2013 Annual Report
HIGHLIGHTS
Petrus Resources Ltd. (“Petrus” or the “Company”) is pleased to report operating and financial results for the fourth quarter and the fiscal
year of 2013. Petrus began 2013, its second full year of operations, with production of 2,853 boe per day (42% oil and liquids) and exited
the year at a record 4,052 boe per day (46% oil and liquids), a 42% increase. The Company set new records for production, cash flow and
reserves per share in 2013. Other highlights include:
•
•
Production per share up 21% in 2013. Average annual production was 3,206 boe per day in 2013, up from 1,880 boe per day in
2012. Fourth quarter production averaged 3,658 boe per day, up from 2,735 boe per day in the same period of 2012, an increase
of 34% per share. New Montney and Cardium oil production generated a 44% increase in oil and natural gas liquids production
from the first quarter to the fourth quarter of 2013, driving strong growth in cash flow per share.
Cash flow per share up 77% in 2013. Petrus generated $31.1 million in cash flow from operations during the year, a two-and-a-
half-fold increase over the $12.5 million generated in 2012. Cash flow from operations was $9.2 million in the fourth quarter, up
from $6.3 million in the same period last year, an increase of 39% on a per share basis.
• Operating netback up 35% in 2013, rising from $21.29 per boe in 2012 to $28.74 per boe in 2013. The Company’s operating
netback in the fourth quarter was $31.04.
•
•
Reserves per share up 21% in 2013. Proved plus probable reserves increased from 12.3 mmboe in 2012 to 14.9 mmboe in 2013.
The Company replaced 3.2 times annual production at an all-in annual Finding, Development and Acquisition (“FD&A”) cost of
$21.57 per boe including future development capital (“FDC”) for the proved plus probable category.
Petrus ended 2013 with $228.1 million of reserve value on a proved plus probable basis, discounted at 10%, 1.6 times the prior
year total. On a per share basis, adjusted for debt, the proved plus probable reserve value was up 35%.
• Over the twelve month period ended December 31, 2013, Petrus invested $58.9 million in exploration and acquisition activity, up
from $52.2 million in 2012.
•
•
•
•
Petrus had 86.4 million common shares outstanding at December 31, 2013 and access to a $60.0 million credit facility. The
Company ended the year with net debt of $22.3 million, or 0.6x annualized fourth quarter cash flow. The debt-adjusted growth
per share metrics year-over-year are 26% for exit production, 55% for cash flow and 7% for proved plus probable reserves.
At year end Petrus had 133,339 net acres of undeveloped land, with a large inventory of oil and gas drilling locations in each of its
core operating areas.
Subsequent to December 31, 2013 Petrus announced the acquisition of oil and natural gas assets in the foothills of Alberta;
included in this acquisition were 875 boe per day of production and 36,307 net acres of undeveloped land. The acquisition was
made for total cash consideration of approximately $19.1 million (before post-closing adjustments) and closed February 28, 2014.
Concurrently the Company’s borrowing base increased to $90 million, including a $10 million development line.
The Petrus Board of Directors approved a base capital budget of $74 million for 2014, excluding acquisitions. The capital budget
provides for the drilling of 36 gross (24 net) wells, with approximately $45 million directed at foothills development and $29
million directed toward the Peace River area. Concurrent with closing of the acquisition of foothills assets the capital budget
increased to $100 million. The capital budget will be funded through cash flow and available credit facilities.
Page | 1
SELECTED FINANCIAL INFORMATION
Twelve months
ended
Dec. 31, 2013
Twelve months
ended
Dec. 31, 2012
Three months
ended
Dec. 31, 2013
Three months
ended
Sept. 30, 2013
Three months
ended
June 30, 2013
Three months
ended
Mar. 31, 2013
(000s) except per boe amounts
OPERATIONS
Average Production
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Total (boe)
Natural gas sales weighting
Exit production (boe/d)
Exit natural gas sales weighting
Realized Sales Prices
Natural gas ($/mcf)
Oil ($/bbl)
NGLs ($/bbl)
Total ($/boe)
Hedging gain (loss) ($/boe)
Operating Netback ($/boe)
Effective price
Royalty income (1)
Royalty expense (1)
Operating expense
Transportation expense
Operating netback (3) ($/boe)
G & A expense
Net interest expense (2)
Corporate netback (3) ($/boe)
FINANCIAL ($000s except per
share)
Oil and natural gas revenue (1)
Cash flow from operations (3)
Cash flow from operations per
share (3)
Net income (loss)
Net income (loss) per share
Capital expenditures
Net acquisitions (dispositions)
Common shares outstanding
Weighted average shares
As at quarter end ($000s)
Working capital (deficit)
Bank debt outstanding
Bank debt available
Shareholder’s equity
Total assets
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
7,490
585
47
1,880
686,200
66%
2,853
58%
2.61
79.07
61.16
36.53
0.82
37.35
0.54
(5.10)
(10.32)
(1.18)
21.29
(2.74)
(0.38)
18.18
25,511
12,513
0.20
431
0.01
52,159
59,630
86,276
61,377
10,848
1,778
72
3,658
336,539
49%
4,052
54%
3.78
77.83
65.17
50.33
(1.21)
49.12
0.46
(7.05)
(9.88)
(1.61)
31.04
(1.73)
(0.75)
28.56
17,094
9,220
0.11
2,086
0.02
9,736
—
86,377
86,377
10,405
1,373
54
3,162
290,877
55%
3,235
53%
2.54
93.93
67.20
50.31
(1.46)
48.85
0.56
(8.02)
(8.46)
(2.19)
30.74
(1.96)
(0.74)
28.04
14,741
8,157
0.09
2,171
0.03
14,166
—
86,377
86,369
9,681
1,300
76
2,990
272,090
54%
3,065
53%
3.60
88.13
45.37
51.14
(0.55)
50.59
0.57
(7.39)
(10.12)
(1.71)
31.94
(1.57)
(0.79)
29.58
14,093
8,048
0.09
4,010
0.05
15,416
(1,701)
86,362
86,349
10,315
1,212
76
3,007
270,638
57%
3,071
53%
3.29
77.02
71.55
44.15
(1.21)
42.94
0.55
(8.31)
(11.38)
(1.82)
21.98
(1.02)
(0.02)
20.94
12,128
5,666
0.06
47
0.01
19,533
—
86,276
86,276
(10,551)
11,304
28,696
146,432
184,139
(1) The Company re-classified gross overriding royalty expense from oil and natural gas revenue 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) Interest expense is presented net of interest income.
(3) Non-GAAP measures defined on page 7 of the MD&A for the period ended December 31, 2013.
(15,756)
20,968
39,032
151,304
199,508
(21,558)
17,966
42,034
153,857
201,208
(22,288)
23,380
36,620
156,002
211,952
(22,288)
23,380
36,620
156,002
211,952
2,793
—
40,000
145,782
181,976
Page | 2
OPERATIONS UPDATE
Foothills
Drilling success continues to add new oil weighted production in the foothills. Average production in the fourth quarter of 2013 from the
Cordel area increased approximately 538 boe per day from the third quarter of 2013. Three successful light oil wells were drilled in the
fourth quarter of 2013. The last well, in which Petrus has a 25% working interest, has delivered the highest initial production rate from an
oil well at Cordel to date, with gross production averaging 1,420 boe per day (90% oil) over a 30 day period in January and February. The
sales increase from the prior quarter is also due to the completion of permanent production facilities in the fourth quarter. These facilities
enabled the multi-well pad drilled earlier in 2013 to produce at near full rates for the fourth quarter.
The foothills asset acquisition added 875 boe per day (94% natural gas). The base purchase price of $22.9 million was reduced to net cash
consideration of $19.1 million, as $2.6 million was received due to exercise of a third party ROFR on a minor facility working interest in
addition to purchase price adjustments related to the interim period. The acquisition was funded using available credit facilities and closed
February 28, 2014. The acquisition provides Petrus with drilling upside at current commodity prices and increased working interest on near
term oil drilling opportunities at Brown Creek where Petrus plans to resume drilling in the summer of 2014. The Company has identified
additional drilling locations targeting various reservoirs in other strike areas, as well as reactivation opportunities.
Peace River
During the fourth quarter Petrus finished completions and tie-in of the six wells drilled in the summer of 2013. Two of these wells are water
disposal wells. New Montney oil wells produced a combined total of approximately 100 boe per day (90% light oil) once brought onto
production in December.
During the fourth quarter Petrus completed a battery with water disposal at Tangent North and the system is now operational. A second
disposal system at Tangent South was completed at the end of the first quarter of 2014. Both batteries are expected to significantly
decrease operating costs, increase runtime and allow for waterflood, which the Company believes will ultimately increase Montney oil
recoveries. Petrus has made an application to the provincial regulator for a pilot waterflood at Tangent North which, if approved, is
expected to commence in the second half of 2014.
Petrus resumed drilling in Tangent in January with a seven well program targeting oil in the Montney formation. Two of the wells had test
rates over a 32 hour period in excess of 200 bbl per day of oil with lower water cuts than expected. These wells will be brought on
production over the summer of 2014 dependent on weather and surface conditions.
ANNUAL GENERAL MEETING
The Company’s Annual General Meeting will be held at the Jamieson Place Conference Centre, 3rd floor, 308-4th Ave SW Calgary, Alberta, on
Tuesday June 3, 2014 at 9:00 a.m. (Calgary time). The Information Circular and Annual Report for 2013 will be available on the Company’s
website, www.petrusresources.com.
Page | 3
PRESIDENT’S MESSAGE
Petrus continued on a very exciting growth profile in 2013 deploying $58.9 million on various projects during the year almost exclusively
targeting light oil additions.
Drilling continued on the prolific Cordel/Stolberg structure in the Canadian foothills resulting in several outstanding oil wells. Petrus’
average working interest has increased in the latest wells to 25 – 30 percent from 9 – 21 percent in the earlier wells in the program. With
additional wells, the structural interpretation is better refined and additional opportunities are better understood. Together with other
owners, Petrus is looking at the viability of secondary recovery techniques to optimize recovery factors. During 2014 Petrus expects to
participate in several additional Cordel wells and expects to resume drilling on a similar structure targeting oil at Brown Creek.
Petrus has also advanced development of our Tangent Montney projects with the construction of two multi-well batteries and water
disposal systems. These investments are expected to dramatically reduce operating expenses associated with trucking water from single
well batteries. Longer term, these facility assets will be utilized to implement waterfloods in the Montney reservoirs improving ultimate
recoveries. Petrus has drilled both unstimulated horizontal wells and vertical wells to determine the optimal depletion strategy for
development of its extensive Montney acreage. Recent commissioning of these facilities together with additional drilling will provide us
with valuable design data for long term exploitation of these resources.
Late in the year oil and gas sales reached a record 4,000 boe per day and, following an 875 boe per day acquisition in the first quarter,
recent sales rates have been approximately 5,000 boe per day. Importantly, our oil and liquids sales have increased from less than 100 bbls
per day in mid-2012 to over 2,000 bbls per day currently. These are very important growth milestones achieved in a relatively short period
of time.
Commodity prices continued to show strength through 2013. Increasing build-out of rail capacity in Western Canada together with
incremental pipeline takeaway capacity from Cushing Oklahoma has reduced overall oil price differentials. Pipeline takeaway capacity from
Alberta remains a very important issue for all Canadians and progress on these critical national infrastructure projects must be made soon.
Gas prices were relatively weak during the summer but an early, cold, and long winter across most of North America has resulted in record
withdrawals from storage. These withdrawals together with a 10% slide in the Canadian dollar, resulted in realized gas prices improving
dramatically during the fourth quarter and through the first quarter of 2014. In spite of these recent higher gas prices, gas directed drilling
is still subdued and the industry will face challenges to refill storage prior to next winter to levels achieved in recent years. Petrus expects
gas prices to remain well supported through 2014.
The slow global economic recovery is beginning to generate life in equity markets for Canadian juniors. Overall, valuations are improving.
Acquisition and divestiture activity is recovering along with associated financings. Petrus has been active evaluating a variety of potential
transactions. With a very strong base of production and cash flow, a lightly levered balance sheet, and strong shareholder support, Petrus is
in an enviable position. 2014 should prove to be another exciting growth year on many fronts.
Kevin Adair
President, CEO and Director
Page | 4
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, 2013. The report is dated April 11, 2014. This MD&A should be read in conjunction
with the December 31, 2013 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, 2013
Twelve months
ended
Dec. 31, 2013
Twelve months
ended
Dec. 31, 2012
Three months
ended
Dec. 31, 2013
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 (1)
Oil and natural gas revenue (1)
Average realized prices
Natural gas ($/mcf)
Oil ($/bbl)
NGLs ($/bbl)
Total ($/boe)
Hedging gain (loss)
Total realized ($/boe)
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
7,490
585
47
1,880
688,205
2,853
58%
7,157
16,930
1,052
25,139
373
25,511
2.61
79.07
61.16
36.53
0.82
37.35
10,848
1,778
72
3,658
336,539
4,052
54%
3,775
12,734
430
16,939
155
17,094
3.78
77.83
65.17
50.33
(1.21)
49.12
10,405
1,373
54
3,162
290,877
3,235
53%
2,431
11,866
336
14,634
107
14,741
2.54
93.93
67.20
50.31
(1.46)
48.85
Three months
ended
June 30, 2013
Three months
ended
Mar. 31, 2013
9,681
1,300
76
2,990
272,090
3,065
53%
3,174
10,426
315
13,915
179
14,094
3.60
88.13
45.37
51.14
(0.55)
50.59
10,315
1,212
76
3,007
270,638
3,071
53%
3,058
8,399
491
11,948
180
12,128
3.29
77.02
71.55
44.15
(1.21)
42.94
Twelve months
ended
Dec. 31, 2013
Twelve months
ended
Dec. 31, 2012
Three months
ended
Dec. 31, 2013
Three months
ended
Sept. 30, 2013
Three months
ended
June 30, 2013
Three months
ended
Mar. 31, 2013
3.19
93.30
2.39
87.41
3.53
86.70
2.43
105.05
3.53
92.90
3.26
88.54
Average benchmark prices
Natural gas
AECO (C$/mcf)
Crude Oil
Edm Lt. (C$/ bbl)
Foreign Exchange
US$/C$
1.00
(1) The Company re-classified gross overriding royalty expense from oil and natural gas revenue to royalty expenses in the Statement of Net Income and Comprehensive Income. The
comparative information has been re-classified to conform to current presentation.
0.96
0.98
0.97
1.00
0.94
OIL AND NATURAL GAS REVENUE
Average production for the fourth quarter of 2013 was 3,658 boe per day (49% natural gas), compared to 2,735 boe per day (56% natural
gas) for the fourth quarter of the prior year. Total commodity revenue increased from $25.1 million in 2012 to $57.4 million in the year
ended December 31, 2013. The increase is due to the Company’s on-going drilling success and improved commodity prices.
Natural gas
During the three months ended December 31, 2013, the benchmark natural gas price in Canada (set at the AECO hub) increased by 10%
from the prior year (average price of $3.53 per mcf in the fourth quarter compared to $3.21 per mcf in the prior year). The AECO price
increased 33% from the average annual price of $2.39 per mcf in 2012 to $3.19 per mcf in 2013. Demand and pricing for natural gas peaked
in February 2013 and normalized later in April. The average price of $3.19 for 2013 approximates the five year average. Near the end of the
year, stockpiles were depleted faster than expected and natural gas prices climbed 19% from the third quarter to the fourth quarter of
2013 and 7% in the final month of the year. Cold fronts began their sweep across the United States in December and continued into 2014.
The Company’s average realized gas price during the fourth quarter of 2013 was $3.78 per mcf compared to $3.49 per mcf in the prior year,
which represents an 8% increase. Natural gas revenue for the fourth quarter of 2013 was $3.8 million and production of 998,016 mcf
Page | 5
accounted for approximately 50% of fourth quarter production volume and 22% of commodity revenue (compared to revenue of $2.9
million and production of 839,776 mcf for 56% of production volume and 26% of commodity revenue in the prior year).
The Company’s average realized gas price for the year ended December 31, 2013 was $3.30 per mcf compared to $2.61 per mcf in the prior
year, which represents a 26% increase. Natural gas revenue for the year ended December 31, 2013 was $12.4 million and production of
3,764,610 mcf accounted for approximately 54% of 2013 production volume and 22% of commodity revenue (compared to revenue of $7.2
million and production of 2,733,850 mcf for 66% of production volume and 29% of commodity revenue in the prior year).
Crude oil and condensate
Edmonton Light Sweet (“Edmonton”) crude oil prices increased 11% from the fourth quarter of 2012 to the fourth quarter of 2013 ($97.43
per bbl for the fourth quarter of 2013 compared to an average price of $87.96 per bbl for the prior period). In July WTI prices began to rally
and held a range above $100 per bbl through the summer. This increase in prices was driven in part by new pipeline infrastructure which
connected the U.S. Gulf Coast to Cushing. The infrastructure expansion enabled a significant draw from storage. In addition, prices were
driven higher near the end of the fourth quarter by conflict in Syria and an oil worker strike in Libya. Subsequent to the end of the fourth
quarter, oil prices receded as geopolitical risk has decreased and turnaround season began.
The average realized price of Petrus’ crude oil and condensate was $93.93 per bbl for the fourth quarter of 2013 compared to $80.55 per
bbl for the same period in the prior year. For the year ended December 31, 2013 the Company’s average realized price for crude oil and
condensate increased 6 percent from 2012, primarily as a result of an increase in the US$ WTI benchmark price and a weaker Canadian
dollar. Petrus realized an average negative oil differential of $7.33 in 2013, compared to a negative differential of $7.49 in 2012. The
differential widened significantly in the fourth quarter, resulting in a realized negative differential of $14.79 in the fourth quarter of 2013
compared to a negative differential of $2.87 in the comparable period of the prior year.
Oil and condensate revenue for the fourth quarter of 2013 was $12.7 million and production of 163,576 bbl accounted for approximately
49% of total production volume and 75% of commodity revenue (compared to revenue of $8.0 million and production of 104,832 bbl for
42% of total production volume and 70% of commodity revenue in the fourth quarter of the prior year).
Oil and condensate revenue for the year ended December 31, 2013 was $43.4 million and production of 517,205 bbl accounted for
approximately 44% of total production volume and 76% of commodity revenue (compared to revenue of $16.9 million and production of
213,525 bbl for 31% of total production volume and 67% of commodity revenue in the prior year).
Natural gas liquids (NGLs)
Petrus’ NGL production mix consists of ethane, propane, butane, pentane and sulphur. The pricing received for Petrus’ NGL production is
based on the product mix, the fractionation process required and the demand for fractionation facilities. In the fourth quarter Petrus’ NGL
production decreased as a result of the operated Peace River facility turnaround. Petrus’ overall realized NGL price averaged $67.20 per bbl
compared to $64.33 per bbl in the prior year. NGL revenue for the fourth quarter of 2013 was $430,000 and production of 6,624 bbl
accounted for approximately 2% of the Company’s production volume and 3% of commodity revenue in the fourth quarter (compared to
revenue of $437,000 and production of 6,822 bbl for 3% of total production and 4% of commodity revenue for the fourth quarter of the
prior year).
NGL revenue for the year ended December 31, 2013 was $1.6 million and production of 25,550 bbl accounted for approximately 2% of the
Company’s production volume and 3% of commodity revenue in the fourth quarter (compared to revenue of $1.1 million and production of
17,155 bbl for 3% of total production and 4% of commodity revenue for the fourth quarter of the prior year).
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
$155,000 compared to $134,000 in the same quarter of the prior year. As noted the Company re-classified gross overriding royalty expense
from other income to royalty expenses. The comparative information has been re-classified to conform to current presentation. For the
year ended December 31, 2013 Petrus earned $620,000, an increase of 66% from $373,000 earned in the year ended December 31, 2012.
The increase is attributed to higher commodity prices and additional wells drilled on the Company’s royalty interest land.
Page | 6
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
Cash flow from operations
Twelve months
ended
Dec 31, 2013
Twelve months
ended
Dec 31, 2012
Three months
ended
Dec 31, 2013
Three months
ended
Dec 31, 2012
26,238
4,853
31,091
5,071
7,442
12,513
7,079
2,141
9,220
(43)
6,659
6,616
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, 2013
As at
Dec 31, 2012
11,184
(10,092)
(23,380)
(22,288)
23,828
(21,002)
—
2,826
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 end of 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 a six times debt-adjusted
cash flow multiple on trailing quarter annualized cash flow. This multiple 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 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)
Six times debt-adjusted cash flow multiple.
Twelve months
ended
Dec 31, 2013
Twelve months
ended
Dec 31, 2012
86,343
37,164
2.32
(22,288)
9,592
95,935
61,377
27,472
1.94
2,793
(1,438)
59,923
Page | 7
CASH FLOW FROM OPERATIONS AND EARNINGS
Petrus generated cash flow from operations of $9.2 million during the quarter ended December 31, 2013 ($6.6 million during the fourth
quarter of 2012). Commodity prices, natural gas in particular, improved materially from the fourth quarter of 2012. Natural gas (AECO)
increased 10% from the fourth quarter of 2012 to the fourth quarter of 2013, and Edmonton crude increased 3% for the same period.
The Company’s cash flow from operations increased 1.5 times from $12.5 million generated for the year in 2012 to $31.1 million for 2013.
The increase is attributed to a 71% increase in total production year over year and a 34% increase in average commodity price for the year
on a boe basis.
Net income increased to $2.1 million in the fourth quarter of 2013 (compared to a net loss of $706,000 in the fourth quarter of the prior
year). The increase is due to an increase in production and commodity prices relative to the prior year. For the year ended December 31,
2013, Petrus reported net income of $8.1 million compared to $431,000 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.
Twelve months ended
Dec. 31, 2013
Twelve months ended
Dec. 31, 2012
$000s
$/boe
$000s
$/boe
Three months ended
Dec. 31, 2013
$000s
$/boe
Three months ended
Dec. 31, 2012
$000s
$/boe
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 & administrative
Interest expense (3)
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)
25,139
(811)
24,328
(3,502)
373
21,198
(7,103)
563
(1,885)
(260)
36.53
(1.18)
35.35
(5.10)
0.54
30.80
(10.32)
0.82
(2.74)
(0.38)
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)
11,372
(277)
11,095
(1,856)
134
9,373
(1,998)
(142)
(546)
(71)
45.19
(1.10)
44.09
(7.38)
0.53
37.25
(7.94)
(0.56)
(2.17)
(0.28)
Cash flow from operations
26.30
(1) The Company re-classified gross overriding royalty expense from oil and natural gas revenue 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) Interest expense is presented net of interest income.
31,091
12,513
28.56
26.56
18.18
9,220
6,616
(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, 2013
Twelve months ended
Dec. 31, 2012
Three months ended
Dec. 31, 2013
Three months ended
Dec. 31, 2012
31,091
0.36
8,141
0.09
86,377
86,343
12,513
0.20
431
0.01
86,276
61,377
9,220
0.11
2,086
0.02
86,377
86,377
6,616
0.08
(706)
(0.01)
86,276
86,276
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 55% year-over-year from 2012. The same metric for the fourth
quarter-over-fourth quarter was an increase of 39%. Petrus increased exit production on a per debt-adjusted thousand share basis 26%
from the prior year as shown in the table below:
Twelve months ended
Twelve months ended
%
Change
Three months ended
Three months ended
%
Change
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2013
Dec. 31, 2012
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.
$0.32
$0.11
$0.21
$0.08
15.4
12.3
55%
26%
—
—
39%
—
Page | 8
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, 2012
Twelve months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2012
Royalty Expenses ($000s)
Oil and NGLs ($000s)
% of production revenue
Natural gas (000s)
% of production revenue
Gas cost (allowance) (000s)
Gross overriding(1)
Total (000s)
1,927
11%
568
8%
(640)
39
1,894
(1) The Company re-classified gross overriding royalty expense from oil and natural gas revenue to royalty expenses in the Statement of Net Income and Comprehensive Income. The
comparative information has been re-classified to conform to current presentation.
9,837
22%
1,822
15%
(2,951)
256
8,964
3,973
11%
1,026
8%
(1,534)
37
3,502
2,562
20%
409
11%
(735)
136
2,372
The increase in total royalties from the fourth quarter of 2012 ($1.9 million) to the fourth quarter of 2013 ($2.4 million) is the result of new
production and an increased oil royalty rate paid for certain foothills production. The prolific Cordel wells drilled to date exceed the volume
maximum of 50,000 bbls of oil in a short time period. As a result, some of the wells no longer qualify under the Alberta crown royalty
incentive program and are subject to the maximum royalty rate of 40%. Total oil royalties paid in the quarter were $2.6 million,
approximately 20% of production revenue ($1.9 million and 11% of production volume in the fourth quarter of 2012).
For the year ended December 31, 2013 Petrus recorded total royalties of $9.0 million compared to $3.5 million in the same period of 2012.
The increase is directly related to the 71% increase in total production from the prior year. Furthermore certain new foothills production is
subject to a gross overriding royalty and as a result the gross overriding royalty expense incurred in 2013 ($256,000) increased significantly
from the prior year ($37,000).
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, 2013:
Natural Gas
Period Hedged
Jan. 1, 2014 to Mar. 31, 2014
Jan. 1, 2014 to Mar. 31, 2014
Jan. 1, 2014 to Mar. 31, 2014
Jan. 1, 2014 to Mar. 31, 2014
Apr. 1, 2014 to Oct. 31, 2014
Apr. 1, 2014 to Oct. 31, 2014
Apr. 1, 2014 to Oct. 31, 2014
Apr. 1, 2014 to Oct. 31, 2014
Nov. 1, 2014 to Mar. 31, 2015
Nov. 1, 2014 to Mar. 31, 2015
Crude Oil
Period Hedged
Jan. 1, 2014 to Jun. 30, 2014
Jan. 1, 2014 to Dec. 31, 2014
Jan. 1, 2014 to Dec. 31, 2014
Jan. 1, 2014 to Dec. 31, 2014
Jan. 1, 2014 to Dec. 31, 2014
Jan. 1, 2014 to Jun. 30, 2014
Jul. 1, 2014 to Dec. 31, 2014
Jul. 1, 2014 to Dec. 31, 2014
Type
Costless collar
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Daily Volume
Price (CAD)
4,000 GJ
1,000 GJ
1,500 GJ
1,000 GJ
1,500 GJ
2,500 GJ
1,000 GJ
1,500 GJ
2,000 GJ
2,000 GJ
$3.25 - $3.53/GJ
$3.55/GJ
$3.64/GJ
$3.70/GJ
$3.44/GJ
$3.61/GJ
$3.64/GJ
$3.65/GJ
$3.75/GJ
$3.81/GJ
Type
Daily Volume
Price (USD)
300 Bbl
200 Bbl
300 Bbl
100 Bbl
200 Bbl
100 Bbl
300 Bbl
200 Bbl
WTI $95.90/Bbl
WTI $85.00/Bbl
WTI $89.00/Bbl
WTI $92.00/Bbl
WTI $93.80/Bbl
WTI $96.05/Bbl
WTI $92.10/Bbl
WTI $94.05/Bbl
Fixed price
Put Option
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Page | 9
Electric Power
Period Hedged
Jan. 1, 2014 to Dec. 31, 2014
Jan. 1, 2015 to Dec. 31, 2015
Type
Annual Volume
Price (CAD)
Fixed price
Fixed price
12,264 MW
12,264 MW
$57.75/MWH
$50.00/MWH
Subsequent to December 31, 2013 the Company entered into the following financial derivative contracts:
Natural Gas
Period Hedged
Mar. 1, 2014 to Mar. 31, 2014
Mar. 1, 2014 to Mar. 31, 2014
Apr. 1, 2014 to Oct. 31, 2014
Apr. 1, 2014 to Oct. 31, 2014
Apr. 1, 2014 to Oct. 31, 2014
Nov. 1, 2014 to Mar. 31, 2015
Nov. 1, 2014 to Mar. 31, 2015
Nov. 1, 2014 to Mar. 31, 2015
Nov. 1, 2014 to Mar. 31, 2015
Nov. 1, 2014 to Mar. 31, 2015
Crude Oil
Period Hedged
Mar. 1, 2014 to Dec. 31, 2014
Aug. 1, 2014 to Dec. 31, 2014
Jan. 1, 2015 to Dec. 31, 2015
Type
Daily Volume
Price
(CAD)
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
1,000 GJ
500 GJ
1,000 GJ
500 GJ
1,000 GJ
1,000 GJ
1,000 GJ
1,000 GJ
500 GJ
1,000 GJ
$4.30/GJ
$4.53/GJ
$3.99/GJ
$4.07/GJ
$4.32/GJ
$3.84/GJ
$4.04/GJ
$4.10/GJ
$4.18/GJ
$4.43/GJ
Type
Daily Volume
Price
Fixed price
Fixed price
Fixed price
300 Bbl
300 Bbl
200 Bbl
WTI $CAD105.20/Bbl
WTI $CAD103.05/Bbl
WTI $CAD100.00/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, 2013
Twelve months
ended
Dec. 31, 2012
(1,311)
(1,495)
(2,806)
563
(770)
(207)
Three months ended
Three months ended
Dec. 31, 2013
Dec. 31, 2012
(409)
11
(398)
(142)
(2,237)
(2,469)
Strong commodity prices resulted in a fourth quarter realized hedging loss of $409,000, compared to a $142,000 loss realized in the same
quarter of the prior year. The fourth quarter realized loss decreased the Company’s realized price by $1.22 per boe, compared to a
decrease in the prior year comparable period of $0.56 per boe. For the year ended December 31, 2013 Petrus recorded a $1.3 million loss
on financial derivatives compared to a $563,000 gain recorded in the prior year. The change from 2012 to 2013 is due to the strengthening
commodity price environment for oil and natural gas.
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, 2013
Twelve months
ended
Dec. 31, 2012
Three months ended
Three months ended
Dec. 31, 2013
Dec. 31, 2012
12,009
10.26
7,103
10.32
3,716
11.03
1,998
7.94
Operating expenses totalled $3.7 million for the fourth quarter of 2013, an 85% increase from $2.0 million recorded in the same quarter of
the prior year. The increase in aggregate net operating expenses is due to new production compared to the prior period.
For the year ended December 31, 2013, operating costs on a per boe basis were consistent with the prior year. New water disposal facilities
in the Peace River area are expected to contribute to operating cost reductions in future periods.
Page | 10
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, 2013
Twelve months
ended
Dec. 31, 2012
Three months ended
Three months ended
Dec. 31, 2013
Dec. 31, 2012
2,136
1.83
811
1.18
543
1.61
277
1.10
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 totalled $543,000 or $1.61
per boe in the fourth quarter of 2013 ($277,000 or $1.10 per boe for the comparative period in the prior year). The increase in
transportation costs is due to the higher reliance on trucking to deliver liquids production to sales points. Production volume increased and
trucking costs on a per unit basis increased. Wait times at third party facilities rose as operators faced capacity constraints.
Transportation costs increased year over year from $1.18 per boe for the year ended December 31, 2012 to $1.83 per boe for the same
period in 2013. The significant increase is due to increased trucking costs as well as pipeline facility constraints that led to higher volumes
being trucked to sales delivery points.
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, 2013
Twelve months
ended
Dec. 31, 2012
Three months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2012
3,368
(1,511)
1,856
1,858
(929)
2,786
2,829
(944)
1,885
2,071
(972)
2,984
491
91
582
349
(174)
756
966
(420)
546
645
(323)
869
Fourth quarter 2013 net general and administration expenses (excluding non-cash share based compensation), totalled $582,000 or $1.73
per boe (compared to $546,000 or $2.17 per boe for the fourth quarter of 2012). Petrus capitalizes and reclassifies those general and
administrative expenses which are directly attributable to the acquisition, exploration and development activities of the Company. In the
fourth quarter Petrus reduced the capitalized component of G&A costs which resulted in an adjustment recorded in the fourth quarter of
2013. The 20% reduction in fourth quarter G&A costs on a per boe basis is attributed to G&A efficiencies as the production base grows.
For the year ended December 31, 2013, the Company’s total G&A costs (including non-cash share based compensation) were consistent
with prior year. As a result of the significant production increase from 2012 the total G&A costs on a per boe basis decreased 45% from
$4.35 per boe in 2012 to $2.38 per boe in 2013.
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, 2013
Twelve months
ended
Dec. 31, 2012
Three months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2012
16,402
761
17,163
14.02
0.65
14.67
7,630
459
8,089
11.09
0.67
11.75
6,120
539
6,659
18.19
1.60
19.79
5,423
174
5,597
21.55
0.69
22.24
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.
Page | 11
Petrus recorded depletion expense in the fourth quarter of 2013 of $6.1 million or $18.19 per boe, compared to the fourth quarter of 2012,
when $5.4 million or $21.55 per boe was recorded. For the quarter ended December 31, 2013, depreciation expense totalled $539,000,
compared to $174,000 in the comparable quarter of the prior year. For the year ended December 31, 2013 Petrus recorded $17.2 million
related to depletion and depreciation which represents a 112% increase from $8.1 million recorded in the prior year. The Company’s
depletion and depreciation have increased from prior year due to the increased production and reserves base.
Depletion and depreciation for the year ended December 31, 2013 increased 25% from the comparable period in 2012. The increase is due
to the significant increase in the depletable base which relates to additions to petroleum and natural gas properties as well as future
development cost estimates.
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, 2013
Twelve months
ended
Dec. 31, 2012
Three months
ended
Dec. 31, 2013
Three months
ended
Dec. 31, 2012
(000s)
Weighted average outstanding commons shares
Basic
Diluted
Outstanding instruments
86,377
86,276
Common shares
4,355
3,995
Stock options
6,423
6,423
Warrants
At April 11, 2014 the Company had 86,376,598 common shares outstanding. Subsequent to December 31, 2013 the Company issued
455,000 stock options. As at April 11, 2014 the Company had 4,810,000 and 6,422,603 stock options and performance warrants
outstanding, respectively.
86,276
3,995
6,423
86,377
4,355
6,423
86,343
86,343
59,629
59,629
86,276
86,276
86,377
86,377
Page | 12
LIQUIDITY AND CAPITAL RESOURCES
The Company had a credit facility of $60 million with a major Canadian lender at December 31, 2013. The credit facility consisted of a $55
million demand revolver and a $5 million development line. The amount of the credit facility is subject to a borrowing base test performed
on a semi-annual review by the lender, based primarily on reserves and using commodity prices estimated by the lender as well as other
factors. The Company provided security by way of a $130 million debenture over all of the present and future acquired property of the
Company. A decrease in the borrowing base could result in a reduction to the available credit facility.
At December 31, 2013, the Company did not have any letters of credit against the facility (December 31, 2012; $nil) and had drawn $23.4
million against the facility (December 31, 2012; nil). The Company has no drilling or other significant capital commitments.
Subsequent to December 31, 2013, Petrus entered into a purchase and sale agreement to acquire oil and natural gas assets from a working
interest partner in the central Alberta foothills (the “Acquisition”). The Acquisition was made for total cash consideration of approximately
$19.1 million (before post-closing adjustments) and closed February 28, 2014.
Concurrent with the closing of the acquisition, a semi-annual review of the credit facility took place on February 28, 2014 and the facility
was increased to $90 million, comprised of an $80 million revolving credit facility and a $10 million development line. Subsequent to
December 31, 2013, the Petrus Board of Directors approved a base capital budget of $74 million (before acquisitions) for 2014. The capital
budget provides for the drilling of 36 gross (24 net) wells, with approximately $45 million directed at foothills development and $29 million
directed toward the Peace River area. Concurrent with closing of the acquisition of foothills assets the capital budget increased to $100
million. The capital budget will be funded through cash flow and credit facilities.
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 2013 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 | 13
CAPITAL EXPENDITURES
Capital expenditures, excluding acquisitions and dispositions, totalled $9.7 million in the fourth quarter of 2013 compared to $21.5 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 21 wells (11.4 net). Petrus invested $57.2 million (net of dispositions) in 2013, funded by cash
flow from operations and the Company’s revolving credit facility. The following table shows capital expenditures for the reporting periods
indicated. All capital is presented before decommissioning obligations:
Twelve months
ended
Dec. 31, 2013
Twelve months
ended
Dec. 31, 2012
Three months ended
Three months ended
Dec. 31, 2013
Dec. 31, 2012
($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
44,259
9,129
698
2,177
91
2,497
58,851
(1,701)
57,150
21 (11.4)
39,650
3,147
787
5,680
980
1,915
52,159
59,630
111,789
23 (15.0)
3,844
3,616
97
1,421
60
698
9,736
0
9,736
1 (0.3)
16,578
2,569
19
1,174
374
956
21,457
-
21,457
10 (9.1)
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, 2013(1)
December 31, 2012(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, 2013 reserves were evaluated by GLJ Petroleum Engineers and Sproule and Associates.
(2)The Company’s December 31, 2012 reserves were evaluated by GLJ Petroleum Engineers.
(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)
5,190
7,690
12,301
($000s)
71,336
90,923
149,484
(MBoe)
5,696
8,638
14,864
($000s)
88,804
127,454
228,083
FD&A(3)
$49.64
$42.90
$24.79
FD&A(3)
$34.72
$31.38
$21.57
RLI(4)
4.9
7.4
12.7
—
—
—
—
—
—
—
—
—
RLI(4)
5.1
7.5
12.1
—
—
—
In 2013 Petrus’ total company interest reserves increased 21% to 14.9 mmboe on a proved plus probable (“P+P”) basis and 12% on a total proved
basis to 8.6 mmboe. The 2.9 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 $21.57 per boe including future development capital (“FDC”).
Page | 14
SUMMARY OF QUARTERLY RESULTS
($000s) except per share amounts
Dec. 31,
2013
Sep. 30,
2013
Jun. 30,
2013
Three months ended
Dec. 31,
Mar. 31,
2012
2013
Sep 30,
2012
Jun. 30,
2012
Mar. 31,
2012
107
14,634
(636)
13,998
(2,276)
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
Interest expense (3)
Cash flow from operations
Per share – basic/diluted
Net income (loss)
Per share – basic/diluted
Common shares (000s)
Weighted average shares (000s)
Total assets
Net working capital (net debt)
2,181
(91)
2,090
(524)
72
1,638
(607)
193
(348)
14
890
0.03
1,459
0.05
32,033
32,033
62,836
(2,241)
(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) Interest expense is presented net of interest income.
16,939
(543)
16,396
(2,372)
155
14,179
(3,716)
(409)
(582)
(252)
9,220
0.11
2,086
0.02
86,377
86,377
211,952
(22,288)
11,948
(491)
11,457
(2,282)
180
9,355
(3,080)
(328)
(276)
(5)
5,666
0.07
47
0.01
86,276
86,276
184,139
(10,551)
13,915
(466)
13,449
(2.034)
179
11,594
(2,753)
(150)
(427)
(216)
8,048
0.09
4,010
0.05
86,362
86,349
199,507
(15,756)
1,950
(140)
1,810
503
61
2,374
(1,259)
242
(658)
(194)
505
0.02
(2,060)
(0.06)
83,493
32,174
153,422
21,440
11,372
(277)
11,095
(1,856)
134
9,374
(1,998)
(142)
(546)
(71)
6,616
0.08
(706)
(0.01)
86,276
86,276
181,976
2,826
9,637
(303)
9,334
(1,630)
111
7,815
(3,236)
270
(379)
32
4,502
0.05
1,738
0.02
86,276
86,124
167,438
17,285
11,829
(2,460)
(425)
(571)
(216)
8,157
0.09
2,171
0.03
86,377
86,369
201,208
(21,558)
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 (“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.
Page | 15
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, 2013.
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:
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
Page | 16
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 | 17
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 | 18
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 | 19
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, 2013 and 2012, 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, 2013 and 2012 and its financial performance and its cash flows for the years then ended in accordance with
International Financial Reporting Standards.
Chartered accountants
Calgary, Canada
April 11, 2014
Page | 20
BALANCE SHEETS
(AUDITED)
(Expressed in Canadian dollars)
As at
ASSETS
Current
Cash
Deposits and prepaid expenses
Accounts receivable (note 14)
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
Decommissioning obligation (note 9)
Deferred income tax liability (note 15)
Shareholders’ Equity
Share capital (note 11)
Contributed surplus
Retained earnings (deficit)
See accompanying notes to the financial statements
Commitments (note 20)
Approved by the Board of Directors,
(signed) “Don T. Gray”
Don T. Gray
Chairman
December 31, 2013
December 31, 2012
—
303,101
10,880,771
26,418
11,210,290
50,528,518
150,212,756
200,741,274
211,951,564
23,379,651
10,092,329
2,286,940
35,758,920
15,546,813
4,644,065
55,949,798
144,339,234
3,961,972
7,700,560
156,001,766
11,589,033
589,566
11,649,891
371,574
24,200,064
45,790,854
111,985,145
157,775,999
181,976,063
—
21,002,078
1,137,562
22,139,640
12,395,714
1,658,369
36,193,723
144,119,128
2,103,466
(440,254)
145,782,340
211,951,564
181,976,063
(signed) “Patrick Arnell”
Patrick Arnell
Director
Page | 21
STATEMENTS OF NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(AUDITED)
(Expressed in 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 17)
Transportation expenses
General and administrative (note 18)
Share-based compensation (notes 11 and 18)
Finance (note 12)
Exploration and evaluation expense (note 6)
Depletion and depreciation (note 7)
NET INCOME (LOSS) BEFORE INCOME TAXES
Current tax expense
Deferred income tax expense (note 15)
TOTAL NET INCOME AND COMPREHENSIVE
INCOME
Net income per common share
Basic and diluted
See accompanying notes to the financial statements
Year ended
December 31, 2013
Year ended
December 31, 2012
58,055,347
(8,963,869)
49,091,478
50,074
(2,805,500)
46,336,052
12,009,277
2,135,930
1,856,245
929,253
1,111,536
—
17,162,735
35,204,977
11,131,075
—
2,990,261
2,990,261
25,510,732
(3,501,921)
22,008,811
90,116
(206,662)
21,892,265
7,102,809
811,190
1,885,007
1,099,242
517,667
420,000
8,088,689
19,924,604
1,967,661
2,660
1,534,062
1,536,722
8,140,814
430,939
0.09
0.01
Page | 22
STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(AUDITED)
(Expressed in Canadian dollars)
Balance, December 31, 2011
Net income
Issuance of common shares (note 11)
Premium liability of flow-through shares
Share-based compensation expensed
Share-based compensation capitalized
Share issue costs
Tax benefit of share issue costs
Deferred tax benefits
Balance, December 31, 2012
Net income
Issuance of common shares (note 11)
Premium liability of flow-through shares
Share-based compensation expensed
Share-based compensation capitalized
Tax benefit of share issue costs
Balance, December 31, 2013
See accompanying notes to the financial statements
Share
Capital
Contributed
Surplus
Retained
Earnings
(Deficit)
51,018,159
—
95,160,000
(215,422)
—
—
(2,914,580)
876,400
194,571
144,119,128
—
215,540
(13,610)
—
—
18,176
144,339,234
32,391
—
—
—
1,099,242
971,833
—
—
—
2,103,466
—
—
—
929,253
929,253
—
3,961,972
(871,193)
430,939
—
—
—
—
—
—
—
(440,254)
8,140,814
—
—
—
—
—
7,700,560
Total
50,179,357
430,939
95,160,000
(215,422)
1,099,242
971,834
(2,914,580)
876,400
194,570
145,782,340
8,140,814
215,540
(13,610)
929,253
929,253
18,176
156,001,766
Page | 23
STATEMENTS OF CASH FLOWS
(AUDITED)
(Expressed in Canadian dollars)
Funds generated by (used in):
OPERATING ACTIVITIES
Net income (loss)
Adjust items not affecting cash:
Share-based compensation
Unrealized hedging losses (note 10)
Finance expenses (note 12)
Exploration and evaluation expense (note 6)
Depletion and depreciation (note 7)
Deferred income tax expense (note 15)
Change in operating non-cash working capital (note 16)
Funds generated by operations
FINANCING ACTIVITIES
Issuance of common shares (note 11)
Share issue costs (note 11)
Increase in bank indebtedness
Change in financing non-cash working capital (note 16)
Funds generated by financing activities
INVESTING ACTIVITIES
Property and equipment (acquisitions) dispositions (note 7)
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 16)
Funds 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
Year ended
December 31, 2013
Year ended
December 31, 2012
8,140,814
430,939
929,253
1,494,534
372,978
—
17,162,735
2,990,261
31,090,575
(4,852,774)
26,237,801
215,540
—
23,379,651
—
23,595,191
1,701,319
(5,197,494)
(52,833,869)
(90,592)
(5,001,389)
(61,422,025)
(11,589,033)
11,589,033
—
661,151
—
1,099,242
769,888
170,035
420,000
8,088,689
1,534,062
12,512,856
(7,441,454)
5,071,402
95,160,000
(2,914,580)
—
(979,856)
91,265,564
(59,586,195)
(16,979,120)
(31,539,972)
(765,295)
16,673,973
(92,534,721)
3,802,245
7,786,788
11,589,033
280,189
2,660
7
7
Page | 24
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. These financial statements report the twelve months ended December 31, 2013 and were approved by the Company’s Audit
Committee April 11, 2014.
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. It conducts many of its activities jointly with others. These financial statements reflect only
the Company’s share of these jointly controlled assets and its proportionate share of the relevant revenue and related costs. The Company’s head
office is located at 2400, 240 – 4th Avenue SW, Calgary, Alberta Canada.
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”), interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”) and
adopted by the Canadian Institute of Chartered Accountants (“CICA”).
(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 (“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.
Page | 25
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. 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.
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 as well as processing income.
(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, other directly attributable costs 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 bringing
Page | 26
in or enhancing production from such 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 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 reducing balance
method so as to write off the cost of these assets, less estimated residual values, over their estimated useful lives. The expected useful lives of
property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.
Impairment
The carrying amounts of property, plant and equipment are grouped into CGU’s and 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 assessment for impairment entails comparing the carrying value of the CGU with its recoverable amount: that is, the higher of fair value,
less costs to sell, and value in use. Each CGU is identified in accordance with IAS 36, Impairment of Assets. Petrus’ property, plant and
equipment are grouped into CGU’s 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 recoverable amount is the higher of fair value, less costs to sell, and the value-in-use. Fair value, less costs to sell, 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).
Amortization
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.
Page | 27
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
by grouping the exploration and evaluation assets with property, plant and equipment CGU’s to which they belong for impairment testing. The
equivalent combined carrying value of the CGU’s is compared against the recoverable amount of the CGU’s and any resulting impairment loss is
written off to net income (loss). The recoverable amount is the greater of fair value, less costs to sell, 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 and depreciation 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 and accretion of the discount on decommissioning obligations.
(g) Financial instruments
Non-derivative financial instruments
Non-derivative financial instruments comprise cash and cash equivalents, 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 and cash equivalents are classified as financial assets at fair value, showing separately (i) those designated as such upon initial
recognition and (ii) those classified as held for trading in accordance with IAS 39 Financial Instruments: Recognition and Measurement.
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.
(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.
(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. The
difference between the initial liability and the deferred tax liability created is recorded as a deferred tax expense.
Page | 28
(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. The
measurement of deferred tax liabilities and assets reflects the tax consequences that would follow from the manner in which Petrus expects, at the end
of the reporting period, to recover or settle the carrying amount of its assets and liabilities.
(k) Joint interests
Petrus undertakes certain business activities through joint arrangements. A joint arrangement is established under contractual arrangement whereby
two or more parties undertake an economic activity that is subject to joint control. Joint control is the contractually agreed sharing of control over an
economic activity, and exists only when the strategic financial and operating decisions relating to the activity require the unanimous consent of the
parties sharing control.
(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.
(o) 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:
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.
Page | 29
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 – In November 2009, the International Accounting Standards Board (“IASB”) issued IFRS 9 Financial Instruments to replace
IAS 39 Financial Instruments: Recognition and Measurement. The standard was expanded in October 2010 and will be published in three phases, of
which two phases have been published. The first phase replaces the current approach to classification and measurement of financial assets and
liabilities and uses a model of only two classification categories: fair value or amortized cost. The second phase, amended in 2013 by the IASB,
incorporates a new general hedge accounting model which will allow reporting entities more opportunities to apply hedge accounting. The third phase
clarifies the use of a single impairment method when evaluating financial instruments. A mandatory effective date for IFRS 9 in its entirety will be
announced when the project is closer to completion. Early adoption of phases one and two is permitted only if adopted in their entirety at the
beginning of a fiscal period. The Company is currently evaluating the impact of adopting IFRS 9 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.
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 Statement of Financial Position 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.
The Company’s financial instruments recorded at fair value 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.
Page | 30
•
•
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,
2013. The carrying value of cash and cash equivalents, accounts receivables, deposits and accounts payables and accrued liabilities included in
the Statement of Financial Position approximate fair value due to the short-term nature of those instruments. These assets and liabilities are
not included in the following table.
Financial Assets
Fair value of financial instruments
Financial Liabilities
Fair value of financial instruments
5. ACQUISITIONS
Carrying Amount
As at December 31, 2013
Level 1
Fair Value
Level 2
Level 3
26,418
26,418
2,286,940
2,286,940
—
—
26,418
2,286,940
—
—
On June 29, 2012 Petrus closed an acquisition of petroleum and natural gas assets in the Peace River area of Alberta, with an effective date of April 1, 2012,
for total cash consideration of $60.3 million, net of adjustments and acquisition related 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 and was financed by
existing cash balances and proceeds from an equity financing. A total of $72,243 in acquisition related costs, which relate to professional fees, have been
charged to finance expenses in the Statement of Net Income and Comprehensive Income in the year ended December 31, 2012.
The financial statements incorporate the operations of the properties beginning June 30, 2012. During the period June 30, 2012 to December 31, 2012, the
Company recorded oil and natural gas revenue of $11.3 million and net income of $6.3 million related to the acquisition. The impact of this acquisition on
revenue and net income, as if acquired at the beginning of the year, would have been incremental revenue of $11.3 million and incremental net income of
approximately $6.3 million.
The following table summarizes the net assets acquired pursuant to the acquisition:
Fair value of net assets acquired
Prepaid operating expenses
Exploration and evaluation assets
Petroleum and natural gas properties and equipment
Decommissioning obligations
Total net assets acquired
6. EXPLORATION AND EVALUATION ASSETS
The components of the Company’s Exploration and Evaluation assets are as follows:
Balance, December 31, 2011
Additions
Acquisitions (dispositions)
Capitalized G&A and share-based compensation
Decommissioning costs incurred
Transfers to property, plant and equipment
Balance, December 31, 2012
Additions
Acquisitions (dispositions)
Capitalized G&A and share-based compensation
Decommissioning costs incurred
Transfers to property, plant and equipment
Balance, December 31, 2013
Page | 31
568,271
5,612,500
61,754,458
(7,652,684)
60,282,545
7,232,470
42,693,416
5,612,500
957,661
919,996
(11,625,189)
45,790,854
4,441,890
—
1,220,230
—
(924,456)
50,528,518
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, 2013 the Company incurred exploration and evaluation expense in the Statement of Net
Income and Comprehensive Income of $nil which relates to expiring undeveloped land in minor properties (2012 - $420,000).
During the year ended December 31, 2013 the Company capitalized $1.2 million (2012 - $957,661) of general & administrative expenses (“G&A”)
directly attributable to exploration activities. Included in this amount is non-cash share-based compensation of $464,626 (2012 - $485,917).
7. PROPERTY, PLANT AND EQUIPMENT
$
Balance, December 31, 2011
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, 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
Cost
40,715,777
5,647,482
61,754,458
957,661
11,625,189
—
—
120,700,567
52,168,855
(1,901,319)
1,220,232
924,456
—
2,778,122
175,890,913
Accumulated
DD&A
Net book value
(626,733)
—
—
—
(8,088,689)
—
(8,715,422)
—
200,000
—
—
(17,162,735)
—
(25,678,157)
40,089,044
5,647,482
61,754,458
957,661
11,625,189
(8,088,689)
—
111,985,145
52,168,855
(1,701,319)
1,220,232
924,456
(17,162,735)
2,778,122
150,212,756
Estimated future development costs of $58.8 million (2012 - $42.8 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, 2013 the Company capitalized $1.2
million (2012 - $957,661) of general & administrative expenses (“G&A”) directly attributable to development activities. Included in this amount is non-
cash share-based compensation of $464,627 (2012 - $485,916).
8. REVOLVING CREDIT FACILITY
The Company has a credit facility of $60 million with a major Canadian lender (see note 21). The credit facility consists of a $55 million demand revolver
and a $5 million development line. The facility is available on a revolving basis for a period until June 29, 2014 and then for a further year under the
term out provisions. The initial term out date may be extended for further 364 day periods at the request of Petrus, subject to approval by the lender.
The credit facility provides that advances may be made by way of direct Canadian advances (at an interest rate equal to the Bank of Canada prime rate
plus 0.75% per annum), U.S. dollar advances (at an interest rate equal to the U.S. Base Rate plus 0.75% per annum), or bankers’ acceptances (at a
stamping fee calculated on the face amount of the banker’s acceptance at a rate equal to 175 basis points per annum).
The amount of the credit facility is subject to a borrowing base test performed on a semi-annual review by the lender, based primarily on reserves and
using commodity prices estimated by the lender as well as other factors. The Company has provided security by way of a $130 million debenture over
all of the present and after acquired property of the Company. A decrease in the borrowing base could result in a reduction to the available credit
facility. A semi-annual review of the credit facility took place on February 28, 2014 and as noted in Note 21 the facility was increased to $90 million,
comprised of an $80 million revolving credit facility and a $10 million development line. The next scheduled review will take place June 30, 2014. At
December 31, 2013, the Company has no outstanding letters of credit against the facility (December 31, 2012; $180,000) and had drawn $23.4 million
against the facility (December 31, 2012; nil).
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 three percent and an inflation rate of two percent (December 31, 2012; two percent and two percent,
respectively). The Company has estimated the net present value of the decommissioning obligations to be $15.6 million as at December 31, 2013
($12.4 million at December 31, 2012). The undiscounted, uninflated total future liability at December 31, 2013 is $19.7 million ($12.4 million at
December 31, 2012). The payments are expected to be incurred over the operating lives of the assets. The following table reconciles the
decommissioning liability:
Page | 32
Balance, December 31, 2011
Acquisitions
Liabilities incurred
Accretion expense
Balance, December 31, 2012
Dispositions
Liabilities incurred
Change in estimates
Accretion expense
Balance, December 31, 2013
3,652,999
7,652,684
919,996
170,035
12,395,714
(80,000)
749,308
2,108,814
372,977
15,546,813
10. FINANCIAL RISK MANAGEMENT
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, 2013 (see note 21):
Natural Gas
Period Hedged
Jan. 1, 2014 to Mar. 31, 2014
Jan. 1, 2014 to Mar. 31, 2014
Jan. 1, 2014 to Mar. 31, 2014
Jan. 1, 2014 to Mar. 31, 2014
Apr. 1, 2014 to Oct. 31, 2014
Apr. 1, 2014 to Oct. 31, 2014
Apr. 1, 2014 to Oct. 31, 2014
Apr. 1, 2014 to Oct. 31, 2014
Nov. 1, 2014 to Mar. 31, 2015
Nov. 1, 2014 to Mar. 31, 2015
Crude Oil
Period Hedged
Jan. 1, 2014 to Jun. 30, 2014
Jan. 1, 2014 to Dec. 31, 2014
Jan. 1, 2014 to Dec. 31, 2014
Jan. 1, 2014 to Dec. 31, 2014
Jan. 1, 2014 to Dec. 31, 2014
Jan. 1, 2014 to Jun. 30, 2014
Jul. 1, 2014 to Dec. 31, 2014
Jul. 1, 2014 to Dec. 31, 2014
Electric Power
Period Hedged
Jan. 1, 2014 to Dec. 31, 2014
Jan. 1, 2015 to Dec. 31, 2015
Total risk management asset
Total risk management liability
Type
Daily Volume
Price (CAD)
Costless collar
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
4,000 GJ
1,000 GJ
1,500 GJ
1,000 GJ
1,500 GJ
2,500 GJ
1,000 GJ
1,500 GJ
2,000 GJ
2,000 GJ
$3.25 - $3.53/GJ
$3.55/GJ
$3.64/GJ
$3.70/GJ
$3.44/GJ
$3.61/GJ
$3.64/GJ
$3.65/GJ
$3.75/GJ
$3.81/GJ
Type
Daily Volume
Price (USD)
Fixed price
Put Option
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
300 Bbl
200 Bbl
300 Bbl
100 Bbl
200 Bbl
100 Bbl
300 Bbl
200 Bbl
WTI $95.90/Bbl
WTI $85.00/Bbl
WTI $89.00/Bbl
WTI $92.00/Bbl
WTI $93.80/Bbl
WTI $96.05/Bbl
WTI $92.10/Bbl
WTI $94.05/Bbl
Type
Annual Volume
Price (CAD)
Fixed price
Fixed price
12,264 MW
12,264 MW
$57.75/MWH
$50.00/MWH
26,418
2,286,940
For the twelve months ended December 31, 2013, Petrus recorded a realized loss of $1.3 million and an unrealized loss of $1.5 million (twelve months
ended December 31, 2012 a realized gain of $563,226 and an unrealized loss of $769,888).
Page | 33
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
Balance, December 31, 2011
Common shares issued under private placement (a)
Common shares issued under private placement (b)
Common shares issued under private placement (d)
Flow-through shares issued, net of premium (c)
Flow-through shares issued, net of premium (d)
Share issue costs
Tax benefit of share issue costs
Deferred tax benefits
Balance, December 31, 2012
Common shares issued under private placement (e)
Flow-through shares issued, net of premium (e)
Tax benefit of share issue costs
Common shares issued under private placement (f)
Balance, December 31, 2013
Number of Shares
Amount
32,033,017
80,000
50,774,571
2,772,557
605,488
10,000
—
—
—
86,275,633
52,655
34,024
—
14,286
86,376,598
51,018,159
160,000
88,855,499
4,851,975
1,059,604
17,500
(2,914,580)
876,400
194,571
144,119,128
105,310
68,048
18,176
28,572
144,339,234
Share Issuances
(a)
In April 2012 the Company completed a subsequent closing to its November 2011 private equity placement and issued 80,000 common shares at a price
of $2.00 per common share for gross proceeds of $160,000.
The Company completed its third significant private equity placement on June 29, 2012. 50,774,571 common shares were issued at a price of $1.75 per
share for gross proceeds of $88,855,499.
(b)
(c) On June 29, 2012, the Company also issued 605,488 flow-through shares at a price of $2.10 per share for total gross proceeds of $1,271,525. Of the
issuance price, $0.35 per share or $211,921 was determined to be the premium on the flow-through shares. Petrus spent $1,059,604 on qualified
exploration and development expenditures to satisfy the obligation.
(d) On July 5, 2012 the Company issued 2,772,557 common shares at a price of $1.75 per share for gross proceeds of $4.9 million. In addition, the Company
issued 10,000 common shares on a flow-through basis at a price of $2.10 per share for gross proceeds of $21,000. Of the issuance price, $0.35 per share
or $3,501 was determined to be the premium on the flow-through shares. The issuances were subsequent additional closings related to the June 2012
private equity placement.
(e) 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 $186,968. Of the issuance price, $0.40 per share or $13,610 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. Under National Instrument 45-102, the common shares issued are subject to a restricted hold period which expired
August 27, 2013.
On August 19, 2013 the Company issued 14,286 common shares at a price of $2.00 per share for gross proceeds of $28,572. The issuance was made
pursuant to an Exempt Offering which provided employees and key consultants an opportunity to purchase common and flow-through shares of the
Company. Under National Instrument 45-102, the common shares issued are subject to a restricted hold period which expires December 19, 2013.
(f)
SHARE-BASED COMPENSATION
Performance Warrants
The Company may issue performance warrants to employees, consultants and directors of the Company. Performance warrants are granted and vest
based on three criteria, time (one third vest per year), market (one third vest as certain share price hurdles are achieved) and employment or service.
The warrants expire five years from the date of issuance. Upon exercise of the warrants the Company settles the obligation by issuing common shares
of the Company and cash settlements are not required. The shares to be offered consist of common shares of the Company`s authorized but unissued
common shares. The aggregate number of shares issuable upon the exercise of all warrants granted shall not exceed 20% of the issued and outstanding
shares as at April 30, 2012. At December 31, 2013, 6,422,603 (December 31, 2012; 6,422,603) performance warrants were issued.
Balance, December 31, 2011
Granted
Exercised
Forfeited or expired
Balance, December 31, 2012
Forfeited or expired
Granted
Balance, December 31, 2013
Exercisable, December 31, 2013
Number of warrants
Weighted Average
Exercise Price ($)
4,934,000
1,581,603
—
93,000
6,422,603
(417,000)
417,000
6,422,603
—
$2.00
$2.00
—
$2.00
$2.00
$2.00
$2.25
$2.02
—
Page | 34
During the year ended December 31, 2013 417,000 performance warrants were forfeited by the warrant holder. The warrants were distributed to
new warrant holders later in the year. At December 31, 2013 there are no exercisable performance warrants given the market (one third vest as
certain share price hurdles are achieved) criteria has not yet been met.
The following tables summarize information about the performance warrants granted since inception:
Grant date
December 19, 2011
March 20, 2012
May 1, 2012
September 5, 2012
July 10, 2012
August 6, 2012
November 5, 2012
November 14, 2013
Warrants Issued
Warrants Exercisable
Number
granted
Weighted
average
exercise price
Weighted
average
remaining life
(years)
Number
exercisable
Weighted
average
exercise price
4,934,000
400,000
400,000
225,000
56,603
400,000
100,000
417,000
6,932,603
$2.00
$2.00
$2.00
$2.00
$2.00
$2.00
$2.00
$2.25
$2.02
2.96
3.22
3.33
3.68
3.52
3.60
3.85
4.87
3.19
—
—
—
—
—
—
—
—
—
$2.00
$2.00
$2.00
$2.00
$2.00
$2.00
$2.00
$2.25
$2.02
The fair value of each warrant granted of $0.24 (2012 - $0.25) per warrant is estimated on the date of grant using the Black-Scholes pricing model with
the following weighted average assumptions (at December 31):
Risk free interest rate
Expected life (years)
Estimated volatility of underlying common shares (%)
Estimated forfeiture rate
Expected dividend yield (%)
2013
1.09%
5
50%
20%
0%
2012
1.23%
5
50%
20%
0%
Petrus estimated the volatility of the underlying common shares by analyzing the volatility of peer group private companies with similar corporate
structure, oil and gas assets and size. With respect to the market condition inherent in the warrants, Petrus estimated the probability of achieving the
condition and applied the probability to each individual vesting tranche in order to fairly estimate the fair value of each warrant.
Stock Options
The Company has a stock option plan in place whereby it may issue stock options to employees, consultants and directors of the Company. The
aggregate number of shares that may be acquired upon exercise of all Options granted pursuant to the plan shall, at any date or time of determination,
be equal to ten percent (10%) of the number that is equal to (i) the number of the Company’s basic Common shares then issued and outstanding; minus
(ii) a number equal to five (5) times the number of Common Shares that are issuable upon exercise of the then outstanding Performance Warrants
minus (iii) a number equal to fifty percent (50%) of the number of Common Shares that have previously been issued upon the exercise of Performance
Warrants. At December 31, 2013, 4,355,000 stock options were issued. The summary of stock option activity is presented below:
Balance, December 31, 2011
Granted
Balance, December 31, 2012
Granted
Forfeited or expired
Balance, December 31, 2013
Exercisable, December 31, 2013
Number of stock
options
Weighted Average
Exercise Price ($)
—
3,995,000
3,995,000
584,000
224,000
4,355,000
3,771,000
—
$1.75
$1.75
$2.20
$1.75
$1.84
$1.75
Page | 35
The following tables summarize information about the stock options granted since inception:
Grant date
June 29, 2012
July 10, 2012
August 27, 2012
November 5, 2012
March 18, 2013
June 3, 2013
November 14, 2013
December 31, 2013
Stock Options Issued
Number
granted
Weighted
average
exercise price
Weighted
average
remaining life
(years)
3,600,000
65,000
175,000
155,000
99,000
10,000
160,000
315,000
4,579,000
$1.75
$1.75
$1.75
$1.75
$2.00
$2.00
$2.25
$2.25
$1.84
3.75
3.52
3.65
3.84
4.20
4.41
4.85
4.98
3.95
Weighted
average
exercise price
$1.75
$1.75
$1.75
$1.75
$2.00
$2.00
$2.25
$2.25
$1.84
The fair value of each stock option granted of $0.79 (2012 - $0.77) per option is estimated on the date of grant using the Black-Scholes pricing model
with the following weighted average assumptions (at December 31):
Risk free interest rate
Expected life (years)
Estimated volatility of underlying common shares (%)
Estimated forfeiture rate
Expected dividend yield (%)
2013
1.20%
5
50%
20%
0%
2012
1.20%
5
50%
20%
0%
Petrus estimated the volatility of the underlying common shares by analyzing the volatility of peer group private companies with similar corporate
structure, oil and gas assets and size.
The following table summarizes the Company’s share-based compensation costs:
Share-based compensation costs ($):
Expensed in net income
Capitalized to exploration and evaluation assets
Capitalized to property, plant and equipment
Total share-based compensation
12. FINANCE EXPENSES
The components of finance expenses are as follows:
Cash:
Interest
Acquisition related expenses (note 5)
Non cash:
Accretion on decommissioning obligations (note 9)
Total finance expenses
13. CAPITAL MANAGEMENT
Year ended
December 31, 2013
929,253
464,626
464,627
1,858,506
Year ended
December 31, 2012
1,099,242
485,917
485,917
2,071,076
2013
2012
688,485
—
372,977
1,061,462
275,389
72,243
347,632
170,035
517,667
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.
Page | 36
14. 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, 2013, 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 $10.9 million of
accounts receivable outstanding at December 31, 2013 (December 31, 2012; $11.6 million), $5.0 million is owed from ten parties and was received
subsequent to the quarter end (December 31, 2012 - $6.1 million from eight parties). As at December 31, 2013 and December 31, 2012, the majority of
Petrus’ accounts receivable were all aged less than 90 days and the Company had no past due receivables.
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, 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, 2013, the Company had a $60 million credit facility, of which $36.6 million was undrawn (December 31, 2012, the Company had a $40
million credit facility which was entirely 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.
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 is exposed to interest rate cash flow risk as it is 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, 2013 would have changed income by
approximately $116,898, which relates to interest expense on the average outstanding revolving credit facility during the period, assuming that all other
variables remain constant (twelve months ended December 31, 2012 – nil). The Company considers this risk to be limited.
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, 2013, it is estimated that a $0.25/mcf change in the price of natural gas would have changed net income by
$941,153 (twelve months ended December 31, 2012 - $554,770). For the twelve month period ended December 31, 2013, it is estimated that a
$5.00/CDN WTI/bbl change in the price of oil would have changed net income by $2.6 million (twelve months ended December 31, 2012 - $686,120).
Page | 37
15. DEFERRED INCOME TAXES
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
Deferred tax benefits not previously recognized
Prior year true up
Change in rates
Part XXII.6 tax
Other
Current tax expense
Deferred tax expense
Effective tax rate
Year ended
December 31, 2013
Year ended
December 31, 2012
11,131,075
25%
2,782,769
465,157
—
—
(222,864)
—
—
(34,802)
—
2,990,260
26.9%
1,967,661
25%
491,915
524,153
597,638
(107,289)
—
—
2,660
27,645
2,660
1,534,062
78.1%
The components of the Company’s deferred tax liability at December 31, 2013 and December 31, 2012 are as follows:
$
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 $15,600,079 (2012 - $15,604,554) which may be applied against future income for Canadian tax
purposes. These non-capital losses expire in 2031 and 2032.
Year ended
December 31, 2013
(13,655,088)
3,886,703
671,919
3,887,270
565,131
(4,644,065)
Year ended
December 31, 2012
(9,763,312)
3,098,929
913,280
3,901,138
191,596
(1,658,369)
16. SUPPLEMENTAL CASH FLOW INFORMATION
The following table reconciles the changes in non-cash working capital as disclosed in the statements of cash flows:
$
Source (use) in non-cash working capital:
Accounts receivable
Deposits and prepaid expenses
Accounts payable and accrued liabilities
Risk management asset
Flow-through share premium liability
Risk management liability
Operating activities
Financing activities
Investing activities
17. OPERATING EXPENSES
Year ended
December 31, 2013
Year ended
December 31, 2012
769,120
286,466
(10,909,749)
-
-
-
(9,854,163)
(4,852,774)
—
(5,001,389)
(8,014,533)
(192,909)
16,673,973
(371,574)
(979,856)
1,137,562
8,252,663
(7,441,454)
(979,856)
16,673,973
The Company’s gross operating expenses for 2013 were $10.0 million (December 31, 2012; $9.3 million) which includes $2.9 million (December 31,
2012; $1.5 million) of processing, gathering and compression charges and $6.4 million (December 31, 2012; $8.0 million) of other operating expenses
incurred to operate the Company’s producing assets. The Company generated processing income recoveries of $683,697 (December 31, 2012; $2.2
million) which reduced the Company’s reported operating expenses to $9.3 million for the year ended December 31, 2013 ($7.1 million for the year
ended December 31, 2012).
Page | 38
18. GENERAL AND ADMINISTRATIVE EXPENSES
The Company’s general and administrative expenses consisted of the following expenditures:
$
Salaries and benefits
Subscriptions and licenses
Office costs
Legal, accounting and consulting
Capitalized general and administrative
19. KEY MANAGEMENT PERSONNEL
Year ended
December 31, 2013
1,885,285
118,117
673,659
690,394
(1,511,209)
1,856,245
Year ended
December 31, 2012
1,892,848
66,643
504,901
364,105
(943,490)
1,885,007
The Company consider its directors and officers to be key management personnel. The following table outlines transactions with key management
personnel:
$
Salaries and wages
Short term employee benefits
Share based compensation, gross
Year ended
December 31, 2013
880,660
26,100
1,435,286
2,342,046
Year ended
December 31, 2012
704,738
19,442
1,381,246
2,105,426
20. COMMITMENTS
The commitments for which the Company is responsible are as follows:
Commitments (000s)
Office equipment lease
Corporate office lease
Total commitments
Total
< 1 year
1-5 years
10
1,052
1,062
3
502
505
7
550
557
21. SUBSEQUENT EVENTS
Business combination
On February 28, 2014 Petrus closed an acquisition of petroleum and natural gas assets in the central Alberta foothills, with an effective date of January 1,
2014, 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, will be charged to finance expenses in the Statement of Net Income and
Comprehensive Income in the year ended December 31, 2014 as the transaction occurred subsequent to year end.
Concurrent with the closing of the asset acquisition on February 28, 2014, the Company’s borrowing base was increased to $90 million, including a $10
million development line.
The following table summarizes the net assets acquired pursuant to the acquisition:
Fair value of net assets acquired
Exploration and evaluation assets
Petroleum and natural gas properties and equipment
Decommissioning obligations
Total net assets acquired
5,446,050
17,058,504
(3,391,360)
19,113,194
Other subsequent events
On February 10, 2014 the Company granted 150,000 stock options at an exercise price of $2.25. On March 12, 2014 the Company granted 140,000 stock
options at an exercise price of $2.50. On March 31, 2014 the Company granted 165,000 stock options at an exercise price of $2.50.
Page | 39
Subsequent to December 31, 2013 the Company entered into the following financial derivative contracts:
Natural Gas
Period Hedged
Mar. 1, 2014 to Mar. 31, 2014
Mar. 1, 2014 to Mar. 31, 2014
Apr. 1, 2014 to Oct. 31, 2014
Apr. 1, 2014 to Oct. 31, 2014
Apr. 1, 2014 to Oct. 31, 2014
Nov. 1, 2014 to Mar. 31, 2015
Nov. 1, 2014 to Mar. 31, 2015
Nov. 1, 2014 to Mar. 31, 2015
Nov. 1, 2014 to Mar. 31, 2015
Nov. 1, 2014 to Mar. 31, 2015
Crude Oil
Period Hedged
Mar. 1, 2014 to Dec. 31, 2014
Aug. 1, 2014 to Dec. 31, 2014
Jan. 1, 2015 to Dec. 31, 2015
Type
Daily Volume
Price
(CAD)
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
1,000 GJ
500 GJ
1,000 GJ
500 GJ
1,000 GJ
1,000 GJ
1,000 GJ
1,000 GJ
500 GJ
1,000 GJ
$4.30/GJ
$4.53/GJ
$3.99/GJ
$4.07/GJ
$4.32/GJ
$3.84/GJ
$4.04/GJ
$4.10/GJ
$4.18/GJ
$4.43/GJ
Type
Daily Volume
Price
Fixed price
Fixed price
Fixed price
300 Bbl
300 Bbl
200 Bbl
WTI $CAD105.20/Bbl
WTI $CAD103.05/Bbl
WTI $CAD100.00/Bbl
Page | 40
CORPORATE INFORMATION
OFFICERS
Kevin L. Adair, P. Eng.
President and Chief Executive Officer
DIRECTORS
Don T. Gray
Chairman
Calgary, Alberta
Neil Korchinski, P. Eng.
Vice President, Engineering
Kevin L. Adair
Calgary, Alberta
Cheree Stephenson, CA
Vice President, Finance and
Chief Financial Officer
Joe Looke
Irving, Texas
Peter Verburg
Corporate Secretary
Patrick Arnell
Calgary, Alberta
SOLICITOR
Burnet, Duckworth & Palmer LLP
Calgary, Alberta
AUDITOR
Ernst & Young LLP
Chartered Accountants
Calgary, Alberta
INDEPENDENT RESERVE EVALUATORS
GLJ Petroleum Consultants
Calgary, Alberta
Sproule and Associates
Calgary, Alberta
BANKERS
Canadian Imperial Bank of Commerce
Calgary, Alberta
Peter Verburg
Calgary, Alberta
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
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