CALGARY, AB, March 2, 2023 /PRNewswire/ - Crescent Point Energy Corp. ("Crescent Point" or the "Company") (TSX:CPG) (NYSE:CPG) is pleased to announce its operating and financial results for the year ended December 31, 2022.

KEY HIGHLIGHTS

Generated significant excess cash flow of approximately $1.2 billion, driven by a strong netback asset base.
Reduced net debt by approximately $850 million, or over 40 percent.
Returned nearly $500 million to shareholders through dividends and share repurchases totaling over five percent of the float.
Increased drilling inventory in the Kaybob Duvernay to over 20 years while optimizing portfolio through non-core dispositions.
Increased NAV per share by 30 to 35 percent across all categories and replaced 113 percent of 2022 production on a 2P basis.
Generated strong FD&A recycle ratios, including change in FDC, of 3.4 and 2.3 times based on PDP and 2P reserves.
Achieved best safety scores in company history and remain on track to meet or exceed land, emissions and water targets.
Expect to generate significant excess cash flow of approximately $1.0 billion in 2023 at US$75/bbl WTI.

"Our success in 2022 demonstrates our ability to execute our long-term strategy of capital discipline, balance sheet strength, sustainability and returning capital to our shareholders," said Craig Bryksa, President and CEO of Crescent Point. "Since beginning this transformation five years ago, we have delivered consistent and compounding benefits for our shareholders. Our multi-basin portfolio generates significant excess cash flow driven by industry leading netbacks, which we have further enhanced through the addition of our Kaybob Duvernay asset. This, combined with our superior technical, operational and safety performance, positions us to deliver substantial returns to shareholders now and well into the future."

FINANCIAL HIGHLIGHTS

Adjusted funds flow totaled over $2.2 billion for the year ended December 31, 2022, or $3.91 per share diluted, driven by a strong operating netback of $62.94 per boe. In fourth quarter, adjusted funds flow totaled $522.8 million, or $0.93 per share diluted.
For the year ended December 31, 2022, development capital expenditures, which included drilling and development, facilities and seismic costs, totaled $956.1 million, in-line with the Company's annual guidance of $950 million.
Net debt as at December 31, 2022 was less than $1.2 billion, reflecting a reduction of $850.3 million, or over 40 percent since the beginning of 2022. On January 11, 2023, Crescent Point closed its acquisition of additional Kaybob Duvernay assets, which included a net cash payment of approximately $370 million. As of the acquisition close, Crescent Point's net debt was approximately $1.5 billion.
For the year ended December 31, 2022, Crescent Point reported net income of approximately $1.5 billion. The Company's 2022 net income includes the positive contribution of a $0.4 billion ($0.3 billion after-tax) non-cash impairment reversal due to higher commodity prices, net of increased cost assumptions due to inflation.
As part of its risk management program, Crescent Point has hedged approximately 15 percent of its total production in 2023, net of royalty interest, including over 20 percent in the first half of the year.

RETURN OF CAPITAL HIGHLIGHTS

In July 2022, the Company updated its return of capital framework to target the return of up to 50 percent of its discretionary excess cash flow, in addition to its base dividend, through a combination of share repurchases and special dividends.
The Company's total return of capital to its shareholders in 2022 was $483.3 million comprised of base dividends, share repurchases and special dividends. This included $287.8 million in the second half of the year under its updated framework, or approximately 60 percent of its excess cash flow.
During fourth quarter, Crescent Point repurchased 8.6 million shares for $86.6 million, bringing total repurchases to 31.3 million shares for $294.2 million in 2022, representing over five percent of its public float. The Company remains active on its normal course issuer bid ("NCIB") and has repurchased 3.2 million shares for $30.0 million to-date in 2023. Crescent Point has filed notice with the Toronto Stock Exchange ("TSX") of the intention to renew its NCIB, which is due to expire on March 8, 2023.
The Company's Board of Directors ("Board") has declared a special cash dividend, based on fourth quarter 2022 results, of $0.032 per share payable on March 17, 2023, to shareholders of record as of the close of business on March 10, 2023.
As previously announced, Crescent Point's Board approved and declared a first quarter 2023 dividend of $0.10 per share, payable on April 3, 2023 to shareholders of record on March 15, 2023. This equates to an annualized dividend of $0.40 per share, an increase of 25 percent from the prior level or 122 percent since the beginning of 2022.

Adjusted funds flow, adjusted funds flow per share diluted, excess cash flow, recycle ratio, operating netback, total return of capital and net debt 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 132,282 boe/d in 2022, comprised of over 80 percent oil and liquids, in-line with production guidance of 132,000 boe/d. Crescent Point's average production in fourth quarter 2022 was 134,124 boe/d.
In the Kaybob Duvernay, the Company brought its sixth fully operated multi-well pad on-stream in early 2023. This multi-well pad, which was located in the liquids-rich phase of the basin, generated an average 30-day initial production (IP) rate of approximately 1,235 boe/d per well (51% condensate, 15% NGLs). This strong performance further demonstrates Crescent Point's consistency in its operational execution in the play.
The Kaybob Duvernay asset continues to generate significant excess cash flow driven by strong netbacks and high mix of condensate production. As a result, Crescent Point expects to achieve a two-year payback period on its original Kaybob acquisition of approximately $900 million by the end of first quarter 2023.
In January 2023, the Company closed its previously announced acquisition of additional assets in the Kaybob Duvernay, which included approximately 130 net drilling locations and over 4,000 boe/d of production. The Company has identified over 20 years of inventory in the play, based on current production.
In the second half of 2022, Crescent Point began leveraging open hole multi-lateral drilling techniques in the Viewfield Bakken. The Company's most recent eight-leg wells have delivered strong IP30 rates averaging over 225 bbl/d per well. This innovation has materially improved returns by enhancing estimated ultimate reserves, lowering water cuts and improving capital efficiencies. The Company has identified approximately 150 additional locations with potential for open hole multi-lateral drilling within the play, equating to approximately four years of additional drilling inventory. Crescent Point plans to drill several of these wells in 2023, while also exploring the potential to implement this technique in other areas within its asset portfolio.
As part of its ongoing commitment to decline mitigation, the Company converted approximately 105 producing wells to water injection wells through its secondary recovery waterflood program in 2022. Crescent Point plans to convert a similar number of producing wells to water injection wells in 2023, while continuing to advance other decline mitigation projects.
Through its continued commitment to strong environmental, social and governance ("ESG") practices, Crescent Point achieved its Scope 1 emissions intensity reduction target of 50 percent, including a 70 percent reduction in absolute methane emissions, well ahead of its expected 2025 timeframe. The Company subsequently introduced a target to further reduce its Scope 1 and 2 emissions intensity by 38 percent by 2030, relative to its 2020 baseline. Crescent Point also announced two new water targets to build upon its existing strong water management performance, including a 50 percent reduction in surface freshwater use in southeast Saskatchewan completions by 2025. Furthermore, the Company has made significant progress toward its target to reduce its inactive well inventory by 30 percent by 2031 and expects to achieve this target ahead of schedule.
Crescent Point achieved its best serious incident frequency ("SIF") and total recordable incident frequency ("TRIF") scores in the Company's history, demonstrating its ongoing commitment to safe operations.
Crescent Point's continued commitment to ESG practices was recognized by Morgan Stanley Capital International ("MSCI") Inc. in 2022, as previously announced. In its ESG Ratings assessment, MSCI increased the Company's rating for the second consecutive year, improving its score to "AA".

RESERVES HIGHLIGHTS

"Our 2022 reserves highlight the success of our long-term strategy and development activities, particularly in the Kaybob Duvernay," said Bryksa. "Our proved plus probable reserves additions more than replaced our annual production and resulted in strong recycle ratios. Looking forward, we see significant opportunity to further enhance shareholder value through ongoing optimization and potential reserves growth, including in the Kaybob Duvernay where approximately 75 percent of locations are currently unbooked."

As at year-end 2022, Crescent Point's Proved plus Probable ("2P") reserves totaled 713.1 million boe ("MMboe"), Proved ("1P") reserves totaled 481.9 MMboe and Proved Developed Producing ("PDP") reserves totaled 301.3 MMboe. These totals exclude any reserves attributed to the Company's recent acquisition in the Kaybob Duvernay which closed in January 2023.
On a 2P basis, Crescent Point achieved reserve additions of 54.6 MMboe, replacing 113 percent of its 2022 production, excluding acquisitions and dispositions ("A&D"). The majority of these reserve additions originated from the Company's Kaybob Duvernay asset, which contributed organic 2P reserve adds of 50.0 MMboe, primarily through drilling and development activities. The remaining reserve additions were identified throughout the Company's other assets.
The Company's 2P reserve life index ("RLI") is approximately 15 years based on 2022 annual average production.
Crescent Point generated 2P finding, development and acquisition ("FD&A") costs, including change in future development capital ("FDC"), of $27.56 per boe, producing a recycle ratio of 2.3 times based on an operating netback of $62.94 per boe in 2022. The Company's PDP FD&A costs, including change in FDC, totaled $18.77 per boe, resulting in a recycle ratio of 3.4 times.
Strong performance from the Company's Kaybob Duvernay asset resulted in an attractive F&D of approximately $12.00 per boe for wells brought on-stream in 2022, equating to a strong recycle ratio of over 5.0 times.
The independent engineers have ascribed booked reserves in the Kaybob Duvernay, on the wells Crescent Point has drilled and completed since entering the play, ranging from approximately 700 Mboe (62% condensate, 11% NGLs) to 2,000 Mboe (21% condensate, 22% NGLs).
Crescent Point's 2P net asset value ("NAV") was $21.50 per share at year-end 2022, based on independent engineering pricing. On a 1P and PDP basis, the Company's NAV was $15.14 and $10.38 per share, respectively. These NAV forecasts, which include the reduction of net debt at year-end, represent an increase of approximately 30 to 35 percent compared to the prior year. The independent engineering price forecast assumes an average WTI price of approximately US$78.50/bbl in the first five years.

Additional information on the Company's 2022 reserves is provided in its Annual Information Form ("AIF") for the year-ended December 31, 2022.

OUTLOOK

Crescent Point's 2022 results demonstrate the success and consistency of its operational, financial and strategic execution.

The Company remains on track with its previously released 2023 average production guidance of 138,000 to 142,000 boe/d. Since last updating its annual guidance, Crescent Point has advanced plans to add a second rig in the Kaybob Duvernay in fourth quarter 2023 to further accelerate the development of its high-return inventory in the play. The addition of this rig is not expected to impact the Company's capital expenditures budget, which remains unchanged at $1.0 to $1.1 billion.

Crescent Point's 2023 budget is expected to generate significant excess cash flow of approximately $1.0 billion at US$75/bbl WTI, providing returns of over $600 million directly to shareholders, based on its framework. These returns are in addition to per-share growth and expected net debt reduction of approximately $400 million during the year.

Within its five-year plan, the Company expects to generate over $4.2 billion of cumulative after-tax excess cash flow from 2023 to 2027, assuming US$75/bbl WTI. Crescent Point's five-year outlook is supported by its Kaybob Duvernay play which is now expected to grow to over 60,000 boe/d in 2027, highlighting the continued outperformance of this asset. The Company's five-year plan remains disciplined, with a continued focus on returns and long-term sustainability.

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, 2022. 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, 2022 ^{(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	118,455	108,945	38,102	33,802	18,986	15,886	74,510	64,332
Proved Developed Non-Producing	2,395	1,984	337	323	2,323	2,108	2,719	2,211
Proved Undeveloped	48,806	44,385	10,757	10,023	1,731	1,583	69,253	58,722
Total Proved	169,657	155,313	49,197	44,148	23,039	19,578	146,482	125,266
Total Probable	101,378	91,946	36,550	32,419	7,230	6,127	52,892	42,655
Total Proved plus Probable	271,034	247,259	85,747	76,567	30,268	25,705	199,374	167,920

	Shale Gas (MMcf)		Natural Gas (MMcf)		Total (Mboe)
Reserves Category	Gross	Net	Gross	Net	Gross	Net
Proved Developed Producing	271,834	247,578	35,719	32,243	301,312	269,601
Proved Developed Non-Producing	13,953	12,435	69	59	10,111	8,709
Proved Undeveloped	235,901	212,657	3,491	3,251	170,446	150,698
Total Proved	521,688	472,670	39,279	35,553	481,868	429,008
Total Probable	175,480	152,970	23,599	21,366	231,230	202,203
Total Proved plus Probable	697,167	625,640	62,877	56,919	713,098	631,211

(1)	Based on three evaluator's average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) December 31, 2022, 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, 2022 ⁽¹⁾

			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	301,312	9,407	7,530	6,288	5,448
	Total Proved	481,868	14,592	11,153	8,932	7,441
	Total Proved plus Probable	713,098	23,972	16,523	12,460	9,969

(1)	Price deck based on three evaluator's average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) December 31, 2022, escalated price forecast.

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 Probable	Proved	Probable	Proved plus Probable
December 31, 2021	181,545	107,868	289,413	61,122	40,574	101,696	24,259	7,255	31,514
Extensions and Improved Recovery	2,511	(178)	2,333	2,000	741	2,741	93	30	123
Technical Revisions	2,462	(6,096)	(3,634)	(1,115)	(2,301)	(3,416)	(447)	(157)	(605)
Acquisitions	139	43	182	-	-	-	-	-	-
Dispositions	(710)	(1,023)	(1,733)	(9,052)	(3,046)	(12,098)	-	-	-
Economic Factors	3,368	764	4,133	1,453	582	2,034	603	102	706
Production	(19,659)	-	(19,659)	(5,210)	-	(5,210)	(1,470)	-	(1,470)
December 31, 2022	169,657	101,378	271,034	49,197	36,550	85,747	23,039	7,230	30,268

	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, 2021	130,029	47,742	177,772	444,884	158,493	603,377	43,612	25,077	68,690
Extensions and Improved Recovery	20,614	5,283	25,896	90,983	22,017	113,000	684	299	983
Technical Revisions	4,410	(1,253)	3,157	5,167	(10,983)	(5,816)	(2,149)	(1,955)	(4,104)
Acquisitions	10,046	2,494	12,540	61,482	15,322	76,804	-	-	-
Dispositions	(7,065)	(1,824)	(8,890)	(38,086)	(10,679)	(48,765)	(1,290)	(371)	(1,661)
Economic Factors	1,791	451	2,242	5,037	1,310	6,347	2,247	549	2,796
Production	(13,343)	-	(13,343)	(47,779)	-	(47,779)	(3,826)	-	(3,826)
December 31, 2022	146,482	52,892	199,374	521,688	175,480	697,167	39,279	23,599	62,877

	Total Oil Equivalent (Mboe)
Factors	Proved	Probable	Proved plus Probable
December 31, 2021	478,371	234,035	712,406
Extensions and Improved Recovery	40,496	9,595	50,090
Technical Revisions	5,813	(11,964)	(6,151)
Acquisitions	20,432	5,090	25,523
Dispositions	(23,390)	(7,735)	(31,125)
Economic Factors	8,429	2,209	10,639
Production	(48,283)	-	(48,283)
December 31, 2022	481,868	231,230	713,098

(1)	Based on three evaluator's average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) December 31, 2022, 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 2022

	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	975	597	1,572	782	568	1,350
Total Proved	975	383	1,359	782	387	1,170
Proved Developed Producing	975	28	1,004	782	28	811

Reserves Additions (Mboe)
Total Proved plus Probable	54,578	-	54,578	48,975	-	48,975
Total Proved	54,738	-	54,738	51,780	-	51,780
Proved Developed Producing	49,209	-	49,209	43,183	-	43,183

Costs ($/boe) ⁽¹⁾
Total Proved plus Probable	$17.87	-	$28.80	$15.97	-	$27.56
Total Proved	$17.82	-	$24.82	$15.11	-	$22.59
Proved Developed Producing	$19.82	-	$20.39	$18.12	-	$18.77

Recycle Ratio ⁽²⁾
Total Proved plus Probable	3.5	-	2.2	3.9	-	2.3
Total Proved	3.5	-	2.5	4.2	-	2.8
Proved Developed Producing	3.2	-	3.1	3.5	-	3.4

(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 2022 operating netback of $62.94 per boe.

Future Development Capital

At year-end 2022, FDC for 2P reserves totaled $5.1 billion, compared to $4.6 billion at year-end 2021. The Company's FDC increased by approximately $570 million, primarily driven by higher cost assumptions related to inflation and the addition of new drilling locations. This FDC equates to a conservative program that is also aligned with the Company's current level of capital spending and five-year plan.

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
2023	468	521	271	401	739	922
2024	608	732	36	232	644	964
2025	763	898	8	63	771	962
2026	624	725	-	-	624	725
2027	552	702	-	-	552	702
2028	52	652	-	-	52	652
2029	4	201	-	-	4	201
2030	5	5	-	-	5	5
2031	6	6	-	-	6	6
2032	2	2	-	-	2	2
2033	1	1	-	-	1	1
2034	1	1	-	-	1	1
Subtotal ⁽¹⁾	3,087	4,446	315	696	3,402	5,143
Remainder	2	2	-	-	2	2
Total ⁽¹⁾	3,089	4,448	315	696	3,404	5,145
10% Discounted	2,432	3,327	293	626	2,724	3,953

(1)	Numbers may not add due to rounding.

CONFERENCE CALL DETAILS

Crescent Point management will host a conference call on Thursday, March 2, 2023 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.

2023 GUIDANCE

The Company's guidance for 2023 is as follows:

Total Annual Average Production (boe/d)⁽¹⁾

138,000 - 142,000

Capital Expenditures
Development capital expenditures ($ millions)	$1,000 - $1,100
Capitalized administration ($ millions)	$40
Total ($ million) ⁽²⁾	$1,040 - $1,140

Other Information for 2023 Guidance
Reclamation activities ($ millions) ⁽³⁾	$40
Capital lease payments ($ millions)	$20
Annual operating expenses ($/boe)	$14.25 - $15.25
Royalties	13.75% - 14.25%

1)	Total annual average production (boe/d) is comprised of approximately 80% Oil, Condensate & 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: 90% drilling & development and 10% facilities & seismic
3)	Reflects Crescent Point's portion of its expected total budget

RETURN OF CAPITAL OUTLOOK

Base Dividend
Current quarterly base dividend per share	$0.10
Additional Return of Capital
% of discretionary excess cash flow ⁽¹⁾⁽²⁾	50 %

1)	Discretionary excess cash flow is calculated as excess cash flow less base dividends
2)	This % is part of a framework that targets to return up to 50% of discretionary excess cash flow to shareholders

The Company's audited consolidated financial statements and management's discussion and analysis for the year ended December 31, 2022, 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)	2022	2021	2022	2021
Financial
Cash flow from operating activities	589.5	492.4	2,192.2	1,495.8
Adjusted funds flow from operations	522.8	432.5	2,232.4	1,476.9
Per share⁽²⁾	0.93	0.74	3.91	2.57
Net income (loss)	(498.1)	121.6	1,483.4	2,364.1
Per share ⁽²⁾	(0.90)	0.21	2.60	4.11
Adjusted net earnings from operations ⁽¹⁾	209.8	160.0	965.7	515.3
Per share ^{(1) (2)}	0.38	0.27	1.69	0.90
Dividends declared	118.8	26.0	200.6	47.8
Per share ⁽²⁾	0.2150	0.0450	0.3600	0.0825
Net debt	1,154.7	2,005.0	1,154.7	2,005.0
Net debt to adjusted funds flow from operations⁽³⁾	0.5	1.4	0.5	1.4
Weighted average shares outstanding
Basic	555.2	582.1	566.7	569.2
Diluted	559.2	587.7	571.1	575.1
Operating
Average daily production
Crude oil and condensate (bbls/d)	90,759	88,544	91,679	95,839
NGLs (bbls/d)	17,770	20,884	17,039	17,769
Natural gas (mcf/d)	153,572	125,871	141,384	114,452
Total (boe/d)	134,124	130,407	132,282	132,683
Average selling prices ⁽⁴⁾
Crude oil and condensate ($/bbl)	103.42	91.27	115.72	78.43
NGLs ($/bbl)	38.55	47.59	45.02	42.33
Natural gas ($/mcf)	6.37	5.66	6.60	4.51
Total ($/boe)	82.39	75.05	93.06	66.21
Netback ($/boe)
Oil and gas sales	82.39	75.05	93.06	66.21
Royalties	(10.61)	(9.57)	(12.45)	(8.44)
Operating expenses	(14.50)	(12.85)	(14.77)	(12.91)
Transportation expenses	(3.09)	(2.48)	(2.90)	(2.43)
Operating netback	54.19	50.15	62.94	42.43
Realized loss on commodity derivatives	(7.75)	(9.60)	(13.29)	(7.45)
Other ⁽⁵⁾	(4.07)	(4.50)	(3.41)	(4.48)
Adjusted funds flow from operations netback ⁽¹⁾	42.37	36.05	46.24	30.50
Capital Expenditures
Capital acquisitions ⁽⁶⁾	1.3	5.2	90.7	942.4
Capital dispositions ⁽⁶⁾	1.2	(0.1)	(283.6)	(99.0)
Development capital expenditures
Drilling and development	213.9	198.9	865.7	523.7
Facilities and seismic	32.5	30.6	90.4	100.5
Total	246.4	229.5	956.1	624.2
Land expenditures	4.2	0.8	19.2	4.9

(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", "total return of capital", "excess cash flow", "discretionary excess cash flow", "base dividends, "net debt", "net debt to adjusted funds flow" (equivalent to "net debt to adjusted funds flow from operations" and "leverage ratio"), "total operating netback", "total netback", "operating netback", "netback", "recycle ratio", "adjusted funds flow from operations netback" and "adjusted working capital (surplus) 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, 2022, 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)	2022	2021	% Change	2022	2021	% Change
Oil and gas sales	1,016.6	900.4	13	4,493.1	3,206.5	40
Royalties	(130.9)	(114.8)	14	(600.9)	(408.8)	47
Operating expenses	(178.9)	(154.2)	16	(713.1)	(625.3)	14
Transportation expenses	(38.1)	(29.8)	28	(139.8)	(117.7)	19
Total operating netback	668.7	601.6	11	3,039.3	2,054.7	48
Realized loss on commodity derivatives	(95.6)	(115.2)	(17)	(641.8)	(360.8)	78
Total netback	573.1	486.4	18	2,397.5	1,693.9	42
Other ⁽¹⁾	(50.3)	(53.9)	(7)	(165.1)	(217.0)	(24)
Total adjusted funds flow from operations netback	522.8	432.5	21	2,232.4	1,476.9	51

(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, excess cash flow and discretionary excess cash flow:

	Three months ended December 31			Year ended December 31
($ millions)	2022	2021	% Change	2022	2021	% Change
Cash flow from operating activities	589.5	492.4	20	2,192.2	1,495.8	47
Changes in non-cash working capital	(71.8)	(69.1)	4	15.0	(51.6)	(129)
Transaction costs	1.8	0.3	500	5.1	12.5	(59)
Decommissioning expenditures ⁽¹⁾	3.3	8.9	(63)	20.1	20.2	—
Adjusted funds flow from operations	522.8	432.5	21	2,232.4	1,476.9	51
Capital expenditures	(264.9)	(242.9)	9	(1,027.4)	(676.1)	52
Payments on lease liability	(5.1)	(5.6)	(9)	(20.4)	(21.2)	(4)
Decommissioning expenditures	(3.3)	(8.9)	(63)	(20.1)	(20.2)	—
Other items ⁽²⁾	1.9	7.3	(74)	(12.3)	29.0	(142)
Excess cash flow	251.4	182.4	38	1,152.2	788.4	46
Base dividends	(44.3)	(17.4)	155	(152.2)	(21.7)	601
Discretionary excess cash flow	207.1	165.0	26	1,000.0	766.7	30

(1)	Excludes amounts received from government grant programs.
(2)	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.

The following table reconciles dividends declared to base dividends:

	Three months ended December 31			Year ended December 31
($ millions)	2022	2021	% Change	2022	2021	% Change
Dividends declared	118.8	26.0	357	200.6	47.8	320
Dividend timing adjustment ⁽¹⁾	(55.1)	(8.6)	541	(29.0)	(26.1)	11
Special dividends	(19.4)	—	100	(19.4)	—	100
Base dividends	44.3	17.4	155	152.2	21.7	601

(1)	Dividends declared where the declaration date and record date are in different periods.

The following table reconciles adjusted working capital (surplus) deficiency:

($ millions)	2022	2021	% Change
Accounts payable and accrued liabilities	448.2	450.7	(1)
Dividends payable	99.4	43.5	129
Long-term compensation liability ⁽¹⁾	59.2	42.6	39
Cash	(289.9)	(13.5)	2,047
Accounts receivable	(327.8)	(314.3)	4
Prepaids and deposits ⁽²⁾	(84.2)	(7.4)	1,038
Adjusted working capital (surplus) deficiency	(95.1)	201.6	(147)

(1)	Includes current portion of long-term compensation liability and is net of equity derivative contracts.
(2)	Includes deposit on acquisition.

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

($ millions)	2022	2021	% Change
Long-term debt ⁽¹⁾	1,441.5	1,970.2	(27)
Adjusted working capital (surplus) deficiency	(95.1)	201.6	(147)
Unrealized foreign exchange on translation of US dollar long-term debt	(191.7)	(166.8)	15
Net debt	1,154.7	2,005.0	(42)

(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)	2022	2021	% Change	2022	2021	% Change
Net income (loss)	(498.1)	121.6	(510)	1,483.4	2,364.1	(37)
Amortization of E&E undeveloped land	2.8	9.6	(71)	15.2	51.0	(70)
Impairment (impairment reversal)	1,056.3	—	100	(428.6)	(2,514.4)	(83)
Unrealized derivative (gains) losses	(53.7)	(87.1)	(38)	(171.0)	141.4	(221)
Unrealized foreign exchange (gain) loss on translation of hedged US dollar long-term debt	(16.1)	(13.1)	23	27.7	(37.0)	(175)
Unrealized gain on long-term investments	—	—	(100)	—	(3.1)	(100)
Gain on sale of long-term investments	—	—	(100)	—	(7.0)	(100)
Net (gain) loss on capital dispositions	0.2	—	100	(25.9)	(58.4)	(56)
Deferred tax adjustments	(281.6)	129.0	(318)	64.9	578.7	(89)
Adjusted net earnings from operations	209.8	160.0	31	965.7	515.3	87

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.

In 2021, the Company's Kaybob Duvernay asset generated a recycle ratio of 3.7 times based F&D for wells brought on-stream.

	F&D	F&D Total (incl. change in FDC)	FD&A	FD&A Total (incl. change in FDC)
2021 Recycle Ratios
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

Total return of capital is a supplementary financial measure and is comprised of base dividends, special dividends and share repurchases, adjusted for the timing of special dividend payments.

Excess cash flow for 2023 is a forward-looking non-GAAP measures and are calculated consistently with the measures 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, 2022.

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: drilling inventory in the Kaybob Duvernay; expected 2023 excess cash flow at the WTI prices stated; delivering substantial returns to shareholders; expected payout of the sixth fully operated multi-well pad in the Kaybob Duvernay; two-year payback on the original Kaybob Duvernay acquisition; plans to drill additional open hole multi-lateral wells in 2023; hedging expectations; years of inventory in the Kaybob Duvernay play; exploring the implementation of open hole multi-lateral wells elsewhere in the Company's portfolio; plans to convert an additional producing wells to water injection wells in 2023, while continuing to advance other decline mitigation projects; reducing scope 1 and 2 emissions intensity by 38 percent by 2030, relative to its 2020 baseline; water targets including a 50 percent reduction in surface freshwater use in southeast Saskatchewan completions by 2025; target to reduce inactive well inventory by 30 percent by 2031 and expectations of achieving this target ahead of schedule; significant opportunity to further enhance shareholder value through ongoing optimization and potential reserves growth, including in the Kaybob Duvernay; adding a second rig in the Kaybob Duvernay in fourth quarter 2023; 2023 budget is expected to generate excess cash flow of approximately $1.0 billion at US$75/bbl WTI, allowing for the return of significant capital to shareholders, in addition to per-share growth and further net debt reduction; based on its return of capital framework and 2023 budget, expectations of returning over $600 million directly back to shareholders at US$75/bbl WTI, including base dividend; the Company plans to remain active on its share repurchase program; focus on further improving balance sheet strength; generating approximately $4.2 billion of cumulative after-tax excess cash flow from 2023 to 2027, assuming US$75/bbl WTI; net present values of reserves; forecast company annual capital expenditures; Crescent Point's five-year excess cash flow outlook being supported by plans to grow its Kaybob Duvernay asset to over 60,000 boe/d in 2027; Crescent Point plans to remain disciplined as it executes its five-year plan, with a continued focus on returns and long-term sustainability; Crescent Point's 2023 production and development capital expenditures guidance; and other information for Crescent Point's 2023 guidance, including capitalized administration, reclamation activities, capital lease payments, annual operating expenses and royalties; return of capital outlook, including base dividend, and the additional return of capital targeted as a percentage of discretionary excess cash flow.

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, 2022. 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, 2022, 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, 2022 under "Risk Factors" and our Management's Discussion and Analysis for the year ended December 31, 2022, 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, 2022, 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, including 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.

Included in this presentation are Crescent Point's 2023 guidance in respect of capital expenditures and average annual production and 5-year outlook information which are based on various assumptions as to production levels, commodity prices and other assumptions and are provided for illustration only and are based on budgets and forecasts that have not been finalized and are subject to a variety of contingencies including prior years' results. The Company's return of capital framework is based on certain facts, expectations and assumptions that may change and, therefore, this framework may be amended as circumstances necessitate or require. To the extent such estimates constitute a "financial outlook" or "future oriented financial information" in this presentation, as defined by applicable securities legislation, such information 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.

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 2022 and 2021, the aggregate average production for fourth quarter of 2022 and 2021, and the references to "natural gas", "crude oil" and "condensante" 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
	2022	2021	2022	2021
Light & Medium Crude Oil (bbl/d)	13,671	15,517	14,274	17,859
Heavy Crude Oil (bbl/d)	3,870	4,226	4,027	4,203
Tight Oil (bbl/d)	52,095	55,965	53,861	62,492
Total Crude Oil (bbl/d)	69,636	75,708	72,162	84,554

NGLs (bbl/d)	38,893	33,720	36,556	29,054

Shale Gas (mcf/d)	142,803	115,482	130,902	103,124
Conventional Natural Gas (mcf/d)	10,769	10,389	10,482	11,328
Total Natural Gas (mcf/d)	153,572	125,871	141,384	114,452

Total (boe/d)	134,124	130,407	132,282	132,683

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.

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, 2022 escalated price forecast, the fair value for the Company's oil and gas hedges based on such December 31, 2022 escalated price forecast, and less outstanding net debt. The NAV per share is calculated on a fully diluted basis and a discount of 10 percent.

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.

Reserve 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, 2022.

Initial 30 day production on the Company's sixth fully operated multi-well pad in the Kaybob Duvernay consists of 51% condensate, 15% NGLs and 34% shale gas. Viewfield Bakken most recent eight-leg wells with IP30 averaging 225 bbl/d per well consisted of 100% tight oil.

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", "replacement rate" 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.

Replacement rate is the amount of oil added to the Company's 2P reserves, divided by production. It is a measure of the ability of the Company to sustain production levels.

Reserve Life Index is calculated as set forth above, it is a measure of the longevity of the Company's reserves.

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. This press release discloses approximately 130 net drilling locations associated with the acquisition of additional assets in the Kaybob Duvernay, of which none are booked at year-end 2022. This press release references over 20 years of inventory in the Kaybob Duvernay play and the potential for open hole multi-lateral drilling within the Viewfield Bakken play to add approximately four years of additional drilling inventory, which amounts include booked and unbooked locations. This press release discloses approximately 150 additional potential net drilling locations in the Viewfield Bakken of which none are booked at year-end 2022. All of the required information will be contained in the Company's Annual Information Form for the year ended December 31, 2022, which will be filed on SEDAR (accessible at www.sedar.com) and EDGAR (accessible at www.sec.gov/edgar.shtml) on or before March 2, 2023 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.

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SOURCE Crescent Point Energy Corp.

Crescent Point Announces 2022 Results & Reserves