CALGARY, AB – Perpetual Energy Inc. (“Perpetual”, or the “Company”) is pleased to release its fourth quarter and year-end 2020 financial and operating results and a summary of the Company’s year-end 2020 reserves as reported by the independent engineering firm McDaniel and Associates Consultants Ltd. (“McDaniel”). A complete copy of Perpetual’s audited consolidated financial statements, Management’s Discussion and Analysis (“MD&A”) and Annual Information Form for the year ended December 31, 2020 are available through the Company’s website at www.perpetualenergyinc.com and SEDAR at www.sedar.com.
FOURTH QUARTER AND YEAR-END HIGHLIGHTS
- Sequentially grew production to 4,730 boe/d in the fourth quarter of 2020 (69% conventional natural gas), up 13% from 4,188 boe/d in the third quarter (65% conventional natural gas) and up 29% from 3,662 boe/d in the second quarter of 2020 (77% conventional natural gas). Increased production reflected the restart of heavy crude oil production which was shut-in during the first quarter in response to the collapse in oil prices and the commencement of production from five (2.5 net) new wells at East Edson. On April 1, 2020 Perpetual sold a 50% working interest in its East Edson properties (the “East Edson Transaction”) for proceeds of $35 million in cash and the carried interest funding of an eight well drilling program. Five of the commitment wells were drilled and placed onstream in 2020, two are forecast to commence production in March, and the final carried interest commitment well is scheduled to be drilled in the third quarter of 2021.
- Total proved plus probable reserves were 35.4 MMboe at December 31, 2020, a decrease of 46% year-over-year reflecting the East Edson Transaction, but offset by strong reserve additions from the Clearwater play. Total future development costs (“FDC”) decreased $246.3 million (69%) to $112.5 million at year-end 2020.
- After giving effect to the East Edson Transaction, FDC to develop Wilrich proved plus probable reserves at East Edson decreased a further 63% ($102.9 million) from the Year-End 2019 McDaniel Reserve Report, reflecting the revised East Edson development plan which incorporates longer extended-reach wells, increased well spacing, and reflects reduced capital costs per well related to the operator’s scale of operations as demonstrated by the execution of the 2020 drilling program.
- Four (4.0 net) Clearwater multi-lateral heavy crude oil wells were drilled at Ukalta in the first quarter of 2020, resulting in area finding and development costs (“F&D”) of $9.26/boe on a proved plus probable basis, including changes in FDC.
- Active exploration and land capture activities on the Clearwater play in Eastern Alberta resulted in a 495% increase in proved plus probable reserves year-over-year. McDaniel recognized proved plus probable reserves to be recovered by 21 (21.0 net) multi-lateral drilling locations targeting the Clearwater in eastern Alberta, representing 10% of the Company’s year-end 2020 reserves (2019 – 1%).
- The Company continued its active abandonment and reclamation program, receiving 13 reclamation certificates in 2020 and an additional six reclamation certificates in 2021 related to project work completed in 2020.
- During the fourth quarter, a process was initiated to exchange Perpetual’s January 2022 Senior Notes into new January 2025 Senior Secured Notes. The exchange of Senior Notes was completed in January 2021.
FOURTH QUARTER 2020 FINANCIAL AND OPERATING RESULTS
Capital Spending, Production and Operations
- At East Edson, three (1.5 net) horizontal Wilrich conventional natural gas wells were drilled and tied-in to production during the fourth quarter pursuant to the Purchaser’s carried interest drilling commitment.
- Fourth quarter spending in Eastern Alberta was nominal, consistent with guidance released on November 10, 2020.
- Fourth quarter production averaged 4,730 boe/d (69% conventional natural gas), down 41% from the comparative period of 2019 due to the East Edson Transaction.
- Compared to the third quarter of 2020, total production increased by 13% or 542 boe/d, as production from the first five (2.5 net) East Edson carried interest wells is now online. Additionally, the Company continued to reactivate heavy crude oil production as oil prices recovered and stabilized. As of December 31, 2020, Perpetual had restarted all heavy crude oil production with the exception of approximately 185 bbl/d of higher cost production from certain wells at Mannville.
- See “Financial and Operating Highlights” on page 12 of this news release for constituent product types and conversions used in the calculation of “boe”.
Financial Highlights
- Realized revenue was $21.73/boe in the fourth quarter of 2020, 11% higher than the comparative period of 2019. The increase was due primarily to the 20% improvement in Perpetual’s realized oil price to $52.60/bbl, bolstered by financial hedging gains of $2.2 million ($18.92/boe). Compared to the prior year period, realized natural gas prices of $1.46/Mcf were 27% lower, due to realized hedging losses on locked-in AECO-NYMEX basis differential contracts of $2.6 million ($1.46/Mcf) despite the 6% increase in both NYMEX and AECO reference prices over the same period.
- Cash costs on a unit-of-production basis were $17.92/boe, down 3% from the comparative period of 2019. On an absolute dollar basis, cash costs were $7.8 million, 42% lower than the prior year period due to the East Edson Transaction, the reduction in work hours and corresponding employee compensation to 80% effective April 1, 2020, and payments received from the Canada Emergency Wage Subsidy (“CEWS”) and Canada Emergency Rent Subsidy (“CERS”) of $0.3 million. In addition, the semi-annual interest payment of $1.8 million that was payable on December 31, 2020, was deferred by the Company’s Term Loan lender and added to the principal amount owing as a condition of the Credit Facility lenders agreeing to extend the Credit Facility maturity to March 1, 2021.
- Net income for the fourth quarter of 2020 was $14.4 million ($0.24/share), up $46.9 million from the prior year period. The increase was due primarily to the non-cash impairment reversal of $18.0 million recognized in the fourth quarter of 2020 as oil and natural gas prices recovered from their mid-year lows.
- Net cash flows used in operating activities were $1.1 million, comparable to the prior year period of $1.3 million. Excluding changes in non-cash working capital, net cash flows from operating activities were $0.4 million, an increase of $1.0 million from the prior year period, due primarily to the deferral of $1.8 million of Term Loan interest.
- Adjusted funds flow in the fourth quarter of 2020 was $1.2 million ($0.02/share), $0.9 million higher than the prior year period.
YEAR-END 2020 FINANCIAL AND OPERATING RESULTS
Capital Spending, Production and Operations
- Exploration and development spending in 2020 was $6.0 million, down 54% from the prior year. Capital investment was focused on the Clearwater play in Eastern Alberta, where total spending of $5.5 million included costs to drill, complete and tie-in four (4.0 net) heavy crude oil wells in the Ukalta area. The program successfully demonstrated enhanced capital efficiency and performance, de-risked additional development drilling inventory, and resulted in F&D costs of $9.26/boe (2019 – $17.27/boe) on a proved and probable basis, including changes in FDC. The Clearwater drilling program, combined with better than forecast well performance and farm-in arrangements, contributed to a year-over-year increase in Clearwater proved and probable reserves of 2.7 million bbls.
- In accordance with the terms of the East Edson Transaction, five (2.5 net) horizontal Wilrich carried interest wells were drilled, completed and tied-in during the year at the 50% owned East Edson property.
- For the year ended December 31, 2020, Perpetual executed $1.0 million (2019 – $1.7 million) of abandonment and reclamation projects, $0.8 million of which was funded by Alberta’s Site Rehabilitation Program (“SRP”).
- Production in 2020 averaged 5,012 boe/d (29% heavy crude oil and NGL), a decrease of 44% from 2019. The decrease in production was due primarily to the closing of the East Edson Transaction, combined with the temporary shut-in of heavy crude oil production throughout the second quarter in response to the abrupt drop in oil prices experienced due to local and global supply and demand imbalances and the COVID-19 pandemic. As Western Canadian Select (“WCS”) prices improved from their April lows, the Company began reactivating certain low-cost heavy crude oil production in mid-May 2020, and has continued to ramp up production as oil prices improve.
- Perpetual’s operating netback was $8.4 million ($4.57/boe), down 78% from 2019. The decrease was due to a 44% decline in year-over-year production, combined with the impact of lower realized natural gas and NGL prices of 69% and 23% respectively.
Financial Highlights
- Realized revenue was $30.2 million in 2020, down $43.4 million (59%) from 2019 due to the combined effect of lower production related to the East Edson Transaction, heavy crude oil shut-ins, and net hedging losses. On a unit-of-production basis, realized revenue was $16.46/boe, 27% lower than the prior year due primarily to lower realized natural gas and NGL prices. Compared to the AECO Daily Index price of $2.23/Mcf, realized natural gas prices were negatively impacted by physical and financial AECO-NYMEX basis differential hedging and market diversification contract losses of $12.7 million ($1.62/Mcf). For the year ended December 31, 2020, Perpetual’s realized oil price was $49.37/bbl, up 10% from $44.87/bbl in 2019. Realized oil prices were improved by hedging gains of $7.5 million ($19.05/bbl) during the year.
- Net loss for 2020 was $61.6 million ($1.01/share), down from $94.0 million in 2019 ($1.56/share). The net loss in 2020 was impacted by aggregate non-cash impairment charges of $42.5 million, comprised of $60.5 million of impairment charges booked at March 31, 2020 as oil and natural gas prices collapsed following the onset of the COVID-19 pandemic, partially offset by an $18.0 million impairment reversal recorded at December 31, 2020 as oil and natural gas prices recovered from their mid-year lows.
- Net cash flows used in operating activities were $9.5 million in 2020, down $27.3 million compared to 2019. The decrease was due primarily to the $43.4 million reduction in realized revenue, partially offset by a $20.5 million reduction in cash costs.
- For the year ended December 31, 2020, adjusted funds flow was negative $7.8 million ($0.13/share), down $22.3 million from $14.5 million ($0.24/share) in 2019 as the impact of the 44% year-over-year decrease in production combined with lower natural gas and NGL prices outweighed the 36% decrease in cash costs.
- At December 31, 2020, Perpetual had total net debt of $105.0 million, down $13.1 million (11%) from December 31, 2019 due to the closing of the East Edson Transaction. The cash proceeds from the East Edson Transaction were used to repay bank debt. Compared to September 30, 2020, net debt increased by $2.9 million (3%) due to increased draws on the Credit Facility to fund net working capital payments and cash flows used in operating activities.
2021 OUTLOOK
Perpetual’s reserve-based credit facility is currently undergoing its borrowing limit redetermination, which is scheduled to be completed on or prior to March 1, 2021 and its Term Loan matures on March 14, 2021. To preserve liquidity, the Company will defer further capital spending until the credit facility borrowing limit redetermination has been completed and the Term Loan has been refinanced or maturity extended. The Company will issue its 2021 Outlook once the borrowing limit redetermination is known and capital spending plans have been approved by the Board of Directors.
Production at Perpetual’s non-operated West Central properties is expected to increase 25% to 30% from fourth quarter levels to 3,800 to 4,000 boe/d in the first quarter of 2021 (Q4 2020 – 3,033 boe/d). Production continues to ramp up at East Edson as new carried interest wells come onstream, with two (1.0 net) additional carried interest wells forecast to be on production by the end of March 2021. The Purchaser is anticipated to complete its eight well carried interest drilling commitment by the end of the third quarter of 2021.
Total abandonment and reclamation expenditures of up to $2.2 million are forecast in 2021, with up to $1.3 million to be funded through the Alberta SRP.
YEAR-END 2020 RESERVES
On a total Company basis, there was a 46% reduction in proved plus probable reserves year-over-year excluding production. The reduction associated with the East Edson Transaction was 45%, as East Edson represented 89% of total Company proved plus probable reserves at year-end 2019 and now represents 74% of proved plus probable reserves at year-end 2020. Strong performance of heavy crude oil and conventional natural gas wells in the Mannville property held reserves largely unchanged, excluding production. The Clearwater heavy crude oil play reserves increased by 495% in the proved plus probable reserve category and now represents 10% of total Company total proved plus probable reserves compared to 1% at year-end 2019. Perpetual’s proved plus probable reserves at year-end 2020 are 35.4 MMboe, comprised of 28% heavy crude oil and NGL (2019 – 67.1 MMboe; 17% heavy crude oil and NGL).
The quality of Perpetual’s assets and positive momentum to drive operational and execution excellence in its core operating areas are demonstrated by the highlights below:
- Total proved reserves were 25.0 MMboe at year-end 2020, representing 71% of the Company’s proved plus probable reserves (2019 – 60%).
- Proved plus probable producing reserves were 12.4 MMboe at December 31, 2020, representing 35% of total proved plus probable reserves.
- The East Edson Transaction resulted in a large disposition adjustment of 29.8 MMboe. Further, the East Edson development plan has been revised to reflect longer extended-reach wells and reduced capital costs per well related to the operator’s scale of operations as demonstrated by the execution of the 2020 drilling program, and increased well spacing, all contributing to increased capital efficiencies. Increased reserve recoveries per well have shifted a significant reserve volume from probable undeveloped to proved undeveloped, resulting in the positive technical revision in the proved category. Fewer overall probable locations now booked in East Edson resulted in a negative technical reserve revision in the probable category.
- Total proved plus probable reserves in the Clearwater play increased 495%. Drilling of four (4.0 net) wells in the Ukalta area resulted in additions of 1.6 MMboe. An additional 1.2 MMboe of proved plus probable undeveloped reserves is attributed to a farm-in agreement on three sections of development land.
- Total proved plus probable reserves in the Mannville district are largely unchanged, with a small decrease of 5% excluding production despite no capital spending in 2020 and price-related negative reserve revisions. Continued constructive waterflood performance resulted in positive technical reserve revisions as in past years.
- Exploration and development spending of $6.0 million in 2020 was largely focused on Clearwater projects. F&D costs related to the Clearwater play were $9.80/boe on a proved plus probable basis, including changes in FDC.
- Overall, FDC dropped to $112.5 million (2019 – $358.8 million) in the proved plus probable category, a reduction of $246.3 million. The difference is primarily at East Edson where FDC dropped $267.2 million to $61.4 million at year-end 2020, down from $328.6 million at December 31, 2019. The East Edson Transaction reduced the Company’s interest in the East Edson property and its share of FDC to 50%, with a further reduction as a result of the carried interest funding of the associated eight (4.0 net) well drilling program. Furthermore, lower capital costs per well established by the operator, and a revised development plan with longer wells at wider spacing which results in fewer gross wells required for full development, combined for a positive impact on capital efficiencies to enhance the value of the East Edson property.
- Based on an equal weighting of three consultant average price (McDaniel, GLJ, Sproule) forecasts (the “Consultant Average Price Forecast”) used by McDaniel, the net present value (“NPV”) of Perpetual’s total proved plus probable reserves (discounted at 10%) before income tax, was $187.8 million (2019 – $297.3 million). The decrease related primarily to the East Edson Transaction and the material decrease in the independent reserve evaluators’ forecast for crude oil prices at year-end 2020 as compared to the prior year.
- All abandonment, decommissioning and reclamation obligations are included in the reserve report, consistent with year-end 2019. All reserve well decommissioning obligations as well as the additional costs expected to be incurred to abandon and reclaim non-reserve wells, facilities and pipelines are included.
- Based on the Consultant Average Price Forecast, Perpetual’s reserve-based net asset value (“NAV”) (discounted at 10%) at year-end 2020 is estimated at $98.8 million ($1.61 per share) as compared to $200.5 million ($3.27 per share) at year-end 2019.
Reserves Disclosure
Working interest reserves included herein refer to working interest reserves before royalty deductions. Reserves information is based on an independent reserves evaluation report prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”) with an effective date of December 31, 2020 (the “McDaniel Report”), and has been prepared in accordance with National Instrument 51-101 (“NI 51-101”) using the Consultant Average Price Forecast. Complete NI 51-101 reserves disclosure including after-tax reserve values, reserves by major property and abandonment costs will be included in Perpetual’s Annual Information Form (“AIF”), which, when filed, will be available on the Company’s website at www.perpetualenergyinc.com and SEDAR at www.sedar.com. Perpetual’s reserves at December 31, 2020 are summarized below:
Working Interest Reserves at December 31, 2020(1) |
|||||
Light and |
Heavy |
Conventional |
Natural |
Oil |
|
Proved Producing |
7 |
2,100 |
43,407 |
686 |
10,028 |
Proved Non-Producing |
– |
294 |
2,367 |
3 |
691 |
Proved Undeveloped |
– |
2,283 |
64,988 |
1,217 |
14,331 |
Total Proved |
7 |
4,676 |
110,762 |
1,906 |
25,050 |
Probable Producing |
2 |
531 |
10,175 |
166 |
2,395 |
Probable Non-Producing |
– |
63 |
4,584 |
41 |
868 |
Probable Undeveloped |
– |
2,095 |
27,058 |
519 |
7,123 |
Total Probable |
2 |
2,689 |
41,816 |
726 |
10,386 |
Total Proved plus Probable |
9 |
7,365 |
152,579 |
2,633 |
35,436 |
(1) |
May not add due to rounding. |
Total proved reserves at December 31, 2020 account for 71% (2019 – 60%) of total proved plus probable reserves. Proved producing reserves of 10.0 MMboe comprise 40% (2019 – 40%) of total proved reserves. Proved plus probable producing reserves of 12.4 MMboe represent 35% (2019 – 30%) of total proved plus probable reserves.
Reserves Reconciliation
Working Interest Reserves(1) |
|||
Barrels of Oil Equivalent (Mboe) |
Proved |
Probable |
Proved and |
Opening Balance, December 31, 2019 |
40,298 |
26,759 |
67,057 |
Extensions and Improved Recovery |
1,149 |
419 |
1,568 |
Discoveries |
– |
– |
– |
Technical Revisions |
3,170 |
(4,985) |
(1,815) |
Acquisitions |
436 |
785 |
1,221 |
Dispositions |
(17,545) |
(12,283) |
(29,829) |
Production |
(1,830) |
– |
(1,830) |
Economic Factors |
(628) |
(308) |
(937) |
Closing Balance, December 31, 2020 |
25,050 |
10,386 |
35,436 |
(1) |
May not add due to rounding. |
The East Edson Transaction resulted in the large disposition adjustment. Further, the East Edson development plan has been revised to reflect increased well spacing, longer extended-reach wells and reduced capital costs per well related to the operator’s scale of operations as demonstrated by the execution of the 2020 drilling program, all contributing to increased capital efficiencies. Increased reserve recoveries per well have shifted a significant reserve volume from probable undeveloped to proved undeveloped, resulting in the positive technical revision in the proved category. Fewer overall probable locations now booked in East Edson resulted in a negative technical reserve revision in the probable category.
Two of the four Clearwater wells drilled in Ukalta in 2020 were recorded as transfers from undeveloped to developed producing, while the other two wells were booked as extensions. Positive heavy crude oil technical revisions are attributed to improved reserve recoveries at Ukalta due to better well performance than previously forecast.
Furthermore, 2020 Clearwater exploration and development activity and farm-in arrangements increased the number of undeveloped locations assigned reserves from 5 (5.0 net) wells to 21 (21.0 net) wells.
The table below summarizes the FDC estimated by McDaniel by play type to bring proved plus probable non-producing and undeveloped reserves to production.
Future Development Capital(1) |
|||||||
($ millions) |
2021 |
2022 |
2023 |
2024 |
2025 |
Remainder |
Total |
Eastern Alberta Shallow Gas |
– |
0.4 |
0.8 |
0.2 |
– |
– |
1.3 |
Mannville Heavy Oil |
0.5 |
2.1 |
2.7 |
6.9 |
5.2 |
3.0 |
20.4 |
Clearwater |
10.8 |
15.3 |
3.2 |
– |
– |
– |
29.3 |
East Edson Wilrich |
6.4 |
13.1 |
12.8 |
12.6 |
14.1 |
2.5 |
61.4 |
Total |
17.7 |
30.9 |
19.4 |
19.7 |
19.3 |
5.5 |
112.5 |
(1) |
May not add due to rounding. |
The McDaniel Report estimates that FDC of $112.5 million will be required over the life of the Company’s proved plus probable reserves. Proved plus probable reserve forecast FDC have decreased by $246.3 million (69%) from $358.8 million at December 31, 2019.
The very significant reduction in FDC was driven by the East Edson Transaction, where FDC was reduced due to the sale of 50% of the Company’s interest, and no capital being recorded for the remaining three wells of the eight well carried capital drilling program. Lower capital costs per well and fewer development wells in the revised development plan at East Edson further reduced FDC. FDC is attributable to the drilling, completion, equipping and tie–in of 32 (15.7 net) horizontal conventional natural gas wells targeting the Wilrich at East Edson, down from 66 (63.3 net) at year end 2019 due to the East Edson Transaction and the revised development plan requiring fewer developments wells due to increased well spacing and longer wells.
FDC in Eastern Alberta increased $20.9 million year-over-year to $51.1 million on a proved plus probable basis. Increases are attributed to an increase in undeveloped locations booked in the Clearwater play, where 21 (21.0 net) multi-lateral horizontal heavy crude oil locations are booked as undeveloped, an increase from 5 (5.0 net) locations at year end 2019. At the Mannville property, 17 (17.0 net) horizontal heavy crude oil wells are booked as undeveloped, down from 19 (19.0 net) at year end 2019. Future capital costs also include recompletion of 22 conventional natural gas wells included in Perpetual’s proved plus probable reserves.
RESERVE LIFE INDEX
Perpetual’s proved plus probable reserves to production ratio, also referred to as reserve life index (“RLI”), was 14.5 years at year-end 2020, while the proved RLI was 10.9 years, based upon the 2021 production estimates in the McDaniel Report. The following table summarizes Perpetual’s historical calculated RLI.
Reserve Life Index(1) |
|||||
Year-end |
2020 |
2019 |
2018 |
2017 |
2016 |
Total Proved |
10.9 |
13.4 |
13.1 |
9.1 |
9.3 |
Total Proved plus Probable |
14.5 |
21.5 |
19.9 |
13.2 |
15.1 |
(1) |
Calculated as year-end reserves divided by year one production estimate from the McDaniel Report. |
NET PRESENT VALUE OF RESERVES SUMMARY
Perpetual’s heavy crude oil, conventional natural gas, and NGL reserves were evaluated by McDaniel using the Consultant Average Price Forecast effective January 1, 2021 and include the forecasted impact of the Company’s market diversification contract, but prior to provision for financial oil and natural gas price hedges, foreign exchange contracts, income taxes, interest, debt service charges and general and administrative expenses. The following table summarizes the NPV of future revenue from reserves at January 1, 2021, assuming various discount rates:
NPV of Reserves, before income tax(1)(2)(3) |
||||||
($ millions except as noted) |
Undiscounted |
5% |
10% |
15% |
Discounted |
Unit Value |
Proved Producing |
9 |
27 |
28 |
26 |
24 |
3.89 |
Proved Non-Producing |
4 |
4 |
4 |
3 |
3 |
5.78 |
Proved Undeveloped |
172 |
118 |
86 |
66 |
51 |
6.55 |
Total Proved |
185 |
149 |
117 |
95 |
78 |
5.62 |
Probable Producing |
31 |
22 |
17 |
13 |
11 |
7.72 |
Probable Non-Producing |
5 |
3 |
2 |
2 |
1 |
3.08 |
Probable Undeveloped |
120 |
75 |
51 |
37 |
29 |
7.96 |
Total Probable |
156 |
101 |
70 |
52 |
41 |
7.51 |
Total Proved plus Probable |
341 |
250 |
188 |
147 |
119 |
6.21 |
(1) |
January 1, 2021 Consultant Average price forecast |
(2) |
Inclusive of the East Edson royalty and a further reduction for the retained East Edson royalty obligation by Perpetual through December 31, 2022 as part of the East Edson Transaction, asset retirement obligations for sites not assigned reserves, and corporate marketing obligations. |
(3) |
May not add due to rounding. |
(4) |
The unit values are based on net reserve volumes. |
McDaniel’s NPV10 estimate of Perpetual’s total proved plus probable reserves at year-end 2020 was $187.8 million, down 37% from $297.3 million at year-end 2019. The decrease in NPV10 reflects the East Edson Transaction and the impact of lower commodity prices. These decreases were offset by reduced FDC in East Edson resulting from a more capital efficient development plan and an increase in value attributed to the Clearwater play including the drilling of four wells and the capture of additional lands that increased proved plus probable locations from five (5.0 net) at year-end 2019 to 21 (21.0 net) at year-end 2020. At a 10% discount factor, total proved reserves account for 63% (2019 – 59%) of the proved plus probable value. Proved plus probable producing reserves represent 24% (2019 – 34%) of the total proved plus probable value (discounted at 10%) as obligations for non-producing wells, facilities and pipelines and forecast corporate marketing adjustments reduce the value of the developed producing reserves.
FAIR MARKET VALUE OF UNDEVELOPED LAND
Perpetual’s independent third-party estimate of the fair market value of its undeveloped acreage by region for purposes of the NAV calculation is based on past Crown land sale activity, adjusted for tenure and other considerations. In West Central Alberta, no undeveloped land value was assigned where proved and/or probable undeveloped reserves have been booked.
Fair Market Value of Undeveloped Land |
|||
Net Acres |
Value ($ millions) |
$/Acre |
|
Eastern and other |
103,009 |
7.2 |
70.13 |
West Central |
8,553 |
6.3 |
738.80 |
Oil Sands |
96,000 |
6.0 |
62.66 |
Total |
207,562 |
19.6 |
94.23 |
The fair market value of Perpetual’s undeveloped land at year-end 2020, adjusted to remove the value of undeveloped lands with reserves assigned in West Central Alberta, is estimated by an external land consultant at $19.6 million, a decrease of 46% from $36.0 million relative to year-end 2019. The fair market value of undeveloped oil sands leases incorporates the depreciated value of the absolute investment to date in the ongoing bitumen extraction pilot project at Panny, with the remaining undeveloped land valued by historical land sale activity, adjusted for tenure.
NET ASSET VALUE
The following NAV table shows what is normally referred to as a “produce-out” NAV calculation under which the Company’s reserves would be produced at forecast future prices and costs. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. It should not be assumed that the NAV represents the fair market value of Perpetual’s shares. The calculations below do not reflect the value of the Company’s prospect inventory to the extent that the prospects are not recognized within the NI 51-101 compliant reserve assessment, except as they are valued through the estimate of the fair market value of undeveloped land.
Pre-tax NAV at December 31, 2020(1) |
||||
Discounted at |
||||
($ millions, except as noted) |
Undiscounted |
5% |
10% |
15% |
Total Proved plus Probable Reserves(2) |
340.9 |
249.6 |
187.8 |
146.8 |
Fair market value of undeveloped lands(3) |
19.6 |
19.6 |
19.6 |
19.6 |
Bank debt, net of working capital(1) |
(24.6) |
(24.6) |
(24.6) |
(24.6) |
Term loan(4) |
(46.8) |
(46.8) |
(46.8) |
(46.8) |
Senior notes(4) |
(33.6) |
(33.6) |
(33.6) |
(33.6) |
Estimate of Additional Future Abandonment and Reclamation Costs(5) |
(0.0) |
(0.0) |
(0.0) |
(0.0) |
Derivatives(6) |
(3.6) |
(3.6) |
(3.6) |
(3.6) |
NAV |
251.9 |
160.6 |
98.8 |
57.8 |
Common shares outstanding (million) |
61.3 |
61.3 |
61.3 |
61.3 |
NAV per share ($/share) |
4.11 |
2.62 |
1.61 |
0.94 |
(1) |
Financial information is per Perpetual’s 2020 audited consolidated financial statements. |
(2) |
Reserve values per McDaniel Report as at December 31, 2020. |
(3) |
Independent third-party estimate; excludes undeveloped land in West Central Alberta with reserves assigned. |
(4) |
Measured at principal amount. |
(5) |
All abandonment obligations including future abandonment and reclamation costs for pipelines and facilities and non-reserve wells are included in the McDaniel Report. |
(6) |
Fair value as at December 31, 2020, relative to the Consultant Average Price Forecast. Excludes market diversification contract which is included in total proved plus probable reserves. |
The above evaluation includes FDC expectations required to bring undeveloped reserves on production, as recognized by McDaniel, that meet the criteria for booking under NI 51-101. The fair market value of undeveloped land does not reflect the value of the Company’s extensive prospect inventory which is anticipated to be converted into reserves and production over time through future capital investment.
FINDING AND DEVELOPMENT COSTS
Under NI 51-101, the methodology to be used to calculate F&D costs includes incorporating changes in FDC required to bring the proved and probable undeveloped reserves to production. Changes in forecast FDC occur annually as a result of development activities, acquisitions and disposition activities, undeveloped reserve revisions and capital cost estimates that reflect the independent evaluator’s best estimate of what it will cost to bring the proved plus probable undeveloped reserves on production.
2020 F&D Costs(1) |
||||
($ millions except as noted) |
Proved |
Proved & |
||
F&D Costs, including FDC |
||||
Exploration and development capital expenditures(2) |
$ |
5.98 |
$ |
5.98 |
Total change in FDC |
$ |
7.62 |
$ |
(0.73) |
Total F&D capital, including change in FDC |
$ |
13.59 |
$ |
5.24 |
Reserve additions, including revisions (MMboe) |
3.69 |
(1.18) |
||
F&D Costs, including FDC ($/boe) |
$ |
3.68 |
$ |
(4.43) |
FD&A Costs, including FDC |
||||
Exploration and development capital expenditures(2) |
$ |
5.98 |
$ |
5.98 |
Proceeds on dispositions, net of acquisitions |
$ |
(34.53) |
$ |
(34.53) |
Total change in FDC |
$ |
(108.32) |
$ |
(246.30) |
Total FD&A capital, including change in FDC |
$ |
(136.88) |
$ |
(274.86) |
Reserve additions, including net acquisitions (MMboe) |
(13.42) |
(29.79) |
||
FD&A Costs, including FDC ($/boe) |
$ |
10.20 |
$ |
9.23 |
(1) |
Financial information is per Perpetual’s 2020 audited consolidated financial statements. |
(2) |
Excludes corporate assets and expenditures on decommissioning obligations. |
Financial and Operating Highlights |
Three Months ended December 31 |
Year ended December 31 |
||||
($Cdn thousands, except volume and per share amounts) |
2020 |
2019 |
Change |
2020 |
2019 |
Change |
Financial |
||||||
Oil and natural gas revenue |
8,178 |
15,830 |
(48%) |
29,486 |
74,361 |
(60%) |
Net income (loss) |
14,443 |
(32,498) |
(144%) |
(61,597) |
(94,015) |
(34%) |
Per share – basic and diluted(2) |
0.24 |
(0.54) |
(144%) |
(1.01) |
(1.56) |
(35%) |
Cash flow from (used in) operating activities |
(1,104) |
(1,290) |
(14%) |
(9,533) |
17,806 |
(154%) |
Per share(1)(2) |
(0.02) |
(0.02) |
– |
(0.16) |
0.30 |
(153%) |
Adjusted funds flow(1) |
1,240 |
340 |
265% |
(7,787) |
14,534 |
(154%) |
Per share(2) |
0.02 |
0.01 |
100% |
(0.13) |
0.24 |
(154%) |
Revolving bank debt |
17,495 |
47,552 |
(63%) |
17,495 |
47,552 |
(63%) |
Senior notes, principal amount |
33,580 |
33,580 |
– |
33,580 |
33,580 |
– |
Term loan, principal amount |
46,823 |
45,000 |
4% |
46,823 |
45,000 |
4% |
TOU share margin demand loan, principal amount |
– |
100 |
(100%) |
– |
100 |
(100%) |
TOU share investment |
– |
(15,220) |
(100%) |
– |
(15,220) |
(100%) |
Net working capital deficiency(1) |
7,099 |
7,068 |
– |
7,099 |
7,068 |
– |
Total net debt(1) |
104,997 |
118,080 |
(11%) |
104,997 |
118,080 |
(11%) |
Net capital expenditures |
||||||
Capital expenditures |
466 |
1,995 |
(77%) |
5,939 |
12,939 |
(54%) |
Net proceeds on acquisitions and dispositions |
– |
– |
– |
(34,528) |
– |
100% |
Net capital expenditures |
466 |
1,995 |
(77%) |
(28,589) |
12,939 |
(321%) |
Common shares outstanding (thousands) |
||||||
End of period(3) |
61,305 |
60,513 |
1% |
61,305 |
60,513 |
1% |
Weighted average – basic and diluted |
61,266 |
60,444 |
1% |
61,013 |
60,258 |
1% |
Operating |
||||||
Daily average production |
||||||
Conventional natural gas (MMcf/d) |
19.5 |
36.6 |
(47%) |
21.5 |
42.3 |
(49%) |
Heavy crude oil (bbl/d) |
1,241 |
1,275 |
(3%) |
1,082 |
1,224 |
(12%) |
NGL (bbl/d) |
237 |
606 |
(61%) |
346 |
719 |
(52%) |
Total (boe/d)(5) |
4,730 |
7,991 |
(41%) |
5,012 |
8,988 |
(44%) |
Average prices |
||||||
Realized natural gas price ($/Mcf)(4) |
1.46 |
2.00 |
(27%) |
0.85 |
2.77 |
(69%) |
Realized oil price ($/bbl)(4) |
52.60 |
43.85 |
20% |
49.37 |
44.87 |
10% |
Realized NGL price ($/bbl)(4) |
38.03 |
43.93 |
(13%) |
31.40 |
41.01 |
(23%) |
Wells drilled |
||||||
Conventional natural gas – gross (net) |
3 (1.5) |
– (–) |
5 (2.5) |
– (–) |
||
Heavy crude oil – gross (net) |
– (–) |
– (–) |
4 (4.0) |
5 (5.0) |
||
Total – gross (net) |
– (–) |
– (–) |
9 (6.5) |
5 (5.0) |
(1) |
These are non-GAAP measures. Please refer to “Non-GAAP Measures” at the end of this press release. |
(2) |
Based on weighted average basic common shares outstanding for the period. |
(3) |
All common shares are net of shares held in trust (2020 – 556; 2019 – 801). See “Note 16 to the Audited Consolidated Financial Statements”. |
(4) |
Realized natural gas, oil, and NGL prices included physical forward sales contracts for which delivery was made during the reporting period, along with realized gains and losses on financial derivatives and foreign exchange contracts. |
(5) |
Please refer to “Boe volume conversions” below. |