Annual Report
December 31, 2014
HIGHLIGHTS
Petrus Resources Ltd. (“Petrus” or the “Company”) is pleased to report operating and financial results for the fourth quarter and the 2014
fiscal year, in which the Company set new records for production, cash flow and reserves.
•
•
•
•
•
Petrus began 2014, its third full year of operations, with production of 4,052 boe per day (46% oil and liquids) and exited the year
at a record 11,200 boe per day (46% oil and liquids), nearly a three-fold increase. On a debt-adjusted per share basis, exit
production was up 28% year-over-year. Average 2014 production was 6,032 boe per day, up from 3,206 boe per day in 2013.
Fourth quarter production averaged 9,822 boe per day, compared to 3,658 boe per day in the same period of 2013, an increase of
24% per debt-adjusted share.
The increase in production drove strong cash flow growth. Petrus generated $61.3 million in cash flow from operations during the
year, nearly double the $31.1 million generated in 2013. Cash flow from operations was $24.6 million in the fourth quarter, up
from $9.2 million in the same period last year, an increase of 24% per debt-adjusted share.
Cash flow growth was also enhanced by the Company’s continual efforts to build a more efficient business. Operating costs
declined 20% in 2014, from $10.26 per boe in 2013 to $8.23 per boe. Annual cash costs including net royalties, operating costs,
transportation, G&A and interest totaled $22.43 per boe, delivering a 56% operating margin for 2014. The Company’s cash costs in
the fourth quarter totaled $15.86, resulting in a corporate netback of $27.24 and a 63% operating margin.
Reserves per debt-adjusted share increased by 34% on a proved developed producing basis, and 26% on a proved plus probable
basis. Total proved plus probable reserves increased from 14.9 mmboe in 2013 to 40.6 mmboe in 2014. The Company replaced
12.7 times annual production at an all-in annual Finding, Development and Acquisition (“FD&A”) cost of $21.49 per boe including
future development capital (“FDC”) for the proved plus probable category.
Petrus ended 2014 with $488.5 million of proved plus probable reserve value, discounted at 10%, 2.1 times the prior year total.
On a debt-adjusted per share basis, the proved plus probable reserve value declined 1%, partly a reflection of the steep decline in
the reserve evaluator’s price forecast. The Company’s proved developed producing reserve value grew 38% per debt-adjusted
share.
• Over the twelve month period ended December 31, 2014, Petrus invested $443.0 million in exploration and acquisition activity, up
from $57.2 million in 2013. Petrus invested $115.2 million in finding and development activities, along with $327.7 million in
acquisitions (net of dispositions). The investments were funded by cash flow, debt (including the issuance of a $90 million term
loan) and net equity proceeds in 2014 of $200.8 million.
•
•
•
At December 31, 2014 Petrus had 140.6 million common shares outstanding and was 50% drawn against its $200.0 million credit
facility. The Company ended the year with net debt of $215.0 million, 2.2 times annualized fourth quarter cash flow.
At year end Petrus had 248,038 net acres of undeveloped land, a two-fold increase over the undeveloped land position a year
earlier. The percentage of operated production more than doubled in 2014, from 32% to 78%.
Subsequent to December 31, 2014 Petrus closed two acquisitions in the Ferrier area of Alberta; included in these acquisitions
were approximately 815 boe per day of production and 1,759 net acres of undeveloped land. The acquisitions were made for total
cash consideration of approximately $8.9 million (before post-closing adjustments) and closed in the first quarter of 2015. Petrus
also disposed of working interest in a non-core property in the Pembina area of Alberta in the first quarter, for net proceeds of
$8.2 million (before post-closing adjustments).
• The Petrus Board of Directors has approved a base capital budget of $50 million for 2015, excluding acquisitions. The capital
budget includes the drilling of 10 gross (six net) wells and the construction of a gas plant in the Ferrier area to reduce future third-
party processing fees. The capital budget will be funded through cash flow.
Page | 1
SELECTED FINANCIAL INFORMATION
Twelve months
ended
Dec. 31, 2014
Twelve months
Ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2014
Three months
ended
Sept. 30, 2014
Three months
ended
June 30, 2014
Three months
ended
Mar. 31, 2014
(000s) except per boe amounts
OPERATIONS
Average Production
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Total (boe)
Natural gas sales weighting
Exit production (boe/d)
Exit natural gas sales weighting
Realized Sales Prices
Natural gas ($/mcf)
Oil ($/bbl)
NGLs ($/bbl)
Total ($/boe)
Hedging gain (loss) ($/boe)
Operating Netback ($/boe)
Effective price
Royalty income
Royalty expense
Operating expense
Transportation expense
Operating netback (2) ($/boe)
G & A expense (1)
Net interest expense
Corporate netback (2) ($/boe)
FINANCIAL ($000s except per
share)
Oil and natural gas revenue
Cash flow from operations (2)
Cash flow from operations per
share (2)
Net income (loss)
Net income (loss) per share
Capital expenditures
Net acquisitions (dispositions)
Common shares outstanding
Weighted average shares
As at quarter end ($000s)
Net debt (3)
Bank debt outstanding
Bank debt available
Shareholder’s equity
Total assets
20,540
2,227
382
6,032
2,201,856
57%
11,200
54%
4.59
87.14
45.23
50.67
0.42
51.09
0.52
(8.69)
(8.23)
(1.94)
32.75
(2.27)
(1.82)
28.66
112,705
61,250
0.57
(47,491)
(0.45)
115,218
327,746
140,593
106,719
(215,049)
190,000
100,000
311,760
647,304
10,314
1,417
70
3,206
1,170,141
54%
4,052
54%
3.30
83.95
61.87
49.08
(1.12)
47.96
0.53
(7.66)
(10.26)
(1.83)
28.74
(1.59)
(0.59)
26.56
58,055
31,091
0.36
8,141
0.09
58,851
(1,701)
86,377
86,343
(22,288)
23,380
36,620
156,002
211,952
34,626
2,998
1,053
9,822
903,620
59%
11,200
54%
3.97
67.47
47.52
39.37
3.73
43.10
0.47
(4.38)
(6.43)
(1.25)
31.51
(2.34)
(1.93)
27.24
35,998
24,627
0.18
(63,308)
(0.45)
53,049
195,028
140,593
140,571
(215,049)
190,000
100,000
311,760
647,304
17,557
1,799
203
4,928
453,359
59%
5,600
63%
4.23
95.51
51.08
52.04
(3.00)
49.04
0.28
(8.90)
(9.69)
(2.87)
27.86
(3.19)
(2.88)
21.79
23,592
9,878
0.09
7,530
0.07
28,964
113,605
140,458
108,212
21,014
90,000
50,000
374,070
549,248
16,800
2,012
147
4,959
451,269
56%
4,836
55%
5.21
100.20
37.60
59.42
(3.32)
56.10
0.67
(12.76)
(9.29)
(2.17)
32.55
(1.77)
(1.36)
29.42
26,815
13,278
0.15
5,505
0.06
9,275
—
101,748
91,106
415
—
90,000
213,508
259,110
12,864
2,134
95
4,373
393,601
49%
4,641
57%
6.03
94.13
60.91
64.99
(3.64)
61.35
0.73
(13.69)
(9.47)
(2.21)
36.71
(1.61)
(0.85)
34.25
25,581
13,467
0.16
2,208
0.03
23,930
19,113
86,377
86,377
(51,638)
51,901
38,099
158,655
257,245
(1) G&A expenses are shown net of capitalized general & administrative costs. Please refer to the G&A section on page 12 in the December 31, 2014 MD&A.
(2) Non-GAAP measures, including the methodology used to calculate debt-adjusted share amounts, are defined on page 8 of the December 31, 2014 MD&A.
(3) Net debt includes working capital (deficiency).
Page | 2
OPERATIONS UPDATE
The Petrus Board of Directors has approved a base capital budget of $50 million for 2015, excluding acquisitions. The capital budget
includes the drilling of 10 gross (six net) wells and the construction of a gas plant in the Ferrier area to reduce future third-party processing
fees. The capital budget is expected to be funded through cash flow.
The Company’s production was significantly diversified during the year as a result of acquisition activities that provided Petrus with new
core areas in Ferrier and Central Alberta, more than doubling the operated production (to 78%) and doubling the net undeveloped land (to
248,035 acres). In late February, production was estimated at 9,700 boe per day, with some volumes shut in due to an interruption in
service on a major TransCanada pipeline. Average fourth quarter production from the Company’s four operating areas was as follows:
Average production for the
quarter ended December 31, 2014
Average Production
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Foothills
Peace River
Ferrier(1)
Central Alberta(2)
Total
11,313
871
119
2,876
4,468
908
34
1,687
6,490
10
590
1,681
12,355
1,209
310
3,578
34,626
2,998
1,053
9,822
Natural gas sales weighting
59%
(1) Petrus closed a property acquisition in Ferrier September 5, 2014 and the corporate acquisition of Arriva Energy Inc. on September 8, 2014.Petrus amalgamated Arriva on October 8, 2014.
(2) Petrus closed the acquisition of Ravenwood Energy Corp. on October 8, 2014. Petrus amalgamated Ravenwood on October 8, 2014.
58%
66%
44%
64%
Foothills
Petrus invested $65.6 million in the Foothills area in 2014 to drill 18 (6.0 net) wells and for the construction of production facilities; $17.7
million of the 2014 spending was invested during the fourth quarter. Production in the Foothills has grown 16% year-over-year from 2,427
boe per day in the fourth quarter of 2013 to 2,826 boe per day in the fourth quarter of 2014.
Petrus has entered into two farm-in deals in the Foothills, one in Cordel and one in Brown Creek. The first well is a twin of an existing well in
Brown Creek for a Notikewin gas target, and will earn Petrus a 65% working interest. The second is an offset location to a producing well in
Cordel in which Petrus would earn a 75% working interest. The wells are being drilled in the first quarter and the drilling rig will be released.
Peace River
Petrus invested $28.4 million in the Peace River area in 2014 to drill 17 (16.6 net) wells and construct water disposal and production
facilities; $4.3 million was invested during the fourth quarter to drill three (3.0 net) wells in the Berwyn area. Production in the Peace River
area has grown 45% year-over-year, from 1,166 boe per day in the fourth quarter of 2013 to 1,687 boe per day in the fourth quarter of
2014.
Two oil batteries with water disposal capabilities are now fully operational at Tangent and Berwyn contributing to significantly reduced
operating costs and increased runtime. Operating costs per boe in the two areas have declined 54% from $25.30 in 2013 to $11.70 in 2014.
Petrus has initiated a pilot waterflood program at Berwyn and expects to expand the waterflood area over the next year.
Ferrier
Petrus closed the corporate acquisition of Arriva Energy Inc. on September 8, 2014 and closed an acquisition of complimentary petroleum
and natural gas assets on September 5, 2014 in the Ferrier area of Alberta. The two acquisitions provided Petrus with undeveloped land of
17,839 net acres, production of 1,160 boe per day on close of the acquisitions, in addition to incremental production awaiting tie in. Fourth
quarter production was 1,681 boe per day.
Petrus invested $134.9 million (including acquisitions of $117.9 million) in the Ferrier area in 2014. Following the close of the Arriva
acquisition Petrus drilled five (3.9 net) wells in Ferrier. Two of the wells were drilled under a farm-in arrangement which earned Petrus a
working interest in two sections of land plus an option on three additional sections. The well results have been consistent with expectations
and Petrus plans to drill at least six wells in Ferrier in 2015.
In the near term, Petrus expects to encounter third party facility constraints in the Ferrier area. The Company has secured capacity at a
third party production facility for incremental Arriva volumes, and has initiated a process to build its own production facilities in order to
mitigate capacity constraints. In addition, an interruption in service on a major TransCanada pipeline in the second half of January resulted
Page | 3
in many producers being required to reduce sales volumes. Petrus was required to shut in approximately half of its Ferrier volumes and is
currently flowing on varied capacity constraints. TransCanada has stated that it expects the pipeline issue to be rectified in the first quarter
of 2015.
Central Alberta
Petrus closed the corporate acquisition of Ravenwood Energy Corp. on October 8, 2014. The acquisition provided Petrus with
approximately 3,500 boe/d of production (40% oil and liquids) and 42,352 net acres of undeveloped land in the Thorsby/Pembina area of
Alberta. In 2014 Petrus executed a horizontal well program targeting Glauconite light oil in the Thorsby area which was scheduled in
conjunction with Ravenwood’s 2014 nine well drilling program. Tie in activities have added incremental production of over 250 boe per day
to date subsequent to close of the transaction. Fourth quarter production in the Central Alberta area was 3,578 boe per day.
Petrus invested $217 million (including acquisitions of $195 million) in the Central Alberta area in 2014. Following the close of the
Ravenwood acquisition Petrus drilled five (4.7 net) wells in Thorsby. Petrus does not plan to invest additional capital in Central Alberta until
commodity prices improve; however Petrus is evaluating waterflood expansion opportunities to optimize the assets in the near term.
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
Friday May 15, 2015 at 9:00 a.m. (Calgary time). The Information Circular and Annual Report for 2014 will be available on the Company’s
website, www.petrusresources.com.
Page | 4
PRESIDENT’S MESSAGE
The past year was a particularly busy one for Petrus. Improving industry and market conditions in the first half of the year provided a
constructive backdrop for the Company’s growth plans. A $19 million acquisition of partner interests in February doubled our Northern
Foothills acreage and importantly, Petrus assumed operatorship of these low decline assets. A $50 million equity raise in May reduced the
Company’s debt to zero and positioned the balance sheet to support additional acquisition and development activities in the second half of
the year.
During the summer, Petrus identified two separate corporate acquisition opportunities that fit our strategy of accumulating low-decline oil
and liquids-rich gas assets. The Arriva acquisition closed in September followed by an oversubscribed private placement for $155 million
later that month, and the closing of the Ravenwood acquisition in early October. Throughout the year, Petrus continued to actively drill its
existing properties and also finished commissioning two new multi-well production facilities complete with water disposal facilities in the
Peace River area. These facilities expenditures significantly reduced current and future operating costs in their respective fields.
By mid-year, oil prices began to come under pressure with worldwide production consistently exceeding demand. New volumes added in
North America over the previous five years had marginally outstripped world demand growth leading to surplus supply capability. Negative
pricing pressure increased in the fall and culminated in late November with OPEC deciding to maintain their output volumes. The
benchmark WTI oil price ended the year at approximately US$50 per bbl, down over 50% from the previous mid-summer highs. Similarly,
natural gas prices also declined in the second half of 2014 as a result of robust supply. Moderating these effects to some extent was the
coincident 10% decline in the Canadian dollar over the same period.
Like many energy companies, Petrus has responded to these industry conditions by reducing capex, high-grading opportunities and
reducing costs wherever practical. Our goal is to manage prudently through the downturn while maintaining an ability to significantly
benefit during the eventual recovery. Our low decline and low cost asset base, combined with our ability to access capital to capture
strategic opportunities are very significant competitive advantages in these times.
Downturns are challenging but often have silver linings that aren’t immediately apparent. Cost structures that get unsustainably high during
prolonged exuberance get reset. Minds and hands are refocused on less glamorous but equally effective optimization and cost control
processes. Problems and irritations that seem significant when times are good don’t have the same relevance with the help of additional
perspective. In the end, challenges and struggles often result in a leaner, more efficient industry and one that is more resilient to additional
trials.
There is no doubt that the North American industry is under pressure in our own markets from world suppliers that aren’t subject to the
same rules. Data transparency in reserves, production, financial, and environmental performance are legislated here and these data are not
disclosed at all in many other jurisdictions. Laws against collusive behavior are stringently enforced here and yet those same behaviors are
open practice elsewhere – including OPEC itself. Without the tremendous efforts of North American energy companies and investors over
the past five years, oil prices could have been much higher. The rest of the world failed to add any material production capacity, even at
$100 oil, yet our companies and investors are disadvantaged by foreign suppliers acting in concert while hiding their actual capabilities from
independent scrutiny.
The huge reduction in oil and gas capital expenditures together with the stimulating effect of low prices will eventually rebalance the world
oil market. Petrus is well positioned to participate fully in the resulting price recovery and we sincerely appreciate the support and patience
of our shareholders while the rebalancing takes place.
Kevin Adair
President, CEO and Director
Page | 5
MANAGEMENT’S DISCUSSION & ANALYSIS
The following is management’s discussion and analysis ("MD&A") of the financial and operating results of the Company as at and for the
three and twelve month periods ended December 31, 2014. The report is dated March 25, 2015. This MD&A should be read in conjunction
with the December 31, 2014 audited financial statements. Readers are directed to the advisories at the end of this report regarding
forward-looking statements, BOE presentation and non-IFRS measures.
FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES
Three months
ended
Sept. 30, 2014
Twelve months
ended
Dec. 31, 2014
Twelve months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2014
Three months
ended
June 30, 2014
Three months
ended
Mar. 31, 2014
Quarterly average production
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Total (boe)
Exit production (boe/d)
Exit gas weighting
Revenue (000s)
Natural Gas
Oil
NGLs
Commodity revenue
Royalty revenue
Oil and natural gas revenue
Average realized prices
Natural gas ($/mcf)
Oil ($/bbl)
NGLs ($/bbl)
Total ($/boe)
Hedging gain (loss)
Total realized ($/boe)
Average benchmark prices
Natural gas
AECO (C$/mcf)
Crude Oil
Edm Lt. (C$/ bbl)
Foreign Exchange
US$/C$
20,540
2,227
382
6,032
2,201,856
11,200
54%
34,415
70,846
6,302
111,563
1,142
112,705
4.59
87.14
45.23
50.67
0.42
51.09
10,314
1,417
70
3,206
1,170,141
4,052
54%
12,438
43,425
1,572
57,435
620
58,055
3.30
83.95
61.87
49.08
(1.12)
47.96
34,626
2,998
1,053
9,822
903,620
11,200
54%
12,639
19,742
3,194
35,575
423
35,998
3.97
67.47
47.52
39.37
3.73
43.10
17,557
1,799
203
4,928
453,359
5,600
63%
6,830
15,811
951
23,592
128
23,720
4.23
95.51
51.08
52.04
(3.00)
49.04
16,800
2,012
147
4,959
451,269
4,836
50%
7,966
18,346
503
26,815
303
27,118
5.21
100.20
37.60
59.42
(3.32)
56.10
12,864
2,134
95
4,373
393,601
4,641
57%
6,980
18,081
520
25,581
288
25,869
6.03
94.13
60.91
64.99
(3.64)
61.35
Twelve months
ended
Dec. 31, 2014
Twelve months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2014
Three months
ended
Sept. 30, 2014
Three months
ended
Jun. 30, 2014
Three months
ended
Mar. 31, 2014
4.64
94.45
0.91
3.19
93.30
0.97
3.61
75.44
0.88
4.19
97.71
0.92
4.68
104.48
0.92
6.00
100.18
0.91
OIL AND NATURAL GAS REVENUE
Average production for the fourth quarter of 2014 was 9,822 boe per day (59% natural gas), compared to 3,658 boe per day (49% natural
gas) for the fourth quarter of the prior year. Total commodity revenue increased from $57.4 million in 2013 to $111.6 million in the year
ended December 31, 2014.
Natural gas
During the three months ended December 31, 2014, the benchmark natural gas price in Canada (set at the AECO hub) increased by 2% from
the prior year (average price of $3.61 per mcf in the fourth quarter compared to $3.53 per mcf in the prior year). The AECO price increased
45% from the average annual price of $3.19 per mcf in 2013 to $4.64 per mcf in 2014.
The Company’s average realized gas price during the fourth quarter of 2014 was $3.97 per mcf compared to $3.78 per mcf in the prior year,
which represents a 5% increase. Natural gas revenue for the fourth quarter of 2014 was $12.6 million and production of 3,185,615 mcf
accounted for approximately 59% of fourth quarter production volume and 36% of commodity revenue (compared to revenue of $3.8
million and production of 998,016 mcf for 50% of production volume and 22% of commodity revenue in the prior year).
The Company’s average realized gas price for the year ended December 31, 2014 was $4.59 per mcf compared to $3.30 per mcf in the prior
year, which represents a 39% increase. Natural gas revenue for the year ended December 31, 2014 was $34.4 million and production of
Page | 6
7,497,099 mcf accounted for approximately 57% of 2014 production volume and 31% of commodity revenue (compared to revenue of
$12.4 million and production of 3,764,610 mcf for 54% of production volume and 22% of commodity revenue in the prior year).
Crude oil and condensate
Edmonton Light Sweet (“Edmonton”) crude oil prices decreased 23% from the fourth quarter of 2013 to the fourth quarter of 2014 ($75.44
per bbl for the fourth quarter of 2014 compared to an average price of $97.43 per bbl for the prior period).
The average realized price of Petrus’ crude oil and condensate was $67.47 per bbl for the fourth quarter of 2014 compared to $93.93 per
bbl for the same period in the prior year. For the year ended December 31, 2014 the Company’s average realized price for crude oil and
condensate increased 4% from 2013 ($87.14 per bbl in 2014 compared to an average price of $83.95 per bbl in 2013). Petrus realized an
average negative oil differential of $7.43 in 2014, compared to a negative differential of $7.33 in 2013. Petrus realized a negative
differential of $6.53 in the fourth quarter of 2014 compared to a negative differential of $14.79 in the comparable period of the prior year.
Oil and condensate revenue for the fourth quarter of 2014 was $19.7 million and production of 275,812 bbl accounted for approximately
30% of total production volume and 55% of commodity revenue (compared to revenue of $12.7 million and production of 163,576 bbl for
49% of total production volume and 75% of commodity revenue in the fourth quarter of the prior year). Fourth quarter production and
revenue increased from the prior year as a result of the acquisitions of Arriva, Ravenwood and properties which were acquired early in the
fourth quarter.
Oil and condensate revenue for the year ended December 31, 2014 was $70.9 million and production of 812,986 bbl accounted for
approximately 37% of total production volume and 64% of commodity revenue (compared to revenue of $43.4 million and production of
517,205 bbl for 44% of total production volume and 76% of commodity revenue in the prior year). The increase in production from 2013 to
2014 is attributed to the property and corporate acquisitions completed during the year. In addition, average commodity prices were
stronger in 2014 compared to the prior year.
Natural gas liquids (NGLs)
The Company’s NGL production mix consists of ethane, propane, butane, pentane and sulphur. The pricing received for NGL production is
based on the product mix, the fractionation process required and the demand for fractionation facilities. In the fourth quarter, Petrus’
combined realized NGL price averaged $47.52 per bbl compared to $67.20 per bbl in the prior year. NGL revenue for the fourth quarter of
2014 was $3.2 million and production of 96,873 bbl accounted for approximately 10% of the Company’s production volume and 9% of
commodity revenue in the fourth quarter (compared to revenue of $0.4 million and production of 6,624 bbl for 2% of total production and
3% of commodity revenue for the fourth quarter of the prior year). The significant increase in NGL production and revenue is directly
attributed to the property and corporate acquisitions completed early in the fourth quarter.
NGL revenue for the year ended December 31, 2014 was $6.3 million and production of 139,354 bbl accounted for approximately 6% of the
Company’s production volume and 5% of commodity revenue in the fourth quarter (compared to revenue of $1.6 million and production of
25,550 bbl for 2% of total production and 3% of commodity revenue for the fourth quarter of the prior year). The increase in production
and revenue from 2013 to 2014 is due to the significant increase attributed to the acquisitions completed in 2014. The average NGL price
realized offset the positive increase in production.
Royalty Revenue
Petrus records gross overriding royalty revenue for production related to land or mineral rights owned. The revenue is included in “Other
Income” on the Company’s Statement of Net Income and Comprehensive Income. Royalty revenue received in the fourth quarter was $0.4
million compared to $0.2 million in the same quarter of the prior year. For the year ended December 31, 2014 Petrus earned $1.1 million,
an increase of 91% from $0.6 million earned in the year ended December 31, 2013. The increase is attributed to higher commodity prices
and incremental royalty revenue generated on lands acquired by way of the acquisition activity in 2014. On August 29, 2014 Petrus
divested of certain gross overriding royalty interests in its Foothills area for cash proceeds of $4.2 million. A $2.2 million gain was recorded
on the disposition.
Page | 7
NON-GAAP MEASURES
Petrus uses key performance indicators and industry benchmarks such as “cash flow from operations,” “cash flow from operations per
share,” “cash flow from operations per debt-adjusted share,” and “net debt” to analyze financial and operating performance. These
indicators are not defined by IFRS and therefore may not be comparable to performance measures presented by other companies.
Management believes that in addition to net income, the aforementioned non-IFRS measurements are useful supplemental measures as
they assist in the determination of the Company’s operating performance, leverage and liquidity. Investors should be cautioned, however,
that these measures should not be construed as an alternative to both net income and net cash from operating activities, which are
determined in accordance with IFRS, as indicators of the Company’s performance.
Cash Flow from Operations
Cash flow from operations represents cash flow from operating activities prior to changes in non-cash working capital and settlement of
decommissioning obligations. Petrus evaluates its financial performance primarily on cash flow from operations and considers it a key
performance indicator as it demonstrates the Company’s ability to generate sufficient cash flow to fund capital investment and repay debt.
The reconciliation between cash flow from operations and cash flow from operating activities, as defined by IFRS, is as follows:
($000s)
Cash flow from operating activities
Changes in non-cash working capital
Decommissioning expenditures
Cash flow from operations
Twelve months
ended
Dec 31, 2014
Twelve months
ended
Dec 31, 2013
Three months
ended
Dec 31, 2014
Three months
ended
Dec 31, 2013
80,988
(20,834)
1,096
61,250
26,238
4,853
—
31,091
47,198
(23,318)
747
24,627
7,079
2,141
—
9,220
Net Debt
Working capital (net debt) is a non-GAAP measure and is calculated as current assets (excluding financial derivative assets) less current
liabilities (excluding financial derivative liabilities) and bank debt. Petrus uses net debt as a key indicator of its leverage and strength of its
balance sheet. The reconciliation of net debt, as defined, is as follows:
($000s)
Current assets (excluding financial derivative assets)
Less: current liabilities (excluding financial derivative liabilities)
Less: bank debt
Working capital (net debt)
As at
Dec 31, 2014
As at
Dec 31, 2013
43,901
(69,831)
(189,119)
(215,049)
11,184
(10,092)
(23,380)
(22,288)
Debt-adjusted shares
Debt-adjusted shares are calculated by adding the shares outstanding for the relevant period to the share equivalent of the Company’s net
debt at the end of the period. The calculation assumes the debt is extinguished with a share issuance. Petrus is a privately held company
with no public market pricing data. In order to determine the price to convert the Company’s debt to shares, Petrus uses the current equity
price if a share issuance was completed during the current period. If a share issuance was not completed, a six times debt-adjusted cash
flow multiple is used to estimate the share price. The cash flow multiple is based upon trailing quarter annualized funds flow from
operations which represents the annualized cash flow from operating activities prior to changes in non-cash working capital and settlement
of decommissioning obligations. The multiple calculated does not, in any way, indicate a fair value for Petrus shares and the sole purpose is
to show a comparative metric. Weighted average shares are used for the average quarterly and annual production metrics as well as for
cash flow growth; end-of-period shares outstanding are used for exit production and reserves growth performance metrics. The table
below reconciles the debt-adjusted shares for the average year-over-year cash flow growth performance metric.
($000s, except per share amounts)
Weighted average shares outstanding
Annualized trailing cash flow from operations before interest
Share price to extinguish debt (1)
Ending net debt
Share equivalent on ending net debt
Debt-adjusted shares
(1) Equity price if shares issued arm’s length during the current quarter, otherwise six times debt-adjusted cash flow multiple on annualized trailing quarter cash flow is used to estimate the
share price.
106,719
111,920
3.25
(215,049)
66,169
172,888
86,343
37,888
2.37
(22,288)
9,389
95,732
Twelve months
ended
Dec 31, 2014
Twelve months
ended
Dec 31, 2013
Page | 8
CASH FLOW FROM OPERATIONS AND EARNINGS
Petrus generated cash flow from operations of $24.6 million during the quarter ended December 31, 2014 ($9.2 million during the fourth
quarter of 2013). Natural gas (AECO C$/mcf) increased 2% from the fourth quarter of 2013 to the fourth quarter of 2014, and Edmonton
crude (Edm. Lt. C$/bbl) decreased 13% for the same period.
The Company’s cash flow from operations effectively doubled from $31.1 million generated for the year in 2013 to $61.3 million for 2014.
The increase is attributed to an 88% increase in total production year over year (due to development and acquisition activity) and a 3%
increase in average commodity price for the year on a boe basis, as well as lower cash costs.
Petrus reported a net loss of $63.3 million in the fourth quarter of 2014 (compared to net income of $2.1 million in the fourth quarter of
the prior year). The loss was incurred due to an impairment charge due to weaker commodity prices. For the year ended December 31,
2014, Petrus reported a net loss of $47.5 million compared to net income of $8.1 million in the prior year. The following table provides
detail on the Company’s cash flow from operations on a barrel of oil equivalent (“boe”) basis.
Oil and natural gas revenue
Transportation
Net revenue
Royalty expense
Royalty income
Net oil and natural gas revenue
Operating expense (1)
Hedging gain (loss)
General & administrative(2)
Interest expense (3)
Twelve months ended
Dec. 31, 2014
Twelve months ended
Dec. 31, 2013
$000s
111,563
(4,279)
107,284
(19,140)
1,142
89,285
(18,130)
(918)
(4,992)
(3,995)
$/boe
$000s
$/boe
50.67
(1.94)
48.73
(8.69)
0.52
40.56
(8.23)
(0.42)
(2.27)
(1.82)
57,435
(2,136)
55,299
(8,964)
620
46,955
(12,009)
(1,311)
(1,856)
(688)
49.08
(1.83)
47.26
(7.66)
0.53
40.13
(10.26)
(1.12)
(1.59)
(0.59)
Three months ended
Dec. 31, 2014
$000s
$/boe
Three months ended
Dec. 31, 2013
$000s
$/boe
35,575
(1,126)
34,449
(3,958)
423
30,914
(5,815)
3,371
(2,117)
(1,744)
39.37
(1.25)
38.12
(4.38)
0.47
34.21
(6.43)
3.73
(2.34)
(1.93)
16,939
(543)
16,396
(2,372)
155
14,179
(3,716)
(409)
(582)
(252)
50.33
(1.61)
48.72
(7.05)
0.46
42.13
(9.88)
(1.21)
(1.73)
(0.75)
Cash flow from operations
61,250
27.82
31,091
26.56
24,627
27.25
9,220
28.56
(1) Operating expenses are presented net of processing income and overhead recoveries.
(2) G&A expenses are shown net of capitalized general & administrative costs. Please see the G&A section on page 11 in the MD&A for more detail.
(3) Interest expense is presented net of interest income.
(000s except per share)
Cash flow from operations
Cash flow from operations/share
Net Income (loss)
Net income (loss)/share
Common shares
Weighted average shares
Twelve months ended
Dec. 31, 2014
Twelve months ended
Dec. 31, 2013
Three months ended
Dec. 31, 2014
Three months ended
Dec. 31, 2013
61,250
0.57
(47,491)
(0.45)
140,593
106,719
31,091
0.36
8,141
0.09
86,377
86,343
24,627
0.18
(63,308)
(0.45)
140,593
140,571
9,220
0.11
2,086
0.02
86,377
86,377
Page | 9
Performance Metrics
Petrus uses certain performance metrics as key indicators to demonstrate the Company’s ability to generate shareholder value. On a debt-
adjusted per share basis, Petrus increased cash flow from operations 9% year-over-year from 2013. The same metric for the fourth quarter-
over-fourth quarter was an increase of 24%. Petrus increased exit production on a per debt-adjusted thousand share basis 28% from the
prior year as shown in the table below:
Twelve months ended
Twelve months ended
%
Change(2)
Three months ended
Three months ended
%
Change(2)
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2014
Dec. 31, 2013
Cash flow from operations per
debt-adjusted share(1) ($)
Exit production per debt-adjusted
thousand shares(1) (boe per day)
(1) Cash flow from operations per debt-adjusted share is a non-GAAP measure and is reconciled to the nearest GAAP measure on page 7 in the section heading “Non-GAAP” Measures. Debt
adjusted calculation uses period ending debt.
(2) Variance percentages may not recalculate due to rounding.
$0.12
$0.35
0.054
$0.33
$0.10
0.042
28%
9%
—
—
24%
—
RESULTS OF OPERATIONS
Royalty Expenses
Royalties are paid to the Government of Alberta and to gross overriding royalty owners. The following table shows the Company’s quarterly
royalty expenses by product category, based upon the primary product produced at the well.
Twelve months
ended
Dec. 31, 2013
Twelve months
ended
Dec. 31, 2014
Three months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2014
Royalty Expenses ($000s)
Oil and NGLs ($000s)
% of production revenue
Natural gas (000s)
% of production revenue
Gas cost (allowance) (000s)
Gross overriding
Total (000s)
16,270
21%
6,219
18%
(6,020)
2,671
19,140
9,837
22%
1,822
15%
(2,951)
256
8,964
3,653
16%
2,902
23%
(4,543)
1,946
3,958
2,562
20%
409
11%
(735)
136
2,372
The increase in total royalties from the fourth quarter of 2013 ($2.4 million) to the fourth quarter of 2014 ($4.0 million) is the result of
higher production levels.
For the year ended December 31, 2014 Petrus recorded total royalties of $19.1 million compared to $9.0 million in the same period of
2013. The increase is related to production growth from the prior year. Gross overriding royalty expense incurred in 2014 ($2.7 million) was
significantly higher than the prior year ($0.3 million) due to the overriding royalty structure attributed to acquired properties. Estimates for
gas cost allowance were recognized in the fourth quarter related to the two corporate acquisitions. In addition, estimates were revised for
the existing assets.
Financial Instruments
The Company utilizes commodity contracts as a risk management technique to mitigate exposure to commodity price volatility. The
following table summarizes the financial derivative contracts Petrus has outstanding as at December 31, 2014:
Natural Gas
Contract Period
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Dec. 31, 2015
Jan. 1, 2015 to Dec. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Apr. 1, 2015 to Oct. 31, 2015
Nov. 1, 2015 to Mar. 31, 2016
Daily Volume
Price (CAD$/GJ)
2,000 GJ
2,000 GJ
1,000 GJ
1,000 GJ
1,000 GJ
500 GJ
1,000 GJ
1,000 GJ
5,000 GJ
4,000 GJ
3,000 GJ
3,000 GJ
6,000 GJ
$3.75/GJ
$3.81/GJ
$3.84/GJ
$4.04/GJ
$4.10/GJ
$4.18/GJ
$4.43/GJ
$4.83/GJ
$3.50 – 3.63/GJ
$3.49/GJ
$4.17/GJ
$3.35/GJ
$3.74/GJ
Type
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Costless Collar
Fixed price
Fixed price
Fixed price
Fixed price
Page | 10
Crude Oil
Contract Period
Jan. 1, 2015 to Dec. 31, 2015
Jan. 1, 2015 to Dec. 31,2015
Jan. 1, 2015 to Dec. 31, 2015
Apr. 1, 2015 to Dec. 31, 2015
Apr. 1, 2015 to Dec. 31, 2015
Electric Power
Contract Period
Jan. 1, 2015 to Dec. 31, 2015
Type
Daily Volume
Price ($/Bbl)
Fixed price
Fixed Price
Fixed Price
Fixed Price
Fixed Price
200 Bbl
100 Bbl
500 Bbl
250 Bbl
250 Bbl
WTI $CAD100.00/Bbl
WTI $CAD 95.50/Bbl
WTI $95.00-104.50/Bbl
WTI $97.80/Bbl
WTI $92.50-103.50/Bbl
Type
Annual Volume
Price (CAD)
Fixed price
12,264 MW
$50.00/MWH
Subsequent to December 31, 2014 the Company entered into the following financial derivative contracts:
Natural Gas
Period Hedged
Apr. 1, 2015 to Oct. 31, 2015
Nov. 1, 2015 to Mar. 31, 2016
Apr. 1, 2016 to Oct. 31, 2016
Nov. 1, 2016 to Mar. 31, 2017
Apr. 1, 2015 to Oct. 31, 2015
Nov. 1, 2015 to Mar. 31, 2016
Apr. 1, 2016 to Oct. 31, 2016
Nov. 1, 2016 to Mar. 31, 2017
Apr. 1, 2015 to Oct. 31, 2015
Nov. 1, 2015 to Mar. 31, 2016
Apr. 1, 2016 to Oct. 31, 2016
Nov. 1, 2016 to Mar. 31, 2017
Jan. 1, 2016 to Mar. 31, 2016
Apr. 1, 2016 to Oct. 31, 2016
Crude Oil
Contract Period
Apr. 1, 2015 to Jun. 30, 2015
Jul. 1, 2015 to Sep. 31, 2015
Jan. 1, 2016 to Dec. 31, 2016
Type
Daily Volume
Price (CAD$/GJ)
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
2,000 GJ
2,000 GJ
2,000 GJ
2,000 GJ
4,000 GJ
4,000 GJ
2,000 GJ
2,000 GJ
6,000 GJ
6,000 GJ
6,000 GJ
6,000 GJ
5,000 GJ
5,000 GJ
$2.52/GJ
$3.03/GJ
$2.93/GJ
$3.38/GJ
$2.46/GJ
$2.96/GJ
$2.85/GJ
$3.31/GJ
$2.37/GJ
$2.87/GJ
$2.75/GJ
$3.21/GJ
$3.26/GJ
$2.91/GJ
Type
Daily Volume
Price ($/Bbl)
Costless collar
Costless collar
Costless collar
2,000 Bbl
2,000 Bbl
700 Bbl
WTI $USD45.00-60.10/Bbl
WTI $USD45.00-66.00/Bbl
WTI $CAD70.00-75.75/Bbl
The impact of the contracts which were outstanding during the reporting periods are recorded as realized hedging gains (losses) and affect
the Company’s realized commodity price. The unrealized gain (loss) is recorded to demonstrate the impact of the outstanding contracts had
they settled on the relative financial reporting period date. The contracts entered had the following impact on net income:
Other Income ($000s)
Realized hedging gain (loss)
Unrealized hedging gain (loss)
Total gain (loss) on derivatives
Twelve months
ended
Dec. 31, 2014
Twelve months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2014
Three months
ended
Dec. 31, 2013
(918)
17,311
16,393
(1,311)
(1,495)
(2,806)
3,371
15,205
18,576
(409)
11
(398)
Weakened commodity prices resulted in a realized hedging gain of $3.4 million during the fourth quarter of 2014, compared to a $409,000
loss realized in the same quarter of the prior year. The fourth quarter realized gain increased the Company’s realized price by $3.73 per
boe, compared to a decrease in the prior year comparable period of $1.22 per boe. For the year ended December 31, 2014 Petrus recorded
a $925,000 gain on financial derivatives compared to a $1.3 million loss recorded in the prior year.
Page | 11
Operating Expenses
The following table shows the Company’s operating expenses for the reporting periods which are shown net of processing income and
overhead recoveries:
Operating Expenses ($000s)
Operating expense, net
Operating expense, net ($ per boe)
Twelve months
ended
Dec. 31, 2014
Twelve months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2014
Three months
ended
Dec. 31, 2013
18,129
8.23
12,009
10.26
5,815
6.43
3,716
11.03
Operating expenses totaled $5.8 million for the fourth quarter of 2014, a 57% increase from $3.7 million recorded in the same quarter of
the prior year. The increase in aggregate net operating expenses is due to 142% higher average fourth quarter production in 2014
compared to the prior year. In addition, overhead recoveries were adjusted in the fourth quarter and third party facility equalizations were
received.
For the year ended December 31, 2014, operating costs on a per boe basis were 20% lower than the prior year. New water disposal
facilities in the Peace River contributed to operating cost reductions.
Transportation Expenses
The following table shows transportation expenses paid in the reporting periods:
Transportation Expenses ($000s)
Transportation expense
$ per boe
Twelve months
ended
Dec. 31, 2014
Twelve months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2014
Three months
ended
Dec. 31, 2013
4,279
1.94
2,136
1.83
1,126
1.25
543
1.61
Petrus pays commodity and demand charges for transporting its gas on various pipeline systems. The Company also incurs trucking costs on
the portion of its oil and natural gas liquids production that is not pipeline connected. Transportation expenses totaled $1.1 million or $1.25
per boe in the fourth quarter of 2014 ($0.5 million or $1.61 per boe for the comparative period in the prior year). The decrease in
transportation costs is due to the reduced reliance on trucking to deliver liquids production to sales points as more volume was transported
via pipeline.
Transportation costs increased year over year from $1.83 per boe for the year ended December 31, 2013 to $1.94 per boe for the same
period in 2014. The increase is due to increased trucking costs as well as pipeline facility constraints that led to higher volumes being
trucked to sales delivery points in the first half of 2014.
General and Administrative Expenses
The following table illustrates the Company’s general and administrative expenses which are shown net of capitalized costs directly related
to exploration and development activities:
General and Administrative Expenses ($000s)
Gross general and administrative expense
Capitalized general and administrative
Net general and administrative expense
Share based compensation expense
Capitalized share based compensation
Total general and administrative expense, net
Twelve months
ended
Dec. 31, 2014
Twelve months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2014
Three months
ended
Dec. 31, 2013
6,794
(1,802)
4,992
1,483
(741)
5,734
3,367
(1,511)
1,856
1,858
(929)
2,786
2,144
(27)
2,117
459
(229)
2,347
491
91
582
349
(174)
757
Fourth quarter 2014 gross general and administration expenses (before capitalized G&A and share based compensation), totaled $2.1
million or $2.37 per boe (compared to $0.5 million or $0.55 per boe for the fourth quarter of 2013). Petrus incurred transaction and one-
time costs in the fourth quarter attributed to the corporate acquisitions and financing activities which occurred late in 2014. One-time costs
totaled $1.3 million or $1.44 per boe.
For the year ended December 31, 2014, the Company’s gross G&A costs (before capitalized G&A and share based compensation) were $6.8
million compared to $3.4 million incurred in 2013. The increase is due to the organic growth of the Company as well as the corporate
acquisitions that occurred in the second half of 2014. Gross G&A for 2013 was $2.88 per boe and in 2014 gross G&A expenses incurred
were $3.63 per boe (includes transaction and one-time costs associated with the acquisition activity of $0.59 per boe).
Page | 12
Depletion and Depreciation
The following table compares depletion and depreciation expenses recorded in the reporting periods:
Depletion and Depreciation ($000s)
Depletion
Depreciation
Total
Depletion ($ per boe)
Depreciation ($ per boe)
Total ($ per boe)
Twelve months
ended
Dec. 31, 2014
Twelve months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2014
Three months
ended
Dec. 31, 2013
36,797
53
36,850
16.75
0.02
16.77
16,402
761
17,163
14.02
0.65
14.67
18,703
20
18,723
20.70
0.02
20.72
6,120
539
6,659
18.19
1.60
19.79
Depletion and depreciation expense is calculated on a unit-of-production basis. This fluctuates period to period primarily as a result of
changes in the underlying proved plus probable reserve base and in the amount of costs subject to depletion and depreciation, including
future development costs. Such costs are segregated and depleted on an area by area basis relative to the respective underlying proved
plus probable reserve base.
Petrus recorded depletion expense in the fourth quarter of 2014 of $18.7 million or $20.70 per boe, compared to the fourth quarter of
2013, when $6.1 million or $18.19 per boe was recorded.
For the year ended December 31, 2014 Petrus recorded $36.9 million or $16.75 per boe related to depletion which represents a $2.08 per
boe or 14% increase from $17.2 million or $14.67 per boe recorded in the prior year. The Company’s depletion and depreciation have
increased from the prior year due to the increased production and reserves base (primarily attributed to acquisitions).
SHARE CAPITAL
The authorized share capital consists of an unlimited number of common voting shares without par value. The following table details the
number of issued and outstanding instruments for the financial periods shown:
Twelve months
ended
Dec. 31, 2014
Twelve months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2014
Three months
ended
Dec. 31, 2013
(000s)
Weighted average outstanding common shares
Basic
Diluted
Outstanding instruments
86,377
140,593
Common shares
6,115
4,355
Stock options
6,408
Warrants
6,423
At March 25, 2015 the Company had 140,592,598 common shares outstanding. Subsequent to December 31, 2014 the Company issued
505,000 stock options. As at March 25, 2015 the Company had 6,620,000 and 6,422,603 stock options and performance warrants
outstanding, respectively.
140,593
6,155
6,408
86,377
4,355
6,423
140,571
144,511
106,719
110,659
86,343
86,343
86,377
86,377
LIQUIDITY AND CAPITAL RESOURCES
Revolving Credit Facility
On July 31, 2014 the Company syndicated its existing credit facility to five institutions and structured a $100 million, committed, secured
364-day revolving plus one year term-out facility. It was comprised of a $20 million operating facility, as well as an $80 million syndicated
facility. The facilities bear interest at Canadian bank prime, or at the Company’s option, Canadian bankers’ acceptances, plus applicable
margin and stamping fee. The stamping fees range, depending on Petrus’ debt to EBITDA (which is: earnings before interest, taxes,
depreciation and amortization as defined in the banking agreement), between 100 bps and 250 bps on Canadian bank prime borrowings
and between 200 bps and 350 bps on Canadian dollar bankers’ acceptances. The undrawn portion of the facilities, are subject to a standby
fee in the range of 50 bps to 87.50 bps.
Concurrent with the closing of the acquisition of Arriva Energy Inc., Petrus obtained commitment from its syndicated lenders to increase its
demand credit facility from $80 million to $120 million for a total combined credit facility, inclusive of the $20 million operating facility, of
$140 million. At December 31, 2014, the Company had no outstanding letters of credit against the facility (December 31, 2013; Nil) and had
drawn $100 million against the facility (December 31, 2013; $23.4 million).
Page | 13
Concurrent with the closing of the acquisition of the Ravenwood Energy Corporation, Petrus obtained commitment from its syndicated
lenders to increase its demand credit facility from $120 million to $180 million for a total combined credit facility, inclusive of the $20
million operating facility, of $200 million.
The amount of the credit facility is subject to a borrowing base review performed on a semi-annual basis by the lender, based primarily on
reserves and commodity prices estimated by the lenders as well as other factors. A decrease in the borrowing base could result in a
reduction to the available credit facility. The next scheduled review of the borrowing base is to place on May 31, 2015. The Company has
provided collateral by way of a $600 million debenture over all of the present and after acquired property of the Company.
The facilities carry a financial covenant which limits the Company’s ability to borrow amounts greater than the facility limit as well as:
(a) a financial covenant of PV10 to Net Secured Debt Ratio being less than 1.25 to 1.00 whereby Net Secured Debt (as defined by
the banking agreement) means all amounts owing under the Credit Facility and any other secured debt of Petrus on a
consolidated basis, minus restricted cash and cash equivalents and “PV10” means the discounted net present value (at a
discount rate of 10%) of Petrus’ proved reserves, as adjusted for commodity swaps then in effect and
(b) certain financial covenants only when any indebtedness under the second lien term facility remain outstanding which are:
a. The Working Capital Ratio will not be less than 1.00 to 1.00;
b. The Proved Asset Coverage Ratio will not be less than 1.25 to 1.00; and
c. The PDP Asset Coverage Ratio will not be less than 1.00 to 1.00.
At December 31, 2014 the Company was in compliance with financial covenants under the revolving credit facility.
Term Loan
Concurrent with the closing of the acquisition of Ravenwood Energy Corp., Petrus closed a $90 million second lien term loan facility with
Macquarie Bank Limited (the "Macquarie Facility"). The Term Loan matures and is repayable in full 24 months following funding. Interest is
due and payable monthly and accrues at a per annum rate of the (three-month) Canadian Dealer offered Rate (CDOR) plus 700 basis points.
The Term Loan is subject to three financial covenants: (1) the same financial covenant of PV10 to Net Secured Debt Ratio being less than
1.25 to 1.00 as the Credit Facilities; (2) a covenant that Petrus may not, as of the effective date of each annual independent engineering
reserve report and each internally prepared semi-annual internally prepared reserve report, permit the PDP to Net Secured Debt Ratio to
be less than 1.00 to 1.00 where “PDP” means the present value (discounted at 10.0%) of future net revenues attributable to Petrus’
reserves and (3) Petrus' working capital ratio (current assets to current liabilities) will not be less than 1.0 to 1.0.
Under the agreement, current assets are the current assets under IFRS plus any undrawn availability under the Revolving Credit Facility, less
any non-cash amount required to be included in current assets as the result of the application of IFRS including non-cash commodity and
interest rate hedges assets and liabilities. Current liabilities are the current liabilities under IFRS, excluding (a) non-cash obligations under
GAAP including non-cash commodity and interest rate hedges assets and liabilities, and (b) the current portion of long-term Debt, including
the term loan debt.
The Term Loan is secured with a $250 million second lien priority interest on the same collateral as the Credit Facilities and requires a
certain level of production volume to be hedged in 2015 and 2016. At December 31, 2014 the Company was in compliance with all
covenants under the term loan agreement.
The Company’s general capital management policy is to maintain a sufficient capital base in order to manage its business to enable the
Company to increase the value of its assets and therefore its underlying share value. The Company’s objectives when managing capital are
(i) to manage financial flexibility in order to preserve the Company’s ability to meet financial obligations; (ii) maintain a capital structure
that allows Petrus the ability to finance its growth using internally generated cash flow, and (iii) to maintain a flexible capital structure
which optimizes the cost of capital at an acceptable risk level and provides an optimal return to equity holders.
In the management of capital, Petrus includes share capital and total net debt, which is made up of debt and working capital (current assets
less current liabilities). Petrus manages its capital structure and makes adjustments in light of economic conditions and the risk
characteristics of the underlying assets. In order to maintain or adjust the capital structure, Petrus may issue new equity, increase or
decrease debt, adjust capital expenditures and acquire or dispose of assets. Petrus anticipates that it will have adequate liquidity to fund
future working capital and forecasted capital expenditures in 2014 through a combination of cash flow, current working capital and use of
its credit facility. Petrus is able to modify its capital program in response to changes in commodity prices and cash flows. Should the
Company choose to expand its capital program, actual funding alternatives will be influenced by the then current market environment and
the ability to access capital on reasonable terms, balanced with the investment opportunities presented.
Page | 14
CAPITAL EXPENDITURES
Capital expenditures, excluding acquisitions and dispositions, totaled $53.0 million in the fourth quarter of 2014 compared to $9.7 million in
the fourth quarter of the prior year. The majority of funds were invested in drilling and completions, construction of production facilities
and tie-ins. During the year Petrus drilled 43 wells (29.3 net). Petrus invested $443.0 million (including acquisitions net of dispositions) in
2014, funded by cash flow from operations, debt and equity. The following table shows capital expenditures for the reporting periods
indicated. All capital is presented before decommissioning obligations:
Twelve months
ended
Dec. 31, 2014
Twelve months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2014
($000s)
Drill and complete
Oil and gas equipment
Geological
Land and lease
Office
Capitalized general and administrative
Total
Acquisitions/(dispositions)
Total capital
Gross (net) wells spud
78,543
28,433
2,630
3,170
640
1,802
115,218
327,746
442,964
43 (29.3)
44,259
9,129
698
2,177
91
2,497
58,851
(1,701)
57,150
21 (11.4)
39,423
10,389
1,202
2,152
372
(489)
53,049
195,027
248,076
14 (10.4)
3,844
3,616
97
1,421
60
698
9,736
—
9,736
1 (0.3)
RESERVES
The following table provides a summary of the Company’s reserves, as evaluated by third party reserve engineers:
Reserves and Reserve Ratio Summary
December 31, 2014(1)
December 31, 2013(2)
Company Interest Reserves
Proved Producing
Total Proved
Total Proved +Probable
Net Present Value Discounted at 10%
Proved Producing
Total Proved
Total Proved +Probable
(1)The Company’s December 31, 2014 reserves were evaluated by Sproule and Associates.
(2)The Company’s December 31, 2013 reserves were evaluated by GLJ Petroleum Engineers and Sproule and Associates.
(3)FD&A (finding, development and acquisition) cost is defined as capital costs for the time period including change in future development capital divided by change in reserves including
revisions and production for that same time period.
(4)RLI (reserve life index) is defined as total reserves by category divided by the annualized fourth quarter production.
(MBoe)
5,696
8,638
14,864
($000s)
88,804
127,454
228,083
(MBoe)
16,533
26,557
40,590
($000s)
264,310
329,415
488,480
FD&A(3)
$34.72
$31.38
$21.57
FD&A(3)
$35.35
$27.44
$21.49
RLI(4)
4.6
7.3
11.2
—
—
—
—
—
—
—
—
—
RLI(4)
4.2
6.4
11.0
—
—
—
In 2014 Petrus’ total company interest reserves increased 273% to 40.6 mmboe on a proved plus probable (“P+P”) basis and 307% on a total
proved basis to 26.6 mmboe. The 27.9 mmboe net reserves addition in the company interest P+P category was accomplished at an all in finding,
development and acquisition (“FD&A”) cost of $21.49 per boe including future development capital (“FDC”).
Page | 15
SUMMARY OF QUARTERLY RESULTS
($000s) except per share amounts
Oil and natural gas revenue
Transportation
Net revenue
Royalty expense (1)
Royalty income (1)
Net oil and natural gas revenue
Operating expense (2)
Hedging gain (loss)
General and administrative expense (3)
Interest expense (4)
Dec. 31,
2014
Sep. 30,
2014
Jun. 30,
2014
Three months ended
Mar. 31,
2014
Dec. 31,
2013
Sep. 30,
2013
Jun. 30,
2013
Mar. 31,
2013
35,574
(1,126)
34,448
(3,958)
423
30,913
(5,815)
3,371
(2,117)
(1,725)
23,592
(1,303)
22,289
(4,035)
128
18,382
(4,395)
(1,359)
(1,446)
(1,304)
26,815
(979)
25,836
(5,760)
303
20,379
(4,194)
(1,496)
(797)
(614)
25,581
(872)
24,709
(5,387)
288
19,610
(3,727)
(1,432)
(634)
(335)
16,939
(543)
16,396
(2,372)
155
14,179
(3,716)
(409)
(582)
(252)
14,634
(636)
13,998
(2,276)
107
11,829
(2,460)
(425)
(571)
(216)
13,915
(466)
13,449
(2.034)
179
11,594
(2,753)
(150)
(427)
(216)
11,948
(491)
11,457
(2,282)
180
9,355
(3,080)
(328)
(276)
(5)
Cash flow from operations
Per share – basic
Net income (loss)
Per share – basic
Common shares (000s)
Weighted average shares (000s)
Total assets
Net working capital (net debt)
5,566
0.06
47
0.01
86,276
86,276
184,139
(10,551)
(1) The Company re-classified gross overriding royalty expense from other income to royalty expenses in the Statement of Net Income and Comprehensive Income. The comparative
information has been re-classified to conform to current presentation.
(2) Operating expenses are presented net of processing income and overhead recoveries.
(3) General and administrative expense is presented net of capitalized G&A.
(4) Interest expense is presented net of interest income.
24,627
0.18
(63,308)
(0.45)
140,593
140,571
647,304
(215,049)
13,482
0.16
2,208
0.03
86,377
86,377
257,245
(51,638)
8,157
0.09
2,171
0.03
86,377
86,332
201,208
(21,558)
8,048
0.09
4,010
0.05
86,362
86,349
199,507
(15,756)
9,220
0.11
2,086
0.02
86,377
86,377
211,952
(22,288)
9,878
0.09
7,530
0.07
140,458
108,212
549,248
21,014
13,278
0.15
5,505
0.06
101,748
91,106
259,110
415
The oil and natural gas exploration and production industry is cyclical in nature. Petrus' financial position, results of operations and cash flows are affected
by commodity prices and production levels.
Petrus has had continued quarterly growth over the last two years as summarized in the table above. The slight decrease in production volume from the
first quarter to the second quarter of 2013 was attributable to facility turnaround activity which required temporary production restrictions. Petrus'
average quarterly production has increased, from 3,007 boe/d in the first quarter of 2013 to 6,032 boe/d in the fourth quarter of 2014. The production
growth was equally attributable to the Corporation's exploration and development activities and acquisitions of producing properties.
The Corporation's funds flow from operations was $5.7 million in the first quarter of 2013 and $24.6 million in the fourth quarter of 2014. Funds flow from
operations increased with higher production levels as well as strengthened commodity prices, natural gas in particular. Commodity price improvements can
enable higher reinvestment in exploration, development and acquisition activities in future periods as they increase the funds received from operations.
Commodity price reductions reduce revenues received and can challenge the economics of the Corporation's development program as the quantity of
reserves may not be economically recoverable. Petrus' reinvestment in future reserves will be dependent on its ability to obtain debt and equity financing
as well as the funds it receives from operations.
CRITICAL ACCOUNTING ESTIMATES
The timely preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the
application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from these
estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which
the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of the financial
statements are outlined below.
Depletion and reserve estimates
Petroleum and natural gas assets are depleted on a unit of production basis at a rate calculated by reference to proved and probable reserves determined
in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The calculation incorporates the estimated
future cost of developing and extracting those reserves. Proved and probable reserves are estimated using independent reservoir engineering reports and
represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a
specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. Reserves
estimates, although not reported as part of the Company’s financial statements, can have a significant effect on net income (loss), assets and liabilities as a
result of their impact on depletion and depreciation, decommissioning liabilities, deferred taxes, asset impairments and business combinations.
Independent reservoir engineers perform evaluations of the Company’s petroleum and natural gas reserves on an annual basis. The estimation of reserves
is an inherently complex process requiring significant judgment. Estimates of economically recoverable petroleum and natural gas reserves are based upon
Page | 16
a number of variables and assumptions such as geoscientific interpretation, production forecasts, commodity prices, costs and related future cash flows, all
of which may vary considerably from actual results. These estimates are expected to be revised upward or downward over time, as additional information
such as reservoir performance becomes available or as economic conditions change.
Impairment indicators and cash-generating units
For purposes of impairment testing, petroleum and natural gas assets are aggregated into cash-generating units (“CGU’s”), based on separately
identifiable and largely independent cash inflows. The determination of the Company’s CGU’s is subject to judgment.
The recoverable amounts of CGU’s and individual assets have been determined based on the higher of the value-in-use calculations and fair values less
costs to sell. These calculations require the use of estimates and assumptions, including the discount rate, future petroleum and natural gas prices,
expected production volumes and anticipated recoverable quantities of proved and probable reserves. These assumptions are subject to change as new
information becomes available and changes in economic conditions take place. Changes may impact the estimated life of the field and economical
reserves recoverable and may require a material adjustment to the carrying value of petroleum and natural gas assets. The Company monitors internal
and external indicators of impairment relating to its tangible assets.
Technical feasibility and commercial viability of exploration and evaluation assets
The determination of technical feasibility and commercial viability, based on the presence of proved and probable reserves, results in the transfer of
assets from exploration and evaluation assets to property, plant and equipment. As discussed above, the estimate of proved and probable reserves is
inherently complex and requires significant judgment. Thus any material change to reserve estimates could affect the technical feasibility and commercial
viability of the underlying assets.
Decommissioning obligation
At the end of the operating life of the Company’s facilities and properties and upon retirement of its petroleum and natural gas assets, decommissioning
costs will be incurred by the Company. This requires judgment regarding abandonment date, future environmental and regulatory legislation, the extent
of reclamation activities, the engineering methodology for estimating cost, future removal technologies in determining the removal cost and discount
rates to determine the present value of these cash flows.
Income taxes
Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts recognized in income or loss both in the
period of change, which would include any impact on cumulative provisions, and in future periods. Deferred tax assets (if any) are recognized only to the
extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse
and a judgment as to whether or not there will be sufficient taxable income available to offset the tax assets when they do reverse. This requires
assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can
be an increase or decrease in the amounts recognized in respect of deferred tax assets as well as the amounts recognized in income or loss in the period in
which the change occurs. Additionally, future changes in tax laws in the jurisdictions in which the Company operates could limit the ability of the
Company to obtain tax deductions in future periods.
Measurement of share-based compensation
Share-based compensation recorded pursuant to share-based compensation plans are subject to estimated fair values, forfeiture rates and the future
attainment of performance criteria.
Business combinations
Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management to make
assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of exploration and evaluation
assets and petroleum and natural gas assets acquired generally require the most judgment and include estimates of reserves acquired, forecast
benchmark commodity prices and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets
and liabilities could impact the amounts assigned to assets, liabilities and goodwill in the purchase price allocation.
Contingencies
By their nature, contingencies will only be resolved when one or more future events occur or fail to occur. The assessment of contingencies inherently
involves the exercise of significant judgment and estimates of the outcome of future events.
ACCOUNTING POLICIES AND NEW STANDARDS
Significant accounting policies
The Company’s significant accounting policies can be read in note 3 to the Company’s audited financial statements as at and for the year ended December
31, 2014.
New standards and interpretations not yet adopted
On January 1, 2013, the Company adopted the following new standards and amendments which became effective for periods on or after January 1, 2013:
Page | 17
IFRS 10 Consolidated Financial Statements builds on existing principles by identifying the concept of control as the determining factor in whether an entity
should be included within the consolidated financial statements of the parent company. The standard provides additional guidance to assist in the
determination of control where it is difficult to assess. IFRS 10 replaces those parts of IAS 27 Consolidated and Separate Financial Statements (revised 2011)
that address when and how an entity should prepare consolidated financial statements and replaces SIC 12.
IFRS 11 Joint Arrangements provides for a more substance based reflection of joint arrangements by focusing on the rights and obligations of the
arrangement, rather than its legal form (as is currently the case). The standard addresses inconsistencies in the reporting of joint arrangements. IFRS 11
supersedes IAS 31 Interests in Joint Ventures and SIC 13 Jointly Controlled Entities – Non-Monetary Contributions by Ventures. IAS 28 Investments in
Associates and Joint Ventures (revised 2011) has been amended to conform to changes based on the issuance of IFRS 10 and IFRS 11.
IFRS 12 Disclosure of Interests in Other Entities requires extensive disclosures relating to an entity’s interests in subsidiaries, joint arrangements, associates
and unconsolidated structured entities. An entity is required to disclose information that help users of its financial statements evaluate the nature of and
risks associated with its interests in other entities and the effects of those interests on its financial statements. The effective date of IFRS 12 is January 1,
2013.
IFRS 13 Fair Value Measurement establishes a single framework for measuring fair values. This standard applies to all transactions and balances (whether
financial or non-financial) for which IFRS requires or permits fair value measurements, with the exception of share-based payment transactions accounted
for under IFRS 2 Share-based Payment and leasing transactions within the scope of IAS 17 Leases. IFRS 13 defines fair value, provides guidance on its
determination and introduces consistent requirements for disclosures on fair value measurements.
Petrus has assessed the impact of adopting these pronouncements and has determined these standards did not have a material impact on the Company’s
financial statements.
In 2013, the IASB issued amendments to IAS 36 “Impairment of Assets” which reduce the circumstances in which the recoverable amount of CGUs is
required to be disclosed and clarify the disclosures required when an impairment loss has been recognized or reversed in the period. The amendments are
to be adopted retrospectively for fiscal years beginning January 1, 2014. Petrus will adopt these amendments effective January 1, 2014. The adoption will
impact disclosures in the notes to the financial statements only in periods when an impairment loss or impairment reversal is recognized.
Levies
In May 2013, the IASB issued IFRIC 21 Levies, which clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as
identified by the relevant legislation, occurs. No liability should be recognized before
the specified minimum threshold to trigger that levy is reached.
IFRIC 21 is required to be adopted retrospectively for fiscal years beginning January 1, 2014, with earlier adoption permitted. Petrus is currently assessing
whether these changes will have an effect on its financial statements.
Other accounting standards and interpretations
IFRS 9 Financial Instruments issued in November 2009 and amended in October 2010 introduces new requirements for the classification and measurement
of financial assets and financial liabilities and for derecognition. IFRS 9 is expected to be published in three parts. The first part, Phase 1 – classification and
measurement of financial instruments sets out the requirements for recognizing and measuring financial assets, financial liabilities and some contracts to
buy or sell non-financial items. Phase 1 simplifies the measurement of financial assets by classifying all financial assets as those being recorded at amortized
cost or being recorded at fair value. Phase 1 is effective for periods beginning on or after January 1, 2015, although earlier adoption is allowed. Except for
certain additional disclosures, the adoption of this standard is not expected to have an impact on the Company’s financial statements.
Page | 18
ADVISORIES
Basis of Presentation
Financial data presented below have largely been derived from the Company’s financial statement, prepared in accordance with International Financial
Reporting Standards (“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, 2013. 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 document, including management’s assessment of the Company’s future plans and operations,
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 MD&A include, but are not limited to, statements with respect to: the size of, and future net
revenues from, crude oil, NGL (natural gas liquids) and natural gas reserves; future prospects; the focus of and timing of capital expenditures; expectations
regarding the ability to raise capital and to continually add to reserves through acquisitions and development; 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; 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; future land expiries; dispositions and joint venture
arrangements; amount of operating, transportation and general and administrative expenses; treatment under governmental regulatory regimes and tax
laws; estimated tax pool balances and anticipated IFRS elections and the impact of the conversion to IFRS. 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.
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 MD&A, 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 MD&A 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 MD&A 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 nine 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 equivalency of the two commodities at the burner tip. However, BOE’s do not represent an economic value equivalency at the wellhead and therefore
may be a misleading measure if used in isolation.
Abbreviations
000’s
bbl
bbl/d
bcf
boe/d
CAD
GJ
GJ/d
mbbls
mboe
mcf
thousand dollars
barrel
barrels per day
billion cubic feet
barrel of oil equivalent per day
Canadian dollar
gigajoule
gigajoules per day
thousand barrels
thousand barrels of oil equivalent
thousand cubic feet
Page | 19
mcf/d
mmbbls
mmboe
mmcf
mmcf/d
NGLs
USD
WTI
thousand cubic feet per day
million barrels
millions of barrels of oil equivalent
million cubic feet
million cubic feet per day
natural gas liquids
United States dollar
West Texas Intermediate
Cover page photo credit: Alain Sleigher Photography
Page | 20
INDEPENDENT AUDITORS’ REPORT
To the Shareholders of Petrus Resources Ltd.:
We have audited the accompanying financial statements of Petrus Resources Ltd., which comprise the balance sheets as at
December 31, 2014 and 2013, and the statements of net income (loss) and comprehensive income (loss), changes in shareholders’
equity and cash flows for the years then ended and a summary of significant accounting policies and other explanatory information.
Management's responsibility for the financial statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with International
Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of
financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ responsibility
Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in
accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements
and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material
misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements.
The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the
financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant
to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate
in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit
also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by
management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit
opinion.
Opinion
In our opinion, the financial statements present fairly, in all material respects, the financial position of Petrus Resources Ltd. as at
December 31, 2014 and 2013 and its financial performance and its cash flows for the years then ended in accordance with
International Financial Reporting Standards.
Chartered accountants
Calgary, Canada
March 25, 2015
Page | 21
BALANCE SHEETS
(Expressed in 000’s of Canadian dollars)
As at
ASSETS
Current
Cash
Deposits and prepaid expenses
Accounts receivable (note 15)
Risk management asset (note 10)
Non-current
Exploration and evaluation assets (notes 5 and 6)
Property, plant and equipment (notes 5 and 7)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current
Bank indebtedness (note 8)
Accounts payable and accrued liabilities
Risk management liability (note 10)
Non-Current
Long term debt (note 8)
Decommissioning obligation (note 9)
Deferred income tax liability (note 16)
Shareholders’ Equity
Share capital (note 11)
Contributed surplus
Retained earnings (deficit)
See accompanying notes to the financial statements
Commitments (note 21)
Approved by the Board of Directors,
(signed) “Don T. Gray”
Don T. Gray
Chairman
December 31, 2014
December 31, 2013
19,524
1,042
23,336
14,609
58,511
94,073
494,720
588,793
647,304
99,710
69,831
197
169,738
89,409
58,634
17,763
335,544
346,106
5,445
(39,791)
311,760
647,304
—
303
10,881
26
11,210
50,529
150,213
200,742
211,952
23,380
10,092
2,287
35,759
—
15,547
4,644
55,950
144,339
3,962
7,701
156,002
211,952
(signed) “Donald Cormack”
Donald Cormack
Director
Page | 22
STATEMENTS OF NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(Expressed in 000’s of Canadian dollars, except for share information)
REVENUE
Oil and natural gas revenue
Royalty expense
Oil and natural gas revenue, net of royalties
Other income
Gain (loss) on financial derivatives (note 10)
EXPENSES
Operating (note 18)
Transportation expenses
General and administrative (note 19)
Share-based compensation (note 11)
Finance (note 13)
Exploration and evaluation expense (note 6)
Depletion and depreciation (note 7)
Impairment (note 7)
NET INCOME (LOSS) BEFORE INCOME TAXES
Deferred income tax expense (recovery) (note 16)
TOTAL NET INCOME (LOSS) AND COMPREHENSIVE
INCOME (LOSS)
Net income (loss) per common share
Basic and diluted (note 12)
See accompanying notes to the financial statements
Year ended
December 31, 2014
Year ended
December 31, 2013
112,705
(19,140)
93,565
2,182
16,393
112,140
18,129
4,279
4,992
741
4,696
1,158
36,850
104,762
175,607
(63,467)
(15,975)
(15,975)
(47,492)
58,055
(8,963)
49,092
50
(2,806)
46,336
12,009
2,136
1,856
929
1,112
—
17,163
—
35,205
11,131
2,990
2,990
8,141
(0.45)
0.09
Page | 23
STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Expressed in 000’s of Canadian dollars)
Balance, December 31, 2012
Net income
Issuance of common shares (note 11)
Premium liability of flow-through shares
Share-based compensation (note 11)
Tax effect of share issue costs
Balance, December 31, 2013
Net income (loss)
Issuance of common shares (note 11)
Premium liability of flow-through shares
Share-based compensation (note 11)
Share issue costs
Tax effect of share issue costs
Balance, December 31, 2014
See accompanying notes to the financial statements
Share
Capital
Contributed
Surplus
Retained
Earnings
(Deficit)
Total
144,119
—
216
(14)
—
18
144,339
—
205,571
(235)
—
(4,759)
1,190
346,106
2,103
—
—
—
1,859
—
3,962
—
—
—
1,483
—
—
5,445
(440)
8,141
—
—
—
—
7,701
(47,492)
—
—
—
—
—
(39,791)
145,782
8,141
216
(14)
1,859
18
156,002
(47,492)
205,571
(235)
1,483
(4,759)
1,190
311,760
Page | 24
STATEMENTS OF CASH FLOWS
(Expressed in 000’s of Canadian dollars)
Funds generated by (used in):
OPERATING ACTIVITIES
Net income (loss)
Adjust items not affecting cash:
Share-based compensation (note 11)
Unrealized hedging (gains) losses (note 10)
Finance expenses (note 13)
Depletion and depreciation (note 7)
Impairment (note 7)
Exploration and evaluation expense (note 6)
Gain on disposition (note 5)
Deferred income tax expense (recovery) (note 16)
Decommissioning expenditures
Funds generated by operations
Change in operating non-cash working capital (note 17)
Cash provided by operations
FINANCING ACTIVITIES
Issuance of common shares (note 11)
Share issue costs (note 11)
Increase in bank indebtedness
Increase in long term debt
Debt transaction costs
Cash provided by financing activities
INVESTING ACTIVITIES
Property and equipment (acquisitions) dispositions (note 5)
Corporate acquisitions (note 5)
Exploration and evaluation asset expenditures (note 6)
Petroleum and natural gas property expenditures (note 7)
Other capital expenditures
Change in investing non-cash working capital (note 17)
Cash used in investing activities
Increase (decrease) in cash
Cash, beginning of year
Cash, end of year
Cash interest paid
Cash taxes paid
See accompanying notes to the financial statements
Page | 25
Year ended
December 31, 2014
Year ended
December 31, 2013
(47,492)
742
(17,311)
691
36,850
104,762
1,158
(2,175)
(15,975)
(1,096)
60,154
20,834
80,988
205,571
(4,759)
73,097
90,000
(881)
363,028
(29,746)
(298,000)
(6,654)
(107,922)
(642)
18,472
(424,492)
19,524
—
19,524
4,004
—
8,141
929
1,495
373
17,163
—
—
—
2,990
—
31,091
(4,853)
26,238
215
—
23,380
—
—
23,595
1,701
—
(5,197)
(52,834)
(91)
(5,001)
(61,422)
(11,589)
11,589
—
661
—
NOTES TO THE FINANCIAL STATEMENTS
1. NATURE OF THE ORGANIZATION
Petrus Resources Ltd. (“Petrus” or the “Company”) is a privately held entity which was incorporated under the laws of the Province of Alberta on
December 13, 2010. On October 8, 2014 Petrus amalgamated its two wholly owned subsidiaries, Arriva Energy Inc. and Ravenwood Energy Corp.
The principal undertaking of Petrus is the investment in energy business-related assets. The operations of the Company consist of the acquisition,
development, exploration and exploitation of these assets. The Company’s head office is located at 2400, 240 – 4th Avenue SW, Calgary, Alberta
Canada.
These financial statements report the twelve months ended December 31, 2014 and comparative periods and were approved by the Company’s Audit
Committee March 25, 2015.
2. BASIS OF PRESENTATION
(a) Statement of Compliance
These financial statements have been prepared by management in accordance with International Financial Reporting Standards (“IFRS”) as issued by
the International Accounting Standards Board (“IASB”). The policies applied in these financial statements are based on IFRS guidance issued and
outstanding as of March 25, 2015."
(b) Measurement Basis
These financial statements were prepared on the basis of historical cost except for financial derivatives and share based payments which are measured
at fair value. This method is consistent with the method used in prior years. The financial statements are presented in Canadian dollars.
(c) Critical Accounting Estimates
The timely preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that
affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may
differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized
in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the
preparation of the financial statements are outlined below.
Depletion and reserve estimates
Petroleum and natural gas assets are depleted on a unit of production basis at a rate calculated by reference to proved and probable reserves
determined in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The calculation
incorporates the estimated future cost of developing and extracting those reserves. Proved and probable reserves are estimated using
independent reservoir engineering reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which
geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known
reservoirs and which are considered commercially producible. Reserves estimates, although not reported as part of the Company’s financial
statements, can have a significant effect on net income (loss), assets and liabilities as a result of their impact on depletion and depreciation,
decommissioning liabilities, deferred taxes, asset impairments and business combinations. Independent reservoir engineers perform
evaluations of the Company’s petroleum and natural gas reserves on an annual basis. The estimation of reserves is an inherently complex
process requiring significant judgment. Estimates of economically recoverable petroleum and natural gas reserves are based upon a number of
variables and assumptions such as geoscientific interpretation, production forecasts, commodity prices, costs and related future cash flows, all
of which may vary considerably from actual results. These estimates are expected to be revised upward or downward over time, as additional
information such as reservoir performance becomes available or as economic conditions change.
Impairment indicators and cash-generating units
For purposes of impairment testing, petroleum and natural gas assets are aggregated into cash-generating units (“CGUs”), based on
separately identifiable and largely independent cash inflows. The determination of the Company’s CGUs is subject to judgment.
The recoverable amounts of CGU’s and individual assets have been determined based on the higher of the value-in-use calculations and fair
value less costs of disposal. These calculations require the use of estimates and assumptions, including the discount rate, future petroleum
and natural gas prices, expected production volumes and anticipated recoverable quantities of proved and probable reserves. These
assumptions are subject to change as new information becomes available and changes in economic conditions take place. Changes may
impact the estimated life of the field and economical reserves recoverable and may require a material adjustment to the carrying value of
petroleum and natural gas assets. The Company monitors internal and external indicators of impairment relating to its tangible assets.
Technical feasibility and commercial viability of exploration and evaluation assets
The determination of technical feasibility and commercial viability, based on the presence of proved and probable reserves, results in the
transfer of assets from exploration and evaluation assets to property, plant and equipment. As discussed above, the estimate of proved and
Page | 26
probable reserves is inherently complex and requires significant judgment. Thus any material change to reserve estimates could affect the
technical feasibility and commercial viability of the underlying assets.
Financial Instruments
Financial instruments are subject to valuations at the end of each reporting period. Generally the valuation is based on active and efficient
markets. However, certain financial instruments may not be traded on an efficient market or the market may disappear or be subject to
conditions that impede the efficiency of the market.
Decommissioning obligation
At the end of the operating life of the Company’s facilities and properties and upon retirement of its petroleum and natural gas assets,
decommissioning costs will be incurred by the Company. This requires judgment regarding abandonment date, future environmental and
regulatory legislation, the extent of reclamation activities, the engineering methodology for estimating cost, future removal technologies in
determining the removal cost and discount rates to determine the present value of these cash flows.
Income taxes
Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts recognized in income or loss
both in the period of change, which would include any impact on cumulative provisions, and in future periods. Changes in tax laws in the
jurisdictions in which the Company operates could limit the ability of the Company to obtain tax deductions in future periods. Income taxes
are subject to measurement uncertainty.
Measurement of share-based compensation
Share-based compensation recorded pursuant to share-based compensation plans are subject to estimated fair values, forfeiture rates and
the future attainment of performance criteria.
Business combinations
Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires
management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair
value of exploration and evaluation assets and petroleum and natural gas assets acquired generally require the most judgment and include
estimates of reserves acquired, forecast benchmark commodity prices and discount rates. Changes in any of the assumptions or estimates
used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill in the
purchase price allocation.
Contingencies
By their nature, contingencies will only be resolved when one or more future events occur or fail to occur. The assessment of contingencies
inherently involves the exercise of significant judgment and estimates of the outcome of future events.
3. SIGNIFICANT ACCOUNTING POLICIES
(a) Revenue recognition
Revenue from the sale of petroleum and natural gas is recognized when volumes are delivered and title passes to an external party at contractual
delivery points and are recorded gross of transportation charges incurred by the Company.
The costs associated with the delivery, including transportation and production-based royalty expenses, are recognized in the same period in which the
related revenue is earned and recorded.
Royalty income is recognized as it accrues in accordance with the terms of the respective overriding royalty agreements.
Other income is recognized as it is earned which includes interest income, processing income and gains on disposition.
(b) Property, plant and equipment
The Company’s property, plant and equipment is comprised of petroleum and natural gas assets and corporate assets.
Capitalization
Petroleum and natural gas assets are measured at cost less accumulated depletion and depreciation and accumulated impairment losses, if any.
Petroleum and natural gas assets consists of the purchase price and costs directly attributable to bringing the asset to the location and
condition necessary for its intended use. Petroleum and natural gas assets include developing and producing interests such as land acquisitions,
geological and geophysical costs, facility and production equipment, including any directly attributable general and administration costs and
share-based payments and the initial estimate of the costs of dismantling and removing an asset and restoring the site on which it was located.
Subsequent costs
Costs incurred subsequent to the determination of technical feasibility and commercial viability are recognized as developing and producing
petroleum and natural gas interests when they increase the future economic benefits embodied in the specific asset to which they relate. Such
capitalized petroleum and natural gas interests generally represent costs incurred in developing proved and/or probable reserves, and are
accumulated on a field or geotechnical area basis. The cost of day-to-day servicing of an item of petroleum and natural gas assets is expensed in
income or loss as incurred. Petroleum and natural gas assets are derecognized upon disposal or when no future economic benefits are
Page | 27
expected to arise from the continued use of the asset. Any gain or loss arising from the disposal of an asset, determined as the difference
between the net disposal proceeds and the carrying amount of the asset, is recognized in income or loss.
Depletion and depreciation
The costs related to area cost centres for petroleum and natural gas properties, including related pipelines and facilities, are depleted using a
unit-of-production method based on the commercial proved and probable reserves allocated to its CGU.
Petroleum and natural gas assets are not depleted until production commences. This depletion calculation includes actual production in the
period and total estimated proved and probable reserves attributable to the assets being depleted, taking into account total capitalized costs
plus estimated future development costs necessary to bring those reserves into production. Relative volumes of reserves and production
(before royalties) are converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil.
Proved and probable reserves are estimated using independent reservoir engineering reports and represent the estimated quantities of crude
oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to
be recoverable in future years from known reservoirs and which are considered commercially producible.
Corporate assets are stated on the balance sheet at cost less accumulated depreciation. Depreciation is calculated on a declining balance
method so as to write off the cost of these assets, less estimated residual values, over their estimated useful lives consistent with the treatment
used for tax purposes.
Impairment
The assessment for impairment entails comparing the carrying value of the CGU with its recoverable amount: that is, the higher of fair value,
less costs of disposal, and value in use. Each CGU is identified in accordance with IAS 36, Impairment of Assets. Petrus’ property, plant and
equipment are grouped into CGUs based on separately identifiable and largely independent cash inflows considering geological characteristics,
shared infrastructure and exposure to market risks. Estimates of future cash flows used in the calculation of the recoverable amount are based
on reserve evaluation reports prepared by independent reservoir engineers.
The CGU’s are reviewed quarterly for indicators of impairment. Indicators are events or changes in circumstances that indicate that the carrying
amount may not be recoverable. If indicators of impairment exist, the recoverable amount of the CGU is estimated. If the carrying amount of
the CGU exceeds the recoverable amount, the CGU is written down with an impairment recognized in net income (loss).
The recoverable amount is the higher of fair value, less costs of disposal, and the value-in-use. Fair value, less costs of disposal, is derived by
estimating the discounted after-tax future net cash flows. Discounted future net cash flows are based on forecasted commodity prices and
costs over the expected economic life of the reserves and discounted using market-based rates to reflect a market participant’s view of the risks
associated with the assets. Value-in-use is assessed using the expected future cash flows discounted at a pre-tax rate.
Impairments of property, plant and equipment are only reversed when there is significant evidence that the impairment has been reversed, but
only to the extent of what the carrying amount would have been had no impairment been recognized.
(c) Exploration & evaluation assets
Capitalization
All costs incurred after the rights to explore an area have been obtained, such as geological and geophysical costs, other direct costs of
exploration (drilling, testing and evaluating the technical feasibility and commercial viability of extraction) and appraisal and including any
directly attributable general and administration costs and share-based payments, are accumulated and capitalized as exploration and
evaluation assets.
Certain costs incurred prior to acquiring the legal rights to explore are charged directly to net income (loss).
Depletion & depreciation
Exploration and evaluation costs are not amortized prior to the conclusion of appraisal activities. At the completion of appraisal activities, if
technical feasibility is demonstrated and commercial reserves are discovered, then the carrying value of the relevant exploration and evaluation
asset will be reclassified as a property, plant and equipment asset into the CGU to which it relates, but only after the carrying value of the
relevant exploration and evaluation asset has been assessed for impairment and, where appropriate, its carrying value adjusted. Technical
feasibility and commercial viability are considered to be demonstrable when proved or probable reserves are determined to exist. If it is
determined that technical feasibility and commercial viability have not been achieved in relation to the exploration and evaluation assets
appraised, all other associated costs are written down to the recoverable amount in net income (loss).
Expired land leases included as undeveloped land in exploration and evaluation assets are recognized in exploration and evaluation cost in net
income (loss) upon expiry.
Impairment
If and when facts and circumstances indicate that the carrying value of an exploration and evaluation asset may exceed its recoverable amount,
an impairment review is performed. For exploration and evaluation assets, when there are such indications, an impairment test is carried out
Page | 28
by grouping the exploration and evaluation assets with property, plant and equipment CGUs to which they belong for impairment testing. The
equivalent combined carrying value of the CGUs is compared against the recoverable amount of the CGUs and any resulting impairment loss is
written off to net income (loss). The recoverable amount is the greater of fair value, less costs of disposal, or value-in-use.
(d) Business combinations
Business combinations are accounted for using the acquisition method. Identifiable assets acquired and liabilities and contingent liabilities assumed in a
business combination are measured at their fair values at the acquisition date. The cost of an acquisition is measured as the fair value of the assets
given, equity instruments issued and liabilities incurred or assumed at the acquisition date. The excess of the cost of the acquisition over the fair value
of the identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill. If the cost of the acquisition is less than the fair value of
the net assets of the subsidiary acquired, the difference is recognized immediately in net income (loss). Transaction costs associated with a business
combination are expensed as incurred.
(e) Decommissioning obligations
The Company’s activities give rise to dismantling, decommissioning and reclamation requirements. Costs related to these abandonment activities are
estimated by management in consultation with the Company’s engineers based on risk-adjusted current costs which take into consideration current
technology in accordance with existing legislation and industry practices.
Decommissioning obligations are measured at the present value of the best estimate of expenditures required to settle the obligations at the reporting
date. When the fair value of the liability is initially measured, the estimated cost, discounted using a risk-free rate, is capitalized by increasing the
carrying amount of the related petroleum and natural gas assets. The increase in the provision due to the passage of time, or accretion, is recognized as
a finance expense. Increases and decreases due to revisions in the estimated future cash flows are recorded as adjustments to the carrying amount of
the related petroleum and natural gas assets.
Actual costs incurred upon settlement of the liability are charged against the obligation to the extent that the obligation was previously established. The
carrying amount capitalized in petroleum and natural gas assets is depleted in accordance with the Company’s depletion policy. The Company reviews
the obligation at each reporting date and revisions to the estimated timing of cash flows, discount rates and estimated costs will result in an increase or
decrease to the obligations. Any difference between the actual costs incurred upon settlement of the obligation and recorded liability is recognized as
an increase or reduction in income.
(f) Finance expenses
Finance expense may be comprised of interest expense on borrowings, acquisition related (transaction) costs, foreign exchange expenses and accretion
of the discount on decommissioning obligations.
(g) Financial instruments
Non-derivative financial instruments
Non-derivative financial instruments are comprised of cash, accounts receivables, accounts payable and accrued liabilities and outstanding
credit facilities. Non-derivative financial instruments are recognized initially at fair value plus any directly attributable transaction costs.
Subsequent to initial recognition, non-derivative financial instruments are measured based on their classification. The Company has made the
following classifications:
•
•
•
Cash is classified as a financial asset at fair value.
Accounts receivable are classified as loans and receivables and are measured at amortized cost using the effective interest method.
Typically, the fair value of these balances approximates their carrying value due to their short term to maturity.
Accounts payable and accrued liabilities and outstanding credit facilities are classified as other liabilities and are measured at amortized
cost using the effective interest method. Due to the short term nature of accounts payable and accrued liabilities, their carrying values
approximate their fair values. The Company’s outstanding credit facilities bear interest at a floating rate and accordingly the fair market
value approximates the carrying value.
Risk Management Contracts
The Company enters into risk management contracts in order to manage its exposure to market risks from fluctuations in commodity prices,
foreign exchange rates and interest rates in the normal course of operations. Petrus has not designated its risk management contracts as
effective hedges, and thus has not applied hedge accounting, even though it considers most of these contracts to be economic hedges. As a
result, all risk management contracts are classified as fair value through profit or loss and are recorded at fair value on the balance sheet with
changes in fair value recorded in the statement of income (loss) and comprehensive income (loss). The fair values of these derivative
instruments are generally based on an estimate of the amounts that would be paid or received to settle these instruments at the balance
sheet date.
(h) Share capital
Common shares are classified as equity. Incremental costs directly attributable to the issuance of common shares are recognized as a reduction in share
capital, net of any tax effects.
Page | 29
(i) Flow-through shares
The resources expenditure deductions for income tax purposes related to exploratory activities funded by flow-through shares are renounced to
investors in accordance with tax legislation. Upon issuance of a flow-through share, a liability is recognized representing the premium paid on flow-
through common shares over regular common shares. This liability is reduced as the expenditures are incurred and tax attributes are renounced.
(j) Income taxes
The Company’s income tax expense is comprised of current and deferred tax. Income tax expense is recognized through income or loss except to the
extent that it relates to items recognized directly in equity, in which case the related income taxes are also recognized in equity.
Current tax is the expected tax payable on taxable income for the period, using tax rates enacted or substantively enacted at the reporting date, and
any adjustment to tax payable in respect of previous years.
Deferred tax is recognized on temporary differences between the carrying amounts of assets and liabilities in the financial statements and the
corresponding tax basis used in the computation of taxable income. Deferred tax liabilities are generally recognized for all taxable temporary
differences. Deferred tax assets are generally recognized for all deductible temporary differences to the extent that it is probable that taxable income
will be available against which those deductible temporary differences can be utilized. The carrying amount of deferred tax assets is reviewed at the end
of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the
asset to be recovered.
Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period in which the liability is expected to be settled or
the asset realized, based on tax rates (and tax laws) that have been enacted or substantively enacted by the end of the reporting period.
(k) Joint interests
A portion of the Company’s exploration, development and production activities are conducted jointly with others through unincorporated joint
ventures. These financial statements reflect only the Company’s proportionate interest of these joint operations and the proportionate share of the
relevant revenue and related costs.
(l) Share-based compensation
The Company follows the fair value method of valuing stock option and performance warrant grants. Share-based compensation expense is determined
based on the estimated fair value of shares on the date of grant. Forfeitures are estimated at the grant date and are subsequently adjusted to reflect
actual forfeitures. The expense is recognized over the service period, with a corresponding increase to contributed surplus. The Company capitalizes the
qualifying portion of share-based compensation expense directly attributable to the exploration and development activities of exploration and
evaluation assets and petroleum and natural gas assets, with a corresponding decrease to share-based compensation expense. At the time the stock
options or performance warrants are exercised, the issuance of common shares is recorded as an increase to shareholders’ capital and a corresponding
decrease to contributed surplus.
(m) Earnings per share
Earnings per share are presented for basic and diluted earnings. Basic per share information is computed by dividing the net income (loss) for the period
attributable to equity owners of the Company by the weighted average number of common shares outstanding during the period. The weighted
average number of shares for fully diluted earnings per share information is calculated using the treasury stock method whereby it is assumed that
proceeds obtained upon exercise of share warrants and stock options issued under the Company’s Stock Option Plan would be used to purchase
common shares at the average market price during the period. The treasury stock method also assumes that the deemed proceeds related to
unrecognized share-based payments expense are used to repurchase shares at the average market price during the period. Under the treasury stock
method, stock options and share warrants have a dilutive effect only when the average market price of the common shares during the period exceeds
the exercise price of the options or warrants (they are "in-the-money"). Exercise of in-the-money stock options and share warrants is assumed at the
beginning of the year or date of issuance, if later. Should the Company have a loss for the period, stock options and share warrants would be anti-
dilutive and therefore will have no effect on the determination of loss per share.
(n) New standards and interpretations
On January 1, 2014, the Company adopted the following new standards and amendments which became effective for periods on or after January 1,
2014:
Amendments to IAS 32, “Financial Instruments: Presentation”: The amendments clarify that the right to offset financial assets and liabilities must be
available on the current date and cannot be contingent on a future event. IAS 32 does not impact the Company’s financial statements.
Amendments to IAS 36 “Impairment of Assets.” The amendment reduces the circumstances in which the recoverable amount of CGUs is required to be
disclosed and clarifies the disclosures required when an impairment loss has been recognized or reversed in the period. Petrus adopted these
amendments effective January 1, 2014. The adoption impacted disclosures in the notes to the financial statements as an impairment loss was
recognized.
IFRIC 21, “Levies”: which clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by the relevant
legislation, occurs. The adoption of IFRIC 21 did not result in any changes to the accounting for levies by the Company.
Page | 30
Future accounting standards and interpretations
IFRS 9 Financial Instruments – IFRS 9 Financial Instruments – On July 24, the IASB issued IFRS 9 “Financial Instruments” (“IFRS 9”) to replace IAS 39,
“Financial Instruments: Recognition and Measurement”. IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if
IFRS 9 is adopted in its entirety at the beginning of a fiscal period. The Company is currently evaluating the impact of adopting IFRS 9 on the financial
statements.
In May, 2014 the IASB published IFRS 15, “Revenue from Contracts with Customers” (“IFRS 15”) replacing IAS 11, “Construction Contracts”, IAS 18,
“Revenue” and several revenue related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with
customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive when
control is transferred to the purchaser. Disclosure requirements have also been expanded. The new standard is effective for annual periods beginning
on or after January 1, 2017. The Company is currently evaluating the impact of adopting IFRS 15 on the financial statements.
4. DETERMINATION OF FAIR VALUES
A number of the Company’s accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and
liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further
information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.
Petroleum and natural gas properties and equipment and exploration and evaluation assets
The fair value of petroleum and natural gas properties and equipment recognized in a business combination, is based on market values. The
market value of petroleum and natural gas properties and equipment is the estimated amount for which property, plant and equipment could
be exchanged on the acquisition date between a willing buyer and a willing seller in an arm’s length transaction after proper marketing wherein
the parties had each acted knowledgeably, prudently and without compulsion. The market value of oil and natural gas interests (included in
petroleum and natural gas properties and equipment) and intangible exploration and evaluation assets is estimated with reference to the
discounted cash flow expected to be derived from oil and natural gas production based on externally prepared reserve reports. The risk-
adjusted discount rate is specific to the asset with reference to general market conditions. The fair value less cost to sell value used to
determine the recoverable amount of the impaired petroleum and natural gas properties are classified as Level 3 fair value measurements.
Refer to “Financial Instruments” section below for fair value hierarchy classifications.
Derivatives
The fair value of commodity price risk management contracts is determined by discounting the difference between the contracted prices and
published forward price curves as at the balance sheets date, using the remaining contracted oil and natural gas volumes and a risk-free
interest rate (based on published government rates). The fair value of options is based on option models that use published information with
respect to volatility, prices and interest rates.
Share-based payments
The fair value of employee share-based payments is measured using a Black-Scholes option-pricing model. Measurement inputs include share
price on measurement date, exercise price of the instrument, expected volatility in share price (based on weighted average historic volatility
adjusted for changes expected due to publicly available information), weighted average expected life of the instruments (based on historical
experience and general option holder behavior), expected dividend yield, risk-free interest rate (based on government bonds) and estimated
forfeiture rate at the initial grant date.
Financial Instruments
The fair value of cash, deposits, accounts receivable, accounts payable and bank indebtedness approximate their carrying amount due to the
short term nature of the instrument. The Company’s fair value measurements require disclosure about how the fair value was determined
based on significant levels of inputs described in the following hierarchy:
•
•
•
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are
those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or
indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for
commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.
Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.
Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the
fair value hierarchy level. The following tables provide fair value measurement information for financial assets and liabilities as of December 31,
2014.
Page | 31
$000s
Financial Assets
Fair value of financial instruments
Financial Liabilities
Fair value of financial instruments
5. ACQUISITIONS AND DISPOSITIONS
a. Property acquisitions and dispositions
(i)
Business combination
Carrying Amount
As at December 31, 2014
Level 1
Fair Value
Level 2
Level 3
14,609
14,609
197
197
—
—
14,609
197
—
—
On February 28, 2014 Petrus closed an acquisition of petroleum and natural gas assets in the central Alberta foothills, for total cash consideration of $19.1
million, net of adjustments. The transaction was accounted for as a business combination using the acquisition method whereby the net assets acquired
and the liabilities assumed are recorded at fair value. The acquisition was financed by way of the Company’s revolving credit facility. Acquisition related
costs, which relate to professional fees, are charged to finance expenses in the Statement of Net Income (Loss).
Petrus obtained resource tax pools equal to the total net assets acquired of $19.1 million. Neither deferred tax nor goodwill was recorded in conjunction
with the acquisition.
The following table summarizes the net assets acquired pursuant to the acquisition:
Fair value of net assets acquired $000s
Exploration and evaluation assets
Petroleum and natural gas properties and equipment
Decommissioning obligations
Total net assets acquired
5,446
17,058
(3,391)
19,113
From the date of acquisition to December 31, 2014, the assets contributed approximately $6.9 million of revenue and $4.1 million of operating income. If
the acquisition had taken place at January 1, 2014, the proforma incremental revenue and operating income (defined as revenue, net of royalties, less
operating and transportations costs) of the Company for the twelve months ended December 31, 2014 would have been approximately $8.9 million and
$5.3 million, respectively. The proforma information is not necessarily indicative of the results of operations that would have resulted had the acquisitions
been effective ono the dates indicated, or future results.
(ii)
Royalty interest disposition
On August 29, 2014 Petrus closed the disposition of non-core royalty interest properties for total cash consideration of $4.2 million after post-closing
adjustments. The Company recorded a gain of $2.2 million on the divestiture during the twelve months ended December 31, 2014.
(iii)
Business combination
On September 5, 2014 Petrus closed an acquisition of petroleum and natural gas assets in the Ferrier area of Alberta and on November 7, 2014 Petrus
closed a minor acquisition of petroleum and natural gas assets in the Peace River area of Alberta, for total cash consideration of $14.9 million, net of
adjustments. The transactions were accounted for as business combinations using the acquisition method whereby the net assets acquired and the
liabilities assumed were recorded at fair value. The acquisitions were financed by way of the Company’s revolving credit facility. Acquisition related costs,
which relate to professional fees, are charged to finance expenses in the Statement of Net Income (Loss).
Petrus obtained resource tax pools equal to the total net assets acquired of $14.9 million. Neither deferred tax nor goodwill was recorded in conjunction
with the acquisition.
The following table summarizes the net assets acquired pursuant to the acquisition:
Fair value of net assets acquired $000s
Exploration and evaluation assets
Petroleum and natural gas properties and equipment
Decommissioning obligations
Total net assets acquired
10,864
7,703
(3,695)
14,872
From the date of acquisition to December 31, 2014, the assets contributed approximately $0.7 million of revenue and $0.4 million of operating income. If
the acquisition had taken place at January 1, 2014, the proforma incremental revenue and operating income (defined as revenue, net of royalties, less
operating and transportations costs) of the Company for the twelve months ended December 31, 2014 would have been approximately $2.4 million and
Page | 32
$1.6 million, respectively. The proforma information is not necessarily indicative of the results of operations that would have resulted had the acquisitions
been effective ono the dates indicated, or future results.
5. ACQUISITIONS AND DISPOSITIONS
b. Corporate acquisitions and dispositions
(i) Arriva Energy Inc.
On September 8, 2014 Petrus acquired all of the issued and outstanding shares of Arriva Energy Inc. (“Arriva”) at a price of $2.05 per share. As
consideration Petrus paid $103 million in cash by way of its revolving credit facility. Transaction costs of $0.2 million were charged to general &
administrative expenses. Arriva was a privately held entity with oil and natural gas operations in the Ferrier area of Alberta, Canada. Petrus acquired the
business in order to establish a core operating area in this geographic location as well as to provide accretive, liquids rich natural gas weighted petroleum
and natural gas assets to Petrus.
Results from Arriva operations are included in the Company’s consolidated financial statements from the closing date of the transaction. Petrus obtained
the tax base of the identifiable assets and liabilities of Arriva at pre-acquisition amounts and obtained tax basis for the cost of the shares acquired. No
goodwill was recorded in connection with the acquisition. The temporary differences gave rise to an $18.5 million deferred tax liability.
The acquisition has been accounted for using the acquisition method based on fair values. The deferred tax liability is based upon information available at
the time and may be subject to change in a future period:
Fair value of net assets acquired $000s
Accounts receivable
Other current assets
Current liabilities
Petroleum and natural gas properties and equipment
Exploration and evaluation assets
Bank debt
Decommissioning obligations
Deferred income tax liability
Risk management liability
Total net assets acquired
Cash consideration
Excess of net assets acquired over consideration
593
1,520
(1,042)
113,908
8,809
—
(2,330)
(18,450)
(8)
103,000
103,000
—
From the date of acquisition to December 31, 2014, the acquisition contributed approximately $5.7 million of revenue and $3.7 million of operating income.
If the acquisition had taken place at January 1, 2014, the proforma incremental revenue and operating income defined as revenue, net of royalties, less
operating and transportations costs of the Company for the twelve months ended December 31, 2014 would have been approximately $15.0 million and
$10.1 million, respectively. The proforma information is not necessarily indicative of the results of operations that would have resulted had the acquisitions
been effective on the dates indicated, or future results.
Page | 33
(ii) Ravenwood Energy Corp.
On October 8, 2014 Petrus acquired all of the issued and outstanding common shares of Ravenwood for $195 million, inclusive of debt and transaction
costs. Ravenwood was a privately held entity with oil and natural gas operations in the Thorsby and Pembina areas of Alberta, Canada and was controlled
by a shareholder of Petrus. Petrus acquired the business in order to establish a core operating area in this geographic location as well as to provide
accretive, oil weighted petroleum and natural gas assets to Petrus. Transaction costs of $0.4 million were incurred in conjunction with the acquisition and
relate to professional service fees. These transaction costs were recorded in the Statement of Net Income (Loss) as general & administrative expenses. The
transaction was accounted for as a business combination using the acquisition method whereby the net assets acquired and the liabilities assumed are
recorded at fair value. The acquisition was financed by way of a Term Loan (note 8) as well as proceeds from the Company’s equity issuances (note 11).
The acquisition has been accounted for using the acquisition method based on the information available at the date of these financial statements. The
amounts may be subject to change in a future period:
Fair value of net assets acquired $000s
Cash
Accounts receivable
Other current assets
Risk management asset
Current liabilities
Petroleum and natural gas properties and equipment
Exploration and evaluation assets
Bank debt
Decommissioning obligations
Deferred income tax liability
Risk management liability
Total net assets acquired
Cash consideration
Excess of net assets acquired over consideration
30,703
7,177
1,191
177
(22,429)
226,524
12,706
(28,249)
(20,169)
(11,825)
(806)
195,000
195,000
—
From the date of acquisition to December 31, 2014, the acquisition contributed approximately $13 million of revenue and $8.9 million of operating income.
If the acquisition had taken place at January 1, 2014, the proforma incremental revenue and operating income defined as revenue, net of royalties, less
operating and transportations costs of the Company for the twelve months ended December 31, 2014 would have been approximately $55.2 million and
$43.7 million, respectively. The proforma information is not necessarily indicative of the results of operations that would have resulted had the acquisitions
been effective ono the dates indicated, or future results.
6. EXPLORATION AND EVALUATION ASSETS
The components of the Company’s Exploration and Evaluation assets are as follows:
$000s
Balance, December 31, 2012
Additions
Capitalized G&A and share-based compensation
Transfers to property, plant and equipment
Balance, December 31, 2013
Additions
Property acquisitions (note 5)
Corporate acquisitions (note 5)
Exploration and evaluation expense
Capitalized G&A and share-based compensation
Transfers to property, plant and equipment
Balance, December 31, 2014
45,791
4,442
1,220
(924)
50,529
5,753
16,310
21,514
(1,158)
1,272
(147)
94,073
Exploration and evaluation assets consist of Petrus’ undeveloped land and exploration and development projects which are pending the determination
of technical feasibility. Additions represent the Company’s share of costs incurred on these assets during the period. Exploration and evaluation assets
are not subject to depletion. For the year ended December 31, 2014 the Company incurred $1.2 million of exploration and evaluation expense in the
Statement of Net Income (Loss) and Comprehensive Income (Loss) which relates to expiring undeveloped land in non-core properties (2013 - $Nil).
During the year ended December 31, 2014 the Company capitalized $1.3 million (2013 - $1.2 million) of general & administrative expenses (“G&A”)
directly attributable to exploration activities. Included in this amount is non-cash share-based compensation of $0.3 million (2013 - $0.5 million).
Page | 34
7. PROPERTY, PLANT AND EQUIPMENT
$000s
Balance, December 31, 2012
Cash additions
Acquisitions (dispositions)
Capitalized G&A and share-based compensation
Transfers from exploration and evaluation assets
Depletion & depreciation
Change in decommissioning provision
Balance, December 31, 2013
Additions
Property acquisitions (note 5)
Property (dispositions) (note 5)
Corporate acquisitions (note 5)
Capitalized G&A and share-based compensation
Transfers from exploration and evaluation assets
Depletion & depreciation
Increase in decommissioning provision (note 11)
Impairment loss
Balance, December 31, 2014
Cost
Accumulated
DD&A
Net book value
120,701
52,169
(1,901)
1,220
924
—
2,778
175,891
107,662
17,675
(2,880)
317,935
1,272
147
—
43,492
—
661,194
(8,715)
—
200
—
—
(17,163)
—
(25,678)
—
—
816
—
—
—
(36,850)
—
(104,762)
(166,474)
111,985
52,169
(1,701)
1,220
925
(17,163)
2,778
150,213
107,662
17,675
(2,064)
317,935
1,272
147
(36,850)
43,492
(104,762)
494,720
Estimated future development costs of $199.4 million (2013 - $58.8 million) associated with the development of the Company’s proved plus probable
undeveloped reserves were included with the costs subject to depletion. During the year ended December 31, 2014 the Company capitalized $1.3
million (2013 - $1.2 million) of general & administrative expenses (“G&A”) directly attributable to development activities. Included in this amount is
non-cash share-based compensation of $0.3 million (2013 - $0.5 million).
At December 31, 2014, the Company recorded property, plant and equipment impairments of $104.8 million, resulting from a decline in oil and natural
gas price forecasts on each of its four CGUs (Central Alberta - $60.3 million; Ferrier - $26.1 million; Peace River - $13.6 million; and Foothills - $4.8
million). The recoverable amounts of the Company’s CGUs were estimated at fair value less costs to sell, based on the net present value of pre-tax cash
flows from oil and natural gas reserves, using reserve values estimated by independent reserve evaluators. The recoverable amount for each of the
Company’s four CGUs was as follows: Central Alberta - $155.2 million; Ferrier - $100.2 milliion; Peace River - $59.7 million; and Foothills - $120.8 million.
In calculating the net present values of cash flows from oil and natural gas reserves, the Company used a pre-tax discount rate of 12% and the following
forward commodity price estimates:
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Remainder
(1)
Source: Sproule Canadian price forecasts ($CDN/bbl) for Canadian Light Sweet Crude
Foreign Exchange
Rate
Oil (CDN$/bbl)(1)
0.850
0.870
0.870
0.870
0.870
0.870
0.870
0.870
0.870
0.870
0.870
0.870
70.35
87.36
98.28
99.75
101.25
103.85
105.40
106.99
108.59
110.22
111.87
+1.5%/yr
AECO Gas (CDN$/mcf)
3.32
3.71
3.90
4.47
5.05
5.13
5.22
5.31
5.40
5.49
5.58
1.5%/yr
As at December 31, 2014, a one percent change in pre-tax discount rate is estimated to change the impairment by approximately $19.2 million; a
$1.00/Bbl change in the price of oil is estimated to change the impairment by approximately $4.6 million; and a $0.10/mcf change in the price of natural
gas is estimated to change the impairment by approximately $8.4 million.
Page | 35
8. DEBT
(a) Revolving Credit Facility
On July 31, 2014 the Company syndicated its existing credit facility to five institutions and structured a $100 million, committed, secured 364-day
revolving plus one year term-out facility. It was comprised of a $20 million operating facility, as well as an $80 million syndicated demand facility. The
facilities bear interest at Canadian bank prime, or at the Company’s option, Canadian bankers’ acceptances, plus applicable margin and stamping fee.
The stamping fees range, depending on Petrus’ debt to EBITDA (which is: earnings before interest, taxes, depreciation and amortization as defined in
the banking agreement), between 100 bps and 250 bps on Canadian bank prime borrowings and between 200 bps and 350 bps on Canadian dollar
bankers’ acceptances. The undrawn portion of the facilities, are subject to a standby fee in the range of 50 bps to 87.50 bps.
Concurrent with the closing of the acquisition of Arriva Energy Inc., Petrus obtained commitment from its syndicated lenders to increase its demand
credit facility from $80 million to $120 million for a total combined credit facility, inclusive of the $20 million operating facility, of $140 million.
Concurrent with the closing of the acquisition of the Ravenwood Energy Corporation, Petrus obtained commitment from its syndicated lenders to
increase its demand credit facility from $120 million to $180 million for a total combined credit facility, inclusive of the $20 million operating facility, of
$200 million. At December 31, 2014, the Company had no outstanding letters of credit against the facility (December 31, 2013; Nil) and had drawn $100
million against the facility (December 31, 2013; $23.4 million).
The amount of the credit facility is subject to a borrowing base review performed on a semi-annual basis by the lender, based primarily on reserves and
commodity prices estimated by the lenders as well as other factors. A decrease in the borrowing base could result in a reduction to the available credit
facility. The next scheduled review of the borrowing base is to take place on May 31, 2015. The Company has provided collateral by way of a $600
million debenture over all of the present and after acquired property of the Company.
The facilities carry a financial covenant which limits the Company’s ability to borrow amounts greater than the facility limit as well as:
(a) a financial covenant of PV10 to Net Secured Debt Ratio being less than 1.25 to 1.00 whereby Net Secured Debt (as defined by the banking
agreement) means all amounts owing under the Credit Facility and any other secured debt of Petrus on a consolidated basis, minus
restricted cash and cash equivalents and “PV10” means the discounted net present value (at a discount rate of 10%) of Petrus’ proved
reserves, as adjusted for commodity swaps then in effect and
(b) certain financial covenants only when any indebtedness under the second lien term facility remain outstanding which are:
a.
b.
c.
The Working Capital Ratio will not be less than 1.00 to 1.00;
The Proved Asset Coverage Ratio will not be less than 1.25 to 1.00; and
The PDP Asset Coverage Ratio will not be less than 1.00 to 1.00.
Under the facility agreement, for purposes of the Working Capital Ratio, current assets are the current assets under IFRS plus any undrawn availability
under the Revolving Credit Facility, less any non-cash amount required to be included in current assets as the result of the application of IFRS including
non-cash commodity and interest rate hedges assets and liabilities. Current liabilities are the current liabilities under IFRS, excluding (a) non-cash
obligations under IFRS including non-cash commodity and interest rate hedges assets and liabilities, and (b) the current portion of long-term debt,
including the term loan debt.
At December 31, 2014 the Company was in compliance with financial covenants under the revolving credit facility.
(b) Term Loan
Concurrent with the closing of the acquisition of Ravenwood Energy Corp., Petrus closed a $90 million second lien term loan facility with Macquarie
Bank Limited (the "Macquarie Facility"). The Term Loan matures and is repayable in full 24 months following funding (October 1, 2016). Interest is due
and payable monthly and accrues at a per annum rate of (three-month) the Canadian Dealer offered Rate (CDOR) plus 700 basis points. The Term Loan
is subject to three financial covenants: (1) the same financial covenant of PV10 to Net Secured Debt Ratio being less than 1.25 to 1.00 as the Credit
Facilities; (2) a covenant that Petrus may not, as of the effective date of each annual independent engineering reserve report and each internally
prepared semi-annual internally prepared reserve report, permit the PDP to Net Secured Debt Ratio to be less than 1.00 to 1.00 where “PDP” means the
present value (discounted at 10.0%) of future net revenues attributable to Petrus’ PDP reserves and (3) Petrus' working capital ratio (current assets to
current liabilities will not be less than 1.0 to 1.0.
Under the agreement, current assets are the current assets under IFRS plus any undrawn availability under the Revolving Credit Facility, less any non-
cash amount required to be included in current assets as the result of the application of IFRS including non-cash commodity and interest rate hedges
assets and liabilities. Current liabilities are the current liabilities under IFRS, excluding (a) non-cash obligations under IFRS including non-cash
commodity and interest rate hedges assets and liabilities, and (b) the current portion of long-term debt, including the term loan debt.
The Term Loan is secured with a $250 million second lien priority interest on the same collateral as the Credit Facilities and requires a certain level of
production volume to be hedged in 2015 and 2016. At December 31, 2014 the Company was in compliance with all covenants of the term loan.
9. DECOMMISSIONING OBLIGATION
The decommissioning liability was estimated based on the Company’s net ownership interest in all wells and facilities, the estimated costs to abandon
and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. The estimated future cash flows have been
discounted using an average risk free rate of 2.33 percent and an inflation rate of 2 percent (December 31, 2013; 3 percent and 2 percent, respectively).
Changes in estimates in 2014 are due to the decrease in discount rate from 3 percent to 2.33 percent and changes in estimated well life, (change in
Page | 36
estimates in 2013 due to changes in estimated costs for abandonments and reclamations). The Company has estimated the net present value of the
decommissioning obligations to be $58.6 million as at December 31, 2014 ($15.6 million at December 31, 2013). The undiscounted, uninflated total
future liability at December 31, 2014 is $61.8 million ($19.7 million at December 31, 2013). The payments are expected to be incurred over the
operating lives of the assets. The following table reconciles the decommissioning liability:
$000s Balance, December 31, 2012
Dispositions
Liabilities incurred
Change in estimates
Accretion expense
Balance, December 31, 2013
Property acquisitions (note 5)
Corporate acquisitions (note 5)
Liabilities incurred
Liabilities settled
Change in estimates
Accretion expense
Balance, December 31, 2014
10. FINANCIAL RISK MANAGEMENT
12,396
(80)
749
2,109
373
15,547
7,086
22,498
7,009
(1,096)
6,899
691
58,634
The Company utilizes commodity contracts as a risk management technique to mitigate exposure to commodity price volatility. The following table
summarizes the financial derivative contracts Petrus has outstanding as at December 31, 2014:
Natural Gas
Contract Period
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Jan. 1, 2015 to Dec. 31, 2015
Jan. 1, 2015 to Dec. 31, 2015
Jan. 1, 2015 to Mar. 31, 2015
Apr. 1, 2015 to Oct. 31, 2015
Nov. 1, 2015 to Mar. 31, 2016
Crude Oil
Contract Period
Jan. 1, 2015 to Dec. 31, 2015
Jan. 1, 2015 to Dec. 31,2015
Jan. 1, 2015 to Mar. 31, 2015
Apr. 1, 2015 to Dec. 31, 2015
Apr. 1, 2015 to Dec. 31, 2015
Electric Power
Contract Period
Jan. 1, 2015 to Dec. 31, 2015
Risk Management Asset and Liability
$000s At December 31, 2013
Commodity derivatives
$000s At December 31, 2014
Commodity derivatives
Type
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Costless Collar
Fixed price
Fixed price
Fixed price
Fixed price
Daily Volume
Price (CAD$/GJ)
2,000 GJ
2,000 GJ
1,000 GJ
1,000 GJ
1,000 GJ
500 GJ
1,000 GJ
1,000 GJ
5,000 GJ
4,000 GJ
3,000 GJ
3,000 GJ
6,000 GJ
$3.75/GJ
$3.81/GJ
$3.84/GJ
$4.04/GJ
$4.10/GJ
$4.18/GJ
$4.43/GJ
$4.83/GJ
$3.50 – 3.63/GJ
$3.49/GJ
$4.17/GJ
$3.35/GJ
$3.74/GJ
Type
Daily Volume
Price ($/Bbl)
Fixed price
Fixed Price
Fixed Price
Fixed Price
Fixed Price
200 Bbl
100 Bbl
500 Bbl
250 Bbl
250 Bbl
WTI $CAD100.00/Bbl
WTI $CAD 95.50/Bbl
WTI $95.00-104.50/Bbl
WTI $97.80/Bbl
WTI $92.50-103.50/Bbl
Type
Annual Volume
Price (CAD)
Fixed price
12,264 MW
$50.00/MWH
Current Asset
Current Liability
26
26
2,287
2,287
Current Asset
Current Liability
14,609
14,609
197
197
Page | 37
Earnings Impact of Realized and Unrealized Gains (Losses) on Commodity Financial Instruments
$000s
Realized loss
Unrealized gain (loss)
Year ended
Dec. 31, 2014
Year ended
Dec. 31, 2013
(918)
17,311
16,393
(1,311)
(1,495)
(2,806)
11. SHARE CAPITAL
Authorized
The authorized share capital consists of an unlimited number of common voting shares without par value.
Issued and Outstanding
Common shares $000s except share amounts
Balance, December 31, 2012
Common shares issued under private placement (a)
Flow-through shares issued, net of premium (a)
Tax effect of share issue costs
Common shares issued under private placement (b)
Balance, December 31, 2013
Common shares issued under private placement (c)
Flow-through shares issued, net of premium (c)
Common shares issued under private placement (d)
Flow-through shares issued, net of premium (d)
Common shares issued under private placement (e)
Common shares issued under private placement (f)
Share issue costs
Tax effect of share issue costs
Balance, December 31, 2014
Number of Shares
Amount
86,275,633
52,655
34,024
—
14,286
86,376,598
15,256,000
115,000
17,784,724
200,000
20,725,276
135,000
—
—
140,592,598
144,119
105
68
18
29
144,339
49,582
374
71,139
800
82,901
540
(4,759)
1,190
346,106
Share Issuances
(a) On April 26, 2013 the Company issued 52,655 common shares at a price of $2.00 per share and 34,024 flow-through shares at a price of $2.40
per share for total gross proceeds of $0.2 million. Of the issuance price, $0.40 per share or $0.01 million was determined to be the premium on
the flow-through shares. The issuance was made pursuant to an Exempt Offering which provided employees and key consultants an
opportunity to purchase common and flow-through shares of the Company. The common shares issued are subject to a restricted hold period
which expired on August 27, 2013.
(b) On August 19, 2013 the Company issued 14,286 common shares at a price of $2.00 per share for gross proceeds of $0.03 million. The issuance
was made pursuant to an Exempt Offering which provided employees and key consultants an opportunity to purchase common and flow-
through shares of the Company. The common shares issued are subject to a restricted hold period which expired on December 19, 2013.
(c) On June 2, 2014 the Company issued 15,256,000 common shares at a price of $3.25 per share and 115,000 flow-through shares at a price of
$3.90 per share for total gross proceeds of $50.0 million. Of the issuance price, $0.65 per share or $0.1 million was determined to be the
premium on the flow-through shares. The common shares issued were subject to a restricted hold period which expired on October 3, 2014.
(d) On September 5, 2014 the Company issued 17,784,724 common shares at a price of $4.00 per share and 200,000 flow-through shares at a price
of $4.80 per share for total gross proceeds of $72.1 million. Of the issuance price, $0.80 per share or $0.2 million was determined to be the
premium on the flow-through shares. The common shares issued are subject to a restricted hold period which expired on January 6, 2015.
(e) On September 23, 2014 the Company issued 20,725,276 common shares at a price of $4.00 per share for total gross proceeds of $82.9 million.
The common shares issued are subject to a restricted hold period which expired on January 24, 2015.
(f) On October 15, 2014 the Company issued 135,000 common shares at a price of $4.00 per share for total gross proceeds of $0.5 million. The
common shares issued are subject to a restricted hold period which expired on February 15, 2015.
SHARE-BASED COMPENSATION
Performance Warrants
The Company has issued performance warrants to employees, consultants and directors of the Company. Performance warrants were granted and vest
based on three criteria, time (one third vest per year), market (one third vest as certain share price hurdles are achieved) and employment or service.
The warrants expire five years from the date of issuance. Upon exercise of the warrants the Company may settle the obligation by issuing common
shares of the Company. The shares to be offered consist of common shares of the Company`s authorized but unissued common shares. The aggregate
number of shares issuable upon the exercise of all warrants granted shall not exceed 20% of the 32,113,016 issued and outstanding shares as at April
30, 2012. At December 31, 2014, 6,407,603 (December 31, 2013; 6,422,603) performance warrants were issued and outstanding.
Page | 38
Balance, December 31, 2012
Forfeited or expired
Granted
Balance, December 31, 2013
Forfeited or expired
Balance, December 31, 2014
Exercisable, December 31, 2014
Number of warrants
outstanding
Weighted Average
Exercise Price ($)
6,422,603
(417,000)
417,000
6,422,603
(15,000)
6,407,603
3,799,564
$2.00
$2.00
$2.25
$2.02
$2.00
$2.02
$2.01
The following tables summarize information about the performance warrants granted since inception:
Range of Exercise Price
Warrants Outstanding
Warrants Exercisable
$2.00 - $2.25
Number
granted
6,407,603
6,407,603
Weighted
average
exercise price
$2.02
$2.02
Weighted
average
remaining life
(years)
Number
exercisable
2.09
2.09
3,799,564
3,799,564
Weighted
average
exercise price
$2.01
$2.01
Weighted
average
remaining life
(years)
2.03
2.03
At December 31, 2014 there were 3,799,564 exercisable performance warrants. The weighted average fair value of each warrant granted during the
current year was Nil as no warrants were granted (2013 - $0.24). The Black-Scholes pricing model uses the following weighted average assumptions
(December 31):
Risk free interest rate
Expected life (years)
Estimated volatility of underlying common shares (%)
Estimated forfeiture rate
Expected dividend yield (%)
2014
—
—
—
—
—
2013
1.23%
5
50%
20%
0%
Petrus estimated the volatility of the underlying common shares by analyzing the volatility of peer group private companies with similar corporate
structure, oil and gas assets and size. With respect to the market condition inherent in the warrants, Petrus estimated the probability of achieving the
condition and applied the probability to each individual vesting tranche in order to fairly estimate the fair value of each warrant.
Stock Options
The Company has a stock option plan in place whereby it may issue stock options to employees, consultants and directors of the Company. The
aggregate number of shares that may be acquired upon exercise of all Options granted pursuant to the plan shall, at any date or time of determination,
be equal to ten percent (10%) of the number that is equal to (i) the number of the Company’s basic Common shares then issued and outstanding; minus
(ii) a number equal to five (5) times the number of Common Shares that are issuable upon exercise of the then outstanding Performance Warrants
minus (iii) a number equal to fifty percent (50%) of the number of Common Shares that have previously been issued upon the exercise of Performance
Warrants. The options vest based on time (one third vest per year starting on the date of grant) and expire five years from the date of issuance. At
December 31, 2014, 6,155,000 (December 31, 2013; 4,355,000) stock options were outstanding. The summary of stock option activity is presented
below:
Balance, December 31, 2012
Forfeited or expired
Granted
Balance, December 31, 2013
Granted
Forfeited or expired
Balance, December 31, 2014
Exercisable, December 31, 2014
Number of stock
options
Weighted Average
Exercise Price ($)
3,995,000
(224,000)
584,000
4,355,000
1,805,000
(45,000)
6,115,000
2,736,666
$1.75
$1.75
$2.20
$1.84
$3.18
$1.75
$2.21
$1.78
Page | 39
The following tables summarize information about the stock options granted since inception:
Range of Exercise Price
Stock Options Outstanding
Stock Options Exercisable
$1.75 - $2.00
$2.01 - $2.75
$2.76 - $4.00
Number
granted
3,875,000
1,050,000
1,190,000
6,115,000
Weighted
average
exercise price
$1.76
$2.38
$3.50
$2.21
Weighted
average
remaining life
(years)
2.53
4.09
4.59
3.21
Number
exercisable
2,578,333
158,333
—
2,736,666
Weighted
average
exercise price
$1.75
$2.25
—
$1.78
Weighted
average
remaining life
(years)
2.47
3.96
—
2.56
The weighted average fair value of each stock option granted of $1.12 (2013 - $0.79) per option is estimated on the date of grant using the Black-
Scholes pricing model with the following weighted average assumptions (at December 31):
Risk free interest rate
Expected life (years)
Estimated volatility of underlying common shares (%)
Estimated forfeiture rate
Expected dividend yield (%)
2014
1.20% - 1.40%
5
50%
20%
0%
2013
1.20%
5
50%
20%
0%
Petrus estimated the volatility of the underlying common shares by analyzing the volatility of peer group private companies with similar corporate
structure, oil and gas assets and size.
The following table summarizes the Company’s share-based compensation costs:
$000s
Expensed in net income
Capitalized to exploration and evaluation assets
Capitalized to property, plant and equipment
Total share-based compensation
2014
2013
741
371
371
1,483
929
465
465
1,859
12. EARNINGS PER SHARE
Earnings per share amounts are calculated by dividing the net income for the period attributable to the common shareholders of the Company by the
weighted average number of common shares outstanding during the year.
Net income (loss) for the year ($000s)
Weighted average number of common shares – basic (000s)
Weighted average number of common shares – diluted (000s)
Net income per common share – basic
Net income per common share – diluted
Year ended
December 31, 2014
(47,492)
106,719
106,719
(0.45)
(0.45)
Year ended
December 31, 2013
8,141
86,377
87,238
0.09
0.09
In computing earnings per share for the twelve months ended December 31, 2014, 1,609,101 warrants and 2,331,072 stock options were considered
however no instruments were added to the calculation as their impact is anti-dilutive. In computing diluted earnings per share for the twelve months
ended December 31, 2013, 861,110 stock options were considered however no instruments were added to the calculation as their impact is anti-
dilutive.
13. FINANCE EXPENSES
The components of finance expenses are as follows:
$000s
Cash:
Interest
Acquisition related expenses
Foreign exchange
Non cash:
Accretion on decommissioning obligations (note 9)
Total finance expenses
2014
2013
4,007
233
(235)
691
4,696
739
—
373
1,112
Page | 40
14. CAPITAL MANAGEMENT
The Company’s general capital management policy is to maintain a sufficient capital base in order to manage its business to enable the Company to
increase the value of its assets and therefore its underlying share value. The Company’s objectives when managing capital are (i) to manage financial
flexibility in order to preserve the Company’s ability to meet financial obligations; (ii) maintain a capital structure that allows Petrus the ability to
finance its growth using internally generated cashflow and (iii) to maintain a flexible capital structure which optimizes the cost of capital at an
acceptable risk level and provides an optimal return to equity holders.
In the management of capital, Petrus includes share capital and total net debt, which is made up of debt and working capital (current assets less current
liabilities). Petrus manages its capital structure and makes adjustments in light of economic conditions and the risk characteristics of the underlying
assets. In order to maintain or adjust the capital structure, Petrus may issue new equity, increase or decrease debt, adjust capital expenditures and
acquire or dispose of assets (refer to Note 8 for restrictions).
15. FINANCIAL INSTRUMENTS
Risks associated with Financial Instruments
Credit risk
The Company may be exposed to certain losses in the event that counterparties to financial instruments fail to meet their obligations in accordance
with agreed terms. The Company mitigates this risk by entering into transactions with highly rated major financial institutions and by routinely assessing
the financial strength of its customers.
At December 31, 2014, financial assets on the balance sheet are comprised of cash, deposits, risk management assets and accounts receivable. The
maximum credit risk associated with these financial instruments is the total carrying value.
The Company’s accounts receivable are with customers and joint venture partners in the petroleum and natural gas business and are subject to normal
credit risk. Concentration of credit risk is mitigated by marketing the majority of the Company’s production to reputable and financially sound
purchasers under normal industry sale and payment terms. As is common in the petroleum and natural gas industry in western Canada, Petrus’
receivables relating to the sale of petroleum and natural gas are received on or about the 25th day of the following month. Of the $23.3 million of
accounts receivable outstanding at December 31, 2014 (December 31, 2013; $10.9 million), $16.6 million is owed from 19 parties (December 31, 2013 -
$5.0 million from ten parties), and the majority of the balance was received subsequent to year end. The remaining amounts are expected to be
collected and no allowance has been recorded. As at December 31, 2014 and December 31, 2013, 90% of Petrus’ accounts receivable were all aged less
than 90 days and the Company does not anticipate any significant collection issues.
The Company’s risk management assets are with chartered Canadian banks and the Company does not consider the assets to carry material credit risk.
Liquidity risk
Liquidity risk relates to the risk the Company will encounter difficulty in meeting obligations associated with its financial liabilities that are settled by
cash as they become due. The Company’s approach to managing liquidity risk is to ensure, as much as possible, that it will have sufficient liquidity to
meet its’ short-term and long-term financial obligations when due, under both normal and unusual conditions without incurring unacceptable losses or
risking harm to the Company’s reputation. The financial liabilities on its balance sheet consist of accounts payable, bank indebtedness, long term debt,
risk management liabilities and accrued liabilities. The Company anticipates it will continue to have adequate liquidity to fund its financial liabilities
through its future cash flows.
Typically the Company ensures that it has sufficient cash on demand to meet expected operational expenses for a normal period. To achieve this
objective, the Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. Further, the
Company utilizes authorizations for expenditures on operated and non-operated projects to further manage capital expenditures. The Company also
attempts to match its payment cycle with collection of oil and natural gas revenue on the 25th day of each month.
At December 31, 2014, the Company had a $200 million credit facility, of which $100 million was undrawn (December 31, 2013, the Company had a $60
million credit facility of which $36.6 million was undrawn). Petrus anticipates it will continue to have adequate liquidity to fund its financial liabilities
through its future funds from operations and available bank debt. The Company is exposed to the risk of reductions to its borrowing base for purposes
of the revolving credit facility or term loan.
Interest Rate Risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company’s cash and accounts
receivable are not exposed to significant interest rate risk. The revolving credit facility and long term debt are exposed to interest rate cash flow risk as
the instruments are priced on a floating interest rate subject to fluctuations in market interest rates. The remainder of Petrus’ financial assets and
liabilities are not exposed to interest rate risk. A 1% change in the Canadian prime interest rate in the twelve months ended December 31, 2014 would
have changed income by approximately $1.1 million, which relates to interest expense on the average outstanding revolving credit facility and long
term debt during the period, assuming that all other variables remain constant (twelve months ended December 31, 2013 – $0.1 million). The
Company considers this risk to be limited.
Page | 41
Commodity Price Risk
Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. A significant change in
commodity prices can materially impact the Company’s borrowing base limit under its revolving credit facility and may reduce the Company’s ability to
raise capital. Commodity prices for petroleum and natural gas are not only influenced by Canadian and United States demand, but also by world events
that dictate the levels of supply and demand.
For the twelve months ended December 31, 2014, it is estimated that a $0.25/mcf change in the price of natural gas would have changed net income by
$1.9 million (twelve months ended December 31, 2013 - $941,153). For the twelve month period ended December 31, 2014, it is estimated that a
$5.00/CDN WTI/bbl change in the price of oil would have changed net income by $4.1 million (twelve months ended December 31, 2013 - $2.6 million).
16. DEFERRED INCOME TAXES
$000s
Income (loss) before taxes
Combined federal and provincial tax rate
Computed “expected” tax expense (recovery)
Increase/(decrease) in taxes resulting from:
Permanent items
Tax impact of flow-through shares
Other
Deferred tax expense (recovery)
Effective tax rate
Net book value of assets in excess of tax pools
Asset retirement obligations
Share issuance costs
Non capital loss carry-forwards
Unrealized hedging gain
Deferred tax liability
$000s
2014
2013
(66,363)
25%
(16,591)
680
352
(416)
(15,975)
24.0%
11,131
25%
2,783
465
—
(258)
2,990
26.9%
2013
(13,655)
3,887
672
3,887
565
(4,644)
(44,507)
14,658
1,449
14,241
(3,603)
(17,763)
17,953
(119)
(540)
3,009
(4,328)
15,975
(48,805)
10,890
1,316
7,345
159
(29,094)
2013
Change through
Statement of
Income (Loss)
Change through
Balance Sheet
2012
The components of the Company’s deferred tax liability at December 31, 2014 and December 31, 2013 are as follows:
$000s
2014
Change through
Statement of
Income (Loss)
Change through
Balance Sheet
Net book value of assets in excess of tax pools
Asset retirement obligations
Share issuance costs
Non capital loss carry-forwards
Unrealized hedging gain
Deferred tax liability
The Company had non-capital losses of approximately $56.7 million (2013 - $15.6 million) which may be applied against future income for Canadian tax
purposes. These non-capital losses expire in 2024 and onwards.
(13,655)
3,887
672
3,887
565
(4,644)
(3,168)
78
(260)
(14)
374
(2,990)
(730)
710
18
—
—
(2)
(9,763)
3,099
913
3,901
191
(1,658)
17. SUPPLEMENTAL CASH FLOW INFORMATION
The following table reconciles the changes in non-cash working capital as disclosed in the statements of cash flows:
$000s
Source (use) in non-cash working capital:
Accounts receivable
Deposits and prepaid expenses
Accounts payable and accrued liabilities
Working capital deficiency acquired
Operating activities
Financing activities
Investing activities
Page | 42
2014
2013
(12,455)
(739)
58,858
(7,239)
38,425
20,834
(881)
18,472
769
287
(10,910)
—
(9,854)
(4,853)
—
(5,001)
18. OPERATING EXPENSES
The Company’s gross operating expenses for 2014 were $20.7 million (December 31, 2013; $12.7 million) which includes $7.9 million of processing,
gathering and compression charges (December 31, 2013; $2.9 million).
The Company generated processing income recoveries of $2.6 million (December 31, 2013; $0.7 million) which reduced the Company’s reported gross
operating expenses to $18.1 million for the year ended December 31, 2014 ($12.0 million for the year ended December 31, 2013).
19. GENERAL AND ADMINISTRATIVE EXPENSES
The Company’s general and administrative expenses consisted of the following expenditures:
$000s
Salaries and benefits
Subscriptions and licenses
Office costs
Legal, accounting and consulting
Transaction costs
Capitalized general and administrative
20. RELATED PARTY TRANSACTIONS
2014
2013
3,604
490
552
1,127
1,021
(1,802)
4,992
1,885
118
674
690
(1,511)
1,856
The Company consider its directors and officers to be key management personnel. The following table outlines transactions with key management
personnel:
$000s
Salaries and wages
Short term employee benefits
Share based compensation, gross
2014
2013
711
26
472
1,209
881
26
1,435
2,342
Included in share issue costs are fees of $0.3 million which relate to the Company’s September 2014 financing. The fees were paid to a company controlled
by a director of Petrus.
21. COMMITMENTS
The commitments for which the Company is responsible are as follows:
$000s
Office equipment lease
Corporate office lease
Total commitments
22. SUBSEQUENT EVENTS
Financial Risk Management
Total
< 1 year
1-5 years
9
927
935
3
502
505
6
425
431
Subsequent to December 31, 2014 the Company entered into the following financial derivative contracts:
Natural Gas
Period Hedged
Apr. 1, 2015 to Oct. 31, 2015
Nov. 1, 2015 to Mar. 31, 2016
Apr. 1, 2016 to Oct. 31, 2016
Nov. 1, 2016 to Mar. 31, 2017
Apr. 1, 2015 to Oct. 31, 2015
Nov. 1, 2015 to Mar. 31, 2016
Apr. 1, 2016 to Oct. 31, 2016
Nov. 1, 2016 to Mar. 31, 2017
Apr. 1, 2015 to Oct. 31, 2015
Nov. 1, 2015 to Mar. 31, 2016
Apr. 1, 2016 to Oct. 31, 2016
Nov. 1, 2016 to Mar. 31, 2017
Jan. 1, 2016 to Mar. 31, 2016
Apr. 1, 2016 to Oct. 31, 2016
Type
Daily Volume
Price (CAD$/GJ)
2,000 GJ
2,000 GJ
2,000 GJ
2,000 GJ
4,000 GJ
4,000 GJ
2,000 GJ
2,000 GJ
6,000 GJ
6,000 GJ
6,000 GJ
6,000 GJ
5,000 GJ
5,000 GJ
$2.52/GJ
$3.03/GJ
$2.93/GJ
$3.38/GJ
$2.46/GJ
$2.96/GJ
$2.85/GJ
$3.31/GJ
$2.37/GJ
$2.87/GJ
$2.75/GJ
$3.21/GJ
$3.26/GJ
$2.91/GJ
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Page | 43
Crude Oil
Contract Period
Apr. 1, 2015 to Jun. 30, 2015
Jul. 1, 2015 to Sep. 31, 2015
Jan. 1, 2016 to Dec. 31, 2016
Type
Daily Volume
Price ($/Bbl)
Costless collar
Costless collar
Costless collar
2,000 Bbl
2,000 Bbl
700 Bbl
WTI $USD45.00-60.10/Bbl
WTI $USD45.00-66.00/Bbl
WTI $CAD70.00-75.75/Bbl
Share Capital
On January 26, 2015 the Company granted 365,000 stock options at an exercise price of $3.50. The options vest based on time (one third vest per year) and
expire five years from the date of issuance.
On February 18, 2015 the Company granted 140,000 stock options at an exercise price of $3.50. The options vest based on time (one third vest per year)
and expire five years from the date of issuance.
Property Acquisitions and Dispositions
On January 1, 2015 Petrus entered into an agreement with an industry partner to acquire petroleum and natural gas assets in the Ferrier/Strachan area of
Alberta for cash consideration of $4.4 million. The acquisition closed on January 20, 2015.
On January 9, 2015 Petrus entered into an agreement with a third party oil and gas company to acquire petroleum and natural gas assets, to acquire
additional assets in the Ferrier/Strachan area of Alberta. Concurrent with the acquisition of these assets, Petrus entered into an agreement with the same
industry partner to dispose of petroleum and natural gas assets in the Pembina area of Alberta. Petrus received total net consideration of $3.7 million
pertaining to these transactions.
Page | 44
CORPORATE INFORMATION
OFFICERS
Kevin L. Adair, P. Eng.
President and Chief Executive Officer
DIRECTORS
Don T. Gray
Chairman
Calgary, Alberta
SOLICITOR
Burnet, Duckworth & Palmer LLP
Calgary, Alberta
Neil Korchinski, P. Eng.
Vice President, Engineering and
Chief Operating Officer
Kevin L. Adair
Calgary, Alberta
AUDITOR
Ernst & Young LLP
Chartered Accountants
Calgary, Alberta
Cheree Stephenson, CA
Vice President, Finance and
Chief Financial Officer
Patrick Arnell
Calgary, Alberta
INDEPENDENT RESERVE EVALUATORS
Sproule and Associates
Calgary, Alberta
Peter Verburg
Corporate Secretary
Donald Cormack
Calgary, Alberta
Brian Minnehan
Irving, Texas
Peter Verburg
Calgary, Alberta
BANKERS
TD Securities
Calgary, Alberta
Macquarie Bank Limited
Houston, Texas
TRANSFER AGENT
Valiant Trust Company
Calgary, Alberta
HEAD OFFICE
2400, 240 – 4th Avenue S.W.
Calgary, Alberta T2P 5H4
Phone: 403-984-9014
Fax: 403-984-2717
WEBSITE
www.petrusresources.com
Page | 45