Crescent Point announces 2023 results & reserve – Canadian Energy News, Top Headlines, Commentaries, Features & Events – EnergyNow

CALGARY, AB, Feb. 29, 2024 /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, 2023.

KEY HIGHLIGHTS

• Transformed portfolio, increasing premium inventory to over 20 years and enhancing excess cash flow profile.
• Replaced over 900 percent of 2023 production on a 2P reserves basis including strategic A&D, or 150 percent organically.
• Generated $980 million of excess cash flow in 2023, with capital expenditures and production in-line with guidance.
• Returned approximately $600 million, or 60 percent of excess cash flow, to shareholders in 2023.
• Increasing quarterly base dividend by 15 percent to $0.115 per share, or $0.46 per share annually.
• Generated a strong FD&A recycle ratio of 2.5 times in 2023, including change in FDC, based on 2P reserves.
• Excess cash flow of $830 million expected in 2024 at US$75 WTI, with 60 percent returned to shareholders.
• Five-year plan expected to generate strong per share growth and cumulative excess cash flow of $4.7 billion at US$70 WTI.

“This past year was pivotal in our company’s history as we successfully transformed our portfolio,” said Craig Bryksa, President and CEO of Crescent Point. “Through this execution, we have materially enhanced the long-term sustainability of our business, including by increasing our premium drilling inventory to over 20 years and enhancing our excess cash flow profile on a per share basis. Our strategic priorities going forward are operational execution, balance sheet strength and increasing return of capital to shareholders.”

FINANCIAL HIGHLIGHTS 

• Adjusted funds flow totaled over $2.3 billion for the year ended December 31, 2023, or $4.27 per share diluted, driven by a strong operating netback of $43.71 per boe. In fourth quarter, adjusted funds flow totaled $574.5 million, or $1.03 per share diluted.
• For the year ended December 31, 2023, development capital expenditures, which included drilling and development, facilities and seismic costs, totaled $1.14 billion, within the Company’s annual guidance range of $1.05 billion to $1.15 billion.
• The Company’s net debt as at December 31, 2023 was approximately $3.7 billion. Throughout 2023, Crescent Point executed on its portfolio strategy which included material additions in the Alberta Montney along with non-core asset dispositions. During fourth quarter 2023, Crescent Point entered into agreements to dispose of its Swan Hills and Turner Valley assets in Alberta, which have closed or are expected to close in first quarter 2024.
• For the year ended December 31, 2023, Crescent Point reported net income from continuing operations of $799.4 million, or $1.46 per share diluted. The Company’s total net income for 2023, including discontinued operations, was $570.3 million, or $1.04 per share diluted, which included net non-cash charges of $106.7 million related to the disposition of its U.S. assets.
• The Company has hedged approximately 45 percent of its oil and liquids production and over 30 percent of its natural gas production in 2024, net of royalty interest. The Company has also diversified its pricing exposure for natural gas, with the majority of its production through 2025 receiving a combination of fixed prices and pricing related to major U.S. markets.

RETURN OF CAPITAL HIGHLIGHTS

• The Company’s total return of capital to shareholders in 2023, including the base dividend, was $599.5 million, or approximately 60 percent of its annual excess cash flow.
• During fourth quarter, Crescent Point prioritized share buybacks within its return of capital framework, repurchasing 8.4 million shares for $83.8 million. The Company repurchased a total of 34.6 million shares for $349.9 million in 2023, representing over six percent of its public float at the start of the year. Crescent Point intends to file with the Toronto Stock Exchange (“TSX”) a notice of intention to renew its normal course issuer bid (“NCIB”), which is due to expire on March 8, 2024.
• Crescent Point’s Board of Directors has approved and declared a first quarter 2024 base dividend of $0.115 per share, an increase of 15 percent from the prior level. The base dividend is payable on April 1, 2024 to shareholders of record on March 15, 2024. This base dividend increase equates to an annualized base dividend of $0.46 per share.

Adjusted funds flow, adjusted funds flow per share diluted, excess cash flow, recycle ratio, 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 159,411 boe/d in 2023, within the Company’s annual production guidance range of 156,000 to 161,000 boe/d, notwithstanding the downtime associated with the Alberta wildfires earlier in the year. Crescent Point’s average production in fourth quarter 2023 was 162,269 boe/d.
• In the Kaybob Duvernay, the Company delivered consistent results throughout 2023, demonstrating the strength of its operational execution. Crescent Point brought on stream over 20 wells during the year through four multi-well pads. These pads generated average peak 30-day rates ranging from 1,000 boe/d to 1,550 boe/d (75% to 85% liquids) per well within the Volatile Oil window and 1,425 boe/d (60% liquids) per well in the Liquids-Rich window. During fourth quarter, Crescent Point added a second rig in the Kaybob Duvernay to accelerate the development of its high-return inventory.
• Crescent Point has also continued to achieve strong operational momentum in the Alberta Montney since its initial entry into the play in second quarter 2023. The Company brought on stream over 25 wells during the remainder of the year through nine multi-well pads. These pads generated average peak 30-day rates ranging from 1,200 boe/d to 2,000 boe/d (70% to 85% liquids) per well in Gold Creek West, 1,000 boe/d to 1,350 boe/d (45% to 75% liquids) per well in Gold Creek and 775 boe/d (85% liquids) per well in Karr East.
• Crescent Point’s open hole multi-lateral (“OHML”) well development program in southeast Saskatchewan included nine eight-leg wells during 2023. The Company’s most recent OHML well achieved a peak-30 day rate of over 300 bbl/d (100% light oil), further highlighting the strong drilling economics of this program. Crescent Point also continued to advance its decline mitigation initiatives in 2023, including by successfully converting approximately 100 producing wells to water injection wells. These initiatives support the Company’s low base decline rate of approximately 15 percent in its Saskatchewan assets, further enhancing its strong excess cash flow generation from these assets.
• In 2023, Crescent Point achieved the best safety scores in the Company’s history, demonstrating its ongoing commitment to safe operations.
• During 2023, Crescent Point continued to demonstrate its commitment to strong environmental, social and governance (“ESG”) practices as it progresses toward each of its environmental targets, including reducing its Scope 1 and 2 emissions intensity, surface freshwater use and inactive well inventory. The Company remains on track to meet or exceed each of these environmental targets. Crescent Point has significantly improved its environmental profile, reducing both its Scope 1 emissions intensity and asset retirement liabilities by approximately 60 percent since beginning its portfolio transformation.

RESERVES HIGHLIGHTS

“Our 2023 reserves highlight the benefits of our strategic portfolio transformation and our technical team’s strong ongoing operational execution,” said Bryksa. “We organically replaced 150 percent of our 2023 annual production on a proved plus probable basis, primarily driven by drilling and development activity in the Kaybob Duvernay. In 2024, we see opportunities to further enhance shareholder value by realizing potential cost efficiencies and productivity enhancements. At year-end 2023, over 70 percent of our premium locations in the Alberta Montney and approximately 60 percent in the Kaybob Duvernay remain unbooked, allowing for future reserves growth.”

• The Company’s reserves at year-end 2023 increased across all categories driven by organic additions and strategic acquisitions, net of non-core dispositions. Proved plus Probable (“2P”) reserves totaled 1,201.3 million boe (“MMboe”), Proved (“1P”) reserves totaled 768.3 MMboe and Proved Developed Producing (“PDP”) reserves totaled 381.1 MMboe.
• The Company’s 2P reserve life index (“RLI”) is approximately 16 years based on mid-point of 2024 annual average production guidance.
• Crescent Point achieved net reserve additions of 88.7 MMboe on a 2P basis, excluding acquisitions and dispositions (“A&D”), replacing approximately 150 percent of its 2023 annual production. These reserve additions primarily originated from the Company’s Kaybob Duvernay asset, which contributed reserve adds at an attractive finding and development (“F&D”) cost, including change in future development capital (“FDC”), of approximately $13.50 per boe. These Kaybob Duvernay reserve additions resulted in a strong recycle ratio of over 3.0 times.
• Reserve additions within Crescent Point’s Alberta Montney asset are captured under the Company’s acquired reserves, given the timing of its initial entry into the play in second quarter 2023. Including strategic acquisitions, net of dispositions, Crescent Point added 457.7 MMboe of 2P reserves. This addition contributed to the significant increase in 2P reserves in 2023 of approximately 70 percent and replaced over 900 percent of the Company’s 2023 annual production.
• Crescent Point generated 2P finding, development and acquisition (“FD&A”) cost, including change in FDC, of $17.70 per boe, producing a recycle ratio of 2.5 times based on an operating netback of $43.71 per boe in 2023.
• Crescent Point’s 2P net asset value (“NAV”) was $22.45 per share at year-end 2023, based on independent engineering pricing. On a PDP and 1P basis, the Company’s NAV was $7.63 and $14.07 per share, respectively. The independent engineering price forecast assumes an average WTI price of approximately US$76.35/bbl and AECO price of approximately $3.60/Mcf in the first five years. The Company’s NAV at year-end 2023 does not include unbooked locations, primarily in the Kaybob Duvernay and Alberta Montney, allowing for future reserves additions.

Additional information on the Company’s 2023 reserves is provided in its Annual Information Form (“AIF”) for the year-ended December 31, 2023.

OUTLOOK

Crescent Point’s strategic priorities remain focused on operational execution, balance sheet strength and increasing return of capital to shareholders.

The Company’s previously released 2024 annual average production guidance of 198,000 to 206,000 boe/d and development capital expenditures budget of $1.4 billion to $1.5 billion remain unchanged. This budget remains disciplined and flexible, with a continued focus on allocating capital to the highest-return assets. Approximately 45 percent of Crescent Point’s 2024 budget is allocated to the Alberta Montney, 35 percent to Kaybob Duvernay and 20 percent to Saskatchewan. The Company’s 2024 capital budget, including its base dividend, remains fully funded at approximately US$55/bbl WTI.

Within its operations, Crescent Point continues to target additional efficiencies and improved productivity by further enhancing drilling and completions optimization, including optimizing wells drilled per section on its recently acquired Alberta Montney assets and drilling longer lateral wells in the Kaybob Duvernay. In Saskatchewan, the Company continues to build on its operational momentum through the advancement of its OHML drilling and decline mitigation programs.

Crescent Point’s 2024 budget is expected to generate significant excess cash flow of approximately $830 million at average commodity prices of approximately US$75/bbl WTI and $2.30/Mcf AECO for the full year. The Company’s funds flow sensitivity is approximately $30 million for every US$1/bbl change in WTI and $20 million for every $0.25/Mcf change in AECO for the remainder of the year.

Crescent Point plans to continue allocating 60 percent of its excess cash flow to shareholders through the base dividend and share repurchases, with the remaining 40 percent directed toward the balance sheet. The Company’s leverage ratio, or net debt to adjusted funds flow, is expected to be approximately 1.2 times by year-end 2024, based on average commodity prices of approximately US$75/bbl WTI and $2.30/Mcf AECO for the full year.

The Company plans to increase the percentage of excess cash flow it returns to shareholders over time as it further strengthens its balance sheet. Crescent Point’s strategy is focused on delivering meaningful and sustainable total returns through a combination of return of capital, per-share growth and balance sheet strength.

INVESTOR DAY

Crescent Point will host an Investor Day on March 20, 2024 to discus its corporate strategy, operational results and long-term development plan.

For more details, please refer to the press release dated February 15, 2024.

CONFERENCE CALL DETAILS

Crescent Point management will host a conference call on Thursday, February 29, 2024 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. To join the call without operator assistance, participants may register online by entering their phone number to receive an instant automated call back. Alternatively, the conference call can be accessed with operated assistance by dialing 1‑888‑390‑0605. Participants will be able to take part in a question and answer session following management’s opening remarks through both the webcast dashboard and the conference line.

The webcast will be archived for replay and can be accessed online at Crescent Point’s conference calls and webcasts page. The replay will be available shortly after the completion of the call.

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

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.

2024 GUIDANCE

The Company’s guidance for 2024 is as follows:

Total Annual Average Production (boe/d) (1)	198,000 – 206,000
Capital Expenditures
Development capital expenditures ($ millions)	$1,400 – $1,500
Capitalized administration ($ millions)	$40
Total ($ million) (2)	$1,440 – $1,540
Other Information for 2024 Guidance
Reclamation activities ($ millions) (3)	$40
Capital lease payments ($ millions)	$20
Annual operating expenses ($/boe)	$12.75 – $13.75
Royalties	10.00% – 11.00%

1)	Total annual average production (boe/d) is comprised of approximately 65% Oil, Condensate & NGLs and 35% 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	$0.115
Total Return of Capital
% of excess cash flow (1)	60 %

1)         Total return of capital is based on a framework that targets to return to shareholders 60% of excess cash flow on an annual basis

The Company’s audited consolidated financial statements and management’s discussion and analysis for the year ended December 31, 2023, will be available on the System for Electronic Document Analysis and Retrieval (“SEDAR”) at www.sedarplus.com, on EDGAR at www.sec.gov/edgar.shtml and on Crescent Point’s website at www.crescentpointenergy.com.

Summary of Reserves

The Company’s reserves were independently evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”) as at December 31, 2023. 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, 2023 ^{(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	131,979	118,448	37,020	33,181	17,173	14,417	82,447	69,988
Proved Developed Non-Producing	587	539	252	244	2,260	2,089	149	134
Proved Undeveloped	106,423	91,180	9,551	8,892	1,729	1,582	107,124	90,233
Total Proved	238,989	210,168	46,823	42,318	21,163	18,088	189,720	160,355
Total Probable	142,434	119,830	33,119	29,445	6,677	5,671	93,735	73,064
Total Proved plus Probable	381,422	329,998	79,942	71,763	27,840	23,760	283,455	233,418

	Shale Gas  (MMcf)		Natural Gas  (MMcf)		Total  (Mboe)
Reserves Category	Gross	Net	Gross	Net	Gross	Net
Proved Developed Producing	636,829	584,298	38,074	34,551	381,103	339,176
Proved Developed Non-Producing	1,603	1,510	64	54	3,527	3,267
Proved Undeveloped	949,769	860,513	3,013	2,834	383,624	335,779
Total Proved	1,588,202	1,446,322	41,151	37,440	768,254	678,222
Total Probable	917,729	805,980	24,721	22,440	433,040	366,080
Total Proved plus Probable	2,505,931	2,252,302	65,872	59,879	1,201,294	1,044,302

(1)	Based on three evaluator’s average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) December 31, 2023, 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, 2023 ⁽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	381,103	10,035	8,130	6,792	5,868
	Total Proved	768,254	18,053	13,709	10,808	8,834
	Total Proved plus Probable	1,201,294	31,466	21,634	16,024	12,527

(1) Price deck based on three evaluator’s average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) December 31, 2023, 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, 2022	169,657	101,378	271,034	49,197	36,550	85,747	23,039	7,230	30,268
Extensions and Improved Recovery	6,982	(1,517)	5,465	388	(149)	239	–	–	–
Technical Revisions	2,183	(4,415)	(2,232)	1,643	(3,370)	(1,727)	(675)	(580)	(1,255)
Acquisitions	111,332	74,357	185,689	126	22	148	–	–	–
Dispositions	(29,001)	(27,601)	(56,602)	(376)	(190)	(565)	–	–	–
Economic Factors	1,161	232	1,393	468	255	723	193	27	220
Production	(23,326)	–	(23,326)	(4,623)	–	(4,623)	(1,394)	–	(1,394)
December 31, 2023	238,989	142,434	381,422	46,823	33,119	79,942	21,163	6,677	27,840

	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, 2022	146,482	52,892	199,374	521,688	175,480	697,167	39,279	23,599	62,877
Extensions and Improved Recovery	18,017	28,950	46,968	80,000	196,761	276,761	158	(157)	–
Technical Revisions	(4,919)	(5,213)	(10,132)	15,063	(5,454)	9,609	4,034	58	4,092
Acquisitions	55,257	25,209	80,466	1,082,973	581,238	1,664,211	2,684	927	3,610
Dispositions	(10,262)	(8,257)	(18,519)	(34,516)	(30,627)	(65,143)	(176)	(38)	(215)
Economic Factors	305	153	458	1,165	331	1,497	(899)	333	(566)
Production	(15,160)	–	(15,160)	(78,170)	–	(78,170)	(3,928)	–	(3,928)
December 31, 2023	189,720	93,735	283,455	1,588,202	917,729	2,505,931	41,151	24,721	65,872

	Total Oil Equivalent  (Mboe)
Factors	Proved	Probable	Proved  plus Probable
December 31, 2022	481,868	231,230	713,098
Extensions and Improved Recovery	38,747	60,052	98,799
Technical Revisions	1,415	(14,477)	(13,062)
Acquisitions	347,657	196,616	544,273
Dispositions	(45,420)	(41,159)	(86,579)
Economic Factors	2,172	778	2,949
Production	(58,185)	–	(58,185)
December 31, 2023	768,254	433,040	1,201,294

(1)	Based on three evaluator’s average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) December 31, 2023, 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 2023

	Proved Developed Producing	Total Proved	Total Proved plus Probable
Capital ($ millions)
F&D	1,172	1,172	1,172
Change in FDC on F&D	(14)	54	585
F&D Total (incl. change in FDC)	1,159	1,226	1,757
FD&A	5,148	5,148	5,148
Change in FDC on FD&A	32	2,952	4,520
FD&A Total (incl. change in FDC)	5,180	8,101	9,669
Reserves Additions (Mboe)
Reserves Additions	32,354	42,334	88,687
Reserves Additions incl. A&D	137,976	344,571	546,380
Costs ($/boe) & Recycle Ratio (1)(2)
F&D Total (incl. change in FDC)	$35.82	$28.96	$19.82
Recycle Ratio	1.2	1.5	2.2
FD&A Total (incl. change in FDC)	$37.54	$23.51	$17.70
Recycle Ratio	1.2	1.9	2.5

(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 2023 operating netback of $43.71 per boe.
(4)	F&D and FD&A costs includes capital expenditures associated with assets disposed of during the year.

Future Development Capital 

At year-end 2023, FDC for 2P reserves totaled $9.7 billion, compared to $5.1 billion at year-end 2022. The Company’s FDC increased by approximately $4.5 billion, primarily driven by location additions from its Alberta Montney and Kaybob Duvernay plays.

Company Annual Capital Expenditures ($ millions)
Year	Total Proved	Total Proved plus Probable
2024	1,233	1,372
2025	1,240	1,437
2026	1,462	1,585
2027	1,429	1,738
2028	888	1,708
2029	26	1,095
2030	11	603
2031	12	19
2032	13	19
2033	9	9
2034	7	9
2035	6	9
Subtotal (1)	6,336	9,603
Remainder	21	62
Total (1)	6,356	9,665
10% Discounted	5,076	7,196

(1) Numbers may not add due to rounding.

CONSOLIDATED FINANCIAL AND OPERATING HIGHLIGHTS

	Three months ended December 31		Year ended December 31
(Cdn$ millions except per share and per boe amounts)	2023	2022	2023	2022
Financial
Cash flow from operating activities	611.3	589.5	2,195.7	2,192.2
Adjusted funds flow from operations (1)	574.5	522.8	2,339.1	2,232.4
Per share (1) (2)	1.03	0.93	4.27	3.91
Net income (loss)	951.2	(498.1)	570.3	1,483.4
Per share (2)	1.70	(0.90)	1.04	2.60
Adjusted net earnings from operations (1)	192.8	209.8	932.6	965.7
Per share (1) (2)	0.34	0.38	1.70	1.69
Dividends declared	68.3	118.8	211.9	200.6
Per share (2)	0.120	0.215	0.387	0.360
Net debt (1)	3,738.1	1,154.7	3,738.1	1,154.7
Net debt to adjusted funds flow from operations (1) (3)	1.6	0.5	1.6	0.5
Weighted average shares outstanding
Basic	556.5	555.2	545.6	566.7
Diluted	559.1	559.2	548.3	571.1
Operating
Average daily production
Crude oil and condensate (bbls/d)	102,350	90,759	102,906	91,679
NGLs (bbls/d)	17,528	17,770	19,017	17,039
Natural gas (mcf/d)	254,345	153,572	224,926	141,384
Total (boe/d)	162,269	134,124	159,411	132,282
Average selling prices (4)
Crude oil and condensate ($/bbl)	95.78	103.42	97.23	115.72
NGLs ($/bbl)	28.08	38.55	29.86	45.02
Natural gas ($/mcf)	2.79	6.37	3.08	6.60
Total ($/boe)	67.82	82.39	70.67	93.06
Netback ($/boe)
Oil and gas sales	67.82	82.39	70.67	93.06
Royalties	(8.17)	(10.61)	(9.13)	(12.45)
Operating expenses	(14.24)	(14.50)	(14.62)	(14.77)
Transportation expenses	(3.82)	(3.09)	(3.21)	(2.90)
Operating netback	41.59	54.19	43.71	62.94
Realized gain (loss) on commodity derivatives	0.17	(7.75)	0.19	(13.29)
Other (5)	(3.28)	(4.07)	(3.70)	(3.41)
Adjusted funds flow from operations netback (1)	38.48	42.37	40.20	46.24
Capital Expenditures
Total capital acquisitions (1) (6)	2,513.9	1.3	4,589.7	90.7
Total capital dispositions (1) (6)	(602.4)	1.2	(613.6)	(283.6)
Development capital expenditures
Drilling and development	239.1	213.9	1,016.9	865.7
Facilities and seismic	39.8	32.5	121.8	90.4
Total	278.9	246.4	1,138.7	956.1
Land expenditures	2.2	4.2	33.6	19.2

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

FINANCIAL AND OPERATING HIGHLIGHTS FROM CONTINUING OPERATIONS

	Three months ended December 31		Year ended December 31
(Cdn$ millions except per share and per boe amounts)	2023	2022	2023	2022
Financial
Cash flow from operating activities from continuing operations	524.0	507.5	1,796.7	1,828.7
Adjusted funds flow from continuing operations (1)	535.1	430.9	1,975.6	1,848.6
Per share (1) (2)	0.96	0.77	3.60	3.24
Net income (loss) from continuing operations	302.6	(577.8)	799.4	1,146.7
Per share (2)	0.54	(1.04)	1.46	2.01
Adjusted net earnings from continuing operations (1)	210.0	165.5	795.9	764.1
Per share (1) (2)	0.37	0.30	1.45	1.34
Weighted average shares outstanding
Basic	556.5	555.2	545.6	566.7
Diluted	559.1	559.2	548.3	571.1
Operating
Average daily production from continuing operations
Crude oil and condensate (bbls/d)	96,144	78,052	88,087	79,323
NGLs (bbls/d)	16,023	13,427	15,026	13,079
Natural gas (mcf/d)	248,306	139,206	211,275	128,099
Production from continuing operations (boe/d)	153,551	114,680	138,326	113,752
Average selling prices from continuing operations (3)
Crude oil and condensate ($/bbl)	94.64	101.86	95.87	114.64
NGLs ($/bbl)	30.53	41.76	32.86	47.10
Natural gas ($/mcf)	2.83	6.35	3.06	6.48
Total ($/boe)	67.01	81.91	69.30	92.66
Netback from Continuing Operations ($/boe)
Oil and gas sales	67.01	81.91	69.30	92.66
Royalties	(7.50)	(8.73)	(7.43)	(10.49)
Operating expenses	(14.48)	(15.19)	(15.26)	(15.13)
Transportation expenses	(3.96)	(3.40)	(3.45)	(3.16)
Operating netback	41.07	54.59	43.16	63.88
Realized gain (loss) on commodity derivatives	0.18	(9.06)	0.31	(15.46)
Other (4)	(3.37)	(4.69)	(4.34)	(3.90)
Adjusted funds flow from continuing operations netback (1)	37.88	40.84	39.13	44.52
Capital Expenditures
Development capital expenditures from continuing operations	276.0	160.5	844.9	698.0

(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)	The average selling prices reported are before realized derivatives and transportation.
(4)	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.

Specified Financial Measures

Throughout this press release, the Company uses the terms “total operating netback”, “total operating netback from continuing operations”, “total operating netback from discontinued operations”, “total netback”, “total netback from continuing operations”, “total netback from discontinued operations”, “operating netback”, “netback”, “adjusted funds flow from operations” (or “adjusted FFO”), “adjusted funds flow from continuing operations”, “adjusted funds flow from discontinued operations”, “excess cash flow”, “adjusted working capital (surplus) deficiency”, “net debt”, “enterprise value”, “net debt to adjusted funds flow from operations”, “net debt as a percentage of enterprise value”, “adjusted net earnings from operations”, “adjusted net earnings from continuing operations”, “adjusted net earnings from continuing operations per share – diluted”, “adjusted net earnings from discontinued operations”, “adjusted net earnings from discontinued operations per share – diluted”, “adjusted net earnings from operations per share”, “adjusted net earnings from operations per share – diluted”, “total capital acquisitions” and “total capital dispositions”. 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, 2023, which section is incorporated herein by reference, and available on SEDAR+ at www.sedarplus.ca 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 and total netback from continuing operations:

	Three months ended December 31						Year ended December 31
($ millions)	2023		2022		% Change		2023		2022		% Change
Oil and gas sales	946.7		864.2		10		3,499.0		3,847.0		(9)
Royalties	(105.9)		(92.1)		15		(375.3)		(435.5)		(14)
Operating expenses	(204.5)		(160.3)		28		(770.5)		(628.2)		23
Transportation expenses	(56.0)		(35.9)		56		(174.3)		(131.0)		33
Total operating netback from continuing operations	580.3		575.9		1		2,178.9		2,652.3		(18)
Realized gain (loss) on commodity derivatives	2.5		(95.6)		(103)		15.5		(641.8)		(102)
Total netback from continuing operations	582.8		480.3		21		2,194.4		2,010.5		9
Other (1)	(47.7)		(49.4)		(3)		(218.8)		(161.9)		35
Total adjusted funds flow from continuing operations netback	535.1		430.9		24		1,975.6		1,848.6		7

(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 oil and gas sales to total operating netback and total netback from discontinued operations:

	Three months ended December 31						Year ended December 31
($ millions)	2023		2022		% Change		2023		2022		% Change
Oil and gas sales	65.7		152.4		(57)		612.9		646.1		(5)
Royalties	(16.1)		(38.8)		(59)		(155.9)		(165.4)		(6)
Operating expenses	(8.1)		(18.6)		(56)		(80.0)		(84.9)		(6)
Transportation expenses	(1.0)		(2.2)		(55)		(12.2)		(8.8)		39
Total operating netback from discontinued operations	40.5		92.8		(56)		364.8		387.0		(6)
Realized loss on commodity derivatives	—		—		100		(4.5)		—		100
Total netback from discontinued operations	40.5		92.8		(56)		360.3		387.0		(7)
Other (1)	(1.1)		(0.9)		22		3.2		(3.2)		(200)
Total adjusted funds flow from discontinued operations netback	39.4		91.9		(57)		363.5		383.8		(5)

(1) Other includes general and administrative expenses, cash-settled share-based compensation and certain cash items and excludes transaction costs and certain non-cash items.

The following tables reconcile total operating netback and total netback from continuing and discontinued operations:

	Three months ended December 31						Year ended December 31
($ millions)	2023		2022		% Change		2023		2022		% Change
Total operating netback from continuing operations	580.3		575.9		1		2,178.9		2,652.3		(18)
Total operating netback from discontinued operations	40.5		92.8		(56)		364.8		387.0		(6)
Total operating netback	620.8		668.7		(7)		2,543.7		3,039.3		(16)

	Three months ended December 31						Year ended December 31
($ millions)	2023		2022		% Change		2023		2022		% Change
Total netback from continuing operations	582.8		480.3		21		2,194.4		2,010.5		9
Total netback from discontinued operations	40.5		92.8		(56)		360.3		387.0		(7)
Total netback	623.3		573.1		9		2,554.7		2,397.5		7
Other (1)	(48.8)		(50.3)		(3)		(215.6)		(165.1)		31
Total adjusted funds flow from operations netback	574.5		522.8		10		2,339.1		2,232.4		5

(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 dividends declared to base dividends:

	Three months ended December 31						Year ended December 31
($ millions)	2023		2022		% Change		2023		2022		% Change
Dividends declared	68.3		118.8		(43)		211.9		200.6		6
Dividend timing adjustment (1)	—		(55.1)		(100)		55.2		(29.0)		(290)
Special dividends	(11.4)		(19.4)		(41)		(47.7)		(19.4)		146
Base dividends	56.9		44.3		28		219.4		152.2		44

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

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)	2023		2022 (1)		% Change		2023		2022 (1)		% Change
Cash flow from operating activities	611.3		589.5		4		2,195.7		2,192.2		—
Changes in non-cash working capital	(82.0)		(71.8)		14		54.9		15.0		266
Transaction costs	31.8		1.8		1,667		48.5		5.1		851
Decommissioning expenditures (2)	13.4		3.3		306		40.0		20.1		99
Adjusted funds flow from operations	574.5		522.8		10		2,339.1		2,232.4		5
Development capital and other expenditures	(292.1)		(264.9)		10		(1,220.5)		(1,027.4)		19
Payments on lease liability	(4.6)		(5.1)		(10)		(20.8)		(20.4)		2
Decommissioning expenditures	(13.4)		(3.3)		306		(40.0)		(20.1)		99
Unrealized gain (loss) on equity derivative contracts	(5.7)		6.4		(189)		(29.3)		(2.9)		910
Transaction costs	(31.8)		(1.8)		1,667		(48.5)		(5.1)		851
Other items (3)	1.9		(2.7)		(170)		1.6		(4.3)		(137)
Excess cash flow	228.8		251.4		(9)		981.6		1,152.2		(15)

(1) Comparative period revised to reflect current period presentation.

(2) Excludes amounts received from government grant programs.

(3) Other items exclude net acquisitions and dispositions.

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

	Three months ended December 31						Year ended December 31
($ millions)	2023		2022		% Change		2023		2022		% Change
Cash flow from operating activities from discontinued operations	87.3		82.0		6		399.0		363.5		10
Changes in non-cash working capital	(57.0)		9.4		(706)		(44.6)		19.8		(325)
Transaction costs	8.7		0.5		1,640		8.7		0.5		1,640
Decommissioning expenditures (1)	0.4		—		100		0.4		—		100
Adjusted funds flow from discontinued operations	39.4		91.9		(57)		363.5		383.8		(5)

(1) Excludes amounts received from government grant programs.

The following tables reconcile cash flow from operating activities and adjusted funds flow from operations from continuing and discontinued operations:

	Three months ended December 31						Year ended December 31
($ millions)	2023		2022		% Change		2023		2022		% Change
Cash flow from operating activities from continuing operations	524.0		507.5		3		1,796.7		1,828.7		(2)
Cash flow from operating activities from discontinued operations	87.3		82.0		6		399.0		363.5		10
Cash flow from operating activities	611.3		589.5		4		2,195.7		2,192.2		—

	Three months ended December 31						Year ended December 31
($ millions)	2023		2022		% Change		2023		2022		% Change
Adjusted funds flow from continuing operations	535.1		430.9		24		1,975.6		1,848.6		7
Adjusted funds flow from discontinued operations	39.4		91.9		(57)		363.5		383.8		(5)
Adjusted funds flow from operations	574.5		522.8		10		2,339.1		2,232.4		5

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 adjusted working capital (surplus) deficiency:

($ millions)	2023		2022		% Change
Accounts payable and accrued liabilities	634.9		448.2		42
Dividends payable	56.8		99.4		(43)
Long-term compensation liability (1)	66.8		59.2		13
Cash	(17.3)		(289.9)		(94)
Accounts receivable	(377.9)		(327.8)		15
Prepaids and deposits	(87.8)		(65.5)		34
Other current assets (2)	(79.2)		(18.7)		324
Adjusted working capital (surplus) deficiency	196.3		(95.1)		(306)

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

(2) Includes deferred consideration receivable and deposit on acquisition.

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

($ millions)	2023		2022		% Change
Long-term debt (1)	3,566.3		1,441.5		147
Adjusted working capital (surplus) deficiency	196.3		(95.1)		(306)
Unrealized foreign exchange on translation of hedged US dollar long-term debt	(24.5)		(191.7)		(87)
Net debt	3,738.1		1,154.7		224

(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)	2023		2022		% Change		2023		2022		% Change
Net income (loss)	951.2		(498.1)		(291)		570.3		1,483.4		(62)
Amortization of E&E undeveloped land	12.0		2.8		329		30.9		15.2		103
Impairment (impairment reversal)	48.4		1,056.3		(95)		822.2		(428.6)		(292)
Unrealized derivative (gains) losses	(98.5)		(53.7)		83		56.9		(171.0)		(133)
Unrealized foreign exchange (gain) loss on translation of hedged US dollar long-term debt	(95.4)		(16.1)		493		(168.6)		27.7		(709)
Net (gain) loss on capital dispositions	13.7		0.2		6,750		9.6		(25.9)		(137)
Reclassification of cumulative foreign currency translation of discontinued foreign operations	(621.7)		—		100		(621.7)		—		100
Deferred tax adjustments	(16.9)		(281.6)		(94)		233.0		64.9		259
Adjusted net earnings from operations	192.8		209.8		(8)		932.6		965.7		(3)

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

	Three months ended December 31						Year ended December 31
($ millions)	2023		2022		% Change		2023		2022		% Change
Net income (loss) from discontinued operations	648.6		79.7		714		(229.1)		336.7		(168)
Amortization of E&E undeveloped land	—		—		—		—		—		100
Impairment (impairment reversal)	—		—		—		728.4		(71.3)		(1,122)
Unrealized derivative (gains) losses	(5.1)		—		100		18.9		—		100
Net loss on capital dispositions	9.0		0.2		4,400		9.0		0.2		4,400
Reclassification of cumulative foreign currency translation of discontinued foreign operations	(621.7)		—		100		(621.7)		—		100
Deferred tax adjustments	(48.0)		(35.6)		35		231.2		(64.0)		(461)
Adjusted net earnings (loss) from discontinued operations	(17.2)		44.3		(139)		136.7		201.6		(32)

The following table reconciles adjusted net earnings from continuing and discontinued operations:

	Three months ended December 31						Year ended December 31
($ millions)	2023		2022		% Change		2023		2022		% Change
Adjusted net earnings from continuing operations	210.0		165.5		27		795.9		764.1		4
Adjusted net earnings (loss) from discontinued operations	(17.2)		44.3		(139)		136.7		201.6		(32)
Adjusted net earnings from operations	192.8		209.8		(8)		932.6		965.7		(3)

The following table reconciles capital acquisitions, net of cash acquired to total capital acquisitions:

	Three months ended December 31						Year ended December 31
($ millions)	2023		2022		% Change		2023		2022		% Change
Capital acquisitions, net of cash acquired	1,540.4		1.3		118,392		3,616.2		90.7		3,887
Common shares issued on capital acquisition	493.0		—		100		493.0		—		100
Working capital acquired through capital acquisition	116.7		—		100		116.7		—		100
Long-term debt acquired through capital acquisition	363.8		—		100		363.8		—		100
Total capital acquisitions	2,513.9		1.3		193,277		4,589.7		90.7		4,960

The following table reconciles capital dispositions to total capital dispositions:

	Three months ended December 31						Year ended December 31
($ millions)	2023		2022		% Change		2023		2022		% Change
Capital dispositions	(593.3)		1.2		(49,542)		(604.5)		(283.6)		113
Working capital disposed through capital disposition	(9.1)		—		100		(9.1)		—		100
Total capital dispositions	(602.4)		1.2		(50,300)		(613.6)		(283.6)		116

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 2024 is a forward-looking non-GAAP measures and is 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, 2023.

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.

	Proved Developed Producing	Total Proved	Total Proved plus Probable
2022 Recycle Ratios
F&D Total (incl. change in FDC)	3.1	2.5	2.2
FD&A Total (incl. change in FDC)	3.4	2.8	2.3

In 2022, the Company’s Kaybob Duvernay asset generated a recycle ratio of 4.5 times based on F&D including FDC.

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: premium inventory of over 20 years and enhanced excess cash flow profile; dividend expectations; excess cash flow of $830 million expected in 2024 at US$75 WTI, with 60 percent returned to shareholders; five-year plan expected to generate strong per share growth and cumulative excess cash flow of $4.7 billion at US$70 WTI; enhanced the long-term sustainability and excess cash flow per share; strategic priorities; the extent and benefits of hedging; diversified pricing exposure for natural gas; dividend expectations; timing for the closing of the sale of Swan Hills and Turner Valley assets; acceleration of high-return inventory in the Kaybob Duvernay; strong drilling economics of the OHML program; low base decline rate of approximately 15 percent in its Saskatchewan assets, further enhancing its strong excess cash flow generation from these assets; opportunities to further enhance shareholder value by realizing potential cost efficiencies and productivity enhancements; unbooked locations and future NAV and reserves growth; reserves life index; 2P NAV; the budget remains disciplined and flexible, with a continued focus on allocating capital to the highest-return assets; 2024 budget allocation by area; 2024 budget, including base dividend, remains fully funded at approximately US$55/bbl WTI; additional efficiencies and improved productivity by further enhancing drilling and completions optimization, including optimizing wells drilled per section on Alberta Montney assets and drilling longer lateral wells in the Kaybob Duvernay; advancement of OHML drilling and decline mitigation programs; 2024 budget is expected to generate significant excess cash flow of approximately $830 million at approximately US$75/bbl WTI and $2.30/Mcf AECO for the full year; plans to continue allocating 60 percent of excess cash flow to shareholders through the base dividend and share repurchases, with the remaining 40 percent directed toward the balance sheet; leverage ratio is expected to be approximately 1.2 times at year-end 2024, based on the commodity price assumptions stated herein; NCIB expectations; 2024 funds flow sensitivities; plans to increase the percentage of excess cash flow returned to shareholders over time as balance sheet strengthens; strategy focused on delivering meaningful and sustainable total returns through a combination of return of capital, per-share growth and balance sheet strength; Crescent Point’s 2024 production and development capital expenditures guidance; and other information for Crescent Point’s 2024 guidance, including capitalized administration, reclamation activities, capital lease payments, annual operating expenses and royalties; and return of capital outlook, including base dividend, and the additional return of capital targeted as a percentage of 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, 2023. 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, 2023, which is accessible at www.sedarplus.ca.

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, 2023 under “Risk Factors” and our Management’s Discussion and Analysis for the year ended December 31, 2023, 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, 2023, 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, pandemics, and blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; risks and uncertainties related to oil and gas interests and operations on 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; the impacts of drought, wildfires and severe weather events; 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; changes in interest rates and inflation; uncertainties associated with regulatory approvals; geopolitical conflicts, including the Russian invasion of Ukraine and the conflict between Israel and Hamas; uncertainty of government policy changes; the impact of the implementation of the Canada-United States-Mexico Agreement; uncertainty regarding the benefits and costs of dispositions; failure to complete acquisitions and dispositions; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry; 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 2024 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 2023 and 2022, the aggregate average production for fourth quarter of 2023 and 2022, and the references to “natural gas”, “crude oil” and “condensate” 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
	2023	2022	2023	2022
Light & Medium Crude Oil (bbl/d)	12,198	13,671	12,665	14,274
Heavy Crude Oil (bbl/d)	3,795	3,870	3,818	4,027
Tight Oil (bbl/d)	56,657	40,068	49,779	42,134
Total Crude Oil (bbl/d)	72,650	57,609	66,262	60,435
NGLs (bbl/d)	39,517	33,871	36,851	31,967
Shale Gas (mcf/d)	236,926	128,437	200,514	117,617
Conventional Natural Gas (mcf/d)	11,380	10,769	10,761	10,482
Total Natural Gas (mcf/d)	248,306	139,206	211,275	128,099
Total production from continuing operations (boe/d)	153,551	114,681	138,326	113,752

	Three months ended December 31		Year ended December 31
	2023	2022	2023	2022
Light & Medium Crude Oil (bbl/d)	12,198	13,671	12,665	14,274
Heavy Crude Oil (bbl/d)	3,795	3,870	3,818	4,027
Tight Oil (bbl/d)	62,512	52,095	63,906	53,861
Total Crude Oil (bbl/d)	78,505	69,636	80,389	72,162
NGLs (bbl/d)	41,373	38,893	41,534	36,556
Shale Gas (mcf/d)	242,965	142,803	214,165	130,902
Conventional Natural Gas (mcf/d)	11,380	10,769	10,761	10,482
Total Natural Gas (mcf/d)	254,345	153,572	224,926	141,384
Total average daily production (boe/d)	162,269	134,124	159,411	132,282

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

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

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), 2P NAV, 1P NAV or PDP 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, proved reserves or proved developed producing reserves, respectively, based on three evaluators’ average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) December 31, 2023 escalated price forecast, the fair value for the Company’s oil and gas hedges based on such December 31, 2023 escalated price forecast, the value of undeveloped land and seismic, 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. Peak IP30 refers to the 30 consecutive days with the highest production rates since a well has come on production and may not be indicative of future performance. For additional product type information for our major operating areas, refer to our Reserves Report. Booked type well data was audited by independent reserves evaluator, McDaniel, effective December 31, 2023.

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”, “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.

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 NGLs 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 NGLs 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, NGLs 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.

This presentation references more than 20 years of premium locations in corporate inventory, which amount includes over 4,000 booked and unbooked locations. Unbooked future drilling locations are not associated with any reserves or contingent resources and have been identified by the Company and have not been audited by independent qualified reserves evaluators. The over 4,000 premium locations consist of: (A) approximately 1,950 Kaybob Duvernay and Alberta Montney premium locations, of which 596 are proved plus probable locations, as assigned in the company’s year end 2023 independent reserves evaluation in accordance with NI 51-101 and the COGE Handbook, and an incremental 1,357 are unbooked locations and (B) over 2,000 Saskatchewan premium locations, of which 1,189 are proved plus probable locations, as assigned in the company’s year end 2023 independent reserves evaluation in accordance with NI 51-101 and the COGE Handbook; and an incremental 882 are unbooked locations.

The peak 30-day rates for the 20 wells brought on stream in the Kaybob Duvernay in 2023 ranging consisted of average product types of 74% condensate, 9% NGLs and 17% shale gas within the Volatile Oil window and 43% condensate, 18% NGLs and 39% shale gas within the Liquids-Rich window.

The average peak 30-day rates for the 25 wells brought on stream in the Alberta Montney since initial entry into the play in second quarter 2023 generated the following average product types: 72% light and medium crude oil, 4% NGLs and 24% shale gas per well in Gold Creek West; 52% light and medium crude oil, 9% NGLs and 39% shale gas per well in Gold Creek and 82% light and medium crude oil, 3% NGLs and 15% shale gas per well in Karr East.

The Company’s most recent OHML achieved a peak-30 day rate of over 300 bbl/d (100% light and medium crude oil).

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, 2023, which will be filed on SEDAR+ (accessible at www.sedarplus.ca and EDGAR (accessible at www.sec.gov/edgar.shtml) on or before February 29, 2024 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.