CALGARY, AB – Crew Energy Inc. (TSX: CR) (“Crew” or the “Company”) today announced our operating and financial results for the three and twelve month periods ended December 31, 2020. Crew’s full audited consolidated Financial Statements, as well as Management’s Discussion and Analysis (“MD&A”) for the three and 12-month periods ended December 31, 2020 are available on Crew’s website and filed on SEDAR at www.sedar.com.
While 2020 proved to be one of the most challenging years in recent memory for commodities and energy companies due to the economic fallout caused by the COVID-19 pandemic, Crew remained focused on the Company’s long-term sustainability. In December, we announced a strategic asset development plan for 2021 and 2022 designed to increase the pace of development of our world-class Montney resource, capturing value from stronger commodity pricing while optimizing production and infrastructure utilization, enhancing margins and ultimately improving leverage metrics. As a result, we anticipate generating meaningful Free Adjusted Funds Flow1 targeting a range of $35 to $65 million2 in 2022, depending on commodity prices.
2020 OPERATING & FINANCIAL HIGHLIGHTS
- 21,955 boe per day3 (131.7 mmcfe per day) average annual production in 2020, 4% lower than 2019 on 24% less capital invested, reflecting the quality of Crew’s asset base and low base decline rate. Q4/20 production averaged 21,666 boe per day3, 7% higher than Q3/20.
- $41.2 million of Adjusted Funds Flow (AFF”)1 ($0.27 per fully diluted share) in 2020, with $15.6 million ($0.10 per fully diluted share) generated in Q4/20, 82% higher than Q3/20 due to stronger commodity pricing and lower operating costs.
- 8% lower net operating costs1 in Q4/20 over Q3/20, averaging $5.30 per boe, while 2020 net operating costs of $5.61 were 5% lower than 2019. General and administrative (“G&A”) costs declined 28% to $1.01 per boe in 2020.
- $28.1 million ($86.3 million gross) net capital expenditures1 in 2020, 48% of which was invested during Q4/20, marking the start of Crew’s two-year asset development plan.
- 15.0 net wells were drilled in 2020, including 12.0 net natural gas wells, 2.0 net heavy oil wells and 1.0 net disposal well, while 10.0 net wells were completed (including 7.0 net natural gas wells) at Crew’s Septimus and West Septimus areas (“Greater Septimus”), primarily in Q4/20. In Q1/21, Crew drilled and cased the longest well in our history, drilled to a total depth of over 20,000 feet in under 11 days at West Septimus.
- 7.0 net wells were drilled, completed, equipped and tied-in on our 9-5 pad at Greater Septimus in 2020, with per well costs 12% lower than originally budgeted, averaging an estimated $5 million.
- Continued positive performance from the 9-5, seven well pad, with average IP60 production sales rates per well of 1,500 boe per day (21% condensate and ngl’s) with flowing metrics of approximately $3,300 per boe4.
- Over 50% of forecast 2021 natural gas production is hedged at an average price of $3.08 per mcf, reflecting the success of our marketing activities in 2020.
- Record low Proved Developed Producing (“PDP”) F&D costs5 of $6.83 per boe and FD&A costs5 of $2.00 per boe in 2020, resulting in recycle ratios5 of 1.8x and 6.1x, respectively.
- 12.0 MMboe of PDP reserves added in 2020, prior to accounting for production, bringing the total to 67.1 MMboe at year-end, a 6% increase over 2019.
- $357.2 million of year-end net debt6, with no near-term maturities or repayment requirements on the $300 million of senior notes termed out until 2024, and 24% drawn on our $150 million credit facility which was reconfirmed until June 2021.
1 Non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented for other entities. See “Advisories – Non-IFRS Measures”. |
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2 See table in the Advisories for key budget and underlying material assumptions related to the two-year development plan and associated guidance. |
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3 See table in the Advisories for production breakdown by product type as defined in NI 51-101. |
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4 Amounts exclude a short cleanup period after 20% of load fracturing fluid is recovered. Volumes include 7.1 mmcfd of sales gas, 176 bbl/d of condensate and 140 bbl/d of ngls. See “Advisories – Test Results and Initial Production (“IP”) Rates”. |
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5 “Finding, Development and Acquisitions costs” or “FD&A costs”, “Finding and Development costs” or “F&D costs” and “recycle ratio” do not have standardized meanings and therefore may not be comparable to similar measures presented for other entities. See “Advisories – Information Regarding Disclosure on Oil and Gas Reserves and Operational Information”. |
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6 Non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented for other entities. See “Advisories – Non-IFRS Measures”. |
FINANCIAL & OPERATING HIGHLIGHTS
FINANCIAL ($ thousands, except per share amounts) |
Three months |
Three months |
Year ended |
Year ended |
Petroleum and natural gas sales |
42,604 |
44,941 |
137,931 |
193,532 |
Adjusted funds flow (1) |
15,568 |
16,086 |
41,150 |
81,034 |
Per share – basic |
0.10 |
0.11 |
0.27 |
0.53 |
– diluted |
0.10 |
0.11 |
0.27 |
0.53 |
Net income / (loss) |
34,668 |
(6,235) |
(203,180) |
12,071 |
Per share – basic |
0.23 |
(0.04) |
(1.34) |
0.08 |
– diluted |
0.22 |
(0.04) |
(1.34) |
0.08 |
Exploration and development expenditures |
41,007 |
26,390 |
86,260 |
114,094 |
Property acquisitions (net of dispositions) |
(23,219) |
82 |
(58,150) |
(19,084) |
Net capital expenditures |
17,788 |
26,472 |
28,110 |
95,010 |
Capital structure ($ thousands) |
As at |
As at |
Working capital deficiency (surplus) (1) |
24,361 |
(149) |
Bank loan |
35,994 |
52,136 |
60,355 |
51,987 |
|
Senior Unsecured Notes |
296,851 |
295,868 |
Total net debt (1) |
357,206 |
347,855 |
Common shares outstanding (thousands) |
151,182 |
151,534 |
Notes: |
|
(1) |
Non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented for other entities. See “Advisories – Non-IFRS Measures”. |
Operations |
Three months |
Three months |
Year ended |
Year ended |
Daily production |
||||
Light crude oil (bbl/d)(1) |
182 |
251 |
187 |
216 |
Heavy crude oil (bbl/d) |
1,281 |
1,600 |
1,362 |
1,639 |
Natural gas liquids (“ngl”)(2) (bbl/d) |
1,953 |
2,011 |
2,070 |
2,056 |
Condensate (bbl/d) |
2,121 |
2,455 |
2,583 |
2,693 |
Natural gas (mcf/d) |
96,771 |
96,776 |
94,519 |
97,398 |
Total (boe/d @ 6:1) |
21,666 |
22,446 |
21,955 |
22,837 |
Average prices (3) |
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Light crude oil ($/bbl) |
47.38 |
62.85 |
39.97 |
63.24 |
Heavy crude oil ($/bbl) |
38.79 |
44.76 |
28.86 |
50.65 |
Natural gas liquids ($/bbl) |
13.20 |
8.66 |
9.01 |
6.78 |
Condensate ($/bbl) |
47.68 |
63.29 |
42.99 |
64.40 |
Natural gas ($/mcf) |
2.87 |
2.36 |
2.12 |
2.53 |
Oil equivalent ($/boe) |
21.37 |
21.76 |
17.17 |
23.22 |
Notes: |
|
(1) |
The Company does not have any medium crude oil as defined by NI 51-101. |
(2) |
Throughout this news release, natural gas liquids (“ngl”) comprise all natural gas liquids as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), other than condensate, which is disclosed separately, and natural gas means conventional natural gas by NI 51-101 product type. |
(3) |
Average prices are before deduction of transportation costs and do not include realized gains and losses on derivative financial instruments. |
Three months |
Three months |
Year ended |
Year ended |
|
Netback ($/boe) |
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Petroleum and natural gas sales |
21.37 |
21.76 |
17.17 |
23.22 |
Royalties |
(0.99) |
(1.97) |
(0.81) |
(1.77) |
Realized commodity hedging gain |
1.27 |
0.78 |
2.06 |
0.28 |
Marketing (loss) income(1) |
(0.04) |
(0.02) |
(0.11) |
0.99 |
Net operating costs(2)(3) |
(5.30) |
(5.51) |
(5.61) |
(5.93) |
Transportation costs |
(4.23) |
(2.88) |
(3.67) |
(2.74) |
Operating netback(3) |
12.08 |
12.16 |
9.03 |
14.05 |
G&A |
(1.30) |
(1.33) |
(1.01) |
(1.40) |
Financing costs on long-term debt |
(2.97) |
(3.06) |
(2.90) |
(2.94) |
Adjusted funds flow(3) |
7.81 |
7.77 |
5.12 |
9.71 |
Drilling activity |
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Gross wells |
15 |
8 |
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Working interest wells |
15 |
8 |
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Success rate, net wells (%) |
100% |
100% |
Notes: |
|
(1) |
Marketing income was recognized from the monetization of forward natural gas sales contracts offset by the cost of committed natural gas transportation that was not available during the period. |
(2) |
Net operating costs are calculated as gross operating costs less processing revenue. |
(3) |
Non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented for other entities. See “Advisories – Non-IFRS Measures”. |
SUSTAINABILITY AND ESG INITIATIVES
Underpinning Crew’s long-term strategy is our unwavering commitment to safely and responsibly operating in the communities in which we work, while focussing on our environmental, social and governance (“ESG”) initiatives. The Company expects the release of our inaugural ESG report to stakeholders by mid-2021, meanwhile, we continue to advance our sustainability goals:
- In the summer of 2021, Crew plans to install a waste heat recovery system at our West Septimus facility, which is expected to reduce emissions and increase condensate stabilization capacity. The system is expected to reduce total greenhouse gas emissions from the facility by approximately 10-15% and increase condensate stabilization capacity by 20% to around 5,000 bbls per day. Crew gratefully acknowledges assistance from the Province of British Columbia for their support of this project.
- Crew is the first Canadian energy producer to receive regulatory approval from the B.C. Oil and Gas Commission for the installation and operation of a next-generation, spoolable surface pipeline for produced water transfer, confirming Crew’s commitment to improving efficiencies and reducing emissions. The pipeline allows for the safe and environmentally responsible transportation of produced water, dramatically reducing the trucking of water in Crew’s area of operations while significantly reducing emissions. As a result of this pipeline, 5,940 two-way truckloads were removed from the road during the completion of the 3-32 pad in Q1 2021, which is the equivalent distance of three trips around the globe. In addition to the CO2 emission reductions, removing vehicles from the road also significantly reduces the risk of accidents and spills, further contributing to improved safety and environmental performance.
- We are proud of Crew’s safety record, which in 2020 featured no lost time injuries for a second consecutive year. In 2020, the Company had only two recordable injuries across our employee and contractor workforce.
- Crew successfully participated in the provincially funded dormant well programs and initiated abandonment and reclamation activities on 79 wells in 2020.
- Through 2020, Crew’s regulatory compliance remained on par with 2019 as we achieved a 95% compliance rating, with 220 regulatory inspections across the three provinces in which we operate.
- Crew has established a new committee, constituted with members of our Board of Directors, which has a specific focus on our ESG initiatives.
OPERATIONS & AREA Overview
NE BC Montney – Greater Septimus
Production & Drilling |
Q4 |
Q3 |
Q2 |
Q1 |
Q4 |
Average daily production (boe/d)(1) |
18,089 |
17,119 |
18,565 |
19,894 |
18,720 |
Wells drilled (gross / net) |
6 / 6.0 |
6 / 6.0 |
0 |
1 / 1.0 |
0 |
Wells completed (gross / net) |
7 / 7.0 |
0 |
1 / 1.0 |
0 |
4 / 4.0 |
Note: |
|
(1) |
See table in the Advisories for production breakdown by product type as defined in NI 51-101. |
Operating Netback |
Q4 |
Q3 |
Q2 |
Q1 |
Q4 |
Petroleum and natural gas sales |
20.41 |
15.73 |
11.97 |
17.61 |
20.13 |
Royalties |
(0.89) |
(0.42) |
(0.36) |
(0.86) |
(1.76) |
Realized commodity hedge gain |
1.45 |
2.18 |
3.06 |
1.44 |
0.90 |
Marketing income(1) |
(0.05) |
(0.33) |
(0.31) |
0.13 |
(0.02) |
Net operating costs(2)(3) |
(4.33) |
(4.71) |
(4.81) |
(4.52) |
(3.99) |
Transportation costs |
(4.33) |
(3.86) |
(3.37) |
(2.99) |
(2.61) |
Operating netback(3) |
12.26 |
8.59 |
6.18 |
10.81 |
12.65 |
Notes: |
|
(1) |
Marketing income was recognized from the monetization of forward physical sales contracts offset by the cost of committed natural gas transportation that was not available during the period. |
(2) |
Net operating costs are calculated as gross operating costs less processing revenue. |
(3) |
Non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented for other entities. See “Advisories – Non-IFRS Measures”. |
- The seven wells on Crew’s 9-5 pad at Greater Septimus were drilled, completed, equipped and tied-in with all wells currently flowing through permanent facilities. The estimated per well costs at this pad averaged $5 million, 12% lower than the original $5.7 million budgeted. Average per well sales production over the first 60 days was approximately 1,500 boe per day (21% condensate and ngl’s) with a flowing IP60 efficiency of approximately $3,300 per boe7.
- From the 9-5 pad, over 120,000 m3 of produced water has been transferred through above ground lines, saving approximately $550,000 while reducing emissions by removing trucks from the road.
- At Crew’s 3-32 pad, five wells were drilled in Q4/20 and six wells were completed in Q1/21, with encouraging initial condensate rates. Production from the 3-32 pad is expected to start in Q2/21.
- Drilling of our seven-well, 1-8 pad began in Q4 and has incorporated the longest wells drilled in the Company’s history. As part of our drive to improve returns, and our ongoing ESG strategy, these ultra-extended reach horizontal wells will reduce future development capital and minimize surface footprint by eliminating the number of wells required to effectively deplete the reservoir while reducing the need for additional pipelines. Following the finalization of the 1-8 pad, the associated drilling rig is scheduled to move to our 4-14 pad, targeting gas and condensate in our ultra-condensate rich area at Greater Septimus.
Other NE BC Montney
- During Q4/20 we initiated the drilling of a three well tenure retention pad in Groundbirch which has recently been rig released. The drilling rig has since moved to Attachie to drill the final lease retention well in that area, which was originally planned to be drilled in Q3/21 and will conclude the Company’s tenure retention program at Attachie.
7 Amounts exclude a short cleanup period after 20% of load fracturing fluid is recovered. Volumes include 7.1 mmcfd of sales gas, 176 bbl/d of condensate and 140 bbl/d of ngls. See “Advisories – Test Results and Initial Production (“IP”) Rates”. |
OUTLOOK
Crew continues to look forward and plan for the future, which we believe to be bright for natural gas. Despite the last six years being challenging for natural gas producers, we have learned to do more with less which has also led to a period of cost cutting and under-investment. We strongly believe that natural gas is and will continue to be an important source of energy as the world transitions to more socially responsible and cleaner energy. With society requiring more environmentally-friendly energy sources, the underlying fundamentals are constructive for natural gas with demand projected to grow by 33% from 2019 to 2050, rivalling the growth of renewables as reported by the Energy Information Administration8. With this important backdrop as support, and as previously announced, Crew developed our strategic asset development plan to enhance long-term sustainability and create meaningful value.
Progress on our Two-Year Plan
Crew’s pivotal two-year plan, designed to expand margins and significantly improve leverage metrics by efficiently matching production volumes with infrastructure and transportation commitments, has been successfully initiated.
- Production Growth – Q1/21 production is expected to average between 25,500 and 26,500 boe per day9, representing a 20% increase at the midpoint over Q4/20 production while also accounting for wells shut-in for offsetting completion operations as the Company ramps up activity.
- Optimizing Commitments – Increasing Q1/21 natural gas production has resulted in Crew increasing the utilization of our committed transportation by over 30% as compared to Q4/20. Further improvements are anticipated as production increases throughout the year and the Company’s committed transportation decreases by over 20% in Q4/21 which is expected to reduce transportation expenses by over $9 million annually.
- Enhanced Hedging Program – Crew currently has over 50% of forecast 2021 natural gas production is hedged at an average price of $2.48 per Gigajoule (“GJ”) (or $3.08 per thousand cubic feet (“mcf”) calculated using Crew’s heat content factor). In addition, approximately 35% of targeted natural gas production for 2022 is hedged at an average price of $2.46 per GJ (or $3.05 per mcf using Crew’s heat content factor).
- Reduced Costs – Crew’s plan to reduce unit costs by over 25% is largely based on increasing production volumes into existing infrastructure, as over 50% of the Company’s expenses are fixed. As production increases, per unit costs associated with operating, transportation, general and administrative and interest expenses are expected to decline from $13.19 per boe in 2020 to approximately $10.00 per boe in 2022.
- Q1 2021 Capital Expenditures are expected to range between $50 and $53 million, a slight increase over initial projections as the Company was able to access and drill a lease expiry well in Q1/21 that was originally planned for Q3/21.
- Full Year 2021 Guidance remains unchanged, with plans to invest between $120 and $145 million of capital over the year, resulting in average annual production of 26,000 to 28,000 boe per day9 and an exit rate of over 30,000 boe per day9.
8 Source: U.S. Energy Information Administration: Annual Energy Outlook 2020 |
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9 See table in the Advisories for production breakdown by product type as defined in NI 51-101. |
The Board, management and our Crew team all remain excited and focussed on the efficient execution of the Company’s business plan. We have identified numerous opportunities within our portfolio to further expand margins, develop additional value and foster profitable growth while participating in the energy transition. With low average costs to find reserves leading to robust recycle ratios, and excellent market access, we are poised to capture additional value from our world-class Montney resource. Crew retains the financial flexibility and expertise to execute on our plans, with ample liquidity and the optionality to raise funds through asset transactions as needed. We commend the hard work of Crew’s employees, contractors and directors whose commitment and dedication are critical to our ongoing success and thank all shareholders and bondholders for your ongoing support.
Advisories
Information Regarding Disclosure on Oil and Gas Reserves and Operational Information
All amounts in this news release are stated in Canadian dollars unless otherwise specified. All reserves information in this press release is derived from our independent reserves evaluation effective December 31, 2020, the details of which were announced in our February 8, 2021 press release (the “Reserves Press Release”). Our oil and gas reserves statement for the year ended December 31, 2020, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form which will be available on our SEDAR profile at www.sedar.com on or before March 31, 2021. The recovery and reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In relation to the disclosure of estimates for individual properties or subsets thereof, such estimates may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.
This press release contains metrics commonly used in the oil and natural gas industry, such as “recycle ratio”, “finding and development costs” and “finding, development and acquisition costs”. Each of these metrics are determined by Crew as specifically set forth in the Capital Program Efficiency tables contained in our Reserves Press Release. These terms do not have standardized meanings or standardized methods of calculation and therefore may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Such metrics have been included to provide readers with additional information to evaluate the Company’s performance however, such metrics are not reliable indicators of future performance and therefore should not be unduly relied upon for investment or other purposes. Recycle Ratio is calculated as operating netback per boe divided by F&D costs on a per boe basis. Management uses these metrics for its own performance measurements and to provide readers with measures to compare Crew’s performance over time.
Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis. The aggregate of the costs incurred in the financial year and changes during that year in estimated FDC may not reflect total F&D costs related to reserves additions for that year. Finding and development costs both including and excluding acquisitions and dispositions have been presented in this press release because acquisitions and dispositions can have a significant impact on our ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of our cost structure.
Non-IFRS Measures
Certain financial measures referred to in this press release, such as adjusted funds flow or AFF, free adjusted funds flow, EBITDA, operating netback, net capital expenditures, net debt, net operating costs and working capital deficiency and are not prescribed by IFRS. Crew uses these measures to help evaluate its financial and operating performance as well as its liquidity and leverage. These non-IFRS financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by other issuers.
“Adjusted funds flow” or “AFF”, presented herein is equivalent to cash flow provided by operating activities, which is an IFRS measure, adding the change in non-cash working capital, decommissioning obligation expenditures, excluding grants, and accretion of deferred financing costs on the senior unsecured notes. The Company considers this metric as a key measure that demonstrate the ability of the Company’s continuing operations to generate the cash flow necessary to maintain production at current levels and fund future growth through capital investment and to service and repay debt. Crew also presents AFF per share in this presentation whereby per share amounts are calculated using fully diluted shares outstanding.
“Free AFF” is calculated by taking adjusted funds flow and subtracting capital expenditures, excluding acquisitions and dispositions. Management believes that free adjusted funds flow provides a useful measure to determine Crew’s ability to improve sustainability and to manage the long-term value of the business.
“EBITDA” is calculated as consolidated net income (loss) before interest and financing expenses, income taxes, depletion, depreciation and amortization, adjusted for certain non-cash, extraordinary and non-recurring items primarily relating to unrealized gains and losses on financial instruments and impairment losses. Crew utilizes EBITDA as a measure of operational performance and cash flow generating capability. EBITDA impacts the level and extent of funding for capital projects investments. This measure is consistent with the EBITDA formula prescribed under the Company’s Credit Facility and allows Crew and others to assess its ability to fund financing expenses, net debt reductions and other obligations.
“Operating Netbacks” equals petroleum and natural gas sales including realized gains and losses on commodity related derivative financial instruments, marketing income, less royalties, net operating costs and transportation costs calculated on a boe basis. Management considers operating netback an important measure to evaluate its operational performance as it demonstrates its field level profitability relative to current commodity prices. The calculation of Crew’s netbacks can be seen under “Operating Netbacks” within the Company’s most recently filed MD&A.”
“Net Capital Expenditures” equals exploration and development expenditures plus property acquisitions or less property dispositions.
“Net Debt” is defined as outstanding long-term debt and net working capital.
“Net Operating Costs” equals gross operating costs less processing revenue.
“Working Capital Surplus (Deficiency)” equals current assets less current liabilities and derivative financial instruments.
Please refer to Crew’s most recently filed MD&A for additional information relating to Non-IFRS measures including a reconciliation of AFF to its most closely related IFRS measure. The MD&A can be accessed either on Crew’s website at www.crewenergy.com or under the Company’s profile on www.sedar.com.