_____________________________________________________________________________
ANNUAL REPORT | DECEMBER 31, 2011
MANAGEMENT’S DISCUSSION AND ANALYSIS
INTRODUCTION
The following report is management’s discussion and analysis ("MD&A") of financial and operating results for Petrus
Resources Ltd. (“Petrus” or the “Company”) for the three month period ended December 31, 2011 as well as the
period from inception on December 13, 2010 to December 31, 2011. There is no comparable financial information
as Petrus did not commence operations until 2011. This MD&A should be read in conjunction with the audited
financial statements for the period from inception on December 13, 2010 to December 31, 2011 and other operating
and financial information included in this report.
Readers are directed to the advisories at the end of this report regarding forward-looking statements, BOE
presentation and non-IFRS measures.
DESCRIPTION OF THE COMPANY
Petrus is a private Canadian energy company focused on property exploitation, strategic acquisitions and risk-
managed exploration, principally in the foothills area of the Alberta Deep Basin. Petrus was incorporated December
13, 2010 and commenced operations in late 2011.
During 2011, Petrus completed an initial financing, closed a major asset acquisition, entered into a farm-in agreement
and closed a $43 million private placement, establishing itself by December 31, 2011 as an emerging junior producer
with significant opportunities to develop new oil and liquids-rich gas reserves.
2011 SIGNIFICANT EVENTS
•
In April 2011, Petrus held the first close of an initial non-brokered financing. The total seed capital raised in
the initial financing was $11.1 million.
• On October 31, 2011, Petrus closed the acquisition of oil and natural gas assets in the central Alberta
foothills area (the "Acquisition"). The Acquisition was made jointly with Manitok Energy Inc. ("Manitok") for
total gross cash consideration of $85 million before closing adjustments and related costs. Petrus’ net 50%
share of the Acquisition provided Petrus with immediate cash flow from 1,300 barrels of oil equivalent per
day (“Boe/d”) of low-decline gas production, ownership interests in significant gathering, compression, and
processing facilities, access to an extensive seismic database and an initial drilling inventory of Cardium oil
and gas locations.
•
•
•
In conjunction with the Acquisition, Petrus and Manitok established an area of mutual interest and entered
into a joint venture agreement on a portion of Manitok’s pre-existing lands in the Stolberg/Cordel and Fallen
Timber areas. The farm-in area includes about 8,320 net acres in Stolberg and about 14,080 net acres in
Fallen Timber. Petrus participated in the drilling of the first earning well in the Manitok farm-in during the
fourth quarter of 2011.
In November 2011, Petrus closed a private placement offering of 17.8 million common shares of the
Company at an issue price of $2.00 per common share and 3.0 million common shares issued on a "flow-
through" basis pursuant to the provisions of the Income Tax Act (Canada) at an issue price of $2.40 per
flow-through share, for aggregate gross proceeds of $42.7 million. A portion of the proceeds was used to
repay all outstanding indebtedness incurred in connection with the Acquisition.
Effective December 31, 2011, Petrus has 6.7 MMboe of company working interest proved plus probable
reserves, based on an evaluation prepared by GLJ Petroleum Consultants. Company working interest proved
reserves totalled 4.9 MMboe, of which 59% are categorized as proved producing.
2011 | MD&A
2
•
Petrus exited the year with production of approximately 1,282 Boe/d, positive working capital of $6.5
million and an undrawn credit facility of $22 million. The Company has 32 million shares outstanding, of
which 30% is owned by management and directors (39% fully diluted).
2012 OUTLOOK
To date in 2012, Petrus has participated in the completion of three successful Cardium oil wells in the
Stolberg/Cordel area. Petrus also participated in the drilling of one exploratory well in the Hamburg area. The primary
target was not productive; however, Petrus intends to evaluate a secondary zone of interest later this year.
Petrus has analyzed seismic data received through the Acquisition, and purchased additional 3D seismic data over a
portion of the acquired lands. New Cardium oil drilling opportunities have been identified and will be pursued as part
of the planned $18 million 2012 capital program. The Company has also acquired a 50% working interest in 384
gross hectares of undeveloped land in the heart of the Cardium oil fairway at Stolberg.
Petrus is working with Manitok to redeploy/optimize some compression assets, with the goal of reducing
maintenance capital and operating costs, as well as recouping stranded capital.
During the first quarter of 2012, Petrus hedged approximately 67% of estimated 2012 production at various prices
to reduce the impact of current low gas prices. The contract floor prices average $2.46/GJ.
Petrus is evaluating asset acquisition and new joint venture opportunities on an ongoing basis. Petrus is a return-
driven company that is focused on delivering per share growth. The Petrus team pursues assets that are
geographically focused, have predictable, low-risk production, are statistically economic and repeatable, and have
drilling targets with multiple production horizons.
RESULTS OF OPERATIONS
Capital Expenditures (000s)
Drilling and completions
Geological and geophysical
Land and lease retention
Office
Capitalized G&A, net
Total before acquisitions
Acquisitions
Total capital expenditures
Q4 2011
Q3 2011
2011
1,228
571
—
155
32
1,986
41,979
43,965
—
—
203
60
85
348
—
348
1,228
571
203
215
117
2,334
41,979
44,313
Petrus’ total capital budget for 2011 was $45 million. At December 31, 2011, $44.3 million was spent, which
includes the acquisition ($42 million), drilling and completions ($1.2 million), land and G&G costs ($774 thousand)
and office and capitalized G&A ($332 thousand).
Drilling costs of $1.2 million incurred to December 31, 2011 relate to the preliminary costs incurred on 3 gross (0.85
net) wells drilled; two (0.40 net) in the Southern Alberta Foothills and one (0.45 net) in Northwestern Alberta. The
projects were all underway at year end.
Petrus incurred $571 thousand on geological and geophysical costs during the fourth quarter of 2011. These costs
were incurred on seismic and seismic reprocessing projects in order to further evaluate and develop the Acquisition
land base for exploration opportunities.
2011 | MD&A
3
In addition to the capitalized G&A costs of $117 thousand recorded for the period ended December 31, 2011, Petrus
capitalized $10 thousand of non-cash share based compensation for 2011.
Petrus has approximately 20 thousand net acres of undeveloped land at December 31, 2011.
RESERVES
The following table provides a summary of the Company’s reserves, which were evaluated by GLJ Petroleum
Consultants with an effective date of December 31, 2011.
Reserves (MBoe)
Proved Producing
Total Proved
Total Proved +Probable
Net Present Value ($000s) Discounted at 10%
Proved Producing
Total Proved
Total Proved +Probable
Dec. 31,
2011
FD&A*
($/boe)
2,887
4,912
6,703
$38,665
$51,968
$67,542
14.94
10.51
8.19
—
—
—
RLI*
(yrs)
6.1
10.4
14.2
—
—
—
*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. RLI (reserve life index) is defined as total reserves by category divided by the annualized Nov
and Dec production.
CASH FLOW
Funds from operations is commonly used in the oil and gas industry to analyze operating performance. Funds from
operations, as presented does not have any standardized meaning prescribed by IFRS and therefore it may not be
comparable with the calculations of similar measures for other companies. Funds from operations as presented is not
intended to represent cash flow from operating activities, net loss or other measures of financial performance
calculated in accordance with IFRS. All references to funds from operations throughout this report are based on cash
flow from operating activities as per the Statement of Cash Flows before changes in noncash working capital and
decommissioning obligations.
The Company commenced operations in 2011 and production of the Acquisition assets commenced in November
2011. Funds used in operations were $41 thousand for the fourth quarter of 2011 and $204 thousand for the period
of inception to December 31, 2011. Petrus generated production revenue during the last two months of 2011 which
generated $2 million of oil and gas revenue however the weak commodity price environment resulted in a lower than
anticipated operating netback. To mitigate the risk of further commodity price decreases, Petrus entered into
financial hedging contracts in 2012 for future periods.
Petrus had a net loss of $871 thousand ($0.08 per share) for the period of inception to December 31, 2011 which is
due to Petrus commencing operations in 2011 and incurring G&A related expenses as it advanced toward becoming
an operational oil and gas company.
2011 | MD&A
4
The following table analyzes the Company’s netbacks on a barrel of oil equivalent (boe) basis, during the last two
months of 2011, when Petrus commenced production:
($/boe)
Sales price
Royalties
Operating expenses, net of processing
Transportation expenses
Operating netback
Overriding royalty income
Interest income*
G&A expense (excluding non-cash)*
Cash flow netback
Two months ended
December 31, 2011*
24.01
(5.66)
(13.44)
(1.05)
3.86
1.08
0.58
(5.61)
(0.09)
*For comparability, only November and December interest income and G&A expenses are included as production did not commence until November 1, 2011.
FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES
Two months ended
December 31, 2011*
Production*
Natural gas (mcf/d)
NGLs (boe/d)
Oil (boe/d)
Total (boe/d)
Total (boe)
Revenue (000s)*
Natural Gas
NGLs
Oil
Commodity revenue
Gross overriding royalty revenue
Oil and natural gas revenue
Average realized prices
Natural gas (per mcf)
NGLs (per bbl)
Oil (per bbl)
Combined average (per boe)
*The Company’s production commenced on November 1, 2011.
6,988
35
88
1,288
78,574
1,283
151
458
1,892
85
1,977
$3.01
$59.29
$89.57
$24.08
2011 | MD&A
5
Average benchmark prices
Natural gas
AECO (Cdn $ per mcf)
Crude Oil
Edmonton Light (Cdn$ per bbl)
Foreign Exchange
Cdn $/US$
US$/Cdn$
*The Company’s production commenced on November 1, 2011.
Two months ended
December 31, 2011*
$3.04
$97.59
1.02
0.98
2011 production from the Southern Alberta Foothills assets averaged 1,288 boe per day and was generated during
the last two months of 2011 as the assets were acquired October 31, 2011. As the Company continues to focus on
its oil opportunities it anticipates a reduction in natural gas production in 2012 through natural decline and the
addition of new oil production. Petrus’ production weighting in 2011 was approximately 90% natural gas, with the
remainder comprised of oil and natural gas liquids.
Canadian natural gas prices have seen downward pressure over the past two years and ended 2011 at the lowest
point in the past 24 months. During the two months ended December 31, 2011, the benchmark natural gas price in
Canada (set at the AECO hub) fell by 12 percent from the same period in 2010. AECO prices averaged $3.04 per
mcf throughout the last two months of 2011 compared to Petrus’ average realized price during the same period of
$3.01 per mcf. Petrus generated production revenue for the last two months of 2011 from the Acquisition assets.
Petrus uses a single marketer to manage its natural gas portfolio and sells its natural gas on a daily NOVA Alberta
Index. Natural gas revenue for 2011 was $1.3 million and production of 426,268 mcf accounted for 90% of Petrus’
production volume in 2011.
As part of a risk management program, Petrus entered into commodity derivative contracts in 2012 for a portion of
its natural gas production to protect against downward pressure on natural gas pricing. These contracts were not in
effect as at December 31, 2011.
Oil prices continued to recover in the last two months of 2011 with the West Texas Intermediate (WTI) averaging
$97.59 per bbl. The benchmark for crude oil prices in North America, and also widely referenced globally, is WTI.
As with natural gas, there can still be net price differentials due to differences in regional demand and transportation
constraints which affect the actual prices received for the commodities. Petrus includes pentanes and condensates
in the oil revenue stream for reporting purposes. The average realized price of Petrus’ crude oil and condensate was
$89.57 per bbl for the last two months of 2011 when Petrus commenced production of the Acquisition assets. The
oil and condensate revenue for 2011 was $458 thousand and production of 5,368 boe accounted for approximately
seven percent of Petrus’ production volume in 2011.
In 2011, Petrus’ NGL production mix consisted of ethane, butane, propane and sulphur. The pricing received for
Petrus’ NGL production is based on the specific product being produced and can therefore vary from period to period
depending on the production mix. In the last two months of 2011, Petrus’ overall realized NGL price averaged
$59.29/bbl. The NGL revenue for 2011 was $151 thousand and production of 2,135 boe accounted for
approximately three percent of Petrus’ 2011 production volume.
2011 | MD&A
6
Royalties
Royalties by Type
(000s)
Crown royalty expense
$/boe
Gross overriding royalty revenue*
$/boe
Two months ended
December 31, 2011
445
$5.66
85
$1.08
*Gross overriding royalty revenue is included in oil and natural gas revenues on the Statements of Net loss and Comprehensive loss
The following table shows the Company’s crown royalty expense, broken down by commodity.
Crown Royalties by Commodity
Oil
(000s)
% of production revenue
NGLs
(000s)
% of production revenue
Natural Gas
(000s)
% of production revenue
Total
% of production revenue
Two months ended
December 31, 2011
141
29%
51
40%
253
20%
445
24%
Crown royalty payments are made by producers of oil and natural gas to the owners of the mineral rights on the
Company’s leases that are paid to provincial governments (Crown).
Petrus’ overall effective crown royalty rate was 24% in the two month period ended December 31, 2011. Petrus’
royalties are primarily influenced by the gas royalties with 57% of total royalties in 2011 being gas. Alberta Crown
royalties are impacted by reference prices and by production per well.
Petrus generated $85 thousand or $1.08/boe of gross overriding royalty revenue from third parties by way of
contractual overriding royalties in the two month period ended December 31, 2011.
Operating Expenses
(000s)
Operating expense
Processing revenue*
Operating expense net of processing
Operating expense, net (per boe)
*Processing revenues are included in Other income on the Statement of Net loss and Comprehensive loss
Two months ended
December 31, 2011
1,139
(83)
1,056
$13.44
Operating expenses totalled $1.14 million or $14.49 per boe for the two months ended December 31, 2011. The
Company’s operating expenses consist of $336 thousand or $4.28 per boe of processing, gathering and compression
charges, and $803 thousand of other operating expenses incurred related to the producing assets which were
acquired October 31, 2011. Petrus generated $83 thousand or $1.05 of processing revenue on jointly owned
facilities. As a result, Petrus’ net operating expenses totalled $1.1 million or $13.44 per boe, which were all incurrd
in the last two months of 2011.
2011 | MD&A
7
Transportation Expenses
(000s)
Transportation expense
$/boe
Two months ended
December 31, 2011
82
$1.05
Petrus pays commodity and demand charges for transporting its gas on the Nova pipeline system. Transportation
expenses totalled $82 thousand or $1.05/boe for 2011, which commenced in November upon close of the asset
Acquisition.
Finance Expenses
(000s)
Accretion
$/boe
Two months ended
December 31, 2011
18
$0.23
Petrus’ finance expenses consist of accretion of its decommissioning obligation for the year ended December 31,
2011. Petrus recognized a $3.6 million obligation on October 31, 2011 associated with the asset acquisition. The
accretion of this obligation for the two months ended December 31, 2011, using a risk free interest rate of three
percent, resulted in $18 thousand of accretion being recognized.
General and Administrative Expenses
(000s)
Gross G&A expense
Capitalized G&A
Net G&A expense
Share based compensation, net
Total G&A expense, net
Q4 2011
Q3 2011
2011
496
(32)
463
23
486
283
(85)
198
—
198
778
(117)
661
23
684
The 2011 general and administration (“G&A”) expenses, net of capitalized costs directly attributable to exploration
and development totalled $684 thousand. For 2011, Petrus capitalized $117 thousand of cash G&A that directly
related to exploration and development activities.
For the three months ended December 31, 2011, Petrus’ net G&A was $486 thousand compared to $198 thousand
in the prior quarter. The overall increase in G&A for the fourth quarter compared to the third quarter in 2011 is due
to increased operating expenditures including office rent and salaries reflecting Petrus making advances toward
becoming a fully operational oil and gas company.
On December 19, 2011, Petrus made its first grant of performance warrants. 4,934,000 performance warrants were
granted at an exercise price of $2.00 and during the year no warrants were forfeited or expired. Non-cash expenses
related to Petrus’ performance warrants were $32 thousand for 2011, of which $10 thousand was capitalized,
representing the portion directly attributable to exploration and development activities. Petrus uses the Black Scholes
pricing model to estimate the fair value of the warrants on the date of grant and amortizes the estimated expense
using graded vesting over the vesting period.
At December 31, 2011, Petrus had 4,934,000 warrants outstanding at an average exercise price of $2.00. No
warrants were vested or exercisable at December 31, 2011. All warrants were anti-dilutive at December 31, 2011.
2011 | MD&A
8
Depletion and Depreciation
(000s)
Depletion
Depreciation
Total
$/boe*
Depletion
Depreciation
Total ($/boe)
Q4 2011
Q3 2011
618.3
8.4
626.7
7.87
0.11
7.98
—
0.4
0.4
—
—
—
*Petrus commenced production on November 1, 2011 therefore $/boe amounts are for the two month period ended December 31, 2011.
Depletion and depreciation expense is computed 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.
As the Company had production assets effective October 31, 2011, 2011 depletion of $618.3 thousand or $7.87
per boe was recorded for the last two months of 2011.
For the period of inception to December 31, 2011, depreciation expense totalled $8.8 thousand which relates to
amortization of the Company’s office related assets for the year. The depreciation incurred in the fourth quarter of
2011 was $8.4 thousand, and was significantly higher than the $0.4 thousand incurred in the third quarter as a
result of office equipment purchases and leasehold improvements made during the fourth quarter, as Petrus made
advances toward becoming an operational oil and gas company.
Impairment Analysis
Under International Accounting Standard (IAS) 36 – Impairment of Assets, impairment testing is performed at the
cash generating unit (CGU) level and is a one step process for testing and measuring impairment of assets wherein
each CGU’s carrying value is compared to the higher of “value in use” and “fair value less costs to sell.” Value in
use is defined as the present value of future cash flows expected to be derived from the CGU. Impairment tests
were performed at December 31, 2011 using future cash flows given a present value using a discount rate of 10%.
For the Company’s Southern Alberta Foothills CGU at December 31, 2011, no impairment was identified.
Other Income
In 2011, the Company invested excess cash balances into Guaranteed Investment Certificates with its bank. Interest
income was $68 thousand in the period ended December 31, 2011.
Also included in other income is processing revenue of $83 thousand which relates to processing fees charged to
joint venture partners at jointly owned processing facilities.
2011 | MD&A
9
Deferred Taxes
At December 31, 2011, deferred income tax assets have not been recognized due to the uncertainty as to future
realization. Management will review the carrying amount of deferred tax assets at the end of the next reporting
period and determine if sufficient taxable income will be available to allow all or part of the asset to be recovered.
Net loss before taxes
Combined federal and provincial tax rate
Computed “expected” tax (recovery)
Increase/(decrease) in taxes resulting from:
Permanent items
Impact of flow through shares
Share issuance costs
Change in rates
Deferred tax benefits deemed not probable to be recovered
Deferred tax (recovery)
Effective tax rate
Year ended December 31,
2011
(871,193)
26.5%
(230,866)
6,619
331,563
(551,600)
(6,075)
450,359
—
25.0%
The Corporation had non-capital losses of approximately $2.5 million which may be applied against future income for
Canadian tax purposes. These noncapital losses expire in 2031. These losses have not been recorded in the
Corporation’s records as they are deemed not probable to be recovered.
The Corporation had tax allowances of approximately $5.9 million which may be applied against future income for
Canadian tax purposes. These allowances are not subject to expiry. These allowances have been recorded in the
Corporation’s records as they are deemed not probable to be recovered.
Equity
In November 2011, the Company closed a private placement offering of 17.8 million common shares of the Company
at an issue price of $2.00 per common share and 3.0 million common shares issued on a "flow-through" basis
pursuant to the provisions of the Income Tax Act (Canada) at an issue price of $2.40 per flow-through share, for
aggregate gross proceeds of $42.7 million. A portion of the proceeds was used to repay all outstanding indebtedness
incurred in connection with the Acquisition. The remainder of the proceeds from the November offering will be used
to fund the Company's capital expenditure program and for working capital purposes.
The Company has a stock option plan (the “Plan”) in place whereby it may issue stock options and performance
warrants to employees, consultants and directors of the Company. The shares to be offered under the Plan consist
of common shares of the Company’s authorized but unissued common shares. The aggregate number of shares
issuable upon the exercise of all options granted under the Plan shall not exceed 20% of the issued and outstanding
shares from time to time. If any option or warrant granted hereunder shall expire or terminate for any reason in
accordance with the terms of the Plan without being exercised, the unpurchased shares subject thereto shall again be
available for the purpose of this Plan.
Excluded from diluted per share amounts for the year ended December 31, 2011 is the effect of 4,934,000 warrants
as their effect is anti-dilutive.
2011 | MD&A
10
At April 26, 2012, there are 32 million shares outstanding and 4,934,000 performance warrants outstanding. The
exercise price of the performance warrants outstanding is $2.00.
Funds from Operations, Cash Flow from Operating Activities and Net Loss
December 31, 2011
Funds (used in) operations ($)
Funds (used in) operations ($ per share)
Basic
Diluted
Cash flow (used in) operations
Net loss ($)
Net loss ($ per share)
Basic
Diluted
Shares outstanding
Basic
Diluted
Weighted average shares outstanding
Basic
Diluted
Three months ended
Twelve months ended
(40,718)
(203,826)
(0.002)
(0.002)
(705,769)
(707,726)
(0.03)
(0.03)
32,033,016
32,033,016
21,619,878
21,619,878
(0.02)
(0.02)
(839,248)
(871,193)
(0.08)
(0.08)
32,033,016
32,033,016
10,615,543
10,615,543
Liquidity and Capital Resources
As at December 31, 2011, the Company had a demand revolving credit facility of $22 million with a major Canadian
lender. At December 31, 2011, the Company has not drawn against the credit facility and the Company had a
working capital surplus of $6.5 million.
The credit facility was obtained for general corporate purposes as well as to provide bridge financing for the
Acquisition which closed October 31, 2011. The facility is available on a revolving basis for a period until June 30,
2012 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 overdraft borrowings, direct Canadian and U.S. dollar advances, bankers’ acceptances or
standby letters of credit/guarantees. 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. A decrease in the borrowing base could result in a reduction to the available credit
facility. The next semi-annual review of the credit facility is to take place on June 30, 2012.
‐
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.
2011 | MD&A
11
Petrus anticipates that it will have adequate liquidity to fund future working capital and forecasted capital
expenditures in 2012 through a combination of cash flow and additional use of its existing 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.
Related Party and Off Balance Sheet Transactions
Included in share issue costs are structuring fees of $359 thousand which relate to the Company’s initial financing.
The fees were paid to a company controlled by a director of Petrus.
The Company entered into a bridge financing agreement with a lender who is also a director of the Company. The
bridge term loan was used to finance the Acquisition which Petrus closed October 31, 2011 prior to the November
2011 private equity placement. Prior to year end, the Company repaid the bridge loan and terminated the agreement.
Provisions and Contingencies
The Company is committed to incur exploration expenditures of $5.88 million on or before December 31, 2012,
related to the flow through share issuance completed on November 14, 2011, as indicated in note 10. Petrus may
be subject to Part XII.6 tax based upon the prescribed rate, on the balance of exploration expenditures not yet
incurred at the end of each month subsequent to January 31, 2012 however it is expected that the Company will
satisfy the obligation during the first quarter of 2012.
Petrus is the subject of litigation arising out of the termination of an officer of the Company. Damages claimed under
this litigation are indeterminate however they may be material to the Company’s financial condition or results of
operations. Petrus has made a provision for the estimated costs associated with this litigation based upon guidance
provided by its legal counsel. The likelihood of success of the litigation is not yet known.
Commitments
The commitments for which the Company is responsible are as follows:
Commitments (000s)
Office equipment lease
Capital commitments
Corporate office lease
Total Commitments
Total
< 1 year
1-3 years
4-5 years
>5 years
20
10,696
3,294
14,010
5
5,296
271
5,572
10
5,400
631
6,031
5
—
661
666
—
—
1,731
1,731
Petrus enters into many contractual obligations in the course of conducting its day to day business. Material
contractual obligations consist of long-term debt with a syndicate of major banks, firm transportation charges and
operating lease arrangements.
The Company estimates it will incur approximately $6.6 million to settle its decommissioning liabilities to abandon
and reclaim petroleum and natural gas assets including well sites, gathering systems and processing facilities. The
present value of the expected cash flows is $3.6 million and has been recorded on the Company’s balance sheet as
at December 31, 2011. These costs will be incurred over the operating lives of the assets with the majority being at
or after the end of production. The Company may enter into farm-in agreements where it commits to capital
expenditures in order to earn and retain certain lands. These are considered routine in nature and form part of the
normal course of operations for active oil and gas companies and are not included in the table above.
2011 | MD&A
12
Subsequent Events
Financial derivative contracts
Subsequent to December 31, 2011, the Company entered into the following commodity financial derivative
contracts:
Natural Gas
Period Hedged
Type
Daily Volume
February 1, 2012 to March 31, 2012
February 1, 2012 to December 31, 2012
April 1, 2012 to October 31, 2012
May 1, 2012 October 31, 2012
November 1, 2012 March 31, 2013
April 1, 2013 to October 31, 2013
Fixed price
Costless collar
Fixed price
Fixed price
Fixed price
Costless collar
1,500 GJ
1,500 GJ
1,500 GJ
2,000 GJ
4,000 GJ
1,500 GJ
Price
(CAD)
$2.71/GJ
$2.70 - $2.95/GJ
$2.77/GJ
$2.25/GJ
$2.25/GJ
$2.50 - $3.02/GJ
Crude Oil
Period Hedged
Type
Daily Volume
Price
(USD)
May 1, 2012 to December 31, 2012
Costless collar
75 Bbl
WTI $95.00 - $106.55/Bbl
Common share issuance
On April 11, 2012 the Company issued 80,000 common shares at a price of $2.00 per share for gross proceeds of
$160,000. The issuance was a subsequent additional closing related to the November 2011 private equity
placement.
Outlook
Petrus’ capital will focus primarily on its oil opportunities in 2012 and capital spending of approximately $18 million
will be funded by cash flow and available debt financing. Petrus has a high-quality, low-risk asset base and
numerous oil resource opportunities to provide sustained growth. To date in 2012, Petrus has incurred sufficient
capital expenditures to satisfy its $5.88 million flow through commitment related to the flow through share issuance
completed on November 14, 2011.
2011 | MD&A
13
_____________________________________________________________________________________________________________
CRITICAL ACCOUNTING ESTIMATES AND SOURCES OF JUDGMENT
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 condensed interim consolidated 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
101 - Standards of
to proved and probable reserves determined in accordance with National Instrument 51
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 condensed consolidated financial
statements, can have a significant effect on net 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.
‐
‐
‐
in
The recoverable amounts of CGU’s and individual assets have been determined based on the higher of the
value
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 petroleum and
natural gas assets. 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.
2011 | MD&A
14
Decommissioning obligations
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
Share
values, forfeiture rates and the future attainment of performance criteria.
based payments recorded pursuant to share
based payments
‐
‐
‐
based compensation plans are subject to estimated fair
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. Future net earnings
can be affected as a result of changes in future depletion and depreciation, asset impairment or goodwill
impairment.
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.
Financial Reporting Update
International Financial Reporting Standards (“IFRS”)
Publicly accountable enterprises are required to apply IFRS, in full and without modification, for financial periods
beginning on January 1, 2011. Private enterprises are not yet required to apply IFRS, however Petrus has elected to
adopt the standards. Given that 2011 is Petrus’ first year of operations, Petrus had no financial statements balances
to restate as at January 1, 2010. As a result, a reconciliation of Canadian GAAP to IFRS was not required.
These audited financial statements present the Company’s financial results of operations issued under International
Financial Reporting Standards (“IFRS”) as at and for the period ended December 31, 2011. These audited financial
statements have been prepared by management using accounting policies consistent with IFRS as issued by the
2011 | MD&A
15
International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting
Interpretations Committee (“IFRIC”).
Financial Instruments
Financial instruments are comprised of cash and cash equivalents, accounts receivable, accounts payable and
accrued liabilities. The fair values of cash and cash equivalents, accounts receivable, and accounts payable and
accrued liabilities approximate their carrying amounts due to their short-term maturities.
Disclosure Controls and Procedures
Disclosure controls and procedures have been designed to ensure that information required to be disclosed by Petrus
is accumulated and communicated to the Company’s management as appropriate to allow timely decisions regarding
required disclosures. Petrus’ President and Chief Financial Officer have concluded that the Company’s disclosure
controls and procedures are effective to provide reasonable assurance that material information related to Petrus, is
made known to them by others within the Company.
Internal Control over Financial Reporting (“ICFR”)
Petrus’ President and Chief Financial Officer have designed internal controls over financial reporting related to the
Company to provide reasonable assurance regarding the reliability of Petrus’ financial reporting and preparation of
financial statements for external purposes in accordance with GAAP.
It should be noted that while Petrus’ President and Chief Financial Officer believe that the Company’s disclosure and
internal control procedures provide a reasonable level of assurance that they are effective, they do not expect that
the disclosure and internal control procedures will prevent all errors and fraud. A control system, no matter how well
conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system
are met.
Risk Factors
There are a number of risk factors facing companies that participate in the Canadian oil and gas industry. A summary
of certain risk factors relating to Petrus’ business are disclosed below.
Risks to Petrus’ Revenues
Volatility of Commodity Prices and Markets
Petrus’ financial performance and condition are substantially dependent on the prevailing prices of oil and natural gas
which are unstable and subject to fluctuation. Fluctuations in oil or natural gas prices could have an adverse effect on
Petrus’ operations and financial condition and the value and amount of its reserves. Prices for crude oil fluctuate in
response to global supply of and demand for oil, market performance and uncertainty and a variety of other factors
which are outside the control of Petrus including, but not limited, to the world economy and OPEC's ability to adjust
supply to world demand, government regulation, political stability and the availability of alternative fuel sources.
Natural gas prices are influenced primarily by factors within North America, including North American supply and
demand, economic performance, weather conditions and availability and pricing of alternative fuel sources.
Decreases in oil and natural gas prices typically result in a reduction of Petrus’ net production revenue and may
change the economics of producing from some wells, which could result in a reduction in the volume of Petrus’
reserves. Any further substantial declines in the prices of crude oil or natural gas could also result in delay or
cancellation of existing or future drilling, development or construction programs or the curtailment of production. All
of these factors could result in a material decrease in Petrus’ net production revenue, cash flows and profitability
causing a reduction in its oil and gas acquisition and development activities. In addition, bank borrowings available to
Petrus will in part be determined by Petrus’ borrowing base. A sustained material decline in prices from historical
average prices could further reduce such borrowing base, therefore reducing the bank credit available and could
require that a portion of its bank debt be repaid.
2011 | MD&A
16
Petrus may enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of
revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such
agreements, Petrus will not benefit from such increases.
Delay in Cash Receipts and Credit Worthiness of Counterparties
In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of Petrus’ properties,
and by the operator to Petrus, payments between any of such parties may also be delayed by restrictions imposed by
lenders, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, blowouts
or other accidents, recovery by the operator of expenses incurred in the operation of Petrus’ properties or the
establishment by the operator of reserves for such expenses. In addition, the insolvency or financial impairment of
any counterparty owing money to Petrus, including industry partners and marketing agents, could prevent Petrus
from collecting such debts.
Substantial Capital Requirements, Liquidity
Petrus may have to make substantial capital expenditures for the acquisition, exploration, development and
production of oil and natural gas reserves in the future. If revenues or reserves decline, Petrus may have limited
ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance
that debt or equity financing or cash generated by operations will be available or sufficient to meet these
requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms
acceptable to the Company. Moreover, future activities may require Petrus to alter its capitalization significantly. The
inability of the Company to access sufficient capital for its operations could have a material adverse effect on its
financial condition, results of operations or prospects.
Exploration, Development and Production Risks
Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful
evaluation may not be able to overcome. The long-term commercial success of Petrus depends on its ability to find,
acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new
reserves, any existing reserves the Company may have at any particular time, and the production therefrom will
decline over time as such existing reserves are exploited. A future increase in the Company's reserves will depend
not only on its ability to explore and develop any properties it may have from time to time, but also on its ability to
select and acquire suitable producing properties or prospects. No assurance can be given that the Company will be
able to continue to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or
participations are identified, management of Petrus may determine that current markets, terms of acquisition and
participation or pricing conditions make such acquisitions or participations uneconomic. There is no assurance that
further commercial quantities of oil and natural gas will be discovered or acquired by the Company.
Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells
that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and
other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and
operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations,
and various field operating conditions may adversely affect the production from successful wells. These conditions
include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme
weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions.
While diligent well supervision and effective maintenance operations can contribute to maximizing production rates
over time, production delays and declines from normal field operating conditions cannot be eliminated and can be
expected to adversely affect revenue and cash flow levels to varying degrees.
Oil and natural gas exploration operations are subject to all the risks and hazards typically associated with such
operations, including hazards such as fire, explosion, blowouts, cratering and oil spills, each of which could result in
substantial damage to oil and natural gas wells, producing facilities, other property and the environment or in
2011 | MD&A
17
personal injury. In accordance with industry practice, Petrus is not fully insured against all of these risks, nor are all
such risks insurable. Although Petrus maintains liability insurance in an amount which it considers adequate, the
nature of these risks is such that liabilities could exceed policy limits, in which event Petrus could incur significant
costs that could have a materially adverse effect upon its financial condition. Oil and natural gas production
operations are also subject to all the risks typically associated with such operations, including premature decline of
reservoirs and the invasion of water into producing formations.
Project Risks
The Company manages a variety of projects in the conduct of its business. Project delays may delay expected
revenues from operations. Significant project cost over-runs could make a project uneconomic. The Company's ability
to execute projects and market oil and natural gas depends upon numerous factors beyond The Company's control,
including:
•
•
•
•
•
•
•
•
•
•
•
•
•
the availability of processing capacity;
the availability and proximity of pipeline capacity;
the availability of storage capacity;
the supply of and demand for oil and natural gas;
the availability of alternative fuel sources;
the effects of inclement weather;
the availability of drilling and related equipment;
unexpected cost increases;
accidental events;
currency fluctuations;
changes in regulations;
the availability and productivity of skilled labour; and
the regulation of the oil and natural gas industry by various levels of government and governmental
agencies.
Because of these factors, Petrus could be unable to execute projects on time, on budget or at all, and may not be
able to effectively market the oil and natural gas that it produces.
Reserve Replacement
Petrus’ future oil and natural gas reserves and production and the cash flows to be derived therefrom are highly
dependent on successfully acquiring or discovering new reserves. Without the continual addition of new reserves,
any existing reserves Petrus may have at any particular time and the production therefrom will decline over time as
such existing reserves are exploited. A future increase in reserves will depend not only on Petrus’ ability to develop
any properties it may have from time to time, but also on its ability to select and acquire suitable producing
properties or prospects. There can be no assurance that Petrus’ future exploration and development efforts will result
in the discovery and development of additional commercial accumulations of oil and natural gas.
Operational Dependence
Oil and natural gas exploration and development activities are dependent on the availability of drilling and related
equipment in the particular areas where such activities will be conducted. Demand for such limited equipment or
access restrictions may affect the availability of such equipment to Petrus and may delay exploration and
development activities.
To the extent Petrus will not be the operator of its oil and natural gas properties, it will be dependent on such
operators for the timing of activities related to such properties and will be largely unable to direct or control the
activities of the operators. Payments from production generally flow through the operator and there is a risk of delay
and additional expense in receiving such revenues if the operator becomes insolvent.
2011 | MD&A
18
In addition, the success of Petrus will be largely dependent upon the performance of its management and key
employees. Petrus does not have any key man insurance policies and, therefore, there is a risk that the death or
departure of any member of management or any key employee could have a material adverse effect on the Company.
Petrus’ ability to market oil and natural gas from its wells also depends upon numerous other factors beyond its
control, including, among other things, the availability of natural gas processing and storage capacity, the availability
of pipeline capacity, the price of oilfield services and the effects of inclement weather. Because of these factors,
Petrus may be unable to market some or all of the oil and natural gas it produces or to obtain favorable prices for the
oil and natural gas it produces.
Reserve Estimates
There are numerous uncertainties inherent in evaluating quantities of reserves and the net present value of future net
revenue to be derived therefrom, including many factors beyond the control of Petrus. The reserves information
contained in the GLJ Report and set forth herein, including information respecting the net present value of future net
revenue from reserves, represents an estimate only. This estimate is based on number of assumptions relating to
factors such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of
capital expenditures, marketability of production, future prices of oil and natural gas, operating costs and royalties
and other government levies that may be imposed over the producing life of the reserves. These assumptions were
based on price forecasts in use at the date the GLJ Report was prepared and many of these assumptions are subject
to change and are beyond the control of Petrus. Ultimately, the actual reserves attributable to Petrus’ properties will
vary from the estimates contained in the GLJ Report and those variations may be material and affect the market price
of the Common shares.
Insurance
Petrus’ involvement in the exploration for and development of oil and natural gas properties may result in the
Company becoming subject to liability for pollution, blow outs, property damage, personal injury or other hazards.
Although Petrus maintains insurance consistent with prudent industry practice, it is not fully insured against certain
environmental risks, either because such insurance is not available or because of high premium costs. In particular,
insurance against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic
damages) is not available on economically reasonable terms. Accordingly, Petrus’ properties may be subject to
liability due to hazards that cannot be insured against, or that have not been insured against due to prohibitive
premium costs or for other reasons. It is also possible that changing regulatory requirements or emerging
jurisprudence could render such insurance of less benefit to Petrus. The payment of any uninsured liabilities would
reduce the funds available to Petrus.
Competition
There is strong competition relating to all aspects of the oil and natural gas industry. Petrus will actively compete for
capital, skilled personnel, undeveloped land, reserve acquisitions, access to drilling rigs, service rigs and other
equipment, access to processing facilities and pipeline and refining capacity, and in all other aspects of its operations
with a substantial number of other organizations, many of which may have greater technical and financial resources
than Petrus. Some of those organizations not only explore for, develop and produce oil and natural gas but also carry
on refining operations and market petroleum and other products on a world-wide basis and as such have greater and
more diverse resources on which to draw. Petrus’ ability to increase reserves and production in the future will depend
not only on its ability to develop its present properties, but also on its ability to select and acquire suitable producing
properties or prospects for exploratory drilling.
Risks Associated with Government Regulation
Regulatory
Oil and natural gas operations (exploration, production, pricing, marketing, transportation and royalty rates) are
subject to extensive controls and regulations imposed by various levels of government, which may be amended from
2011 | MD&A
19
time to time. Petrus’ oil and natural gas operations may also be subject to compliance with federal, provincial and
local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the
protection of the environment. Governments may regulate or intervene with respect to price, taxes, royalties and the
exportation of oil and natural gas. Such regulations may be changed from time to time in response to economic or
political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil
and natural gas industry could reduce demand for natural gas and crude oil and increase the Company’s costs, any of
which may have a material adverse effect on the Company’s business, financial condition, results of operations and
prospects. In order to conduct oil and gas operations, Petrus will require licenses from various governmental
authorities. There can be no assurance that the Company will be able to obtain all of the licenses and permits that
may be required to conduct operations that it may wish to undertake.
Changes to the regulation of the oil and gas industry in jurisdictions in which Petrus operates may adversely impact
Petrus’ ability to economically develop existing reserves and add new reserves.
Environmental Concerns
Many aspects of the oil and natural gas business present environmental risks and hazards, including the risk that
Petrus may be in noncompliance with an environmental law, regulation, permit, licence, or other regulatory approval,
possibly unintentionally or without knowledge. Such risks may expose Petrus to fines or penalties, third party
liabilities or to the requirement to remediate, which could be material.
The operational hazards associated with possible blowouts, accidents, oil spills, gas leaks, fires, or other damage to a
well or a pipeline may require Petrus to incur costs and delays to undertake corrective actions, could result in
environmental damage or contamination or could result in serious injury or death to employees, consultants,
contractors or members of the public, creating the potential for significant liability to Petrus. Also, the occurrence of
any such incident could damage Petrus’ reputation in the surrounding communities and make it more difficult for
Petrus to pursue its operations in those areas.
Compliance with environmental laws and regulations could materially increase Petrus’ costs. Petrus may incur
substantial capital and operating costs to comply with increasingly complex laws and regulations covering the
protection of the environment and human health and safety. In particular, Petrus may be required to incur significant
costs to comply with future federal or provincial greenhouse gas emissions reduction requirements or other
regulations, if enacted.
Abandonment and Reclamation Costs
Petrus will be responsible for compliance with terms and conditions of environmental and regulatory approvals and all
laws and regulations regarding abandonment and reclamation in respect of its properties, which abandonment and
reclamation costs may be substantial. A breach of such legislation or regulations may result in the imposition of fines
and penalties, including an order for cessation of operations at the site until satisfactory remedies are made.
Net Asset Value
Petrus’ net asset value will vary depending upon a number of factors beyond the control of Petrus’ management,
including oil and natural gas prices. The market price of the common shares is also determined by a number of
factors which are beyond the control of management and such market price may be greater than or less than the net
asset value of Petrus.
Permits and Licenses
The operations of Petrus may require licenses and permits from various governmental authorities. There can be no
assurance that Petrus will be able to obtain all necessary licenses and permits that may be required to carry out
exploration and development at its projects. Further, if the Company or the holder of the license or lease fails to meet
the specific requirement of a license or lease, the license or lease may terminate or expire. There can be no assurance
that any of the obligations required to maintain each license or lease will be met. The termination or expiration of the
2011 | MD&A
20
Company’s licenses or leases or the working interests relating to a license or lease may have a material adverse
effect on the Company’s business, financial condition, results of operations and prospects.
Title to Properties
Although title reviews will be done according to industry standards prior to the purchase of most oil and natural gas
producing properties or the commencement of drilling wells as determined appropriate by management, such reviews
do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat a claim of Petrus
which could result in a reduction of the revenue received by Petrus.
ADVISORIES
Basis of Presentation
Financial data presented below have largely been derived from the Company’s audited financial statements for the
period of inception to December 31, 2011, prepared in accordance with International Financial Reporting Standards
(“IFRS”). Accounting policies adopted by the Company are set out in Note 3 to the audited financial statements for
the period of inception to December 31, 2011. 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;
2011 | MD&A
21
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 fi
nancial 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 six thousand cubic feet to one barrel of oil.
The intention is to sum oil and natural gas measurement units into one basis for improved measurement of results
and comparisons with other industry participants. Petrus uses the 6:1 BOE measure which is the approximate energy
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.
2011 | MD&A
22
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 sheet as at
December 31, 2011, and the statements of net loss and comprehensive loss, changes in shareholders’ equity and cash flows
for the period from inception on December 13, 2010 to December 31, 2011, 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 audit. We conducted our audit 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 audit 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 balance sheet of Petrus Resources Ltd. as at
December 31, 2011 and its financial performance and its cash flows for the period from inception on December 13, 2010 to
December 31, 2011 in accordance with International Financial Reporting Standards.
Calgary, Canada
May 7, 2012
Chartered accountants
2011 | Annual Report
1
BALANCE SHEET
(AUDITED)
(Expressed in Canadian dollars)
As at
ASSETS
Current
Cash and cash equivalents
Deposits and prepaid expenses
Accounts receivable
Non-current
Exploration and evaluation assets (note 5)
Property, plant and equipment (note 6)
LIABILITIES
Current
Accounts payable and accrued liabilities
Flow-through share premium liability (note 10)
Non-Current
Decommissioning obligation (note 9)
Shareholders’ Equity
Share capital (note 10)
Contributed surplus
Deficit
See accompanying notes to the financial statements
Commitments (note 21)
Subsequent events (note 22)
Approved by the Board of Directors,
(signed) “Don T. Gray”
Don T. Gray
Executive Chairman
December 31, 2011
7,786,788
396,657
3,635,358
11,818.803
7,232,470
40,089,044
47,321,514
59,140,317
4,328,105
979,856
5,307,961
3,652,999
8,960,960
51,018,159
32,391
(871,193)
50,179,357
59,140,317
(signed) “Patrick Arnell”
Patrick Arnell
Director
2011 | Annual Report
2
STATEMENT OF NET LOSS AND COMPREHENSIVE LOSS
(AUDITED)
(Expressed in Canadian dollars, except for share information)
REVENUE
Oil and natural gas revenue
Royalties
Oil and natural gas revenue, net of royalties
Other income
EXPENSES
Operating (note 17)
Transportation expenses
General and administrative (note 18)
Share-based compensation (note 11)
Finance (note 9)
Depletion and depreciation (note 6)
NET LOSS BEFORE INCOME TAXES
Deferred income tax expense (note 15)
TOTAL NET LOSS AND COMPREHENSIVE LOSS
Net loss per common share (note 13)
Basic and diluted
See accompanying notes to the financial statements
Period of inception to
December 31, 2011
1,976,817
444,757
1,532,060
150,923
1,682,983
1,138,867
87,302
660,640
22,674
17,960
626,733
2,554,176
(871,193)
—
(871,193)
(0.08)
2011 | Annual Report
3
STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(AUDITED)
(Expressed in Canadian dollars)
Balance at inception
Net loss
Issuance of common shares
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 (note 15)
Balance, December 31, 2011
See accompanying notes to the financial statements
Share
Capital
Contributed
Surplus
—
—
54,204,418
(1,188,386)
—
—
(2,206,403)
584,697
(376,167)
51,018,159
—
—
—
—
22,674
9,717
—
—
—
32,391
Retained
Earnings
(Deficit)
—
(871,193)
—
—
—
—
—
—
—
(871,193)
Total
—
(871,193)
54,204,418
(1,188,386)
22,674
9,717
(2,206,403)
584,697
(376,167)
50,179,357
2011 | Annual Report
4
STATEMENT OF CASH FLOWS
(AUDITED)
(Expressed in Canadian dollars)
Funds generated by (used in):
OPERATING ACTIVITIES
Net loss
Adjust items not affecting cash:
Share-based compensation
Finance expenses
Depletion and depreciation
Change in operating non-cash working capital (note 16)
Funds used in operations
FINANCING ACTIVITIES
Issuance of common shares (note 10)
Share issue costs (note 10)
Bridge financing issuance (notes 8 and 10)
Bridge financing repayment (notes 8 and 10)
Change in financing non-cash working capital (note 16)
Funds generated by financing activities
INVESTING ACTIVITIES
Property and equipment acquisitions (note 4)
Exploration and evaluation asset expenditures (note 5)
Petroleum and natural gas property expenditures (note 6)
Other capital expenditures (note 6)
Change in investing non-cash working capital (note 16)
Funds used in investing activities
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
See accompanying notes to the financial statements
Period of inception to
December 31, 2011
(871,193)
22,674
17,960
626,733
(203,826)
(635,422)
(839,248)
49,200,418
(2,206,403)
12,000,000
(6,996,000)
160,037
52,158,052
(41,979,444)
(1,856,926)
(252,472)
(214,649)
771,475
(43,532,016)
7,786,788
—
7,786,788
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 period of inception of December 13,
2010, to December 31, 2011. 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.
There is no comparable financial information for the prior periods as Petrus did not commence operations until 2011.
The Company’s head office is located at 4210, 525 8th Avenue SW, Calgary, Alberta Canada.
2. BASIS OF PRESENTATION
(a) Statement of Compliance
These audited financial statements have been prepared by management using accounting policies consistent with
International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”)
and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”).
(b) Measurement Basis
These audited financial statements were prepared on the basis of historical cost and are presented in Canadian dollars.
(c) Critical Accounting Estimates and Sources of Judgment
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
101”). The calculation incorporates the estimated future cost of developing and
for Oil and Gas Activities (“NI 51
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.
‐
2011 | Annual Report
6
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.
‐
‐
‐
in
The recoverable amounts of CGU’s and individual assets have been determined based on the higher of the
value
use calculations and fair values less costs to sell. These calculations require the use of estimates and
assumptions, including the discount rate, future petroleum and natural gas prices, expected production volumes
and anticipated recoverable quantities of proved and probable reserves. These assumptions are subject to change
as new information becomes available and changes in economic conditions take place. Changes may impact the
estimated life of the field and economical reserves recoverable and may require a material adjustment to the
carrying value of petroleum and natural gas assets. The Company monitors internal and external indicators of
impairment relating to its tangible assets.
Technical feasibility and commercial viability of exploration and evaluation assets
The determination of technical feasibility and commercial viability, based on the presence of proved and probable
reserves, results in the transfer of assets from exploration and evaluation assets to property, plant and equipment.
As discussed above, the estimate of proved and probable reserves is inherently complex and requires significant
judgment. Thus any material change to reserve estimates could affect the technical feasibility and commercial
viability of the underlying assets.
Decommissioning obligation
At the end of the operating life of the Company’s facilities and properties and upon retirement of its petroleum and
natural gas assets, decommissioning costs will be incurred by the Company. This requires judgment regarding
abandonment date, future environmental and regulatory legislation, the extent of reclamation activities, the
engineering methodology for estimating cost, future removal technologies in determining the removal cost and
discount rates to determine the present value of these cash flows.
Income taxes
Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts
recognized in income or loss both in the period of change, which would include any impact on cumulative
provisions, and in future periods. Deferred tax assets (if any) are recognized only to the extent it is considered
probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are
likely to reverse and a judgment as to whether or not there will be sufficient taxable income available to offset the
tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore
inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or
decrease in the amounts recognized in respect of deferred tax assets as well as the amounts recognized in income
or loss in the period in which the change occurs. Additionally, future changes in tax laws in the jurisdictions in
which the Company operates could limit the ability of the Company to obtain tax deductions in future periods.
Measurement of share
Share
values, forfeiture rates and the future attainment of performance criteria.
based compensation recorded pursuant to share
based compensation
‐
‐
‐
based compensation plans are subject to estimated fair
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
2011 | Annual Report
7
and goodwill in the purchase price allocation. Future net earnings can be affected as a result of changes in future
depletion and depreciation, asset impairment or goodwill impairment.
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) Cash and cash equivalents
The Company’s cash and cash equivalents consist of deposits held in the Company’s chequing account as well as various
guaranteed investment certificates with maturities no greater than 90 days.
(b) 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.
(c) 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 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.
Leased assets
Other leases are capital leases, which are recognized on the Company’s balance sheet. Petrus records the
payments made in accordance with the lease as a reduction to the obligation recorded.
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
production method based on the commercial proved and probable reserves
allocated to its CGU.
of
‐
‐
2011 | Annual Report
8
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 in the statement of financial position 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 useful lives of the Company’s corporate assets are as follows:
Corporate Asset
Years
Office equipment, furniture and fixtures
Computer Hardware
Computer Software
Leasehold Improvements
5
2
1
10
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.
use. Fair value, less costs to
The recoverable amount is the higher of fair value, less costs to sell, and the value
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
use
is assessed using the expected future cash flows discounted at a pre
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.
based rates to reflect a market participant’s view of the risks associated with the assets. Value
tax rate.
in
in
‐
‐
‐
‐
‐
‐
(d) 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
2011 | Annual Report
9
extraction) and appraisal and including any directly attributable general and administration costs and share
payments, are accumulated and capitalized as exploration and evaluation assets.
based
‐
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 petroleum and natural gas
asset into the CGU to which it relates, but only after the carrying value of the relevant exploration and evaluation
asset has been assessed for impairment and, where appropriate, its carrying value adjusted. Technical feasibility
and commercial viability are considered to be demonstrable when proved or probable reserves are determined to
exist. If it is determined that technical feasibility and commercial viability have not been achieved in relation to the
exploration and evaluation assets appraised, all other associated costs are written down to the recoverable amount
in net income (loss).
Expired land leases included as undeveloped land in exploration and evaluation assets are recognized in exploration
and evaluation cost in net income (loss) upon expiry.
Impairment
If and when facts and circumstances indicate that the carrying value of an exploration and evaluation asset may
exceed its recoverable amount, an impairment review is performed. For exploration and evaluation assets, when
there are such indications, an impairment test is carried out 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
use.
in
(e) 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.
(f) 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
2011 | Annual Report
10
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.
(g) Finance expenses
Finance expense may be comprised of interest expense on borrowings and accretion of the discount on decommissioning
obligations.
(h) 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.
(i) 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.
(j) 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.
(k) 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.
2011 | Annual Report
11
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.
(l) Joint interests
Significantly all of the Company’s activities are conducted jointly with others through unincorporated joint ventures. The
Company accounts for its share of the results and net assets of these Joint Ventures as jointly controlled assets. The
audited financial statements include Petrus’ share of these jointly controlled assets and a proportionate share of the
relevant revenue and related costs.
(m) 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.
‐
‐
(n) 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
money stock options and share warrants is assumed at the beginning of the year or
are "in
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.
money"). Exercise of in
the
the
‐
‐
‐
‐
‐
‐
(o) New standards and interpretations not yet adopted
In November 2009, the International Accounting Standards Board (IASB) published IFRS 9 – Financial Instruments, which
covers the classification and measurement of financial assets as part of its project to replace IAS 39 – Financial
Instruments: Recognition and Measurement. In October 2010, the requirements for classifying and measuring financial
liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities at fair value
through earnings. If this option is elected, entities are required to reverse the portion of the fair value change due to credit
risk out of earnings and recognize the change in other comprehensive income. IFRS 9 is effective for the
Company on January 1, 2015. Early adoption is permitted and the standard is required to be applied retrospectively.
In May 2011 the IASB issued four new standards. All are effective for annual periods beginning on or after
January 1, 2015.
IFRS 10 – Consolidated Financial Statements replaces IAS 27 – Consolidated and Separate Financial Statements.
It introduces a new principle-based definition of control, applicable to all investees to determine the scope of consolidation.
The standard provides the framework for consolidated financial statements and their preparation based on the principle of
control.
2011 | Annual Report
12
IFRS 11 – Joint Arrangements replaces IAS 31 – Interests in Joint Ventures. IFRS 11 divides joint arrangements into two
types, each having its own accounting model. A “joint operation” continues to be accounted for using proportionate
consolidation, while a “joint venture” must be accounted for using equity accounting. This differs from IAS 31, in which
there was the choice to use proportionate consolidation or equity accounting for joint ventures. A “joint operation” entails
joint operators having rights to the assets and obligations for the liabilities relating to the arrangement. In a “joint venture”,
the joint venturers have rights to the net assets of the arrangement, typically through their investment in a separate joint
venture entity.
IFRS 12 – Disclosure of Interests in Other Entities is a new standard, which combines all of the disclosure requirements for
subsidiaries, associates and joint arrangements, as well as unconsolidated structured entities.
IFRS 13 – Fair Value Measurement is a new standard meant to clarify the definition of fair value, provide guidance on
measuring fair value and improve disclosure requirements related to fair value measurement.
The Company is evaluating the impact of adopting the newly issued standards.
4. ACQUISITIONS
On October 31, 2011 Petrus closed an acquisition of petroleum and natural gas properties for cash consideration of $42
million, net of adjustments. The transaction was accounted for as a business combination. Petrus recorded $5.2 million in
exploration and evaluation assets for the value of undeveloped land and seismic, $36.8 million in property and equipment
and $3.6 million of decommissioning liabilities were recognized in relation to the acquired properties. Acquisition costs of
$36 thousand were charged to general and administrative expenses on the statement of net loss and comprehensive loss.
The financial statements incorporate the operations of the properties beginning November 1, 2011. During the period
November 1, 2011 to December 31, 2011, the Company recorded oil and natural gas revenue of $2 million and a net loss
of $230 thousand related to the acquisition. The impact of this acquisition on revenue and net loss, as if acquired at
inception, would have been incremental revenue of $10.3 million and an incremental net loss of $1.1 million, respectively.
5. EXPLORATION AND EVALUATION ASSETS
Balance at inception
Cash additions
Capitalized general & administrative
Acquisitions (note 4)
Change in decommissioning provision
Transfers to property, plant and equipment
Balance, December 31, 2011
$
—
1,970,697
58,267
5,160,551
42,955
—
7,232,470
Depletion
E&E 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 E&E assets during the
period. Exploration and evaluation assets are not subject to depletion.
Capitalization of general & administrative expenses
During the year ended December 31, 2011 the Company capitalized $58 thousand (2010 – Nil) of general & administrative
expenses directly attributable to exploration activities. Included in this amount is non-cash related share-based
compensation of $5 thousand.
2011 | Annual Report
13
Impairment
The Company analyzed indicators of impairment in relation to its exploration and evaluation assets at December 31, 2011
to ensure the carrying value does not exceed fair value. Based on the analysis, Petrus concluded that its exploration and
evaluation assets were not impaired at December 31, 2011.
6. PROPERTY, PLANT AND EQUIPMENT
$
Balance at inception
Cash additions
Capitalized general & administrative
Acquisitions (note 4)
Transfers from exploration and evaluation assets
Change in decommissioning provision
Depletion & depreciation
Balance, December 31, 2011
Cost
—
246,532
58,267
36,818,894
—
3,592,084
—
40,715,777
Accumulated
DD&A
Net book value
—
—
—
—
—
—
(626,733)
(626,733)
—
246,532
58,267
36,818,894
—
3,592,084
(626,733)
40,089,044
Depletion and Depreciation
Estimated future development costs of $10.2 million associated with the development of the Company’s proved plus
probable undeveloped reserves were included with the costs subject to depletion.
Capitalization of general & administrative expenses
During the year ended December 31, 2011 the Company capitalized $58 thousand of general & administrative expenses
directly attributable to development activities. Included in this amount is non-cash related share-based compensation of $5
thousand.
Impairment
The Company performed an impairment test at December 31, 2011 to ensure the carrying value of its petroleum and
natural gas assets is recoverable and does not exceed fair value. The petroleum and natural gas prices are based on
December 31, 2011 commodity price forecasts of the Company’s independent reserve evaluators. Based on the
impairment test, Petrus concluded that its petroleum and natural gas assets were not impaired at December 31, 2011.
7. REVOLVING CREDIT FACILITY
As at December 31, 2011, the Company had a demand revolving credit facility of $22 million with a major Canadian
lender.
The credit facility was obtained for general corporate purposes as well as to provide bridge financing for the Acquisition
which closed October 31, 2011. The facility is available on a revolving basis for a period until June 30, 2012 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 first floating charge (with right to fix) over all 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. The next semi-
annual review of the credit facility is to take place on June 30, 2012. At December 31, 2011, the Company has not
drawn against the credit facility.
2011 | Annual Report
14
8. BRIDGE TERM LOAN
The Company utilized a senior, unsecured non-revolving term loan of $12 million in order to finance the October 31, 2011
business combination. The loan was repaid entirely on November 14, 2011 using cash of $7 million and issuing shares in
conjunction with the Company’s private equity placement of $5 million. At December 31, 2011, the loan has been
cancelled in conjunction with its repayment.
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. The Company has estimated the net present value of the decommissioning obligations to
be $3.7 million as at December 31, 2011 based on an undiscounted total future liability of $6.6 million. These payments
are expected to be incurred over the operating lives of the assets.
The following table reconciles the decommissioning liability:
Balance at inception
Acquisitions (note 4)
Liabilities incurred
Accretion expense
Balance, December 31, 2011
10. SHARE CAPITAL
December 31, 2011
—
3,592,084
42,955
17,960
3,652,999
Authorized
The authorized share capital consists of an unlimited number of common voting shares without par value.
Issued and Outstanding
Common shares
Balance at inception
Common shares issued under private placement (1)
Flow-through shares issued, net of premium (2)
Common shares issued under private placement (3)
Share issue costs
Tax benefit of share issue costs
Balance, December 31, 2011
Number of Shares
Amount
—
11,050,000
2,970,966
18,012,050
—
—
32,033,016
—
11,050,000
5,941,932
36,024,100
(2,206,403)
208,530
51,018,159
Share Issuances
(1) The Company completed its initial private equity placement on March 4, 2011 and 5,590,000 common shares were
issued at a price of $1.00 per share for gross proceeds of $5,590,000. Subsequent additional closings related to the
initial private equity placement ($1 per common share) occurred with an aggregate of 5,460,000 additional common
shares issued at $1 per share for additional gross proceeds of $5,460,000.
(2) The Company completed its second private equity placement on November 14, 2011. 2,970,966 flow-through
shares were issued at a price of $2.40 per share for total gross proceeds of $7,130,318. Of the issuance price,
$0.40 per share or $1,188,386 was determined to be the premium on the flow-through shares. As at December 31,
2011 the Company had spent $1,251,183 and therefore the liability outstanding at December 31, 2011 was reduced
to $979,856. Petrus is committed to spending an additional $5.88 million on qualified exploration and development
expenditures by December 31, 2012. Under National Instrument 45-102, the flow through shares issued November
14, 2011 are subject to a restricted hold period which expires March 15, 2012.
2011 | Annual Report
15
(3) On November 14, 2011 the Company also issued 17,338,550 common shares at a price of $2.00 per share for gross
proceeds of $34,677,100. Subsequent additional closings related to this private equity placement ($2 per common
share) occurred as follows: 458,500 common shares ($917,000 gross) on November 22, 2011; and 215,000
common shares ($430,000 gross) on December 31, 2011. Under National Instrument 45-102, the common shares
issued November 14, 2011 are subject to a restricted hold period which expires March 15, 2012. The common
shares issued in subsequent closings are subject to a restricted hold period which expires on March 23, 2011
(November 22, 2011 closing) and May 1, 2012 (December 31, 2011 closing).
(4) 1,500,000 common shares ($3,000,000 gross proceeds) and 835,000 flow through shares ($2,004,000 gross
proceeds) issued in conjunction with the November 14, 2011 private equity placement were issued to settle a portion
of the bridge term loan as discussed in note 8.
11. SHARE
BASED COMPENSATION
‐
The Company has a stock option plan (the “Plan”) in place whereby it may issue stock options and performance warrants
to employees, consultants and directors of the Company. Upon exercise of the options or warrants the Company settles
the obligation by issuing common shares of the Company and cash settlements are not required. The shares to be offered
under the Plan consist of common shares of the Company’s authorized but unissued common shares. The aggregate
number of shares issuable upon the exercise of all options granted under the Plan shall not exceed 20% of the issued and
outstanding shares from time to time. If any option or warrant granted hereunder expires or terminates for any reason in
accordance with the terms of the Plan without being exercised, the un-purchased shares subject thereto shall again be
available for the purpose of this Plan. At December 31, 2011, 4,934,000 performance warrants were issued under the
Company’s stock option plan.
Performance Warrants
Performance warrants are granted for a term of three years and vest based on three criteria, time (one third vest per year),
market (one third vest as certain share price hurdles are achieved) and employment or service. The summary of
performance warrant activity is presented below:
Balance at inception
Granted
Exercised
Forfeited or expired
Balance, December 31, 2011
Exercisable, December 31, 2011
Number of
warrants
Weighted Average
Exercise Price ($)
4,934,000
—
—
4,934,000
—
$2.00
—
—
$2.00
—
The following tables summarize information about the performance warrants outstanding at December 31, 2011:
Grant date
December 19, 2011
Warrants Outstanding
Warrants Exercisable
Weighted
average
exercise
price
Weighted
average
remaining
life (years)
Number
outstanding
Weighted
average
exercise
price
Number
exercisable
4,934,000
4,934,000
$2.00
$2.00
5
5
—
—
$2.00
$2.00
2011 | Annual Report
16
The fair value of each warrant granted of $0.36 per warrant is estimated on the date of grant using the Black
pricing model with the following weighted average assumptions (at December 31, 2011):
Fair value of warrants
Risk free interest rate
Expected life (years)
Estimated volatility of underlying common shares (%)
Estimated forfeiture rate
Expected dividend yield (%)
Scholes
‐
$0.36
1.36%
5
65%
20%
0%
Petrus estimated the volatility of their underlying common shares by analyzing the volatility of peer group public 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.
The following table summarizes the Company’s share
based compensation at December 31, 2011:
Share
Share
Share
‐
‐
Total share
‐
based compensation expensed in net loss
based compensation capitalized to exploration and evaluation assets
based compensation capitalized to property, plant and equipment
‐
based compensation
22,674
4,859
4,859
32,391
12. CAPITAL MANAGEMENT
‐
The Company’s general capital management policy is to maintain a sufficient capital base in order to manage its business
to enable the Company to increase the value of its assets and therefore its underlying share value. The Company’s
objectives when managing capital are (i) to manage financial flexibility in order to preserve the Company’s ability to meet
financial obligations; (ii) maintain a capital structure that allows Petrus the ability to finance its growth using internally
generated cashflow and (iii) to maintain a flexible capital structure which optimizes the cost of capital at an acceptable risk
level and provides an optimal return to equity holders.
In the management of capital, Petrus includes share capital and total net debt, which is made up of debt and working
capital (current assets less current liabilities). Petrus manages its capital structure and makes adjustments in light of
economic conditions and the risk characteristics of the underlying assets. In order to maintain or adjust the capital
structure, Petrus may issue new equity, increase or decrease debt, adjust capital expenditures and acquire or dispose of
assets.
13. EARNINGS PER SHARE AMOUNTS
Basic earnings per share amounts are calculated by dividing net income (loss) for the period by the weighted average
number of common shares outstanding during the period. The following table shows the calculation of basic and diluted
earnings per share for the periods:
Net income (loss) for the period
Weighted average number of common shares
Weighted average number of common shares – basic
Dilutive effect of outstanding warrants
Weighted average number of common shares – diluted
Basic net income (loss) per share
Diluted net income (loss) per share
Period of inception
to Dec. 31, 2011
$(871,193)
10,615,543
—
10,615,543
(0.08)
(0.08)
2011 | Annual Report
17
At December 31, 2011, the market price of $2.00 of the Company’s shares was used to determine the dilutive effect of
performance warrants. For the period ended December 31, 2011, all 4,934,000 warrants issued were anti-dilutive. At
December 31, 2011 the Company had 32,033,016 common shares outstanding.
14. FINANCIAL INSTRUMENTS
The Company’s financial instruments recognized on the financial statements consist of cash and cash equivalents,
accounts receivable and accounts payable & accrued liabilities. The fair value of Petrus’ financial instruments were
assessed and found to approximate their carrying amounts.
Fair Value of Financial Instruments
The fair value of Petrus’ financial instruments, approximate their carrying amounts due to their short terms to maturity or
the indexed rate of interest on the bank debt:
Financial Assets
Loans and receivables:
Cash and cash equivalents
Accounts receivable
Financial Liabilities
Other Financial Liabilities:
Accounts payable and accrued liabilities
As at December 31, 2011
Carrying Amount
Fair Value
7,786,788
3,635,358
7,786,788
3,635,358
4,328,105
4,328,105
The Company continues to monitor its trade and other receivables and its allowance for doubtful accounts. As at
December 31, 2011, there have been no impairment issues.
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, 2011, financial assets on the audited statement of financial position are comprised of cash and cash
equivalents 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 two 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 $3.6 million of accounts receivable outstanding as at
December 31, 2011 (all of which is less than 90 days old), $2.7 million is owed from four parties and was received in
January 2012. The remaining amount of $800 thousand was related to normal operations of the Company and was
received in 2012. No provision has been made for past due receivables as of December 31, 2011 as the Corporation has
assessed there are no impaired receivables.
Interest rate risk
The Company is not currently exposed to interest rate risk as the Company did not have any amount outstanding against
its credit facility.
Liquidity risk
Liquidity risk relates to the risk the Company will encounter difficulty in meeting obligations associated with its financial
liabilities. The financial liabilities on its statement of financial position consist of accounts payable and accrued liabilities.
2011 | Annual Report
18
The Company anticipates it will continue to have adequate liquidity to fund its financial liabilities through its future cash
flows.
Market risk
Market risk is the risk of uncertainty arising from movements of the market price of commodities and interest rates,
including their impact on the future performance of the business. The market price movements that could have an adverse
effect on the value of the Company’s future cash flows are primarily commodity price movements given that the Company
is not drawn on its credit facility at December 31, 2011. For the period ended December 31, 2011, it is estimated that a
$0.25/mcf decrease in the price of natural gas would have increased the net loss by $107 thousand. For the period ended
December 31, 2011, it is estimated that a $5.00/CDN WTI/bbl decrease in the price of oil would have increased the net
loss by $27 thousand.
15. DEFERRED INCOME TAXES
At December 31, 2011, deferred income tax assets have not been recognized due to the uncertainty as to future
realization. Management will review the carrying amount of deferred tax assets at the end of the next reporting period and
determine if sufficient taxable income will be available to allow all or part of the asset to be recovered.
Income (loss) before taxes
Combined federal and provincial tax rate
Computed “expected” tax expense (recovery)
Increase/(decrease) in taxes resulting from:
Permanent items
Impact of flow-through shares
Share issuance costs
Change in rates
Deferred tax benefits deemed not probable to be recovered
Deferred tax expense (recovery)
Effective tax rate
Year ended December
31, 2011
(871,193)
26.5%
(230,866)
6,619
331,563
(551,600)
(6,075)
450,359
—
25.0%
The Corporation had non-capital losses of approximately $2,495,207 which may be applied against future income for
Canadian tax purposes. These noncapital losses expire in 2031. These losses have not been recorded in the Corporation’s
records as they are deemed not probable to be recovered.
The Corporation had tax allowances of approximately $5,859,400 which may be applied against future income for
Canadian tax purposes. These allowances are not subject to expiry. These allowances have not been recorded in the
Corporation’s records as they are deemed not probable to be recovered.
2011 | Annual Report
19
16. SUPPLEMENTAL CASH FLOW INFORMATION
The following table reconciles the changes in non
flows:
‐
cash working capital as disclosed in the interim statements of cash
$
Source (use) in non-cash working capital:
Accounts receivable
Deposits and prepaid expenses
Accounts payable and accrued liabilities
Operating activities
Financing activities
Investing activities
17. OPERATING EXPENSES
Period of inception
to Dec. 31, 2011
(3,635,358)
(396,657)
4,328,105
296,090
(635,422)
160,037
771,475
The Company’s operating expenses consist of $336 thousand of processing, gathering and compression charges and $803
thousand of other operating expenses incurred to operate the Company’s producing assets which were acquired October
31, 2011.
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
Transaction costs (note 4)
Capitalized general and administrative
Period of inception
to Dec. 31, 2011
408,485
36,589
132,578
153,429
36,376
(106,817)
660,640
19. KEY MANAGEMENT PERSONNEL
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
Period of inception
to Dec. 31, 2011
401,944
8,364
31,039
441,347
20. RELATED PARTY TRANSACTIONS
Included in share issue costs are structuring fees of $359 thousand which relate to the Company’s initial financing. The
fees were paid to a company controlled by a director of Petrus.
The Company entered into a bridge financing agreement with a lender who is also a director of the Company. The bridge
term loan was used to finance the Acquisition which Petrus closed October 31, 2011 prior to the November 2011 private
equity placement. Prior to year end, the Company repaid the bridge loan (see note 8) and terminated the agreement.
2011 | Annual Report
20
21. COMMITMENTS AND CONTINGENCIES
Provisions and Contingencies
The Company’s provision for decommissioning obligations is presented in note 9.
The Company is committed to incur exploration expenditures of $5.88 million on or before December 31, 2012, related to
the Flow-through Share issuance completed on November 14, 2011, as indicated in note 10. Petrus may be subject to
Part XII.6 tax based upon the prescribed rate, on the balance of exploration expenditures not yet incurred at the end of
each month subsequent to January 31, 2012 however it is expected that the Company will satisfy the obligation during
the first quarter of 2012.
Petrus is the subject of litigation arising out of the termination of an officer of the Company. Damages claimed under this
litigation are indeterminate however they may be material to the Company’s financial condition or results of operations.
Petrus has made a provision for the estimated costs associated with this litigation based upon guidance provided by its
legal counsel. The likelihood of success of the litigation is not yet known.
The commitments for which the Company is responsible are as follows:
Commitments (000s)
Office equipment lease
Capital commitments
Corporate office lease
Total commitments
22. SUBSEQUENT EVENTS
Total
< 1 year
1-3 years
4-5 years
>5 years
20
10,696
3,294
14,010
5
5,296
271
5,572
10
5,400
631
6,041
5
—
661
666
—
—
1,731
1,731
Financial derivative contracts
Subsequent to December 31, 2011, the Company entered into the following commodity financial derivative contracts:
Natural Gas
Period Hedged
Type
Daily Volume
February 1, 2012 to March 31, 2012
February 1, 2012 to December 31, 2012
April 1, 2012 to October 31, 2012
May 1, 2012 October 31, 2012
November 1, 2012 March 31, 2013
April 1, 2013 to October 31, 2013
Fixed price
Costless collar
Fixed price
Fixed price
Fixed price
Costless collar
1,500 GJ
1,500 GJ
1,500 GJ
2,000 GJ
4,000 GJ
1,500 GJ
Crude Oil
Period Hedged
Type
Daily Volume
Price
(CAD)
$2.71/GJ
$2.70 - $2.95/GJ
$2.77/GJ
$2.25/GJ
$2.25/GJ
$2.50 - $3.02/GJ
Price
(USD)
May 1, 2012 to December 31, 2012
Costless collar
75 Bbl
WTI $95.00 - $106.55/Bbl
Common share issuance
On April 11, 2012 the Company issued 80,000 common shares at a price of $2.00 per share for gross proceeds of
$160,000. The issuance was a subsequent additional closing related to the November 2011 private equity placement.
Under National Instrument 45-102, the common shares issued are subject to a restricted hold period which expires August
12, 2012.
2011 | Annual Report
21
CORPORATE INFORMATION
OFFICERS
Kevin L. Adair, P. Eng.
President and Chief Executive Officer
DIRECTORS
Don T. Gray
Executive Chairman
Calgary, Alberta
SOLICITOR
Burnet, Duckworth & Palmer LLP
Calgary, Alberta
Neil Korchinski, P. Eng.
Vice President, Engineering
Rick F. Braund
Calgary, Alberta
AUDITOR
Ernst & Young LLP
Chartered Accountants
Calgary, Alberta
Cheree Stephenson, CA
Chief Financial Officer
Patrick Arnell
Calgary, Alberta
INDEPENDENT RESERVE EVALUATOR
GLJ Petroleum Consultants
Calgary, Alberta
Peter Verburg
Corporate Secretary
Peter Verburg
Calgary, Alberta
Kevin L. Adair
Calgary, Alberta
BANKERS
Royal Bank of Canada
Calgary, Alberta
Canadian Imperial Bank of Commerce
Calgary, Alberta
TRANSFER AGENT
Valiant Trust Company
Calgary, Alberta
HEAD OFFICE
4210, 525 – 8th Avenue S.W.
Calgary, Alberta T2P 1G1
Phone: 403-984-9014
Fax: 403-984-2717
WEBSITE
www.petrusresources.com
2011 | Annual Report
22