Crescent Point Replaces 315 Percent of 2015 Production, Increases Reserves by 16 Percent and Generates $9.83 Per boe Finding and Development Costs

March 9, 2016 4:30 AM

CALGARY, ALBERTA–(Marketwired – March 9, 2016) –

(All financial figures are approximate and in Canadian dollars unless otherwise noted)

Crescent Point Energy Corp. (“Crescent Point” or the “Company”) (TSX:CPG) (NYSE:CPG) is pleased to announce the results of its year-end 2015 reserves evaluation. Crescent Point’s reserves were independently evaluated by GLJ Petroleum Consultants Ltd. (“GLJ”) and Sproule Associates Limited (“Sproule”) as at December 31, 2015.

2015 RESERVES HIGHLIGHTS

In 2015, Crescent Point generated its 14^th consecutive year since inception of strong organic reserves additions. During the year, the Company invested approximately $1.56 billion into the development and expansion of its asset base, including funds invested in facilities, land and seismic. The Company added more than 65 million boe (“MMboe”) of Proved plus Probable (“2P”) reserves, excluding reserves added through acquisitions, and generated Finding and Development (“F&D”) costs of $9.83 per 2P boe, including changes in future development capital (“FDC”). This represents a recycle ratio of 2.6 times based on the Company’s 2015 average operating netback prior to realized derivatives of $25.43 per boe.

Crescent Point’s reserves additions in 2015 included significant additions at the Flat Lake, Viking, North Dakota Bakken, and Uinta resource plays, as well as reserves additions attributed to the waterfloods in each of the Viewfield Bakken and Shaunavon tight rock resource plays.

Including acquisitions in 2015, Crescent Point replaced 315 percent of production and increased 2P reserves by 128 MMboe to 935.7 MMboe. This represents year over year growth of approximately 16 percent. The Company generated Finding, Development and Acquisition (“FD&A”) costs of $18.77 per 2P boe, including changes in FDC, for a recycle ratio of 1.4 times.

“2015 was another strong year that demonstrated the strength of our asset base and our technical teams,” said Scott Saxberg, president and CEO of Crescent Point. “We grew reserves on a per share basis and replaced our 2015 annual production by over 300 percent. Since inception, we have added approximately 578 MMboe of 2P reserves, which equates to 62 percent of our year-end 2015 2P reserves. We are well positioned in the current environment and have an excellent long-term set of growth opportunities due to our high-quality asset base, large drilling inventory and low recovery to date.”

2P HIGHLIGHTS

Replaced 315 percent of production and increased 2P reserves by 16 percent to 935.7 MMboe (91 percent oil and liquids);
Generated a before tax 2P Net Asset Value (“NAV”) of $26.49 per fully diluted share, discounted at 10 percent;
Added 65.0 MMboe of reserves, excluding reserves added through acquisitions, generating 2P F&D of $9.83 per boe, including changes in FDC. This represents a recycle ratio of 2.6 times;
Replaced 109 percent of production on a 2P basis, excluding reserves added through acquisitions, highlighting the success of the Company’s long-term development focus and the advancement of its resource plays;
Increased reserve life index to 15.5 years, up from 14.5 years at year-end 2014, based on annual average production guidance as at March 9, 2016 and January 6, 2015 respectively;
Reduced FDC, excluding acquisitions, by $922.1 million on a 2P basis, reflecting the Company’s cost reduction initiatives in 2015. The Company expects that costs will continue to fall in the current low oil price environment, which could lead to future reductions in the Company’s FDC;
Generated a five-year weighted average F&D cost, including land, facility and seismic expenditures and excluding changes in FDC, of $20.39 per 2P boe. This represents a five-year weighted average recycle ratio of 2.2 times, based on the Company’s five-year weighted average operating netback prior to realized derivatives of $44.47 per boe. This highlights the high netbacks of the Company’s asset base, as well as the Company’s technical ability to efficiently add value to its large oil-in-place assets;
Added approximately 4.5 MMboe of 2P reserves attributed to waterflood at the Shaunavon and Viewfield tight rock plays. This represents the third consecutive year of waterflood reserves recognized by independent evaluators at Viewfield. Crescent Point’s waterflood activities continue to expand providing the opportunity for future reserve growth at attractive F&D costs.
Internally identified approximately 14 years of drilling inventory based on approximately 7,700 net drilling locations. A total of 2,378 net locations are booked as 1P and 3,683 net locations are booked as 2P in the independent evaluator’s report. The remaining net locations of approximately 4,000 are internally identified locations that are unbooked. Crescent Point’s unbooked drilling locations provide the opportunity for future reserves and NAV growth;

1P HIGHLIGHTS

Replaced 207 percent of production and increased Proved (“1P”) reserves by 12 percent to 592.1 MMboe (91 percent oil and liquids);
Generated a before tax 1P NAV of $15.89 per fully diluted share, discounted at 10 percent;
1P reserves accounted for 63 percent of total 2P reserves;
Added 50.2 MMboe of positive reserves, generating 1P F&D of $13.97 per boe, including changes in FDC. This represents a recycle ratio of 1.8 times.

PDP HIGHLIGHTS

Replaced 195 percent of production and increased Proved Developed Producing (“PDP”) reserves by approximately 18 percent to 363.0 MMboe (91 percent oil and liquids). This represents reserves per fully diluted share growth of 4.8 percent;
Generated a before tax PDP NAV of $10.88 per fully diluted share, discounted at 10 percent;
Added 67.0 MMboe of positive reserves, generating PDP F&D of $22.67 per boe, including changes in FDC. This represents a recycle ratio of 1.1 times.

2015 YEAR-END RESERVES

Crescent Point’s reserves were independently evaluated by GLJ and Sproule as at December 31, 2015, and were aggregated by GLJ. The reserves evaluation and reporting was conducted in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGEH”) and – National Instrument 51-101 Standards for Disclosure of Oil and Gas Activities (“NI 51-101”).

Summary of Reserves

As at December 31, 2015 ^{(1) (2) (3)}

	Tight Oil ⁽⁴⁾ (Mbbls)		Light and Medium Oil (Mbbls)		Heavy Oil (Mbbls)		Natural Gas Liquids (Mbbls)
Reserves Category	Company Gross	Company Net	Company Gross	Company Net	Company Gross	Company Net	Company Gross	Company Net
Proved Developed Producing	160,093	144,622	113,630	98,885	22,106	19,645	34,211	30,377
Proved Developed Non-Producing	5,465	4,979	4,856	4,291	282	256	1,158	1,032
Proved Undeveloped	129,664	115,947	45,641	41,462	2,104	1,738	18,740	16,424
Total Proved ⁽⁶⁾	295,222	265,548	164,127	144,638	24,492	21,639	54,109	47,834
Total Probable	178,066	157,477	99,230	86,158	8,356	7,145	28,646	25,070
Total Proved plus Probable ⁽⁶⁾	473,288	423,025	263,356	230,796	32,847	28,784	82,755	72,904

	Shale Gas ⁽⁵⁾(MMcf)		Conventional Natural Gas (MMcf)		Total (Mboe)
Reserves Category	Company Gross	Company Net	Company Gross	Company Net	Company Gross	Company Net
Proved Developed Producing	97,097	87,881	100,904	92,036	363,040	323,517
Proved Developed Non-Producing	2,663	2,460	5,312	4,640	13,091	11,741
Proved Undeveloped	91,605	79,489	27,061	25,044	215,926	192,993
Total Proved ⁽⁶⁾	191,365	169,831	133,278	121,719	592,056	528,251
Total Probable	107,277	94,251	68,532	62,224	343,599	301,929
Total Proved plus Probable ⁽⁶⁾	298,642	264,082	201,810	183,944	935,656	830,180

(1)	Based on Sproule’s December 31, 2015, escalated price forecast.
(2)	“Gross Reserves” are the total Company’s interest share before the deduction of any royalties and without including any royalty interest of the Company.
(3)	“Net Reserves” are the total Company’s interest share after deducting royalties and including any royalty interest.
(4)	Volumes reported as “Tight Oil” under revised guidelines previously would have been reported as “Light & Medium Oil” based on product quality. These volumes are now considered “Tight Oil” due to reservoir characteristics as well as drilling and completion techniques.
(5)	Volumes reported as “Shale Gas” under revised guidelines relate to gas volumes that have been produced in association with “Tight Oil” or as non-associated shale gas volumes. These volumes would have previously been reported as “Associated and Non-Associated Gas”.
(6)	Numbers may not add due to rounding.

Summary of Before and After Tax Net Present Values

As at December 31, 2015 ⁽¹⁾

	Before Tax Net Present Value ($ millions)					After Tax Net Present Value ($ millions)
	Discount Rate					Discount Rate
Reserves Category	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%
Proved Developed Producing	12,615	9,295	7,367	6,113	5,236	11,864	8,851	7,086	5,926	5,106
Proved Developed Non-Producing	414	317	252	207	175	285	222	179	149	126
Proved Undeveloped	5,626	3,545	2,300	1,515	997	4,228	2,605	1,629	1,016	612
Total Proved ⁽²⁾	18,654	13,157	9,919	7,836	6,409	16,376	11,677	8,894	7,090	5,844
Total Probable	13,972	8,144	5,392	3,859	2,908	9,954	5,774	3,804	2,710	2,032
Total Proved plus Probable ⁽²⁾	32,626	21,301	15,311	11,695	9,317	26,330	17,452	12,698	9,799	7,876

(1)	Based on Sproule’s December 31, 2015, escalated price forecast.
(2)	Numbers may not add due to rounding.

Before Tax Net Asset Value per Share, Fully Diluted, Utilizing Independent Engineering, Escalated Pricing

	2015 ^{(1) (2) (3)}	2014	2013	2012	2011	2010	2009	2008	2007	2006
PV 0%	$60.55	$75.33	$75.69	$68.39	$71.39	$71.38	$72.01	$80.66	$61.03	$34.08
PV 5%	$38.28	$48.62	$51.04	$46.49	$49.81	$47.65	$46.91	$49.30	$40.21	$21.61
PV 10%	$26.49	$34.74	$38.13	$35.11	$38.42	$36.02	$35.08	$34.97	$30.05	$15.70
PV 15%	$19.37	$26.41	$30.25	$28.15	$31.35	$29.10	$28.27	$26.85	$24.04	$12.27

(1)	Based on Sproule’s December 31, 2015, escalated price forecast.
(2)	Based on 508.9 million shares fully-diluted.
(3)	Net debt of $4.3 billion as at December 31, 2015.

Reserves Reconciliation

Gross Reserves ^{(1) (2)}

	Tight Oil ⁽³⁾(Mbbls)						Light and Medium Oil (Mbbls)						Heavy Oil (Mbbls)
Factors	Proved		Probable		Proved plus Probable		Proved		Probable		Proved plus Probable		Proved		Probable		Proved plus Probable
January 1, 2015	287,378		158,576		445,954		138,739		72,935		211,673		27,616		8,097		35,713
Extensions and Improved Recovery	27,622		25,542		53,164		7,513		4,179		11,692		–		–		–
Technical Revisions	4,183		(19,465	)	(15,282	)	3,516		(2,986	)	530		(870	)	340		(530	)
Acquisitions	14,525		12,291		26,817		33,289		25,355		58,644		23		8		31
Dispositions	(58	)	(998	)	(1,056	)	(45	)	(14	)	(60	)	–		–		–
Economic Factors	(6,085	)	2,119		(3,966	)	(3,338	)	(239	)	(3,576	)	(160	)	(89	)	(249	)
Production	(32,343	)	–		(32,343	)	(15,546	)	–		(15,546	)	(2,117	)	–		(2,117	)
December 31, 2015 ⁽⁵⁾	295,222		178,066		473,288		164,127		99,230		263,356		24,492		8,356		32,847

	Natural Gas Liquids (Mbbls)					Shale Gas ⁽⁴⁾(MMcf)						Conventional Natural Gas (MMcf)
Factors	Proved		Probable	Proved plus Probable		Proved		Probable		Proved plus Probable		Proved		Probable		Proved plus Probable
January 1, 2015	36,594		18,713	55,307		155,663		80,038		235,701		71,124		45,613		116,737
Extensions and Improved Recovery	2,840		2,341	5,182		14,761		14,541		29,302		1,881		1,624		3,505
Technical Revisions	8,310		1,988	10,298		15,490		(9,509	)	5,982		20,921		1,156		22,076
Acquisitions	10,924		5,508	16,432		32,191		21,765		53,955		56,500		22,399		78,898
Dispositions	–		–	–		–		–		–		–		–		–
Economic Factors	(628	)	97	(531	)	(3,835	)	443		(3,392	)	(5,331	)	(2,259	)	(7,590	)
Production	(3,932	)	–	(3,932	)	(22,905	)	–		(22,905	)	(11,816	)	–		(11,816	)
December 31, 2015 ⁽⁵⁾	54,109		28,646	82,755		191,365		107,277		298,642		133,278		68,532		201,810

	Total Oil Equivalent (Mboe)
Factors	Proved		Probable		Proved plus Probable
January 1, 2015	528,124		279,262		807,386
Extensions and Improved Recovery	40,749		34,756		75,505
Technical Revisions	21,208		(21,515	)	(307	)
Acquisitions	73,543		50,523		124,066
Dispositions	(103	)	(1,012	)	(1,116	)
Economic Factors	(11,738	)	1,586		(10,152	)
Production	(59,725	)	–		(59,725	)
December 31, 2015 ⁽⁵⁾	592,056		343,599		935,656

(1)	Based on Sproule’s December 31, 2015, escalated price forecast.
(2)	“Gross reserves” are the Company’s working-interest share before deduction of any royalties and without including any royalty interests of the Company.
(3)	Volumes reported as “Tight Oil” under revised guidelines would have been previously reported as “Light & Medium Oil” based on product quality. These volumes are now are considered “Tight Oil” due to reservoir characteristics as well as drilling and completion techniques.
(4)	Volumes reported as “Shale Gas” under revised guidelines relate to gas volumes that have been produced in association with “Tight Oil” or as non-associated shale gas volumes. These volumes would have previously been reported as “Associated and Non-Associated Gas”.
(5)	Numbers may not add due to rounding.

Finding, Development and Acquisition Costs

	F&D	Change in FDC on F&D		F&D Total (incl. change in FDC)	FD&A ⁽¹⁾	Change in FDC on FD&A		FD&A Total (incl. change in FDC) ⁽¹⁾
Capital ($ millions) ⁽²⁾
Total Proved plus Probable	1,561.8	(922.1	)	639.7	3,435.2	93.0		3,528.2
Total Proved	1,561.8	(860.1	)	701.7	3,435.2	(396.9	)	3,038.3

Reserves (Mboe) ⁽³⁾
Total Proved plus Probable	65,046	–		65,046	187,996	–		187,996
Total Proved	50,219	–		50,219	123,659	–		123,659

(1)	FD&A is calculated by dividing the identified capital expenditures including acquisition costs by the applicable reserves additions. FD&A can include or exclude changes to future development capital costs.
(2)	The capital expenditures include the announced purchase price of corporate acquisitions rather than the amounts allocated to property, plant and equipment for accounting purposes. The capital expenditures also exclude capitalized administration costs and transaction costs.
(3)	Gross Company interest reserves are used in this calculation (working interest reserves, before deduction of any royalties and without including any royalty interests of the Company).

	Excluding changes in FDC			Including changes in FDC
	($/boe, except recycle ratios)			($/boe, except recycle ratios)
	2015	2014	3 Years Ended Dec. 31, 2015 (Weighted Avg.)	2015	2014	3 Years Ended Dec. 31, 2015 (Weighted Avg.)
F&D Cost ⁽¹⁾
Total Proved plus Probable	$24.01	$21.59	$21.04	$9.83	$22.11	$18.25
Total Proved	$31.10	$24.95	$26.05	$13.97	$24.75	$20.99

F&D Recycle Ratio ⁽¹⁾⁽²⁾
Total Proved plus Probable	1.1	2.4	2.0	2.6	2.4	2.3
Total Proved	0.8	2.1	1.6	1.8	2.1	2.0


FD&A Cost
Total Proved plus Probable	$18.27	$22.07	$19.88	$18.77	$27.30	$22.57
Total Proved	$27.78	$29.32	$27.64	$24.57	$33.56	$27.86

FD&A Recycle Ratio ⁽²⁾
Total Proved plus Probable	1.4	2.4	2.1	1.4	1.9	1.9
Total Proved	0.9	1.8	1.5	1.0	1.6	1.5

(1)	F&D is calculated by dividing the identified capital expenditures by the applicable reserves additions. F&D can include or exclude changes to future development capital costs.
(2)	Recycle Ratio is calculated as operating netback divided by F&D or FD&A costs. Based on a 2015 netback (prior to realized derivatives), of $25.43 per boe, a 2014 netback (prior to realized derivatives) of $52.43 per boe and a three-year weighted average netback (prior to realized derivatives) of $41.90 per boe.

Future Development Capital

At year-end 2015, FDC for 2P reserves totaled $7.0 billion compared to $6.9 billion at year-end 2014. Net of acquisitions, FDC at year-end 2015 declined $922.1 million reflecting the impact of the Company’s cost reduction initiatives and improved drilling efficiencies.

Company Annual Capital Expenditures ($ millions)
	Canada		US		Total
Year	Total Proved	Total Proved Plus Probable	Total Proved	Total Proved Plus Probable	Total Proved	Total Proved Plus Probable
2016	601	849	93	162	694	1,011
2017	757	1,168	187	328	944	1,497
2018	843	1,259	320	453	1,163	1,712
2019	587	1,101	218	354	805	1,455
2020	450	814	155	246	605	1,059
2021	8	11	91	126	99	137
2022	10	8	–	15	10	23
2023	7	6	–	–	7	6
2024	6	8	–	–	6	8
2025	9	6	–	2	9	7
2026	5	4	–	–	5	4
2027	4	6	–	–	4	6
Subtotal ⁽¹⁾	3,287	5,240	1,064	1,686	4,351	6,925
Remainder	54	62	–	–	54	62
Total ⁽¹⁾	3,341	5,302	1,064	1,686	4,405	6,987
10% Discounted	2,638	4,165	815	1,293	3,453	5,458

(1)	Numbers may not add due to rounding.

Corporate Base Decline Rate

Crescent Point has consistently increased production growth while lowering its corporate decline rate through waterflood development and disciplined capital programs. Since 2011, the Company has successfully lowered its corporate decline rate from 35 percent to an estimated 28 percent in 2016, a relative reduction of 20 percent. The Company expects an improvement in its 2017 corporate base decline rate through waterflood advancement and a prudent 2016 capital development program.

[expand title=”Advisories & Contact”]Definitions

Decline rate is the reduction in the rate of production from one period to the next. This rate is usually expressed on an annual basis.

Finding and development costs (F&D) is calculated by dividing the identified capital expenditures by the applicable reserves additions. F&D can include or exclude changes to future development capital costs.

Finding, development and acquisitions costs (FD&A) is calculated by dividing the identified capital expenditures including acquisition costs by the applicable reserves additions. FD&A can include or exclude changes to future development capital costs.

Future development capital (FDC) reflects the independent evaluator’s best estimate of the cost required to bring proved undeveloped and probable reserves on production. Changes in FDC can result from acquisition and disposition activities, development plans or changes in capital efficiencies due to improvements in service costs or drilling and completion methods.

Net asset value (NAV) is a snapshot in time as at year-end, and is based on the Company’s reserves evaluated using the independent evaluators forecast for future prices, costs and foreign exchange rates. The Company’s NAV is calculated on a before tax basis and is the sum of the present value of proved and probable reserves, the fair value for land and seismic, the fair value for the Company’s oil and gas hedges based on Sproule’s December 31, 2015 escalated price forecast, less outstanding net debt. The NAV per share is calculated on a fully diluted basis.

N1 51-101 means “National Instrument 51-101 – Standards for Disclosure for Oil and Gas Activities“.

Recycle Ratio is calculated as operating netback divided by F&D or FD&A costs. Based on a 2015 netback (prior to realized derivatives), of $25.43 per boe, a 2014 netback (prior to realized derivatives) of $52.43 per boe and a three-year weighted average netback (prior to realized derivatives) of $41.90 per boe.

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 the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Proved reserves are reserves estimated to have a high degree of certainty of recoverability. Probable reserves are less certain to be recoverable than probable reserves and possible reserves are less certain than probable reserves.

Reserve life index (RLI) is based upon dividing the appropriate year-end reserves category by the Company’s corresponding current year production guidance.

Reserves Data

The reserves information contained in this press release has been prepared in accordance with NI 51-101. Complete NI 51-101 reserves disclosure will be included in our Annual Information Form for the year ended December 31, 2015, which will be filed on or before March 9, 2016. Listed below are cautionary statements that are specifically required by NI 51-101.

Where applicable, a barrels of oil equivalent (“boe”) conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent (6Mcf:1bbl) has been used based on an energy equivalent conversion method primarily applicable at the burner tip. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.

This press release contains metrics commonly used in the oil and natural gas industry such as “netbacks,” and “reserve life index”. These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies and, therefore, should not be used to make such comparisons.

F&D costs, including changes in FDC have been presented in this news release because they provide a useful measure of capital efficiency. F&D costs, including land, facility and seismic expenditures and excluding changes in FDC have also been presented in this news release because they provide a useful measure of capital efficiency.

Management uses recycle ratio for its own performance measurements and to provide shareholders with measures to compare the Company’s performance over time.

Netback is calculated on a per boe basis as oil and gas sales, less royalties, operating and transportation expenses and realized derivative gains and losses. Netback is used by management to measure operating results on a per boe basis to better analyze performance against prior periods on a comparable basis.

Drilling inventory is calculated in years as the Company’s 2015 year-end inventory divided by the number of wells in its 2016 drilling program. Drilling inventory is used by management to assess the amount of available drilling opportunities. Drilling inventory does not have a standardized meaning and as such may not be reliable, and should not be used to make comparisons.

There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil, natural gas and NGL 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, NGL 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. The Company’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.

Individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation. This press release contains estimates of the net present value of the Company’s future net revenue from our reserves. Such amounts do not represent the fair market value of our reserves. The recovery and reserve estimates of the Company’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.

The reserve data provided in this news release presents only a portion of the disclosure required under National Instrument 51-101. All of the required information will be contained in the Company’s Annual Information Form for the year ended December 31, 2015, which will be filed on SEDAR (accessible at www.sedar.com) and EDGAR (accessible at www.sec.gov/edgar.shtml) on March 9, 2016.

Notice to US Readers

The oil and natural gas reserves contained in this press release have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects of United States or other foreign disclosure standards. For example, the United States Securities and Exchange Commission (the “SEC”) generally permits oil and gas issuers, in their filings with the SEC, to disclose only proved reserves (as defined in SEC rules), but permits the optional disclosure of “probable reserves” and “possible reserves” (each as defined in SEC rules). Canadian securities laws require oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only proved reserves (which are defined differently from the SEC rules) but also probable reserves and permits optional disclosure of “possible reserves”, each as defined in NI 51-101. Accordingly, “proved reserves”, “probable reserves” and “”possible reserves” disclosed in this news release may not be comparable to US standards, and in this news release, Crescent Point has disclosed reserves designated as “proved plus probable reserves.” Probable reserves are higher-risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves. “Possible reserves” are higher risk than “probable reserves” and are generally believed to be less likely to be accurately estimated or recovered than “probable reserves”. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross volumes, which are volumes prior to deduction of royalties and similar payments. The SEC rules require reserves and production to be presented using net volumes, after deduction of applicable royalties and similar payments. Moreover, Crescent Point has determined and disclosed estimated future net revenue from its reserves using forecast prices and costs, whereas the SEC rules require that reserves be estimated using a 12-month average price, calculated as the arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Consequently, Crescent Point’s reserve estimates and production volumes in this news release may not be comparable to those made by companies using United States reporting and disclosure standards.

All amounts in the news release are stated in Canadian dollars unless otherwise specified.

Forward-Looking Statements

Certain statements contained in this press release constitute “forward-looking statements” within the meaning of section 27A of the Securities Act of 1933 and section 21E of the Securities Exchange Act of 1934 and “forward looking information” for the purposes of Canadian securities regulation. The Company has tried to identify such forward-looking statements by use of such words as “could”, “should”, “can”, “anticipate”, “expect”, “believe”, “will”, “may”, “intend”, “projected”, “sustain”, “continues”, “strategy”, “potential”, “projects”, “grow”, “take advantage”, “estimate”, “well-positioned” and other similar expressions, but these words are not the exclusive means of identifying such statements.

In particular, this press release contains forward-looking statements pertaining to the following: the recognition of strong reserve additions in 2015 under the heading “2015 Reserve Highlights”; the volumes, estimated values and life of the Company’s oil and gas reserves; the volume and product mix of Crescent Point’s oil and gas production; future prices for oil and natural gas; future results from operations metrics; future development, exploration, acquisition and development activities and related expectations; cost reduction expectations and the impact of such reductions on FDC; the potential for reserve and NAV growth from unbooked drilling locations; the potential for reserve growth from waterflood activity; and expected improvements to decline rates.

Statements relating to “reserves” are also deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. Actual reserve values may be greater than or less than the estimates provided herein.

All forward-looking statements are based on Crescent Point’s beliefs and assumptions based on information available at the time the assumption was made including, without limitation: that Crescent Point will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities (including development of infrastructure) will be consistent with past results; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of the Company’s reserve and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and cash flow to fund the Company’s planned expenditures. There are a number of assumptions associated with the development of the Company’s assets, including the quality of the reservoirs where the Company operates, continued performance from existing wells, recovery factors, future drilling programs, performance from new wells and the growth of infrastructure. Crescent Point believes that the expectations reflected in these forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this report should not be unduly relied upon.

By their nature, the forward-looking statements contained in this news release are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements, including those material risks discussed in the Company’s Annual Information Form under “Risk Factors”. In addition, risk factors include: 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; industry conditions including changes in laws and regulations and 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; 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; unexpected geological, technical, drilling, construction and processing problems; general economic, market and business conditions; changes in income tax laws, crown royalty rates and incentive programs relating to the oil and gas industry. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Crescent Point’s future course of action depends on management’s assessment of all information available at the relevant time.

Additional information on these and other factors that could affect Crescent Point’s operations or financial results are included in Crescent Point’s reports on file with Canadian and U.S. securities regulatory authorities. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed herein or otherwise and Crescent Point undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required to do so pursuant to applicable law. All subsequent forward-looking statements, whether written or oral, attributable to Crescent Point or persons acting on the Company’s behalf are expressly qualified in their entirety by these cautionary statements.

Crescent Point shares are traded on the Toronto Stock Exchange and New York Stock Exchange, both under the symbol CPG.

Crescent Point Energy Corp.
Ken Lamont, Chief Financial Officer
Telephone: (403) 693-0020
(403) 693-0070 (FAX)
Toll-free (US & Canada): 888-693-0020
Website: www.crescentpointenergy.com

Crescent Point Energy Corp.
Trent Stangl, Senior Vice President, Investor Relations and
Communications
Telephone: (403) 693-0020
(403) 693-0070 (FAX)
Toll-free (US & Canada): 888-693-0020
Website: www.crescentpointenergy.com

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Crescent Point Replaces 315 Percent of 2015 Production, Increases Reserves by 16 Percent and Generates $9.83 Per boe Finding and Development Costs

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