Crew Energy Announces Year End 2019 Reserves Highlighted by Strong Capital Efficiencies and Provides Operational Update

CALGARY – 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, 2019 (the “Sproule Report”).

2019 RESERVES HIGHLIGHTS

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

Crew’s 2019 capital program focused on the development of the Company’s Ultra-Condensate Rich (“UCR”)³ area emphasizing growth in high-value condensate production and reserves.  Continued efforts to control both capital expenditures and operating costs and our ongoing 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 B.C., of which 6.0 net wells were drilled in Greater Septimus, and the completion of 12.0 net wells in our UCR area at Greater Septimus.

• Proved Developed Producing Reserves Growth:  In 2019, Crew added 11.3 MMboe of PDP reserves representing approximately 19% of 2018 PDP reserves, bringing the total to 63.1 MMboe at year-end, 5% higher than 2018.  PDP FD&A² costs were $8.79 per boe resulting in a recycle ratio² of 1.4x.
• Proved Reserves Increased 17% over 2018:  Crew added 37.5 MMboe of 1P reserves, which increased 17% to 202.0 MMboe, and achieved a 1P FD&A cost of $6.16 per boe resulting in a recycle ratio of 2.0x.  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 totaled 97.3 MMboe, 1P was 50.8 MMboe, and PDP was 15.8 Mmboe.
  • Condensate⁵ reserves in the area increased over 2018 with PDP up 110% to 4.0 MMbbls; 1P up 52% to 13.7 MMbbls and 2P increased by 24% to 26.4 MMbbls.
  • In Crew’s UCR area the estimated net present value of future net revenue discounted at 10% (before tax) (“NPV₁₀ BT”) for 2P reserves assigned by Sproule to 17.5 net sections was $856.0 million⁶.
• 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% 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 below 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.

• Three Year Costs Trending Lower: With an ongoing 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 totaled $5.66 per boe and $5.02 per boe, respectively, reflecting reductions of 4% and 9% from 2018, respectively.

OPERATIONAL UPDATE

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% 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 bbls per day, a propane/butane sales rate averaging 142 bbls per day and a conventional natural gas sales rate averaging 2.37 mmcf per day over the last six hours of a 19 day production test.  During the flow period, over 50,000 bbls of sales condensate was produced and total sales liquid averaged approximately 70% of total production, with strong final flowing casing pressures averaging 1,123 psi at the end of the test.

Based on unaudited field estimates, Crew’s annual production averaged 22,837 boe per day⁸ in 2019 while fourth quarter production was at the high end of the guidance range at 22,446 boe per day⁹ as the four completed UCR wells saw first hydrocarbons sooner and rates were higher than anticipated. Annual condensate volumes averaged 2,693 bbls per day which were 6% higher than the previously announced forecast of 2,550 bbls per day.

2019 RESERVES DETAIL

The detailed reserves data set forth below is based upon the Sproule Report with an effective date of December 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 (“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, 2019 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, 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 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 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 (the “AIF”) for the year ended December 31, 2019, which will be filed on the Company’s profile at www.sedar.com on or before March 30, 2020.

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.

Corporate Reserves^(1,2,5)

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, 2019 and based on the Sproule Report and the published Sproule (December 31, 2019) future price forecast are summarized in the following table:

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 years’ 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 to the corresponding ADR measures at the end of 2018.

Price Forecast

The Sproule December 31, 2019 price forecast is summarized as follows:

Reserves Reconciliation

The following reconciliation of Crew’s gross reserves compares changes in the Company’s reserves as at December 31, 2019 based on the Sproule (December 31, 2019) future price forecast relative to the reserves as at December 31, 2018.

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 bbls/mmcf in 2018 to 36.0 bbls/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% at year end 2018 to 9.0% in 2019.  Finally, in the greater Tower area, 16 probable only locations were removed as those extended beyond the ten years of development timing guidance as prescribed within the COGE Handbook, with a lower priority of corporate commitment to the project.

Capital Program Efficiency

Future Development Capital

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