Crescent Point Announces 2018 Results and Reserves

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Mar 07, 2019, 06:30 ET

CALGARY, March 7, 2019 /CNW/ - Crescent Point Energy Corp. ("Crescent Point" or the "Company") (TSX and NYSE: CPG) is pleased to announce its operating and financial results for the year ended December 31, 2018.

KEY HIGHLIGHTS

Over $400 million of excess cash flow expected to be available in 2019 for net debt repayment and additional share repurchases based on current strip prices. This amount excludes proceeds from any additional dispositions.
Strong capital discipline with 2018 capital expenditures $38 million under budget and annual production ahead of guidance.
Executed over $355 million of dispositions in 2018.
Replaced 142 percent of 2018 production through organic reserves growth.
Increased net asset value ("NAV") per share by approximately four percent, assuming a constant price deck of US$55.00/bbl, or approximately eight percent adjusted for dividends paid during the year.
Commenced a normal course issuer bid ("NCIB") on January 25, 2019, with approximately 1.3 million shares repurchased to date at an average cost of $3.89 per share, which is a significant discount to the Company's current NAV.
Continued board renewal process, including the recent appointment of John Dielwart as a new independent director.

"In 2018, we spent below budget, exceeded our production guidance and increased our net asset value per share," said Craig Bryksa, President and CEO of Crescent Point. "In mid-2018, new management began transitioning the company to be more focused and efficient, realizing cost structure improvements and prioritizing capital allocation based on returns while continuing to advance our core areas. In addition to these changes and those set out in our transition plan, we also welcome and look forward to the additional insight and expertise provided through our ongoing board renewal process."

FINANCIAL HIGHLIGHTS

For the year ended December 31, 2018, the Company's adjusted funds flow totaled $1.74 billion, or $3.16 per share diluted. In fourth quarter, adjusted funds flow totaled $337.3 million, or $0.61 per share diluted.
For the year ended December 31, 2018, Crescent Point's capital expenditures on drilling and development, facilities and seismic totaled $1.737 billion, which was below its annual guidance of $1.775 billion. Capital expenditures totaled $302.3 million in fourth quarter, including $278.4 million spent on drilling and development to drill 172 (139.6 net) wells.
As at December 31, 2018, net debt to adjusted funds flow was 2.3 times, with cash and unutilized credit capacity of approximately $1.62 billion. Based on current strip commodity prices and guidance, net debt to adjusted funds flow is forecast to be 2.0 times at year-end 2019, with over $400 million of excess cash flow available for net debt reduction and share repurchases.
For the year ended 2018, the Company incurred a net loss of $2.62 billion, including a non-cash impairment of $3.71 billion ($2.73 billion after-tax). Post-impairment, Crescent Point's balance sheet reflects a better approximation of the fair value of its asset base in the current environment and incorporates a higher cost of capital. The charge was not related to underlying asset performance and does not impact the Company's adjusted funds flow or the amount of credit available under its bank credit facilities.

DIFFERENTIALS AND MARKET ACCESS

Crescent Point's fourth quarter oil differential widened to $23.34/bbl from $10.74/bbl in third quarter. This compared positively to the fourth quarter Edmonton Par differential of $34.88/bbl. Based on realized prices to date and the forward curve, the Company's first quarter 2019 oil differential is expected to narrow to approximately $8.75/bbl. This is expected to improve its realized oil price by approximately 15 percent relative to fourth quarter 2018. Crescent Point remains unaffected by the Alberta Government's production curtailments given the smaller size of its operations in the province.
During periods of increased market access constraint in Canada, the Company expects that its oil production will continue receiving a premium due to a significant portion of its assets located either downstream of recent apportionment points or in the United States. Crescent Point is also exploring solutions to further enhance realized pricing for its Canadian oil production.
Subsequent to fourth quarter 2018, the Company resolved a National Energy Board complaint and legal action through the negotiation and execution of a settlement agreement. The agreement includes a cash settlement payable to Crescent Point in addition to a revised pipeline tariff that is expected to increase the Company's netback for oil production transported on the Saskatchewan Pipeline System.

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 and Forward-Looking Statements sections of this press release, respectively.

OPERATIONAL HIGHLIGHTS

Annual average production in 2018 was 178,166 boe/d, exceeding Crescent Point's guidance of 177,000 boe/d. As previously announced, the Company sold approximately 7,000 boe/d during 2018 for proceeds of approximately $355 million.
Crescent Point continues to advance its key focus areas. In Viewfield, the Company's waterflood program has allowed for a base decline rate of approximately 25 percent in 2019. This decline rate is below the corporate average and helps drive free cash flow generation in the play. In Flat Lake, the Company has been testing longer laterals and drilled several two-mile horizontal wells as part of its fourth quarter program. This group of wells generated encouraging results with average 30-day initial production ("IP30") rates of over 270 boe/d and are expected to pay out in approximately 18 months at current strip prices. Crescent Point has budgeted for an increased number of two-mile horizontal wells in 2019 based on these results and recent well cost reductions of approximately 10 percent.
In the Uinta Basin, Crescent Point continues to generate strong production results through its two-mile horizontal well program. During 2018, the Company completed 11 two-mile horizontal wells targeting the Wasatch and Uteland Butte zones with IP30 rates averaging approximately 900 boe/d. Notwithstanding these strong results and its ability to reduce well costs by over 10 percent, the Company reduced capital allocated to this play in 2019 based on returns due to existing market access.
As part of its waterflood program, Crescent Point converted 79 producing wells to water injection wells in 2018 for approximately $50 million. The Company plans to convert approximately 145 wells in 2019 for approximately $40 million, highlighting its focus on cost reductions while advancing decline mitigation techniques. Conversion costs to date in 2019 have been on, or below, budget.

RESERVES HIGHLIGHTS

On a Proved Plus Probable ("2P") basis, Crescent Point organically replaced 142 percent of its 2018 production and achieved reserves of 987.6 million boe ("MMboe") (90 percent oil and liquids). Excluding acquisitions and dispositions ("A&D"), the Company's 2P reserves grew by 27.2 MMboe, net of 2018 production.
Crescent Point added 92.2 MMboe of organic 2P reserves in 2018, generating 2P F&D costs of $19.20 per boe, excluding changes in Future Development Capital ("FDC"), and an operating netback of $35.52 per boe, for a recycle ratio of 1.9 times.
Total 2P reserves growth benefited from 132.1 MMboe of extensions and improved recovery less 40.6 MMboe of net technical revisions. These technical revisions include a reduction of vertical drilling locations in the Uinta Basin as part of the Company's asset review and its increased focus on horizontal well development.
Over 23 percent of the Company's total organic 2P reserves additions in 2018, or 21.5 MMboe, were attributed to low F&D waterflood activities. Crescent Point has added over 60 MMboe of 2P waterflood reserves across its operations since 2013, with 2018 marking the sixth consecutive year independent evaluators have recognized tight rock waterflood additions.
On a Proved ("1P") basis, Crescent Point replaced 120 percent of its 2018 production and achieved reserves of 619.5 MMboe (90 percent oil and liquids). Excluding changes in FDC, 1P F&D costs totaled $22.61 per boe, for a recycle ratio of 1.6 times. Overall, 1P reserves accounted for 63 percent of total 2P reserves.
On a Proved Developed Producing ("PDP") basis, Crescent Point replaced 115 percent of 2018 production and achieved PDP reserves of 386.9 MMboe (90 percent oil and liquids). PDP F&D costs totaled $23.64 per boe, excluding changes in FDC, representing a recycle ratio of 1.5 times. Overall, PDP reserves accounted for 39 percent of total 2P reserves.

NET ASSET VALUE HIGHLIGHTS

The Company's 2P NAV was $24.41 per share at year-end 2018, based on independent engineering pricing, or $13.38 per share, based on a more conservative pricing assumption of flat US$55.00/bbl.
Excluding any value attributed to land and seismic, Crescent Point's year-end 2P NAV increased by four percent to $11.37 per share in 2018. This NAV includes $6.01 per share of developed producing value for the Company's existing production over its remaining economic life, as represented by its year-end 2018 proved and probable developed producing reserves.
The Company's 1P and PDP NAVs at US$55.00/bbl increased by approximately eight percent and 11 percent, respectively, in 2018, excluding any value attributed to land and seismic.

Before Tax Net Asset Value Per Share, Fully Diluted, as at December 31, 2018 at Flat Pricing of US$55.00/bbl

Reserves Category	NAV
Proved and Probable	$13.38
Proved and Probable Developed Producing	$8.02
Proved Developed Producing	$5.37

(1)	NAV per share based on 553.4 million shares fully diluted and a 10% discount rate.
(2)	NAV includes land, seismic and derivatives less net debt of of $4.0 billion as at December 31, 2018.

BOARD RENEWAL PROCESS

As part of Crescent Point's ongoing Board of Directors ("Board") renewal process, and as previously announced, Mr. Dielwart has joined the Board as a new independent director. The Company also announces today the retirement of Rene Amirault from its Board.

"Rene has provided Crescent Point valuable guidance, especially in his most recent role as Chair of our Environmental, Health and Safety Committee," said Bob Heinemann, Chairman of the Board. "We've appreciated his strong focus on efficient operations, capital discipline and long-term strategy."

As previously announced, Peter Bannister and Gerald Romanzin both plan to retire from the Board at the Company's 2019 annual general meeting ("AGM"). Crescent Point remains committed to its deliberate and thoughtful Board renewal process and expects to replace its retiring members with additional independent Board members. Crescent Point's Board expects to have completed a full Board renewal since 2014, following its 2019 AGM.

OUTLOOK

Since the second half of 2018, Crescent Point's new management team has prioritized its key value drivers, which include disciplined capital allocation, cost reductions and balance sheet improvement.

The Company now allocates capital based on returns versus simple volume growth. This shift in focus has allowed Crescent Point to adopt a capital program with more consistent activity levels throughout the year and has resulted in increased competition for capital across the Company's portfolio of assets.

Crescent Point has increased its emphasis on cost reductions compared to its historical focus on operational outperformance. Since September 2018, management has reduced the Company's workforce, streamlined its executive team and implemented new initiatives that have resulted in significant savings in general and administrative costs, operating expenses and well costs. Crescent Point is also implementing new practices to further improve its controllable operating expenses. Further savings across the organization are expected as the Company continues to focus its asset base.

Crescent Point's financial flexibility remains strong with cash and unutilized credit capacity of $1.62 billion, no material near-term debt maturities and a strong portfolio of oil and gas commodity hedges. As part of its transition plan, Crescent Point is targeting to further improve its balance sheet through net debt reduction by way of free cash flow generation and proceeds from any dispositions.

On January 15, 2019, the Company revised its dividend strategy. This new strategy provides increased flexibility in the event of lower commodity prices and enhanced free cash flow generation as commodity prices improve. Crescent Point also initiated a disposition process during first quarter 2019 to market its southeast Saskatchewan conventional assets while at the same time progressing the strategic divestment of certain infrastructure assets. The Company plans to remain disciplined and flexible throughout its divestiture processes.

As the Company generates additional cash flow at higher commodity prices or realizes proceeds from potential asset dispositions, it plans to continue prioritizing the allocation of such funds to further net debt reduction and accretive share repurchases. Based on an updated adjusted funds flow sensitivity of approximately $40 million for every US$1.00/bbl change in WTI, the Company expects to realize over $400 million of excess cash flow in 2019 based on its guidance and current strip prices, including approximately $50 million of hedging gains.

As at March 1, 2019, Crescent Point had, on average, over 40 percent of its oil and liquids production, net of royalty interest, hedged through 2019. The Company has also recently added oil hedges at attractive prices extending through to third quarter 2020.

Crescent Point is on track with its 2019 budget, which remains unchanged, with annual average production of 170,000 to 174,000 boe/d and capital expenditures of $1.20 to $1.30 billion. The Company expects to update shareholders as it continues to execute its transition plan and elect new independent directors as part of its Board renewal process.

Summary of Reserves

The Company's reserves were independently evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") and Sproule Associates Limited ("Sproule") as at December 31, 2018 and were aggregated by GLJ. The reserves evaluation and reporting was conducted in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGEH") and National Instrument 51-101 Standards for Disclosure of Oil and Gas Activities ("NI 51-101").

As at December 31, 2018 ^{(1) (2) (3) (4) (5)}


	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	182,326	165,038	91,817	81,766	24,625	20,295	49,254	44,686
Proved Developed Non-Producing	4,925	4,529	1,789	1,629	2,619	2,293	1,189	1,082
Proved Undeveloped	138,096	122,293	33,819	31,420	1,771	1,545	25,357	22,408
Total Proved	325,347	291,861	127,424	114,815	29,015	24,133	75,800	68,176
Total Probable	209,486	185,354	71,959	64,954	7,903	6,370	42,302	37,904
Total Proved plus Probable	534,833	477,215	199,383	179,769	36,918	30,502	118,102	106,080


	Shale Gas (MMcf)		Natural Gas (MMcf)		Total (Mboe)
Reserves Category	Gross	Net	Gross	Net	Gross	Net
Proved Developed Producing	162,060	147,915	71,229	66,719	386,903	347,558
Proved Developed Non-Producing	5,287	4,686	1,154	930	11,595	10,470
Proved Undeveloped	119,169	104,552	12,882	11,927	221,051	197,079
Total Proved	286,515	257,154	85,264	79,576	619,549	555,107
Total Probable	178,677	158,549	39,955	36,980	368,089	327,169
Total Proved plus Probable	465,193	415,702	125,219	116,557	987,638	882,276


(1)	Based on Sproule's December 31, 2018, 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.
(5)	Detailed reserves and analysis are provided in the Company's Annual Information Form for the year-ended December 31, 2018 (the "AIF").

Summary of Before Tax Net Present Values

As at December 31, 2018 ^{(1) (2) (3)}


			Before Tax Net Present Value ($ millions)
			Discount Rate
Price Deck	Reserves Category	Gross Reserves (Mboe)	0%	5%	10%	15%
Sproule Forecast	Proved Developed Producing	386,903	13,918	10,392	8,358	7,044
	Proved and Probable Developed Producing Total Proved Total Proved plus Probable	523,223	20,295	13,763	10,518	8,601
		619,549	19,894	14,319	11,053	8,953
		987,638	35,283	22,832	16,596	12,925
US$55.00/bbl WTI Flat	Proved Developed Producing	365,403	8,764	6,950	5,798	5,007
	Proved and Probable Developed Producing	493,811	12,321	9,078	7,265	6,114
	Total Proved	552,005	11,479	8,726	6,971	5,777
	Total Proved plus Probable	917,872	19,713	13,620	10,232	8,115


(1)	Sproule Forecast based on Sproule's December 31, 2018, escalated price forecast.
(2)	Reserve values as of December 31, 2018.
(3)	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, 2017	323,698	204,252	527,950	143,580	84,179	227,759	26,335	7,237	33,571
Extensions and Improved Recovery	48,896	32,368	81,264	14,731	8,858	23,590	1,613	710	2,323
Technical Revisions	(9,293)	(26,229)	(35,522)	(707)	(7,768)	(8,474)	2,732	(37)	2,696
Acquisitions	596	107	702	22	51	73	-	-	-
Dispositions	(3,039)	(1,503)	(4,542)	(17,379)	(14,080)	(31,459)	-	-	-
Economic Factors	(223)	492	269	1,318	718	2,036	115	(7)	108
Production	(35,288)	-	(35,288)	(14,141)	-	(14,141)	(1,780)	-	(1,780)
December 31, 2018	325,347	209,486	534,833	127,424	71,959	199,383	29,015	7,903	36,918


	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, 2017	69,090	39,039	108,129	300,259	175,023	475,281	111,140	54,695	165,834
Extensions and Improved Recovery	8,061	4,986	13,047	33,558	31,237	64,795	3,810	2,437	6,247
Technical Revisions	7,954	(651)	7,303	(13,549)	(27,643)	(41,192)	4,456	(2,889)	1,567
Acquisitions	13	3	16	463	122	586	-	-	-
Dispositions	(1,934)	(1,122)	(3,056)	(3,147)	(1,025)	(4,172)	(16,725)	(12,754)	(29,479)
Economic Factors	(156)	47	(109)	(3,004)	962	(2,042)	(5,924)	(1,534)	(7,458)
Production	(7,229)	-	(7,229)	(28,064)	-	(28,064)	(11,493)	-	(11,493)
December 31, 2018	75,800	42,302	118,102	286,515	178,677	465,193	85,264	39,955	125,219


	Total Oil Equivalent (Mboe)
Factors	Proved	Probable	Proved plus Probable
December 31, 2017	631,270	372,993	1,004,262
Extensions and Improved Recovery	79,529	52,535	132,064
Technical Revisions	(829)	(39,773)	(40,602)
Acquisitions	708	108	889
Dispositions	(25,664)	(19,001)	(44,665)
Economic Factors	(434)	1,155	721
Production	(65,031)	-	(65,031)
December 31, 2018	619,549	368,089	987,638

(1)	Based on Sproule's December 31, 2018, escalated price forecast.
(2)	"Gross Reserves" are the Company's working-interest share before deduction of any royalties and without including any royalty interests of the Company.
(3)	Numbers may not add due to rounding.
(4)	Detailed descriptions for significant changes in values are included in the AIF.

Finding and Development Costs


	2018 Totals	Change in FDC	Total
Capital ($ millions) ⁽¹⁾
Total Proved plus Probable	1,770	501	2,271
Total Proved	1,770	279	2,049
Proved Developed Producing	1,770	(52)	1,717

Reserves Additions (Mboe) ⁽²⁾
Total Proved plus Probable	92,183	-	92,183
Total Proved	78,266	-	78,266
Proved Developed Producing	74,873	-	74,873


(1)	The capital expenditures exclude capitalized administration costs and transaction costs.
(2)	Gross Company interest reserves are used in this calculation (working interest reserves, before deduction of any royalties and without including any royalty interests of the Company).


	Excluding changes in FDC ($/boe, except recycle ratios)			Including changes in FDC ($/boe, except recycle ratios)
	2018	2017	3 Years Ended Dec. 31, 2018 (Weighted Avg.)	2018	2017	3 Years Ended Dec. 31, 2018 (Weighted Avg.)
F&D Cost ⁽¹⁾
Total Proved plus Probable	$19.20	$18.56	$18.42	$24.64	$21.64	$18.93
Total Proved	$22.61	$20.76	$20.97	$26.18	$23.57	$21.17
Proved Developed Producing	$23.64	$19.79	$21.15	$22.94	$19.96	$20.97

F&D Recycle Ratio ⁽²⁾
Total Proved plus Probable	1.9	1.6	1.6	1.4	1.4	1.5
Total Proved	1.6	1.4	1.4	1.4	1.2	1.4
Proved Developed Producing	1.5	1.5	1.4	1.5	1.5	1.4


(1)	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.
(2)	Recycle Ratio is calculated as netback before hedging divided by F&D costs. Based on a 2018 netback (before hedging) of $35.52 per boe, a 2017 netback (before hedging) of $29.42 per boe and a three-year weighted average netback (before hedging) of $29.17 per boe.

Future Development Capital

At year-end 2018, FDC for 2P reserves totaled $7.0 billion, compared to $6.9 billion at year-end 2017. Net of A&D, FDC at year-end 2018 increased primarily due to the addition of new drilling locations identified by the Company.


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
2019	770	1,010	371	489	1,141	1,498
2020	780	1,097	406	558	1,186	1,655
2021	584	997	374	655	958	1,652
2022	455	790	255	504	711	1,293
2023	193	590	227	303	420	893
2024	8	2	1	-	9	2
2025	2	2	-	-	2	2
2026	1	2	-	1	1	3
2027	4	1	-	-	4	1
2028	1	5	-	-	1	5
2029	3	1	-	-	3	1
2030	1	3	-	-	1	3
Subtotal ⁽¹⁾	2,800	4,498	1,635	2,510	4,435	7,008
Remainder	12	15	-	-	12	15
Total ⁽¹⁾	2,812	4,513	1,635	2,510	4,447	7,023
10% Discounted	2,333	3,658	1,332	2,025	3,665	5,683


(1)	Numbers may not add due to rounding.

CONFERENCE CALL DETAILS

Crescent Point management will host a conference call on Thursday, March 7, 2019 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 at https://event.on24.com/wcc/r/1938081/3C8AE3F85E3132D87BFE894A568308B4. 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 website at https://www.crescentpointenergy.com/invest/conference-calls-webcasts. 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.

2019 GUIDANCE

The Company's guidance for 2019 is as follows:

Total annual average production (boe/d)

% Oil and NGLs

170,000 - 174,000

91%

Capital expenditures ($ millions) ⁽¹⁾

Drilling and development (%)

Facilities and seismic (%)

$1,200 to $1,300

90%

10%


(1)	Capital expenditures excludes any potential net property and land acquisitions and approximately $35 million of capitalized G&A.

The Company's audited financial statements and management's discussion and analysis for the year ended December 31, 2018, 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)	2018	2017	2018	2017
Financial
Cash flow from operating activities	359.1	449.6	1,748.0	1,718.7
Adjusted funds flow from operations ⁽¹⁾	337.3	494.7	1,741.2	1,728.8
Per share ^{(1) (2)}	0.61	0.90	3.16	3.16
Net income (loss)	(2,390.5)	(56.4)	(2,616.9)	(124.0)
Per share ⁽²⁾	(4.35)	(0.10)	(4.77)	(0.23)
Adjusted net earnings (loss) from operations ⁽¹⁾	(16.3)	(35.1)	234.6	100.0
Per share ^{(1) (2)}	(0.03)	(0.06)	0.43	0.18
Dividends declared	49.4	49.5	198.5	197.7
Per share ⁽²⁾	0.09	0.09	0.36	0.36
Payout ratio (%)⁽¹⁾	15	10	11	11
Net debt ⁽¹⁾	4,011.3	4,024.9	4,011.3	4,024.9
Net debt to adjusted funds flow from operations ^{(1) (3)}	2.3	2.3	2.3	2.3
Weighted average shares outstanding
Basic	550.2	545.8	549.1	545.2
Diluted	550.2	546.9	550.2	546.8
Operating
Average daily production
Crude oil (bbls/d)	140,281	140,544	140,298	139,996
NGLs (bbls/d)	20,210	19,437	19,805	18,250
Natural gas (mcf/d)	106,236	113,963	108,376	106,599
Total (boe/d)	178,198	178,975	178,166	176,013
Average selling prices ⁽⁴⁾
Crude oil ($/bbl)	54.38	64.27	69.43	59.05
NGLs ($/bbl)	32.76	34.16	33.66	27.80
Natural gas ($/mcf)	2.95	2.31	2.25	2.61
Total ($/boe)	48.28	55.64	59.78	51.43
Netback ($/boe)
Oil and gas sales	48.28	55.64	59.78	51.43
Royalties	(7.61)	(7.44)	(9.11)	(7.35)
Operating expenses	(12.86)	(12.53)	(13.13)	(12.56)
Transportation expenses	(2.06)	(2.07)	(2.02)	(2.08)
Operating netback ⁽¹⁾	25.75	33.60	35.52	29.44
Realized gain (loss) on derivatives	(1.34)	0.84	(4.00)	1.58
Other ⁽⁵⁾	(3.84)	(4.39)	(4.75)	(4.11)
Adjusted funds flow from operations netback ⁽¹⁾	20.57	30.05	26.77	26.91
Capital Expenditures
Capital acquisitions (dispositions), net ⁽⁶⁾	(42.5)	(156.0)	(340.5)	1.8
Development capital expenditures
Drilling and development	278.4	332.9	1,536.2	1,452.3
Facilities and seismic	23.9	42.3	200.4	172.7
Land	4.9	104.5	33.2	187.1
Total	307.2	479.7	1,769.8	1,812.1


(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, payout ratio, 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 and cash-settled share-based compensation and excludes transaction costs, foreign exchange on US dollar long-term debt and certain non-cash items.
(6)	Capital acquisitions (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 from operations", "adjusted funds flow from operations per share - diluted", "adjusted net earnings from operations", "adjusted net earnings from operations per share - diluted", "excess cash flow", "free cash flow", "net debt", "net debt to adjusted funds flow from operations", "netback" and "payout ratio". 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 is 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. 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 activity and to ensure that this metric is more comparable between periods. Decommissioning expenditures are excluded as the Company has a voluntary reclamation fund to fund decommissioning costs. 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.

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)	2018	2017	2018	2017
Cash flow from operating activities	359.1	449.6	1,748.0	1,718.7
Changes in non-cash working capital	(27.9)	35.5	(37.2)	(18.7)
Transaction costs	0.8	1.4	5.1	3.7
Decommissioning expenditures	5.3	8.2	25.3	25.1
Adjusted funds flow from operations	337.3	494.7	1,741.2	1,728.8

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 on property, plant and equipment ("PP&E"), 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 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)	2018	2017	2018	2017
Net income (loss)	(2,390.5)	(56.4)	(2,616.9)	(124.0)
Amortization of E&E undeveloped land	39.0	34.8	157.2	134.3
Impairment to PP&E	3,690.7	(102.9)	3,705.9	203.6
Unrealized derivative (gains) losses	(737.9)	180.0	(439.4)	163.6
Unrealized foreign exchange (gain) loss on translation of hedged US dollar long-term debt	184.4	(53.7)	254.2	(201.2)
Unrealized (gain) loss on long-term investments	3.8	(3.8)	16.2	3.4
(Gain) loss on sale of long-term investments	1.0	—	(0.7)	—
Net (gain) loss on capital dispositions	28.3	(21.0)	129.1	(31.1)
Deferred tax relating to adjustments	(835.1)	(12.1)	(971.0)	(48.6)
Adjusted net earnings (loss) from operations	(16.3)	(35.1)	234.6	100.0

Free cash flow is calculated as adjusted funds flow less capital expenditures. Excess cash flow is calculated as free cash flow less dividends. Management utilizes excess cash flow and free cash flow as key measures 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, dividends payable 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)	2018	2017
Long-term debt ⁽¹⁾	4,276.7	4,111.0
Accounts payable and accrued liabilities	532.9	613.3
Dividends payable	16.5	16.8
Long-term compensation liability ⁽²⁾	10.0	22.9
Cash	(15.3)	(62.4)
Accounts receivable	(322.6)	(380.2)
Prepaids and deposits	(4.6)	(4.5)
Long-term investments	(8.7)	(72.6)
Excludes:
Unrealized foreign exchange on translation of hedged US dollar long-term debt	(473.6)	(219.4)
Net debt	4,011.3	4,024.9


(1)	Includes current portion of long-term debt.
(2)	Includes current portion of long-term compensation liability.

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. 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 and cash-settled share-based compensation, excluding transaction costs, foreign exchange on US dollar long-term debt and certain non-cash items. Operating netback and 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.

Payout ratio is calculated on a percentage basis as dividends declared divided by adjusted funds flow from operations. Payout ratio is used by management to monitor the dividend policy and the amount of adjusted funds flow from operations retained by the Company for capital reinvestment.

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: over $400 million of excess cash flow expected to be available in 2019; and the expected use of such funds for net debt repayment and additional share repurchases; forecasts of net debt to adjusted funds flow; expectations of improving oil price differential to approximately $8.75/bbl during first quarter 2019; expectations of an improved realized oil price for the Corporation by approximately 15 percent relative to fourth quarter 2018; the effect of the Alberta Government's production curtailment on the Company; the Company's expectation that its oil production will continue receiving a premium during periods of increased market access constraints; the Company's expectations of solutions to further enhance its realized pricing; the anticipated effects of the settlement agreement related to a National Energy Board complaint, including improved netbacks for the Company's oil production in southeast Saskatchewan; expected base decline rates in Viewfield; the timing of pay out for recent two-mile horizontal wells in Flat Lake; an increased number of two-mile horizontal wells in 2019; the Company's plans to spend less capital in Uinta in 2019; the Company's plans to convert waterflood wells to injections wells and the associated costs therewith; the timing and effectiveness of director appointments and retirements; board renewal and its benefits and timing; cash and credit capacity; oil and gas hedges; no material near-term debt maturities; the Company's plans to further improve its controllable operating costs and achieve further savings across the organization; the Company's target to further improve its balance sheet through debt reduction by way of excess cash flows and proceeds from dispositions; expectations of additional savings as the asset base is further focused; the dividend strategy and reasons for revision; the disposition process in southeast Saskatchewan; that the Company will remain disciplined and flexible throughout its divestiture processes; the Company's priorities for excess cash flow at higher commodity prices and proceeds realized form potential asset dispositions; the Company's expectations for free cash flow, including hedging gains of approximately $50 million in 2019; 2019 annual average production and capital expenditures and 2019 performance with respect to budget; the Company's plans to update shareholders as it continues to execute its transition plan and elect new independent directors as part of its board renewal process; and the Company's 2019 guidance.

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, 2018. 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, 2018, 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, 2018 under "Risk Factors" and our Management's Discussion and Analysis for the year ended December 31, 2018, 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, 2018, under the headings "Capital Expenditures", "Liquidity and Capital Resources", "Critical Accounting Estimates", "Risk Factors", "Changes in Accounting Policies" and "Outlook". 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; delays in business operations, pipeline restrictions, blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions, including changes in laws and regulations and the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; risks and uncertainties related to all oil and gas interests and operations on tribal lands; uncertainties associated with estimating oil and natural gas reserves; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; fluctuations in foreign exchange and interest rates; stock market volatility; failure to realize the anticipated benefits of acquisitions; general economic, market and business conditions; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry; and other factors, many of which are outside the control of Crescent Point. 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 or otherwise. 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.

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, 2018 escalated price forecast, the fair value for land and seismic, the fair value for the Company's oil and gas hedges based on Sproule's December 31, 2018 escalated price forecast, less outstanding net debt. The NAV per share is calculated on a fully diluted basis. 1P NAV is calculated similarly to 2P NAV but is based solely on the present value of proved reserves. Developed Producing Reserve value is calculated similarly but excludes probable and proved reserves that are not producing.

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 2018 netback (before hedging), of $35.52 per boe, a 2017 netback (before hedging) of $29.42 per boe and a three-year weighted average netback (before hedging) of $29.17 per boe.

Replacement is calculated by dividing total proved and probable reserves additions by annual average production during the same year.

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 and Drilling Data

The reserves information contained in this press release has been prepared in accordance with NI 51-101. Complete NI 51-101 reserves disclosure will be included in our Annual Information Form for the year ended December 31, 2018, which will be filed on or before March 7, 2019.

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", "replacement", "decline rate", and "drilling inventory". 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.

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.

Drilling inventory is calculated in years as the Company's 2018 year-end inventory divided by the number of wells in its 2019 drilling program. Drilling inventory is used by management to assess the amount of available drilling opportunities.

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, 2018, which will be filed on SEDAR (accessible at www.sedar.com) and EDGAR (accessible at www.sec.gov/edgar.shtml) on or before March 7, 2019.

Crescent Point is a leading North American light oil producer, driven to enhance shareholder returns by cost-effectively developing a focused asset base in a responsible and sustainable manner.

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

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

www.crescentpointenergy.com

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

SOURCE Crescent Point Energy Corp.

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