Crescent Point Announces 2021 Results & Reserves and Increases Share Repurchases

CALGARY, AB, March 3, 2022 /PRNewswire/ – Crescent Point Energy Corp. (“Crescent Point” or the “Company”) (TSX: CPG) and (NYSE: CPG) is pleased to announce its operating and financial results for the year ended December 31, 2021 and increased share repurchases.

KEY HIGHLIGHTS 

• Generated over $785 million of excess cash flow in 2021 with capital expenditures and production in-line with annual guidance.
• Increased PDP reserves by 17 percent with a strong FD&A recycle ratio of 2.7 times, including change in FDC.
• Replaced 197 percent of 2021 production on a 2P basis, resulting in a FD&A recycle ratio of 2.2 times, including change in FDC.
• Improved full-cycle returns in the Kaybob Duvernay through additional well cost reductions now totaling 20 percent.
• Achieved strong IP rate of over 825 boe/d per well, based on approximately 30 days, on first fully operated Kaybob Duvernay pad.
• Fully repaid $670 million of debt to acquire the Kaybob Duvernay assets, in addition to reducing net debt by $144 million in 2021.
• Disciplined 2022 budget, which is expected to generate approximately $1.1 billion of excess cash flow at US$80/bbl WTI.
• Increasing planned share repurchases to up to $150 million, to be executed by mid-2022, from $100 million announced previously.
• On track to meet or exceed targets to reduce emissions intensity and inactive wells, highlighting strong ESG practices.

“Our discipline and execution over the past few years positioned us to not only capitalize on strategic opportunities during 2021, but also to begin returning additional capital to shareholders,” said Craig Bryksa, President and CEO of Crescent Point. “We are very pleased with our initial success in the Kaybob Duvernay, including our strong operational execution that has resulted in increased rates of return. Due to our continued discipline and focus, we are on track to achieve our near-term leverage targets over the next six months at current commodity prices. As we continue to strengthen our balance sheet we will look to provide increased returns to shareholders in the context of a more defined return of capital framework.”

FINANCIAL HIGHLIGHTS 

• For the year ended December 31, 2021, adjusted funds flow totaled $1.48 billion, or $2.57 per share diluted, driven by a strong operating netback of $42.43 per boe. In fourth quarter, adjusted funds flow totaled $432.5 million, or $0.74 per share diluted.
• For the year ended December 31, 2021, development capital expenditures, which included drilling and development, facilities and seismic costs, totaled $624.2 million, in-line with the Company’s annual guidance of $625 million.
• Crescent Point’s net debt as at December 31, 2021 was approximately $2.0 billion. The Company fully repaid approximately $670 million of debt incurred to acquire the Kaybob Duvernay assets, in addition to reducing its net debt by $144 million in 2021. In total, approximately $815 million of funds were directed to the balance sheet in 2021, including proceeds from dispositions.
• As previously announced, Crescent Point successfully renewed and extended its unsecured, covenant-based credit facilities of $2.3 billion with a maturity date of November 2025. The Company retains significant liquidity with an unutilized credit capacity of approximately $2.0 billion as at December 31, 2021.
• For the year ended December 31, 2021, Crescent Point reported net income of approximately $2.4 billion, primarily driven by a $2.5 billion ($1.9 billion after-tax) reversal of non-cash impairment in second quarter due to an increase in forward commodity prices and the independent engineers’ price forecast. In fourth quarter, net income totaled $121.6 million.

RETURN OF CAPITAL HIGHLIGHTS

• As previously announced, the Company’s Board of Directors (“Board”) approved and declared a first quarter 2022 dividend of $0.045 per share, payable on April 1, 2022 to shareholders of record on March 15, 2022. This equates to an annualized dividend of $0.18 per share, an increase of 50 percent from the prior level.
• The Board has approved the return of additional capital to shareholders given the continued strength in commodity prices and Crescent Point’s improving financial position. The Company is increasing its total planned share repurchases to up to $150 million, which it expects to execute by mid-2022, from $100 million announced previously. These planned repurchases were initiated in December 2021 with approximately 8.1 million shares repurchased and cancelled to-date for total consideration of approximately $60 million. Crescent Point has filed notice with the Toronto Stock Exchange (“TSX”) of the intention to renew its normal course issuer bid (“NCIB”), which is due to expire on March 8, 2022.

Adjusted funds flow, adjusted funds flow per share diluted, excess cash flow, recycle ratio, operating netback, net debt and net debt to adjusted funds flow are specified financial measures – refer to the Specified Financial Measures section in this press release for further information. All financial figures are approximate and in Canadian dollars unless otherwise noted. This press release contains forward-looking information and references to specified financial measures. Significant related assumptions and risk factors, and reconciliations are described under the Specified Financial Measures, Forward-Looking Statements and Reserves and Drilling Data sections of this press release, respectively. Further information breaking down the production information contained in this press release by product type can be found in the “Product Type Production Information” section of this press release.

OPERATIONAL HIGHLIGHTS

• Achieved annual average production of 132,683 boe/d in 2021, comprised of over 80 percent oil and liquids, and in-line with the previously increased annual guidance.
• The Company continues to gain operational momentum in its Kaybob Duvernay play, realizing ongoing operational efficiencies and cost reductions. Recent well costs are trending at approximately $8.25 million, including drilling, completion, equip and tie-in, down from $8.75 million previously announced. Crescent Point has now removed approximately $2.0 million of per well costs, or approximately 20 percent, since entering the play in second quarter 2021. These savings have improved expected full-cycle rates of return and provide additional insulation to the Company’s capital budget in the current inflationary environment.
• Crescent Point’s Kaybob Duvernay wells are expected to generate full-cycle rates of return of over 120 percent and a payout of less than a year, at current commodity prices and budgeted cost inflation assumptions. These economics are based on an average of booked Proved plus Probable (“2P”) reserves per well within the Company’s current drilling program. These returns exclude any potential improvements to recoverable reserves resulting from Crescent Point utilizing a larger frac design than the prior operator. The Company will seek to further enhance returns in the play through ongoing drilling and completions optimization.
• Crescent Point recently brought onstream its first fully operated five-well pad in the Kaybob Duvernay, with approximately 30 days of production data now available. Initial production (“IP”) rates from these wells exceeded the 2P booked type well expectations, with an average IP rate of over 825 boe/d per well (74% condensate, 6% NGL and 20% shale gas). Crescent Point also completed and brought on production two multi-well pads, with a 50 percent working interest, as part of its previously announced farm-in agreement with a Kaybob Duvernay operator. The combined 30-day IP rate, net to the Company, for these three pads totaled over 11,000 boe/d (51% condensate, 9% NGL and 40% shale gas). This data includes a normal clean-up period for each well where pressure is maintained and production rates are moderated.
• Crescent Point continued to enhance returns by realizing efficiencies across its asset base in 2021, including reducing its drilling days within its Viewfield, Shaunavon and North Dakota resource plays by 10 to 15 percent. Such improvements provide the Company with sustainable cost efficiencies and further highlight its commitment to ongoing operational execution.
• The Company continued to advance its various decline mitigation initiatives in 2021, which included the successful conversion of approximately 135 producing wells to water injection wells. Crescent Point expects to execute a similar waterflood program in 2022. The Company also continues to progress its other decline mitigation programs, including the expansion of its polymer floods and pilot program to test carbon dioxide (CO₂) sequestration and enhanced oil recovery in Saskatchewan.
• As part of its continued commitment to strong environmental, social and governance (“ESG”) practices, Crescent Point increased its target for emissions intensity reduction to 50 percent, up from 30 percent, by 2025, as previously announced. This target includes a 70 percent reduction in methane emissions. The Company is on track to meet or exceed its existing targets ahead of schedule and plans to revisit its current emissions reduction goals in second quarter 2022 in coordination with the release of its annual sustainability report. Crescent Point also made progress toward its target to reduce its inactive well count by approximately 30 percent by 2031 by safely retiring over 500 inactive wells during the year. The Company plans to retire approximately 350 additional wells in 2022.

RESERVES HIGHLIGHTS

“Our 2021 reserves and strong recycle ratios benefited from the addition of the Kaybob Duvernay asset, high-return development and improved recoveries from our decline mitigation programs,” said Bryksa. “As a result, our proved developed producing net asset value increased by approximately 15 percent on a per share basis, excluding year-over-year changes in pricing. We remain encouraged about the Kaybob Duvernay assets and the opportunity we have to further enhance shareholder value by achieving additional cost efficiencies, improving well productivity and adding reserves.”

• Crescent Point’s 2P reserves increased by seven percent at year-end 2021 to 712.4 million boe (“MMboe”), Proved (“1P”) reserves by 16 percent to 478.4 MMboe and Proved Developed Producing (“PDP”) reserves by 17 percent to 306.4 MMboe.
• On a 2P basis, the Company achieved reserve additions of 95.5 MMboe, replacing 197 percent of its 2021 production. Crescent Point benefited from the strategic Kaybob Duvernay acquisition, organic reserves additions, improved recovery factors associated with its decline mitigation programs and economic factors due to higher pricing. The Company’s 2P reserve life index (“RLI”) is approximately 15 years.
• Crescent Point generated 2P finding, development and acquisition (“FD&A”) costs, including change in future development capital (“FDC”), of $19.68 per boe, producing a recycle ratio of 2.2 times based on an operating netback of $42.43 per boe in 2021.
• On a PDP basis, the Company generated finding and development (“F&D”) costs, including change in FDC, of $12.22 per boe, producing a recycle ratio of 3.5 times. Crescent Point’s PDP FD&A costs, including change in FDC, totaled $15.93 per boe, resulting in a recycle ratio of 2.7 times.
• Crescent Point’s 2P and 1P net asset value (“NAV”) was $16.56 and $11.18 per share, respectively, at year-end 2021, based on independent engineering pricing. On a PDP basis, NAV was $7.62 per share and increased by approximately 15 percent compared to the prior year, adjusting for year-over-year changes in pricing and excluding land and seismic. This NAV forecast assumes an average WTI price of approximately US$69/bbl in the first five years.
• Crescent Point’s 2P FDC increased by approximately $400 million, or 10 percent, to $4.6 billion primarily driven by location additions from its Kaybob Duvernay play. This FDC equates to a conservative program that is also aligned with the Company’s current level of capital spending and five year plan.

In contrast to the prior year, Crescent Point elected to use a single independent evaluator to determine its 2021 corporate reserves, providing consistency across the evaluation process. Certain reserves metrics, including F&D costs, FD&A costs and recycle ratios, may not be meaningful or comparable year-over-year given significant portfolio changes executed over the last three years. Additional information on the Company’s 2021 reserves is provided in its Annual Information Form (“AIF”) for the year-ended December 31, 2021.

OUTLOOK

Crescent Point’s strong 2021 results highlight the continued success of its operational, financial and strategic execution.

The Company is on track to meet its 2022 average production guidance of 133,000 to 137,000 boe/d within its development capital expenditures budget of $825 to $900 million. This budget remains unchanged, despite a stronger commodity price environment, as management remains disciplined and focused on generating significant excess cash flow to create shareholder value. Crescent Point’s capital expenditures guidance also remains unchanged, despite continued cost inflation pressures, due to the Company’s ongoing efforts to realize internal efficiencies and its supply chain management. Assuming US$80/bbl WTI for the remainder of the year, Crescent Point’s budget is expected to generate approximately $1.1 billion of excess cash flow in 2022.

The Company continues to prioritize its balance sheet as it moves closer to achieving its near-term leverage target of approximately 1.0 times net debt to adjusted funds flow at US$55/bbl WTI, or approximately $1.3 to $1.4 billion of absolute net debt. At current commodity prices, Crescent Point expects to achieve this near-term debt target over the next six months.

The Company will look to provide increased returns to shareholders and a more defined return of capital framework as the balance sheet continues to strengthen. Based on Crescent Point’s continued successes and improving outlook, the Company is increasing its total planned share repurchases to up to $150 million, which it expects to execute by mid-2022, from $100 million announced previously.

Crescent Point is committed to a model that returns capital to shareholders while also generating additional returns through debt-adjusted per share growth.

Net debt to adjusted funds flow is a specified financial measure – refer to the Specified Financial Measures section in this press release for further information.

Summary of Reserves

The Company’s reserves were independently evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”) as at December 31, 2021. The reserves evaluation and reporting was conducted in accordance with the definitions, standards and procedures contained in the COGEH and National Instrument 51-101 Standards for Disclosure of Oil and Gas Activities (“NI 51-101”).

As at December 31, 2021 ^{(1) (2) (3) (4)}

	Tight Oil (Mbbls)		Light and Medium Oil (Mbbls)		Heavy Oil (Mbbls)				Natural Gas Liquids (Mbbls)
Reserves Category	Gross	Net	Gross	Net	Gross		Net		Gross	Net
Proved Developed Producing	118,028	109,274	46,241	41,857	20,230		16,839		71,949	63,859
Proved Developed Non-Producing	1,761	1,462	528	505	2,352		2,136		504	418
Proved Undeveloped	61,755	55,934	14,353	13,561	1,677		1,460		57,577	51,195
Total Proved	181,545	166,669	61,122	55,922	24,259		20,434		130,029	115,471
Total Probable	107,868	98,235	40,574	36,729	7,255		6,091		47,742	40,108
Total Proved plus Probable	289,413	264,905	101,696	92,651	31,514		26,525		177,772	155,579
	Shale Gas (MMcf)		Natural Gas (MMcf)		Total (Mboe)
Reserves Category	Gross	Net	Gross	Net	Gross	Net
Proved Developed Producing	259,805	241,945	39,979	36,719	306,412	278,273
Proved Developed Non-Producing	1,504	1,239	165	148	5,423	4,751
Proved Undeveloped	183,576	169,285	3,468	3,223	166,536	150,900
Total Proved	444,884	412,469	43,612	40,090	478,371	433,924
Total Probable	158,493	144,084	25,077	23,108	234,035	209,029
Total Proved plus Probable	603,377	556,553	68,690	63,198	712,406	642,952

 

(1)	Based on three evaluator’s average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) December 31, 2021, escalated price forecast.
(2)	“Gross Reserves” are the total Company’s working-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 Tax Net Present Values

As at December 31, 2021 ^{(1)  (2)} 

			Before Tax Net Present Value ($ millions)
			Discount Rate
Price Deck	Reserves Category	Gross Reserves (Mboe)	0%	5%	10%		15%
Three Evaluator Average	Proved Developed Producing	306,412	8,628	7,119	5,995		5,207
	Total Proved	478,371	12,600	9,948	8,078		6,781
	Total Proved plus Probable	712,406	20,714	14,723	11,230		9,037
(1)	Price deck based on three evaluator’s average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) December 31, 2021, escalated price forecast.
(2)	Numbers may not add due to rounding.

RESERVES RECONCILIATION

Gross Reserves ^{(1) (2) (3) (4)}

	Tight Oil (Mbbls)					Light and Medium Oil (Mbbls)					Heavy Oil (Mbbls)
Factors	Proved		Probable		Proved plus Probable	Proved	Probable		Proved plus P robable		Proved		Probable		Proved plus Probable
December 31, 2020	206,262		136,923		343,185	83,454	53,678		137,131		24,935		6,665		31,600
Extensions and Improved Recovery	12,139		216		12,355	6,786	1,753		8,539		1,810		1,362		3,173
Technical Revisions	(17,677)		(27,407)		(45,085)	(3,267)	(2,184)		(5,451)		(1,863)		(939)		(2,802)
Acquisitions	–		–		–	24	6		30		–		–		–
Dispositions	(1,943)		(3,393)		(5,336)	(23,463)	(14,422)		(37,885)		–		–		–
Economic Factors	5,575		1,530		7,104	4,107	1,744		5,851		911		167		1,078
Production	(22,810)		–		(22,810)	(6,519)	–		(6,519)		(1,534)		–		(1,534)
December 31, 2021	181,545		107,868		289,413	61,122	40,574		101,696		24,259		7,255		31,514
	Natural Gas Liquids (Mbbls)				Shale Gas (MMcf)			Natural Gas (MMcf)
Factors	Proved	Probable		Proved plus Probable	Proved	Probable	Proved plus Probable	Proved		Probable		Proved plus Probable
December 31, 2020	58,082	33,832		91,914	176,738	110,880	287,618	52,042		29,381		81,423
Extensions and Improved Recovery	31,404	6,241		37,645	113,922	20,659	134,581	1,581		820		2,402
Technical Revisions	(4,385)	(4,344)		(8,729)	(14,641)	(17,625)	(32,266)	(1,970)		(1,940)		(3,910)
Acquisitions	54,314	12,327		66,641	203,901	48,064	251,966	–		–		–
Dispositions	(1,396)	(1,159)		(2,554)	(3,188)	(5,272)	(8,460)	(7,728)		(4,712)		(12,440)
Economic Factors	2,615	845		3,460	5,793	1,786	7,579	3,822		1,527		5,350
Production	(10,605)	–		(10,605)	(37,640)	–	(37,640)	(4,135)		–		(4,135)
December 31, 2021	130,029	47,742		177,772	444,884	158,493	603,377	43,612		25,077		68,690

 

	Total Oil Equivalent (Mboe)
Factors	Proved	Probable	Proved plus Probable
December 31, 2020	410,862	254,476	665,338
Extensions and Improved Recovery	71,389	13,151	84,541
Technical Revisions	(29,961)	(38,135)	(68,096)
Acquisitions	88,322	20,343	108,665
Dispositions	(28,621)	(20,638)	(49,259)
Economic Factors	14,810	4,838	19,648
Production	(48,429)	–	(48,429)
December 31, 2021	478,371	234,035	712,406
(1)	Based on three evaluator’s average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) December 31, 2021, escalated price forecast.
(2)	“Gross Reserves” are the total Company’s working-interest share before the deduction of any royalties and without including any royalty interest of the Company.
(3)	Numbers may not add due to rounding

Finding, Development and Acquisition Costs for 2021

The Company’s F&D costs, FD&A costs and recycle ratios may not be meaningful or comparable year-over-year given significant portfolio changes executed over the last three years.

	F&D	Change in FDC on F&D	F&D Total (incl. change in FDC)	FD&A	Change in FDC	FD&A Total (incl. change in FDC)
Capital ($ millions)
Total Proved plus Probable	629	319	948	1,472	407	1,879
Total Proved	629	190	819	1,472	458	1,931
Proved Developed Producing	629	(38)	591	1,472	(6)	1,467
Reserves Additions (Mboe)
Total Proved plus Probable	36,092	–	36,092	95,498	–	95,498
Total Proved	56,238	–	56,238	115,939	–	115,939
Proved Developed Producing	48,338	–	48,338	92,066	–	92,066
Costs ($/boe) (1)
Total Proved plus Probable	$17.43	–	$26.27	$15.42	–	$19.68
Total Proved	$11.19	–	$14.56	$12.70	–	$16.65
Proved Developed Producing	$13.01	–	$12.22	$15.99	–	$15.93
Recycle Ratio (2)
Total Proved plus Probable	2.4	–	1.6	2.7	–	2.2
Total Proved	3.8	–	2.9	3.3	–	2.5
Proved Developed Producing	3.3	–	3.5	2.6	–	2.7
(1)	Numbers may not add due to rounding.
(2)	F&D and FD&A are calculated by dividing the identified capital expenditures by the applicable reserves additions. These can include or exclude changes in future development capital costs.
(3)	Recycle ratio is calculated as operating netback before hedging divided by F&D or FD&A costs. Based on a 2021 operating netback of $42.43 per boe.

Future Development Capital 

At year-end 2021, FDC for 2P reserves totaled $4.6 billion, compared to $4.2 billion at year-end 2020. The Company’s FDC increased by approximately $400 million, primarily driven by location additions from its Kaybob Duvernay play.

Company Annual Capital Expenditures ($ millions)
	Canada			U.S.		Total
Year	Total Proved	Total Proved + Probable		Total Proved	Total Proved + Probable	Total Proved	Total Proved + Probable
2022	608	612		130	130	738	742
2023	551	607		51	128	602	736
2024	606	742		121	141	727	883
2025	550	727		81	137	631	864
2026	284	505		6	138	290	643
2027	6	399		–	24	6	424
2028	4	265		–	–	4	265
2029	3	3		–	–	3	3
2030	3	3		–	–	3	3
2031	5	3		–	–	5	3
2032	3	2		–	–	3	2
2033	1	1		–	–	1	1
Subtotal (1)	2,624	3,870		390	699	3,014	4,568
Remainder	3	9		–	–	3	9
Total (1)	2,627	3,878		390	699	3,017	4,577
10% Discounted	2,134	2,941		331	558	2,465	3,499
(1)	Numbers may not add due to rounding.

CONFERENCE CALL DETAILS

Crescent Point management will host a conference call on Thursday, March 3, 2022 at 10:00 a.m. MT (12:00 p.m. ET) to discuss the Company’s results and outlook. A slide deck will accompany the conference call and can be found on Crescent Point’s website.

Participants can listen to this event online via webcast. Alternatively, the conference call can be accessed by dialing 1–888–390–0605.

The webcast will be archived for replay and can be accessed on Crescent Point’s conference calls and webcasts webpage under the invest tab. The replay will be available approximately one hour following completion of the call.

Shareholders and investors can also find the Company’s most recent investor presentation on Crescent Point’s website.

2022 GUIDANCE

The Company’s guidance for 2022 is as follows:

Total Annual Average Production (boe/d) (1)	133,000 – 137,000
Capital Expenditures
Development capital expenditures ($ millions)	$825 – $900
Capitalized G&A ($ millions)	$40
Total ($ million) (2)	$865 – $940

 

Other Information for 2022 Guidance
Reclamation activities ($ millions) (3)	$20
Capital lease payments ($ millions)	$20
Annual operating expenses ($/boe)	$13.25 – $13.75
Royalties	12.5% – 13.5%
1)	Total annual average production (boe/d) is comprised of approximately 80% Oil & NGLs and 20% Natural Gas
2)	Land expenditures and net property acquisitions and dispositions are not included. Development capital expenditures spend is allocated on an approximate basis as follows: 85% drilling & development and 15% facilities & seismic
3)	Reflects Crescent Point’s portion of its expected total budget

The Company’s audited financial statements and management’s discussion and analysis for the year ended December 31, 2021, will be available on the System for Electronic Document Analysis and Retrieval (“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$ millions except per share and per boe amounts)	2021	2020	2021	2020
Financial
Cash flow from operating activities	492.4	245.1	1,495.8	860.5
Adjusted funds flow from operations	432.5	220.2	1,476.9	874.4
Per share (2)	0.74	0.41	2.57	1.64
Net income (loss)	121.6	(51.2)	2,364.1	(2,519.9)
Per share (2)	0.21	(0.10)	4.11	(4.76)
Adjusted net earnings from operations (1)	160.0	85.6	515.3	177.4
Per share (1) (2)	0.27	0.16	0.90	0.33
Dividends declared	26.0	1.4	47.8	9.4
Per share (2)	0.0450	0.0025	0.0825	0.0175
Net debt	2,005.0	2,149.2	2,005.0	2,149.2
Net debt to adjusted funds flow from operations (3)	1.4	2.5	1.4	2.5
Weighted average shares outstanding
Basic	582.1	530.0	569.2	529.3
Diluted	587.7	534.4	575.1	531.8
Operating
Average daily production
Crude oil and condensate (bbls/d)	88,544	87,512	95,839	95,859
NGLs (bbls/d)	20,884	13,033	17,769	14,542
Natural gas (mcf/d)	125,871	64,033	114,452	67,447
Total (boe/d)	130,407	111,217	132,683	121,642
Average selling prices (4)
Crude oil and condensate ($/bbl)	91.27	49.40	78.43	43.50
NGLs ($/bbl)	47.59	24.96	42.33	17.19
Natural gas ($/mcf)	5.66	3.42	4.51	3.02
Total ($/boe)	75.05	43.76	66.21	38.01
Netback ($/boe)
Oil and gas sales	75.05	43.76	66.21	38.01
Royalties	(9.57)	(5.65)	(8.44)	(4.88)
Operating expenses	(12.85)	(13.30)	(12.91)	(12.62)
Transportation expenses	(2.48)	(2.29)	(2.43)	(2.27)
Operating netback	50.15	22.52	42.43	18.24
Realized gain (loss) on commodity derivatives	(9.60)	4.03	(7.45)	5.52
Other (5)	(4.50)	(5.03)	(4.48)	(4.12)
Adjusted funds flow from operations netback (1)	36.05	21.52	30.50	19.64
Capital Expenditures
Capital acquisitions (6)	5.2	—	942.4	1.4
Capital dispositions (6)	(0.1)	1.1	(99.0)	(508.2)
Development capital expenditures
Drilling and development	198.9	152.3	523.7	586.5
Facilities and seismic	30.6	17.1	100.5	68.3
Total	229.5	169.4	624.2	654.8
Land expenditures	0.8	0.8	4.9	3.6
(1)	Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section for further information.
(2)	The per share amounts (with the exception of dividends per share) are the per share – diluted amounts.
(3)	Net debt to adjusted funds flow from operations is calculated as the period end net debt divided by the sum of adjusted funds flow from operations for the trailing four quarters.
(4)	The average selling prices reported are before realized derivatives and transportation.
(5)	Other includes net purchased products, general and administrative expenses, interest on long-term debt, foreign exchange, cash-settled share-based compensation and certain cash items and excludes transaction costs, foreign exchange on US dollar long-term debt and certain non-cash items.
(6)	Capital dispositions, net represent total consideration for the transactions, including long-term debt and working capital assumed, and exclude transaction costs.

Specified Financial Measures

Throughout this press release, the Company uses the terms “adjusted funds flow” (equivalent to “adjusted funds flow from operations”), “adjusted funds flow from operations per share – diluted”, “adjusted net earnings from operations”, “adjusted net earnings from operations per share – diluted”, “excess cash flow”, “net debt”, “net debt to adjusted funds flow” (equivalent to “net debt to adjusted funds flow from operations”), “recycle ratio”, “total operating netback”, “total netback”, “operating netback”, “netback”, “adjusted funds flow from operations netback” and “adjusted working capital deficiency”. 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. For information on the composition of these measures and how the Company uses these measures, refer to the Specified Financial Measures section of the Company’s MD&A for the year ended December 31, 2021, which section is incorporated herein by reference, and available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar.

Adjusted funds flow from operations netback is a non-GAAP financial ratio and is calculated as adjusted funds flow from operations divided by total production. Adjusted funds flow from operations netback is a common metric used in the oil and gas industry and is used to measure operating results on a per boe basis.

The following table reconciles oil and gas sales to total operating netback, total netback and adjusted funds flow from operations netback:

		Three months ended December 31						Year ended December 31
($ millions)		2021		2020		% Change		2021		2020			% Change
Oil and gas sales		900.4		447.8		101		3,206.5		1,692.2			89
Royalties		(114.8)		(57.8)		99		(408.8)		(217.1)			88
Operating expenses		(154.2)		(136.1)		13		(625.3)		(561.8)			11
Transportation expenses		(29.8)		(23.4)		27		(117.7)		(101.1)			16
Total operating netback		601.6		230.5		161		2,054.7		812.2			153
Realized gain (loss) on commodity derivatives		(115.2)		41.2		(380)		(360.8)		245.7			(247)
Total netback		486.4		271.7		79		1,693.9		1,057.9			60
Other (1)		(53.9)		(51.5)		5		(217.0)		(183.5)			18
Total adjusted funds flow from operations netback		432.5		220.2		96		1,476.9		874.4			69
(1)		Other includes net purchased products, general and administrative expenses, interest on long-term debt, foreign exchange, cash-settled share-based compensation and certain cash items and excludes transaction costs, foreign exchange on US dollar long-term debt and certain non-cash items.

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

	Three months ended December 31						Year ended December 31
($ millions)	2021		2020 (1)		% Change		2021		2020 (1)			% Change
Cash flow from operating activities	492.4		245.1		101		1,495.8		860.5			74
Changes in non-cash working capital	(69.1)		(29.0)		138		(51.6)		(6.2)			732
Transaction costs	0.3		—		100		12.5		5.4			131
Decommissioning expenditures (2)	8.9		4.1		117		20.2		14.7			37
Adjusted funds flow from operations	432.5		220.2		96		1,476.9		874.4			69
Capital expenditures	(242.9)		(181.6)		34		(676.1)		(698.8)			(3)
Payments on lease liability	(5.6)		(5.2)		8		(21.2)		(30.0)			(29)
Decommissioning expenditures	(8.9)		(4.1)		117		(20.2)		(14.7)			37
Other items (3)	7.3		13.1		(44)		29.0		0.5			5,700
Excess cash flow	182.4		42.4		330		788.4		131.4			500
(1)	Comparative period revised to reflect current year presentation.
(2)	Excludes amounts received from government subsidy programs.
(3)	Other items include, but are not limited to, unrealized gains on equity derivative contracts, sale of long-term investments and transaction costs. Other items exclude net acquisitions and dispositions.

Adjusted funds flow from operations per share – diluted is a supplementary financial measure and is calculated as adjusted funds flow from operations divided by the number of weighted average diluted shares outstanding. It is used as a key measure to assess the ability of the Company to finance dividends, operating activities, capital expenditures and debt repayments.

The following table reconciles adjusted working capital deficiency:

($ millions)	2021		2020		% Change
Accounts payable and accrued liabilities	450.7		310.3		45
Dividends payable	43.5		1.3		3,246
Long-term compensation liability (1)	42.6		16.3		161
Cash	(13.5)		(8.8)		53
Accounts receivable	(314.3)		(200.5)		57
Prepaids and deposits	(7.4)		(22.7)		(67)
Long-term investments	—		(2.5)		(100)
Adjusted working capital deficiency	201.6		93.4		116
(1)	Includes current portion of long-term compensation liability and is net of equity derivative contracts.

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

($ millions)		2021		2020		% Change
Long-term debt (1)		1,970.2		2,259.6		(13)
Adjusted working capital deficiency		201.6		93.4		116
Unrealized foreign exchange on translation of US dollar long-term debt		(166.8)		(203.8)		(18)
Net debt		2,005.0		2,149.2		(7)
(1)		Includes current portion of long-term debt.

The following table reconciles net income (loss) to adjusted net earnings from operations:

	Three months ended December 31						Year ended December 31
($ millions)	2021		2020		% Change		2021		2020		% Change
Net income (loss)	121.6		(51.2)		(338)		2,364.1		(2,519.9)		(194)
Amortization of E&E undeveloped land	9.6		13.9		(31)		51.0		71.9		(29)
Impairment (impairment reversal)	—		—		100		(2,514.4)		3,557.8		(171)
Unrealized derivative (gains) losses	(87.1)		185.5		(147)		141.4		112.5		26
Unrealized foreign exchange gain on translation of hedged US dollar long-term debt	(13.1)		(86.2)		(85)		(37.0)		(62.1)		(40)
Unrealized (gain) loss on long-term investments	—		(0.9)		(100)		(3.1)		4.2		(174)
Gain on sale of long-term investments	—		—		(100)		(7.0)		—		(100)
Net gain on capital dispositions	—		(8.5)		(100)		(58.4)		(316.4)		(82)
Deferred tax adjustments	129.0		33.0		291		578.7		(670.6)		(186)
Adjusted net earnings from operations	160.0		85.6		87		515.3		177.4		190

Recycle ratio is a non-GAAP ratio and is calculated as operating netback before hedging divided by FD&A costs. Recycle ratios may not be comparable year-over-year given significant changes executed over the last three years. Recycle ratio is a common metric used in the oil and gas industry and is used to measure profitability on a per boe basis.

Excess cash flow forecasted for 2022 is a forward-looking non-GAAP measure and is calculated consistently with the measure disclosed in the Company’s MD&A. Refer to the Specified Financial Measures section of the Company’s MD&A for the year ended December 31, 2021.

Management believes the presentation of the specified financial measures above provide useful information to investors and shareholders as the measures provide increased transparency and the ability to better analyze performance against prior periods on a comparable basis.

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. Further, the SEC rules are based on unescalated costs and forecasts.

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

Forward-Looking Statements

Any “financial outlook” or “future oriented financial information” in this 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.

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 (collectively, “forward-looking statements”). 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, among other things, to the following: excess cash flow generation in 2022; timing and amount of share repurchases and renewal of NCIB program; retention of significant liquidity; the risk management program protects cash flow generation; the Company remaining disciplined in its hedging program; the Company’s strengthening financial position; well cost savings providing additional insulation to the Company’s capital budget in the current inflationary environment; the Company seeking to further enhance returns in the Kaybob-Duvernay play, through ongoing drilling and completions optimization; sustainable cost efficiencies; Kaybob Duvernay wells generating full-cycle rates of return of over 120 percent and payout in less than a year, at current commodity priced and budged cost inflation assumptions;  the Company’s 2022 waterflood program; continued progression of decline mitigation programs; target for emissions intensity reduction to 50 percent of 2017 levels by 2025, including a 70 percent reduction in methane emissions (compared to 2017 levels); Crescent Point on track to meet or exceed its existing emissions targets before 2025 and plans to revisit its current emissions reduction goals in second quarter 2022; plans to retire approximately 350 wells in 2022; prospects for the Kaybob Duvernay assets; the opportunity to enhance shareholder value through potential cost efficiencies, productivity improvements, new locations and reserves; 2P reserves life index; the Company is on track to meet its 2022 average production guidance of 133,000 to 137,000 boe/d within its development capital expenditures budget of $825 to $900 million; management remains disciplined and focused on generating significant excess cash flow to create shareholder value; Crescent Point’s 5 year plan and related FDC spending; assuming US$80/bbl WTI, Crescent Point’s budget is expected to generate approximately $1.1 billion of excess cash flow in 2022; prioritized balance sheet; moving toward the Company’s near-term leverage target of approximately 1.0 times net debt to adjusted funds flow at US$55/bbl WTI, or approximately $1.3 to $1.4 billion of absolute net debt; at current commodity prices, the Company expects to achieve its near-term debt target over the next six months; Crescent Point’s plans to provide increased returns to shareholders alongside a more defined return of capital framework as the balance sheet strengthens; the Company’s commitment to a model that returns capital to shareholders while also generating additional returns through debt-adjusted per share growth; Crescent Point’s 2022 production and development capital expenditures guidance; and other information for Crescent Point’s 2022 guidance, including capitalized G&A, reclamation activities, capital lease payments, operating expenses and royalties.

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.

Unless otherwise noted, reserves referenced herein are given as at December 31, 2021. Also, estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates and future net revenue for all properties due to the effect of aggregation. All required reserve information for the Company is contained in its Annual Information Form for the year ended December 31, 2021, which is accessible at www.sedar.com.

With respect to disclosure contained herein regarding resources other than reserves, there is uncertainty that it will be commercially viable to produce any portion of the resources and there is significant uncertainty regarding the ultimate recoverability of such resources.

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 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, 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 the Company’s Annual Information Form for the year ended December 31, 2021 under “Risk Factors” and our Management’s Discussion and Analysis for the year ended December 31, 2021, 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, 2021, under the headings “Overview”, “Commodity Derivatives”, “Liquidity and Capital Resources” and “Guidance”. 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, decisions or actions of OPEC and non-OPEC countries in respect of supplies of oil and gas; delays in business operations or delivery of services due to pipeline restrictions, rail blockades, outbreaks, blowouts and business closures and social distancing measures mandated by public health authorities in response to COVID-19; uncertainty regarding the benefits and costs of acquisitions and dispositions; failure to complete acquisitions and dispositions; 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 Indigenous 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 and likelihood of acquisitions and dispositions, and exploration and development programs; unexpected geological, technical, drilling, construction, processing and transportation problems; availability of insurance; fluctuations in foreign exchange and interest rates; stock market volatility; general economic, market and business conditions, including uncertainty in the demand for oil and gas and economic activity in general as a result of the COVID-19 pandemic; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainty regarding the benefits and costs of dispositions; failure to complete acquisitions and dispositions; uncertainties associated with credit facilities and counterparty credit risk; changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry; the wide-ranging impacts of the COVID-19 pandemic, including on demand, health and supply chain; and other factors, many of which are outside the control of the Company. 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. Crescent Point undertakes no obligation to update publicly or revise any forward-looking statements, 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.

Product Type Production Information

The Company’s annual aggregate production for 2021 and 2020, the aggregate average production for fourth quarter of 2021 and 2020, and the references to “natural gas” and “crude oil”, reported in this Press Release consist of the following product types, as defined in NI 51-101 and using a conversion ratio of 6 mcf : 1 bbl where applicable:

	Three months ended December 31		Year ended December 31
	2021	2020	2021	2020
Light & Medium Crude Oil (bbl/d)	15,517	21,025	17,859	20,842
Heavy Crude Oil (bbl/d)	4,226	4,276	4,203	4,380
Tight Oil (bbl/d)	55,965	62,211	62,492	70,637
Total Crude Oil (bbl/d)	75,708	87,512	84,554	95,859
NGLs (bbl/d)	33,720	13,033	29,054	14,542
Shale Gas (mcf/d)	115,482	52,370	103,124	53,666
Conventional Natural Gas (mcf/d)	10,389	11,663	11,328	13,781
Total Natural Gas (mcf/d)	125,871	64,033	114,452	67,447
Total (boe/d)	130,407	111,217	132,683	121,642

NI 51-101 includes condensate within the natural gas liquids (NGLs) product type. The Company has disclosed condensate as combined with crude oil and/or separately from other natural gas liquids in this press release since the price of condensate as compared to other natural gas liquids is currently significantly higher and the Company believes that this crude oil and condensate presentation provides a more accurate description of its operations and results therefore.

DEFINITIONS

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

Finding, development and acquisition costs (FD&A) are equivalent to F&D costs plus the costs of acquiring and disposing particular assets.

Full cycle rate of return is the internal rate of return of a well including the drilling, completion, equipping, tie-in and facility costs of the project.

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

Net asset value (NAV) or 2P 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 based on three evaluators’ average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) December 31, 2021 escalated price forecast, the fair value for the Company’s oil and gas hedges based on such December 31, 2021 escalated price forecast, and 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 and is based on the netbacks reported above.

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 proved reserves and possible reserves are less certain than probable reserves.

Reserves Life Index is calculated as proved plus probable reserves divided by production.

Reserves and Drilling Data

The reserves information contained in this press release has been prepared in accordance with 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.

Initial production is for a limited time frame only (30 days) and may not be indicative of future performance. Booked type well data was audited by independent reserves evaluator, McDaniel, effective December 31, 2021.

This press release contains metrics commonly used in the oil and natural gas industry, including “netbacks”, “F&D costs”, “FD&A costs”, “FDC”, “NAV”, “recycle ratio”, “payout ratio” 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. Readers are cautioned as to the reliability of oil and gas metrics used in this press release.

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

Payout is the point at which all costs associated with leasing, exploring, drilling and operating have been recovered from the production of a well. It is an indication of profitability.

NAV is an estimate of the value of the Company’s net assets.

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.

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, 2021, which will be filed on SEDAR (accessible at www.sedar.com) and EDGAR (accessible at www.sec.gov/edgar.shtml) on or before March 3, 2022 and further supplemented by Material Change Reports as applicable.

FOR MORE INFORMATION ON CRESCENT POINT ENERGY, PLEASE CONTACT:

Shant Madian, Vice President, Capital Markets

Sarfraz Somani, Manager, Investor Relations

Telephone: (403) 693-0020 Toll-free (US and Canada): 888-693-0020  Fax: (403) 693-0070

Address: Crescent Point Energy Corp. Suite 2000, 585 – 8th Avenue S.W. Calgary AB  T2P 1G1

www.crescentpointenergy.com

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

SOURCE Crescent Point Energy Corp.

 

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