CALGARY, Alberta, March 14, 2019 (GLOBE NEWSWIRE) — Petrus Resources Ltd. (“Petrus” or the “Company”) (TSX: PRQ) is pleased to report financial and operating results for the three and twelve month periods ended December 31, 2018 and to provide 2018 year end reserves information as evaluated by Sproule Associates Limited (“Sproule”). The Company’s Management’s Discussion and Analysis (“MD&A”) and audited consolidated financial statements dated as at and for the year ended December 31, 2018 are available on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com.
In 2018, the Company’s primary objectives were to improve its financial position and to increase its light oil weighting. This was done in order to increase the value of its production and funds flow per share. The Company’s Ferrier Cardium asset base provides optionality between natural gas and light oil which allows the Company’s development program to respond to changes in commodity pricing. The Company planned to invest $25 to $30 million in 2018, directed toward drilling Cardium light oil wells in Ferrier and targeted debt reduction of $10 to $15 million. Petrus substantially achieved these objectives in 2018: $24.1 million was invested in 2018 to drill 10 gross (4.3 net) Cardium light oil wells in Ferrier, each with a significantly higher number of multi-stage fracs than had been used in the past. The Company’s December 2018 light oil weighting increased 59% from January 2018 and the full impact of the higher liquids weighting is expected to be represented in 2019(2). The Company ended 2018 with net debt(1) of $139.2 million, which is an $8.9 million or 6% decrease since December 31, 2017(1).
- Light oil development – In 2018 Petrus set out to prove its Cardium light oil inventory and maximize its return on investment by significantly increasing the number of fracture stimulations used in its completion operations. Petrus drilled or participated in 2 gross (0.7 net) Cardium condensate wells during the first half of 2018. Petrus strategically deferred further capital development until the second half of 2018 in order to permit debt repayment early in the year as well as to provide time to analyze well performance to evaluate the new completion techniques. The Company’s 2018 operated drilling program resumed in the second half of 2018 with 5 gross (2.9 net) Cardium light oil wells drilled and fracture stimulated with an average of 76 stages per one mile lateral length. The December test production, over a 14 day period, attributed to Petrus’ 2.9 net additional wells was approximately 2,000 boe/d(3), which was comprised of 50% light oil (60% total liquids). The light oil test rates of approximately 1,000 boe/d nearly doubled Petrus’ light oil production reported for the third quarter of 2018 of 1,243 boe/d. Petrus is pleased with the results of the 2018 drilling program and looks forward to continued development of its Cardium light oil in Ferrier in a consistent, disciplined manner. The Company plans to drill throughout 2019 within funds flow and repay $1 to $2 million of debt each quarter. Petrus’ Board of Directors has approved a second quarter 2019 capital budget of $7 to $8 million, based on a current forecast for commodity futures pricing, anticipated service costs and current activity levels.
- Increased liquids weighting – Fourth quarter average production was 7,934 boe/d in 2018 compared to 10,711 boe/d in 2017. The new liquids production related to the fourth quarter 2018 wells is not reflected for a full quarter as the wells were brought on stream in December. The new production is more valuable in the current commodity environment as the light oil and total liquids weighting have increased significantly. The Company’s December 2018 light oil weighting increased 59% from January 2018. Similarly, the Company’s December 2018 total liquids weighting was 40% which is a 43% increase from January 2018. The Company’s operating netback increased 5% from $14.33 per boe(3) in 2017 to $15.08 per boe in 2018; however the full impact of the increase in liquids weighting is not reflected due to when the new wells were brought on-stream, in late December.
- Company best F&D costs – In 2018, the Company realized Finding and Development (“F&D”) costs of $5.15/boe and $8.16/boe for Proved Plus Probable (“P+P”) and Total Proved (“TP”), respectively. These finding costs were the best in the Company’s history. In terms of deploying capital to create reserves volume and value, this was the most effective year Petrus has ever had.
- Reserve value growth – Petrus ended 2018 with $316 million and $507 million of Total Proved (“TP”) and Proved Plus Probable (“P+P”), respectively, reserve values before-tax, discounted at 10%. The reserve values increased by 1% and 5%, respectively, from the December 31, 2017 Sproule Report. Absent of any changes to the December 31, 2017 Sproule Price forecast, the reserve values would have increased by 22% and 24%, respectively. In 2018, Petrus was also able to increase its Reserve Life Index in every reserve category.
- Best in class operating costs – Total operating expenses were 6% lower from 2017 at $4.75 per boe in 2018 which is the lowest operating cost in the Company’s history (a 57% decrease since 2012) and marks the third consecutive year of operating cost reductions. The Company continues to focus on optimizing its cost structure, particularly in the Ferrier area, through facility ownership and control.
- Funds flow – Petrus generated funds flow of $5.0 million in the fourth quarter of 2018 which is lower than the $13.1 million generated in the fourth quarter of 2017 primarily due to significantly lower market price of Edmonton light oil and natural gas (AECO) during the fourth quarter of 2018. Relative to global oil prices (West Texas Intermediate), Western Canadian light oil traded at historically high differentials in the fourth quarter mainly due to insufficient take away capacity. On December 2, 2018 the Alberta government announced a production curtailment mandate of 325,000 boe/d of Alberta crude oil production effective January 1, 2019. In February, the Alberta government announced plans to transport 120,000 boe/d via rail by 2020. These measures were intended to help alleviate current take away capacity constraints impacting Alberta producers and to reduce storage levels. The temporary production reduction applies to all operators in Alberta producing in excess of 10,000 barrels per day of oil production. Petrus’ oil production is within the 10,000 barrels per day and therefore the Company is exempt from reducing production. As a result of these measures, the differential for Western Canadian light oil prices has tightened significantly.
- Commodity price risk mitigation – Petrus utilizes financial derivative contracts to mitigate commodity price risk and provide stability and sustainability to the Company’s economic returns, funds flow and capital development plan. During the fourth quarter, the Company recognized a $1.3 million ($1.38 per boe) realized gain related to natural gas, offset by a $1.9 million ($2.61 per boe) realized loss related to light oil. As a percentage of fourth quarter 2018 production, Petrus has derivative contracts in place for 52%, at an average price of $2.00/mcf and 53% at an average price of $68.79/bbl, of its natural gas and oil and natural gas liquids production, respectively, for 2019.
(1) Refer to “Non-GAAP Financial Measures”.
(2) Refer to “Advisories – Forward-Looking Statements”.
(3) Refer to “Oil and Gas Disclosures”.
SELECTED FINANCIAL INFORMATION
OPERATIONS | Twelve months ended Dec. 31, 2018 |
Twelve months ended Dec. 31, 2017 |
Three months ended Dec. 31, 2018 |
Three months ended Sept. 30, 2018 |
Three months ended Jun. 30, 2018 |
Three months ended Mar. 31, 2018 |
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Average Production | ||||||||||||
Natural gas (mcf/d) | 37,101 | 43,747 | 30,480 | 33,461 | 39,126 | 45,543 | ||||||
Oil (bbl/d) | 1,402 | 1,823 | 1,358 | 1,243 | 1,484 | 1,530 | ||||||
NGLs (bbl/d) | 1,433 | 1,103 | 1,496 | 1,519 | 1,241 | 1,475 | ||||||
Total (boe/d) | 9,019 | 10,217 | 7,934 | 8,338 | 9,246 | 10,596 | ||||||
Total (boe) | 3,292,828 | 3,729,095 | 730,819 | 767,095 | 841,316 | 953,598 | ||||||
Natural gas sales weighting | 69 | % | 71 | % | 64 | % | 67 | % | 71 | % | 72 | % |
Realized Prices | ||||||||||||
Natural gas ($/mcf) | 1.73 | 2.39 | 1.95 | 1.50 | 1.24 | 2.18 | ||||||
Oil ($/bbl) | 69.74 | 59.56 | 52.26 | 77.24 | 75.29 | 73.91 | ||||||
NGLs ($/bbl) | 40.50 | 31.52 | 29.01 | 45.27 | 41.53 | 46.50 | ||||||
Total realized price ($/boe) | 24.40 | 24.26 | 21.91 | 25.79 | 22.92 | 26.50 | ||||||
Royalty income | 0.12 | 0.02 | 0.10 | 0.32 | 0.05 | 0.03 | ||||||
Royalty expense | (3.54 | ) | (3.56 | ) | (3.34 | ) | (3.12 | ) | (2.54 | ) | (4.90 | ) |
Net oil and natural gas revenue ($/boe) | 20.98 | 20.72 | 18.67 | 22.99 | 20.43 | 21.63 | ||||||
Operating expense | (4.75 | ) | (5.08 | ) | (5.28 | ) | (4.95 | ) | (4.57 | ) | (4.36 | ) |
Transportation expense | (1.15 | ) | (1.31 | ) | (1.17 | ) | (0.98 | ) | (1.17 | ) | (1.26 | ) |
Operating netback (1) ($/boe) | 15.08 | 14.33 | 12.22 | 17.06 | 14.69 | 16.01 | ||||||
Realized gain (loss) on derivatives ($/boe) | (0.90 | ) | 1.00 | (0.79 | ) | (2.69 | ) | (0.74 | ) | 0.31 | ||
Other income | 0.13 | — | 0.37 | 0.08 | 0.12 | — | ||||||
General & administrative expense | (1.57 | ) | (0.87 | ) | (1.46 | ) | (1.72 | ) | (1.63 | ) | (1.50 | ) |
Cash finance expense | (2.51 | ) | (1.88 | ) | (3.25 | ) | (2.53 | ) | (2.49 | ) | (1.96 | ) |
Decommissioning expenditures | (0.14 | ) | (0.52 | ) | (0.21 | ) | (0.20 | ) | — | (0.23 | ) | |
Funds flow and corporate netback (1) ($/boe) | 10.09 | 12.06 | 6.88 | 10.00 | 9.95 | 12.63 | ||||||
FINANCIAL (000s except per share) | Twelve months ended Dec. 31, 2018 |
Twelve months ended Dec. 31, 2017 |
Three months ended Dec. 31, 2018 |
Three months ended Sept. 30, 2018 |
Three months ended Jun. 30, 2018 |
Three months ended Mar. 31, 2018 |
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Oil and natural gas revenue | 80,716 | 90,569 | 16,064 | 20,030 | 19,321 | 25,301 | ||||||
Net income (loss) | (3,284 | ) | (111,261 | ) | 21,063 | (8,048 | ) | (10,615 | ) | (5,684 | ) | |
Net income (loss) per share | ||||||||||||
Basic | (0.07 | ) | (2.28 | ) | 0.43 | (0.16 | ) | (0.21 | ) | (0.11 | ) | |
Fully diluted | (0.07 | ) | (2.28 | ) | 0.43 | (0.16 | ) | (0.21 | ) | (0.11 | ) | |
Funds flow | 33,184 | 45,003 | 5,030 | 7,685 | 8,364 | 12,105 | ||||||
Funds flow per share | ||||||||||||
Basic | 0.67 | 0.92 | 0.10 | 0.16 | 0.17 | 0.24 | ||||||
Fully diluted | 0.67 | 0.92 | 0.10 | 0.16 | 0.17 | 0.24 | ||||||
Capital expenditures | 24,098 | 72,750 | 12,660 | 3,637 | 1,745 | 6,056 | ||||||
Net acquisitions (dispositions) | (448 | ) | 4,741 | (6 | ) | (50 | ) | (269 | ) | (123 | ) | |
Weighted average shares outstanding | ||||||||||||
Basic | 49,492 | 48,825 | 49,492 | 49,492 | 49,492 | 49,492 | ||||||
Fully diluted | 49,492 | 48,825 | 49,492 | 49,492 | 49,492 | 49,492 | ||||||
As at period end | ||||||||||||
Common shares outstanding | ||||||||||||
Basic | 49,492 | 49,492 | 49,492 | 49,492 | 49,492 | 49,492 | ||||||
Fully diluted | 49,492 | 49,492 | 49,492 | 49,492 | 49,492 | 49,492 | ||||||
Total assets | 341,820 | 353,445 | 341,820 | 322,335 | 330,359 | 343,161 | ||||||
Non-current liabilities | 171,646 | 173,272 | 171,646 | 170,908 | 172,757 | 174,634 | ||||||
Net debt (1) | 139,214 | 148,066 | 139,214 | 131,603 | 135,111 | 142,238 |
(1)Refer to “Non-GAAP Financial Measures”.
(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.
OPERATIONS UPDATE
Production
Fourth quarter average production by area was as follows:
For the three months ended December 31, 2018 | Ferrier | Foothills | Central Alberta | Total | ||||
Natural gas (mcf/d) | 22,254 | 1,998 | 6,228 | 30,480 | ||||
Oil (bbl/d) | 812 | 160 | 386 | 1,358 | ||||
NGLs (bbl/d) | 1,317 | 5 | 174 | 1,496 | ||||
Total (boe/d) | 5,837 | 499 | 1,598 | 7,934 | ||||
Natural gas sales weighting | 58 | % | 66 | % | 65 | % | 64 | % |
Petrus set out in 2018 to prove its Cardium light oil inventory and maximize its return on investment by significantly increasing the number of fracture stimulations used in its completion operations. Petrus drilled or participated in 2 gross (0.7 net) Cardium condensate wells during the first half of 2018. Petrus strategically deferred further capital development until the second half of 2018 in order to permit debt repayment early in the year as well as to provide time to analyze well performance to evaluate the new completion techniques. The Company’s 2018 operated drilling program resumed in the second half of 2018 with 5 gross (2.9 net) Cardium light oil wells drilled and fracture stimulated with an average of 76 stages per one mile lateral length. The December test production, over a 14 day period, attributed to Petrus’ 2.9 net additional wells was approximately 2,000 boe/d, which was comprised of 50% light oil (60% total liquids). The light oil test rates of approximately 1,000 boe/d nearly doubled Petrus’ light oil production reported for the third quarter of 2018 of 1,243 boe/d. Petrus is pleased with the results of the 2018 drilling program and looks forward to continue development of its Cardium light oil in Ferrier in a consistent, disciplined manner. The Company plans to drill evenly throughout 2019 within funds flow and repay $1 to $2 million of debt each quarter.
Fourth quarter average production was 7,934 boe/d in 2018 compared to 10,711 boe/d in 2017. Looking at the Company’s recent change in total boe production rates is inaccurate as an evaluation of potential cash flow and value. In the current commodity price environment, as liquids weighting increases, cash flow and value can increase despite lower overall boe production. The new liquids production related to the fourth quarter 2018 wells is not reflected for a full quarter as the wells were brought on-stream in December. The resulting production is more valuable in the current commodity environment as the light oil and total liquids weighting has increased significantly. The Company’s December 2018 light oil weighting increased 59% from January 2018. Similarly, the Company’s December 2018 total liquids weighting was 40% which is a 43% increase from January 2018. The Company’s operating netback increased 5% from $14.33 per boe in 2017 to $15.08 per boe in 2018; however the full impact of the increase in liquids weighting is not reflected due to when the new wells were brought on stream, in late December.
In 2018, the Company’s drilling program proved that the Ferrier Cardium asset base provides optionality between natural gas or light oil development. This optionality permits the Company’s development program to be agile and efficiently respond to changes in commodity pricing.
Petrus’ Board of Directors has approved a first quarter 2019 capital budget of $8 to $10 million, based on a current forecast for commodity futures pricing, anticipated service costs and current activity levels. Management anticipates that the 2019 capital plan will be fully funded by funds flow, systematically scheduled evenly through the year to maintain flexibility, and permit debt reduction each quarter. In the first quarter of 2019 the Company expects to generate funds flow between $10 and $11 million, with the remaining $1 to $2 million to be directed toward debt repayment. The commodity price assumptions used for the first quarter 2019 capital budget were an average price of $1.31 C$/GJ for natural gas (AECO) and $53.03 US$/bbl for oil (WTI). Petrus’ estimated first quarter average differential for Western Canadian light oil is estimated at $7.55 US$/bbl. The first quarter capital budget is expected to include the drilling of 5 gross (2.0 net) Cardium wells targeting the most condensate rich areas within the reservoir.
As part of the 2019 first quarter capital budget, Petrus has drilled 2 gross (1.2 net) Cardium light oil wells. The wells have finished drilling and offset the recently drilled 5 gross (2.9 net) wells from the fourth quarter 2018 drilling program. The 2 first quarter 2019 wells have 1.5 mile and 1.0 mile horizontal lateral lengths, respectively. Both wells are being fracture stimulated with 124 and 77 stages, respectively. Completion operations are currently ongoing and the wells’ test volumes can flow inline as the wells were drilled from pre-existing surface locations. Both wells are expected to be on production by the end of March.
Petrus’ Board of Directors has approved a second quarter 2019 capital budget of $7 to $8 million, based on a current forecast for commodity futures pricing, anticipated service costs and current activity levels. The second quarter budget will allow for debt repayment of $1 to $2 million in the quarter.
Petrus estimates the 2019 capital plan will maintain production year over year, increase its oil and total liquids weighting, and reduce debt throughout the year. Approximately 85% of the capital plan will be directed to development of Cardium light oil wells in the Ferrier area of Alberta, which we estimate will have payouts of less than one year and achieve its objective to increase its light oil production weighting and funds flow.
(1) Refer to “Advisories – Forward-Looking Statements”.
RESERVES
Petrus’ 2018 year end reserves were evaluated by independent reserves evaluator Sproule Associates Limited (“Sproule”) 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, 2018 (“2018 Sproule Report”). Additional reserve information as required under NI 51-101 will be included in our Annual Information Form for the year ended December 31, 2018, which will be filed on SEDAR.
Petrus has a reserves committee, comprised of independent board members, that reviews the qualifications and appointment of the independent reserve evaluators. 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 evaluators 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 2018 Sproule Report.
The following table provides a summary of the Company’s before tax reserves as evaluated by Sproule:
As at December 31, 2018 | 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 | 52,491 | 1,250 | 3,388 | 13,386 | 258,437 | 211,579 | 181,588 | |||||||
Proved Non-Producing | 16,980 | 94 | 121 | 3,044 | 21,959 | 16,299 | 12,754 | |||||||
Proved Undeveloped | 57,180 | 1,474 | 4,882 | 15,887 | 249,274 | 172,272 | 121,860 | |||||||
Total Proved | 126,650 | 2,818 | 8,391 | 32,317 | 529,671 | 400,149 | 316,203 | |||||||
Proved + Probable Producing | 67,773 | 1,672 | 4,255 | 17,223 | 348,210 | 264,084 | 216,812 | |||||||
Total Probable | 65,072 | 2,519 | 4,320 | 17,684 | 390,858 | 262,581 | 190,929 | |||||||
Total Proved Plus Probable | 191,723 | 5,337 | 12,710 | 50,001 | 920,528 | 662,730 | 507,132 |
(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 Nil, 5% and 10%, respectively and is presented before tax and based on Sproule’s pricing assumptions.
(3)Total company interest reserve volumes are presented above and in the remainder of this annual report are presented as the Company’s total working interest before the deduction of royalties (but after including any royalty interests of Petrus).
In 2018, Petrus’ development program generated Proved Developed Producing (“PDP”) reserve volume additions of 0.6 mmboe which were comprised of 100% liquids. The Company produced 3.3 mmboe during 2018 and ended the year with 13.4 mmboe of PDP reserve volume. Petrus’ PDP liquids percentage increased from 28% in 2017 to 35% in 2018.
Petrus ended 2018 with $194.3 million, $316.2 million and $507.1 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 2018 Sproule Report. In 2018, the Company realized Finding and Development (“F&D”) costs(3) of $11.55/boe, $8.16/boe and $5.15/boe for PD, TP and P+P reserves, respectively. PDP F&D costs were materially influenced by the shut in of uneconomic dry gas volumes in the Foothills; therefore, PD is a more indicative metric for developed finding costs in 2018.
Based on the 2018 Sproule Report, the Company’s PDP reserve value before-tax, discounted at 10% is $ 3.67 per share. On the same basis, the P+P reserve value is $10.25 per share.
FUTURE DEVELOPMENT COST
Future Development Cost (“FDC”) reflects Sproule’s best estimate of what it will cost to bring the P+P undeveloped reserves on production. FDC associated with Petrus’ total P+P reserves at December 31, 2018, based on the 2018 Sproule Report, is $290.9 million (undiscounted) and includes 230 gross (128.2 net) booked P+P locations.
The following table provides a summary of the Company’s FDC as set forth in the 2018 Sproule Report:
Future Development Cost ($000s) | Total Proved | Total Proved + Probable | ||
2018 | 67,578 | 81,596 | ||
2019 | 79,748 | 147,315 | ||
2020 | 45,822 | 60,356 | ||
2021 | 1,609 | 1,609 | ||
Thereafter | — | — | ||
Total FDC, Undiscounted | 194,757 | 290,876 | ||
Total FDC, Discounted at 10% | 172,129 | 255,422 |
PERFORMANCE RATIOS
The following table highlights annual performance ratios for the Company from 2014 to 2018:
December 31, 2018 | December 31, 2017 | December 31, 2016 | December 31, 2015 | December 31, 2014 | ||||||
Proved Producing | ||||||||||
FD&A ($/boe) (1)(2) | 37.76 | 13.05 | (0.43 | ) | 23.18 | 35.35 | ||||
F&D ($/boe) (1)(2) | 42.27 | 11.57 | 9.89 | 29.80 | 59.67 | |||||
Reserve Life Index (yr) (1) | 4.6 | 4.1 | 4.4 | 5.2 | 4.6 | |||||
Reserve Replacement Ratio (1) | 0.2 | 1.6 | 0.4 | 0.7 | 5.9 | |||||
FD&A Recycle Ratio (1) | 0.4 | 1.1 | (24.8 | ) | 0.7 | 0.8 | ||||
Proved Developed | ||||||||||
FD&A ($/boe) (1)(2) | 11.34 | 16.74 | (0.23 | ) | 39.85 | 32.06 | ||||
F&D ($/boe) (1)(2) | 11.55 | 14.62 | 7.69 | 65.74 | 68.87 | |||||
Reserve Life Index (yr) (1) | 5.6 | 4.5 | 5.3 | 5.8 | 5.4 | |||||
Reserve Replacement Ratio (1) | 0.6 | 1.2 | 0.7 | 0.4 | 6.5 | |||||
FD&A Recycle Ratio (1) | 1.4 | 0.9 | (46.3 | ) | 0.4 | 0.9 | ||||
Total Proved | ||||||||||
FD&A ($/boe) (1)(2) | 8.73 | 14.33 | (15.78 | ) | 16.77 | 27.82 | ||||
F&D ($/boe) (1)(2) | 8.16 | 12.03 | 2.46 | 21.02 | 122.89 | |||||
Reserve Life Index (yr) (1) | 11.1 | 8.0 | 9.8 | 10.9 | 7.3 | |||||
Reserve Replacement Ratio (1) | 1.3 | 1.1 | 0.5 | 2.9 | 9.1 | |||||
FD&A Recycle Ratio (1) | 1.8 | 1.0 | (0.7 | ) | 0.9 | 1.0 | ||||
Future Development Cost ($000s) | 194,757 | 182,086 | 201,556 | 223,409 | 122,326 | |||||
Total Proved + Probable | ||||||||||
FD&A ($/boe) (1)(2) | 6.49 | 14.87 | 350.09 | 15.40 | 21.49 | |||||
F&D ($/boe) (1)(2) | 5.15 | 17.28 | (8.06 | ) | 19.01 | (604.56 | ) | |||
Reserve Life Index (yr) (1) | 17.1 | 12.3 | 14.6 | 16.4 | 11.2 | |||||
Reserve Replacement Ratio (1) | 1.5 | 1.7 | (0.1 | ) | 3.7 | 12.7 | ||||
FD&A Recycle Ratio (1) | 2.4 | 1.0 | — | 1.0 | 1.3 | |||||
Future Development Cost ($000s) | 290,876 | 283,030 | 269,144 | 325,325 | 199,410 |
(1)Refer to “Oil and Gas Disclosures”.
(2)Certain changes in FD&A and F&D produce non-meaningful figures as discussed in “Oil and Gas Disclosures”.
While FD&A and F&D costs, reserve life index, reserve replacement ratio and finding and development costs 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.
FD&A and F&D costs take into account reserves revisions during the year on a per boe basis. The aggregate of the exploration and development costs incurred in the financial year and changes during that year in estimated future development costs generally will not reflect total FD&A and F&D costs related to reserves additions for that year.
NET ASSET VALUE
The following table shows the Company’s Net Asset Value (“NAV”), calculated using the price forecast from Sproule:
As at December 31, 2018 ($000s except per share) |
Proved Developed Producing |
Total Proved |
Proved + Probable |
||||||
Present Value Reserves, before tax (discounted at 10%) (1) | 181,588 | 316,203 | 507,132 | ||||||
Undeveloped Land Value (2) | 42,410 | 42,410 | 42,410 | ||||||
Net Debt (3) | (139,214 | ) | (139,214 | ) | (139,214 | ) | |||
Net Asset Value | 84,784 | 219,399 | 410,328 | ||||||
Fully Diluted Shares Outstanding (4) | 49,492 | 49,492 | 49,492 | ||||||
Estimated Net Asset Value per Share | $1.71 |
$4.43 |
$8.29 |
(1)Based on the 2018 Sproule Report, using the forecast future prices and costs.
(2)Based on the exploration and evaluation assets as per the Company’s December 31, 2018 audited consolidated financial statements.
(3)See “Non-GAAP Financial Measures”.
(4)There were no “in-the-money” options or warrants based on the Company’s December 31, 2018 closing share price of $0.52, therefore the calculation uses the common shares outstanding at December 31, 2018.
ANNUAL GENERAL MEETING
The Company’s Annual General Meeting will be held at the Jamieson Place Conference Centre (3rd floor) 308, 4th Ave SW Calgary, Alberta, on Tuesday May 7, 2019 at 2:00 p.m. (Calgary time).
An updated corporate presentation can be found on the Company’s website at www.petrusresources.com.