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Crew Energy Announces Year End 2018 Reserves


CALGARYFeb. 7, 2019 /CNW/ – Crew Energy Inc. (TSX: CR) of Calgary, Alberta (“Crew” or the “Company”) is pleased to provide highlights from our independent corporate reserves evaluation prepared by Sproule Associates Ltd. (“Sproule”) with an effective date of December 31, 2018 (the “Sproule Report”).

2018 RESERVES HIGHLIGHTS

With net capital expenditures of $93 million ($103.2 million gross)1, Crew successfully expanded reserves through the drilling of ten (10.0 net) and completion of 14 (12.2 net) wells in the Montney at West Septimus, of which three (3.0 net) extended reach horizontal (“ERH”) wells were drilled in the Ultra-Condensate Rich (“UCR”) area.  In addition, four (4.0 net) multi-lateral horizontal wells were drilled at Lloydminster.

Highlights of the proved developed producing (“PDP”), total proved (“1P”) and total proved plus probable (“2P”) reserves from the Sproule Report are provided below.  Finding, development and acquisition (“FD&A”)1,2 costs and finding and development (“F&D”)1,2 costs include changes in future development capital (“FDC”)2.

  • Improving Capital Efficiencies and Robust Recycle Ratios1,2: Crew’s 2P F&D and FD&A cost per boe has improved over prior years and reflects the success of the Company’s UCR drilling program which features enhanced completions design, longer lateral lengths and reduced drill times compared to previous wells. Recycle ratios are based on the estimated corporate operating netback divided by the F&D costs or the FD&A costs.

F&D per boe

F&D recycle

FD&A per boe

FD&A recycle

PDP

$11.62

1.4x

$10.52

1.5x

1P

$6.82

2.3x

$6.03

2.6x

2P

$4.72

3.4x

$4.52

3.5x

  • Continued Development Success at West Septimus:  PDP reserves at West Septimus increased 10% over 2017, with 1P and 2P reserves up 3% and 2%, respectively, primarily due to the focus on drilling in the UCR area which generates higher returns and stronger economics in the current commodity price environment.
  • Condensate Growth a Focus at West Septimus:  Within the UCR area at West Septimus, shifting to ERH wells led to a 28% increase in 1P reserves to 30,170 mboe, while 2P reserves increased 17% to 71,681 mboe. Condensate increased by 30% on 1P reserves and represents 30% of UCR 2P reserves3. Corporate 2P condensate reserves totaled 50,053 mbbl.
  • Meaningful Reserves Value in UCR Area:  Within Crew’s UCR area, the net present value of future net revenue discounted at 10% (before tax) (“NPV10 BT”) for 2P was $774.1 million4 assigned to 14 of 32 net prospective sections at West SeptimusCorporately, the Company’s NPV10 BT totaled $507.9 million on PDP reserves, $1.2 billion on 1P reserves and $2.5 billion on 2P reserves.

______________________________

1

All 2018 financial amounts are unaudited. See advisories.

2

“Finding, Development and Acquisitions costs” or “FD&A costs”, “Finding and Development costs” or “F&D costs”, “recycle ratio” and “operating netback” do not have standardized meanings. See the table “Capital Program Efficiency” and “Information Regarding Disclosure on Oil and Gas Reserves and Operational Information” contained in this news release.

3

Condensate reserves referenced herein include wellhead plus plant recovery.

4

Excludes field-level facility and maintenance operating expenses. 

  • ERH Wells Improve Capital Efficiencies:  Crew brought three new ERH wells onto production in late 2018 within our UCR area and has an additional six (6.0 net) wells to bring on in the first quarter of 2019. The Company now has 38 ERH undeveloped 2P locations assigned by Sproule in the UCR area. The ERH program will require fewer wells to develop the resource, resulting in a smaller overall surface footprint providing superior economic returns relative to the previously drilled shorter-reach horizontal wells.
  • Average 3-Year F&D Trending in the Right Direction: With an ongoing focus on lowering capital costs while improving drilling and completions efficiencies, Crew achieved another consecutive year of declining average three year 2P F&D costs in 2018.

3 Year Average F&D Has Trended Down (CNW Group/Crew Energy Inc.)

  • Continued Corporate Reserves Growth with Conservative Capital Program:  Approximately $67 million of our $103.2 million exploration and development capital program was directed to drilling and completions activities in 2018.  This generated increases across all reserves categories, including approximately 0.3% growth in PDP reserves, 2% in 1P reserves and 11% in 2P reserves compared to 2017, with Crew’s reserves replacement ratios5 on PDP, 1P and 2P totaling 102%, 140% and 568%, respectively.
  • Multilateral Development Increased Heavy Oil Inventory: Recent success drilling multilateral horizontal wells resulted in additions to overall heavy oil reserves in 2018.  Heavy oil multilaterals now represent 32% and 31% of Crew’s total 1P and 2P heavy oil reserves, respectively.

2018 RESERVES DETAIL

The detailed reserves data set forth below is based upon an independent reserves assessment and evaluation prepared by Sproule with an effective date of December 31, 2018.  The following presentation summarizes the Company’s crude oil, natural gas liquids and natural gas reserves and the net present values before income tax of future net revenue for the Company’s reserves using forecast prices and costs based on the Sproule Report.  The Sproule Report has been prepared in accordance with definitions, standards, and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI-51-101”). The reserves evaluation was based on Sproule forecast escalated pricing and foreign exchange rates at December 31, 2018 as outlined in the table herein entitled “Price Forecast”.

All evaluations and summaries of future net revenue are stated prior to provision for interest, debt service charges and general administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs for entities with reserves assigned and estimated future capital expenditures associated with reserves.  It should not be assumed that the estimates of net present value of future net revenues presented in the tables below represent the fair market value of the reserves.  There is no assurance that the forecast prices and cost assumptions will be attained and variances could be material.  The recovery and reserve estimates of our crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.  Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.  Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without including any royalty interests) unless noted otherwise.  In addition to the detailed information disclosed in this news release, more detailed information will be included in the Company’s Annual Information Form (the “AIF”) for the year ended December 31, 2018, which will be filed on the Company’s profile at www.sedar.com on or before March 29, 2019.

_________________________________

5 “Reserves replacement” and “reserves replacement ratio” do not have standardized meanings. See the table “Capital Program Efficiency” and “Information Regarding Disclosure on Oil and Gas Reserves and Operational Information” contained in this news release.

See “Information Regarding Disclosure on Oil and Gas Reserves and Operational Information” for additional cautionary language, explanations and discussions and “Forward Looking Information and Statements” for a statement of principal assumptions and risks that may apply.

The preparation and audit of Crew’s 2018 annual consolidated financial statements is not yet complete, and accordingly all financial amounts referred to in this news release are unaudited and represent management’s estimates.  Readers are advised that these financial estimates may be subject to change.

Corporate Reserves(1,2,5)

Light Crude Oil

and Medium

Crude Oil

Heavy Crude

Oil

Natural Gas
Liquids

Conventional

Natural Gas(3)

Barrels of
oil

equivalent(4)

(mbbl)

(mbbl)

 (mbbl)

 (mmcf)

 (mboe)

Proved

Developed Producing

411

1,414

11,456

281,509

60,199

Developed Non-producing

22

1,198

118

5,079

2,184

Undeveloped

1,379

2,119

24,122

497,023

110,457

Total Proved

1,811

4,731

35,696

783,611

172,840

Total Probable

9,089

3,941

45,342

1,078,529

238,127

Total Proved plus Probable

10,900

8,672

81,038

1,862,140

410,967

Notes:

(1)

Reserves have been presented on a “gross” basis which is defined as Crew’s working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of the Company.

(2)

Based on Sproule’s December 31, 2018 escalated price forecast.

(3)

Reflects 100% Conventional Natural Gas by product type.

(4)

Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.

(5)

Columns may not add due to rounding.

Reserves Values(1)(2)(3)(4)  

The estimated before tax net present value (“NPV”) of future net revenues associated with Crew’s reserves effective December 31, 2018 and based on the Sproule Report and the published Sproule (December 31, 2018) future price forecast are summarized in the following table:

(m$)

0%

5%

10%

15%

20%

Proved

Developed Producing

836,054

636,129

507,945

423,426

364,631

Developed Non-producing

35,548

29,715

25,415

22,137

19,559

Undeveloped

1,905,289

1,052,586

646,886

428,435

298,470

Total Proved

2,776,892

1,718,430

1,180,246

873,998

682,660

Total Probable

4,951,916

2,276,352

1,277,008

812,555

562,075

Total Proved plus Probable

7,728,808

3,994,783

2,457,254

1,686,553

1,244,736

Notes:

(1)

Based on Sproule’s December 31, 2018 escalated price forecast.

(2)

The estimated future net revenues are stated prior to provision for interest, debt service charges, general administrative expenses, the impact of hedging activities, and after deduction of royalties, operating costs, certain estimated well abandonment and reclamation costs and estimated future capital expenditures.

(3)

The after-tax present values of future net revenue attributed to Crew’s reserves will be included in the Company’s 2018 AIF to be filed on or before
March 29, 2019.

(4)

Columns may not add due to rounding.

Price Forecast

The Sproule December 31, 2018 price forecast is summarized as follows:

 Year

Exchange
Rate

WTI @
Cushing

Canadian
Light Sweet

Western

Canada Select

Natural gas

AECO-C spot

Westcoast

Station 2

($US/$Cdn)

(US$/bbl)

(C$/bbl)

(C$/bbl)

(C$/mmbtu)

(C$/mmbtu)

2019

0.770

63.00

75.27

59.47

1.95

1.35

2020

0.800

67.00

77.89

62.31

2.44

1.94

2021

0.800

70.00

82.25

67.45

3.00

2.60

2022

0.800

71.40

84.79

69.53

3.21

2.81

2023

0.800

72.83

87.39

71.66

3.30

2.90

2024

0.800

74.28

89.14

73.10

3.39

2.99

2025

0.800

75.77

90.92

74.56

3.49

3.09

2026

0.800

77.29

92.74

76.05

3.58

3.18

2027

0.800

78.83

94.60

77.57

3.68

3.28

2028

0.800

80.41

96.49

79.12

3.78

3.38

2029

0.800

82.02

98.42

80.70

3.88

3.48

2030 +(1)

2.0%/yr

2.0%/yr

2.0%/yr

2.0%/yr

2.0%/yr

Note:

(1)

Escalated at 2.0% per year starting in 2030 with the exception of foreign exchange which remains flat.

Reserves Reconciliation

The following reconciliation of Crew’s gross reserves compares changes in the Company’s reserves as at December 31, 2018 based on the Sproule (December 31, 2018) future price forecast relative to the reserves as at December 31, 2017.

TOTAL PROVED

Light &

Medium Crude

Oil (mbbl)

Heavy
Crude Oil

 (mbbl)

Natural Gas

Liquids
(mbbl)

Conventional

Natural Gas

(mmcf)

Oil Equivalent

(mboe)

Opening Balance

1,809

4,382

31,403

790,685

169,376

Extensions & Improved Recovery(1)

0

866

1,959

19,606

6,093

Infill Drilling

0

16

0

0

16

Technical Revisions

110

119

4,251

22,677

8,259

Discoveries

0

0

0

0

0

Acquisitions

0

0

0

0

0

Dispositions

0

(18)

0

0

(18)

Economic Factors

(7)

17

(406)

(10,624)

(2,167)

Production

(101)

(651)

(1,512)

(38,732)

(8,718)

Closing Balance

1,811

4,731

35,696

783,612

172,840

TOTAL PROVED PLUS

PROBABLE

Light &

Medium Crude

Oil (mbbl)

Heavy
Crude Oil

 (mbbl)

Natural Gas

Liquids
(mbbl)

Conventional

Natural Gas

(mmcf)

Oil Equivalent

(mboe)

Opening Balance

12,527

8,339

68,879

1,682,775

370,208

Extensions & Improved Recovery(1)

0

1,776

6,137

105,585

25,511

Infill Drilling

0

15

682

17,944

3,688

Technical Revisions

(1,510)

(800)

6,986

100,560

21,436

Discoveries

0

0

0

0

0

Acquisitions

0

0

0

0

0

Dispositions

0

(28)

0

0

(28)

Economic Factors

(16)

20

(134)

(5,991)

(1,129)

Production

(101)

(651)

(1,512)

(38,732)

(8,718)

Closing Balance

10,900

8,672

81,038

1,862,141

410,967

Notes:

(1)

Increases to Extensions and Improved Recovery are the result of step-out locations drilled by Crew. Reserves additions for improved recovery and extensions are combined and reported as “Extensions and Improved Recovery”.

(2)

Columns may not add due to rounding.

Capital Program Efficiency

2018

2017

3 Year Average
2018-2016

1P

2P

1P

2P

1P

2P

Exploration and Development Expenditures(1)(6)

($ thousands)

103,219

103,219

238,302

238,302

449,723

449,723

Acquisitions/(Dispositions)(1)(6)
($ thousands)

(9,805)

(9,805)

(47,906)

(47,906)

(53,737)

(53,737)

Change in Future Development Capital(1)

($ thousands)

– Exploration and Development

(19,952)

130,237

9,514

182,870

126,749

600,090

– Acquisitions/Dispositions

(40)

(40)

(7,875)

(21,800)

(7,915)

(21,840)

Reserves Additions with Revisions and Economic

Factors (mboe)

– Exploration and Development

12,201

49,505

25,870

59,370

77,023

178,865

– Acquisitions/Dispositions

(18)

(28)

(1,284)

(4,688)

42

(3,031)

12,183

49,478

24,585

54,681

77,065

175,834

Finding & Development Costs(2)(5)
($ per boe)

– with revisions and economic factors

6.82

4.72

9.58

7.09

7.48

5.87

Finding, Development & Acquisition Costs(2)(5) 

($ per boe)

– with revisions and economic factors

6.03

4.52

7.81

6.43

6.68

5.54

Recycle Ratio(3)(5) (F&D)

2.3

3.4

1.9

2.5

Reserves Replacement(4)(5)

140%

568%

292%

650%

Notes:

(1)

The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development capital generally will not reflect total finding and development costs related to reserve additions for that year.

(2)

The calculation of F&D and FD&A costs incorporates the change in FDC required to bring proved undeveloped and developed reserves into production.  In all cases, the F&D or FD&A number is calculated by dividing the identified capital expenditures by the applicable reserves additions after changes in FDC costs.

(3)

Recycle ratio is defined as operating netback per boe divided by F&D costs on a per boe basis.  Operating netback is calculated as revenue (including realized hedging gains and losses) minus royalties, operating expenses, and transportation expenses.  Crew’s operating netback in fourth quarter 2018, used in the above calculations, averaged $15.83 per boe (unaudited). 

(4)

Reserves replacement ratio is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production. Crew’s 2018 annual production averaged 23,885 boe per day.

(5)

“Reserves Replacement”, “FD&A Cost”, “F&D Cost”, and “Recycle Ratio” do not have standardized meanings.  See “Information Regarding Disclosure on Oil and Gas Reserves and Operational Information” in this news release.

(6)

All 2018 financial amounts are unaudited. See advisories.

Future Development Capital

The following table provides a summary of the estimated FDC required to bring Crew’s reserves on production.

Total

Total Proved

Future Development Capital ($millions)(1)

Proved

plus Probable

2019

34

102

2020

120

207

2021

137

257

2022

206

282

2023

95

184

Remainder

117

863

Total FDC undiscounted

710

1,894

Total FDC discounted at 10%

520

1,190

Notes:

(1)

Reflects development costs deducted by Sproule in the Sproule Report in the estimation of future net revenue attributed to the noted reserve categories using Sproule’s forecast pricing and foreign exchange rates at December 31, 2018.   

(2)

Columns may not add due to rounding



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