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
$68.79/bbl, of its natural gas and oil and natural gas liquids production, respectively, for 2019.
(1) Refer to "Non-GAAP Financial Measures".
(2) Refer to "Advisories - Forward-Looking Statements".
(3) Refer to "Oil and Gas Disclosures".
SELECTED FINANCIAL INFORMATION
| OPERATIONS |
Twelve months
ended
Dec. 31, 2018 |
Twelve months
ended
Dec. 31, 2017 |
Three months
ended
Dec. 31, 2018 |
Three months
ended
Sept. 30, 2018 |
Three months
ended
Jun. 30, 2018 |
Three months
ended
Mar. 31, 2018 |
| Average Production |
|
|
|
|
|
|
| Natural gas (mcf/d) |
37,101 |
|
43,747 |
|
30,480 |
|
33,461 |
|
39,126 |
|
45,543 |
|
| Oil (bbl/d) |
1,402 |
|
1,823 |
|
1,358 |
|
1,243 |
|
1,484 |
|
1,530 |
|
| NGLs (bbl/d) |
1,433 |
|
1,103 |
|
1,496 |
|
1,519 |
|
1,241 |
|
1,475 |
|
| Total (boe/d) |
9,019 |
|
10,217 |
|
7,934 |
|
8,338 |
|
9,246 |
|
10,596 |
|
| Total (boe) |
3,292,828 |
|
3,729,095 |
|
730,819 |
|
767,095 |
|
841,316 |
|
953,598 |
|
| Natural gas sales weighting |
69 |
% |
71 |
% |
64 |
% |
67 |
% |
71 |
% |
72 |
% |
| Realized Prices |
|
|
|
|
|
|
| Natural gas ($/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 |
| 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.
For further information, please contact:
Neil Korchinski, P.Eng.
President and Chief Executive Officer
T: (403) 930-0889
E: nkorchinski@petrusresources.com
NON-GAAP FINANCIAL MEASURES
This press release makes reference to the terms "operating netback", "corporate netback", "net debt" and "net debt to
funds flow." These indicators are not recognized measures under GAAP (IFRS) and do not have a standardized meaning prescribed
by GAAP (IFRS). Accordingly, the Company's use of these terms may not be comparable to similarly defined measures presented by
other companies. Management uses these terms for the reasons set forth below. Please see the Company's December 31, 2018 MD&A
for a reconciliation of such measures to the most directly comparable GAAP (IFRS) measures.
Operating Netback
Operating netback is a common non-GAAP financial measure used in the oil and natural gas industry which is a
useful supplemental measure to evaluate the specific operating performance by product at the oil and natural gas lease level. The
most directly comparable GAAP measure to operating netback is funds flow. Operating netback is calculated as oil and natural gas
revenue less royalties, operating and transportation expenses. It is presented on an absolute value and per unit basis.
Funds Flow and Corporate Netback
Corporate netback is a common non-GAAP financial measure used in the oil and natural gas industry which evaluates
the Company’s profitability at the corporate level. 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. Management believes that funds flow
and corporate netback provide information to assist a reader in understanding the Company's profitability relative to current
commodity prices. It is calculated as the operating netback less general and administrative expense, finance expense,
decommissioning expenditures, plus other income and the net realized gain (loss) on financial derivatives.
Net Debt
Net debt is a non-GAAP financial measure and is calculated as current assets (excluding unrealized financial derivative assets)
less current liabilities (excluding unrealized financial derivative liabilities and deferred share unit liabilities) and long term
debt. Petrus uses net debt as a key indicator of its leverage and strength of its balance sheet. There is no GAAP measure that is
reasonably comparable to net debt.
Net Debt to Funds Flow
Net debt to funds flow is calculated as the period ending net debt divided by the trailing quarter funds flow (annualized).
OIL AND GAS DISCLOSURES
Our oil and gas reserves statement for the year ended December 31, 2018, which includes disclosure of our oil and natural
gas reserves and other oil and natural gas information in accordance with NI 51-101, is contained in the AIF. The recovery and
reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered.
This press release contains metrics commonly used in the oil and natural gas industry, such as "finding and
development costs" or "F&D", "finding, development and acquisition costs" or "FD&A", "future development cost" or "FDC",
"reserve life index" and "reserve replacement ratio." These terms do not have standardized meanings or standardized methods of
calculation and therefore may not be comparable to similar measures presented by other companies, and therefore should not be used
to make such comparisons. Such metrics have been included herein to provide readers with additional information to evaluate the
Company’s performance, however such metrics should not be unduly relied upon.
F&D and FD&A Costs
FD&A cost is defined as capital costs for the time period including change in FDC divided by change in reserves including
revisions and production for that same time period. F&D cost is defined as capital costs for the time period including change
in FDC divided by change in reserves including revisions and production for that same time period, excluding acquisitions and
dispositions. Both F&D and FD&A costs take into account reserve revisions during the year on a per boe basis. The
methodology used to calculate F&D costs includes disclosure required to bring the proved undeveloped and probable reserves to
production. Annually, changes in forecast FDC occur as a result of Petrus’ development, acquisition and disposition
activities, undeveloped reserve revision and capital cost estimates. These values reflect the independent evaluator’s best estimate
of the cost to bring the proved and probable undeveloped reserves to production.
Reserve Life Index
Reserve life index is defined as total reserves by category divided by the annualized fourth quarter production.
Reserve Replacement Ratio
The reserve replacement ratio is calculated by dividing the yearly change in reserves net of production by the actual annual
production for the year.
Management uses oil and gas metrics for its own performance measurements and to provide shareholders with
measures to compare Petrus' operations over time. Readers are cautioned that the information provided by these metrics, or that can
be derived from the metrics presented in this press release, should not be relied upon for investment.
Reserve Replacement Ratio
The reserve replacement ratio is calculated by dividing the yearly change in reserves net of production by the actual annual
production for the year.
ADVISORIES
Basis of Presentation
Financial data presented above has largely been derived from the Company’s financial statements, prepared in accordance with GAAP
which require publicly accountable enterprises to prepare their financial statements using IFRS. Accounting policies adopted by the
Company are set out in the notes to the audited financial statements as at and for the twelve months ended December 31, 2018.
The reporting and the measurement currency is the Canadian dollar. All financial information is expressed in Canadian dollars,
unless otherwise stated.
Forward-Looking Statements
Certain information regarding Petrus set forth in this press release contains forward-looking statements within the meaning of
applicable securities law, that involve substantial known and unknown risks and uncertainties. The use of any of the words
“anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended
to identify forward-looking statements. Such statements represent Petrus’ internal projections, estimates or beliefs concerning,
among other things, an outlook on the estimated amounts and timing of capital investment, anticipated future debt, production,
revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or
performance. These statements are only predictions and actual events or results may differ materially. Although Petrus believes
that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of
activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive,
political and social uncertainties and contingencies. Many factors could cause Petrus’ actual results to differ materially from
those expressed or implied in any forward-looking statements made by, or on behalf of, Petrus.
In particular, forward-looking statements included in this press release include, but are not limited to,
statements with respect to: Petrus’ business plan and capital expenditure program for 2019, including its first quarter capital
budget and the funding of the same; Petrus' drilling plan, including the same being within funds flow; expected 2019 quarterly debt
repayment; Petrus' liquid weighting; the results and success of Petrus' hedging program; the growth of Petrus; expectations
regarding Petrus' balance sheet; expectations regarding the adequacy of Petrus' liquidity and the funding of its financial
liabilities; expected year over year production; sources of and sufficient financing and the requirement therefor; expected funds
flow for the first quarter of 2019; the performance characteristics of the Company’s crude oil, NGL and natural gas
properties including estimated production and production dates; Petrus' adoption of IFRS 16 and the impact of the same; the
development of the Company's Cardium light oil in Ferrier; future prospects; the focus of and timing of capital expenditures;
access to debt and equity markets; projections of market prices and costs; the performance characteristics of the Company’s crude
oil, NGL and natural gas properties including estimated production; crude oil, NGL and natural gas production levels and product
mix; Petrus’ future operating and financial results; capital investment programs; supply and demand for crude oil, NGL and natural
gas; future royalty rates; drilling, development and completion plans and the results therefrom; and treatment under governmental
regulatory regimes and tax laws. In addition, statements relating to “reserves” are deemed to be forward-looking statements, as
they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably
produced in the future.
This press release discloses drilling locations, which are proved plus probable locations as at December 31,
2018 based on Sproule's 2018 year end reserves evaluation. The drilling locations on which the Company will actually drill wells
will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas
prices, costs, actual drilling results, additional reservoir information that is obtained and other factors.
These forward-looking statements are subject to numerous risks and uncertainties, most of which are beyond the
Company’s control, including the impact of general economic conditions; volatility in market prices for crude oil, NGL and natural
gas; industry conditions; currency fluctuation; imprecision of reserve estimates; liabilities inherent in crude oil and natural gas
operations; environmental risks; incorrect assessments of the value of acquisitions and exploration and development programs;
competition; the lack of availability of qualified personnel or management; changes in income tax laws or changes in tax laws and
incentive programs relating to the oil and gas industry; hazards such as fire, explosion, blowouts, cratering, and spills, each of
which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury;
stock market volatility; ability to access sufficient capital from internal and external sources; completion of the financing on
the timing planned and the receipt of applicable approvals; and the other risks. With respect to forward-looking statements
contained in this press release, Petrus has made assumptions regarding: future commodity prices and royalty regimes; availability
of skilled labour; timing and amount of capital expenditures; future exchange rates; the impact of increasing competition;
conditions in general economic and financial markets; availability of drilling and related equipment and services; effects of
regulation by governmental agencies; and future operating costs. Management has included the above summary of assumptions and risks
related to forward-looking information provided in this press release in order to provide shareholders with a more complete
perspective on Petrus’ future operations and such information may not be appropriate for other purposes. Petrus’ actual results,
performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and,
accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or
occur, or if any of them do so, what benefits that the Company will derive therefrom. Readers are cautioned that the foregoing
lists of factors are not exhaustive.
These forward-looking statements are made as of the date of this press release and the Company disclaims any
intent or obligation to update any forward-looking statements, whether as a result of new information, future events or results or
otherwise, other than as required by applicable securities laws.
BOE Presentation
The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent (“boe”) basis
whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil
and natural gas measurement units into one basis for improved measurement of results and comparisons with other industry
participants. Petrus uses the 6:1 boe measure which is the approximate energy equivalence of the two commodities at the burner tip.
Boe’s do not represent an economic value equivalence at the wellhead and therefore may be a misleading measure if used in
isolation.
Abbreviations
$000’s thousand dollars
$/bbl
dollars per barrel
$/boe
dollars per barrel of oil equivalent
$/GJ dollars per gigajoule
$/mcf
dollars per thousand cubic feet
bbl barrel
bbl/d
barrels per day
boe barrel of oil equivalent
mboe barrel of oil equivalent
mmboe
thousand barrel of oil equivalent
boe/d million barrel of oil equivalent per
day
GJ gigajoule
GJ/d
gigajoules per day
mcf
thousand cubic feet
mcf/d thousand cubic feet per day
mmcf/d million cubic feet per day
NGLs natural gas liquids
WTI
West Texas Intermediate
