Mr. Dale Shwed reports
CREW ENERGY ANNOUNCES YEAR END 2019 RESERVES HIGHLIGHTED BY STRONG CAPITAL EFFICIENCIES AND PROVIDES OPERATIONAL UPDATE
Crew Energy Inc. has provided highlights from its independent corporate reserves evaluation prepared by Sproule Associates Ltd. with an effective date of Dec. 31, 2019.
2019 reserves highlights
Highlights of the company's proved developed producing (PDP), total proved (1P) and total proved plus probable (2P) reserves from the Sproule report are attached. All 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).
Crew's 2019 capital program focused on the development of the company's ultracondensate rich (UCR) (3) area emphasizing growth in high-value condensate production and reserves. Continued efforts to control both capital expenditures and operating costs and the company's continuing initiatives to improve efficiencies led to net capital expenditures of $95.0-million ($114.1-million gross) (1) (4). This capital program resulted in the drilling of 8.0 net extended reach horizontal (ERH) wells in British Columbia, of which 6.0 net wells were drilled in Greater Septimus, and the completion of 12.0 net wells in the company's UCR area at Greater Septimus.
Proved developed producing reserves growth: In 2019, Crew added 11.3 million barrels of oil equivalent (MMboe) of PDP reserves representing approximately 19 per cent of 2018 PDP reserves, bringing the total to 63.1 MMboe at year-end, 5 per cent higher than 2018. PDP FD&A (2) costs were $8.79 per boe resulting in a recycle ratio (2) of 1.4 times.
Proved reserves increased 17 per cent over 2018: Crew added 37.5 MMboe of 1P reserves, which increased 17 per cent to 202.0 MMboe, and achieved a 1P FD&A cost of $6.16 per boe resulting in a recycle ratio of 2.0 times. The company's PDP and 1P reserves additions were achieved in concert with lower development capital due to efficiency enhancements in part associated with increasing the number of ERH wells. Crew's 2P reserves replaced production and remained stable at 410.6 MMboe, as the company reduced 2P FDC by $107-million, reflecting improved cost-efficiencies and the removal of longer-dated reserve additions.
Continued strong performance from UCR area: Reserves assigned at Crew's UCR area of operations increased meaningfully in 2019 across all reserve categories:
2P totalled 97.3 MMboe, 1P was 50.8 MMboe and PDP was 15.8 Mmboe;
Condensate (5) reserves in the area increased over 2018 with PDP up 110 per cent to 4.0 million barrels (MMbbl); 1P up 52 per cent to 13.7 MMbbl and 2P increased by 24 per cent to 26.4 MMbbl.
In Crew's UCR area the estimated net present value of future net revenue discounted at 10 per cent (before tax) (NPV10 BT) for 2P reserves assigned by Sproule to 17.5 net sections was $856.0-million
Longer laterals improve recoveries: Significant efficiencies and improvements in recoveries have been gained with the ERH program in Crew's UCR area relative to previous shorter-reach horizontal wells, with a 35-per-cent improvement in drilling cost per lateral length realized from 2016 to 2019. The ERH program can generate equivalent recoveries and superior economic returns with a smaller environmental footprint, lower operating costs and significantly lower development costs. Crew now has 50 ERH undeveloped 2P locations assigned by Sproule in the UCR area.
Strong capital efficiencies and recycle ratios
(1) (2): Continued development success was realized at Crew's UCR area, leveraging improved completions design, longer ERH wells and reduced drill times to improve per well recoveries with reduced capital. Recycle ratios shown in the table are based on the estimated fourth quarter 2019 corporate operating netback of $12.16 per boe (1) (4) divided by the F&D or FD&A costs. For informational purposes, the estimated annual operating netback for 2019 is $14.05 per boe (1) (4).
2019 F&D AND FD&A COSTS
F&D per boe F&D recycle (7) FD&A per boe FD&A recycle (7)
PDP $10.49 1.2x $8.79 1.4x
1P $6.66 1.8x $6.16 2.0x
2P $0.86 14.1x $(1.54) (7.9x)
Three-year costs trending lower: With a continuing focus on reduced capital costs and capturing drilling and completions efficiencies, Crew achieved another consecutive year of declining average three year 2P F&D and FD&A costs in 2019 which totalled $5.66 per boe and $5.02 per boe, respectively, reflecting reductions of 4 per cent and 9 per cent from 2018, respectively.
Results from Crew's 3-32 UCR pad at West Septimus have demonstrated continued improvement in operating efficiencies. In the fourth quarter of 2019, the company completed four UCR wells that came in under budget and averaged greater than 3,000 metres in length, which are the longest in the company's history. On this pad, which incorporated recent completion design improvements, completion costs averaged approximately $3.8-million, or $1,278 per lateral metre, which is 26 per cent lower than Crew's previous pacesetter pad.
The four wells on the 3-32 pad flowed back at restricted rates, with per-well condensate sales volumes averaging 758 bbl per day, a propane/butane sales rate averaging 142 bbl per day and a conventional natural gas sales rate averaging 2.37 million cubic feet per day over the last six hours of a 19-day production test. During the flow period, over 50,000 bbl of sales condensate were produced and total sales liquid averaged approximately 70 per cent of total production, with strong final flowing casing pressures averaging 1,123 pounds per square inch at the end of the test.
Based on unaudited field estimates, Crew's annual production averaged 22,837 boe per day (8) in 2019 while fourth quarter production was at the high end of the guidance range at 22,446 boe per day (9) as the four completed UCR wells saw first hydrocarbons sooner and rates were higher than anticipated. Annual condensate volumes averaged 2,693 bbl per day which were 6 per cent higher than the previously announced forecast of 2,550 bbl per day.
(1) All 2019 financial amounts are unaudited.
(2) Finding, development and acquisitions costs or FD&A costs, finding and development costs or F&D costs and recycle ratio do not have standardized meanings.
(3) Ultracondensate rich or UCR is not defined in National Instrument 51-101 and means a fairway of land at Crew's Greater Septimus area of operations where productive zones have high condensate rates (initial 30-day condensate/gas ratio rates of greater than 75 barrels per mmcf).
(4) Non-IFRS (international financial reporting standards) measure.
(5) Condensate is defined as a mixture of pentanes and heavier hydrocarbons recovered as a liquid at the inlet of a gas processing plant before the gas is processed and pentanes and heavier hydrocarbons obtained from the processing of raw natural gas.
(6) Excludes field-level facility and maintenance operating expenses.
(7) Crew's estimated operating netback in fourth quarter 2019, used in the attached calculations, averaged $12.16 per boe (unaudited), while the company's estimated full-year 2019 operating netback averaged $14.05 per boe (unaudited).
(8) Seventy-one per cent conventional natural gas, 12 per cent condensate, 9 per cent natural gas liquids (NGLs), 7 per cent heavy oil and 1 per cent light oil.
(9) Seventy-two per cent conventional natural gas, 11 per cent condensate, 9 per cent NGLs, 7 per cent heavy oil and 1 per cent light oil.
2019 reserves detail
The detailed reserves data as attached are based upon the Sproule report with an effective date of Dec. 31, 2019. The following presentation summarizes the company's crude oil, natural gas liquids and conventional 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 and National Instrument 51-101 -- Standards of Disclosure for Oil and Gas Activities. The reserves evaluation was based on Sproule forecast escalated pricing and foreign exchange rates at Dec. 31, 2019, as outlined in the "Price forecast" table.
All evaluations and summaries of future net revenue are stated prior to provision for interest, debt service charges and general administrative expenses, the input of hedging activities, and after deduction of royalties, operating costs, estimated well abandonment, decommissioning and reclamation costs associated with the company's assets in the reserve report 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 attached tables 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 the company's crude oil, natural gas liquids and conventional natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, conventional 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 as prescribed by NI 51-101 will be included in the company's annual information form for the year ended Dec. 31, 2019, which will be filed on the company's profile at
SEDAR on or before March 30, 2020.
CORPORATE RESERVES (1) (2) (5)
Light crude oil Barrels of
and medium Heavy crude Natural gas Conventional oil
crude oil oil liquids natural gas (3) equivalent (4)
(mbbl) (mbbl) (mbbl) (mmcf) (mboe)
Developed producing 315 1,070 13,141 291,587 63,122
Developed non-producing 0 856 195 5,098 1,901
Undeveloped 3,198 2,068 27,784 623,453 136,958
Total proved 3,512 3,994 41,120 920,138 201,982
Total probable 3,794 3,574 43,310 947,488 208,592
Total proved plus probable 7,306 7,568 84,430 1,867,626 410,574
(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
(2) Based on Sproule's Dec. 31, 2019, escalated price forecast.
(3) Reflects 100 per cent conventional natural gas by product type.
(4) Oil equivalent amounts have been calculated using a conversion rate of 6,000 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 Dec. 31, 2019, and based on the Sproule report and the published Sproule (Dec. 31, 2019) future price forecast are summarized in the "Reserves values" table.
RESERVES VALUES (1) (2) (3) (4)
(m$) 0% 5% 10% 15% 20%
Developed producing 704,938 543,075 438,722 370,013 322,240
Developed non-producing 27,826 23,323 20,130 17,755 15,903
Undeveloped 1,983,005 1,081,723 653,409 423,237 286,736
Total proved 2,715,768 1,648,121 1,112,261 811,005 624,879
Total probable 4,343,823 1,829,803 956,345 579,980 390,500
Total proved plus probable 7,059,591 3,477,924 2,068,605 1,390,985 1,015,379
(1) Based on Sproule's Dec. 31, 2019, 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, ADR associated with the company's
assets 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 2019 AIF to be filed on or before March 30, 2020.
(4) Columns may not add due to rounding.
Commencing in 2019, Sproule included additional abandonment and reclamation obligations (ARO) in the company's reserves evaluation, which resulted in a decrease in value relative to 2018. This significant change to the prior-year practices, which were consistent with the reporting of many other companies in the industry, was made based on new guidelines contained within the COGE handbook, which recommends adopting the best practice of including abandonment, decommissioning and reclamation (ADR) costs associated with all of the company's assets evaluated in the Sproule report. This includes costs for both active and inactive wells, including ADR costs for producing wells, suspended wells, service wells, gathering systems, facilities and surface land development for all the company's assets. At year-end 2019, Sproule's evaluation of Crew's NPV10 BT for ADR related to Crew's 2P, 1P and PDP reserves was $42.5-million, $42.7-million and $40.8-million, respectively, an increase of $35.3-million, $35.8-million and $36.2-million compared with the corresponding ADR measures at the end of 2018.
The Sproule Dec. 31, 2019, price forecast is summarized as displayed in the "Price forecast" table.
Canadian Western Henry Hub
Exchange rate WTI at Cushing light sweet Canada select natural gas AECO-C spot
Year ($US/$Cdn) (US$/bbl) (C$/bbl) (C$/bbl) (US$/mmbtu) (C$/mmbtu)
2020 0.760 61.00 73.84 59.81 2.80 2.04
2021 0.770 65.00 78.51 63.98 3.00 2.27
2022 0.800 67.00 78.73 63.77 3.25 2.81
2023 0.800 68.34 80.30 65.04 3.32 2.89
2024 0.800 69.71 81.91 66.34 3.38 2.98
2025 0.800 71.10 83.54 67.67 3.45 3.06
2026 0.800 72.52 85.21 69.02 3.52 3.15
2027 0.800 73.97 86.92 70.40 3.59 3.24
2028 0.800 75.45 88.66 71.81 3.66 3.33
2029 0.800 76.96 90.43 73.25 3.73 3.42
2030 0.800 78.50 92.24 74.71 3.81 3.51
2031 +(1) 2.0%/yr 2.0%/yr 2.0%/yr 2.0%/yr 2.0%/yr
(1) Escalated at 2.0 per cent per year starting in 2030 with the exception of foreign exchange which
The "Reserves reconciliation" table of Crew's gross reserves compares changes in the company's reserves as at Dec. 31, 2019, based on the Sproule (Dec. 31, 2019) future price forecast relative to the reserves as at Dec. 31, 2018.
Total proved Total probable Total proved + probable
Factors Mboe Mboe Mboe
Dec. 31, 2018 172,840 238,127 410,967
Extensions and improved recovery (1) 9,542 17,626 27,168
Infill drilling 65 43 108
Technical revisions 30,114 (48,168) (18,054)
Discoveries 0 0 0
Acquisitions 0 0 0
Dispositions (49) (23) (72)
Economic factors (2,195) 987 (1,208)
Production (8,336) 0 (8,336)
Dec. 31, 2019 201,982 208,593 410,574
(1) Increases to extensions and improved recovery are the result of stepout 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.
(3) Reconciliation by product type in accordance with NI 51-101 will be contained in Crew's AIF
to be filed on or before March 30, 2020.
Technical revisions in the 1P category for year-end 2019 were predominantly the result of undeveloped locations moving from the total probable category into the total proved category. Several factors contributed to technical revisions on 2P reserves at year-end 2019, including a minor reduction in NGL yield at Septimus and West Septimus, which declined from 38.5 bbl/mmcf in 2018 to 36.0 bbl/mmcf in 2019. Due to the increase in UCR wells in 2019, Crew realized changes to gas shrinkage rates at Septimus and West Septimus, which increased from 7.5 per cent at year-end 2018 to 9.0 per cent in 2019. Finally, in the greater Tower area, 16 probable-only locations were removed as those extended beyond the 10 years of development timing guidance as prescribed within the COGE handbook, with a lower priority of corporate commitment to the project.
CAPITAL PROGRAM EFFICIENCY
2019 2018 2017-2019
1P 2P 1P 2P 1P 2P
Exploration and development
expenditures (1) (6) ($ thousands) 114,094 114,094 103,219 103,219 455,615 455,615
Acquisitions/(dispositions) (1) (6) ($ thousands) (19,085) (19,085) (9,805) (9,805) (76,796) (76,796)
Change in future development capital (1) ($ thousands)
Exploration and development 135,712 (107,199) (19,952) 130,237 125,274 205,907
Acquisitions/dispositions (10) (10) (40) (40) (7,925) (21,850)
Reserves additions with revisions and economic
Exploration and development 37,526 8,015 12,200 49,506 75,596 74,244
Acquisitions/dispositions (49) (72) (18) (28) (1,352) (4,788)
37,476 7,943 12,182 49,478 74,244 112,102
2019 2018 2017-2019
1P 2P 1P 2P 1P 2P
Finding and development costs (2) (5) ($ per boe)
With revisions and economic factors 6.66 0.86 6.82 4.72 7.68 5.66
Finding, development and acquisition costs (2) (5)
($ per boe)
With revisions and economic factors 6.16 (1.54) 6.03 4.52 6.68 5.02
Recycle ratio (3) (5) (F&D) 1.8 14.1 2.3 3.4
Reserves replacement (4) (5) 450% 95% 140% 568%
(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 a non-IFRS measure and is calculated as revenue (including realized hedging
gains and losses) minus royalties, operating expenses and transportation expenses. Crew's
estimated operating netback in fourth quarter 2019, used in the above calculations, averaged
$12.16 per boe (unaudited), while the company's full-year 2019 estimated operating netback
averaged $14.05 per boe (unaudited). These amounts are estimates and subject to audit verification.
(4) Reserves replacement ratio is calculated as total reserve additions (including acquisitions net of
dispositions) divided by annual production. Based on field estimates, Crew's 2019 annual
production averaged 22,837 boe per day.
(5) Reserves replacement, FD&A cost, F&D cost and recycle ratio do not have standardized meanings and
therefore may not be comparable with the calculation of similar measures for other entities.
(6) All 2019 financial amounts are unaudited.
Future development capital
The "Future development capital" table provides a summary of the estimated FDC required to bring Crew's reserves on production.
Total Total proved
Future development capital ($ millions) (1) proved plus probable
2020 76 80
2021 139 150
2022 191 221
2023 164 187
2024 83 88
Remainder 192 1,061
Total FDC undiscounted 844 1,787
Total FDC discounted at 10% 618 998
(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 Dec. 31, 2019.
(2) Columns may not add due to rounding.
Crew Energy is a dynamic, growth-oriented exploration and production company, focused on increasing long-term production, reserves and cash flow per share through the development of the company's world-class Montney resource. Crew is based in Calgary, Alta., and its shares are traded on the Toronto Stock Exchange under the trading symbol CR.
We seek Safe Harbor.
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