exh99_1.htm

CRESCENT POINT ENERGY ANNOUNCES YEAR-END 2013 RESULTS

March 12, 2014 CALGARY, ALBERTA. Crescent Point Energy Corp. (“Crescent Point” or the “Company”) (TSX and NYSE: CPG) is pleased to announce its operating and financial results for the year ended December 31, 2013. The Company also announces that its audited financial statements and management’s discussion and analysis for the year ended December 31, 2013, will be available shortly on SEDAR at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml and on Crescent Point’s website at www.crescentpointenergy.com.

FINANCIAL AND OPERATING HIGHLIGHTS

	Three months ended December 31									Year ended December 31
(Cdn$000s except shares, per share and per boe amounts)	2013			2012			% Change			2013			2012			% Change
Financial
Funds flow from operations (1)		533,310			430,386			24			2,047,817			1,601,850			28
Per share (1) (2)		1.35			1.18			14			5.28			4.83			9
Net income (loss)		(13,723	)		(95,241	)		(86	)		144,876			190,653			(24	)
Per share (2)		(0.03	)		(0.26	)		(88	)		0.37			0.57			(35	)
Operating income (1)		78,216			(19,802	)		(495	)		485,688			303,568			60
Per share (1) (2)		0.20			(0.05	)		(500	)		1.25			0.91			37
Dividends paid or declared		274,797			255,621			8			1,081,551			931,400			16
Per share (2)		0.69			0.69			-			2.76			2.76			-
Payout ratio (%) (1) (3)		52			59			(7	)		53			58			(5	)
Per share (%) (1) (2) (3)		51			58			(7	)		52			57			(5	)
Net debt (1)		2,077,078			1,760,324			18			2,077,078			1,760,324			18
Net debt to funds flow from operations (1) (4)		1.0			1.1			(9	)		1.0			1.1			(9	)
Capital acquisitions (net) (5)		20,109			926,985			(98	)		118,267			3,021,230			(96	)
Development capital expenditures (6)		485,460			463,438			5			1,724,507			1,488,947			16
Decommissioning and environmental expenditures (6)		4,272			4,478			(5	)		15,008			15,440			(3	)
Weighted average shares outstanding (mm)
Basic		393.8			361.2			9			386.3			329.4			17
Diluted		395.3			363.4			9			387.7			331.8			17
Operating
Average daily production
Crude oil and NGLs (bbls/d)		115,971			97,731			19			109,129			89,704			22
Natural gas (mcf/d)		70,017			61,654			14			66,952			54,284			23
Total (boe/d)		127,641			108,007			18			120,288			98,751			22
Average selling prices (7)
Crude oil and NGLs ($/bbl)		82.81			78.78			5			86.32			80.51			7
Natural gas ($/mcf)		3.90			3.36			16			3.61			2.61			38
Total ($/boe)		77.38			73.20			6			80.32			74.57			8
Netback ($/boe)
Oil and gas sales		77.38			73.20			6			80.32			74.57			8
Royalties		(13.92	)		(13.97	)		-			(14.67	)		(12.95	)		13
Operating expenses		(10.64	)		(12.15	)		(12	)		(11.50	)		(11.65	)		(1	)
Transportation		(2.15	)		(1.74	)		24			(2.17	)		(1.83	)		19
Netback prior to realized derivatives		50.67			45.34			12			51.98			48.14			8
Realized gain (loss) on derivatives		(2.20	)		1.15			(291	)		(2.07	)		(0.49	)		322
Netback (1)		48.47			46.49			4			49.91			47.65			5

(1)

Funds flow from operations, operating income, payout ratio, net debt, net debt to funds flow from operations and netback as presented do not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and, therefore, may not be comparable with the calculation of similar measures presented by other entities. Please refer to the Non-GAAP Financial Measures section of this press release for further information.

(2)	The per share amounts (with the exception of per share dividends) are the per share – diluted amounts.

(3)	Payout ratio is calculated as dividends paid or declared (including the value of dividends paid pursuant to the Company’s dividend reinvestment plans) divided by funds flow from operations.

(4)	Net debt to funds flow from operations is calculated as the period end net debt divided by the sum of funds flow from operations for the trailing four quarters.

(5)	Capital acquisitions represent total consideration for the transactions, including long-term debt and working capital assumed, and exclude transaction costs.

(6)	Decommissioning and environmental expenditures includes environmental emission reduction expenditures, which are also included in development capital expenditures in the table above.

(7)	The average selling prices reported are before realized derivatives and transportation charges.

FOURTH QUARTER 2013 HIGHLIGHTS

In fourth quarter 2013, Crescent Point continued to execute its integrated business strategy of acquiring, exploiting and developing high-quality, long-life light and medium oil and natural gas properties.

Crescent Point achieved a new production record in fourth quarter 2013 and averaged 127,641 boe/d. This represents a production per share growth rate of 9 percent over fourth quarter 2012. A successful drilling program and the Company’s continued advancements in technology drove production, with Crescent Point surpassing its 2013 exit guidance of 124,000 boe/d in November.

During the quarter, the Company spent $389.4 million on drilling and development activities, drilling 205 (161.6 net) wells with a 99 percent success rate. Crescent Point also spent $96.1 million on land, seismic and facilities, for total capital expenditures of $485.5 million.

Crescent Point generated funds flow from operations of $1.35 per share – diluted ($533.3 million) in fourth quarter 2013, representing a 14 percent increase over fourth quarter 2012 funds flow from operations of $1.18 per share – diluted ($430.4 million). Funds flow from operations was driven by strong operating netbacks prior to realized derivatives of $50.67 per boe and better than expected production volumes.

Crescent Point maintained consistent monthly dividends of $0.23 per share, totaling $0.69 per share for fourth quarter 2013. This is unchanged from $0.69 per share paid in fourth quarter 2012. On an annualized basis, the fourth quarter dividend equates to a yield of 6.9 percent, based on a volume weighted average quarterly share price of $40.15.

Subsequent to the quarter, on January 22, 2014, Crescent Point’s shares opened for trading on the New York Stock Exchange (“NYSE”), under the symbol “CPG.” KCG Americas LLC is the Designated Market Maker for the Company. To celebrate the listing, Scott Saxberg, president and CEO of Crescent Point, will visit the NYSE on March 24, 2014, to ring The Opening Bell®.

2013 HIGHLIGHTS

Crescent Point executed strong organic production growth across its core areas in 2013, growing average daily production to 120,288 boe/d, a 22 percent increase over 2012. Production was weighted 91 percent to light and medium crude oil and liquids.

Due to its successful drilling program in 2013, as well as the Company’s ongoing technological advancements in both multi-stage cemented liner techniques and tight-rock waterfloods, Crescent Point raised its production targets four times throughout the year. The Company exited the year ahead of targets and grew annual average production by approximately 20,000 boe/d.

In 2013, the Company spent $1.7 billion on development capital activities, including $1.4 billion on drilling and development activities and $300.2 million on land, seismic and facilities. Crescent Point drilled 737 (549.5 net) wells in 2013 with a 100 percent success rate.

The Company increased proved plus probable reserves by 9 percent to 663.8 million boe (“mmboe”) at year-end 2013, weighted 91 percent to light and medium crude oil and liquids. Proved reserves increased by 8 percent to 432.8 mmboe. This represents annual reserves per share growth of 4 percent for proved plus probable reserves and 3 percent for proved reserves.

Crescent Point’s Net Asset Value (“NAV”) per share increased to $38.13 per fully diluted share, discounted at 10 percent, representing growth of 9 percent over 2012, not including dividends paid during the year. Including dividends paid in 2013, this represents a 16 percent growth in value per share.

Crescent Point achieved 2013 Finding and Development (“F&D”) costs of $18.42 per proved plus probable boe and $23.84 per proved boe of reserves, excluding changes in Future Development Capital (“FDC”). This represents recycle ratios of 2.8 times and 2.2 times, respectively, based on the Company’s strong netback prior to realized derivatives of $51.98 per boe. Including changes in FDC, 2013 F&D costs were $20.09 per proved plus probable boe and $21.51 per proved boe, generating proved plus probable and proved recycle ratios of 2.6 times and 2.4 times, respectively.

Crescent Point achieved 2013 Finding, Development and Acquisition (“FD&A”) costs of $18.64 per proved plus probable boe of reserves and $24.15 per proved boe of reserves, excluding changes in FDC.

In 2013, Crescent Point added 93.6 mmboe of proved plus probable reserves, excluding reserves added through acquisitions. This includes approximately 83 mmboe in its core Bakken/Torquay, Shaunavon and Uinta Basin resource plays and represents the twelfth consecutive year of strong positive technical and development reserves additions.

Crescent Point’s strong reserves additions included reserves attributed to the Company’s waterfloods in the Viewfield Bakken resource play, as well as a significant increase in reserves due to the latest generation of the Company’s cemented liner completions. In the Viewfield Bakken inner core area, Estimated Ultimate Recoveries (“EURs”) assigned by the Company’s independent reserve evaluators increased by approximately 25 percent per well on average due to the application of current cemented liner technology, which provides more efficient fracture stimulation results, more controlled access to the reservoir and lower decline rates. In general, these EUR increases have raised the value of the Bakken inner core area by approximately 35 percent.

Additionally in the Viewfield Bakken, Crescent Point’s independent reserve evaluators assigned the Company’s waterflood patterns an incremental 3 percent recovery factor from the previous primary recoverable reserve levels, which equates to a 16 percent increase in EURs. This is consistent with the Company’s independent engineering firm’s study earlier in the year that found ultimate long-term recovery factors up to 30 percent are achievable in these areas. This is the first time “improved recovery” reserves have been independently recognized in the early stages of the Company’s Viewfield Bakken waterflood.

Beyond the reserve additions, Crescent Point continues to be pleased with ongoing results from its waterfloods, which have now been implemented in all of Crescent Point’s major Canadian unconventional oil fields. In the Viewfield Bakken alone, the Company has grown volumes positively affected by waterfloods to more than 15,000 bbl/d and expects to more than double current affected volumes within two years. During 2013, the Company received approval for its first waterflood unit in the Lower Shaunavon resource play and technical approval for its first Viewfield Bakken waterflood unit, which are significant milestones for its waterflood programs. The Company continues to pursue approvals for subsequent units, both in the Lower Shaunavon and the Viewfield Bakken resource plays, as unitization allows Crescent Point to implement its waterfloods across larger areas.

Crescent Point is also pleased with successful results from its first full year of operations in the Uinta Basin resource play in Utah. In 13 months to year-end 2013, the Company grew production in the resource play by more than 30 percent and grew reserves, including production, by more than 30 percent from the November 2012 time of acquisition. Also during the year, Crescent Point established and grew its rail operations in Utah to help broaden the market for Uinta Basin crude. Based on results to date and Crescent Point’s plans for future development, the Company believes the Uinta Basin resource play has significant long-term upside.

Crescent Point generated record funds flow from operations of $5.28 per share – diluted ($2.05 billion) in 2013. This represents a 9 percent per share increase over 2012 funds flow from operations of $4.83 per share – diluted ($1.60 billion). The Company’s record funds flow from operations was driven by higher than expected production and its strong netback prior to realized derivatives of $51.98 per boe.

Crescent Point maintained consistent monthly dividends of $0.23 per share, totaling $2.76 per share for the year. This is unchanged from $2.76 per share paid in 2012. Since inception, Crescent Point has paid approximately $4.8 billion in dividends.

Consistent with Crescent Point’s dedication to environmental responsibility, in 2013 the Company contributed $30.7 million ($0.70 per produced boe) to its reclamation fund and spent $15.0 million during the year on decommissioning and environmental emission reduction projects. Since inception, Crescent Point has contributed $86.7 million to its reclamation fund and spent $60.6 million.

OPERATIONS REVIEW

Fourth Quarter Operations Summary

Crescent Point achieved a new production record in fourth quarter and averaged 127,641 boe/d. This represents production per share growth of 9 percent over fourth quarter 2012. The Company’s strong organic production performance during the quarter was driven by its successful drilling program, the Company’s ongoing waterflood success, lower-than-budgeted corporate declines and continued strong results from cemented liner completion techniques.

Drilling Results

The following tables summarize our drilling results for the three months and year ended December 31, 2013:

Three months ended December 31, 2013	Gas		Oil		D&A		Service		Standing		Total		Net		% Success
Southeast Saskatchewan and Manitoba		-		104		1		2		1		108		101.5		99
Southwest Saskatchewan		-		42		-		1		-		43		40.7		100
Alberta and West Central Saskatchewan		-		17		-		-		-		17		9.2		100
United States (1)		-		37		-		-		-		37		10.2		100
Total		-		200		1		3		1		205		161.6		99

Year ended December 31, 2013	Gas		Oil		D&A		Service		Standing		Total		Net		% Success
Southeast Saskatchewan and Manitoba		-		322		1		3		1		327		287.2		100
Southwest Saskatchewan		-		126		-		1		-		127		118.3		100
Alberta and West Central Saskatchewan		-		101		-		-		-		101		61.2		100
United States (1)		-		182		-		-		-		182		82.8		100
Total		-		731		1		4		1		737		549.5		100

(1) The net well count is subject to final working interest determination.

Southeast Saskatchewan and Manitoba

In fourth quarter, Crescent Point continued to successfully execute its large capital program in southeast Saskatchewan and Manitoba. Successful results in the Company’s Viewfield Bakken and Flat Lake resource plays in southeast Saskatchewan continue to be strong drivers of Crescent Point’s organic production growth.

Crescent Point’s work to refine its one-mile, 25-stage cemented liner completion technique in the Viewfield Bakken resource play continues to drive strong rates of return. The Company has been utilizing cemented liner completions in the Viewfield area for more than three years and is pleased with production performance from wells completed using the most recent generation of the technology. Crescent Point’s advancements have reduced water utilized per well by approximately 45 percent from 2011 levels and first-year decline rates are coming in approximately 10 percent lower than those of the previous generation.

In the Viewfield Bakken inner core area, EURs assigned by the Company’s independent reserves evaluators increased by approximately 25 percent per well on average due to the application of current cemented liner technology, which provides more efficient fracture stimulation results, more controlled access to the reservoir and lower decline rates. In general, these EUR increases have raised the value of the Bakken inner core area by approximately 35 percent.

The Company’s waterflood continues to improve production performance in the Viewfield Bakken resource play. The Company has grown volumes positively affected by waterfloods to more than 15,000 bbl/d and plans to double the number of water injection wells in the play over the next two years. Crescent Point’s plans for 2014 include the conversion of 30 producing wells to water injection wells, which is expected to ultimately lower production declines and improve rates of return on adjacent producing oil wells. Also, based on success in the Manitoba Bakken play, the Company is pursuing waterflood unitization to initiate its first waterflood in the area in 2014 and is planning to build a battery in 2014 to accommodate increased production.

During fourth quarter, the Company continued construction to expand its Viewfield gas plant from 30 mmscf/d to 42 mmscf/d. The expansion is expected to be complete in early 2014 and is designed to accommodate Crescent Point’s growing production volumes in the Viewfield Bakken resource play.

At Flat Lake, Crescent Point drilled 30 net wells in 2013 and current production is more than 5,500 boe/d. The Company plans to drill 48 net wells in the area in 2014.

Southwest Saskatchewan

Crescent Point had its most active quarter for waterflood activity in the Lower Shaunavon resource play during fourth quarter, converting a total of seven producing wells into water injection wells. Two of the conversions were in the Company’s recently approved waterflood unit, the Leitchville North Shaunavon Unit #1, and five were in a second development area adjacent to the first unit. Crescent Point plans to apply for unitization for the second development area in second quarter 2014. In total, the Company currently has eight water injection wells operating in the Leitchville North Shaunavon Voluntary Unit #1 and 10 water injection wells operating in the second development area, all in the Lower Shaunavon zone. Current waterflood-affected production in the first unit is more than 2,600 bbl/d and waterflood-affected production in the second development area is more than 600 bbl/d. Crescent Point plans to double the number of water injection wells in the play by year-end 2014, as the Company continues to be pleased with production performance in both its Lower and Upper Shaunavon waterflood projects.

Crescent Point had a record year of activity in the Upper Shaunavon resource play, having drilled 26.5 net Upper Shaunavon horizontal wells, 17 of which were drilled in the third quarter. The Company is pleased with results, which continue to exceed expectations, and plans to drill 27 net horizontal wells in the Upper Shaunavon resource play in 2014.

Based on ongoing successful results from cemented liner completion technology, Crescent Point expects to continue to refine this completion approach as it proceeds with its drilling program in 2014. The Company plans to apply techniques developed in the Viewfield Bakken resource play to the Shaunavon resource play drilling program, including using 25-stage cemented liner completions with lower tonnage on each drill. As seen in the Viewfield Bakken, Crescent Point believes this technology should result in higher EURs in the Shaunavon play and should ultimately lead to positive technical reserve additions on its remaining booked drilling inventory and existing producing wells in the future.

Also during the quarter, Crescent Point continued construction of two oil storage tanks with 120,000 barrels of total storage. The tanks, which are adjacent to the Company’s rail-loading facility in Dollard, provide Crescent Point with operational flexibility and are expected to be commissioned toward the end of first quarter 2014.

During fourth quarter, the Company set a new production record of more than 3,000 boe/d in its Battrum units. A successful drilling program, combined with optimization of lift equipment and facility configuration, drove the record results. Since acquiring the property in 2006, Crescent Point continues to increase production in this large oil in place waterflood, which has been on production since 1956.

Alberta and West Central Saskatchewan

As a result of Crescent Point’s ongoing testing of various completion techniques, costs in the south/central Alberta and west central Saskatchewan area continue to be optimized. For example, operated drilling, completion and equipping costs in Dodsland, Saskatchewan, dropped by approximately 25 percent during 2013.

Crescent Point and its partner continue to inject water into their first waterflood pilot in the Beaverhill Lake play. Expansion of the pilot, incorporating two additional water injection wells, is anticipated in second quarter 2014. The Company has also received regulatory approval for its first operated waterflood pilot in the play. Water injection in this pilot is expected to begin in third quarter 2014.

United States

In its first full year of operations in the Uinta Basin, Crescent Point achieved significant success in production increases, reserves additions and field operation cost reductions. In 13 months to year-end 2013, the Company grew production in the resource play by more than 30 percent and grew reserves, including production, by more than 30 percent from the November 2012 time of acquisition. Crescent Point continues to test various new completion techniques in the area in an effort to further increase fracture stimulation efficiency and improve production rates and ultimate recoveries. In addition, the Company has implemented several field optimization projects in the Randlett area to increase production levels, such as recompleting wells to access bypassed pay and resizing pumps to reduce fluid levels. Based on results to date and Crescent Point’s plans for future development, the Company believes the Uinta Basin resource play has significant potential long-term upside.

During early fourth quarter 2013, Crescent Point initiated the permitting process for a 3-D seismic program covering a large portion of the Company’s operated lands in the Randlett area. Data acquisition is expected to begin in third quarter 2014. Crescent Point has also received state regulatory approval for down-spaced drilling and a waterflood injection pilot in a four-section Randlett area of the Uinta Basin. Water injection is expected to begin in early 2015.

Rail operations in Utah have allowed the Company to broaden the market for Uinta Basin crude beyond the Salt Lake City refining market. Crescent Point’s permanent rail-loading site is now fully operational, with capacity of approximately 10,000 bbl/d and the capability to increase volumes in the future.

Crescent Point is working with partners to design and participate in the drilling of horizontal wells in the Wasatch and Uteland Butte formations. Initial production rates from wells drilled to date are encouraging and Crescent Point is monitoring their early decline profile. The Company anticipates using completion techniques similar to those successfully utilized in the Viewfield Bakken play to increase recovery factors in Utah.

Environmental Responsibility

As part of Crescent Point’s ongoing commitment to the environment and to reduce greenhouse gas emissions, Crescent Point has a voluntary reclamation fund for future decommissioning costs and environmental emissions reduction costs. During 2013, the Company contributed $0.70 per produced boe to the fund, of which $0.40 per boe was for future decommissioning costs and $0.30 per boe was directed to environmental emissions reduction.

The reclamation fund increased by $15.7 million during 2013 due to contributions of $30.7 million, partially offset by expenditures of $15.0 million. The expenditures included $11.4 million related primarily to decommissioning work completed in Alberta and southeast Saskatchewan. The remaining $3.6 million related to environmental emissions work completed primarily in Saskatchewan to reduce greenhouse gas emissions and to meet and exceed provincial and federal targets. Since inception, $86.7 million has been contributed to the reclamation fund and $60.6 million has been spent.

RESERVES

Crescent Point achieved 2013 F&D costs of $18.42 per proved plus probable boe and $23.84 per proved boe, excluding changes in FDC, generating proved plus probable and proved recycle ratios of 2.8 times and 2.2 times, respectively. Including changes in FDC, 2013 F&D costs were $20.09 per proved plus probable boe and $21.51 per proved boe, generating proved plus probable and proved recycle ratios of 2.6 times and 2.4 times, respectively.

Crescent Point’s 5-year weighted average F&D cost, including expenditures on land, seismic and facilities, is $17.91 per proved plus probable boe and $22.97 per proved boe, representing 5-year weighted average recycle ratios of 2.7 times and 2.1 times, respectively. This highlights the Company’s technical ability to efficiently add value to its large resource-in-place asset base and accurately reflects the full cycle nature of investments in land, seismic and facilities.

Crescent Point achieved 2013 FD&A costs of $18.64 per proved plus probable boe and $24.15 per proved boe of reserves, excluding changes in FDC. This represents recycle ratios of 2.8 times and 2.2 times, respectively. Including changes in FDC, 2013 FD&A costs were $20.22 per proved plus probable boe and $21.95 per proved boe, generating proved plus probable and proved recycle ratios of 2.6 times and 2.4 times, respectively.

Crescent Point replaced 213 percent of production on a proved plus probable basis, excluding reserves added through acquisitions. Including acquisitions, the Company replaced 225 percent of production.

Crescent Point’s NAV per share increased to $38.13 per fully diluted share, discounted at 10 percent, representing growth of 9 percent over 2012, not including dividends paid during the year. Including dividends paid in 2013, this represents a 16 percent growth in value per share.

The Company’s reserves were independently evaluated by GLJ Petroleum Consultants Ltd. (“GLJ”) and Sproule Associates Ltd. (“Sproule”) as at December 31, 2013, and the following highlights are based on such evaluations.

Summary of Reserves

As at December 31, 2013 (1) (2) (3)

	Light and Medium Oil				Heavy Oil				Natural Gas Liquids				Natural Gas				Total (4)
Reserves Category	Company		Company		Company		Company		Company		Company		Company		Company		Company		Company
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
	(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(MMcf)		(MMcf)		(Mboe)		(Mboe)
Proved Developed Producing		209,811		183,588		639		626		9,611		8,656		116,104		106,070		239,413		210,549
Proved Developed Non-Producing		9,361		8,429		490		462		557		502		10,049		9,226		12,082		10,931
Proved Undeveloped		157,511		141,172		146		131		8,867		7,947		88,495		79,550		181,272		162,509
Total Proved (4)		376,683		333,189		1,274		1,220		19,035		17,105		214,647		194,845		432,767		383,989
Total Probable		201,896		176,362		672		614		9,222		8,110		115,200		103,089		230,990		202,267
Total Proved Plus Probable (4)		578,580		509,551		1,947		1,834		28,257		25,215		329,848		297,934		663,758		586,256

(1) Based on GLJ’s January 1, 2014, 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)	Numbers may not add due to rounding.

Summary of Before and After Tax Net Present Values

As at December 31, 2013 (1)

	Before Tax Net Present Value ($MM)											After Tax Net Present Value ($MM)
	Discount Rate											Discount Rate
Reserves Category		0	%	5	%	10	%	15	%	20	%		0	%	5	%	10	%	15	%	20	%
Proved Developed Producing		11,774		8,870		7,263		6,223		5,488			10,235		7,734		6,345		5,444		4,806
Proved Developed Non-Producing		579		459		382		330		291			439		346		288		247		218
Proved Undeveloped		6,441		4,305		3,037		2,224		1,672			4,860		3,163		2,155		1,508		1,071
Total Proved (2)		18,794		13,634		10,683		8,777		7,451			15,534		11,244		8,787		7,200		6,095
Total Probable		11,763		7,105		4,907		3,667		2,884			8,537		5,104		3,484		2,570		1,994
Total Proved Plus Probable (2)		30,557		20,739		15,590		12,444		10,335			24,071		16,348		12,271		9,770		8,088

(1) Based on GLJ’s January 1, 2014, 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

	2013		2012		2011		2010		2009		2008		2007		2006		2005
PV 0%		$75.69		$68.39		$71.39		$71.38		$72.01		$80.66		$61.03		$34.08		$21.99
PV 5%		$51.04		$46.49		$49.81		$47.65		$46.91		$49.30		$40.21		$21.61		$15.12
PV 10%		$38.13		$35.11		$38.42		$36.02		$35.08		$34.97		$30.05		$15.70		$11.45
PV 15%		$30.25		$28.15		$31.35		$29.10		$28.27		$26.85		$24.04		$12.27		$9.10

Reserves Reconciliation

Gross Reserves (1)

	Light and Medium Oil (Mbbls)									Heavy Oil (Mbbls)									Natural Gas Liquids (Mbbls)
Factors	Proved			Probable			Proved			Proved			Probable			Proved			Proved			Probable			Proved
							Plus									Plus									Plus
							Probable									Probable									Probable
January 1, 2013		348,627			181,600			530,227			2,487			1,088			3,575			15,417			7,849			23,266
Discoveries		-			-			-			-			-			-			-			-			-
Extensions and Improved Recovery		38,352			29,672			68,024			-			-			-			1,394			1,059			2,451
Technical Revisions		23,945			(9,791	)		14,154			(576	)		(264	)		(840	)		4,127			352			4,479
Acquisitions		3,714			1,498			5,212			-			-			-			173			78			251
Dispositions		(57	)		(110	)		(166	)		-			-			-			(11	)		(47	)		(57	)
Economic Factors		(322	)		(974	)		(1,296	)		(456	)		(152	)		(607	)		12			(71	)		(58	)
Production		(37,575	)		-			(37,575	)		(181	)		-			(181	)		(2,076	)		-			(2,076	)
December 31, 2013 (2)		376,683			201,896			578,580			1,274			672			1,947			19,035			9,222			28,257

	Natural Gas (MMcf)									Total Oil Equivalent (Mboe)
Factors	Proved			Probable			Proved			Proved			Probable			Proved
							Plus									Plus
							Probable									Probable
January 1, 2013		203,053			107,319			310,373			400,373			208,424			608,797
Discoveries		-			-			-			-			-			-
Extensions and Improved Recovery		19,367			13,047			32,414			42,972			32,907			75,879
Technical Revisions		17,119			(3,292	)		13,827			30,348			(10,251	)		20,097
Acquisitions		1,083			509			1,592			4,068			1,660			5,728
Dispositions		(280	)		(1,245	)		(1,525	)		(114	)		(364	)		(478	)
Economic Factors		(1,257	)		(1,137	)		(2,395	)		(976	)		(1,385	)		(2,361	)
Production		(24,437	)		-			(24,437	)		(43,905	)		-			(43,905	)
December 31, 2013 (2)		214,647			115,200			329,848			432,767			230,990			663,758

(1)	Based on GLJ’s January 1, 2014, escalated price forecast. “Gross reserves” are the Company’s working-interest share before deduction of any royalties and without including any royalty interests of the Company.

(2)	Numbers may not add due to rounding.

Finding, Development and Acquisition Costs

	Finding & Development		Acquisitions (Net of Dispositions)		FD&A Subtotal		Change in FDC			F&D Total (incl. change in FDC)		FD&A Total (incl. change in FDC)
Capital ($M) (1)
Total Proved Plus Probable		1,724,507		118,267		1,842,774		156,012			1,880,519		1,998,786
Total Proved		1,724,507		118,267		1,842,774		(168,068	)		1,556,439		1,674,706

Reserves (Mboe) (2)
Total Proved Plus Probable		93,615		5,250		98,865		-			93,615		98,865
Total Proved		72,344		3,954		76,298		-			72,344		76,298

(1)	The capital expenditures exclude capitalized administration costs and transaction costs.

(2)	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 change in FDC						Including change in FDC
	($/boe, except recycle ratios)						($/boe, except recycle ratios)
	2013		2012		3 Years Ended Dec. 31, 2013 (Weighted Avg.)		2013		2012		3 Years Ended Dec. 31, 2013 (Weighted Avg.)
F&D Cost
Total Proved Plus Probable	$18.42		$19.80		$18.89		$20.09		$27.25		$24.81
Total Proved	$23.84		$26.08		$24.31		$21.51		$33.04		$28.58

F&D Recycle Ratio (1)
Total Proved Plus Probable		2.8		2.4		2.7		2.6		1.8		2.1
Total Proved		2.2		1.8		2.1		2.4		1.5		1.8


FD&A Cost
Total Proved Plus Probable	$18.64		$20.64		$20.01		$20.22		$23.19		$23.57
Total Proved	$24.15		$29.23		$27.09		$21.95		$31.78		$29.80

FD&A Recycle Ratio (1)
Total Proved Plus Probable		2.8		2.3		2.6		2.6		2.1		2.2
Total Proved		2.2		1.6		1.9		2.4		1.5		1.7

(1)	Based on a 2013 netback (prior to realized derivatives) of $51.98 per boe, a 2012 netback (prior to realized derivatives) of $48.14 per boe and a three-year weighted average netback (prior to realized derivatives) of $51.27 per boe.

OUTLOOK AND UPWARDLY REVISED GUIDANCE FOR 2014 FUNDS FLOW FROM OPERATIONS

Crescent Point continues to execute its business plan of creating sustainable value-added growth in reserves, production and cash flow through management’s integrated strategy of acquiring, exploiting and developing high-quality, long-life light and medium oil and natural gas properties in United States and Canada.

The Company’s drilling program and its commitment to advancing its waterflood programs and multi-stage cemented liner techniques have created a dual-track growth plan that has positioned Crescent Point well for long-term stability. Advancements in these technologies allow Crescent Point to grow production at a reasonable pace while lowering decline rates and well costs.

2013 was a very successful year for Crescent Point on many fronts. Not only did the Company execute a successful drilling program in its core Viewfield Bakken, Lower Shaunavon and Uinta Basin resource plays, but it continued to refine its waterflood and multi-stage cemented liner techniques. Crescent Point expects these technologies will continue to add value to the Company’s large development inventory. With its ongoing focus on technology and its ability to leverage technological advancements on a broad scale across its large original oil in place asset base, the Company is poised for another strong year of results in 2014.

In total in 2014, Crescent Point plans to drill 604 net wells of its more than 7,100 net internally identified low-risk drilling locations in its inventory. Also throughout the year, the Company plans to continue to develop and expand its waterflood programs, which have been initiated in all of Crescent Point’s major unconventional oil fields and continue to show positive results.

To date in first quarter 2014, WTI has averaged nearly Cdn$110 per barrel due to higher US$WTI oil prices and a weaker Canadian dollar exchange rate. The Company’s realized oil price has averaged 18 percent higher than originally forecast. As a result, Crescent Point is upwardly revising its guidance for funds flow from operations for 2014. Funds flow from operations is now expected to be approximately $2.25 billion ($5.59 per share – diluted), based on forecast pricing of US$100.00 per barrel WTI, Cdn$4.65 per mcf AECO gas and a US$/Cdn$0.90 exchange rate, with annualized fourth quarter funds flow from operations of approximately $2.46 billion.

As at March 3, 2014, the Company had hedged 65 percent of its expected oil production, net of royalty interest, for 2014. The Company had also hedged 35 percent, 21 percent and 4 percent of its expected oil production, net of royalty interest, for 2015, 2016 and the first half of 2017, respectively. Average quarterly hedge prices range from Cdn$90 per bbl to Cdn$94 per bbl. The Company’s hedges provide upside participation when oil prices increase while also providing a steady cash flow.

Crescent Point also has an average of approximately 14,200 bbl/d of WTI oil differentials locked in for 2014. These differential hedges provide a measure of stability to volatile North American oil price differentials. The corporate oil price differential for full year 2014 is forecast at 13 percent of WTI, which reflects the current market environment and Crescent Point’s existing differential hedges.

During 2013, the Company completed a private placement of senior guaranteed notes to a group of institutional investors. In total, US$290 million and CDN$10 million was raised through three separate series of notes. Proceeds from the offering were used to repay a portion of the Company’s outstanding bank debt.

Crescent Point’s balance sheet remains strong, with significant unutilized credit capacity. The Company continues to execute its aggressive hedging program, using both oil production and WTI oil differential hedges to provide a steady cash flow and reduce volatile North American oil price differentials.

The Company continues to be disciplined in its approach to capital spending, acquisition opportunities and balance sheet management. Crescent Point’s management believes that with the Company’s high-quality reserve base and low-risk development drilling inventory, excellent balance sheet and solid risk management program, the Company is well-positioned to continue generating strong operating and financial results through 2014 and beyond.

2014 GUIDANCE

The Company’s revised guidance for 2014 is as follows:

Production	Prior		Revised
Oil and NGL (bbls/d)		115,000		115,000
Natural gas (mcf/d)		69,000		69,000
Total (boe/d)		126,500		126,500
Exit (boe/d)		135,000		135,000
Annualized fourth quarter funds flow from operations ($000) (1)		2,315,000		2,460,000
Funds flow from operations ($000)		2,100,000		2,250,000
Funds flow per share – diluted ($)		5.24		5.59
Cash dividends per share ($)		2.76		2.76
Capital expenditures (2)
Drilling and completions ($000)		1,420,000		1,420,000
Facilities, land and seismic ($000)		330,000		330,000
Total ($000)		1,750,000		1,750,000
Pricing
Crude oil – WTI (US$/bbl)		95.00		100.00
Crude oil – WTI (Cdn$/bbl)		101.06		111.11
Corporate oil differential (%)		14		13
Natural gas – AECO (Cdn$/mcf)		3.25		4.65
Exchange rate (US$/Cdn$)		0.94		0.90

(1) Annualized fourth quarter funds flow from operations is fourth quarter funds flow from operations multiplied by four.

(2) The projection of capital expenditures excludes acquisitions, which are separately considered and evaluated.

ON BEHALF OF THE BOARD OF DIRECTORS

Scott Saxberg

President and Chief Executive Officer

March 12, 2014

Non-GAAP Financial Measures

Any “financial outlook” or “future oriented financial information” in the press release, as defined by applicable securities legislation, 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.

Throughout this press release, the Company uses the terms “funds flow from operations”, “funds flow from operations per share – diluted”, “operating income”, “operating income per share – diluted”, “net debt”, “net debt to funds flow from operations”, “netback”, “payout ratio” and “payout ratio per share – diluted”. These terms do not have any standardized meaning as prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other issuers.

Funds flow from operations is calculated based on cash flow from operating activities before changes in non-cash working capital, transaction costs and decommissioning expenditures. Funds flow from operations per share – diluted is calculated as funds flow from operations divided by the number of weighted average diluted shares outstanding. Management utilizes funds flow from operations as a key measure to assess the ability of the Company to finance dividends, operating activities, capital expenditures and debt repayments. Funds flow from operations as presented is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS.

The following table reconciles cash flow from operating activities to funds flow from operations:

($000s)	2013		2012		% Change
Cash flow from operating activities		1,973,332		1,543,943		28
Changes in non-cash working capital		57,349		29,375		95
Transaction costs		5,761		16,436		(65	)
Decommissioning expenditures		11,375		12,096		(6	)
Funds flow from operations		2,047,817		1,601,850		28

Operating income is calculated based on net income before amortization of exploration and evaluation (“E&E”) undeveloped land, unrealized derivative gains or losses, unrealized foreign exchange gain or loss on translation of US dollar senior guaranteed notes and unrealized gains or losses on marketable securities and long-term investments. Operating income per share – diluted is calculated as operating income divided by the number of weighted average diluted shares outstanding. Management utilizes operating income to present a measure of financial performance that is more comparable between periods. Operating income as presented is not intended to represent net earnings or other measures of financial performance calculated in accordance with IFRS.

The following table reconciles net income to operating income:

($000s)	2013			2012			% Change
Net income		144,876			190,653			(24	)
Amortization of E&E undeveloped land		275,504			247,883			11
Unrealized derivative (gains) losses		111,876			(185,724	)		(160	)
Unrealized foreign exchange (gain) loss on translation of US dollar senior guaranteed notes		60,994			(5,774	)		(1,156	)
Unrealized loss on long-term investments		10,677			89,472			(88	)
Deferred tax relating to adjustments		(118,239	)		(32,942	)		259
Operating income		485,688			303,568			60

Net debt is calculated as long-term debt plus accounts payable and accrued liabilities and dividends payable, less cash, accounts receivable, prepaids and deposits and long-term investments, excluding the equity settled component of dividends payable and unrealized foreign exchange on translation of US dollar senior guaranteed notes. Management utilizes net debt as a key measure to assess the liquidity of the Company.

The following table reconciles long-term debt to net debt:

($000s)	2013			2012			% Change
Long-term debt		1,734,114			1,474,589			18
Accounts payable and accrued liabilities		789,305			655,191			20
Dividends payable		90,849			86,182			5
Cash		(15,941	)		-			-
Accounts receivable		(352,519	)		(301,770	)		17
Prepaids and deposits		(5,532	)		(8,484	)		(35	)
Long-term investments		(74,229	)		(84,906	)		(13	)
Excludes:
Equity settled component of dividends payable		(25,799	)		(58,302	)		(56	)
Unrealized foreign exchange on translation of US dollar senior guaranteed notes		(63,170	)		(2,176	)		2,803
Net debt		2,077,078			1,760,324			18

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.

Payout ratio and payout ratio per share – diluted are calculated on a percentage basis as dividends paid or declared (including the value of dividends issued pursuant to the Company’s dividend reinvestment plan) divided by funds flow from operations. Payout ratio is used by management to monitor the dividend policy and the amount of funds flow from operations retained by the Company for capital reinvestment.

Net debt to funds flow from operations is calculated as the period end net debt divided by the sum of funds flow from operations for the trailing four quarters. The ratio of net debt to funds flow from operations is used by management to measure the Company’s overall debt position and to measure the strength of the Company’s balance sheet. Crescent Point monitors this ratio and uses this as a key measure in making decisions regarding financing, capital spending and dividend levels.

Reserves Data

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.

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, 2013, which will be filed on SEDAR (accessible at www.sedar.com) and EDGAR (accessible at www.sec.gov/edgar.shtml) on March 12, 2014.

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. 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, inter alia, to the following: the performance characteristics of Crescent Point’s oil and natural gas properties; anticipated oil and natural gas production levels; expected capital expenditure levels and how such expenditures are expected to be funded; implementation of a 3-D seismic program at Randlett; drilling programs; the future cost to drill wells, including anticipated cost savings associated therewith; the initiation and ongoing development of planned and existing waterflood programs; the expected impact of waterfloods on corporate declines and reserves; the expected impact of the conversion of producing wells to water injection wells in Viewfield Bakken on production declines and rates of return on adjacent wells; anticipated waterflood pilot and unit approval applications; the anticipated impact of refined cemented liner completion techniques on recovery factors and reserve additions; anticipated future improvements in the Company’s completion technologies; the anticipated impact of technological advancements on the value of the Company’s development inventory; the quantity of Crescent Point’s oil and natural gas reserves and anticipated future cash flows from such reserves; projections of commodity prices and costs; 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; expected debt levels and credit facilities; battery, facility expansion, battery additions and tank construction plans, and the anticipated timing of completion thereof; expected deliveries by rail; the addition of rail loading facilities, including in Utah and the transfer of equipment and staff to a permanent site in Utah; and treatment under governmental regulatory regimes and the state of certain governmental approvals.

All forward-looking statements are based on Crescent Point’s beliefs and assumptions based on information available at the time the assumption was made. Crescent Point believes that 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 included in this report should not be unduly relied upon. By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements, including those material risks discussed in our annual information form under “Risk Factors” and our Management’s Discussion and Analysis for the year ended December 31, 2013, under the headings “Risk Factors” and “Forward-Looking Information.” The material assumptions are disclosed in the Management’s Discussion and Analysis for the year ended December 31, 2013, under the headings “Dividends”, “Capital Expenditures”, “Decommissioning Liability”, “Liquidity and Capital Resources”, “Critical Accounting Estimates”, “Future Changes in Accounting Policies” and “Outlook” and include, but are not limited to: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas; delays in business operations, pipeline restrictions, 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; 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. 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.

Barrels of oil equivalent (“boes”) 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.

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 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 United States and Canada.

FOR FURTHER INFORMATION ON CRESCENT POINT ENERGY CORP. PLEASE CONTACT:

Greg Tisdale, Chief Financial Officer, or Trent Stangl, Vice President Marketing and Investor Relations.

Telephone: (403) 693-0020	Toll-free (US & Canada): 888-693-0020
Fax: (403) 693-0070	Website: www.crescentpointenergy.com

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

Crescent Point Energy Corp.

Suite 2800, 111-5th Avenue S.W.

Calgary, Alberta T2P 3Y6