation and its affiliates.
 
"Ryland" means Ryland Oil Corporation.
 
"Ryland Arrangement" means the plan of arrangement under Section 193 of the ABCA involving the Corporation, the Partnership, Ryland, Ryland Oil ULC, Pebble Petroleum Inc. and the Ryland Oil shareholders completed on August 20, 2010, as more particularly described under the heading "General Development of the Business of the Corporation – History – 2010".
 
"Shareholders" means the holders from time to time of Common Shares.
 
"Shelter Bay" means Shelter Bay Energy Inc., a corporation incorporated pursuant to the ABCA.
 
"Shelter Bay Arrangement" means the plan of arrangement under Section 193 of the ABCA involving the Corporation and Shelter Bay completed on July 2, 2010, as more particularly described under the heading "General Development of the Business of the Corporation – History – 2010".
 
"Sproule" means Sproule Associates Limited.
 
"Trust" means Crescent Point Energy Trust, an unincorporated open ended investment trust governed by the laws of the Province of Alberta that was dissolved pursuant to the Conversion Arrangement.
 
"Trust Units" means the trust units of the Trust.
 
"TSX" means the Toronto Stock Exchange.
 
"Unitholders" means holders of Trust Units.
 
"U.S." means the United States of America.
 
"Ute" means Ute Energy Upstream Holdings LLC, a limited liability company organized under the laws of the State of Delaware and amalgamated with CPEUS on November 29, 2012.
 
"Ute Assets" means the assets of CPEUS owned by Ute prior to its amalgamation with CPEUS.
 
"Wild Stream" means Wild Stream Exploration Ltd.
 
"Wild Stream Arrangement" means the plan of arrangement under Section 193 of the ABCA involving Wild Stream and the Corporation, completed on March 15, 2012, as more particularly described under the heading "General Development of the Business of the Corporation – History – 2012".
 
In this AIF, references to "dollars" and "$" are to the currency of Canada, unless otherwise indicated.
 
 
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SELECTED ABBREVIATIONS
 
In this AIF, the abbreviations set forth below have the following meanings:
 
Oil and Natural Gas Liquids
Natural Gas
bbl
barrel
Mcf
thousand cubic feet
bbls
barrels
Mcf/d
thousand cubic feet per day
bbl/d
barrels per day
Mcfe
thousand cubic feet of gas equivalent converting one barrel of oil to 6 Mcf of natural gas equivalent
Mbbls
thousand barrels
MMcf
MMcf/d
million cubic feet
million cubic feet per day
NGLs
natural gas liquids
MMBTU
million British Thermal Units
   
GJ
gigajoule
 
Other
   
AECO
API
the natural gas storage facility located at Suffield, Alberta
American Petroleum Institute
 
API
an indication of the specific gravity of crude oil measured on the API gravity scale. Liquid petroleum with a specified gravity of 28° API or higher is generally referred to as light crude oil
 
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
m³
m3/d
barrel of oil equivalent per day
cubic metres
cubic metres per day
 
M$
thousand dollars
 
Mboe
thousand barrels of oil equivalent
 
MMboe
MW
MW/h
million barrels of oil equivalent
mega watt
mega watt per hour
 
WTI
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade
 
 
 
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CURRENCY OF INFORMATION
 
The information set out in this AIF is stated as at December 31, 2012 unless otherwise indicated. Capitalized terms used but not defined in the text are defined in the Glossary.
 
OUR ORGANIZATIONAL STRUCTURE
 
The Corporation
 
Crescent Point Energy Corp. (the "Corporation" and, together with its direct and indirect subsidiaries and partnerships, where appropriate, "we", "our" or "us") is the successor to the Trust, following the completion of the "conversion" of the Trust from an income trust to a corporate structure by way of a court-approved plan of arrangement under the ABCA on July 2, 2009. Pursuant to the Conversion Arrangement, on July 2, 2009, Unitholders of the Trust exchanged their Trust Units for Common Shares of the Corporation on a one-for-one basis.
 
The Corporation was originally incorporated pursuant to the provisions of the Company Act (British Columbia) on April 20, 1994 as 471253 British Columbia Ltd. 471253 British Columbia Ltd. changed its name to Westport Research Inc. ("Westport") on August 12, 1994. On August 1, 2006, Westport was continued into Alberta under the ABCA. On October 11, 2006, Westport changed its name to 1259126 Alberta Ltd. ("1259126"). On February 8, 2007, 1259126 amended its articles to change its name to Wild River Resources Ltd. ("Wild River"), to add a class of non-voting common shares, to change the number of authorized Common Shares from 1,000,000 to unlimited and to change the rights, privileges, restrictions and conditions attaching to such shares, to reorganize its share structure, to change the number of Wild River's issued and outstanding shares on a pro rata basis to an aggregate of 5,000,000 Common Shares, to remove the restrictions on share transfer and to amend the "other provisions" section of the articles. On June 29, 2009, Wild River amended its articles to cancel the non-voting common shares and to change the rights, privileges, restrictions and conditions of the Common Shares to remove the references to the non-voting common shares. On July 2, 2009, in connection with the Conversion Arrangement, Wild River filed Articles of Amendment to give effect to the consolidation of the Common Shares on the basis of 0.1512 of a post-consolidation Common Share for each pre-consolidation Common Share and subsequent Articles of Amendment to change its name to Crescent Point Energy Corp. On January 1, 2011, the Corporation amalgamated with Ryland Oil ULC, Darian Resources Ltd. and Shelter Bay Energy ULC.
 
The head and principal office of the Corporation is located at Suite 2800, 111 – 5th Avenue S.W., Calgary, Alberta, T2P 3Y6 and its registered office is located at Suite 3700, 400 – 3rd Avenue S.W., Calgary, Alberta, T2P 4H2.
 
The Corporation is a conventional oil and gas producer with assets strategically focused in properties comprised of high quality, long life, operated, light and medium oil and natural gas reserves in Western Canada and the United States. In addition, we continually review and assess numerous corporate and asset acquisition opportunities as part of our ongoing acquisition program.
 
We make monthly cash dividends to Shareholders from our net cash flow. Our primary source of cash flow is distributions from the Partnership.
 
Partnership
 
The Partnership is a general partnership governed by the laws of the Province of Alberta. As set forth in the diagram below under "Organizational Structure of the Corporation", the partners of the Partnership are CPHI and the Corporation.
 
The existing business of the Corporation is carried on through the Partnership and through CPEUS. The Partnership holds all of the Corporation's Canadian operating assets and CPEUS holds all of our U.S. operating assets.
 
 
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CPHI
 
CPHI is a wholly-owned subsidiary of the Corporation. CPHI is a partner of the Partnership.
 
CPLux
 
CPLux is a wholly-owned indirect subsidiary of the Corporation.
 
CPUSH
 
Crescent Point U.S. Holdings Corp. is a wholly-owned direct subsidiary of the Corporation.
 
CPEUS
 
Crescent Point Energy U.S. Corp. is a wholly-owned indirect subsidiary of the Corporation. CPEUS holds the Corporation's operating assets in the United States, including, but not limited to, the Ute Assets.
 
Relationships
 
The following table provides the name, the percentage of voting securities owned by the Corporation and the jurisdiction of incorporation, continuance or formation of the Corporation's material subsidiaries as at the date hereof.
 
 
Percentage of Voting Securities (Directly or Indirectly)
 
Jurisdiction of Incorporation/Formation
       
CPHI
100%
 
Alberta
       
Partnership
100%
 
Alberta
       
CPUSH
100%
 
Nevada
       
CPEUS
100%
 
Delaware
       
CPLux
100%
 
Luxembourg
 
 
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Organizational Structure of the Corporation
 
The following diagram describes the intercorporate relationships among the Corporation and its material direct and indirect subsidiaries described above as at March 13, 2013. Reference should be made to the appropriate sections of this AIF for a complete description of the structure of the Corporation.
 
 
GENERAL DEVELOPMENT OF THE BUSINESS OF THE CORPORATION
 
History
 
The following is a description of the general development of the business of Crescent Point over the past three years.
 
2010
 
On January 15, 2010, the Corporation closed the acquisition of certain assets in southwest Saskatchewan from Penn West Energy Trust. The consideration was comprised of Crescent Point's 100 percent working interest in the Pembina Cardium play, a 50 percent working interest in Crescent Point's Dodsland Viking play and $434 million cash.
 
On March 24, 2010, the Corporation closed an offering of senior unsecured notes in the United States and Canada on a private placement basis with an aggregate principal amount of US$260 million and $50 million. The terms of the U.S. notes range from 5 to 10 years with a weighted average term of 8.5 years and coupon rates ranging from 4.71% to 6.03% and the Canadian notes have a term of 5 years with a coupon rate of 4.92%.
 
On June 2, 2010, the Corporation announced the closing of its equity offering of 9,150,000 Common Shares at $41.00 per Common Share for aggregate gross proceeds of approximately $375.2 million.
 
On June 10, 2010, the terms of the Corporation's $1.5 billion Syndicated Credit Facility (as defined in "Credit Facilities" herein) were changed to a revolving credit facility with a 3 year term which is extendible annually for a 1, 2 or 3 year period.
 
On July 2, 2010, the Corporation closed the Shelter Bay Arrangement for total consideration of approximately $1.2 billion, comprised of 24,397,586 Common Shares and assumed debt. See "Description of Our Business – Reorganizations".
 
On July 2, 2010, the Corporation announced it had acquired ownership of 13.3% of the issued and outstanding Class A shares of Painted Pony. The Class A shares were acquired pursuant to the Shelter Bay Arrangement.
 
 
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On July 5, 2010, the Corporation closed a plan of arrangement under Section 193 of the ABCA with a private company for total consideration of approximately $95.6 million, comprised of 740,537 Common Shares and assumed debt. See "Description of Our Business – Reorganizations".
 
On August 6, 2010, the Corporation disposed of all its interest in 5,333,333 shares of a private oil and gas company.
 
On August 20, 2010, the Corporation closed the Ryland Arrangement for total consideration of approximately $116.3 million, comprised of 2,178,719 Common Shares and assumed debt. See "Description of Our Business – Reorganizations".
 
On October 13, 2010, the Corporation announced the closing of its equity offering of 10,250,000 Common Shares at $36.60 per Common Share for aggregate gross proceeds of approximately $375.2 million.
 
On November 5, 2010, the Corporation completed the acquisition of approximately 950 boe/d of high-quality, low-decline production in southeast Saskatchewan for cash consideration of $87.3 million.
 
2011
 
On January 14, 2011, the Corporation announced the disposal of 5,861,200 Class A Shares of Painted Pony, representing 11.5% of the issued and outstanding Class A Shares of Painted Pony.
 
On April 14, 2011, the Corporation closed an offering of senior unsecured notes in the United States and Canada on a private placement basis with an aggregate principal amount of US$165 million and $50 million. The terms of the U.S. notes range from 5 to 10 years with a weighted average term of 7.9 years and coupon rates ranging from 3.93% to 5.13% and the Canadian notes have a term of 10 years with a coupon rate of 5.53%.
 
On June 10, 2011 the Corporation extended the term of the Syndicated Credit Facility by 1 year to June 10, 2014.
 
On July 14, 2011, the Corporation announced its land position in the Beaverhill Lake light oil resource play at more than 380 (165 net) sections of land. The Corporation also announced that it had ownership and control of 16,750,000 common shares of Arcan Resources Ltd. ("Arcan"), a leading Beaverhill Lake producer, representing 19% of the issued and outstanding common shares of Arcan.
 
On August 31, 2011, the Corporation announced that it had acquired approximately 750 boe/d of production and more than 78 net sections of lower-risk land in North Dakota, U.S., through two strategic acquisitions.
 
On September 21, 2011 and September 30, 2011, the Corporation announced the closing of its equity offering of 8,625,000 Common Shares and the over-allotment of 400,000 Common Shares at $43.50 per Common Share for aggregate gross proceeds of approximately $392.6 million.
 
On October 11, 2011, the Corporation announced that it acquired 1,748,000 common shares of Arcan pursuant to Arcan's public offering. The Corporation owns a total of 18,498,000 common shares, representing approximately 19% of the issued and outstanding common shares of Arcan.
 
2012
 
On January 24, 2012, the Corporation announced that it had expanded its land position in the Beaverhill Lake light oil resource play in northwest Alberta by more than 100 net sections through a series of acquisitions and Crown land sales.
 
On January 25, 2012, the Corporation acquired approximately 940 boe/d of production in southwest Manitoba for cash consideration of $130.3 million.
 
On March 8, 2012, the Corporation announced the closing of its equity offering of 13,351,500 Common Shares at $45.25 per Common Share for aggregate gross proceeds of approximately $604.2 million.
 
 
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On March 15, 2012, the Corporation closed the Wild Stream Arrangement for total estimated consideration of $610.2 million, comprised of 12,082,012 Common Shares and assumed debt. See "Description of Our Business - Reorganizations".
 
On March 16, 2012, the Corporation closed its agreement with PetroBakken Energy Ltd. to acquire more than 2,900 boe/d of production and more than 25 net sections of land in the Viewfield Bakken resource play for cash consideration of $426.4 million.
 
On April 16, 2012, the Corporation closed the sale to a private junior exploration and production company of approximately 900 boe/d of non-core Alberta assets, 80 percent of which was weighted to natural gas, and approximately 20 net sections of undeveloped land for total consideration of $35 million, comprised of $10 million of cash and $25 million of shares in the private company.
 
On May 1, 2012, the Corporation closed the Reliable Arrangement, pursuant to which the Corporation acquired all of the remaining issued and outstanding shares of Reliable not already owned by the Corporation (as at May 1, 2012, Crescent Point had a 12.8% equity interest in Reliable). Total consideration for the acquisition of the 87.2% interest of Reliable not then owned by Crescent Point was $100.7 million, comprised of 1,672,109 Common Shares and assumed debt. See "Description of Our Business - Reorganizations".
 
On May 22, 2012, the Corporation closed an offering of senior guaranteed notes in the United States and Canada on a private placement basis with aggregate principal amounts of US$268 million and $32 million. The terms of the U.S. notes range from 7 to 10 years with a weighted average term of 9.2 years and coupon rates ranging from 3.39% to 4.00% and the terms of the Canadian notes range from 7 to 10 years with a weighted average term of 9.3 years and coupon rates ranging from 4.29% to 4.76%.
 
On May 23, 2012, Crescent Point closed a $500.0 million increase and extension to its syndicated unsecured credit facility with a syndicate of Canadian and international banks, with a maturity date in June 2015. The syndicated unsecured credit facility also includes an accordion feature that allows the Corporation to increase the facility by up to $500 million, for a total of $2.5 billion. The Corporation also renewed and extended its unsecured revolving operating credit facility, with $100 million of credit available and a maturity date in June 2014. In total, the Corporation increased its bank lines from $1.6 billion to $2.1 billion.
 
On June 1, 2012, Crescent Point acquired approximately 2,500 boe/d of production in the Shaunavon resource play in southwest Saskatchewan for cash consideration of $343.0 million.
 
On June 20, 2012, the Corporation closed the Cutpick Arrangement for total consideration of approximately $398.3 million, comprised of 7,556,960 Common Shares and assumed debt. See "Description of Our Business - Reorganizations".
 
On July 17, 2012, the Corporation acquired 21,666,667 common share units of Alston at an effective issue price of $0.15 per unit. Each unit was comprised of one common share of Alston and one-half of one common share purchase warrant of Alston. Each warrant entitles the Corporation to acquire one common share of Alston at a price of $0.20 per common share within the 18 month period beginning on July 17, 2012. The units were acquired in connection with a sale by the Corporation to Alston of certain natural gas properties near Alexander, Alberta, which included approximately 225 boe/d of primarily natural gas production.
 
On August 30, 2012, the Corporation announced the closing of its equity offering of 15,433,000 Common Shares at $41.00 per Common Share for aggregate gross proceeds of approximately $632.8 million.
 
On November 21, 2012, the Corporation announced the closing of its equity offering of 18,750,000 Common Shares at $40.00 per Common Share and on November 29, 2012 the Corporation announced the partial exercise of the over-allotment option granted to the underwriters to purchase an additional 1,250,000 Common Shares at the offering price of $40.00 per Common Share. Including the partial exercise of the over-allotment option, the Corporation issued 20,000,000 Common Shares for aggregate gross proceeds of $800.0 million.
 
 
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On November 29, 2012, the Corporation closed of the acquisition of Ute for total consideration of approximately $867.6 million, comprised of cash consideration of approximately $783.9 million and assumed debt. See "Description of Our Business - Ute Acquisition".
 
DESCRIPTION OF OUR BUSINESS
 
General
 
The Corporation is an oil and gas exploration, development and production company. The Corporation is a conventional oil and gas producer with assets strategically focused in properties comprised of high quality, long life, operated, light and medium oil and natural gas reserves in Western Canada and the United States. In addition, we continually review and assess numerous corporate and asset acquisition opportunities as part of our ongoing acquisition program. The primary assets of the Corporation are currently the shares in CPHI, units in the Partnership and shares in CPUSH and, indirectly, in CPEUS.
 
The crude oil and natural gas properties and related assets generating income for the benefit of the Corporation are located in the provinces of Saskatchewan, Alberta, British Columbia and Manitoba and 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, land and possible reserves.
 
We pay monthly cash dividends to Shareholders from our net cash flow in accordance with our dividend policy. Our primary sources of cash flow are distributions from the Partnership. See "Dividends".
 
Strategy
 
We strive to create sustainable, value-added growth in reserves, production and cash flow through the execution of management's integrated strategy of acquiring, exploiting and developing high quality, long life, light and medium oil and natural gas properties.
 
We continually investigate and search out producing properties including those with large resource potential that we believe will result in meaningful reserve and production additions. We generally focus capital on higher-quality, longer-life reservoirs in proved growth areas that offer existing infrastructure, low cost drilling and multi-zone potential. Our goal is to acquire operational control of properties that we believe offer significant exploitation and development potential.
 
We develop our properties through a detailed technical analysis of information including reservoir characteristics, petroleum initially in place, recovery factors and the applicability of enhanced recovery techniques. Our goal is to increase reserves and production in a cost effective manner through a number of techniques, including drilling infill and step-out wells, fracture stimulation of horizontal wells, re-completing existing wells and implementing waterflood or pressure support schemes.
 
Risk Management and Marketing
 
Factors outside our control impact, to varying degrees, the prices we receive for production and the associated operating expenses we incur. These include but are not limited to:
 
 
(a)
world market forces, including the ability of the OPEC to set and maintain production levels and prices for crude oil;
 
(b)
political conditions, including the risk of hostilities in the Middle East and other regions throughout the world;
 
(c)
increases or decreases in crude oil quality differentials and their implications for prices received by us;
 
(d)
the impact of changes in the exchange rate between Canadian and U.S. dollars on prices received by us for our crude oil and natural gas;
 
 
- 11 -

 
 
 
(e)
North American market forces, most notably shifts in the balance between supply and demand for crude oil and natural gas and the implications for the price of crude oil and natural gas;
 
(f)
availability, proximity and capacity of oil and gas gathering systems, pipeline and processing facilities, railcars and railcar loading facilities;
 
(g)
global and domestic economic and weather conditions;
 
(h)
price and availability of alternative fuels; and
 
(i)
the effect of energy conservation measures and government regulations.
 
Fluctuations in commodity prices, quality differentials and foreign exchange and interest rates, among other factors, are outside of our control and yet can have a significant impact on the level of cash we have available for payment of dividends to Shareholders.
 
To mitigate a portion of these risks, we actively initiate, manage and disclose the effects of our hedging activities. Our strategy for crude oil and natural gas production is to hedge up to 65% of our existing net of royalty production on a rolling three and a half year basis, at the discretion of management. With recent increases in the volatility of price differentials between WTI and western Canadian crude prices, Crescent Point has expanded its risk management programs to include the hedging of these differentials. The Corporation uses a combination of financial derivatives and fixed-differential physical contracts to hedge these price differentials. For differential hedging, Crescent Point’s risk management program allows for hedging a forward profile of 3½ years, and up to 35% net of royalty production. All hedging activities are governed by our Risk Management and Counterparty Credit Policy and are regularly reviewed by the board of directors of the Corporation.
 
As part of our risk management program benchmark oil prices are hedged using financial WTI-based instruments transacted in Canadian dollars and benchmark natural gas prices are hedged using financial AECO-based instruments transacted in Canadian dollars. Total financial oil and gas hedges in 2012 amounted to approximately 50% of annual production, net of royalties, consisting of approximately 54% of annual crude oil production and approximately 18% of annual natural gas production, net of royalties. The primary objective of this strategy is to enhance the stability of cash dividends. The Corporation recorded a realized derivative loss on oil and gas hedge contracts of $17.6 million in 2012.
 
The following table summarizes our commitments under all hedging agreements as at December 31, 2012.
 
Financial WTI Crude Oil Derivative Contracts – Canadian Dollar
 
Term
Volume
(bbl/d)
Average
Swap Price
(Cdn$/bbl)
Average Collar
Sold Call Price
(Cdn$/bbl)
Average Collar Bought Put Price
(Cdn$/bbl)
Average Bought Put Price
(Cdn$/bbl)
Average Put Premium
(Cdn$/bbl)
2013 Weighted Average
41,300
94.04
102.80
86.06
93.03
7.40
2014 Weighted Average
27,000
95.70
106.30
87.80
-
-
2015 Weighted Average
12,973
92.77
101.07
87.30
-
-
January to March 2016 Weighted Average
2,500
89.79
-
-
-
-

Financial AECO Natural Gas Derivative Contracts – Canadian Dollar
 
Term
Contracts
Volume
(GJ/d)
Average Swap Price
(Cdn$/GJ)
2013 Weighted Average
Swap
7,326
3.58
2014 Weighted Average
Swap
6,000
3.39
January to October 2015 Weighted Average
Swap
6,000
3.39

Financial Power Derivative Contracts – Canadian Dollar
 
Term
Contract
Volume
(MW/h)
Fixed Rate
($/MW/h)
2013
Swap
3.0
53.00
2014
Swap
3.0
75.00
 
 
- 12 -

 
 
Foreign Exchange Forward Contracts – Canadian Dollar
 
Settlement Date
Contract
Principal (US$)
Exchange Rate
(Cdn$/US$)
January 2013
Forward Purchase
4,000,000
0.9924
January 2013
Forward Purchase
6,000,000
0.9857
February 2013
Forward Purchase
4,000,000
0.9938
February 2013
Forward Purchase
6,000,000
0.9850
March 2013
Forward Purchase
4,000,000
0.9943
March 2013
Forward Purchase
6,000,000
0.9855
July 2013
Forward Purchase
5,000,000
0.9991
October 2013
Forward Purchase
6,000,000
1.0020

Financial Interest Rate Derivative Contracts – Canadian Dollar
 
Term
Contract
Principal (Cdn$)
Fixed Annual
Rate (%)
January 2013 – May 2015
Swap
25,000,000
2.90
January 2013 – May 2015
Swap
25,000,000
3.50
January 2013 – May 2015
Swap
50,000,000
3.09
January 2013 – June 2015
Swap
50,000,000
3.78
January 2013 – July 2015
Swap
50,000,000
3.63

Financial Cross Currency Interest Rate Derivative Contracts – Canadian Dollar
 
Term
Contract
Receive Notional
Principal
(US$)
Fixed Annual Rate
(US%)
Pay Notional Principal (Cdn$)
Fixed Annual
Rate
(Cdn%)
January 2013 – March 2015
Swap
37,500,000
4.71
38,287,500
5.24
January 2013 – April 2016
Swap
52,000,000
3.93
50,128,000
4.84
January 2013 – March 2017
Swap
67,500,000
5.48
68,917,500
5.89
January 2013 – April 2018
Swap
31,000,000
4.58
29,884,000
5.32
January 2013 – May 2019
Swap
68,000,000
3.39
66,742,000
4.53
January 2013 – March 2020
Swap
155,000,000
6.03
158,255,000
6.45
January 2013 – April 2021
Swap
82,000,000
5.13
79,048,000
5.83
January 2013 – May 2022
Swap
170,000,000
4.00
166,855,000
5.03

Financial Cross Currency Principal Derivative Contracts – Canadian Dollar
 
Settlement Date
Contract
Receive Notional
Principal
(US$)
Pay Notional Principal (Cdn$)
May 2022
Swap
30,000,000
32,241,000
 
In addition to hedging benchmark crude oil and natural prices with financial instruments, we have also begun to mitigate crude oil basis risk by delivering a portion of our crude oil production into diversified refinery markets using rail transportation. As of January 2013, Crescent Point owned and operated three railcar loading facilities, serving its key producing areas of southeast Saskatchewan, southwest Saskatchewan and central Alberta.
 
Crude oil volumes loaded at these facilities are sold at the loading facilities and our buyers are responsible for providing railcars and managing transportation logistics from that point until delivery at the refinery gate. By utilizing rail transportation, we have been able to access refining markets that are not pipeline connected to western Canada, which significantly diversifies our price and market risk. In addition, we have been able to enter into term sales contracts on a portion of the volumes transported by rail, which set the price differential between benchmark WTI prices and our selling price at the loading terminals. From July to December 2012, approximately 8,000 bbl/d of oil production was contracted with fixed price differentials off WTI. As of late February 2013, more than 17,500 bbl/d of oil production from March to December 2013 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 Canadian crude oil differentials.
 
 
- 13 -

 
 
We also mitigate risk by having a well-diversified marketing portfolio for oil and natural gas. As a result of our access to rail transportation, we have significantly increased and diversified the number of counterparties with which we transact. Credit risk associated with the Corporation's portfolio of physical crude oil and natural gas sales and with the Corporation's commodity hedging portfolio is managed and mitigated by Crescent Point's Risk Management Committee and is governed by a Board-approved Risk Management and Counterparty Credit Policy that is reviewed by the board of directors on an annual basis. The Policy requires annual credit reviews of all trade counterparties with which the Corporation has, or expects to have, exposures greater than 0.5% of the Corporation’s total aggregate monthly volumetric exposure. Credit limits are required to be set for all trade counterparties, which are based on either a fixed dollar amount which is set annually at a minimum or a percentage of the Corporation's portfolio calculated monthly. Crescent Point utilizes a diversified approach in both its physical sales portfolio and its financial hedging portfolio. The physical sales portfolio consists of more than 30 purchasers and its financial hedging portfolio consists of 11 counterparties. The Corporation's portfolio of counterparty exposures is reviewed monthly by the Chief Financial Officer, the Vice President, Finance and Treasurer, and the Vice President, Marketing and Investor Relations. Counterparty exposures are also reviewed on a quarterly basis by both the Risk Management Committee and the board of directors.
 
To further mitigate credit risk associated with its physical sales portfolio, Crescent Point has secured credit insurance from a leading global credit insurance provider. This policy provides credit coverage for approximately 30 percent of the Corporation's physical sales portfolio.
 
The majority of our oil and natural gas volumes are sold in Alberta and Saskatchewan. Approximately 87% of our oil volumes are sold in Saskatchewan, 9% in Alberta and 4% in the U.S. Approximately 54% of our natural gas volumes are sold in Saskatchewan, 44% in Alberta and 2% in the U.S.
 
Revenue Sources
 
For 2012, our commodity production mix was approximately 91% 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
2012
98%
2%
2011
97%
3%
2010
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 will be dependent upon developing and maintaining close working relationships with our industry partners and joint operators, our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.
 
Seasonal Factors
 
The production of oil and natural gas is dependent on access to areas where development of reserves is to be conducted. Seasonal weather variations, including freeze-up and break-up, affect access in certain circumstances.
 
Personnel
 
As at December 31, 2012, we had 303 full-time employees and 53 consultants at our head office. In the field we had 296 full-time field staff, 4 part-time field staff and 78 consultants.
 
 
- 14 -

 
 
Reorganizations
 
On July 2, 2010, the Corporation closed the Shelter Bay Arrangement for total consideration of approximately $1.2 billion, comprised of 24,397,586 Common Shares and assumed debt. The Shelter Bay Arrangement solidified the Corporation's position in each of the Bakken and Lower Shaunavon oil resource plays in Saskatchewan.
 
On July 5, 2010, the Corporation completed a plan of arrangement under Section 193 of the ABCA with a private company for total consideration of approximately $95.6 million, comprised of 740,537 Common Shares and assumed debt. The acquisition of this private company gave the Corporation more than one million net acres of exploratory land in southern Alberta.
 
On August 20, 2010, the Corporation closed the Ryland Arrangement for total consideration of approximately $116.3 million, comprised of 2,178,719 Common Shares and assumed debt. The Ryland Arrangement solidified the Corporation's position in the Flat Lake Bakken play in southeast Saskatchewan and increased its undeveloped land position in North Dakota.
 
On January 1, 2011, the Corporation amalgamated with Ryland Oil ULC, Darian Resources Ltd. and Shelter Bay ULC.
 
On March 15, 2012, the Corporation closed the Wild Stream Arrangement for total consideration of $610.2 million, comprised of 12,082,012 Common Shares and assumed debt. The Wild Stream Arrangement further solidified the Corporation’s position as the largest player in the Shaunavon resource play in southwest Saskatchewan, in terms of production and land. Wild Stream’s assets also complement the Corporation’s existing position in Alberta’s emerging Beaverhill Lake light oil resource play in the Swan Hills area.
 
On May 1, 2012, the Corporation closed the Reliable Arrangement, pursuant to which the Corporation acquired all of the remaining issued and outstanding shares of Reliable not already owned by the Corporation. Total consideration for the acquisition of the 87.2% interest of Reliable not then owned by Crescent Point was $100.7 million, comprised of 1,672,109 Common Shares and assumed debt. The Reliable Arrangement allowed the Corporation to consolidate the assets that were held through a joint venture with Reliable in the Bakken light oil play in southwest Manitoba.
 
On June 20, 2012, the Corporation closed the Cutpick Arrangement for total consideration of approximately $398.3 million, comprised of 7,556,960 Common Shares and assumed debt. The assets in the Viking light oil resource play near Provost, Alberta acquired from the Cutpick Arrangement complement and consolidate the Corporation’s existing position in the play.
 
Ute Acquisition
 
On November 29, 2012, the Corporation closed the acquisition of Ute for total consideration of approximately $867.6 million, comprised of cash consideration of approximately $783.9 million and assumed debt of approximately $83.7 million. The acquisition established a new core area for potential long-term growth in the Uinta Basin light oil resource play in northeast Utah.
 
The Ute assets are located in the central Uinta Basin, which is the intersection between two main oil-bearing plays within the basin: Monument Butte and Altamont-Bluebell, which have been producing for more than 50 years. Exploration and development agreements ("EDAs"), entered into under the authority of the Indian Mineral Development Act of 1982 and approved by the Bureau of Indian Affairs within the Department of the Interior, with the Ute Indian Tribe of the Uintah and Ouray Reservation (the "Tribe") govern more than 150 net sections of land in the central basin, of which the majority is undeveloped. The EDAs cover several core project areas including the Randlett, Horseshoe Bend, Rocky Point, Blacktail Ridge, North Monument Butte, Bridgeland and Lake Canyon properties. The EDAs create an operating interest in the Tribe’s minerals, requires payment of royalties and rentals to the Tribe and reserve the Tribe’s right to take royalty production in kind. The EDAs grant Ute an interest in real property, which represents a recordable interest in real estate under Utah law. The lands governed by these EDAs were released for development less than 10 years ago. The EDAs have an initial five-year term, with the majority of the EDAs being issued in the last five years, and all of the EDAs contain extension provisions related to meeting certain drilling commitments which provisions, if met, allow for two additional five-year terms that have the potential to provide the Corporation with up to an initial 15-year term to develop the Ute Assets.
 
 
- 15 -

 
 
The Uinta Basin in northeast Utah has been producing light oil since the 1950s and, in recent years, has experienced resurgence in activity with the application of new drilling and completion techniques. Through the application of infill drilling and multi-stage fracture stimulation to both vertical and horizontal oil wells, Crescent Point believes greater potential can be unlocked in the resource play.
 
The Ute Assets are expected to provide low-risk production growth potential over the coming years. The Corporation's near-term growth plan for the Uinta Basin is for moderate growth, similar to other new areas the Corporation has developed in Canada. Management believes that good service availability combined with favourable land tenure provides the Corporation with significant operational flexibility to determine the optimal development plan for the Ute Assets. This should allow for proper integration and potential long-term value creation as Crescent Point develops and expands the play within its existing portfolio of assets.
 
Social and Environmental Policies
 
The Corporation established a reclamation fund to fund future decommissioning costs and environmental emissions reduction costs. From January 1, 2010 to March 30, 2010, we allocated $0.30 per boe of production. From April 1, 2010 to December 31, 2011, we allocated $0.45 per boe of production. From January 1, 2012 to December 31, 2012, we allocated $0.50 per boe of production. Additional contributions can be made at the discretion of management. Effective January 1, 2013, Crescent Point contributes $0.70 per produced boe to the fund, of which $0.40 per boe is for future decommissioning costs and $0.30 per boe is directed to environmental emissions reduction.
 
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, 2012 contained in the consolidated report of GLJ dated March 13, 2013 (the "Crescent Point Reserve Report"). The Crescent Point Reserve Report evaluated, as at December 31, 2012, summarizes our crude oil, NGL and natural gas reserves. The tables below are a combined summary of our crude oil, NGL and natural gas reserves and the net present value of future net revenue attributable to such reserves as evaluated in the Crescent Point Reserve Report based on GLJ's January 1, 2013 forecast price and cost assumptions. GLJ evaluated approximately 39 percent of the assigned total Proved plus Probable reserves and 31 percent of the total Proved plus Probable value discounted at 10 percent. Sproule evaluated approximately 61 percent of the assigned total Proved plus Probable reserves and 69 percent of the total Proved plus Probable value discounted at 10 percent. Sproule evaluated a majority of our Saskatchewan assets including the Viewfield Bakken properties in southeast Saskatchewan and the Shaunavon properties in southwest Saskatchewan. Sproule evaluated their portion of the reserves using the GLJ forecast price and cost escalation assumptions. GLJ evaluated the Corporation’s Alberta and Manitoba assets as well as a portion of the Saskatchewan assets in Canada. GLJ also performed the evaluation of the existing US assets in North Dakota and Montana, as well as the recently acquired properties in Utah in the Ute corporate acquisition. These assets were all evaluated using the GLJ forecast price and cost escalation assumptions. GLJ prepared the total Crescent Point Reserve Report by consolidating the GLJ Canadian and US evaluated properties with the Sproule evaluation using the GLJ pricing and cost escalation assumptions. The tables summarize the data contained in the Crescent Point Reserve Report and, as a result, may contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly.
 
The net present value of future net revenue attributable to our reserves is stated without provision for interest costs, and general and administrative costs, but after providing for estimated royalties, production costs, capital taxes, development costs, other income, future capital expenditures, and well abandonment costs for only those wells assigned reserves by GLJ and Sproule. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to our reserves estimated by GLJ and Sproule represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of our crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.
 
 
- 16 -

 
 
The Crescent Point Reserve Report is based on certain factual data supplied by us as well as GLJ and Sproule's opinion of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to our petroleum properties and contracts (except for certain information residing in the public domain) were supplied by the Corporation to GLJ and Sproule, and were accepted without any further investigation. GLJ and Sproule accepted this data as presented and neither title searches nor field inspections were conducted.
 
Reserves Data – Forecast Prices and Costs
 
Summary of Oil and Gas Reserves(1)
 
 
Light and Medium Oil
Heavy Oil
Natural Gas Liquids
Natural Gas
Total
Reserves Category
Company Gross
(Mbbls)
Company
Net
(Mbbls)
Company
Gross
(Mbbls)
Company
Net
(Mbbls)
Company
Gross
(Mbbls)
Company
Net
(Mbbls)
Company Gross
(MMcf)
Company
Net
(MMcf)
Company
Gross
(Mboe)
Company
Net
(Mboe)
Proved Developed Producing
                   
Canada
171,731
151,450
1,588
1,437
6,818
6,216
92,835
86,097
195,609
173,452
United States
14,329
11,606
-
-
466
373
12,466
10,052
16,873
13,655
Total
186,059
163,056
1,588
1,437
7,284
6,589
105,301
96,149
212,482
187,107
Proved Developed
Non-Producing
                   
Canada
7,643
6,810
553
518
467
425
8,964
8,103
10,157
9,104
United States
2,676
2,174
-
-
26
21
982
798
2,865
2,328
Total
10,319
8,984
553
518
493
446
9,946
8,901
13,022
11,432
Proved Undeveloped
                   
Canada
125,541
115,429
347
308
6,872
6,429
66,874
62,621
143,906
132,604
United States
26,707
21,611
-
-
767
615
20,932
16,904
30,963
25,044
Total
152,248
137,040
347
308
7,640
7,045
87,807
79,526
174,869
157,647
Total Proved
                   
Canada
304,915
273,689
2,487
2,263
14,157
13,071
168,674
156,822
349,672
315,160
United States
43,711
35,392
-
-
1,260
1,009
34,380
27,754
50,701
41,026
Total
348,627
309,080
2,487
2,263
15,417
14,080
203,053
184,576
400,373
356,186
Total Probable
                   
Canada
155,913
138,432
1,088
953
6,790
6,189
88,592
81,762
178,557
159,201
United States
25,687
20,743
-
-
1,059
848
18,727
15,115
29,867
24,111
Total
181,600
159,175
1,088
953
7,849
7,037
107,319
96,877
208,424
183,311
Total Proved Plus Probable
                   
Canada
460,829
412,121
3,575
3,216
20,947
19,260
257,266
238,584
528,229
474,360
United States
69,399
56,135
-
-
2,319
1,857
53,107
42,869
80,568
65,137
Total
530,227
468,256
3,575
3,216
23,266
21,117
310,373
281,453
608,797
539,497

Note:
(1)             Numbers may not add due to rounding.
 
 
- 17 -

 
 
Net Present Value of Future Net Revenue of Oil and Gas Reserves(1)
 
   
Before Income Taxes Discounted at (%/year)
     
After Income Taxes Discounted at (%/year)
 
Reserves Category
0%
(M$)
5%
(M$)
10%
(M$)
15%
(M$)
20%
(M$)
 
0%
(M$)
5%
(M$)
10%
(M$)
15%
(M$)
20%
(M$)
Proved Developed Producing
                     
Canada
8,988,396
6,597,251
5,332,922
4,534,801
3,978,003
 
8,283,191
6,167,500
5,030,981
4,305,951
3,796,179
United States
571,998
444,710
367,550
316,411
280,154
 
571,998
444,710
367,550
316,411
280,154
Total
9,560,394
7,041,961
5,700,471
4,851,212
4,258,156
 
8,855,189
6,612,209
5,398,531
4,622,362
4,076,332
Proved Developed
Non-Producing
                     
Canada
458,317
364,239
304,311
262,933
232,651
 
335,489
265,762
221,339
190,677
168,252
United States
93,867
71,723
58,034
48,924
42,477
 
93,867
71,723
58,034
48,924
42,477
Total
552,183
435,962
362,345
311,858
275,128
 
429,356
337,485
279,373
239,602
210,729
Proved Undeveloped
                     
Canada
4,523,539
3,108,139
2,228,603
1,646,808
1,243,092
 
3,311,234
2,185,002
1,488,073
1,030,509
716,230
United States
676,906
379,590
213,156
111,420
45,051
 
676,906
379,590
213,156
111,420
45,051
Total
5,200,446
3,487,729
2,441,760
1,758,229
1,288,143
 
3,988,140
2,564,592
1,701,229
1,141,929
761,281
Total Proved
                     
Canada
13,970,252
10,069,629
7,865,836
6,444,542
5,453,746
 
11,929,914
8,618,264
6,740,392
5,527,138
4,680,661
United States
1,342,771
896,023
638,740
476,756
367,681
 
1,342,771
896,023
638,740
476,756
367,681
Total
15,313,023
10,965,652
8,504,576
6,921,298
5,821,428
 
13,272,685
9,514,287
7,379,132
6,003,894
5,048,343
Total Probable
                     
Canada
9,032,011
5,571,390
3,937,650
3,002,673
2,402,769
 
6,612,553
4,050,823
2,838,580
2,144,409
1,699,439
United States
1,054,718
585,499
376,438
265,420
198,639
 
640,844
375,266
258,006
193,471
152,314
Total
10,086,729
6,156,889
4,314,088
3,268,093
2,601,408
 
7,253,396
4,426,089
3,096,586
2,337,880
1,851,753
Total Proved Plus Probable
                     
Canada
23,002,263
15,641,019
11,803,486
9,447,215
7,856,515
 
18,542,467
12,669,087
9,578,973
7,671,546
6,380,100
United States
2,397,490
1,481,522
1,015,178
742,176
566,320
 
1,983,615
1,271,289
896,746
670,227
519,995
Total
25,399,753
17,122,541
12,818,663
10,189,391
8,422,836
 
20,526,081
13,940,376
10,475,719
8,341,773
6,900,096
Note:
(1)           Numbers may not add due to rounding.
 
Additional Information Concerning Future Net Revenue – (Undiscounted)(1)
 
Reserves Category
Revenue
(M$)
Royalties
(M$)
Operating
Costs
(M$)
Capital
Development
Costs
(M$)
Abandonment
Costs
(M$)
Future Net
Revenue Before
Income Taxes
(M$)
Income Tax
(M$)
Future Net
Revenue After
Income Taxes
(M$)
Proved
               
Canada
30,223,353
3,610,769
8,682,713
3,664,583
295,036
13,970,252
2,040,338
11,929,914
United States
4,170,692
1,052,266
1,077,230
663,758
34,666
1,342,771
-
1,342,771
Total
34,394,045
4,663,035
9,759,943
4,328,341
329,702
15,313,023
2,040,338
13,272,685
Proved Plus Probable
               
Canada
47,204,621
5,738,176
13,368,669
4,736,362
359,152
23,002,263
4,459,796
18,542,467
United States
6,972,035
1,781,092
1,789,048
957,446
46,958
2,397,490
413,875
1,983,615
Total
54,176,656
7,519,268
15,157,717
5,693,807
406,110
25,399,753
4,873,671
20,526,081
Note:
(1)           Numbers may not add due to rounding.
 
 
- 18 -

 
 
Future Net Revenue by Production Group
 
 
Future Net Revenue
Before Income Taxes(3)
(Discounted at 10% per year)
Percentage
Unit Value
 
(M$)
(%)
($/boe)
($/Mcfe)
Proved
             
CANADA
             
Light and Medium Oil(1)
7,779,120
99
 
25.24
 
4.21
 
Heavy Oil(1)
53,527
<1
 
22.22
 
3.70
 
Natural Gas(2)
33,189
<1
 
7.24
 
1.21
 
Total Canada
7,865,836
100
 
24.96
 
4.16
 
UNITED STATES
             
Light and Medium Oil(1)
638,740
100
 
15.57
 
2.59
 
Heavy Oil(1)
-
-
 
-
 
-
 
Natural Gas(2)
-
-
 
-
 
-
 
Total United States
638,740
100
 
15.57
 
2.59
 
TOTAL
             
Light and Medium Oil(1)
8,417,860
99
 
24.10
 
4.02
 
Heavy Oil(1)
53,527
<1
 
22.22
 
3.70
 
Natural Gas(2)
33,189
<1
 
7.24
 
1.21
 
Total Proved
8,504,576
100
 
23.88
 
3.98
 
Notes:
(1) 
Including solution gas and other by-products.
(2) 
Including by-products but excluding solution gas.
(3) 
Other company revenue and costs not related to a specific production group have been allocated proportionately to production groups.
Unit values are based on Company Net Reserves.
 
 
 
Future Net Revenue
Before Income Taxes(3)
(Discounted at 10% per year)
Percentage
Unit Value
 
(M$)
(%)
($/boe)
($/Mcfe)
Proved Plus Probable
             
CANADA
             
Light and Medium Oil(1)
11,679,273
99
 
25.15
 
4.19
 
Heavy Oil(1)
76,396
<1
 
22.37
 
3.73
 
Natural Gas(2)
47,817
<1
 
7.22
 
1.20
 
Total
11,803,486
100
 
24.88
 
4.15
 
UNITED STATES
             
Light and Medium Oil(1)
1,015,178
100
 
15.59
 
2.60
 
Heavy Oil(1)
-
-
 
-
 
-
 
Natural Gas(2)
-
-
 
-
 
-
 
Total
1,015,178
100
 
15.59
 
2.60
 
TOTAL
             
Light and Medium Oil(1)
12,694,450
99
 
23.97
 
4.00
 
Heavy Oil(1)
76,396
<1
 
22.37
 
3.73
 
Natural Gas(2)
47,817
<1
 
7.22
 
1.20
 
Total Proved Plus Probable
12,818,663
100
 
23.76
 
3.96
 
Notes:
(1) 
Including solution gas and other by-products.
(2) 
Including by-products but excluding solution gas.
(3) 
Other company revenue and costs not related to a specific production group have been allocated proportionately to production groups.
Unit values are based on Company Net Reserves.
 
For future net revenue of the total Proved reserves for the total company, discounted at 10 percent, 99% of the revenue is from light and medium oil, less than 1% from heavy oil, and less than 1% from natural gas. For the total Proved plus Probable reserves for the total company, discounted at 10 percent, 99% of the revenue is from light and medium oil, less than 1% from heavy oil, and less than 1% from natural gas.
 
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.
 
 
- 19 -

 
 
Reserve Categories
 
The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of Proved, Probable and possible reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery.
 
The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions.
 
 
(a)
"Reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.
 
 
(b)
"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
 
 
(c)
"Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
 
 
(d)
"Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.
 
 
(e)
"Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned. In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to sub-divide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.
 
 
(f)
"Probable" reserves are those additional reserves that are less certain to be recovered than Proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable reserves.
 
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
 
 
- 20 -

 
 
·
At least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable reserves.
 
A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.
 
Additional Definitions
 
The following terms, used in the preparation of the Crescent Point Reserve Report and this AIF, have the following meanings:
 
 
(a)
"associated gas" means the gas cap overlying a crude oil accumulation in a reservoir.
 
 
(b)
"crude oil" or "oil" means a mixture that consists mainly of pentanes and heavier hydrocarbons, which may contain small amounts of sulphur and other non-hydrocarbons, that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. It does not include liquids obtained from the processing of natural gas.
 
 
(c)
"development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from the reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
 
 
(i)
gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves;
 
 
(ii)
drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and the wellhead assembly;
 
 
(iii)
acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds measuring devices and production storage, natural gas cycling and processing plants, and central utility and waste disposal system; and
 
 
(iv)
provide improved recovery systems.
 
 
(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");
 
 
- 21 -

 
 
 
(ii)
costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;
 
 
(iii)
dry hole contributions and bottom hole contributions;
 
 
(iv)
costs of drilling and equipping exploratory wells; and
 
 
(v)
costs of drilling exploratory type stratigraphic test wells.
 
 
(f)
"exploratory well" means a well that is not a development well, a service well or a stratigraphic test well.
 
 
(g)
"F&D costs" means finding and development costs.
 
 
(h)
"field" means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata or laterally by local geologic barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to denote localized geological features, in contrast to broader terms such as "basin", "trend", "province", "play" or "area of interest".
 
 
(i)
"future prices and costs" means future prices and costs that are:
 
 
(i)
generally accepted as being a reasonable outlook of the future;
 
 
(ii)
if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Corporation is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (i).
 
 
(j)
"future income tax expenses" means future income tax expenses estimated (generally, year-by-year):
 
 
(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.
 
 
- 22 -

 
 
 
(k)
"future net revenue" means the estimated net amount to be received with respect to the development and production of reserves (including synthetic oil, coal bed methane and other non-conventional reserves) estimated using forecast prices and costs.
 
 
(l)
"gross" means:
 
 
(i)
in relation to the Corporation's interest in production or reserves, its "company gross reserves", which are its working interest (operated or non-operated) share before deduction of royalties and without including any royalty interests of the Corporation;
 
 
(ii)
in relation to wells, the total number of wells in which the Corporation has an interest; and
 
 
(iii)
in relation to properties, the total area of properties in which the Corporation has an interest.
 
 
(m)
"natural gas" means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain natural gas liquids. Natural gas can exist in a reservoir either dissolved in crude oil (solution gas) or in a gaseous phase (associated gas or non-associated gas). Non-hydrocarbon substances may include hydrogen sulphide, carbon dioxide and nitrogen.
 
 
(n)
"natural gas liquids" means those hydrocarbon components that can be recovered from natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes plus, condensate and small quantities of non-hydrocarbons.
 
 
(o)
"net" means:
 
 
(i)
in relation to the Corporation's interest in production or reserves its working interest (operated or non-operated) share after deduction of royalty obligations, plus its royalty interests in production or reserves;
 
 
(ii)
in relation to the Corporation's interest in wells, the number of wells obtained by aggregating the Corporation's working interest in each of its gross wells; and
 
 
(iii)
in relation to the Corporation's interest in a property, the total area in which the Corporation has an interest multiplied by the working interest owned by the Corporation.
 
 
(p)
"non-associated gas" means an accumulation of natural gas in a reservoir where there is no crude oil.
 
 
(q)
"operating costs" or "production costs" means costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment and facilities as well as other costs of operating and maintaining those wells and related equipment and facilities.
 
 
(r)
"production" means recovering, gathering, treating, field or plant processing (for example, processing gas to extract natural gas liquids) and field storage of oil and gas.
 
 
(s)
"property" includes:
 
 
- 23 -

 
 
 
(i)
fee ownership or a lease, concession, agreement, permit, license or other interest representing the right to extract oil or gas subject to such terms as may be imposed by the conveyance of that interest;
 
 
(ii)
royalty interests, production payments payable in oil or gas, and other non-operated interests in properties operated by others; and
 
 
(iii)
an agreement with a foreign government or authority under which the Corporation participates in the operation of properties or otherwise serves as "producer" of the underlying reserves (in contrast to being an independent purchaser, broker, dealer or importer).
 
A property does not include supply agreements, or contracts that represent a right to purchase, rather than extract, oil or gas.
 
 
(t)
"property acquisition costs" means costs incurred to acquire a property (directly by purchase or lease, or indirectly by acquiring another corporate entity with an interest in the property), including:
 
 
(i)
costs of lease bonuses and options to purchase or lease a property;
 
 
(ii)
the portion of the costs applicable to hydrocarbons when land including rights to hydrocarbons is purchased in fee; and
 
 
(iii)
brokers' fees, recording and registration fees, legal costs and other costs incurred in acquiring properties.
 
 
(u)
"proved property" means a property or part of a property to which reserves have been specifically attributed.
 
 
(v)
"reservoir" means a porous and permeable subsurface rock formation that contains a separate accumulation of petroleum that is confined by impermeable rock or water barriers and is characterized by a single pressure system.
 
 
(w)
"service well" means a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for combustion.
 
 
(x)
"solution gas" means natural gas dissolved in crude oil.
 
 
(y)
"stratigraphic test well" means a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Ordinarily, such wells are drilled without the intention of being completed for hydrocarbon production. They include wells for the purpose of core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (i) "exploratory type" if not drilled into a proved property; or (ii) "development type", if drilled into a proved property. Development type stratigraphic wells are also referred to as "evaluation wells".
 
 
(z)
"support equipment and facilities" means equipment and facilities used in oil and gas activities, including seismic equipment, drilling equipment, construction and grading equipment, vehicles, repair shops, warehouses, supply points, camps, and division, district or field offices.
 
 
(aa)
"unproved property" means a property or part of a property to which no reserves have been specifically attributed.
 
 
- 24 -

 
 
 
(bb)
"well abandonment costs" means costs of abandoning a well (net of salvage value) and of disconnecting the well from the surface gathering system. They do not include costs of abandoning the gathering system or reclaiming the wellsite.
 
Pricing Assumptions – Forecast Prices and Costs
 
GLJ and Sproule employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2012 in estimating our reserves data using forecast prices and costs.
 
Year
Natural Gas
Crude Oil
 
NGLs
     
 
Henry Hub
NYMEX
($US/MMBTU)
AECO/NIT
Spot
($Cdn/MMBTU)
WTI at
Cushing
Oklahoma
($US/bbl)
Edmonton
($Cdn/bbl)
Pentanes
Plus
Edmonton
($Cdn/bbl)
Butanes
Edmonton
($Cdn/bbl)
Propane
Edmonton
($Cdn/bbl)
Inflation Rate
(%/yr)
Exchange
Rate
($US/$Cdn)
Forecast
                 
2013
3.75
3.38
90.00
85.00
96.63
65.45
34.06
2.0
1.000
2014
4.25
3.83
92.50
91.50
97.91
70.46
45.75
2.0
1.000
2015
4.75
4.28
95.00
94.00
97.76
72.38
56.40
2.0
1.000
2016
5.25
4.72
97.50
96.50
100.36
74.31
57.90
2.0
1.000
2017
5.50
4.95
97.50
96.50
100.36
74.31
57.90
2.0
1.000
2018
5.80
5.22
97.50
96.50
100.36
74.31
57.90
2.0
1.000
2019
5.91
5.32
98.54
97.54
101.44
75.11
58.52
2.0
1.000
2020
6.03
5.43
100.51
99.51
103.49
76.62
59.71
2.0
1.000
2021
6.15
5.54
102.52
101.52
105.58
78.17
60.91
2.0
1.000
2022
6.27
5.64
104.57
103.57
107.71
79.75
62.14
2.0
1.000
2023+
+2.0%/yr
+2.0%/yr
+2.0%/yr
+2.0%/yr
+2.0%/yr
+2.0%/yr
+2.0%/yr
2.0
1.000

For the year ended December 31, 2012, the average realized sales prices before hedging were $82.19/bbl for light and medium oil, $74.90/bbl for heavy oil, $49.24/bbl for NGLs and $2.61/mcf for natural gas.
 
Reconciliations of Changes in Reserves and Future Net Revenue
 
 
Reserves Reconciliation
 
The following table sets forth a reconciliation of the Corporation's Company Gross reserves by total Proved, total Probable and total Proved plus Probable reserves as at December 31, 2012 against such reserves as at January 1, 2012 based on forecast price and cost assumptions.
 
CANADA
Light and Medium Oil (Mbbls)
Heavy Oil (Mbbls)
Natural Gas Liquids (Mbbls)
Factors
Proved
Probable
Proved +
Probable
Proved
Probable
Proved +
Probable
Proved
Probable
Proved +
Probable
January 1, 2012(1)
242,962
123,374
366,336
1,654
837
2,492
10,370
4,944
15,314
Discoveries
66
18
84
-
-
-
-
-
-
Extensions and Improved Recovery
22,157
15,158
37,316
269
90
359
938
459
1,397
Technical Revisions
16,439
(7,821)
8,618
41
(34)
8
3,770
840
4,610
Acquisitions
55,457
25,952
81,409
774
191
964
1,307
728
2,035
Dispositions
(122)
(55)
(177)
(11)
(3)
(14)
(515)
(162)
(677)
Economic Factors
(2,249)
(713)
(2,962)
18
6
24
(96)
(18)
(114)
Production
(29,796)
-
(29,796)
(258)
-
(258)
(1,617)
-
(1,617)
December 31, 2012(2)
304,915
155,913
460,829
2,487
1,088
3,575
14,157
6,790
20,947
 
CANADA
Associated and Non-Associated Gas (Natural Gas) (MMcf)
BOE (Mboe)
Factors
Proved
Probable
Proved +
Probable
Proved
Probable
Proved +
Probable
January 1, 2012(1)
131,902
65,906
197,807
276,970
140,139
417,109
Discoveries
197
50
247
98
27
125
Extensions and Improved Recovery
12,358
7,201
19,559
25,424
16,907
42,331
Technical Revisions
21,644
542
22,186
23,858
(6,924)
16,934
Acquisitions
38,682
21,498
60,180
63,985
30,453
94,438
Dispositions
(13,369)
(5,042)
(18,411)
(2,876)
(1,060)
(3,936)
Economic Factors
(3,334)
(1,563)
(4,897)
(2,882)
(986)
(3,868)
Production
(19,405)
-
(19,405)
(34,905)
-
(34,905)
December 31, 2012(2)
168,674
88,592
257,266
349,672
178,557
528,229
 
 
- 25 -

 
 
UNITED STATES
Light and Medium Oil (Mbbls)
Heavy Oil (Mbbls)
Natural Gas Liquids (Mbbls)
Factors
Proved
Probable
Proved +
Probable
Proved
Probable
Proved +
Probable
Proved
Probable
Proved +
Probable
January 1, 2012(1)
3,721
3,405
7,126
-
-
-
5
2
7
Discoveries
-
-
-
-
-
-
-
-
-
Extensions and Improved Recovery
8,175
7,955
16,130
-
-
-
619
592
1,211
Technical Revisions
1,109
(914)
195
-
-
-
305
310
615
Acquisitions
32,249
14,905
47,154
-
-
-
336
153
488
Dispositions
-
-
-
-
-
-
-
-
-
Economic Factors
(385)
337
(48)
-
-
-
(2)
2
-
Production
(1,158)
-
(1,158)
-
-
-
(3)
-
(3)
December 31, 2012(2)
43,711
25,687
69,399
-
-
-
1,260
1,059
2,319
 
UNITED STATES
Associated and Non-Associated Gas (Natural Gas) (MMcf)
BOE (Mboe)
 
Factors
Proved
Probable
Proved +
Probable
Proved
Probable
Proved +
Probable
January 1, 2012(1)
2,008
1,206
3,214
4,061
3,608
7,669
Discoveries
-
-
-
-
-
-
Extensions and Improved Recovery
4,932
5,046
9,977
9,615
9,388
19,003
Technical Revisions
93
(403)
(310)
1,429
(670)
759
Acquisitions
28,190
12,634
40,824
37,283
17,163
54,446
Dispositions
-
-
-
-
-
-
Economic Factors
(380)
245
(136)
(450)
379
(71)
Production
(463)
-
(463)
(1,238)
-
(1,238)
December 31, 2012(2)
34,380
18,727
53,107
50,701
29,867
80,568
 
TOTAL
Light and Medium Oil (Mbbls)
Heavy Oil (Mbbls)
Natural Gas Liquids (Mbbls)
Factors
Proved
Probable
Proved +
Probable
Proved
Probable
Proved +
Probable
Proved
Probable
Proved +
Probable
January 1, 2012(1)
246,683
126,778
373,462
1,654
837
2,492
10,375
4,946
15,321
Discoveries
66
18
84
-
-
-
-
-
-
Extensions and Improved Recovery
30,332
23,113
53,446
269
90
359
1,557
1,051
2,608
Technical Revisions
17,548
(8,735)
8,813
41
(34)
8
4,075
1,151
5,226
Acquisitions
87,707
40,857
128,563
774
191
964
1,643
880
2,523
Dispositions
(122)
(55)
(177)
(11)
(3)
(14)
(515)
(162)
(677)
Economic Factors
(2,633)
(377)
(3,010)
18
6
24
(98)
(16)
(114)
Production
(30,953)
-
(30,953)
(258)
-
(258)
(1,621)
-
(1,621)
December 31, 2012(2)
348,627
181,600
530,227
2,487
1,088
3,575
15,417
7,849
23,266
 
TOTAL
Associated and Non-Associated Gas (Natural Gas) (MMcf)
 BOE (Mboe)
Factors
Proved
Probable
Proved +
Probable
Proved
Probable
Proved +
Probable
January 1, 2012(1)
133,910
67,112
201,022
281,031
143,747
424,778
Discoveries
197
50
247
98
27
125
Extensions and Improved Recovery
17,290
12,247
29,536
35,039
26,295
61,334
Technical Revisions
21,737
139
21,876
25,287
(7,594)
17,693
Acquisitions
66,872
34,132
101,004
101,268
47,616
148,884
Dispositions
(13,369)
(5,042)
(18,411)
(2,876)
(1,060)
(3,936)
Economic Factors
(3,715)
(1,318)
(5,033)
(3,332)
(607)
(3,939)
Production
(19,868)
-
(19,868)
(36,143)
-
(36,143)
December 31, 2012(2)
203,053
107,319
310,373
400,373
208,424
608,797

Notes:
(1)
The Corporation has no unconventional reserves (Bitumen, Synthetic Crude Oil, Natural Gas from Coal, Natural Gas from Hydrates, Shale Oil, Shale Gas, etc.).
(2)
Numbers may not add due to rounding.
 
Undeveloped Reserves
 
The following discussion generally describes the basis on which we attribute Proved and Probable undeveloped reserves. Our plans for developing our undeveloped reserves are described in the section "Major Oil and Gas Properties".
 
 
- 26 -

 
 
Proved Undeveloped Reserves
 
Proved undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. In addition, such reserves may relate to planned infill drilling locations. The majority of these reserves are planned to be on stream within a three year timeframe. The following table provides the timing of the initial reserve assignments for the Corporation's gross Proved undeveloped reserves.
 
Timing of Initial Proved Undeveloped Reserve Assignment
 
 
Light & Medium Oil
(Mbbl)
Heavy Oil (Mbbl)
Natural Gas (MMcf)
Natural Gas Liquids
(Mbbl)
Oil Equivalent (Mboe)
 
First
Attributed(1)
Total at
Year-End
First
Attributed(1)
Total at
Year-End
First
Attributed(1)
Total at
Year-End
First
Attributed(1)
Total at
Year-End
First
Attributed(1)
Total at
Year-End
2009
15,495
62,431
-
122
9,113
30,012
745
3,551
17,758
71,106
2010
18,581
96,980
-
125
19,269
44,347
1,317
4,885
23,110
109,381
2011
27,772
108,221
145
226
15,260
51,273
1,201
5,407
31,662
122,399
2012
49,472
152,248
183
347
33,277
87,807
1,636
7,640
56,836
174,869

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, infill drilling locations and lands contiguous to production. The majority of these reserves are planned to be on stream within a five year timeframe. The following table provides the timing of the initial reserve assignments for the Corporation's Probable undeveloped gross reserves.
 
Timing of Initial Probable Undeveloped Reserves Assignment
 
 
Light & Medium Oil
(Mbbl)
Heavy Oil (Mbbl)
Natural Gas (MMcf)
Natural Gas Liquids
(Mbbl)
Oil Equivalent (Mboe)
 
First
Attributed(1)
Total at
Year-End
First
Attributed(1)
Total at
Year-End
First
Attributed(1)
Total at
Year-End
First
Attributed(1)
Total at
Year-End
First
Attributed(1)
Total at
Year-End
2009
22,743
47,301
-
167
10,976
15,868
1,090
2,013
25,663
52,127
2010
18,115
69,189
39
212
12,675
26,143
734
2,511
21,000
76,270
2011
22,493
73,204
137
295
11,870
32,184
673
2,726
25,281
81,589
2012
42,350
109,275
63
322
26,525
60,957
1,341
4,432
48,175
124,188

Note:
(1)           "First attributed" refers to reserves first attributed at year end of the corresponding fiscal year.
 
Significant Factors or Uncertainties Affecting Reserves Data
 
The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions. Our reserves are evaluated by GLJ and Sproule, each an independent engineering firm.
 
As circumstances change and additional data become available, reserve estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental regulations.
 
Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from changes in year end oil and gas prices, and reservoir performance. Such revisions can be either positive or negative.
 
 
- 27 -

 
 
Future Development Costs
 
The table below sets out the development costs deducted in the estimation of future net revenue attributable to total Proved reserves and total Proved plus Probable reserves (using forecast prices and costs).
 
Company Annual Capital Expenditures (M$)
                                  Canada
US
Total
Year
Total Proved
Total Proved
Plus Probable
Total Proved
Total Proved Plus Probable
Total
Proved
Total Proved Plus Probable
2013
1,002,620
1,320,447
284,982
357,162
1,287,602
1,677,609
2014
881,536
1,141,673
238,911
314,902
1,120,447
1,456,575
2015
573,033
755,478
126,778
229,495
699,811
984,972
2016
739,395
890,810
13,087
51,861
752,482
942,671
2017
399,222
554,693
-
4,027
399,222
558,720
2018
5,104
8,207
-
-
5,104
8,207
2019
6,352
5,936
-
-
6,352
5,936
2020
6,604
5,020
-
-
6,604
5,020
2021
3,371
4,295
-
-
3,371
4,295
2022
6,518
6,489
-
-
6,518
6,489
2023
4,611
3,360
-
-
4,611
3,360
2024
3,475
3,815
-
-
3,475
3,815
Subtotal(1)
Remainder
3,631,841
32,742
4,700,223
36,138
663,758
-
957,446
-
4,295,599
32,742
5,657,669
36,138
Total(1)
10% Discounted
3,664,583
2,984,444
4,736,362
3,867,882
663,758
588,078
957,446
834,104
4,328,341
3,572,522
5,693,807
4,701,986
 
 
Note:
(1)       Numbers may not add due to rounding.
 
Company Annual Abandonment Costs (M$)
                                Canada
US
Total
Year
Total Proved
Total Proved
Plus Probable
Total Proved
Total Proved Plus Probable
Total Proved
Total Proved Plus Probable
2013
4,824
4,447
1,594
1,422
6,418
5,869
2014
1,741
1,267
418
194
2,159
1,461
2015
2,575
1,555
233
70
2,808
1,625
2016
3,950
2,884
381
304
4,331
3,188
2017
3,579
2,435
134
54
3,713
2,489
2018
4,488
3,238
107
70
4,595
3,308
2019
5,616
3,293
11
58
5,627
3,351
2020
4,717
3,053
204
113
4,921
3,165
2021
7,170
4,957
153
260
7,324
5,217
2022
5,796
3,617
659
167
6,456
3,784
2023
8,877
5,555
372
286
9,249
5,842
2024
7,505
4,699
433
342
7,938
5,040
Subtotal(1)
Remainder
60,837
234,199
41,000
318,152
4,701
29,966
3,340
43,619
65,537
264,165
44,339
361,771
Total(1)
10% Discounted
295,036
65,525
359,152
53,335
34,666
6,314
46,958
4,977
329,702
71,839
406,110
58,312
 
 
Note:
(1)       Numbers may not add due to rounding.
 
We estimate that our internally generated cash flow will be sufficient to fund the future development costs ("FDC") disclosed above. We typically have available three sources of funding to finance our capital expenditure program: internally generated cash flow from operations, debt financing when appropriate and new equity issues (including proceeds from our DRIP), if available on favourable terms. Debt financing is available to us at market rate plus an applicable margin based on our debt to cash flow ratio. The current rate available to us under prime loan drawdowns, is 3.60% per annum. We expect to fund our total 2013 capital program with internally generated cash flow and, although quarterly fluctuations in funding levels are expected, our objective is to maintain our current net debt level throughout 2013. Our objective is to maintain our net debt to cash flow ratio at 1.0 times estimated future annual cash flows.
 
Major Oil and Gas Properties
 
The following is a description of the Corporation's major oil and natural gas properties, plants, facilities and installations in which we have an interest and that are material to our operations and activities. The production numbers stated refer to our working interest share before deduction of Crown and freehold royalties. Unless otherwise noted, reserve amounts are stated before deduction of royalties, based on escalating cost and price assumptions as evaluated in the Crescent Point Reserve Report as at December 31, 2012.
 
 
- 28 -

 
 
Crescent Point has continued to focus on the development of large resource play assets in Canada and the United States. The properties discussed below account for a majority of the reserve bookings prepared by GLJ and Sproule for year-end 2012, and are representative of the high quality assets in the Corporation’s portfolio.
 
CANADA
 
Viewfield Bakken
 
Crescent Point spent $432 million, or 29 percent of its 2012 capital development program on its Bakken light oil resource property in southeast Saskatchewan. The Corporation continued to advance its holdings in this play through development and exploration drilling, as well as expanding its waterflood operations. In 2012, the Corporation drilled 150.6 net Bakken wells and further expanded its gas-gathering and processing infrastructure. Oil transportation infrastructure was also diversified with the installation of facilities creating the ability to ship up to 45,000 bbl/d by rail, which represents more than one third of the Corporation's yearly average production guidance for 2013.
 
In 2012, Proved plus Probable reserves grew from 187.1 MMboe to 212.2 MMboe, representing a 13 percent increase over year-end 2011. Technical and development Proved plus Probable reserve additions totaled 28 MMboe in 2012. Since acquiring the property in early 2007, the Corporation has added approximately 175 MMboe of positive Proved plus Probable technical and development reserves; achieved through continual improvement of drilling and completion techniques, as well as successful step-out and infill drilling. We believe this illustrates the tendency of large oil in place pools to outperform over time. The Corporation has 1,140 net locations booked to reserves as of year-end 2012, up from 1,090 locations at year-end 2011.
 
By year-end 2012, the Corporation had converted a total of 46 producing wells to water injection wells in the Bakken oil resource play. The Corporation is also proceeding with unitization agreements with the goal to implement unit-wide waterflood programs. We believe that Bakken waterflood pilots continue to demonstrate that this resource is capable of successfully producing under secondary recovery. As more injection patterns are established, we expect that the waterflood should add significant proven reserves, with the potential to materially reduce our overall corporate decline rate.
 
Crescent Point expects to continue to spend significant capital in 2013 in the Bakken area, as a part of its ongoing strategic development of the play. The Corporation's total capital budget for the area is approximately $510 million for 2013; this includes drilling approximately 178 net wells and spending approximately $65 million for land, seismic and facilities. As in years past, this program should set the Corporation up for continued success through the expansion and diversification of facilities, expanded waterflood pilots and the planned development of a large drilling inventory.
 
Shaunavon
 
In 2012, Crescent Point maintained the momentum started in 2011 and continued with the successful development of the play by exploiting the Upper and Lower Shaunavon zones and improving the overall efficiency of field operations. In addition, Crescent Point further solidified its asset base in the area by acquiring three operated legacy units and one non-operated unit. These units are legacy assets with large oil-in-place, low-decline production and, we believe, significant reserves upside through the application of infill drilling, waterflood optimization and Alkaline Surfactant Polymer ("ASP") flooding.
 
 
- 29 -

 
 
The Corporation spent approximately $256 million of its 2012 capital budget in the Shaunavon area. This included successfully drilling 66.7 net Shaunavon wells with 100 percent success. A total of 13 infill locations were drilled in 2012, including 9 wells drilled at a spacing of 8 wells per section and 2 wells drilled at a spacing of 16 wells per section in the Lower Shaunavon and 2 infill wells drilled at 8 wells per section in the Upper Shaunavon. The current 8-well per section infill wells that are on production in the Lower Shaunavon continue to perform at rates similar to the original offsets. These successful pilots have provided encouragement for the Corporation to perform additional downspacing in the future. At the end of the second quarter of 2012, gas conservation commenced with the commissioning of the 6 MMcf/d capacity gas plant. As of December 2012, Crescent Point's Shaunavon production had grown to almost 17,500 boe/d, which represents an increase of approximately 59 percent over December 2011 production rates. As well, in the third quarter of 2012 the Dollard rail-loading facility was commissioned with an initial capacity of 4,000 bbl/d. This has allowed the transportation of crude oil out of the area, accessing markets which were inaccessible utilizing only pipeline.
 
Since the original Shaunavon acquisition in 2009, the Corporation has added approximately 48 MMboe of positive Proved plus Probable technical and development reserves. The Corporation has 766 net locations booked to reserves as of year-end 2012, up from 519 locations at year-end 2011. As of year-end 2012, Crescent Point had booked Proved plus Probable reserves of 145.9 MMboe in the Shaunavon area, including approximately 15 MMboe due to positive technical and development reserve additions in 2012.
 
In 2012, Crescent Point continued to focus on waterflood implementation by increasing the number of water injectors in the play. By year-end 2012, there were eight horizontal injection wells in the Lower Shaunavon zone. The Corporation expanded its water injector count in the Upper Shaunavon through both acquisitions and additional conversions, closing out the year with 22 active injectors. In the Lower Shaunavon, Crescent Point has submitted a request for approval from the Government of Saskatchewan for an operating Unit agreement in which it will apply for a waterflood project. The Corporation plans to continue to expand the waterfloods within the Lower and Upper Shaunavon zones throughout 2013.
 
For 2013, Crescent Point expects to spend $283 million of its capital budget in the Shaunavon area. The Corporation expects to drill approximately 89 net Shaunavon wells and spend more than $46 million on land, seismic and facilities. The facility capital includes the planned expansion of crude oil gathering systems and the upgrading of key crude oil batteries, as well as the expansion of the Dollard rail facility to a capacity of 10,000 bbl/d. These facility expenditures are expected to accommodate both current and future growth in production volumes.
 
Swan Hills
 
In 2012, Crescent Point was highly active in the Swan Hills Beaverhill Lake light oil resource play participating in the drilling of 20.2 net locations. As of December 2012, Crescent Point had 27.6 net wells placed on production within the resource play. The producing day average initial gross 30 day rate for those wells exceeds 550 boe/d per well.
 
Crescent Point has increased average annual production in the area from zero in 2010 to approximately 950 boe/d in 2011 and to approximately 3,250 boe/d in 2012. This represents an increase in production of greater than 240% since 2011. Through continued Crown land sales, farm-ins and acquisitions, Crescent Point expanded its land holdings in the Swan Hills area. At year-end 2012, the Corporation had over 13 MMboe of Proved plus Probable reserves and has 31 net locations booked by independent engineers.
 
Crescent Point, along with their partners, have constructed and commissioned 2 batteries which allow for the conservation of associated liquids rich gas and reduce crude oil trucking costs in the area.
 
With the Corporation's positive results to-date in the Beaverhill Lake light oil resource play, Crescent Point plans to spend approximately $77 million in the area in 2013, drilling up to 11 net wells and commencing a waterflood pilot with our partners.
 
Alliance
 
In June 2012, Crescent Point materially expanded its holdings in the Alliance area through the acquisition of Cutpick. The acquired assets include more than 300 net sections of land in the Alliance area. In 2012, Crescent Point drilled 20 net wells in the Alliance area, further delineating the play. With this successful drilling program, Crescent Point added eight net sections of prospective Viking light oil to the 83 net sections recognized at the time of the acquisition. At year-end 2012, 19.5 MMboe of Proved plus Probable reserves and 163 net locations were recognized by independent engineers.
 
 
- 30 -

 
 
Crescent Point is currently evaluating a waterflood pilot within the field, which was commissioned in August 2011 with a single water injection well. A second injector was added to the pilot in September 2012. In addition, a historical waterflood pilot began in the area in 1998. Crescent Point is encouraged by both historical waterflood response and initial response from the current pilot. Additional injectors in the current pilot and a separate waterflood pilot area are planned for 2013.
 
In early January 2013, Crescent Point’s Alliance rail loading facility commenced operations. This transportation infrastructure provides us with marketing flexibility through the ability to move a substantial portion of area volumes by rail.
 
Up to $63 million in expenditures are planned for 2013, including $50 million for the drilling of up to 30 net wells, as well as $13 million for infrastructure, land, seismic and optimization projects.
 
Battrum and Cantuar
 
In 2012 Crescent Point continued to enhance production and reserves in Battrum through waterflood optimization, infill drilling and recompletions. This resulted in the corporation achieving record monthly production levels of more than 3,000 boe/d in November 2012. Since acquiring the Battrum property in early 2006, the Corporation has increased Proved plus Probable reserves in the three area units from 5.6 MMboe to a total of 17.1 MMboe at year-end 2012. During this same period, Crescent Point has had similar success in Cantuar increasing Proved plus Probable reserves in the Cantuar unit from 9.7 MMboe to a total of 15.9 MMboe at year-end 2012. For 2012, production in the Cantuar area averaged over 2,050 boe/d. These are two legacy assets within the Corporation that have produced year over year positive reserve additions.
 
The Corporation plans to continue to focus on production optimization projects and infill drilling in 2013, with plans to drill up to 5 net oil wells in Battrum and 8 net oil wells in Cantuar.
 
UNITED STATES
 
North Dakota
 
The Corporation initially entered the United States in 2009 through an asset acquisition of certain core southeast Saskatchewan assets that included an exploratory acreage position in Daniels County, Montana. In 2011, the Corporation completed two acquisitions of approximately 750 boe/d of Bakken light oil production and more than 78 net sections of land in North Dakota. The Corporation continues to believe the land is prospective for the lower-risk Bakken and Three Forks zones. Through this series of acquisitions combined with an active leasing program throughout 2010 and 2011, the Corporation established a land position of over 140 net sections in the North Dakota and Montana Bakken/Three Forks play. In 2011 the Corporation successfully drilled its first operated horizontal Bakken well in North Dakota and in total drilled 3.5 net Bakken/Three Forks operated wells during the year.
 
In 2012, Crescent Point continued its operated drilling program in both Divide and Williams Counties. The Corporation continued to focus primarily on the Bakken formation where 10.2 net wells were drilled. The Corporation also proved the multi-zone resource potential on their land in both counties by drilling 8.4 net wells into the deeper Three Forks formation. Through the implementation of drilling and completion techniques developed in the Corporation’s southeast Saskatchewan Bakken assets, well performance has exceeded expectations in 2012. As a result, Proved plus Probable reserves grew from 7.7 MMboe at year-end 2011, to 23.5 MMboe by year-end 2012, representing a 205 percent increase over year-end 2011. Technical and development Proved plus Probable reserve additions totaled 17.2 MMboe in 2012. The Corporation has 43 net locations booked to reserves as of year-end 2012, up from 14 locations at year-end 2011.
 
 
- 31 -

 
 
For 2013, Crescent Point plans to spend approximately $47 million, including approximately $6 million for land to hold and expand its current operated position in Williams County.
 
Utah
 
In 2012, through the acquisition of Ute, the Corporation became active in the Uinta Basin in northeast Utah; a multi-zone, large oil-in-place light oil resource play. With this purchase, Crescent Point acquired 7,800 boe/d and approximately 270 net sections of land in the center of this expansive resource play with a plan to exploit the upside of this multi-zone play through the application of vertical and horizontal drilling, multi-stage fracture stimulations and potential waterflood implementation.
 
In late 2012, following the closing of the Ute acquisition, the Corporation successfully drilled 3.4 net Green River/Wasatch vertical wells in Randlett field. Proved plus Probable reserves at year-end 2012 total 56.9 MMboe with 274 net locations booked to-date, and we believe there is potential for strong follow-up drilling and booking opportunities.
 
For 2013, Crescent Point plans to spend $195 million in the area, with $185 million allocated to drilling and completion operations throughout the basin. A total of 74 net wells are expected to be drilled in 2013.
 
Both North Dakota and Utah assets will be managed through the Corporation’s Denver office.
 
Oil and Gas Wells
 
Producing Wells
Area
  Oil
Gas
 
Gross
Net
Gross
Net
CANADA
       
Southeast Saskatchewan and  Manitoba
4,214
2,367
-
-
Southwest Saskatchewan
1,351
1,064
30
20
South/Central Alberta and West Central SK
746
529
343
237
Northeast B.C./Peace River Arch
43
38
30
27
TOTAL CANADA
6,354
3,998
403
284
U.S.
       
North Dakota and Montana
143
37
5
4
Utah
528
243
2
1
TOTAL U.S.
671
280
7
5
Total
7,025
4,278
410
289


Non-Producing Wells
Area
  Oil
Gas
 
Gross
Net
Gross
Net
CANADA
       
Southeast Saskatchewan and  Manitoba
68
56
-
-
Southwest Saskatchewan
38
37
-
-
South/Central Alberta and West Central SK
12
9
3
3
Northeast B.C./Peace River Arch
-
-
1
0
         TOTAL CANADA
118
102
4
3
U.S.
       
North Dakota and Montana
-
-
-
-
Utah
-
-
-
-
        TOTAL U.S.
-
-
-
-
Total
118
102
4
3
 
All of the Corporation's oil and gas wells are onshore.
 
 
- 32 -

 
 
Properties With No Attributed Reserves
 
The following table summarizes the gross and net acres of unproved properties in which we have an interest and also the number of net acres for which our rights to develop or exploit will, absent further action, expire within one year.
 
As of December 31, 2012
 
 
Gross Acres
 
Net Acres
Net Acres Expiring
Within One Year
CANADA
     
Alberta
1,425,624
1,246,793
850,362
Saskatchewan
1,394,913
1,264,832
212,303
Manitoba
181,037
176,623
33,596
Total
3,001,574
2,688,248
1,096,261
U.S.
     
Montana
392,819
264,847
7,458
North Dakota
130,076
85,592
44,229
Utah
337,202
137,849
27,981
Total
860,097
488,288
79,668
Total
3,861,671
3,176,536
1,175,929

The Corporation has no drilling commitments relating to unproved properties.
 
Drilling Activity
 
The following table summarizes the gross and net exploration and development wells in which we participated during the year ended December 31, 2012, in each of Canada and the United States.
 
 
Development Wells
Exploration Wells
Total Wells
 
Gross
Net
Gross
Net
Gross
Net
CANADA
           
Oil wells
404
296.1
60
48.1
464
344.2
Natural Gas wells
1
0.4
1
1.0
2
1.4
Service wells
-
-
-
-
-
-
Dry Holes
1
1.0
-
-
1
1.0
Total
406
297.5
61
49.1
467
346.6

 
Development Wells
Exploration Wells
Total Wells
 
Gross
Net
Gross
Net
Gross
Net
U.S.
           
Oil wells
87
18.3
7
3.7
94
22.0
Natural Gas wells
-
-
-
-
-
-
Service wells
1
0.4
-
-
1
0.4
Dry Holes
-
-
-
-
-
-
Total
88
18.7
7
3.7
95
22.4

For details on the most important current and likely exploration and development activities during 2012, see "Statement Of Reserves Data And Other Oil And Gas Information – Major Oil and Gas Properties".
 
The Corporation's work commitments for its proved properties (including drilling commitments and the two-year service agreement with a leading U.S. fracture stimulation company expiring December 31, 2013) and timing are as follows:
 
($000's)
       
 
Total
2013
2014
2015
Canada
420
420
-
-
U.S.
59,694
59,694
-
-
TOTAL
60,114
60,114
-
-

Additional Information Concerning Abandonment and Reclamation Costs
 
We estimate well abandonment costs area by area. Such costs are assigned to the reserve wells in the Crescent Point Reserve Report and are included as deductions in arriving at future net revenue. The expected total abandonment costs included in the Corporation's Engineering Report for an estimated 6,918 net wells under the Proved reserves category is $329.7 million undiscounted ($71.8 million discounted at 10%), of which a total of $11.4 million is estimated to be incurred in 2013, 2014 and 2015.
 
 
- 33 -

 
 
Tax Horizon
 
Crescent Point has tax pools of approximately $8.5 billion at December 31, 2012 to shelter future taxable income. Including the impact of income from the Partnership for the year ended December 31, 2012, the net tax pools remaining are approximately $7.8 billion. Based on this pool balance and the forecast of cash flows using approximately US$ 94.00 WTI in 2013, approximately US$ 95.00 in 2014, a 1.00 US$/Cdn$ exchange rate and 2% inflation, with a 2013 capex budget of $1.2 billion, Crescent Point does not expect to be taxable until 2015.
 
Costs Incurred(1)
 
The following table summarizes our property acquisition costs, exploration costs and development costs for the year ended December 31, 2012. The total capital costs were approximately $4.5 billion in 2012.
 
($000's)
Acquisition Costs
 
Proved Properties
Unproved Properties
Exploration Costs
Development Costs
Canada
1,981,851
179,405
153,788
1,060,068
U.S.
626,363
233,611
63,967
211,124
Total
2,608,214
413,016
217,755
1,271,192
Note:
(1)           Costs incurred exclude capitalized administration.

Production Estimates
 
The following table discloses for each product type the gross volume of production estimated by GLJ and Sproule for 2013 in the estimates of future net revenue with forecast pricing from Proved reserves disclosed above under the heading "Reserves Data - Forecast Prices and Costs".
 
Region
Light and Medium
Crude Oil
Heavy Crude Oil
Natural Gas
NGLs
Total
 
(bbl/d)
(bbl/d)
(Mcf/d)
(bbl/d)
(boe/d)
CANADA
         
Southeast Saskatchewan and  Manitoba
59,966
-
29,052
4,859
69,667
Southwest Saskatchewan
28,788
201
7,626
141
30,401
South/Central Alberta and West Central SK
8,025
842
24,724
355
13,343
Northeast B.C./Peace River Arch
840
-
4,851
117
1,765
Total CANADA(1)
97,619
1,042
66,253
5,471
115,175
U.S.
         
North Dakota and Montana
4,255
-
1,689
354
4,890
Utah
8,883
-
7,802
83
10,267
Total U.S.
13,138
-
9,491
437
15,157
Total(1)
110,757
1,042
75,744
5,908
130,331
Note:
(1)           Numbers may not add due to rounding.

Production in southeast Saskatchewan and Manitoba and southwest Saskatchewan accounts for 53% and 23%, respectively, of the Corporation's Proved production estimate in 2013.
 
 
- 34 -

 
 
The following table discloses for each product type the gross volume of production estimated by GLJ and Sproule for 2013 in the estimates of future net revenue with forecast pricing from Proved plus Probable reserves disclosed above under the heading "Reserves Data - Forecast Prices and Costs".
 
Region
Light and Medium
Crude Oil
Heavy Crude Oil
Natural Gas
NGLs
Total
 
(bbl/d)
(bbl/d)
(Mcf/d)
(bbl/d)
(boe/d)
CANADA
         
Southeast Saskatchewan and  Manitoba
71,111
-
34,452
5,787
82,639
Southwest Saskatchewan
34,910
205
9,477
176
36,871
South/Central Alberta and West Central SK
9,995
967
28,768
450
16,206
Northeast B.C./Peace River Arch
986
-
5,647
127
2,054
Total CANADA(1)
117,002
1,172
78,345
6,539
137,770
U.S.
         
North Dakota and Montana
6,575
-
2,325
544
7,507
Utah
10,137
-
8,542
88
11,649
Total U.S.
16,713
-
10,868
632
19,156
Total(1)
133,715
1,172
89,213
7,170
156,925
Note:
(1)           Numbers may not add due to rounding
 
Production in southeast Saskatchewan and Manitoba and southwest Saskatchewan accounts for 53% and 23%, respectively, of the Corporation's total Proved plus Probable production estimate in 2013.
 
Production History
 
The following table discloses, on a quarterly and annual basis for the year ended December 31, 2012, our share of average daily production volume (prior to deducting royalties), and the prices received, royalties, production costs and transportation costs incurred and netbacks on a per unit of volume basis for each product type.
 
Average Daily Production Volume(1)
 
 
Three Months Ended
Year Ended
 
March 31, 2012
June 30, 2012
Sept. 30, 2012
Dec. 31, 2012