FOURTH QUARTER 2019 HIGHLIGHTS
Capital Spending, Production and Operations
Financial Highlights
YEAR-END 2019 FINANCIAL AND OPERATING RESULTS
Capital Spending, Production and Operations
Financial Highlights
SEQUOIA LITIGATION
The Court of Queen’s Bench issued its decision related to the Statement of Claim filed on August 3, 2018 against Perpetual and its President and Chief Executive Officer (“CEO”) with respect to the Company’s disposition of shallow gas assets in Eastern Alberta to an unrelated third party on October 1, 2016 (the “Sequoia Litigation”). The decision dismissed and struck all claims against the Company’s CEO and all but one of the claims filed by PwC in its capacity as trustee in bankruptcy (the “Trustee”) against Perpetual. The Court did not find that the test for summary dismissal relating to whether the transaction was an arm’s length transfer for purposes of section 96(1) of the Bankruptcy and Insolvency Act (the “BIA”) was met, on the balance of probabilities. Accordingly, the BIA claim was not dismissed or struck and only that part of the claim can continue against Perpetual. The Trustee filed a notice of appeal with the Court of Appeal of Alberta, contesting the decision, and Perpetual filed a similar notice of appeal contesting the BIA claim portion of the decision. The appeal proceedings are scheduled to be heard in December 2020.
On January 28, 2020, the Court of Appeal issued its decision with respect to Perpetual’s application for security for costs, requiring the Trustee to post security with the Court of Appeal in the amount of $0.2 million. Applications have been filed by the Trustee to appeal the security for costs decision and alter the reasons for the decision. The Court of Appeal is scheduled to hear these applications in June 2020.
On February 25, 2020, Perpetual filed a new application to strike and summarily dismiss the BIA claim on the basis that there was no transfer at undervalue, and Sequoia was not insolvent at the time of the transaction nor caused to be insolvent by the transaction. The Court is scheduled to hear this application in June 2020.
Management expects that the Company is more likely than not to be successful in defending against the Sequoia Litigation such that no damages will be awarded against it, and therefore, no amounts have been accrued as a liability in Perpetual’s financial statements.
2020 GUIDANCE
The Company’s Board of Directors approved a capital spending program of $6 million for the first quarter of 2020 to drill four (4.0 net) multi-lateral horizontal wells at Ukalta. Perpetual’s reserve-based credit facility is currently undergoing its borrowing limit redetermination which is likely to reduce the current $45 million borrowing limit effective March 31, 2020 due to reductions in bank lending commodity price forecasts. Any reductions in the credit facility borrowing limit will reduce the Company’s available liquidity. To preserve liquidity, the Company will defer further capital spending until the credit facility borrowing limit redetermination has been completed. The Company will issue its 2020 Guidance once the borrowing limit redetermination is known and capital spending plans have been determined.
YEAR-END 2019 RESERVES
To preserve value during the low natural gas price environment in 2019, Perpetual limited capital spending on natural gas assets, executing a capital program funded through 2019 adjusted funds flow with investment weighted to heavy oil drilling and waterflood activities. Strong performance of the base assets resulted in 4% growth in proved and probable reserves year-over-year excluding production. Proved and probable reserves in the Company’s Eastern Alberta Heavy Oil properties grew 10% excluding production, while East Edson natural gas and NGL reserves grew 2% excluding production bringing Perpetual’s year-end reserves just one percent lower to 67.1 MMboe, comprised of 17% oil and NGL (2018 – 67.9 MMboe, 15% 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:
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 with an effective date of December 31, 2019 (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, 2019 are summarized below:
Working Interest Reserves at December 31, 2019(1) |
|||||
Light and |
Heavy Oil |
Conventional |
Natural Gas (Mbbl) |
Oil Equivalent |
|
Proved Producing |
16 |
2,177 |
75,183 |
1,324 |
16,047 |
Proved Non-Producing |
– |
106 |
2,035 |
8 |
453 |
Proved Undeveloped |
– |
1,177 |
124,331 |
1,898 |
23,797 |
Total Proved |
16 |
3,460 |
201,549 |
3,230 |
40,298 |
Probable Producing |
4 |
586 |
17,219 |
305 |
3,765 |
Probable Non-Producing |
– |
21 |
6,838 |
83 |
1,244 |
Probable Undeveloped |
– |
1,046 |
109,652 |
2,429 |
21,750 |
Total Probable |
4 |
1,653 |
133,710 |
2,817 |
26,759 |
Total Proved plus Probable |
21 |
5,113 |
335,259 |
6,047 |
67,057 |
(1) May not add due to rounding. |
Total proved reserves at December 31, 2019 account for 60% (2018 – 63%) of total proved plus probable reserves. Proved producing reserves of 16.0 MMboe comprise 40% (2018 – 41%) of total proved reserves. Proved plus probable producing reserves of 19.8 MMboe represent 30% (2018 – 32%) 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, 2018 |
42,461 |
25,439 |
67,899 |
Extensions and Improved Recovery |
191 |
392 |
584 |
Discoveries |
550 |
187 |
737 |
Technical Revisions |
707 |
801 |
1,508 |
Acquisitions |
– |
– |
– |
Dispositions |
– |
– |
– |
Production |
(3,277) |
– |
(3,277) |
Economic Factors |
(334) |
(60) |
(394) |
Closing Balance, December 31, 2019 |
40,298 |
26,759 |
67,057 |
(1) May not add due to rounding. |
McDaniel recorded net positive technical revisions of 1.5 MMboe related to performance on a proved plus probable basis in 2019. Positive technical revisions of 1.1 MMboe were attributed to improved performance of existing wells in both West Central and Eastern areas and 0.4 MMboe were related to increases in reserve assignments relating to drilling locations in the East Edson area.
The table below summarizes the FDC estimated by McDaniel by play type to bring non-producing and undeveloped reserves to production.
Future Development Capital(1) |
|||||||
($ millions) |
2020 |
2021 |
2022 |
2023 |
2024 |
Remainder |
Total |
Eastern Alberta Shallow Gas |
– |
0.5 |
0.7 |
– |
– |
– |
1.1 |
Mannville Heavy Oil |
5.3 |
4.5 |
6.6 |
5.8 |
0 |
– |
22.3 |
Ukalta |
6.7 |
– |
– |
– |
– |
– |
6.7 |
East Edson Wilrich |
22.9 |
44.3 |
33.8 |
38.8 |
37.4 |
151.5 |
328.6 |
Total |
34.9 |
49.3 |
41.1 |
44.6 |
37.4 |
151.5 |
358.8 |
(1) May not add due to rounding. |
McDaniel estimates the FDC required to convert proved plus probable non-producing and undeveloped reserves to proved producing reserves, to be $358.8 million at December 31, 2019, up $12.8 million from year-end 2018. On a proved plus probable basis, FDC decreased by $0.8 million related to the future development of reserves at East Edson and increased $7.0 million in the Mannville heavy oil area and by $6.7 million in the new Ukalta area. The East Edson development plan has 66 (63.3 net) undeveloped locations (2018 – 63.3 net locations) in the total proved plus probable eight-year development plan. The Mannville Heavy Oil area has 19 (19.0 net) undeveloped locations in the total proved plus probable category, an increase of 3 from year-end 2018. The Ukalta Oil area has 5 (5.0 net) undeveloped locations in the total proved plus probable category. The projects are forecast by McDaniel to generate annual operating cash flow in excess of the annual FDC, making the projects self-funding.
RESERVE LIFE INDEX
Perpetual’s proved plus probable reserves to production ratio, also referred to as reserve life index (“RLI”), was 21.5 years at year-end 2019, while the proved RLI was 13.5 years, based upon the 2020 production estimates in the McDaniel Report. The following table summarizes Perpetual’s historical calculated RLI.
Reserve Life Index(1) |
|||||
Year-end |
2019 |
2018 |
2017 |
2016 |
2015 |
Total Proved |
13.4 |
13.1 |
9.1 |
9.3 |
7.3 |
Total Proved plus Probable |
21.5 |
19.9 |
13.2 |
15.1 |
11.9 |
(1) Calculated as year-end reserves divided by year one production estimate from the McDaniel Report. |
NET PRESENT VALUE OF RESERVES SUMMARY
Perpetual’s oil, natural gas and NGL reserves were evaluated by McDaniel using the Consultant Average Price Forecast effective January 1, 2020 and include the forecast impact of the Company’s market diversification contract, but prior to provision for financial oil and natural gas price hedges, foreign exchange contracts, income taxes, interest, debt service charges and general and administrative expenses. The following table summarizes the NPV of future revenue from reserves at January 1, 2020, assuming various discount rates:
NPV of Reserves, before income tax(1)(2) |
|||||||
($ millions except as noted) |
Undiscounted |
5% |
10% |
15% |
Discounted 20% |
Unit Value at 10%/Year ($/boe)(3) |
|
Proved Producing |
81 |
82 |
75 |
68 |
62 |
6.92 |
|
Proved Non-Producing |
2 |
2 |
2 |
1 |
1 |
3.96 |
|
Proved Undeveloped |
231 |
148 |
98 |
67 |
47 |
4.55 |
|
Total Proved |
314 |
231 |
175 |
137 |
110 |
5.32 |
|
Probable Producing |
58 |
39 |
28 |
21 |
17 |
8.26 |
|
Probable Non-Producing |
9 |
6 |
4 |
3 |
2 |
3.43 |
|
Probable Undeveloped |
290 |
156 |
91 |
57 |
38 |
4.61 |
|
Total Probable |
358 |
201 |
123 |
81 |
56 |
5.07 |
|
Total Proved plus Probable |
671 |
432 |
297 |
217 |
167 |
5.22 |
(1) |
January 1, 2020 Consultant Average price forecast and including market diversification contract. |
(2) |
May not add due to rounding. |
(3) |
The unit values are based on net reserve volumes. |
McDaniel’s NPV10 estimate of Perpetual’s total proved plus probable reserves at year-end 2019 was $ 297 million, down 18% from $361.3 million at year-end 2018. The decrease in NPV10 reflected the impact of lower forecast commodity prices, offset by an increase in weighting to higher netback heavy oil reserves. At a 10% discount factor, total proved reserves account for 59% (2018 – 65%) of the proved plus probable value. Proved plus probable producing reserves represent 34% (2018 – 45%) of the total proved plus probable value (discounted at 10%).
FAIR MARKET VALUE OF UNDEVELOPED LAND
Perpetual’s independent third-party estimate of the fair market value of its undeveloped acreage by region for purposes of the NAV calculation is based on past Crown land sale activity, adjusted for tenure and other considerations. In West Central Alberta, no undeveloped land value was assigned where proved and/or probable undeveloped reserves have been booked.
Fair Market Value of Undeveloped Land |
|||
Net Acres |
Value ($ millions) |
$/Acre |
|
Eastern and other |
101,441 |
6.3 |
62.18 |
West Central |
19,173 |
15.6 |
815.57 |
Oil Sands |
96,640 |
14.0 |
145.27 |
Total |
217,255 |
36.0 |
165.63 |
The fair market value of Perpetual’s undeveloped land at year-end 2019, adjusted to remove the value of undeveloped lands with reserves assigned in West Central Alberta, is estimated by an external land consultant at $36.0 million, a decrease of 9% from $39.4 million relative to year-end 2018. The fair market value of undeveloped oil sands leases incorporates the absolute investment to date in the ongoing bitumen extraction pilot project at Panny, with the remaining undeveloped land valued by historical land sale activity, adjusted for tenure.
NET ASSET VALUE
The following NAV table shows what is normally referred to as a “produce-out” NAV calculation under which the Company’s reserves would be produced at forecast future prices and costs. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. It should not be assumed that the NAV represents the fair market value of Perpetual’s shares. The calculations below do not reflect the value of the Company’s prospect inventory to the extent that the prospects are not recognized within the NI 51-101 compliant reserve assessment, except as they are valued through the estimate of the fair market value of undeveloped land.
Pre-tax NAV at December 31, 2019(1) |
||||
Discounted at |
||||
($ millions, except as noted) |
Undiscounted |
5% |
10% |
15% |
Total Proved plus Probable Reserves(2) |
671.4 |
432.0 |
297.3 |
217.3 |
TOU share investment(3) |
15.2 |
15.2 |
15.2 |
15.2 |
Fair market value of undeveloped land(4) |
36.0 |
36.0 |
36.0 |
36.0 |
Bank debt, net of working capital(1) |
(54.6) |
(54.6) |
(54.6) |
(54.6) |
TOU share margin loan(1)(3)(5) |
(0.1) |
(0.1) |
(0.1) |
(0.1) |
Term loan(5) |
(45.0) |
(45.0) |
(45.0) |
(45.0) |
Senior notes(5) |
(33.6) |
(33.6) |
(33.6) |
(33.6) |
Estimate of Additional Future Abandonment and Reclamation Costs(6) |
(0.0) |
(0.0) |
(0.0) |
(0.0) |
Derivatives(7) |
(14.7) |
(14.7) |
(14.7) |
(14.7) |
NAV |
574.6 |
335.2 |
200.5 |
120.5 |
Common shares outstanding (million) |
61.31 |
61.31 |
61.31 |
61.31 |
NAV per share ($/share) |
9.37 |
5.47 |
3.27 |
1.97 |
(1) |
Financial information is per Perpetual’s 2019 audited consolidated financial statements. |
(2) |
Reserve values per McDaniel Report as at December 31, 2019. |
(3) |
Tourmaline Oil Corp. (“TOU”) share value based on 1.0 million shares at December 31, 2019 closing price ($15.22 per share). |
(4) |
Independent third-party estimate; excludes undeveloped land in West Central Alberta with reserves assigned. |
(5) |
Measured at principal amount. |
(6) |
All abandonment obligations including future abandonment and reclamation costs for pipelines and facilities and non-reserve wells are included in the McDaniel Report. |
(7) |
Value as at December 31, 2019, relative to the Consultant Average Price Forecast. Excludes market diversification contract which is included in total proved plus probable reserves. |
The above evaluation includes FDC expectations required to bring undeveloped reserves on production, as recognized by McDaniel, that meet the criteria for booking under NI 51-101. The fair market value of undeveloped land does not reflect the value of the Company’s extensive prospect inventory which is anticipated to be converted into reserves and production over time through future capital investment.
FINDING AND DEVELOPMENT COSTS
Under NI 51-101, the methodology to be used to calculate F&D costs includes incorporating changes in FDC required to bring the proved and probable undeveloped reserves to production. Changes in forecast FDC occur annually as a result of development activities, acquisitions and disposition activities, undeveloped reserve revisions and capital cost estimates that reflect the independent evaluator’s best estimate of what it will cost to bring the proved plus probable undeveloped reserves on production.
2019 F&D Costs(1) |
|||||
($ millions except as noted) |
Proved |
Proved & Probable |
|||
F&D Costs, including FDC |
|||||
Exploration and development capital expenditures(2) |
$ |
12.87 |
$ |
12.87 |
|
Total change in FDC |
$ |
(2.43) |
$ |
12.78 |
|
Total F&D capital, including change in FDC |
$ |
10.44 |
$ |
25.65 |
|
Reserve additions, including revisions (MMboe) |
1.11 |
2.43 |
|||
F&D Costs, including FDC ($/boe) |
$ |
9.37 |
$ |
10.54 |
|
FD&A Costs, including FDC |
|||||
Exploration and development capital expenditures(2) |
$ |
12.87 |
$ |
12.87 |
|
Proceeds on dispositions, net of acquisitions |
$ |
0.0 |
$ |
0.0 |
|
Total change in FDC |
$ |
(2.43) |
$ |
12.78 |
|
Total FD&A capital, including change in FDC |
$ |
10.44 |
$ |
25.65 |
|
Reserve additions, including net acquisitions (MMboe) |
1.11 |
2.43 |
|||
FD&A Costs, including FDC ($/boe) |
$ |
9.37 |
$ |
10.54 |
(1) |
Financial information is per Perpetual’s 2019 preliminary unaudited 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) |
2019 |
2018 |
Change |
2019 |
2018 |
Change |
Financial |
||||||
Oil and natural gas revenue |
15,830 |
21,510 |
(26%) |
74,361 |
86,128 |
(14%) |
Net loss |
(32,498) |
(331) |
(9,718%) |
(94,015) |
(20,380) |
(361%) |
Per share – basic and diluted(2) |
(0.54) |
(0.01) |
(5,300%) |
(1.56) |
(0.34) |
(359%) |
Cash flow from (used in) operating activities |
(1,290) |
5,163 |
(125%) |
17,806 |
31,525 |
(44%) |
Per share(1)(2) |
(0.02) |
0.09 |
(122%) |
0.30 |
0.53 |
(43%) |
Adjusted funds flow(1) |
340 |
8,052 |
(96%) |
14,534 |
30,155 |
(52%) |
Per share(2) |
0.01 |
0.13 |
(92%) |
0.24 |
0.50 |
(52%) |
Revolving bank debt |
47,552 |
42,561 |
12% |
47,552 |
42,561 |
12% |
Senior notes, principal amount |
33,580 |
32,490 |
3% |
33,580 |
32,490 |
3% |
Term loan, principal amount |
45,000 |
45,000 |
– |
45,000 |
45,000 |
– |
TOU share margin demand loan, principal amount |
100 |
14,144 |
(99%) |
100 |
14,144 |
(99%) |
TOU share investment |
(15,220) |
(28,132) |
(46%) |
(15,220) |
(28,132) |
(46%) |
Net working capital deficiency(1) |
7,068 |
6,543 |
8% |
7,068 |
6,543 |
8% |
Total net debt(1) |
118,080 |
112,606 |
5% |
118,080 |
112,606 |
5% |
Net capital expenditures |
||||||
Capital expenditures |
1,995 |
5,617 |
(64%) |
12,939 |
26,888 |
(52%) |
Net proceeds on acquisitions and dispositions |
– |
(1,285) |
(100%) |
– |
(3,030) |
(100%) |
Net capital expenditures |
1,995 |
4,332 |
(54%) |
12,939 |
23,858 |
(46%) |
Common shares outstanding (thousands) |
||||||
End of period(3) |
60,513 |
60,240 |
– |
60,513 |
60,240 |
– |
Weighted average – basic and diluted |
60,444 |
60,448 |
– |
60,258 |
60,039 |
– |
Operating |
||||||
Average production |
||||||
Natural gas (MMcf/d) |
36.6 |
44.9 |
(18%) |
42.3 |
52.6 |
(20%) |
Oil (bbl/d) |
1,275 |
1,301 |
(2%) |
1,224 |
1,050 |
17% |
NGL (bbl/d) |
606 |
715 |
(15%) |
719 |
774 |
(7%) |
Total (boe/d) |
7,991 |
9,491 |
(16%) |
8,988 |
10,594 |
(15%) |
Average prices |
||||||
Realized natural gas price ($/Mcf) |
2.00 |
4.38 |
(54%) |
2.77 |
3.05 |
(9%) |
Realized oil price ($/bbl) |
43.85 |
19.83 |
121% |
44.87 |
40.62 |
10% |
Realized NGL price ($/bbl) |
43.93 |
35.73 |
23% |
41.01 |
52.96 |
(23%) |
Wells drilled |
||||||
Natural gas – gross (net) |
– (–) |
– (–) |
– (–) |
1 (1.0) |
||
Oil – gross (net) |
– (–) |
– (–) |
5 (5.0) |
6 (6.0) |
||
Total – gross (net) |
– (–) |
– (–) |
5 (5.0) |
7 (7.0) |
(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 (2019 – 801; 2018 – 661). See “Note 17 to the Audited Consolidated Financial |
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