Crescent Point Announces 2020 Results and Reserves

CALGARY, AB, Feb. 24, 2021 /CNW/ - 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, 2020.

Crescent Point recently announced an accretive acquisition of Kaybob Duvernay assets for $900 million (the "Acquisition") that further enhances the Company's balance sheet strength and sustainability, including its expected free cash flow generation. For more information on the Acquisition, which is expected to close in April 2021, please refer to the news release dated February 17, 2021.

KEY HIGHLIGHTS 

• Achieved annual average production ahead of 2020 guidance with capital expenditures under budget.
• Reduced net debt by over $615 million in 2020, driven by an accretive disposition and excess cash flow generation.
• Enhanced sustainability by reducing costs throughout the organization and lowering the production decline rate.
• Increased proved plus probable net asset value per share, excluding changes in pricing, by approximately 13 percent.
• Released second annual sustainability report and established an emissions intensity reduction target of 30 percent by 2025.
• Disciplined 2021 budget expected to generate $375 to $600 million of excess cash flow at US$50/bbl to US$60/bbl WTI.

"Our success over this past year highlights our resiliency, discipline and flexibility," said Craig Bryksa, President and CEO of Crescent Point. "As a result of the volatility in 2020, we acted swiftly, revising our capital program and operations, to enhance our financial flexibility and preserve the long-term value of our assets. Through our actions, over the last two years, we strengthened the Company and positioned ourselves to continue enhancing value for our stakeholders. Our recently announced acquisition of Kaybob Duvernay assets demonstrates this execution. These assets strengthen our expected free cash flow generation, leverage ratios and depth of high-quality inventory, within a transaction that is highly accretive on all financial metrics." 

FINANCIAL HIGHLIGHTS 

• For the year ended December 31, 2020, the Company's adjusted funds flow totaled $874.4 million, or $1.64 per share diluted. In the fourth quarter, adjusted funds flow totaled $220.2 million, or $0.41 per share diluted.
• For the year ended December 31, 2020, Crescent Point's development capital expenditures, which included drilling and development, facilities and seismic, totaled $654.8 million, including $169.4 million spent during fourth quarter. As a result, the Company's 2020 development capital expenditures were below its most recent annual guidance of $665 million.
• As at December 31, 2020, Crescent Point's net debt was approximately $2.1 billion. Management successfully reduced the Company's net debt by over $615 million in 2020, including approximately $40 million in fourth quarter. Crescent Point's unutilized credit capacity is expected to total approximately $2.0 billion upon closing of the Acquisition in April 2021. The Company's credit facilities are not due for renewal until October 2023.
• As part of its risk management program to protect against commodity price volatility, the Company maintains an active hedging portfolio. Crescent Point will have approximately 30 percent of its oil and liquids production, net of royalty interest, hedged through the remainder of 2021 upon closing of the Acquisition. These hedges primarily consist of swaps with an average price of over CDN$60/bbl. Crescent Point plans to remain disciplined in its approach to layering on additional protection in the context of commodity prices.
• As previously announced, the Company recorded a non-cash asset impairment charge of $3.6 billion ($2.7 billion after-tax) in first quarter 2020, primarily due to a significant decrease in the independent engineering price forecast. This resulted in Crescent Point incurring a net loss of $2.5 billion for the year ended December 31, 2020. Neither the Company's adjusted funds flow, nor its credit capacity were impacted by this charge, which is reversible in future periods should there be indications of a change in value, including higher forecast commodity prices. Crescent Point's adjusted net earnings for the year ended December 31, 2020 were $177.4 million.
• Subsequent to the quarter, the Company declared a quarterly cash dividend of $0.0025 per share payable on April 1, 2021.

All financial figures are approximate and in Canadian dollars unless otherwise noted. This press release contains forward-looking information and references to non-GAAP financial measures. Significant related assumptions and risk factors, and reconciliations are described under the Non-GAAP 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

• Annual average production in 2020 was 121,642 boe/d, slightly above Crescent Point's production guidance of 121,000 boe/d. Average production during fourth quarter was 111,217 boe/d, reflecting the reduced capital budget announced earlier in the year.
• Throughout 2020, the Company continued to optimize its workflows and implement its operational technology ("OT") platform across its Saskatchewan asset base. As previously announced, through these initiatives, Crescent Point removed approximately $60 million in budgeted operating expenses in 2020. The Company plans to continue the rollout of its OT platform in 2021.
• At year-end 2020, the Company had successfully reduced its average per well capital costs by over 10 percent, in-line with its previously announced expectation. This improvement highlights the benefits of Crescent Point's significant operational experience, allowing for ongoing knowledge transfer and optimization within its asset portfolio. The Company's 2021 budget does not include additional efficiencies that it plans to seek throughout the year.
• As part of Crescent Point's decline mitigation program, the Company successfully converted over 130 producing wells to water injection wells in 2020. A similar level of conversions is planned for 2021. Crescent Point's base decline rate at the start of 2021 improved by approximately five percent, compared to the prior year, and is expected to remain unchanged on a pro-forma basis at approximately 25 percent. The Company's oil production currently under waterflood accounts for approximately 25 percent of its current total oil production, with a low decline rate of approximately five percent. Crescent Point plans to continue advancement of its waterflood program as only half of its currently planned injector conversions across its resource plays have been completed to-date. The Company also plans to pilot other enhanced oil recovery techniques to further enhance its long-term free cash flow generation and sustainability.
• As part of its continued commitment to strong environmental, social and governance ("ESG") practices, the Company has set an emissions intensity reduction target of 30 percent by 2025, relative to its 2017 baseline. This target includes a 50 percent reduction in methane emissions. Crescent Point is currently on track to meet these targets. The Company also continues to allocate capital towards reducing its asset retirement obligations ("ARO") to minimize its environmental footprint. Including funding expected to be received from government grants, Crescent Point plans to reduce its standing well count by approximately 10 percent in 2021. The recent Acquisition is expected to further enhance the Company's ESG profile, with minimal ARO and a low emissions intensity associated with the Kaybob Duvernay assets.

RESERVES HIGHLIGHTS

"Our 2020 reserves highlight the continued improvements we have made to our cost structure, including lower future development capital and operating expenses, in addition to economic reserves additions through both our drilling and waterflood programs," said Bryksa. "As a result of lower commodity prices during first quarter 2020, we prudently revised our budget and allocated our remaining capital primarily to low-risk, high-return drilling locations. Given the majority of these wells were previously booked as undrilled locations, new reserves additions were not as meaningful as in prior years. Nonetheless, we positively impacted our net asset value in 2020 through our relentless focus on costs and debt reduction and through our disciplined disposition strategy. We look forward to developing the Kaybob Duvernay assets to further enhance shareholder value, including potential reserves additions given the significant undeveloped land included in the Acquisition."

• The Company's Proved plus Probable ("2P") net asset value ("NAV") was $8.53 per share at year-end 2020, based on independent engineering pricing, excluding land and seismic. This NAV forecast assumes an average WTI price of approximately US$51/bbl in the first five years. Excluding the changes in year-over-year pricing, the Company increased its 2P NAV per share by approximately 13 percent.
• Crescent Point's 2P reserves at year-end 2020 totaled 665.3 million boe ("MMboe"). The Company's Proved ("1P") and Proved Developed Producing ("PDP") reserves totaled 410.9 MMboe and 262.8 MMboe, respectively. Year-end 2020 reserves decreased in comparison to the prior year primarily due to economic factors, resulting from a lower independent engineering pricing forecast, which reduced 2P reserves by 35.2 MMboe, 1P reserves by 39.4 MMboe and PDP reserves by 19.3 MMboe.
• Crescent Point's 2P reserve life index ("RLI"), excluding the recently announced Acquisition, increased to approximately 16.6 years, up from approximately 14.3 years in the prior year.
• The Company's 2P reserves continued to benefit from its waterflood activities, which contributed approximately 4.9 MMboe of reserves additions in 2020. Approximately 30 percent, or 193.7 MMboe, of Crescent Point's 2P reserves were under the influence of secondary waterflood recovery at year-end 2020.
• The Company's 2P future development capital ("FDC") decreased by approximately $925 million, or 18 percent, primarily driven by a reduction in its per well capital costs and drilling of previously booked wells.

Additional information on the Company's 2020 reserves is provided in its Annual Information Form ("AIF") for the year-ended December 31, 2020. Crescent Point's 2P reserves from the Acquisition are 107.4 MMboe, which included only 36 booked locations in comparison to approximately 200 net internally identified locations.

OUTLOOK

Crescent Point's 2020 results demonstrated management's resiliency, discipline and flexibility. Despite a challenging year for the industry, the Company successfully and meaningfully enhanced its balance sheet and sustainability.

Crescent Point expects to further enhance the business throughout 2021 through the continued rollout of its OT platform, ongoing drilling and completions optimization, decline mitigation programs and effective risk mitigation strategies.

In addition to the expected accretion from the Acquisition, management will also identify opportunities to further enhance returns by successfully integrating the Kaybob Duvernay assets and by seeking to deliver additional related cost efficiencies. Crescent Point has a proven track record of material success in realizing such efficiencies over the years, including in resource plays with comparable well costs and development programs, such as in North Dakota and its previously owned Uinta Basin asset. 

The Company expects to generate significant excess cash flow in the current price environment, given its high-netback asset base, which is expected to further improve following the closing of the Acquisition. The Company is now expected to generate approximately $375 million to $600 million of excess cash flow in 2021, assuming an average WTI price of US$50/bbl to US$60/bbl for the year.

Management will remain disciplined in its allocation of excess cash flow, which will initially be directed to further net debt reduction, and will evaluate the return of additional capital to shareholders in the context of its capital allocation framework and leverage targets.

Summary of Reserves

The Company's reserves were independently evaluated by GLJ Limited. ("GLJ") and Sproule Associates Limited ("Sproule") as at December 31, 2020 and were aggregated by GLJ. 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, 2020 ^{(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	120,863	111,506	59,759	54,006	21,458	17,922	37,010	33,897
Proved Developed Non-Producing	6,209	5,290	1,453	1,346	2,058	1,816	1,649	1,376
Proved Undeveloped	79,190	70,701	22,242	20,589	1,420	1,229	19,422	17,244
Total Proved	206,262	187,497	83,454	75,941	24,935	20,966	58,082	52,517
Total Probable	136,923	124,744	53,678	48,998	6,665	5,355	33,832	30,689
Total Proved plus Probable	343,185	312,241	137,131	124,939	31,600	26,321	91,914	83,206

	Shale Gas (MMcf)		Natural Gas (MMcf)		Total (Mboe)
Reserves Category	Gross	Net	Gross	Net	Gross	Net
Proved Developed Producing	101,526	92,300	40,591	38,530	262,775	239,136
Proved Developed Non-Producing	4,339	3,659	1,227	1,014	12,297	10,607
Proved Undeveloped	70,873	61,510	10,224	9,408	135,790	121,582
Total Proved	176,738	157,469	52,042	48,952	410,862	371,325
Total Probable	110,880	99,166	29,381	27,312	254,476	230,865
Total Proved plus Probable	287,618	256,635	81,423	76,264	665,338	602,190

(1)	Based on Sproule's December 31, 2020, 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, 2020 ^{(1)  (2)} 

			Before Tax Net Present Value ($ millions)
			Discount Rate
Price Deck	Reserves Category	Gross Reserves (Mboe)	0%	5%	10%	15%
Sproule Forecast	Proved Developed Producing	262,775	4,795	4,017	3,358	2,884
	Proved and Probable Developed Producing	361,172	7,867	5,770	4,509	3,718
	Total Proved	410,862	6,644	5,195	4,115	3,367
	Total Proved plus Probable	665,338	13,464	9,189	6,731	5,223

(1)	Sproule Forecast based on Sproule's December 31, 2020, escalated price forecast.
(2)	Numbers may not add due to rounding.

RESERVES RECONCILIATION
Gross Reserves ^{(1) (2) (3) (4)}

	Tight Oil (Mbbls)			Light and Medium Oil (Mbbls)			Heavy Oil (Mbbls)
Factors	Proved	Probable	Proved plus Probable	Proved	Probable	Proved plus Probable	Proved	Probable	Proved plus Probable
December 31, 2019	235,043	150,052	385,094	100,947	58,348	159,295	27,799	6,894	34,693
Extensions and Improved Recovery	5,722	4,054	9,776	1,693	(946)	747	-	-	-
Technical Revisions	4,936	(18,289)	(13,354)	4,402	(4,687)	(285)	21	73	94
Acquisitions	126	78	204	30	7	37	-	-	-
Dispositions	(83)	(26)	(109)	(1,848)	(1,454)	(3,303)	-	-	-
Economic Factors	(13,629)	1,055	(12,574)	(14,142)	2,410	(11,732)	(1,283)	(301)	(1,584)
Production	(25,853)	-	(25,853)	(7,628)	-	(7,628)	(1,603)	-	(1,603)
December 31, 2020	206,262	136,923	343,185	83,454	53,678	137,131	24,935	6,665	31,600

	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, 2019	63,062	33,315	96,377	179,325	103,163	282,488	72,086	33,640	105,726
Extensions and Improved Recovery	994	253	1,247	2,969	1,827	4,796	631	(106)	526
Technical Revisions	5,187	(413)	4,774	23,892	2,904	26,796	4,398	(1,270)	3,128
Acquisitions	19	10	29	54	28	82	-	-	-
Dispositions	(105)	(63)	(168)	(76)	(23)	(99)	(1,972)	(2,153)	(4,125)
Economic Factors	(5,754)	730	(5,023)	(9,785)	2,981	(6,804)	(18,058)	(730)	(18,788)
Production	(5,322)	-	(5,322)	(19,642)	-	(19,642)	(5,044)	-	(5,044)
December 31, 2020	58,082	33,832	91,914	176,738	110,880	287,618	52,042	29,381	81,423

	Total Oil Equivalent (Mboe)
Factors	Proved	Probable	Proved plus Probable
December 31, 2019	468,753	271,409	740,161
Extensions and Improved Recovery	9,010	3,648	12,657
Technical Revisions	19,261	(23,043)	(3,782)
Acquisitions	184	100	284
Dispositions	(2,377)	(1,906)	(4,283)
Economic Factors	(39,447)	4,269	(35,178)
Production	(44,521)	-	(44,521)
December 31, 2020	410,862	254,476	665,338

(1)	Based on Sproule's December 31, 2020, 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 and Development Costs

The Company's F&D costs and recycle ratios for year-end 2020 may not be meaningful or comparable to prior year results due to a number of factors, including both a significantly lower commodity price forecast, which impacted economic revisions, and a significant reduction in FDC relative to total capital expenditures.

	2020 Totals	Change in FDC	Total
Capital ($ millions) ^(1)
Total Proved plus Probable	658	(908)	(250)
Total Proved	658	(876)	(218)
Proved Developed Producing	658	(3)	655
Reserves Additions (Mboe) ^(2)
Total Proved plus Probable	(26,303)	-	(26,303)
Total Proved	(11,177)	-	(11,177)
Proved Developed Producing	4,173	-	4,173

(1)	The capital expenditures include the announced purchase price of corporate acquisitions rather than the amounts allocated to property, plant and equipment for accounting purposes. The capital expenditures also exclude capitalized administration costs and transaction costs.
(2)	Gross Company interest reserves are used in this calculation (working interest reserves, before deduction of any royalties and without including any royalty interests of the Company).

	Excluding changes in FDC			Including changes in FDC
	($/boe, except recycle ratios)			($/boe, except recycle ratios)
	2020	2019	3 Years Ended Dec. 31, 2020 (Weighted Avg.)	2020	2019	3 Years Ended Dec. 31, 2020 (Weighted Avg.)
F&D Cost ^(1)
Total Proved plus Probable	($25.03)	($118.27)	$67.00	$9.49	($100.09)	$56.09
Total Proved	($58.91)	$158.85	$49.23	$19.50	$151.57	$40.50
Proved Developed Producing	$157.78	$47.32	$34.92	$157.06	$47.03	$34.33
Recycle Ratio ^(2)
Total Proved plus Probable	(0.7)	(0.3)	0.5	1.9	(0.3)	0.5
Total Proved	(0.3)	0.2	0.6	0.9	0.2	0.7
Proved Developed Producing	0.1	0.7	0.9	0.1	0.7	0.9

(1)	F&D is calculated by dividing the identified capital expenditures by the applicable reserves additions. F&D can include or exclude changes to future development capital costs.
(2)	Recycle Ratio is calculated as operating netback before hedging divided by F&D costs. Based on a 2020 operating netback of $18.24 per boe, a 2019 operating netback of $33.81 per boe and a three-year weighted average operating netback of $30.36 per boe.

Future Development Capital

At year-end 2020, FDC for 2P reserves totaled $4.2 billion, compared to $5.1 billion at year-end 2019. The Company's FDC decreased by approximately $925 million, primarily driven by lower per well capital costs and drilling of previously booked wells.

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
2020	292	350	19	38	311	388
2021	478	571	71	71	549	643
2022	431	628	207	208	638	836
2023	351	663	206	206	557	869
2024	197	570	266	268	463	838
2025	18	342	-	141	18	483
2026	3	89	-	-	3	89
2027	1	2	-	-	1	2
2028	2	2	-	-	2	2
2029	1	1	-	-	1	1
2030	1	1	-	-	1	1
2031	2	1	-	-	2	1
Subtotal ^(1)	1,777	3,221	770	933	2,547	4,154
Remainder	12	16	-	-	12	16
Total ^(1)	1,789	3,237	770	933	2,559	4,170
10% Discounted	1,434	2,432	564	668	1,999	3,100

(1)	Numbers may not add due to rounding.

CONFERENCE CALL DETAILS
Crescent Point management will host a conference call on Wednesday, February 24, 2021 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 home page.

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.

2021 GUIDANCE

The Company's guidance for 2021 is as follows:

Total Annual Average Production (boe/d)^(1)	132,000 - 136,000
Capital Expenditures
Development capital expenditures ($ million)	$575 - $625
Capitalized G&A ($ millions)	$35
Total ($ million) ^(2)	$610 - $660
Other Information for 2021 Guidance
Reclamation activities ($ million) ^(3)	$15
Capital lease payments ($ million)	$20
Annual operating expenses	$625 - $645 million  ($12.75 - $13.25/boe)
Royalties	11.5% - 12.5%

1)	Total annual average production (boe/d) is comprised of 87% Oil & NGLs and 13% Natural Gas
2)	Land expenditures and net property acquisitions and dispositions are not included. Development capital expenditures spend is allocated as follows: 87% drilling & development and 13% facilities & seismic
3)	Reflects Crescent Point's portion of its expected total budget

The Company's audited financial statements and management's discussion and analysis for the year ended December 31, 2020, 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)	2020	2019	2020	2019
Financial
Cash flow from operating activities	245.1	396.5	860.5	1,742.9
Adjusted funds flow from operations ^(1)	220.2	418.4	874.4	1,825.4
Per share ^(1) (2)	0.41	0.78	1.64	3.34
Net income (loss)	(51.2)	(932.1)	(2,519.9)	(1,033.3)
Per share ^(2)	(0.10)	(1.73)	(4.76)	(1.89)
Adjusted net earnings from operations ^(1)	85.6	49.9	177.4	386.8
Per share ^(1) (2)	0.16	0.09	0.33	0.71
Dividends declared	1.4	5.4	9.4	22.0
Per share ^(2)	0.0025	0.0100	0.0175	0.0400
Net debt ^(1)	2,149.2	2,765.3	2,149.2	2,765.3
Net debt to adjusted funds flow from operations ^(1) (3)	2.5	1.5	2.5	1.5
Weighted average shares outstanding
Basic	530.0	537.4	529.3	545.7
Diluted	534.4	538.7	531.8	546.0
Operating
Average daily production
Crude oil (bbls/d)	87,512	111,394	95,859	126,219
NGLs (bbls/d)	13,033	21,406	14,542	20,746
Natural gas (mcf/d)	64,033	74,347	67,447	91,592
Total (boe/d)	111,217	145,191	121,642	162,230
Average selling prices ^(4)
Crude oil ($/bbl)	49.40	65.27	43.50	67.14
NGLs ($/bbl)	24.96	19.02	17.19	19.94
Natural gas ($/mcf)	3.42	3.35	3.02	2.75
Total ($/boe)	43.76	54.60	38.01	56.34
Netback ($/boe)
Oil and gas sales	43.76	54.60	38.01	56.34
Royalties	(5.65)	(7.79)	(4.88)	(8.15)
Operating expenses	(13.30)	(11.24)	(12.62)	(12.29)
Transportation expenses	(2.29)	(2.12)	(2.27)	(2.09)
Operating netback ^(1)	22.52	33.45	18.24	33.81
Realized gain (loss) on derivatives	4.03	1.71	5.52	0.73
Other ^(5)	(5.03)	(3.84)	(4.12)	(3.72)
Adjusted funds flow from operations netback ^(1)	21.52	31.32	19.64	30.82
Capital Expenditures
Capital acquisitions (dispositions), net ^(6)	1.1	(663.8)	(506.8)	(924.1)
Development capital expenditures
Drilling and development	152.3	312.7	586.5	1,155.9
Facilities and seismic	17.1	30.7	68.3	96.2
Total	169.4	343.4	654.8	1,252.1
Land expenditures	0.8	5.2	3.6	15.5

(1)	Adjusted funds flow from operations, adjusted funds flow from operations per share, adjusted net earnings from operations, adjusted net earnings from operations per share, net debt, net debt to adjusted funds flow from operations, operating netback and adjusted funds flow from operations netback as presented do not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other entities.
(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.

Non-GAAP Financial Measures

Throughout this press release, the Company uses the terms "adjusted funds flow", "adjusted funds flow from operations", "funds flow", "adjusted funds flow from operations per share - diluted", "adjusted net earnings from operations", "adjusted net earnings from operations per share - diluted", "free cash flow", "excess cash flow", "net debt", "net debt to adjusted funds flow from operations", "netback", "operating netback" and "adjusted funds flow from operations netback".  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.

Adjusted funds flow and funds flow are equivalent to adjusted funds flow from operations. Adjusted funds flow from operations is calculated based on cash flow from operating activities before changes in non-cash working capital, transaction costs and decommissioning expenditures funded by the Company. Adjusted funds flow from operations per share - diluted is calculated as adjusted funds flow from operations divided by the number of weighted average diluted shares outstanding.  Transaction costs are excluded as they vary based on the Company's acquisition and disposition activity and to ensure that this metric is more comparable between periods. Decommissioning expenditures are discretionary and are excluded as they may vary based on the stage of Company's assets and operating areas. Management utilizes adjusted funds flow from operations as a key measure to assess the ability of the Company to finance dividends, operating activities, capital expenditures and debt repayments. Adjusted funds flow from operations as presented is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. Excess cash flow is defined as adjusted funds flow from operations less capital expenditures, payments on lease liability, asset retirement obligations, dividends and other cash items (excluding net acquisitions and dispositions). Management utilizes excess cash flow as a key measure to assess the ability of the Company to finance dividends, potential share repurchases, debt repayments and returns-based growth.

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

	Three months ended December 31		Year Ended December 31
($ millions)	2020	2019	2020	2019
Cash flow from operating activities	245.1	396.5	860.5	1,742.9
Changes in non-cash working capital	(29.0)	6.6	(6.2)	47.5
Transaction costs	—	2.1	5.4	6.3
Decommissioning expenditures ^(1)	4.1	13.2	14.7	28.7
Adjusted funds flow from operations	220.2	418.4	874.4	1,825.4

(1)	Excludes amounts received from government subsidy programs.

Adjusted net earnings from operations is calculated based on net income before amortization of exploration and evaluation ("E&E") undeveloped land, impairment or impairment recoveries, unrealized derivative gains or losses, unrealized foreign exchange gain or loss on translation of hedged US dollar long-term debt, unrealized gains or losses on long-term investments, gains or losses on the sale of long-term investments and gains or losses on capital acquisitions and dispositions. Adjusted net earnings from operations per share - diluted is calculated as adjusted net earnings from operations divided by the number of weighted average diluted shares outstanding. Management utilizes adjusted net earnings from operations to present a measure of financial performance that is more comparable between periods. Adjusted net earnings from operations as presented is not intended to represent net earnings or other measures of financial performance calculated in accordance with IFRS. 

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

	Three months ended December 31		Year ended December 31
($ millions)	2020	2019	2020	2019
Net income (loss)	(51.2)	(932.1)	(2,519.9)	(1,033.3)
Amortization of E&E undeveloped land	13.9	21.3	71.9	129.1
Impairment	—	1,216.5	3,557.8	1,466.4
Unrealized derivative losses	185.5	153.9	112.5	269.6
Unrealized foreign exchange gain on translation of hedged US dollar long-term debt	(86.2)	(52.5)	(62.1)	(207.7)
Unrealized (gain) loss on long-term investments	(0.9)	0.5	4.2	2.0
Net (gain) loss on capital dispositions	(8.5)	(0.1)	(316.4)	199.2
Deferred tax relating to adjustments	33.0	(357.6)	(670.6)	(438.5)
Adjusted net earnings from operations	85.6	49.9	177.4	386.8

Free cash flow is calculated as adjusted funds flow from operations less capital expenditures, payments on lease liability, asset retirement obligations and other cash items (excluding net acquisitions and dispositions). Management utilizes free cash flow as a key measure to assess the ability of the Company to finance dividends, potential share repurchases, debt repayments and returns-based growth.

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

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

($ millions)	2020	2019
Long-term debt ^(1)	2,259.6	2,905.1
Accounts payable and accrued liabilities	311.6	479.4
Long-term compensation liability ^(2)	16.3	13.1
Cash	(8.8)	(56.9)
Accounts receivable	(200.5)	(295.9)
Prepaids and deposits	(22.7)	(6.9)
Long-term investments	(2.5)	(6.7)
Excludes:
Unrealized foreign exchange on translation of hedged US dollar long-term debt	(203.8)	(265.9)
Net debt	2,149.2	2,765.3

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

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. The ratio of net debt to adjusted funds flow from operations is used by management to measure the Company's overall debt position and to measure the strength of the Company's balance sheet. Crescent Point monitors this ratio and uses this as a key measure in making decisions regarding financing, capital spending and dividend levels.

Operating netback is calculated on a per boe basis as oil and gas sales, less royalties, operating and transportation expenses. Adjusted funds flow netback is equivalent to adjusted funds flow from operations netback. Adjusted funds flow from operations netback is calculated on a per boe basis as operating netback less net purchased products, realized derivative gains and losses, general and administrative expenses, interest on long-term debt, foreign exchange, cash-settled share-based compensation and certain cash items, excluding transaction costs, foreign exchange on US dollar long-term debt and certain non-cash items. Cash flow netback is equivalent to adjusted funds flow from operations netback.  Operating netback and adjusted funds flow from operations netback are common metrics used in the oil and gas industry and are used by management to measure operating results on a per boe basis to better analyze performance against prior periods on a comparable basis. Netback calculations are shown in the Financial and Operating Highlights section in this press release.

Management believes the presentation of the Non-GAAP 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: the expected closing of the Kaybob Duvernay acquisition; the expectation that the Kaybob Duvernay assets have minimal ARO and a low emissions intensity; the Company's emissions intensity reduction target of 30 percent by 2025, including a 50 reduction in methane emissions by 2025; $375 to $600 million of excess cash flow generated in 2021 at $US50/bbl to $US60/bbl WTI; preservation of the long-term value of our assets; Crescent Point's positioning as market conditions continue to improve; hedging program plans, extent and expectations; the Company's positioning to continue enhancing value for stakeholders; expectations of the acquisition of the Kaybob Duvernay, including: strengthened free cash flow generation, leverage ratios and depth of high-quality inventory, a transaction that is highly accretive on all financial metrics, and an enhanced Company ESG profile following the acquisition; dividend payment values and dates; expectations of generating significant excess cash flow in a rising price environment and the evaluation of the return of additional capital to shareholders; plans to continue the rollout of OT platform 2021; waterflood conversion plans for 2021; further planned waterflood conversions; decline rates; expected unutilized credit capacity; plans to pilot enhanced oil recovery techniques, and benefits thereof; additional environmental targets set in 2021; excepted 2021 standing well count reduction; Kaybob Duvernay reserves additions; 2P NAV at year-end 2020, based on independent engineering pricing, excluding land and seismic, and an average WTI price of approximately $51/bbl in the first five years; potential for further cost efficiencies in the Kaybob Duvernay assets; NPV values before tax; 2P RLI; 2P FDC; expectations of further enhancing the business throughout 2021, and the components thereof; opportunities to enhance returns through potential cost efficiencies in the Kaybob Duvernay assets; that management will remain disciplined in the allocation of excess cash flow and the directions thereof; the evaluation of return of additional capital shareholders; 2021 guidance including total annual average production, capital expenditures (and proportion allocated to drilling and development and facilities and seismic), capitalized G&A, reclamation activities, capital lease payment, annual operating expenses, annual average transportation costs, and royalties.

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

Unless otherwise noted, reserves referenced herein are given as at December 31, 2020. 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, 2020, 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, 2020 under "Risk Factors" and our Management's Discussion and Analysis for the year ended December 31, 2020, 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, 2020, under the headings "Capital Expenditures", "Liquidity and Capital Resources", "Critical Accounting Estimates", "Risk Factors", "Changes in Accounting Policies" 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 the Acquisition; failure to complete the Acquisition; the risk of carrying out operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; risks and uncertainties related to oil and gas interests and operations on Indigenous lands; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value and likelihood of acquisitions and dispositions, and exploration and development programs; unexpected geological, technical, drilling, construction, processing and transportation problems; availability of insurance; fluctuations in foreign exchange and interest rates; stock market volatility; general economic, market and business conditions, including uncertainty in the demand for oil and gas and economic activity in general as a result of the COVID-19 pandemic; uncertainties associated with regulatory approvals; uncertainty of government policy changes; 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; changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry; the wide-ranging impacts of the COVID-19 pandemic, including on demand, health and supply chain; and other factors, many of which are outside the control of the Company. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Crescent Point's future course of action depends on management's assessment of all information available at the relevant time.

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

Product Type Production Information

The Company's annual aggregate production for 2020 and 2019, the aggregate average production for the fourth quarter of 2020 and 2019, and the references to "natural gas" and "crude oil", reported in this Press Release consist of the following product types, as defined in NI 51-101 and using a conversion ratio of 6 Mcf : 1 Bbl where applicable:

	Three months ended December 31		Year ended December 31
	2020	2019	2020	2019
Light & Medium Crude Oil (bbl/d)	21,025	25,366	20,842	30,094
Heavy Crude Oil (bbl/d)	4,276	4,819	4,380	4,749
Tight Oil (bbl/d)	62,211	81,209	70,637	91,376
Total Crude Oil (bbl/d)	87,512	111,394	95,859	126,219
NGLs (bbl/d)	13,033	21,406	14,542	20,746
Shale Gas (Mcf/d)	52,370	56,446	53,666	71,749
Conventional Natural Gas (Mcf/d)	11,663	17,901	13,781	19,843
Total Natural Gas (Mcf/d)	64,033	74,347	67,447	91,592
Total (boe/d)	111,217	145,191	121,642	162,230

DEFINITIONS

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

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

Future development capital (FDC) reflects the independent evaluator's best estimate of the cost required to bring 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 Sproule's December 31, 2020 escalated price forecast, the fair value for the Company's oil and gas hedges based on Sproule's December 31, 2020 escalated price forecast, less outstanding net debt. The NAV per share is calculated on a fully diluted basis.

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

Recycle Ratio is calculated as operating netback divided by F&D. Based on a 2020 netback (before hedging), of $18.24 per boe, a 2019 netback (before hedging) of $33.81 per boe and a three-year weighted average netback (before hedging) of $30.36 per boe.

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Proved reserves are reserves estimated to have a high degree of certainty of recoverability. Probable reserves are less certain to be recoverable than proved reserves and possible reserves are less certain than probable reserves. 

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

Reserves and Drilling Data

The reserves information contained in this press release has been prepared in accordance with NI 51-101.

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

This press release contains metrics commonly used in the oil and natural gas industry, including "netbacks", "F&D costs", "FDC", "NAV", "recycle ratio", "reserve life index", and "decline rate". 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 changes in FDC have been presented in this news release because they provide a useful measure of capital efficiency. F&D costs, including land, facility and seismic expenditures and excluding changes in FDC have also been presented in this news release because they provide a useful measure of capital efficiency.

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

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

The Company retained McDaniel & Associates Consultants Ltd. ("McDaniel") to evaluate the reserves associated with Kaybob Duvernay assets and prepare the related independent evaluators report (the "McDaniel Report"). The statement of reserves data and other oil and gas information, associated with the Kaybob Duvernay assets, set forth in this press release is dated February 11, 2021. The effective date of the reserves information provided for the Kaybob Duvernay assets herein is December 31, 2020, unless otherwise indicated, and the preparation date is February 11, 2021. McDaniel prepared the McDaniel Report in accordance with the standards contained in NI 51-101 and the COGE Handbook that were in effect at the relevant time. This press release discloses 36 booked drilling locations, which are proved plus probable of approximately 200 potential net drilling locations. Proved plus probable locations consist of proposed drilling locations identified in the McDaniel Report that have proved and/or probable reserves, as applicable, attributed to them. The Company's ability to drill and develop these locations and the drilling locations on which the Company actually drills wells depends on a number of uncertainties and factors, including, but not limited to, the availability of capital, equipment and personnel, oil and natural gas prices, costs, inclement weather, seasonal restrictions, drilling results, additional geological, geophysical and reservoir information that is obtained, production rate recovery, gathering system and transportation constraints, the net price received for commodities produced, regulatory approvals and regulatory changes. As a result of these uncertainties, there can be no assurance that the potential future drilling locations that the Company has identified will ever be drilled and, if drilled, that such locations will result in additional crude oil, natural gas or NGLs produced. As such, the Company's actual drilling activities may differ materially from those presently identified, which could adversely affect the Company's business. There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil, natural gas and NGL reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For these reasons, estimates of the economically recoverable crude oil, NGL and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.

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

The reserve data provided in this news release presents only a portion of the disclosure required under National Instrument 51-101. All of the required information will be contained in the Company's Annual Information Form for the year ended December 31, 2020, which will be filed on SEDAR (accessible at www.sedar.com) and EDGAR (accessible at www.sec.gov/edgar.shtml) on or before February 24, 2021 and further supplemented by Material Change Reports as applicable.

FOR MORE INFORMATION ON CRESCENT POINT ENERGY, PLEASE CONTACT:

Brad Borggard, Senior Vice President, Corporate Planning and Capital Markets, or
Shant Madian, Vice President, Investor Relations and Corporate Communications
Telephone: [phone] Toll-free (US and Canada): 888-693-0020  Fax: [phone]
Address: Crescent Point Energy Corp. Suite 2000, 585 - 8th Avenue S.W. Calgary AB  T2P 1G1

www.crescentpointenergy.com

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

SOURCE Crescent Point Energy Corp.

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