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Crescent Point Announces 2018 Results and Reserves


CALGARYMarch 7, 2019 /PRNewswire/ – 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 $3.16per 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 $23.64per 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.



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