CALGARY, Alberta – Petrus Resources Ltd. (“Petrus” or the “Company”) (TSX: PRQ) is pleased to report financial and operating results as at and for the three and twelve months ended December 31, 2021 and to provide 2021 year end reserves information as evaluated by Insite Petroleum Consultants Ltd. (“Insite”). The Company’s Management’s Discussion and Analysis (“MD&A”) and audited consolidated financial statements are available on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com.
An updated corporate presentation as well as the monthly activity update can be found on the Company’s website at www.petrusresources.com.
Q4 2021 HIGHLIGHTS
- Commodity price improvement – Realized price per boe increased by 92% in the fourth quarter of 2021 compared to the fourth quarter of 2020 due to strengthened oil, natural gas and NGL pricing, which increased by 81%, 78% and 140%, respectively.
- Operating netback up 112% – Operating netback(1) increased by 122% to $33.12/boe in the fourth quarter of 2021 up from $14.95/boe in the fourth quarter of 2020.
- Total funds flow up 62% – Petrus generated funds flow and corporate netback(2) of $10.4 million and $19.26/boe in the fourth quarter of 2021, 62% and 75% higher, respectively, than the fourth quarter of the prior year.
- Increased capital activity – Petrus incurred capital expenditures of $12.2 million in the fourth quarter of 2021 compared to $2.8 million in the fourth quarter of 2020. Petrus began execution of its fourth quarter 2021 drilling program in November, which included the Company’s first operated well in North Ferrier. In December, the Company drilled two net wells in its core Ferrier area.
ANNUAL 2021 HIGHLIGHTS
- Transformative debt reduction – During 2021, Petrus executed transactions that transformed its debt position, as follows:
- Reduced net debt(1) by 46% from $114.4 million to $61.8 million;
- Debt to fourth quarter 2021 annualized funds flow (excluding realized hedge settlements) is now 1.5x;
- Second lien term loan settled in full; and
- First lien debt is now fully conforming at $57.7 million drawn.
- Funds flow per boe up 41% – Petrus generated funds flow and corporate netback of $33.4 million and $15.19/boe in 2021, 26% and 40% higher, respectively, than funds flow of $26.4 million and $10.93/boe in 2020.
- Capital expenditures doubled – Petrus incurred $26.9 million of capital expenditures in 2021, compared to $14.3 million in 2020; drilling ten gross (6.4 net) wells in Ferrier and North Ferrier.
- Maintained production – Petrus held production relatively flat at 6,009 boe/d through 2021 as it focused on debt repayment, which limited capital reinvestment during the first nine months of the year.
2022 OUTLOOK(3)
The completion of the debt restructuring transactions during the third quarter of 2021 transformed Petrus from a company with limited capital resources to one with the ability to create meaningful shareholder value. The substantial debt reduction associated with the second lien debt settlement and equity financing has bolstered the Company’s financial position and provides the flexibility required to invest in the development of its land base and unlock proven value.
On March 1, 2022, the Company entered into a definitive agreement to acquire producing oil and gas properties that are held by a privately owned limited partnership and its general partner (the “Acquired Entities”) for total consideration of approximately $14.4 million, consisting of 10 million common shares of the Company issued at a deemed price of $1.44 per share based on the volume weighted average trading price of the common shares of the Company on the TSX for the five trading days prior to the date of the Agreement (the “Acquisition”). The Acquisition is expected to close in March 2022 and is subject to customary closing conditions. For more information, please refer to the related press release dated March 1, 2022.
Petrus’ Board of Directors has approved a 2022 capital budget of $50 to $55 million. Capital will be largely focused on the drilling, completion and tie-in of 14 net wells in Ferrier. The 2022 budget was constructed using a price forecast of WTI at US$69.00/bbl, AECO at $3.20/GJ and a foreign exchange rate of US$0.79. Through the successful execution of this capital plan and with the Acquired Entities now included, Petrus is expecting to:
- Achieve a 2022 exit production rate of 9,000 to 9,500 boe per day (62% conventional natural gas, 25% light crude oil and 13% natural gas liquids), a projected increase of 40 to 50% compared to 2021 average annual production.
- Generate in excess of $60 million in annual funds flow, an anticipated 65 to 80% improvement compared to 2021 results.
- Continue to reduce debt and further strengthen the Company’s balance sheet.
(1)Non-GAAP measure or non-GAAP ratio. Refer to “Non-GAAP and Other Financial Measures” below.
(2)Corporate netback is equal to funds flow, which is a comparable additional GAAP measure. Petrus analyzes these measures on an absolute value and per unit basis. Refer to “Non-GAAP and Other Financial Measures”.
(3)Refer to “Advisories – Forward-Looking Statements” below.
SELECTED FINANCIAL INFORMATION
OPERATIONS | Twelve months ended Dec. 31, 2021 |
Twelve months endedDec. 31, 2020 |
Three months endedDec. 31, 2021 |
Three months endedSept. 30, 2021 |
Three months ended Jun. 30, 2021 |
Three months ended Mar. 31, 2021 |
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Average production | ||||||||||||
Natural gas (mcf/d) | 23,680 | 27,640 | 23,494 | 23,942 | 24,291 | 22,985 | ||||||
Oil (bbl/d) | 1,019 | 1,021 | 1,002 | 937 | 1,214 | 923 | ||||||
NGLs (bbl/d) | 1,043 | 980 | 962 | 1,010 | 1,046 | 1,158 | ||||||
Total (boe/d) | 6,009 | 6,608 | 5,880 | 5,937 | 6,309 | 5,912 | ||||||
Total (boe) | 2,193,432 | 2,418,259 | 540,924 | 546,227 | 574,084 | 532,099 | ||||||
Light oil weighting | 17 | % | 15 | % | 20 | % | 21 | % | 19 | % | 15 | % |
Realized Prices | ||||||||||||
Natural gas ($/mcf) | 4.03 | 2.57 | 5.45 | 4.04 | 3.28 | 3.33 | ||||||
Oil ($/bbl) | 78.82 | 44.14 | 89.71 | 82.56 | 75.99 | 66.61 | ||||||
NGLs ($/bbl) | 44.09 | 20.84 | 56.35 | 45.10 | 39.76 | 36.79 | ||||||
Total realized price ($/boe) | 36.90 | 20.67 | 46.29 | 37.00 | 33.87 | 30.55 | ||||||
Royalty income | 0.14 | 0.16 | 0.06 | 0.18 | 0.19 | 0.15 | ||||||
Royalty expense | (4.72 | ) | (2.15 | ) | (6.34 | ) | (3.94 | ) | (4.87 | ) | (3.74 | ) |
Net oil and natural gas revenue ($/boe) | 32.32 | 18.68 | 40.01 | 33.24 | 29.19 | 26.96 | ||||||
Operating expense | (5.89 | ) | (4.64 | ) | (5.02 | ) | (5.57 | ) | (6.80 | ) | (6.12 | ) |
Transportation expense | (1.79 | ) | (1.43 | ) | (1.87 | ) | (1.81 | ) | (1.84 | ) | (1.62 | ) |
Operating netback(1) ($/boe) | 24.64 | 12.61 | 33.12 | 25.86 | 20.55 | 19.22 | ||||||
Realized gain (loss) on derivatives ($/boe) | (5.34 | ) | 2.70 | (9.52 | ) | (6.41 | ) | (3.21 | ) | (2.28 | ) | |
Other income (cash) | 0.49 | 0.15 | 0.04 | 0.02 | 1.77 | 0.04 | ||||||
General & administrative expense | (1.95 | ) | (1.41 | ) | (2.24 | ) | (1.47 | ) | (2.41 | ) | (1.65 | ) |
Cash finance expense | (2.34 | ) | (2.75 | ) | (1.58 | ) | (3.30 | ) | (2.52 | ) | (1.93 | ) |
Decommissioning expenditures | (0.31 | ) | (0.37 | ) | (0.56 | ) | (0.27 | ) | (0.14 | ) | (0.27 | ) |
Funds flow & corporate netback(2) ($/boe) |
15.19 | 10.93 | 19.26 | 14.43 | 14.04 | 13.13 | ||||||
FINANCIAL (000s except $ per share) | Twelve months ended
Dec. 31, 2021 |
Twelve months ended
Dec. 31, 2020 |
Three months ended
Dec. 31, 2021 |
Three months ended
Sept. 30, 2021 |
Three months ended
Jun. 30, 2021 |
Three months ended
Mar. 31, 2021 |
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Oil and natural gas revenue | 81,268 | 50,368 | 25,070 | 20,306 | 19,553 | 16,339 | ||||||
Net income (loss) | 114,556 | (97,554 | ) | 114,633 | 7,343 | (4,265 | ) | (3,155 | ) | |||
Net income (loss) per share | ||||||||||||
Basic | 1.83 | (1.97 | ) | 1.19 | 0.04 | (0.09 | ) | (0.06 | ) | |||
Fully diluted | 1.76 | (1.97 | ) | 1.11 | 0.03 | (0.09 | ) | (0.06 | ) | |||
Funds flow | 33,354 | 26,397 | 10,418 | 7,874 | 8,070 | 6,993 | ||||||
Funds flow per share | ||||||||||||
Basic | 0.53 | 0.53 | 0.11 | 0.15 | 0.16 | 0.14 | ||||||
Fully diluted | 0.51 | 0.53 | 0.10 | 0.14 | 0.16 | 0.14 | ||||||
Capital expenditures | 26,916 | 14,298 | 12,235 | 6,101 | 663 | 7,917 | ||||||
Weighted average shares outstanding | ||||||||||||
Basic | 62,557 | 49,469 | 96,660 | 54,167 | 49,513 | 49,469 | ||||||
Fully diluted | 65,207 | 49,469 | 102,868 | 57,638 | 49,513 | 49,469 | ||||||
As at period end | ||||||||||||
Common shares outstanding | ||||||||||||
Basic | 96,708 | 49,469 | 96,708 | 96,603 | 49,559 | 49,469 | ||||||
Fully diluted | 103,889 | 49,469 | 103,889 | 100,074 | 49,559 | 49,469 | ||||||
Total assets | 290,492 | 177,914 | 290,492 | 173,101 | 176,629 | 177,587 | ||||||
Non-current liabilities | 42,172 | 45,321 | 42,172 | 40,200 | 40,838 | 42,028 | ||||||
Net debt(1) | 61,779 | 114,361 | 61,779 | 60,071 | 110,346 | 116,634 |
(1)Non-GAAP measure or non-GAAP ratio. Refer to “Non-GAAP and Other Financial Measures” below.
(2)Corporate netback is equal to funds flow, which is a directly comparable GAAP measure. Petrus analyzes these measures on an absolute value and per unit basis. Refer to “Non-GAAP and Other Financial Measures”.
OPERATIONS UPDATE
Fourth quarter average production by area was as follows:
For the three months ended December 31, 2021 |
Ferrier | North Ferrier | Foothills | Central Alberta | Kakwa | Total |
Natural gas (mcf/d) | 16,288 | 1,194 | 1,405 | 4,415 | 163 | 23,465 |
Oil (bbl/d) | 560 | 40 | 109 | 257 | 37 | 1,003 |
NGLs (bbl/d) | 799 | 26 | 5 | 132 | 4 | 966 |
Total (boe/d) | 4,073 | 265 | 347 | 1,126 | 69 | 5,880 |
Fourth quarter 2021 production averaged 5,880 boe/d compared to 5,937 boe/d in the previous quarter. Three gross (3.0 net) wells were drilled with one well brought on production late in the quarter adding 114 boe/d to the fourth quarter average, which offset natural declines. Production was relatively consistent quarter over quarter.
RESERVES
Petrus’ 2021 year end reserves were evaluated by independent reserves evaluator, InSite Petroleum Consultants Ltd. (“Insite”), in accordance with the 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”) as of December 31, 2021 (“2021 Insite Report”). Additional reserve information as required under NI 51-101 will be included in our Annual Information Form for the year ended December 31, 2021, which will be available under the Company’s profile on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com.
Petrus has a reserves committee, comprised of a majority of independent board members, that reviews the qualifications and appointment of the independent reserves evaluator. The committee also reviews the procedures for providing information to the evaluators. All booked reserves are based upon annual evaluations by the independent qualified reserve evaluator conducted in accordance with the COGE Handbook and NI 51-101. The evaluations are conducted using all available geological and engineering data. The reserves committee has reviewed the reserves information and approved the 2021 Insite Report.
The following table provides a summary of the Company’s before tax reserves as evaluated by Insite:
As at December 31, 2021 | Total Company Interest (1)(3) | ||||||
Reserve Category | Conventional Natural Gas (mmcf) |
Light and Medium Crude Oil (mbbl) |
NGL (mbbl) |
Total (mboe) |
NPV 0%(2) ($000s) |
NPV 5%(2) ($000s) |
NPV 10%(2) ($000s) |
Proved Producing | 49,580 | 885 | 2,550 | 11,698 | 119,994 | 136,554 | 128,517 |
Proved Non-Producing | 1,066 | 2 | 24 | 204 | 1,756 | 1,509 | 1,329 |
Proved Undeveloped | 82,065 | 1,725 | 5,797 | 21,200 | 302,220 | 193,014 | 130,575 |
Total Proved | 132,711 | 2,612 | 8,371 | 33,101 | 423,970 | 331,078 | 260,421 |
Proved + Probable Producing | 59,462 | 1,057 | 3,049 | 14,017 | 163,359 | 162,738 | 146,541 |
Total Probable | 67,070 | 2,300 | 3,812 | 17,291 | 321,029 | 193,091 | 130,210 |
Total Proved Plus Probable | 199,781 | 4,912 | 12,183 | 50,392 | 744,999 | 524,168 | 390,631 |
(1)Tables may not add due to rounding.
(2)NPV 0%, NPV 5% and NPV 10% refer to the risked net present value of the future net revenue of the Company’s reserves, discounted by 0%, 5% and 10%, respectively and is presented before tax and based on Insite’s pricing assumptions.
(3)Total company interest reserve volumes presented above and in the remainder of this press release are presented as the Company’s total working interest before the deduction of royalties (but after including any royalty interests of Petrus).
In 2021, Petrus’ development program generated proved developed producing (“PDP”) reserve volume additions of 3.0 mmboe. The Company produced 2.2 mmboe and had dispositions of 1.3 mmboe of PDP reserves. The Company ended the year with 11.7 mmboe of PDP reserves (29% crude oil and liquids).
Petrus ended 2021 with $129.9 million, $260.4 million and $390.6 million of Proved Developed (“PD”), Total Proved (“TP”), and Proved plus Probable (“P+P”), respectively, reserve value before-tax, discounted at 10%, based on the 2021 Insite Report. In 2021, the Company realized Finding, Development and Acquisition (“FD&A”) costs of $15.64/boe for PDP reserves.
Based on the 2021 Insite Report, the Company’s PDP reserve value before-tax, discounted at 10% is $1.33 per share (96,707,912 basic common shares outstanding at December 31, 2021). On the same basis, the P+P reserve value before tax, discounted at 10%, is $4.04 per share.
FUTURE DEVELOPMENT COST
Future Development Cost (“FDC”) reflects Insite’s best estimate of what it will cost to bring the P+P undeveloped reserves on production. The following table provides a summary of the Company’s FDC as set forth in the 2021 Insite Report:
Future Development Cost ($000s) |
Total Proved | Total Proved + Probable |
2022 | 49,560 | 49,560 |
2023 | 68,890 | 76,030 |
2024 | 68,752 | 68,752 |
2025 | 40,854 | 82,203 |
2026 | 5,629 | 66,942 |
Total FDC, Undiscounted | 233,684 | 343,489 |
Total FDC, Discounted at 10% | 194,687 | 270,860 |
PERFORMANCE RATIOS
The following table highlights annual performance ratios for the Company from 2017 to 2021(3):
December 31, 2021 | December 31, 2020 | December 31, 2019 | December 31, 2018 | December 31, 2017 | |||
Proved Producing | |||||||
FD&A ($/boe) (1)(2) | 15.64 | 4.83 | 13.31 | 37.76 | 13.05 | ||
F&D ($/boe) (1)(2) | 8.90 | 4.83 | 12.81 | 42.27 | 11.57 | ||
Reserve Life Index (yr) (1) | 5.4 | 5.2 | 3.8 | 4.6 | 4.1 | ||
Reserve Replacement Ratio (1) | 1.4 | 1.2 | 0.4 | 0.2 | 1.6 | ||
FD&A Recycle Ratio (1) | 1.6 | 2.6 | 1.2 | 0.4 | 1.1 | ||
Proved Developed | |||||||
FD&A ($/boe) (1)(2) | 14.54 | 4.71 | 12.49 | 11.34 | 16.74 | ||
F&D ($/boe) (1)(2) | 8.53 | 4.71 | 12.03 | 11.55 | 14.62 | ||
Reserve Life Index (yr) (1) | 5.5 | 5.2 | 4.8 | 5.6 | 4.5 | ||
Reserve Replacement Ratio (1) | 1.4 | 1.2 | 0.5 | 0.6 | 1.2 | ||
FD&A Recycle Ratio (1) | 1.7 | 2.7 | 1.3 | 1.4 | 0.9 | ||
Total Proved | |||||||
FD&A ($/boe) (1)(2) | 10.51 | 1.29 | 1.09 | 8.73 | 14.33 | ||
F&D ($/boe) (1)(2) | 9.24 | 1.29 | (6.83 | ) | 8.16 | 12.03 | |
Reserve Life Index (yr) (1) | 15.3 | 10.9 | 9.9 | 11.1 | 8 | ||
Reserve Replacement Ratio (1) | 5.1 | (1 | ) | 0.3 | 1.3 | 1.1 | |
FD&A Recycle Ratio (1) | 2.3 | 9.8 | 14.4 | 1.8 | 1 | ||
Future Development Cost ($000s) | 233,684 | 156,815 | 174,027 | 194,757 | 182,086 | ||
Total Proved + Probable | |||||||
FD&A ($/boe) (1)(2) | 10.57 | 0.37 | (7.32 | ) | 6.49 | 14.87 | |
F&D ($/boe) (1)(2) | 8.36 | 0.37 | 190.21 | 5.15 | 17.28 | ||
Reserve Life Index (yr) (1) | 23.3 | 17.7 | 15.4 | 17.1 | 12.3 | ||
Reserve Replacement Ratio (1) | 6.4 | (1.3 | ) | — | 1.5 | 1.7 | |
FD&A Recycle Ratio (1) | 2.3 | 33.7 | (2.1 | ) | 2.4 | 1.0 | |
Future Development Cost ($000s) | 343,489 | 252,335 | 267,652 | 290,876 | 283,030 |
(1)Refer to “Oil and Gas Disclosures” below.
(2)Certain changes in FD&A costs and F&D costs produce non-meaningful figures as discussed in “Oil and Gas Disclosures” below.
(3)While FD&A costs and F&D costs, reserve life index, reserve replacement ratio and FD&A recycle ratio are commonly used in the oil and nature gas industry and have been prepared by management, these terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies and, therefore, should not be used to make such comparisons.
NET ASSET VALUE
The following table shows the Company’s Net Asset Value (“NAV”), calculated using the 2021 Insite Report and Insite’s December 31, 2021 price forecast:
As at December 31, 2021 ($000s except per share) | Proved Developed Producing | Total Proved | Proved + Probable | ||||||
Present Value Reserves, before tax (discounted at 10%) (1) | 128,517 | 260,421 | 390,631 | ||||||
Undeveloped Land Value (2) | 35,634 | 35,634 | 35,634 | ||||||
Net Debt (3) | (61,779 | ) | (61,779 | ) | (61,779 | ) | |||
Net Asset Value | 102,372 | 234,276 | 364,486 | ||||||
Fully Diluted Shares Outstanding | 103,889 | 103,889 | 103,889 | ||||||
Estimated Net Asset Value per Share | $0.99 | $2.26 | $3.51 |
(1)Based on the 2021 Insite Report, using the forecast future prices and costs.
(2)Based on the exploration and evaluation assets as per the Company’s December 31, 2021 audited consolidated financial statements.
(3)See “Non-GAAP and Other Financial Measures” below.
ANNUAL GENERAL MEETING
The Company’s Annual General Meeting will be held at 240FOURTH (previously BP Centre) 240, 4th Ave SW Calgary, Alberta, on Thursday May 12, 2022 at 1:30 p.m. (Calgary time).