Petrobank Energy and Resources Ltd.

Facilities: Design one, build many

THAI® produces upgraded oil

RealValue

2010 AnnuAl RepoRt

� HBU 2P reserves/share� PBN 2P reserves/share� PMG 2P reserves/share� PMG spun-off to PBG shareholders

� HBU� PBN� PMG� PMG spun-off to PBG shareholders

� HBU� PBG’s ownership of PBN� PBG’s ownership of PMG� PMG spun-off to PBG shareholders

(1) Net present values are before tax and discounted at 10% for PBN and PMG, and at 8% for the HBU

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Contents

1 Financial Highlights

2 the Asset Base

6 the Ability

10 Innovation

12 Real opportunity

14 letters to Shareholders

20 our Real Commitment

23 petrobank Values

During 2010, Petrobank (“PBG”) continued to deliver real value for our shareholders.

Through revisions and improvements to our THAI® production technology we were able to

increase production to commercial levels, and book our first proved reserves attributable

to THAI®. Our 59% owned subsidiary company, PetroBakken (“PBN”), established a new core

area in Alberta’s Cardium play which helped lead them to a 58% increase in production for

the year. 2010 culminated with us distributing our 65% share in Petrominerales (“PMG”)

proportionately to our shareholders.

24 petroBakken overview

28 petrominerales Historical Summary

30 operations Statistical Review

36 Management’s Discussion and Analysis

60 Management’s Report

62 Consolidated Financial Statements

65 notes to the Consolidated Financial Statements

IBC Corporate Information

2010 Annual Report 1

SummaRy of ReSultS (1)

Q4 2010 2010 2009 2008

Financial

($000s, except where noted)

Oil and natural gas revenue from continuing operations 258,359 1,008,556 575,588 585,800

Funds flow from continuing operations (2) 155,344 636,754 380,016 415,059

Per share – basic ($) 1.46 6.10 4.29 5.05

– diluted ($) 1.46 5.96 3.94 4.56

Net income from continuing operations 1,315 21,308 68,559 137,272

Per share – basic ($) 0.01 0.20 0.77 1.67

– diluted ($) 0.01 0.20 0.73 1.59

Net income (loss) attributable to Petrobank shareholders (3) (35,612) 115,785 145,079 244,482

Per share – basic ($) (0.34) 1.11 1.64 2.97

– diluted ($) (0.34) 1.03 1.52 2.76

Capital expenditures

PetroBakken 262,758 811,871 394,023 545,833

Heavy Oil Business Unit (“HBU”) 37,521 121,492 76,019 82,332

Total capital expenditures from continuing operations 300,279 933,363 470,042 628,165

Total assets 6,402,586 6,402,586 5,766,568 2,361,707

Common shares outstanding, end of period (000s)

Basic 106,236 106,236 93,617 83,525

Diluted (4) 110,046 110,046 108,596 99,043

Operations

PetroBakken operating netback ($/boe) (2) (5)

Oil and NGL revenue ($/bbl) (6) 75.19 72.77 64.27 92.80

Natural gas revenue ($/Mcf) (6) 3.96 4.22 4.40 8.06

Oil and natural gas revenue (6) 67.00 65.28 58.97 86.78

Royalties 9.84 9.34 8.55 10.03

Production expenses 8.97 8.18 7.38 8.76

Operating netback (2) (5) (7) 48.19 47.76 43.04 67.99

Average daily production

PetroBakken – oil and NGL (bbls) 34,754 35,109 22,648 15,369

PetroBakken – natural gas (Mcf) 39,474 39,473 22,110 14,436

Total conventional (boe) (5) (8) 41,333 41,688 26,333 17,775

(1) petrominerales ltd. (“petrominerales”) has been presented as discontinued operations for the years ended December 31, 2010 and 2009 as this business unit was spun off to petrobank shareholders at December 31, 2010. please see “net Income from Discontinued operations” section within Management’s Discussion and Analysis (“MD&A”) for presentation and discussion of petrominerales’ results.

(2) non-GAAp measure. See “non-GAAp Measures” section within the MD&A.

(3) Includes the operating results of petrominerales until the business unit was spun-off on December 31, 2010, and a $70.1 million accumulated other comprehensive loss resulting from the historic translations of petrominerales’ u.S. dollar amounts recorded in net income upon the spin-off of petrominerales.

(4) Consists of common shares, stock options, directors deferred common shares, deferred common shares, and incentive shares as at the period end date.

(5) Six Mcf of natural gas is equivalent to one barrel of oil equivalent (“boe”). net of transportation expenses and excludes revenue from purchased oil.

(6) net of transportation expenses.

(7) excludes hedging activities.

(8) HBu bitumen and heavy oil volumes are excluded from average daily production as Conklin and Kerrobert operations are considered to be in the pre-operating stage and accordingly are capitalized.

– diluted ($)

Net income from continuing operations

Per share – basic ($)

– diluted ($)

Net income (loss) attributable to Petrobank shareholders

for real long-term growth

The key to a successful energy company begins

with acquiring a strong asset base and employing

talented and motivated staff to develop and

produce those assets.

This cycle of acquiring strong assets and recruiting and retaining talented staff is continuously repeated. At

Petrobank, we have been building and evolving our asset base for more than a decade. During this time we

have accumulated more than 95,000 acres of heavy oil and oil sands leases in western Canada. This is in

addition to the 1.65 million net acres of conventional light oil and natural gas assets in Canada through our

59% owned publicly traded subsidiary, PetroBakken, and the 11.5 million acres of exploration land we have

been able to acquire in South America through Petrominerales. This accumulation of strong assets is a result

of management’s long term strategy of taking the lead in securing the drilling rights to strategic resources to

which we can apply leading edge technologies that have long term value creation potential.

Petrobank began rebuilding our conventional oil business in 2001 with the acquisition of Barrington Petroleum.

We continued to aggressively expand those assets over the next decade, and started to concentrate on the Bakken

formation in south eastern Saskatchewan, ultimately becoming one of the top producers from that resource. In

October 2009, we contributed our conventional light oil and natural gas assets to a new entity, PetroBakken,

and subsequently merged it with TriStar Oil and Gas Ltd. (“TriStar”). Since that time, PetroBakken has further

increased their overall land holdings, and diversified from being a Bakken-focused producer to having extensive

resource assets in Alberta’s Cardium light oil play and British Columbia’s Montney and Horn River gas plays.

South American operations commenced in 2002 with the purchase of assets in Colombia. This acquisition

laid the foundation for our Latin American Business Unit, which evolved to become Petrominerales,

previously a subsidiary company of Petrobank. Since 2002, Petrominerales has continued to aggressively

expand their asset base in South America, focusing on opportunities in Colombia and Peru. Petrominerales

has been a tremendous success and has drilled some of the most prolific on-shore conventional wells in the

western hemisphere in recent years. On December 31, 2010, we distributed our ownership in Petrominerales

to Petrobank shareholders and Petrominerales now operates independently as one of the most successful

Canadian energy corporations operating in Colombia.

Petrobank’s Heavy Oil Business Unit assets are located in the southern Athabasca Oil Sands, the Peace

River Oil Sands and Saskatchewan’s heavy oil belt. Development of these assets began in 2006 with

the construction and commissioning of the three well Conklin pilot project. Developed as the world’s

petrobank energy and Resources ltd.2

first THAI®/CAPRI® demonstration site, Conklin is still used for the ongoing

development of our THAI® production technology and other enhancements. By

applying what we have learned while developing and operating the Conklin site, we

have made improvements to our design and operating procedures. A second pilot

facility was constructed in 2009 near Kerrobert, Saskatchewan and that property is

now being expanded into a 7,200 barrels of oil per day (“bopd”) commercial project.

After Kerrobert, our next focus will be on our Dawson property in north western

Alberta as we begin development of a two-well pilot. The size and quality of that

reservoir is such that we are applying to regulators later in 2011 to expand to an initial

10,000 bopd commercial facility with an expectation that we could begin construction

during 2013. This project has the potential to rapidly scale up to 20,000 bopd.

Our largest resource base is at our May River project, which will be located roughly two kilometres west of the

Conklin facility. We expect to receive final regulatory approval for this project during 2011, after which we

will begin construction of the Phase I development, a potential 10,000 bopd project. The resources contained

within the May River area may ultimately support production of 100,000 bopd following the construction of

future phases.

KerrobertPetrobank’s Kerrobert project originated as a 50/50 joint venture to develop more than four sections of land

(2,600 acres) on a significant conventional heavy oil pool near Kerrobert, Saskatchewan. With an approval

process of just 56 working days and a construction period of less than four months, our initial two well

project has demonstrated just how quickly and efficiently THAI® operations can be implemented in the field.

The original facility consisted of two THAI® well-pairs, tankage and a small central processing facility.

Over the past year, we have continued to make operational adjustments at Kerrobert to improve on-stream

time and increase production. By the end of 2010, production at the initial two wells at Kerrobert was at levels

that was considered commercially economic by our independent reserve evaluators. The assignment of formal

THAI® reserves in 2010 was an important milestone for Petrobank and the THAI® technology.


Petrobank properties

Alberta oil sands resource 1.7 Trillion bbls

Saskatchewan heavy oil 20 Billion bbls

Saskatchewan medium oil 3.6 Billion bbls

Saskatchewan Bakken light oil 5 Billion bbls

Petrobank lands

Waseca channel

Horizontal oil well

Channel edge

Existing THAI™ oil well

Planned THAI™ oil well

Kerrobert facility


Approval for the expansion of our Kerrobert facility was received on August 6, 2010. In October, we

consolidated our stake in the project by acquiring our joint venture partner’s 50% interest. This acquisition

allowed us to move ahead with full commercialization at our own pace.

Drilling and facilities construction activity levels at the Kerrobert 10 well-pair expansion have progressed

rapidly since the project got underway during the third quarter of 2010. We commenced the pipeline

infrastructure construction in late September 2010 and shortly thereafter we began construction of the

central processing facility. The drilling of the horizontal wells has met or exceeded our design parameters

with respect to trajectory and relationship to the air injection wells. These wells are larger in diameter, have a

higher open flow area to the reservoir, a tighter mesh in the FacsRite™ screen for improved solids control and

an improved wellhead configuration, all of which are expected to result in improved production performance.

The pre-ignition heating cycle (“PIHC”) in three injector wells was initiated on the first pad on March 6, 2011

which is expected to last 20 to 60 days. We anticipate air injection and production on these first expansion

well pairs to commence in the second quarter of 2011 with sustained target production in each well being

reached approximately one year after first air injection. The PIHC on the second pad of five injector wells is

planned for late in the second quarter of 2011. All of the new wells should be on air injection and producing

THAI® oil by the end of July.

May River/ConklinFrom its beginning as an experimental field project in 2006, the Conklin pilot project has been an

important site for the development and testing of our heavy oil technology enhancements. The site of the

world’s first THAI®/CAPRI® pilot, Conklin is also a ready-made test site for several other technologies,

including injecting enriched oxygen, multi-THAI®, direct oxidization of H2S, CO2 co-injection and partial

surface upgrading.

With a 100% working interest in over 46,000 acres of oil sands leases in northern Alberta, Petrobank could

start construction on the first phase of our May River facility as early as this year, subject to regulatory

approval. The initial May River facility will be located roughly two kilometres from the existing Conklin pilot.

We have already received contingent project approval from Alberta Environment and we are now awaiting final

approval for the project from the Energy Resources Conservation Board, which we expect to receive in 2011.

The May River facility will be built in modules so that it can be readily scaled up to as much as 100,000 bopd.

Phase I will have a design capacity of 10,000 bopd from 18 THAI® well-pairs, each producing partially

upgraded bitumen. The advanced small-footprint, modular design elements used in this facility will

“the initial May River facility

will be located roughly two

kilometres from the existing

Conklin pilot. We have

already received contingent

project approval from

Alberta environment.”

Nexen/Opti Nexen/Opti

Stone Petroleum

Stone Petroleum

CenovusChristina Lake

Devon

BP

Devon Jackfish

KNOC

Leismer

MEG

Enermark

Broker

Broker

Broker

SouthernPacific

Glover

MEG

Cenovus

Meg Christina Lake

Conklin

AthabascaPipeline

WaupisooPipeline

Statoilhydro

A B

Petrobank lands

A May River Phase 1

B Conklin Pilot

Pipelines

Highway 881

Other in-situ projects

Town of Conklin

A

B

ALBERTABRITISH

COLUMBIA

BRITISHCOLUMBIA

SASKATCHEWAN

ALBERTA

ALBERTA

SASKATCHEWAN

SASKATCHEWAN

MANITOBA

SASKATCHEWAN MANITOBA

MANITOBA


incorporate our “Design One, Build Many” engineering philosophy. This will facilitate the rolling

development of additional stages at May River, and also provides a blueprint for future facilities in

Canada and worldwide.

DawsonPetrobank’s Dawson project is located in the Peace River area near the existing Seal Lake project.

The property is situated on a large Bluesky formation heavy oil/oil sands fairway and contains an

estimated resource potential of up to 45 million barrels of exploitable oil-in-place in the upper

portions of the main producing zone.

Petrobank consolidated our Dawson land holdings in October, 2010 by acquiring the 50% working

interest from our joint venture partner in the project. This will enable us to develop the project at our

own pace. Final regulatory approval for our Dawson project was received in late November, 2010.

With drilling and construction scheduled to begin during the second quarter of 2011, we expect to

see first oil production from the project in the fourth quarter of 2011.

This project has very similar characteristics to, and will be developed in very much the same way as,

our Kerrobert project. In fact, the surface facility used for the first two well-pairs at Kerrobert will be

re-used on the Dawson pilot. The Dawson pilot project will initially consist of two THAI® well-pairs,

with the potential to increase the size of the project to an estimated 20,000 bopd on existing land.

Petrobank has initiated the environmental evaluation and project design for the follow-up Dawson

expansion project. We expect to submit an application to regulators in the third quarter of 2011.

CRaig BudRiSOperations ManagerPetrobank is constantly developing new technologies for extracting heavy oil and bitumen. The organization embraces new ideas and provides us with the freedom to test new technologies and adopt them once they are proven to be successful. Other companies that I have worked for in the past have been hesitant to similarly test out new technologies and ideas.

Working with such an enthusiastic team makes it exciting for me to come to work every day. My crews are continually learning something new with our processes and how to excel within their teams. Our experienced people are eager to share their knowledge with those new to the industry while our newer operators pass their enthusiasm and comfort with new technology onto the more seasoned operators.

Every employee brings a solid safety and environmental responsibility to their work. Our safety record is outstanding and improves continually, due to our safety programs, and the ownership of the programs by our management and every employee.

There is a very strong group of dedicated people in Petrobank’s corporate office who regularly bring new ideas, concepts, and solutions to the table. There is never a dull day in this organization.

Petrobank

Channel Edge

Baytex

Penn West

Petrobank lands

Channel edge

Existing horizontal oil well

Planned THAI™ oil well

Channel edge

ALBERTABRITISH

COLUMBIA

BRITISHCOLUMBIA

SASKATCHEWAN

ALBERTA

ALBERTA

SASKATCHEWAN

SASKATCHEWAN

MANITOBA


MANITOBA

to deliver real production


Overview

Assets form only part of the picture; it is how we develop those assets that

defines what we are today and our potential for the future.

Canada’s oil sands resources are estimated to contain as much as 1.7 trillion barrels of petroleum initially-

in-place and 170 billion barrels of reserves recoverable using current technologies, while Saskatchewan’s

conventional heavy oil resource base is estimated to contain some 20 billion barrels of remaining resources.

While these regions have been producing for many years, Petrobank believes that conventional cold

production and in-situ thermal production techniques, such as steam assisted gravity drainage (“SAGD”) and

cyclical steam stimulation (“CSS”), do not efficiently maximize the exploitation of the reservoir, so we set out

to refine and apply a superior technology for in-situ bitumen and heavy oil production.

Petrobank acquired the rights to the Toe-to-Heel-Air-Injection (“THAI®”) technology in 2003 and started

to test and commercialize the technology. At the beginning of 2004, Petrobank was granted approval

for a three well THAI® pilot project near Conklin, Alberta that ultimately became the first field scale

application to assess the technology for its in-situ bitumen production potential. Construction of the site

began shortly thereafter, and oil was produced at the project in Q3 2006. Petrobank then initiated a second

pilot project at Kerrobert, Saskatchewan in 2009, this time targeting in-situ heavy oil production.






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John VinetteOperations SupervisorAs Operations Supervisor within the Heavy Oil Business Unit, I help to coordinate and supervise the day to day activities within our operations group. I am next slated to head to the Dawson project near Peace River.

As Petrobank has grown and expanded, it has maintained its small company atmosphere which I believe has made for a more gratifying workplace. Our THAI® technology is interesting and exciting to develop, and I work with a group of people that are all passionate about achieving the same goal.

Having the chance to get in on the THAI® technology at the ground level and watching and helping it grow into a commercially viable technology has been exciting. As the technology and the Company develop, I look forward to new challenges and projects.

“ our Kerrobert project started producing slightly

upgraded heavy oil in January, 2010. production from

this project continued to improve throughout 2010.”

In conjunction with Petrobank’s 2009 reserves assessment, our independent reserves evaluator,

McDaniel and Associates Consultants Ltd. (“McDaniel”), completed the first comprehensive technical

assessment of THAI® at our May River/Conklin leases. This evaluation compared THAI® technology

with SAGD by examining all of the operational and hard data recorded for the project since its

inception. The data was used to establish the effectiveness and reliability of THAI® as an economic

recovery process. As part of this evaluation, McDaniel concluded that the total exploitable bitumen-in-

place for THAI® is 17% greater than the SAGD exploitable bitumen at our May River/Conklin leases.

With the improvements that we have made to THAI® operating procedures in 2010, McDaniel has

revised the total exploitable bitumen-in-place for THAI® to be approximately 1.7 billion barrels, or

20% higher than if SAGD were used in this bitumen reservoir.

In 2009, McDaniel stated that THAI® works and that if Petrobank could show sustained THAI®

economic production levels, then McDaniel would be able to assign THAI® based reserves and resource

estimates. Our efforts during 2010 were directed at achieving and maintaining economic production

rates at our two pilot projects.

Our Kerrobert project began producing upgraded heavy oil in January, 2010. Production from this

project continued to improve throughout 2010; we made significant changes to the operations of the

project, such as the adoption of permanent pumps and their optimization, which have resulted in

sustained economic production rates. Thanks to our operational success at Kerrobert, McDaniel was

able to assign proved and proved plus probable (“2P”) reserves of 3.0 million barrels and 4.8 million

barrels, and proved plus probable plus possible (“3P”) reserves of 8.5 million barrels. These initial

reserves assignments represent 16%, 26%, and 46% recovery factors, respectively. Reserve recognition


“ traditional heavy oil production at Dawson has seen

typical recovery rates of only ten percent. petrobank

expects that with tHAI® those recovery rates could be

many times higher.”

Cindy BoeRdyK, Plant Operator – Conklin Pilot PlantMy duties are to monitor equipment and processes, supervise contractors, communicate with the control room and leads about any issues and to lock out vessels and equipment for maintenance. I am also a volunteer, with Petrobank’s support, with the Conklin Fire Department for medical and fire calls. I love that I am able to leave work to help out in the local community when I am needed.

The biggest difference from what I have seen between Petrobank and other places that I have worked is how close our groups are, and how well we work together. Another big difference is that our leadership throughout the Company is very personable on all levels – the President of the Company will stop you in the hall here at the plant, know your name and ask you how your Christmas was.

for THAI® is a crucial first step in recognizing its economic potential and provides a third party validation of

the process. We believe that as we continue to advance our projects the ultimate economic value and superior

environmental benefits of THAI® will be fully recognized.

Another key attribute of THAI® that McDaniel validated was the value of in-situ upgrading. Based on

the consistent in-situ upgrading achieved at both Conklin and Kerrobert of between 4 – 7 degrees API,

McDaniel estimated that THAI® oil at Kerrobert would receive approximately 10% higher field prices than

native quality produced oil. This attribute is only one of the demonstrated economic benefits of THAI® when

compared to other production methods.

With increased reserves value, improving production, and expansion of the Kerrobert pilot to a full

commercial project, we are now ready to work on other heavy oil and oil sands projects. Our next application

of THAI® will be at our Dawson property. Having received final approval from the Alberta government to

initiate the Dawson pilot project, construction is scheduled to begin in the second quarter of 2011 with first

production expected as early as the fourth quarter of 2011. Traditional heavy oil production at Dawson has

typically seen recovery rates of only 10%. Petrobank expects that with THAI® those recovery rates could be

many times higher.

leads about any issues and to lock out vessels and equipment for maintenance. I am also a volunteer, with Petrobank’s support, with the Conklin Fire Department for medical and fire calls. I love that I am able to leave work to help out in the local community when I am needed.

The biggest difference from what I have seen between Petrobank and other places that I have worked is how close our groups are, and how well we work together. Another big difference is that our leadership throughout the Company is very personable on all levels – the President of the Company will stop you in the hall here at the plant, know your name and ask you how your Christmas was.


By the time Dawson is on production, we expect to have received final approval to begin construction on

Phase I of our May River project. Located on our oil sands leases roughly two kilometres west of our Conklin

pilot project, May River will be Petrobank’s first large scale, THAI® operation in a bitumen reservoir. Initial

engineering and design for Phase I of the May River project has concluded, and we have completed most of

the regulatory approval process. Built in phases, May River will initially have the capacity to handle bitumen

production of up to 10,000 bopd. The project’s modular design will easily allow us to expand it to an ultimate

planned capacity of 100,000 bopd.

Petrobank expects to drill 18 horizontal production wells from four well pads and the project has been

designed with a “hub and spoke” configuration with a single central processing facility and production

pads located across our leases. Using the knowledge and experience gained from operating our Conklin and

Kerrobert projects, we are pioneering THAI® to be a step-change approach to environmental sustainability in

heavy oil and oil sands development.

Our next projects are designed to minimize adverse impacts on air quality, water resources and land use.

May River will use produced low BTU (British thermal unit) gas to generate enough power to be self-

sufficient, and flue gas desulphurization will reduce sulphur dioxide emissions to negligible levels. Due to

the THAI® combustion process, the project is a net useable water producer over its life. During the first

months of a project, we do inject small amounts of steam to condition the reservoir prior to introducing air,

but the total volume of steam used is negligible compared to steam based recovery processes. Greenhouse

gas emissions will also be greatly reduced compared to traditional in-situ thermal production technologies

which burn natural gas at surface to generate steam.

By the end of 2012, Petrobank expects to have Kerrobert at full production of 7,200 bopd, the initial two well-

pair Dawson pilot project producing 1,000 bopd, May River construction well underway and a 10,000 bopd

Dawson expansion proceeding through the regulatory approval process. Including May River, our identified

projects have the potential to be producing almost 30,000 bopd within two years. Our current resource base

could ultimately support and sustain production of over 125,000 bopd.

Typical cross section of a THAI® well showing the estimated reservoir contact as compared with SAGD.

creating real success


Long term vision and innovation have been critical contributors to corporate

success at Petrobank. Early in the last decade we were presented with an

opportunity to acquire the rights to a new heavy oil production technology that

had the potential to recover more resources and produce higher quality oil,

and had superior economics with more environmentally responsible outcomes

than other options.

Having carefully reviewed the existing heavy oil and oil sands extraction methods, Petrobank committed

to the commercial development of the THAI® process by acquiring the patent and agreeing to construct

and operate a full-scale pilot project. Since that time, we have improved the technology, patented

additional enhancements around the world and initiated a commercial THAI® development at our

Kerrobert, Saskatchewan property. Our patented THAI® technology is a potential step-change advance

in the world of heavy oil and bitumen production. Compared to the current in-situ thermal production

methods, such as CSS or SAGD, THAI® is applicable to a wider range of reservoir conditions, is more

capital and operating cost efficient and more environmentally friendly. THAI® also has the added benefit

of producing upgraded oil and having a higher estimated ultimate recovery rate than either CSS or SAGD.

THAI® is an application of in-situ combustion that utilizes modern horizontal drilling technology to

produce heavy oil or bitumen. The process involves drilling well-pairs: one horizontal producer and one

vertical injector at the toe of the producer. The reservoir is pre-heated with steam until communication has

been established between the vertical air injection well and the horizontal production well. This also serves to

warm the reservoir to a desired temperature and condition the reservoir for combustion. Air is injected into

the formation to initiate the spontaneous combustion reaction and is then continuously injected, allowing

the combustion front to build and advance in the reservoir around and through the formation towards the

heel of the producer. The lighter oil fractions are pushed forward and down by gravity and the combustion

gas flows concurrently into the production well, moderating the pressure difference between the well and the

surface. The heavier oil fractions are deposited as coke on the reservoir rock, and ultimately combusted as

fuel. The coke is a byproduct of the upgrading of the oil, as the heavier fraction of the oil is “cracked” by the

high temperature of the process, which operates at 400 to 600 degrees Celsius in the reservoir.

BenefitsFrom the beginning, the THAI® technology was intended to be as simple and efficient as technically

possible. The thoughtful engineering and design that have been put into the technology has resulted

in a relatively small surface footprint that can be built using ‘off-the-shelf ’ equipment and facilities.


Native bitumen 8° API Viscosity 550,000 centipoise

In-situ upgraded THAI® oil 12° API Viscosity 1,225 centipoise

aRChon Innovation is a large part of what we do every day at Petrobank. We are constantly working to revise existing technologies in an effort to create newer, better methods of producing oil. An essential part of our pioneering philosophy is found within our wholly owned subsidiary company, Archon Technologies Ltd. (“Archon”). Archon is at the forefront of our development of innovative production technologies and works to extend and protect the intellectual property of our core THAI® and CAPRI® patents. Archon’s research team works continuously to push the envelope of what is possible, and help Petrobank to improve performance in the field.

It is through calculated risk taking that our technologies have moved from the lab to the field and resulted in the development of THAI® and companion technologies, such as CAPRI®. Other advancements that we are working on include developing additional power generation options for low BTU produced gas, integrating technologies to minimize greenhouse gas emissions and exploring usage options for produced water.

Archon is also leading our global patent and technology rights strategy. We continually file new patents for our developed technologies and we are always seeking opportunities to reinforce and promote Petrobank’s intellectual property portfolio in Canada and throughout the world through the Patent Cooperation Treaty. We now have a total of eight patents issued and pending in 36 countries.

Archon’s strategy is to license and earn royalty income from our intellectual property. Archon looks for opportunities in Canada and around the world to license THAI® and related technologies to earn a steady stream of royalty income. With significant heavy oil and bitumen resources around the world, and a patented, superior thermal production technology, Archon continues to attract significant interest from third parties for the THAI® technology.

This makes the facility not only quicker and less costly to build, but the site is also easier

to maintain and reclaim when operations wind down. Although a minor amount of

steam is used during the pre-ignition heating cycle, it is not required once air injection

commences. There is no need to burn natural gas or to consume and recycle water,

common characteristics of CSS and SAGD. By eliminating water handling facilities

and the associated costs of burning natural gas, THAI® projects require smaller capital

investment and have lower operating costs than steam based projects.

THAI® also has a recovery factor that has been shown by computer simulation and

physical modeling to be as high as 80% of oil in place, comparing favourably to the 10%

or less for conventional heavy oil production and to the estimated 10% to 50% recovery

for other thermal in-situ production methods. The THAI® process can also produce oil

from reservoirs that are unsuited for other thermal methods, including thinner reservoirs

and areas that have a high incident of heterogeneity such as thin shale laminations,

lean zones, and higher water saturation. This is due to well configuration and the high

temperatures involved in the THAI® process. Unlike other processes, THAI® can be used

as a primary, secondary or even tertiary recovery method. Even when producing otherwise

uneconomic resources or injecting new life into reservoirs already developed using

different methods, THAI® can still recover more oil. The THAI® process also consistently

produces upgraded oil. This in-situ upgrading of the oil means that less diluent is required

to achieve pipeline specifications and that less refining is necessary at the surface to turn

the oil into finished products. This translates into a higher valued barrel at the wellhead.

The combustion gases that are produced in larger THAI® projects have a high enough

residual energy value to be able to be used to generate power to make our projects energy

self-sufficient. These realities translate into material economic benefits.

The economic benefits are considerable, but they are not the only advantages. THAI® also

has many environmental benefits when compared with traditional thermal production

technologies. SAGD is a net water user; however, the water produced during the THAI®

process is actually clean enough for industrial use or immediate reinjection. In short,

THAI® does not consume water, but actually produces it from an otherwise unsuitable

source. The in-situ upgrading also translates into lower life-cycle CO2 emissions due to

less surface upgrading being required. Clearly, THAI®’s many economic benefits are also

aligned with its substantial environmental benefits.


New technologies, such as THAI®,

are the key to unlocking this vast resource.

Canada’s oil sands are thought to be the world’s largest single deposit of oil and contain the third

largest reserves in the world, trailing only Saudi Arabia and Venezuela. Lying under more than

140,000 square kilometres of land in the Athabasca, Cold Lake and Peace River regions, Alberta and

Saskatchewan’s immense oil sands deposits contain an estimated 1.7 trillion barrels of crude bitumen

and 170 billion barrels of potential reserves, using today’s production technology.

Canada’s vast oil sands resources, as large as they are, still equate to less than 20% of the estimated

nine trillion barrels (initial volume-in-place) of heavy oil and bitumen resources worldwide. We

believe Petrobank’s leading edge THAI® technology is a key to helping economically unlock that

resource efficiently and effectively.

We have now tested THAI® in both oil sands and mobile heavy oil reservoirs in Alberta and

Saskatchewan. Our business strategy is to first create value from our own oil resources, to joint

venture with other resource owners, and to ultimately use Archon to leverage THAI® by licensing

it to third parties for royalties. Our goal is to make THAI® the benchmark for heavy oil and in-situ

bitumen recovery globally. This multi-prong strategy is intended to provide exciting opportunities

for growth and create significant long-term value for our shareholders.

“ the massive volume of heavy oil and

bitumen resources globally represents

enormous potential for tHAI® expansion

and development throughout the world.“

Heavy Oil + Natural Bitumen in Place

• For the foreseeable future, the world

will rely on hydrocarbons, especially

oil, to meet its energy demand. We

are rapidly depleting reserves of easy

to produce, light, sweet crude – it

is estimated that 1 trillion barrels

remain (USGS)

• Heavy oil and bitumen, however, is an

abundant resource for the future –

estimated at 9 trillion barrels (USGS)

9 trillion barrels Light/Medium

Oil in Place

1trillion barrels

the size of the prize

gReg deuChaRProject Manager – May RiverAs the manager for Petrobank’s May River THAI® project, I am responsible for its execution from planning through to production. This includes project design, procurement of equipment and materials and facility construction.

As an organization, Petrobank is smaller than other companies I have worked for, but we already have the technology and resource base in place to support aggressive future growth. Our May River resource is very well suited to THAI® exploitation, and will provide an excellent base upon which we will continue to build the company and prove up our proprietary THAI® technology.

My job at Petrobank keeps me engaged because we are developing a process which will enable sustainable development of the vast heavy oil and bitumen resources found both here in Canada and worldwide.

Expansion throughout CanadaOf Alberta’s estimated 1.7 trillion barrels of bitumen,

approximately 170 billion barrels are considered

recoverable reserves using current technologies.

Approximately 20% of the oil sands reserves are

accessible through surface mining, while 80% are

too deep to be mined and must be recovered in place,

or in-situ, by drilling wells. Recovery factors for

traditional in-situ recovery methods are estimated to

be approximately 10% to 50%, leaving the majority

of the resource trapped in the ground. Petrobank’s

patented THAI® recovery technology is expected

to have up to an 80% recovery rate, resulting in a

potential step-change in reserves recovery.

Our experience at the Kerrobert project provides

confidence that THAI® is an attractive alternative to conventional drilling and other in-situ thermal

production techniques in many conventional heavy oil accumulations. McDaniel has assigned initial THAI®

proved reserve estimates which exceed conventional recovery rates and we believe that ultimate recovery at

Kerrobert will exceed the initial reserve volumes assigned by McDaniel as at December 31, 2010. Petrobank

intends to capture additional THAI® suitable resources in Canada through acquisitions, exploration and

joint ventures.

THAI® WorldwideThe massive volume of heavy oil and bitumen resources throughout the world represents enormous

potential for THAI® development and expansion globally. Adding to the potential is that THAI® is

applicable to a greater range of resource accumulations than existing heavy oil technologies. While

Canada has an infrastructure system which includes heavy oil and diluent pipelines, roads, abundant

natural gas, fresh water sources and access to refining that can profitably upgrade heavy oil, most other

parts of the world are significantly less developed. In these areas, THAI® has a competitive advantage

since the process needs few external resources (no gas, no water and potentially no diluent) and can be

operated in a self contained and self sustaining manner. These attributes make THAI® a very attractive

and viable production technology for a significant portion of the global heavy oil resources.

An example of where THAI® could be deployed internationally is in Colombia, South America.

Colombia’s stable government and progressive royalty regime actively encourages technological

innovation to develop its vast, under-explored resources. Petrominerales Ltd., Petrobank’s former

subsidiary company, has over 800,000 acres of exploration land in Colombia’s emerging Llanos Basin

heavy oil fairway. We have a THAI® licensing agreement with Petrominerales to allow them to use the

THAI® technology to develop these potential resources.

Many multi-national and state-owned energy companies have approached Petrobank to learn more about

the THAI® technology for their own heavy oil and oil sands resources around the world. We have had

ongoing licensing negotiations with a number of larger state oil companies, as well as other international

oil companies. Our objective in these licensing agreements is to receive a satisfactory return on our

investment through royalty payments and/or licensing fees and protect our technology. The license

agreements should also provide Petrobank the opportunity to participate in projects and gain access to

resources that would not be otherwise available to us. Participation could take the form of joint ventures

or direct ownership of projects and resources where possible within a country’s resource policy framework.



focused on long term value creation

Our core strength remains our people.

The energy business has many challenges and rewards; it is both dynamic and stimulating. Technology

evolves, the regulatory environment changes and commodity and input prices can swing wildly. The one

constant, however, is the people. The energy industry attracts some of the world’s most talented, hard

working individuals and it has been my privilege to work in this industry alongside some truly extraordinary

and gifted people for the past 30 years.

Talent and dedication are key, but shared values and vision are the common threads that make Petrobank’s team

one of a kind. Petrobank has always had a unique vision. There have been many evolutions of our vision - from

the commencement of operations in 1994; implementation of a new business plan and operating team in 2000;

the formalization of a shareholder value maximization plan in 2004; the IPO of Petrominerales in 2006; the

creation of PetroBakken in 2009 and the distribution of our Petrominerales holdings to our shareholders in 2010

– throughout, our team and Board have worked together to create unique routes to maximum shareholder value.

Our vision doesn’t always follow a straight trajectory or deliver instantaneous results that constantly satisfy

the short-term demands of the markets. We try to focus on learning from our mistakes, re-assessing the

optimal route and innovating to enhance and improve our long-term results. Sometimes we experience short-

term setbacks or fall out of favour with the market expectations for our industry, but we always try to keep

our vision clearly focused on our long term goals for value creation.

John D. Wright, president and Chief executive officer and Director


2010 was a challenging year. Following a decade in which Petrobank was a top performing oil and gas

stock on the Toronto Stock Exchange, we have recently found ourselves in the unusual position of under-

performing many of our industry peers. This has not been a comfortable situation for me or any of the

Petrobank and PetroBakken staff, management or directors. All of our businesses have been created with

a clear vision and direction as to how we can achieve long term, sustainable value. Even in times of under-

performance in the capital markets, our vision has not changed and we continue to make significant progress

towards achieving our goals. In 2011, my efforts will be largely focusing on ensuring that we return to our

more familiar position as a market leader.

Not all members of the Petrobank group of Companies had a challenging 2010. In fact, Petrominerales has

delivered, and continues to deliver, outstanding shareholder growth, and in 2010 they initiated a dividend

to return a portion of this success to their shareholders. Petrominerales exited 2010 with a 66% increase in

production, having drilled some of the most prolific wells in the western hemisphere this decade. They grew

reserves by 22% and maintained industry-leading netbacks while increasing the size of their opportunity

inventory for future growth. As Petrominerales grew, we were also able to recognize the contributions of

their team through promotions and succession opportunities. Finally, as an overt part of our ongoing plan

to maximize Petrobank shareholder value, we distributed our ownership in Petrominerales to all Petrobank

shareholders, and I hope we all continue to profit from their success for years to come. I can assure you that

the Petrominerales executive, led by CEO Corey Ruttan, have a true and unique vision for future growth and

I further believe that, under his leadership, the best is yet to come for Petrominerales.

PetroBakken experienced significant success during 2010 in its own right as well. Production increased by

58% this year to average 41,688 barrels of oil equivalent per day. Reserves increased by 18% to 171.4 million

barrels, replacing 2010 production by 274%. The majority of that production was light oil, resulting in

industry leading cash-flow metrics and netbacks. As we have done in the past, we also made an early move

to acquire a dominant position in Alberta’s Cardium light oil play. The subsequent reduction in provincial

“tHAI® is now ready to play a dominant role in

the Company. At the end of 2010, we received

confirmation that we have met our goal of

obtaining tHAI® reserve assignment to an oil pool.“

royalties was timely as it added over $1 million in net present value to

each Cardium well location and precipitated a return of energy industry

investment dollars and jobs to Alberta. In time, I firmly believe our move

will prove to be just as prudent as our early moves into Saskatchewan’s

Bakken formation. PetroBakken’s Cardium results are starting to

crystallize; our Bakken production has matured as a significant cash

generating engine for the Company and we are now enviably positioned

with a terrific drilling inventory and a strong and capable management

team. 2010 may have been a tough year for execution, but I remain

completely convinced in our strategy and the exceptional people who are

implementing it. Exciting days lie ahead.

The Heavy Oil Business Unit remains our proverbial ‘elephant in the room’.

With a huge resource in the Alberta oil sands and exposure to significant

conventional heavy oil resources in Alberta and Saskatchewan, we own

vast amounts of oil resources that can be potentially recovered using our

patented THAI® technology. THAI® is now ready to play a dominant role

in the Company. At the end of 2010, we received confirmation that we

have met our goal of obtaining THAI® reserve assignment to an oil pool.

Although this was our expectation, for me it was remarkable considering

that, to-date, only five THAI® wells had been on production. It was an

accomplishment and a key step, but ultimately just the first of many to

come. We are presently constructing our first commercial production

facility at Kerrobert, Saskatchewan. It has been designed and built for 7,200

barrels of oil per day capacity and the economics are strong, even at half

of that production rate. But this is just the beginning for THAI®. Our

technology holds the promise of unlocking resource in a more economical

and environmentally responsible way, and it has worldwide application.

In 2011, we will focus our efforts on improving production rates and,

through our subsidiary Archon, we will enhance the scope of our THAI®

intellectual property, to more clearly demonstrate to the market the

incredible potential of this game-changing technology.

All of our businesses pursue one common goal: to innovatively find and

produce hydrocarbons pursuant to our Vision and Values. Each business

unit employs technology and expertise in a way that ensures we will

ultimately meet that goal and generate an increasing supply of energy to

a global market that increasingly demands it. It is not an easy business,

but, for our team of visionaries, it is far more personally and professionally

rewarding than anything else we know of.

As always, our Board of Directors provides a firm hand on the tiller of

the Company and we continue to profit from their guidance, wisdom and

experience. This decade has had a promising start for all of us as Petrobank

shareholders, with the receipt of our proportional stake in Petrominerales,

and with our existing business units poised for continued growth. Finally,

we continue to work for all shareholders to develop additional new

business concepts to add to our portfolio, and am confident in the vision

and ability of our people to deliver value today, and for the future.

Respectfully submitted on behalf of the Board of Directors,

John D. Wright

President, Chief Executive Officer and Director

March 29, 2011


“ This is just the beginning for

THAI®. Our technology holds the

promise of unlocking resource

in a more economical and

environmentally responsible way,

and it has worldwide application.”

In 2010, we made real progress in the commercialization of our THAI® technology

and the expansion of our foundation for our heavy oil business.

We believe the global economy will continue to depend on oil to supply much of its energy needs for the

foreseeable future. The pressure to develop large new sources of oil to meet this growing energy demand is

increasing every year and it is only through the development and application of improved technology that we

will be able to meet the challenge. Pioneering the use of leading edge technologies with significant hydrocarbon

resources has been fundamental to Petrobank’s success through the years. In the heavy oil business, this has

been taken a step further by developing and commercializing our own technology that can be applied to oil

sands and heavy oil resources globally. Our business model is the commercialization of THAI® in-house to

maximize its value for our shareholders through the development of our own projects, through joint ventures,

and to license the technology to third parties to generate a considerable revenue stream from royalties. Our

in-house expertise and know-how are also fundamental to the successful implementation of our strategy.

To facilitate this business model we have organized the business into two entities: Whitesands, which is the

operating, exploration and production company holding and developing our resource assets, and Archon,

which houses the patents and intellectual property assets and all of our ongoing research and development

activities. We remain confident that this business model will leverage our resource assets and technology to

generate a significant cash flow stream from production and licensing long into the future.

A milestone achievement for this past year was the formal THAI® reserve recognition from our reserve

auditors, McDaniel. The journey towards reserves recognition began in 2009 with a comprehensive technical

assessment by McDaniel of the THAI® process at our Conklin pilot project. The conclusions from the

assessment were emphatic in that they declared “that the pilot is successfully proving the THAI process”,


Chris J. Bloomer, Senior Vice president and Chief operating officer, Heavy oil and Director

Realizing the potential of thai®


The first step to facilitate our growth is the Kerrobert expansion project,

which began construction during the third quarter of 2010. This 10 well

expansion has a design capacity of 7,200 bopd. The project is located

in Saskatchewan and is in a conventional heavy oil reservoir that had

been previously produced using conventional cold production with less

than a five percent recovery factor. With THAI®, it is estimated that we

could recover an additional 65% of the remaining oil. The Kerrobert

reservoir is also a close analogue to many other heavy oil reservoirs located

throughout the world.

Thanks to an efficient regulatory process in Saskatchewan, our ability to

develop projects on a timely basis has greatly improved. For example, the

regulatory cycle for the Kerrobert expansion was three months compared

to an 18 to 36 month process for similar projects in Alberta. We view

expanding our resource and project base in Saskatchewan as key to

our near term development, augmenting our Alberta projects, as they

ultimately receive approval, as a significant part of our business plan.

To advance this plan we recently acquired a 100% interest in 11 sections

of land along the Kerrobert Mannville channel trend where we see the

potential for other Kerrobert-sized projects.

May River is our first phase commercial development of our oil sands

resource base at Conklin, Alberta with a design capacity of 10,000 bopd.

We have 560 million barrels of best estimate contingent resource of bitumen

on our May River/Conklin leases which could support 100,000 bopd of

ultimate production. The May River Phase I project is in the final steps

of the regulatory process and once approved, the project would have a

24- month construction to on stream time-frame. May River is a modular

design that can be readily expanded and used as a template for other projects

although at that time they stopped short of assigning formal reserves until

we had achieved sustained economic production rates. During 2010 we

were able to meet the production rate target at our Kerrobert project and

earn formal reserves recognition for the project. We now have independent

verification that the THAI® process works technically and economically.

McDaniel also recognized the in-situ upgrading attribute of the THAI®

technology by assigning a value for the THAI® produced oil in the market

place that is approximately 10% higher than conventionally produced heavy

oil in Kerrobert. The reserve evaluation was based upon the comprehensive

results from our activities over the past several years where we have

encountered and overcome many challenges that are part of developing

a new technology of worldwide importance for heavy oil and bitumen

production. We are clear in our intent to continually improve the efficiency

and profitability of the technology, grow the asset base, and build material

cash flow in the near term.

“A milestone achievement for this past year

was the formal THAI® reserve recognition from

our reserve auditors, McDaniel.”


globally. A key element of this project is that it will incorporate power co-

generation by utilizing our produced low BTU gas, another example of how

we are able to employ innovative technology to increase value.

Our Dawson project will see the THAI® technology demonstrated in a third

reservoir type. The Bluesky formation is a bitumen reservoir that can be cold

produced with conventional horizontal wells, but again, using this method,

less than 10% of the oil is recovered. We received our regulatory approval

in November 2010 for a two well project and we intend to be in production

by the end of 2011. The next phase will be a 10,000 bopd project, and we

expect to file the regulatory application by the third quarter of 2011, with an

approval process of approximately 18 months. The resource base at Dawson

has the capacity to ultimately support a 20,000 bopd project. In addition

with the acquisition of our 100% interest in Dawson, we received 27 sections

of land prospective for additional heavy oil resources. These lands will be

evaluated starting in 2011.

The first three THAI® wells and the first THAI®/CAPRI® wells were

drilled at our Conklin pilot project facilitating the fundamental proof

and advancement of these technologies. Our experience at Conklin has

been challenging; however, we have confronted these challenges and

we are striving to continuously improve our operating procedures and

facility designs leading to improvements at our Kerrobert and May River

projects. We view Conklin going forward as a platform to test additional

enhancements and new technologies around THAI®.

Key to our business model is the continual development of our inventory

of intellectual property. We accomplish this through our R&D subsidiary,

Archon. Archon’s mandate is to advance innovation, improve the

technology, and increase our patent portfolio, thereby extending the

lifespan of our proprietary technology and know-how. We have filed

eight patents in 36 countries, focusing on those with significant heavy

oil or bitumen resources. Ownership of all of our intellectual property is

maintained through Archon, which intends to enter into royalty license

agreements with third parties to generate our own high value revenue

stream. We continue to receive considerable interest from a number

of parties around the world and expect to be able to enter into license

agreements on terms that reflect the true value of the technology for

Petrobank shareholders.

It is clear that the development and application of new technologies will

drive the future of the oil business, especially heavy oil, and that Petrobank

has emphatically positioned itself to be a leader in technology innovation as

the vehicle to create growth. In 2010, we made real progress with THAI®

and we are driven to build on this progress to realize its real value.

Chris J. Bloomer

Senior Vice President and Chief Operating Officer,

Heavy Oil and Director

March 29, 2011


Petrobank is committed to supporting the communities in which we operate.

We consult and engage with community leaders and representatives to ensure

alignment on issues, to build a mutual understanding of our impact on the region

and to identify ways we can participate in the enhancement of community well

being. We demonstrate this in many different ways, including investing in local

youth through sponsorship and training, offering direct employment and contracting

opportunities for local service providers, and in support for community initiatives.

Petrobank has contributed to local schools through our commitment to teacher funding in Conklin, the

Youth Apprentice Program in Lac La Biche and several other progressive programs. Our Conklin pilot facility

has been the training ground for students from Duncan’s First Nation who are working towards their Power

Engineering certification. We actively employ local contractors which also enhances opportunities for them to

pursue other contracts in our operating areas.

Petrobank will continue engaging communities throughout the operational lifespan of our projects, from our

initial consultations right through to final land reclamation. We seek to ensure that affected communities

remain informed and are comfortable with our operations and future plans. Where necessary, mitigation is

incorporated into our development plans. Such steps are often designed in collaboration with community

representatives, to ensure that traditional practices can continue to be experienced and enjoyed where

practical. Petrobank is wholeheartedly supportive of the comprehensive environmental regulatory standards

that safeguard the communities in which we operate. These standards are met and often exceeded due to the

outstanding work of Petrobank’s teams in operations, drilling, construction, safety and environment.

to the community

“petrobank will continue

engaging communities

throughout the operational

lifespan of our projects, from

our initial consultations

right through to final land

reclamation. We seek

to ensure that affected

communities remain informed

and are comfortable with our

operations and future plans.”


The Petrobank culture is one of respect, for the land and for our neighbours, while carrying out our primary

business, which is to produce oil. We are proud members of the Canadian energy sector. Our dedication

to innovation introduced the THAI® technology and its environmental benefits to the world. Our pilot

projects have successfully demonstrated the positive environmental advantages to THAI®, which include a

small surface footprint, minimal consumption of water and natural gas, reduced life-cycle greenhouse gas

emissions, and the potential to generate electrical power by utilizing produced low BTU gas.

2010 Community Update:Conklin:

In 2010, oil sands producers operating near the community of Conklin were approached by the local school

principal to support the funding of a teacher at the Conklin Community School. The school was understaffed

due to funding shortfalls in the Northland School Division. Petrobank has contributed to the hiring of a teacher

at the Conklin Community School, and more importantly, we hope that over the long term we can source

skilled local contractors and employees who have benefited from the enhanced local education atmosphere.

Petrobank also supported a local company from Conklin to become a certified security provider. Petrobank has

been working with this local area company since the beginning of the Conklin project and they now employ

enough staff to be able to provide security services throughout the Alberta oil sands development region.

Petrobank, in association with other industry participants, provides support to the Youth Apprentice Program

in Lac La Biche for grades 7 through 12. This program provides the opportunity for hands-on experience to

the students in trades such as electrical, pipefitting, plumbing and carpentry, skills that will remain in great

demand in the region for the foreseeable future.


Peace River:

During our consultation efforts with Duncan’s First Nation near our Dawson project, the community

expressed a desire for some of their community members to receive additional professional training. Working in

conjunction with the local First Nation, two individuals were enrolled in a Power Engineering training program

offered through Northern Lakes College. These students have already successfully completed the first half of

their course and are both on track to complete the program in 2011. Petrobank is providing practical experience

for these students at the Conklin pilot facility and we are impressed and appreciative of their hard work.

Health, Safety and EnvironmentPetrobank is committed to the ongoing development of a health and safety program that takes all reasonable

precautions to prevent injury, workplace illness and damage to the environment.

The health and safety program ensures that all regulatory requirements and industry standards are identified

and implemented in the workplace. Petrobank willingly complies with all applicable Federal, Provincial and

local laws, as well as industry recognized safety practices. We require that all workers, contractors, consultants

and other parties performing work for, or on behalf of, the Company similarly comply. Workplace safety is

a bedrock aspect of our corporate culture and management provides leadership, resources and unwavering

support for implementation of health and safety programs and the promotion of a safe workplace.

“our dedication to

innovation introduced the

tHAI® technology and its

environmental benefits to

the world.”

“ teluS World of Science – Calgary is

excited about our new and important

partnership with the petrobank

Group of Companies. together, we will

promote science education, specifically

related to energy and innovation, to

Calgarians and Southern Albertans of

all ages. this dynamic partnership will

provide members of our community

with the opportunity to learn new

skills and will positively impact the

future workforce.”

teluS WoRld of SCienCe SPonSoRShiP

Petrobank is proud to be part of a multi-year sponsorship of the new TELUS World of Science - Calgary. The centre’s mandate dovetails with our own values of supporting education in the communities in which we operate and fostering technological innovation. Petrobank is looking forward to promoting energy and innovation related science education at the TELUS World of Science in partnership with PetroBakken and Petrominerales.


Petrobank’s commitment to health and safety is driving us to adopt the Certificate

of Recognition (“COR”) program in 2011. COR is a program proven to streamline a

company’s health and safety management system, and reduce workplace health and

safety risks and costs. Petrobank believes that minimizing the social and financial

effects of injuries helps strengthen our business. The program consists of a third-

party audit of our safety management system. Each element of our system will be

scored using the ENFORM Audit Protocol and anyone within the Company may be

randomly selected to participate. It is a worthwhile accomplishment to achieve a COR

and we are very enthusiastic about reaching this goal.

Our project planning integrates health and safety compliance with engineering design

and operational execution. Day-to-day operations proactively demonstrate our safety

ethos through communications with field staff, office staff, contractors, regulators and

the public. At Petrobank, safety communication occurs regularly within all aspects of

our organization.

Petrobank operations also incorporate various environmental monitoring programs.

These programs include shallow groundwater monitoring to monitor water quality;

passive air monitoring to monitor for H2S and total SO2; and soil monitoring to

identify if any of the locations are being impacted by our operations. As Petrobank

grows our production, our monitoring programs will also increase. In preparation,

Petrobank is a contributing member to the Alberta Biodiveristy Monitoring Institute.

Working with the forestry companies and other industries to minimize total

disturbance on the landscape through collaborative planning processes, Petrobank will

continue to implement integrated landscape management principles when developing

our facility and well sites.

Our intent is to provide a healthy and safe work environment for everyone. By working

together and communicating effectively, we will make certain our standards are met

and that we will continue to ensure a safe workplace, environmental compliance, and

wholesome working relationships with the communities where we work.

PetRoBanK ViSion & ValueS n We focus on innovatively creating

long-term shareholder value.

n Petrobank recognizes that our key assets are our employees and we treat them and their families with respect.

n We act as shareholders and always in the best interests of our shareholders.

n We act with honesty and integrity conducting ourselves in an ethically and morally correct fashion in all of our business dealings.

n We communicate openly, honestly and with respect for individuals, communities and cultures.

n We are committed to safety and to minimizing our environmental footprint.

n We view mistakes as opportunities to learn and improve our future performance.

Formed in late 2009 through the combination of Petrobank’s Canadian Business

Unit and the acquisition of TriStar, PetroBakken has emerged as one of the few

large development companies operating in the Western Canadian Sedimentary

Basin with assets and operations primarily focused on light oil.

PetroBakken’s activity is concentrated in three main areas of western Canada through four Business Units.

Southeast Saskatchewan contains our Bakken and Conventional Saskatchewan Business Units and has

traditionally been our largest and most active base of operations. Through the Bakken light oil resource play

and our conventional Mississippian light oil opportunities, these Business Units now generate significant

excess cash flow which we use to fund growth investment in our other plays. Our Cardium Business Unit

in central Alberta is poised to become PetroBakken’s new premier growth opportunity and will receive the

majority of our 2011 drilling budget. Our Cardium light oil resource play is primarily focused around the

Pembina oil field near Drayton Valley, Alberta, but also includes the more exploratory Cardium plays around

Garrington and Lochend. The Cardium play will generate the majority of PetroBakken’s production growth

over the medium term. Our BC/Alberta Business Unit contains our northeast British Columbia natural gas

resource plays in the Horn River and Montney. In addition, this Business Unit is also building exposure to

other potential oil-focused resource plays throughout Alberta.

Our development investments during 2010 were in our Bakken and Cardium light oil resource plays,

where the majority of our 239 net wells were drilled during the year. We allocated minimal drilling and

maintenance capital to our natural gas resource opportunities because of the current low commodity prices

for natural gas. This approach has enabled us to maintain our ability to invest in natural gas when the

economic environment is more lucrative, while remaining focused on our oil opportunities. With over 84%

of our production, reserves, and drilling inventory being light oil, which currently enjoy a much better

economic environment than natural gas, investment in these plays allows us to deliver strong operating

netbacks and significant cash flow growth for future investment.

establishing momentum






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2010 Highlights

Significant Acquisitions• OnFebruary25,2010,PetroBakkenacquiredalltheissuedandoutstandingsharesofBerensEnergy

Ltd. for cash consideration of $252.8 million and the assumption of bank indebtedness of approximately

$74.9 million.

• OnMarch12,2010,PetroBakkenacquiredalltheissuedandoutstandingsharesofRondoPetroleumInc.

for cash consideration of approximately $88.7 million, assumption of bank indebtedness of approximately

$16.0 million and the issuance of approximately 5.5 million PetroBakken common shares.

• OnApril1,2010,PetroBakkenacquiredalloftheissuedandoutstandingsharesofResultEnergyInc.for

cash consideration (net of cash acquired) of $141.2 million and the issuance of approximately 11.2 million

PetroBakken common shares.

Operational Highlights• Ourproductionaveraged41,688boepdduring2010,comparedwith26,333boepdduring2009.Fourth

quarter production averaged 41,333 boepd, up slightly from the 40,095 boepd in third quarter of 2010.

• Nearly85percentofour2010productionishigh-netbacklightoil.

• Weachieveda99percentsuccessrateinthefielddrilling239netwells,themajorityofwhichwereoil

wells located in central Alberta’s Cardium play, or in southeastern Saskatchewan.

2011 Activity Forecast• Capitalbudgetof$800millionwithapproximately75percentofthebudgetdirectedtodrillingand

completions operations in our central Alberta Cardium and southeast Saskatchewan light oil plays.

• Drill207netwells;95netCardiumwells,75netBakkenwellsand30netMississippianwellsinsoutheast

Saskatchewan.

• BalanceofdrillingtargetingnewoilfocusedresourceplaysornaturalgasdrillinginnortheastBritish

Columbia to preserve acreage.

PBN lands

Bakken HZ wells

Bilateral HZ wells

PBN facilities

Bakken development area

Enbridge pipelines

PBN pipelines

Transgas pipeline






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ALBERTABRITISH

COLUMBIA

BRITISHCOLUMBIA

SASKATCHEWAN

ALBERTA

ALBERTA

SASKATCHEWAN

SASKATCHEWAN

MANITOBA


MANITOBA

Bakken Development Area

PBN lands

Bakken HZ wells

Bilateral HZ wells

PBN facilities

Bakken development area

Enbridge pipelines

PBN pipelines

Transgas pipeline

TechnologyEvolution of new technologies is a large part of our drilling and development success at PetroBakken. We have

been recognized as a leader in developing and implementing high-intensity fracture stimulation technologies

that have unlocked production and reserves in the Bakken formation. We continue to be at the forefront

of pioneering and modifying new, cost-effective completion techniques in both our conventional and

unconventional plays. More recently, we have also begun to implement our approach to exploiting technology

to unlock hydrocarbon resources in the Cardium.

Bakken Business UnitPetroBakken is currently the second largest landholder in Saskatchewan’s Bakken play with more than

210,000 net undeveloped acres containing over 900 drilling locations. Our extensive acreage position in the

Bakken fairway, combined with low production expenses and a visionary royalty regime in Saskatchewan,

provides a platform for continued success in this play. During 2010, PetroBakken drilled 140 net wells,

121 of which were bilateral wells, with a 99 percent success rate. Our average Bakken production for 2010

was over 25,000 boepd.


Drilling and completion technology has evolved to the point where PetroBakken is using 1,400 metre-long bilateral horizontal wells to efficiently increase fracture density and greater reservoir contact in the Bakken.

ALBERTABRITISH

COLUMBIA

BRITISHCOLUMBIA

SASKATCHEWAN

ALBERTA

ALBERTA

SASKATCHEWAN

SASKATCHEWAN

MANITOBA


MANITOBA

pembina Cardium light oil Resource play

Cardium CU Legend

PBN Cardium lands

Cardium producing wells

Cardium Business UnitAfter establishing a significant position in central Alberta’s lucrative Cardium play during 2010, we set out to

exploit our Cardium assets through an aggressive drilling program, consisting of a capital budget of $210 million

for 55 net Cardium wells, and bringing 40 net wells onto production. Our ability to innovate quickly led us

to move from oil based fracture stimulations to water based stimulations. The result was lower costs and better

well results. From a standing start, by the end of 2010 we had created a Cardium focused Business Unit that

holds more than 240 net sections of Cardium prospective land with over 650 drilling locations, 43 million

barrels of oil equivalent of proved plus probable reserves and production of 7,300 boepd.

This year PetroBakken expects to spend approximately $345 million to drill and bring on production

approximately 95 net wells in the Cardium, committing significant resources in this area as we build this

light oil resource play into a significant production base for the Company.

Saskatchewan Conventional Business UnitWe hold a large inventory of conventional light oil Mississippian plays in southeast Saskatchewan. By

focusing our development in these areas on the prolific Frobisher, Alida and Tilston formations, we will build

on our current production base and capture significant upside through our extensive drilling inventory in

conventional Mississippian oil pools.

During 2010 PetroBakken drilled 42 net wells targeting Mississippian prospects which contributed to our

average Mississippian production for 2010 of over 7,200 boepd. Our production in this area is currently

limited by facility constraints, which are in the process of being de-bottlenecked and upgraded for water

handling capabilities and pressure restrictions. We expect these upgrades to be completed mid-way through

2011 and they are expected to allow us to increase our production in the area by an additional 1,000 boepd.

As we complete our facility upgrades, we can increase our pace of drilling on these plays, and approximately

$40 million of our 2011 capital budget will be spent further developing Mississippian conventional

opportunities through the drilling of an additional 30 net wells.

BC/Alberta Business UnitThe BC/Alberta Business Unit is responsible for our natural gas opportunities in northeast British Columbia

as well as developing new oil focused resource plays in western Canada.


“ We continue to be at the

forefront of pioneering and

modifying new, cost-effective

completion techniques in

both our conventional and

unconventional plays.”

2002 2003 2004 2005 2006


historical summary

Acquisition of Colombian assets provides foundation for LABU

Petrominerales IPO Colombian production: 2,600 bopd

A Track Record of Growth

We first established our Latin American Business Unit in 2002,

convinced that this underexplored region of the world offered

substantial opportunities. Our LABU started with two incremental

production contracts in Colombia, one at Orito in the Putumayo Basin

and the second at Neiva in the Middle Magdalena Basin. In 2003,

LABU recorded its first oil production that averaged 1,068 bopd for

the year. In 2004, the Colombian government significantly changed

its oil contracting and fiscal regime, creating a unique opportunity

2007 2008 2009 2010 2011


PMG makes initial Corcel discovery

Q4 2008 production: 15,300 bopd

Corcel C-3 well tests at over 9,700 bopd

PMG makes prolific Candelilla discovery. Discovery well produced at over 15,000 bopd.

Petrobank’s 65% stake in PMG is distributed to Petrobank’s shareholders

for oil companies like Petrobank to acquire huge tracts of exploration land. The LABU was spun

out in part from Petrobank in mid 2006 and began trading on the Toronto Stock Exchange as

Petrominerales under the symbol PMG. The funds raised from this IPO were used to acquire an

exciting group of exploration blocks and invest in a balance of exploration and development projects.

Since then, Petrominerales has established a solid foundation of production, an enviable portfolio

of exploration prospects and an asset base exceeding 11 million gross acres of land in Colombia

and Peru. Petrominerales’ average production in 2010 surpassed 37,000 bopd, and Petrobank’s

remaining 65% stake was distributed to our shareholders effective December 31, 2010.

Heavy Oil Business Unit volumes are excluded from average

daily production as operations are considered to be in the

pre-operating stage, and accordingly, revenues net of royalties

and operating costs, are recorded as capitalized costs as

opposed to being recognized in net income.






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TOTAL COMPANYPetrobank’s 2010 production and reserves increases can be attributed to our planned drilling programs and our merger and acquisition activity throughout

2010 and 2009. PetroBakken’s amalgamation with TriStar on October 1, 2009, along with an active drilling program throughout 2010, served to add

significant production when compared to prior year. Petrominerales was the most active exploration company in Colombia in 2010, and has once again

doubled the production when compared year over year.

Our Heavy Oil Business Unit recorded heavy oil reserves from our Kerrobert, Saskatchewan project utilizing our patented THAI® technology; it was the

first such reserves to be recognized from our technology.

As Petrominerales was spun-off to shareholders at December 31, 2010, the following consolidated tables include only results to this date.

average daily production

Oil & NGL (bbl) Natural Gas (Mcf) Total (boe)2010 Average Q4 2010 2010 Average Q4 2010 2010 Average Q4 2010

PetroBakken

Bakken 24,472 22,859 6,711 6,778 25,591 23,989 Conventional (SE SK) 6,842 6,595 2,521 1,854 7,262 6,904 Cardium (central AB) 2,463 4,175 12,761 14,752 4,590 6,634 NE BC / Other AB 1,332 1,125 17,480 16,090 4,245 3,806Total PetroBakken 35,109 34,754 39,473 39,474 41,688 41,333Per basic share (1) 0.20 0.19 0.23 0.22 0.24 0.23Petrominerales

Guatiquia 19,901 14,447 - - 19,901 14,447 Corcel 9,336 9,747 - - 9,336 9,747 Neiva 3,432 3,883 - - 3,432 3,883 Orito 2,825 2,532 - - 2,825 2,532 Casimena 1,027 1,417 - - 1,027 1,417 Others 506 1,116 - - 506 1,116Total Petrominerales 37,027 33,142 - - 37,027 33,142Per basic share (1) 0.24 0.20 - - 0.24 0.20Total Company 72,136 67,896 39,473 39,474 78,715 74,475Per basic share (1) 0.44 0.39 0.23 0.22 0.48 0.43

(1) Includes only petrobank’s ownership share of each of the business unit’s production for the period.






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net present value, before tax, forecast prices (millions) (1)

PetroBakken HBU Total Company($) ($) ($)

Developed producing 2,135 2 1,262Proved 2,845 6 1,685Proved + probable (2P) 4,142 724 3,168Best estimate contingent resources - 3,000 3,000

net present value, after tax, forecast prices (millions) (1)

PetroBakken HBU Total Company($) ($) ($)

Developed producing 1,966 2 1,162Proved 2,446 6 1,449Proved + probable (2P) 3,371 585 2,574Best estimate contingent resources - 2,088 2,088

(1) net present values are discounted at 10% for petroBakken and at 8% for the HBu.

(2) total Company includes only petrobank’s 59% share of petroBakken reserves as at December 31, 2010.

Company interest reserves and resources by business unit, forecast prices (1)

PetroBakken HBU Total Company(Mboe) (Mbbl) (Mboe)

Developed producing 66,183 575 39,623Proved 103,028 3,032 63,819Proved + probable (2P) 171,377 95,409 196,521Best estimate contingent resources - 560,131 560,131Total proved reserves per basic share 0.97 0.03 0.60Proved + probable reserves per basic share 1.61 0.90 1.85

(1) Company interest reserves and resources represent the working interest share including royalty interests in reserves and resources before deduction of royalty obligations.

(2) total Company includes only petrobank’s 59% share of petroBakken reserves as at December 31, 2010.

(2)

(2)

(2)






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land summary (thousands of acres)

In 2010, PetroBakken added to our undeveloped land base in the Cardium formation in Alberta through the acquisition of Result Energy Inc., Rondo

Petroleum Inc, and Berens Energy Ltd., Crown land sales and direct arrangements with mineral rights owners. The Heavy Oil Business Unit also increased

our net holdings by acquiring the remaining 50% interests in our projects at Kerrobert, Saskatchewan and Dawson, Alberta.

Developed Undeveloped Total AverageGross Net Gross Net Gross Net WI%

Saskatchewan 275.4 172.3 742.2 612.1 1,017.6 784.4 77

Alberta 365.5 229.3 557.8 404.4 923.3 633.7 69

British Columbia 68.8 41.6 110.9 85.9 179.7 127.5 71

Manitoba 4.5 2.4 52.1 48.0 56.6 50.4 89

Northwest Territories - - 6.4 2.2 6.4 2.2 34

United States - - 103.6 51.8 103.6 51.8 50

PetroBakken 714.2 445.6 1,573.0 1,204.4 2,287.2 1,650.0 72 Saskatchewan 0.1 0.1 27.5 27.5 27.6 27.6 100

Alberta 0.5 0.5 66.4 66.4 66.9 66.9 100

HBU 0.6 0.6 93.9 93.9 94.5 94.5 100Total Company 714.8 446.2 1,666.9 1,298.3 2,381.7 1,744.5 73

net asset value (millions, except shares outstanding and per share amounts)

Basic Diluted (1)

Petrobank common shares outstanding (000s) 106,236 110,046

Value Per basic

sharePer diluted

share

PetroBakken (2) $ 2,384 $ 22.44 $ 21.66

Heavy Oil Business Unit - proved plus probable reserves (3) 724 6.82 6.58

Heavy Oil Business Unit - best estimate contingent reserves (3) 3,000 28.24 27.26

Working capital surplus (4) 2 0.02 0.02

Stock options, deferred common shares, directors deferred common shares and incentive shares (5) 56 - 0.51

Total net asset value $ 6,166 $ 57.52 $ 56.03

(1) Includes 3.8 million stock options, deferred common shares, directors deferred common shares and incentive shares.

(2) Calculated using closing market price on December 31, 2010 of $21.71 per petroBakken share multiplied by petrobank’s ownership of 109.8 million petroBakken shares.

(3) proved plus probable reserves plus best estimate contingent resources using forecast prices discounted at 8% (before tax).

(4) Includes Corporate and the Heavy oil Business unit.

(5) Assumes 3.8 million stock options, deferred common shares, directors deferred common shares and incentive shares are exercised.


PetroBakken

2010 drilling program

Exploration Development TotalGross Net Gross Net Gross Net

PetroBakken

Oil wells 7.0 6.5 311.0 226.1 318.0 232.6

Natural gas wells 1.0 1.0 3.0 2.7 4.0 3.7

Dry 0.0 0.0 3.0 3.0 3.0 3.0

Service wells – – – – – –

Total PetroBakken 8.0 7.5 317.0 231.8 325.0 239.3Success rate 100% 100% 99% 99% 99% 99%

PetroBakken – company interest reserves (1) – forecast prices

PetroBakken increased proved plus probable reserves by 18% to 171.4 million boe at December 31, 2010, replacing production by 274%.

Total Oil Natural Gas NGLRoyalty

Interests Company

Interest(Mbbl) (MMcf) (Mbbl) (Mboe) (Mboe)

Developed producing 50,888 63,790 3,807 857 66,183Proved 80,866 94,337 5,414 1,025 103,028Proved + probable (2P) 136,153 148,754 8,871 1,561 171,377

(1) Company interest reserves represent petroBakken’s working interest share of reserves including petroBakken’s royalty interests in reserves before deduction of petroBakken’s royalty obligations.

Reserve reconciliation – PetroBakken working interest (1), forecast prices (mboe)

Developed Producing Proved

Proved + Probable

PetroBakken reserves at December 31, 2009 59,415 89,470 143,638

2010 production, net of royalty income (15,031) (15,031) (15,031)

Acquisitions 3,283 5,344 6,817

Net additions and revisions 17,662 22,220 34,393

PetroBakken reserves at December 31, 2010 65,326 102,003 169,816PetroBakken year-over-year increase in reserves 10% 14% 18%PetroBakken production replacement 139% 183% 274%

(1) Company interest reserves excluding royalty income reserves and before deduction of royalties payable.

PetroBakken net present value – forecast prices ($ millions)

Before Tax After Tax

As at December 31, 2010 0% 5% 10% 15% 0% 5% 10% 15%

Developed producing 3,355 2,574 2,135 1,849 3,044 2,355 1,966 1,711

Total proved 4,765 3,541 2,845 2,392 4,073 3,038 2,446 2,059

Proved + probable 8,368 5,521 4,142 3,326 6,707 4,472 3,371 2,713

(1)


finding, development & acquisition costs (“fd&a”) (1)

PetroBakken had an active drilling program in 2010 and achieved 2P F&D costs of $26.11/boe on the operational capital expenditure program (including

future development costs (“FDC”) and land acquisitions). Corporate acquisition and disposition transactions had a material impact on our FD&A costs

for 2010, and resulted in 2P corporate FD&A costs of $39.31/boe (including FDC and land value). Overall, PetroBakken’s non-core disposition program

(including transactions completed in December 2009), generated $312 million of net proceeds at an average 2P reserve value of $18.38/boe.

For the year ended December 31, 2010 F&D Acquisitions Dispositions FD&APetroBakkenCapital expenditures ($000) 781,523 - - 781,523Acquisition/(Disposition) capital ($000) (3) - 714,305 (133,632) 580,673Total capital 781,523 714,305 (133,632) 1,362,196Less: land value 94,751 352,002 - 446,753Total capital excluding land value 686,772 362,303 (133,632) 915,443Change in FDC ($000) (4)

Proved 44,932 133,724 (22,835) 155,821 Proved plus probable 116,303 173,837 (32,540) 257,600Total costs ($000) Proved 826,455 848,029 (156,467) 1,518,017 Proved plus probable 897,826 888,142 (166,172) 1,619,796Net reserve additions/revisions (Mboe) Proved 22,220 13,608 (8,264) 27,564 Proved plus probable 34,393 21,235 (14,419) 41,209FD&A costs ($/boe) (5)

Proved $ 37.19 $ 62.32 $ 18.93 $ 55.07 Proved plus probable $ 26.11 $ 41.82 $ 11.52 $ 39.31 FD&A costs excluding land ($/boe) (5)

Proved $ 32.93 $ 36.45 $ 18.93 $ 38.86 Proved plus probable $ 23.35 $ 25.25 $ 11.52 $ 28.47 For the year ended December 31, 2009FD&A costs ($/boe) (5)


Proved $ 40.52 $ 42.97 $ 43.57 $ 42.56 Proved plus probable $ 30.37 $ 29.96 $ 32.89 $ 29.81 For the three years ended December 31, 2010FD&A costs ($/boe) (5)


Proved $ 30.74 $ 41.31 $ 27.94 $ 38.29 Proved plus probable $ 23.66 $ 28.77 $ 18.38 $ 27.94

(1) the aggregate of the exploration, development and acquisition costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding, development and acquisition costs related to reserves additions for that year.

(2) Includes the corporate acquisitions of Berens energy ltd., Rondo petroleum Inc. and Result energy Inc. and certain other asset acquisitions. the amount of undeveloped land acquired through Crown land purchases and acquisitions.

(3) portion of the purchase prices allocated to property, plant & equipment and reflects the net present value of each corporate acquisition as at its acquisition date based on 2p npV10%, before tax.

(4) the total undiscounted future development costs included in the December 31, 2010 Sproule report was $811.9 million (2009 – $644.5 million) for proved reserves and $1,295.4 million (2009 – $1,038.6 million) for proved plus probable reserves.

(5) FD&A costs are calculated by dividing total capital (or adjusted excluding land) plus change in future costs to develop by net reserve additions.

(2)






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Heavy Oil Business Unit (“HBU”)

Company interest reserves and resources – forecast prices

THAI® proved and proved plus probable reserves recognized for the Kerrobert heavy oil project are 3.0 million barrels and 4.8 million barrels, respectively, with

before tax NPV at 8% of $6.2 million and $46.0 million, respectively. The HBU’s total 2P reserves increased 36% to 95.4 million barrels at December 31, 2010.

As at December 31, 2010 Heavy Oil(Mbbl)

Bitumen(Mbbl)

Total(Mbbl)

Proved developed producing 575 - 575Proved 3,032 - 3,032Proved + probable (2P) 4,837 90,572 95,409Proved + probable + possible 8,513 101,512 110,025

Low estimate contingent resources - 473,964 473,964Best estimate contingent resources - 560,131 560,131High estimate contingent resources - 697,221 697,221

(1) Heavy oil reserve estimates have been based on tHAI® technology.

(2) Bitumen reserve and resource estimates have been based on SAGD technology.

hBu net present value – forecast prices ($ millions)

As at December 31, 2010 Before Tax After Tax

0% 5% 8% 10% 0% 5% 8% 10%

Proved reserves 20 11 6 4 20 11 6 4Proved + probable reserves 2,405 1,102 724 555 1,902 885 585 450Proved + probable + possible reserves 3,163 1,405 929 722 2,470 1,117 746 583

Low estimate contingent resources 10,180 3,923 2,190 1,450 7,591 2,785 1,461 898Best estimate contingent resources 14,088 5,258 3,000 2,067 10,506 3,796 2,088 1,386High estimate contingent resources 20,413 6,821 3,794 2,615 15,243 4,971 2,693 1,810

(1) (2)

TheReal Valueof Petrobank

Petrobank Energy and Resources Ltd.1900, 111 - 5th Avenue S.W.

Calgary, Alberta, Canada t2p 3Y6

tel: 403.750.4400 FAX: 403.266.5794

www.petrobank.com TSX: PBG

tankage area

Vapour recovery unit

Gas separator

Clean oil cooler

Inlet headers

pipeline right of way

oil treater

Recycle pump

Compression/coolers

Control room

existing farmland

talent and experience

petrobank energy and R

esources ltd. 2010 Annual R

eport

MD&A

Petrobank Energy and Resources Ltd.36

Management’s Discussion And Analysis

Summary of Results(1)

Q4 2010 2010 2009 2008

Financial($000s, except where noted)

Oil and natural gas revenue from continuing operations 258,359 1,008,556 575,588 585,800

Funds flow from continuing operations(2) 155,344 636,754 380,016 415,059

Per share – basic ($) 1.46 6.10 4.29 5.05

– diluted ($) 1.46 5.96 3.94 4.56

Net income from continuing operations 1,315 21,308 68,559 137,272

Per share – basic ($) 0.01 0.20 0.77 1.67

– diluted ($) 0.01 0.20 0.73 1.59

Net income (loss) attributable to Petrobank shareholders(3) (35,612) 115,785 145,079 244,482

Per share – basic ($) (0.34) 1.11 1.64 2.97

– diluted ($) (0.34) 1.03 1.52 2.76


PetroBakken 262,758 811,871 394,023 545,833

Heavy Oil Business Unit (“HBU”) 37,521 121,492 76,019 82,332

Total capital expenditures from continuing operations 300,279 933,363 470,042 628,165

Total assets 6,402,586 6,402,586 5,766,568 2,361,707

Common shares outstanding, end of period (000s)

Basic 106,236 106,236 93,617 83,525

Diluted(4) 110,046 110,046 108,596 99,043

OperationsPetroBakken operating netback ($/boe)(2) (5)

Oil and NGL revenue ($/bbl)(6) 75.19 72.77 64.27 92.80

Natural gas revenue ($/Mcf)(6) 3.96 4.22 4.40 8.06

Oil and natural gas revenue(6) 67.00 65.28 58.97 86.78

Royalties 9.84 9.34 8.55 10.03

Production expenses 8.97 8.18 7.38 8.76

Operating netback(2) (5) (7) 48.19 47.76 43.04 67.99


PetroBakken – oil and NGL (bbls) 34,754 35,109 22,648 15,369

PetroBakken – natural gas (Mcf) 39,474 39,473 22,110 14,436

Total conventional (boe)(5) (8) 41,333 41,688 26,333 17,775

(1) Petrominerales Ltd. (“Petrominerales”) has been presented as discontinued operations for the years ended December 31, 2010 and 2009 as this business unit was spun off to Petrobank shareholders at December 31, 2010. Please see “Net Income from Discontinued Operations” section within Management’s Discussion and Analysis (“MD&A”) for presentation and discussion of Petrominerales’ results.

(2) Non-GAAP measure. See “Non-GAAP Measures” section within this MD&A.

(3) Includes the operating results of Petrominerales until the business unit was spun-off on December 31, 2010, and a $70.1 million accumulated other comprehensive loss resulting from the historic translations of Petrominerales U.S. dollar amounts recorded in net income upon the spin-off of Petrominerales.

(4) Consists of common shares, stock options, directors deferred common shares, deferred common shares, and incentive shares as at the period end date.

(5) Six Mcf of natural gas is equivalent to one barrel of oil equivalent (“boe”). Net of transportation expenses and excludes revenue from purchased oil.

(6) Net of transportation expenses.

(7) Excludes hedging activities.

(8) HBU bitumen and heavy oil volumes are excluded from average daily production as Conklin and Kerrobert operations are considered to be in the pre-operating stage and accordingly are capitalized.

The following MD&A is dated March 14, 2011 and should be read in conjunction with the consolidated financial statements and accompanying notes

of Petrobank Energy and Resources Ltd. (“Petrobank”, “we”, “our” or the “Company”) as at and for the years ended December 31, 2010 and 2009. The

consolidated financial statements and comparative information have been prepared in accordance with Canadian Generally Accepted Accounting Principles

(“GAAP”). Additional information for the Company, including the Annual Information Form (“AIF”), can be found on SEDAR at www.sedar.com or at

www.petrobank.com. All amounts are in Canadian dollars, unless otherwise stated and all tabular amounts are in thousands of Canadian dollars, except share

amounts or as otherwise noted. The energy content of natural gas has been measured in gigajoules (“GJ”). Natural gas volumes have been converted to barrels

of oil equivalent (“boe”). Six thousand cubic feet (“Mcf”) of natural gas is equal to one barrel (“bbl”) based on an energy equivalency conversion method

primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, especially if used in isolation.

Peter Cheung, Vice President Finance and Chief Financial Officer

http://www.sedar.com

MD&A


Forward-Looking StatementsIn addition to historical information, the MD&A contains forward-looking statements that are generally identifiable as any statements that express, or

involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events of performance. Specifically, this MD&A contains forward-

looking statements relating to future capital plans and projects, sources of funding, future dividend rates and the impact of transition to International

Financial Reporting Standards (“IFRS”). Forward-looking statements are necessarily based upon assumptions and judgements with respect to the future

including, but not limited to, the outlook for commodity markets and capital markets, success of future evaluation and development activities, the successful

application of technology, prevailing commodity prices, the performance of producing wells and reservoirs, well development and operating performance,

general economic and business conditions, weather, and the regulatory and legal environment. These statements are not historical facts and may be forward-

looking and may involve estimates, assumptions and uncertainties which could cause actual results or outcomes to differ materially from those expressed

in such forward-looking statements. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable

at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a

result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: general economic, market and

business conditions; fluctuations in oil and gas prices; the results of exploration and development of drilling and related activities; costs and availability of

services; fluctuation in foreign currency exchange rates; the uncertainty of reserve estimates; changes in environmental and other regulations; risks associated

with oil and gas operations; the ability to economically test, develop and utilize the Company’s patented technologies, the feasibility of the technologies; and

other factors, many of which are beyond the control of the Company. Accordingly, there is no representation by Petrobank that actual results achieved during

the forecast period will be the same in whole or in part as those forecasts. Except to the extent required by law, Petrobank assumes no obligation to publicly

update or revise any forward-looking statements made in this MD&A or otherwise, whether as a result of new information, future events or otherwise.

Non-GAAP MeasuresThis report contains financial terms that are not considered measures under Canadian GAAP, such as funds flow from continuing operations, funds flow per share,

EBITDA and operating netback. These measures are commonly utilized in the oil and gas industry and are considered informative for management and shareholders.

Specifically, funds flow from continuing operations and funds flow per share reflect cash generated from continuing operating activities before changes in non-cash

working capital. Management considers funds flow from continuing operations and funds flow per share important as they help evaluate performance and demonstrate

the Company’s ability to generate sufficient cash to fund future growth opportunities and repay debt. EBITDA is defined as earnings before interest, taxes, depreciation,

amortization, non-controlling interest (“NCI”) and non-cash items. Operating netback is determined by dividing sales revenue less transportation, royalties and

production expenses by sales volumes. Profitability relative to commodity prices per unit of production is demonstrated by an operating netback. Funds flow from

continuing operations, funds flow per share, EBITDA and operating netbacks may not be comparable to those reported by other companies nor should they be viewed

as an alternative to cash flow from continuing operations, net income or other measures of financial performance calculated in accordance with GAAP.

Petrobank’s Business UnitsDuring 2010, the Company was comprised of three business units: the Heavy Oil Business Unit (“HBU”), PetroBakken Energy Ltd. (“PetroBakken”)

which in previous years and quarters was described as the Canadian Business Unit (“CBU”), and Petrominerales Ltd. (“Petrominerales”), which in previous

years and quarters was described as the Latin American Business Unit (“LABU”).

The HBU is operating the Kerrobert heavy oil project and Conklin oil sands project using Petrobank’s patented THAI® technology. The Kerrobert and

Conklin projects are in the pre-operating stage and accordingly all expenses, net of revenues, are capitalized. Therefore, it is important to note that

throughout this MD&A, results relating to the HBU are not included in operational results such as average daily production, revenue, royalties, production

expenses, or depletion and depreciation expense.

PetroBakken, 59 percent owned by Petrobank as at December 31, 2010, contains conventional oil and gas operations throughout western Canada with

a primary focus on light oil developments from the Bakken formation in southeast Saskatchewan and in the Cardium play in Alberta. Petrobank results

include 100 percent of PetroBakken’s results; the 41 percent minority interest share, which Petrobank does not own, is recorded as income attributable

to NCI on the consolidated statements of operations and retained earnings and as paid-in capital and NCI on the consolidated balance sheets. Results

for PetroBakken are reported on a continuity of interest basis and as such incorporate Petrobank’s CBU operations for the periods prior to the formation

of PetroBakken.

On December 31, 2010, the Company completed the spin-off of Petrominerales, whereby Petrobank shareholders received Petrobank’s 65 percent

proportionate interest in Petrominerales. To properly reflect this reorganization in the Company’s 2010 financial statements, the results of Petrominerales

have been segregated from ongoing operations and separately disclosed as “Discontinued Operations”.

ComparativesComparisons presented in this MD&A are fourth quarter of 2010 compared to the fourth quarter of 2009 and annual comparisons are 2010 to 2009

unless otherwise noted.

MD&A


Net IncomeThroughout this MD&A reference is made to net income, which represents “Net income attributable to Petrobank shareholders” on the Company’s

consolidated financial statements.

Q4 2010 Highlights and Significant Transactions• OnDecember 31, 2010,PetrobankandPetromineralescompletedacorporatereorganizationwhichresultedinPetrobankshareholdersreceiving

Petrobank’s proportionate interest in Petrominerales Ltd. Pursuant to this spin-off, a new Alberta corporation was formed (“New Petrominerales”) which

acquired all the outstanding shares of Petrominerales Ltd. Petrobank shareholders received 0.6142 shares of New Petrominerales and one replacement

common share of Petrobank for each Petrobank common share held. There was no change in the total number of shares outstanding for either Petrobank

or Petrominerales.

• OnOctober8,2010,Petrobankacquiredtheremaining50percentinterestintheDawsonheavyoilprojectfromShellCanadaLtd.TheCompany

received$2.8 millioncashinJanuary2011uponregulatoryapprovaloftheproject.

PetroBakken

• Fourthquarterproductiondecreasedslightlyto41,333 barrelsofoilequivalentperday(“boepd”)comparedto45,621 boepdinthefourthquarter

of 2009, primarily due to natural production declines which more than offset production additions as weather related delays restricted PetroBakken’s

ability to access leases and bring on additional production.

• Operatingnetbacks(excludinghedgingactivity)averaged$48.19 per boeinthefourthquarterof2010,anincreaseofthreepercentcomparedtothe

fourth quarter of 2009, primarily due to higher benchmark oil prices.

• PetroBakkendrilled77.4 netwellsinthequarter,themajorityofwhichweredrilledinsoutheastSaskatchewan,particularlytheBakkenplay,however

activity levels increased in the Cardium play in the fourth quarter as lease conditions improved.

2010 Highlights and Significant Transactions• OnSeptember30,2010,PetrobankcompletedtheacquisitionofBaytexEnergyLtd.’s50percentinterestintheKerrobertheavyoilprojectforcash

considerationof$18.1million.

• OnJanuary8,2010,PetrobankcompletedanearlyconversionofferingwhichresultedinUS$250.7millionprincipalamountof5.125%convertible

debenturesdueJuly10,2015beingexercisedpriortomaturity.Upontheconversion,atotalof7,452,099Petrobankcommonshareswereissued.On

April23,2010,theremainingUS$149.3millionprincipalamountofPetrobank’s5.125%convertibledebentureswasearlyconverted.Anaggregateof

US$27.4millionwaspaidand3,920,446commonshareswereissued.OnMay10,2010,theremainingUS$5.1millionprincipalamountofPetrobank’s

3%convertibledebentureswasearlyconvertedinto179,009commonshares.Asaresultofthesethreeevents,therearenolongeranyPetrobank

convertible debentures outstanding.

• Fundsflowfromcontinuingoperationsincreased68percentto$636.8 millionin2010primarilyasaresultofPetroBakken’sincreasedproductionand

higher operating netbacks. On a per basic and diluted share basis, funds flow from operations increased 42 percent and 52 percent, respectively.

• Netincomefromcontinuingoperationsdecreasedby69percentto$21.3millionin2010.Thedecreaseisduemainlytotheinclusionofaforeign

exchangegainof$57.8millionin2009,whichresultedfromthetranslationofPetrobank’sU.S.dollarconvertibledebentures.

• NetincomeattributabletoPetrobankshareholdersdecreasedby20percentto$115.8 millionin2010.Thedecreaseisduemainlytotherecognitionofa

$70.1millionaccumulatedothercomprehensivelossresultingfromthehistorictranslationsofPetromineralesU.S.dollaramountsintheconsolidated

financial statements, recorded in net income upon the spin-off of Petrominerales.

PetroBakken

• PetroBakken’sproductionincreased58percentto41,688boepdin2010from26,333boepdin2009primarilyduetotheacquisitionofTriStarOiland

Gas Ltd. on October 1, 2009.

• OnJanuary25,2010,PetroBakkenissuedUS$750millionofconvertibledebentures.Thedebenturesareconvertibleintocommonsharesof

PetroBakken at a conversion price that is adjusted for dividends paid. Based on dividends declared to February 2011, the conversion price was

$37.74pershare.Theconvertibledebentureshaveanannualcouponrateof3.125percentandmatureinFebruary2016.

• OnFebruary25,2010,PetroBakkenacquiredalloftheissuedandoutstandingsharesofBerensEnergyLtd.(“Berens”)forcashconsiderationof

$252.8 millionandtheassumptionofbankindebtednessofapproximately$74.9million.Therewasaworkingcapitaldeficiencyof$16.6 million

at the acquisition date.

• OnMarch12,2010,PetroBakkenacquiredalloftheissuedandoutstandingsharesofRondoPetroleumInc.(“Rondo”)forcashconsideration

ofapproximately$88.7million,assumptionofbankindebtednessofapproximately$16.0millionandtheissuanceofapproximately5.5 million

PetroBakken common shares. There was a working capital deficiency of $22.2 million at the acquisition date.

MD&A


• OnApril1,2010,PetroBakkenacquiredalloftheissuedandoutstandingsharesofResultEnergyInc.(“Result”)forcashconsideration(netofcash

acquired)of$141.2millionandtheissuanceofapproximately11.2 millionPetroBakkencommonshares.Therewasworkingcapitalof$2.7 millionat

the acquisition date.

• DuringtheyearendedDecember31,2010,PetroBakkencloseddivestituresrepresentingapproximately3,800boepdofproduction(50percentnatural

gas) in Alberta for net proceeds of $133.6 million. Of this amount, $5.2 million was closed during the fourth quarter, less $1.6 million of post closing

adjustments related to prior period dispositions.

• OnMay17,2010,PetroBakkencommencedanormalcourseissuerbid(“NCIB”)pursuanttowhichPetroBakkenisauthorizedtopurchaseupto

9,431,255 commonshares.TheNCIBwillendonMay18,2011oranearliertimeiftheNCIBiscompletedorterminatedatPetroBakken’selection.

AsofMarch7,2011,1,680,400 commonshareshavebeenrepurchasedundertheNCIBfor$36.4 million.

Subsequent Events• OnJanuary4,2011,Petrobankenteredintoanewthreeyear$200millioncreditagreementwithasyndicateoflenders.

Financial And Operational ReviewThe financial and operational review has been primarily split into continuing operations, which consists of the HBU and PetroBakken, and discontinued

operations, which consists of Petrominerales. As discussed previously, Petrominerales, which operates in Colombia and Peru, was spun-off to Petrobank

shareholders on December 31, 2010. This business unit will not be included in the consolidated results of the Company on a go forward basis.

The HBU operations are considered to be in the pre-operating stage and accordingly revenues, net of royalties and operations costs, are charged to

capitalized costs as opposed to being recognized in net income. Therefore, the following production, pricing, revenue, royalties and operating expense tables

include only PetroBakken results.

Continuing Operations

PetroBakken’s acquisition of TriStar Oil and Gas Ltd. (“TriStar”) on October 1, 2009 has significantly impacted financial and operating results for the year

ended December 31, 2010.

Average Daily Production

Three months ended December 31, Years ended December 31,

2010 2009 Change 2010 2009 Change

PetroBakken

Oil and NGL (bbls) 34,754 38,796 (10%) 35,109 22,648 55%

Natural gas (Mcf) 39,474 40,951 (4%) 39,473 22,110 79%

Total PetroBakken (boe) 41,333 45,621 (9%) 41,688 26,333 58%

Productionincreasedby58 percentfortheyearendedDecember31,2010,primarilyduetotheacquisitionofTriStaronOctober1,2009.Inthefourth

quarter, the nine percent decrease in production was the result of natural production declines, which more than offset production additions as weather

related delays restricted PetroBakken’s ability to access leases and bring on additional production.

The 2010 production additions came from drilling PetroBakken’s light oil properties in southeast Saskatchewan and the Cardium play in southern Alberta,

as well as the Berens, Rondo, and Result corporate acquisitions, offset by asset divestitures and base production declines, which are estimated to be 40

percent in 2010. Drilling activity increased significantly in 2010, as compared to the prior year, commensurate with the increase in oil prices and a larger

capitalprogram.PetroBakkendrilled239.3netwellsin2010(2009–117.3),with77.4netwellsdrilledinthefourthquarter(2009–64.8).In2010,drilling

has been mainly focused in southeast Saskatchewan for both Bakken and conventional Mississippian light oil opportunities. Drilling in the Cardium

commenced in the third quarter. Wet weather in the third and early fourth quarter delayed completions operations, particularly in the Cardium, which

delayed production additions. PetroBakken had 15.5 net Cardium wells waiting to be completed or brought on production at December 31, 2010. In the

Bakken, PetroBakken is currently experimenting with new completions techniques to overcome higher water cuts caused by fracing out of zone. Fracture

stimulation (“fracing”) is the process of pumping fluid down the well to increase permeability of the wellbore which results in increased production. One

of the techniques is to initially produce the wells at a lower rate and then frac them following several months of production. At year-end 2010, PetroBakken

had 15 net wells waiting to be fraced in the Bakken play, the majority of which will be fraced by the end of the first quarter of 2011. Initial results from these

new techniques have been encouraging but longer term production monitoring is still required to confirm this progress. The corporate acquisitions added

approximately5,600boepdofproductionstartinginlateFebruary2010.Non-corepropertydispositions(approximately5,700boepdofproduction)were

completed between December 2009 and April 2010 and more than offset the acquired production on a year-to-date total and average basis.

MD&A


AverageJanuaryproductionisestimatedat41,400boepdbasedonfieldestimates.IntheCardium,PetroBakkennowhas27netwellswaitingtobe

completed or brought on production.

Average Benchmark and Realized Prices


2010 2009 Change 2010 2009 Change

WTI (US$/bbl) 85.18 76.19 12% 79.53 61.80 29%

WTI ($/bbl) 86.24 80.47 7% 81.87 70.57 16%

AECO natural gas ($/Mcf) 3.64 4.50 (19%) 4.00 3.95 1%

US$ per C$1 0.99 0.95 4% 0.97 0.88 10%

PetroBakken – oil and NGL

Realized price per bbl ($/bbl) 76.31 71.63 7% 73.96 64.27 15%

Oil price discount as a % of WTI 14% 11% 27% 11% 9% 22%

PetroBakken – natural gas Realized price per Mcf ($/Mcf)

3.96 4.61 (14%) 4.22 4.40 (4%)

In the fourth quarter and in 2010, realized oil and NGL prices increased due to higher WTI prices, partially offset by a stronger Canadian dollar compared

to the U.S. dollar. The fourth quarter of 2010 also experienced wider price differentials to WTI as Canadian sourced crude experienced restrictions as a

result of Enbridge Inc. pipeline issues in the third and fourth quarters.

Realized natural gas prices decreased in the fourth quarter due to lower AECO prices and a lower premium. The premium received on gas decreased as the

proportion of gas sold under a higher premium long-term gas contract decreased as a percentage of overall gas sales.

RevenueThe change in 2010 revenue is primarily due to higher liquid prices and increased sales associated with the acquisition of TriStar and increased drilling

activity. The change in fourth quarter revenue is the result of lower production partially offset by higher prices. The table below summarizes these changes:

Reconciliation of Changes in Revenue

Three months ended Year ended

PetroBakken

December 31, 2009 276,334 575,588

Sales volume (26,803) 366,251

Realized prices 8,828 66,717

December 31, 2010 258,359 1,008,556$ change in revenue (17,975) 432,968

% change in revenue (7%) 75%

Net Realized Prices


2010 2009 Change 2010 2009 Change

PetroBakken

Gross revenue 258,359 276,334 (7%) 1,008,556 575,588 75%

Transportation expense 3,593 3,297 9% 15,270 8,820 73%

Total revenue, net of transportation 254,766 273,037 (7%) 993,286 566,768 75%

Gross revenue ($/boe) 67.94 65.84 3% 66.28 59.89 11%

Transportation expense ($/boe) 0.94 0.79 19% 1.00 0.92 9%

Realized price, net of transportation ($/boe)

67.00 65.05 3% 65.28 58.97 11%

Net realized price for the fourth quarter and 2010 improved mainly due to higher WTI prices. On a unit of production basis, transportation expenses

increased in the fourth quarter as increased trucking was required due to pipeline outage and apportionment issues in the Bakken. As PetroBakken’s

production infrastructure expands with operations in southeast Saskatchewan and more wells are tied into facilities, we expect a reduction in transportation

expenses on a per boe basis.

MD&A


Royalties


2010 2009 Change 2010 2009 Change

PetroBakken(1) 37,479 42,565 (12%) 142,064 82,151 73%

PetroBakken – $ per boe 9.84 10.14 (3%) 9.34 8.55 9%

PetroBakken – royalties as a % of realized price

15% 16% (6%) 14% 14% -

(1) PetroBakken royalties include the Saskatchewan Resource Surcharge determined as a percentage of sales from PetroBakken’s Saskatchewan Crown lands.

Royalties decreased in the fourth quarter due to production declines and a lower effective royalty rate. Royalties increased in 2010 due to production

additions from the TriStar acquisition and higher oil prices. Royalties as a percentage of revenue decreased in the fourth quarter as there were an

increased number of Bakken wells in Saskatchewan and Cardium wells in Alberta subject to royalty incentive due to increased drilling. On Crown lands

inSaskatchewan,thefirst37,740barrelsofproductionfromhorizontalwellsreceivearoyaltyincentivebutincurSaskatchewanResourceSurchargeof

1.7 percent.OnCrownlandinAlberta,horizontaloilwellsaresubjecttoamaximum5 percentroyaltyratefor18 to 48monthsdependingonwelllength.

Gain (Loss) on Risk Management Contracts

Three months ended December 31, Year ended December 31,

2010 2009 Change 2010 2009 Change

Realized gain (loss):

Crude oil derivative contracts (1,017) 2,952 - (2,925) 23,984 -

Natural gas derivative contracts 1,210 (31) - 5,117 (31) -

Interest rate swap contracts (327) (2,119) 85% (2,414) (2,313) (4%)

Foreign exchange contracts - 2,332 - - 2,332 -

(134) 3,134 - (222) 23,972 -

Unrealized gain (loss):

Crude oil derivative contracts (16,244) (11,836) (37%) (8,347) (40,926) 80%

Natural gas derivative contracts (1,357) 210 - (428) 210 -

Interest rate swap contracts 639 (328) - 571 118 384%

Foreign exchange contracts - (1,343) - - (1,343) -

(16,962) (13,297) (28%) (8,204) (41,941) 80%

Gain (loss) on risk management contracts

(17,096) (10,163) (68%) (8,426) (17,969) 53%

PetroBakken enters into commodity price derivative contracts to limit exposure to declining commodity prices, thereby protecting project economics and

providing increased stability of cash flows, dividends and capital expenditure programs. Commodity prices fluctuate for a number of reasons including

change in economic conditions, political events, weather conditions, disruptions in supply, and changes in demand. PetroBakken’s risk management

activities are conducted pursuant to risk management policies that have been approved by the Board of Directors.

The majority of PetroBakken’s financial commodity derivative contracts are option-based contracts and as such their fair value at a particular point in time

is affected by underlying commodity prices, expected commodity price volatility and the duration of the contract. The fair value of fixed price derivative

contracts at a particular point in time is determined by the expected future settlements of the underlying commodity or interest rate. At December 31, 2010,

the fair value of financial derivative contracts was a liability of $13.0 million. The fair value of this liability represents the estimated amount required to settle

PetroBakken’s outstanding contracts at December 31, 2010 and will be different than what will eventually be realized.

The gain or loss on risk management contracts is made up of two components: the realized component reflects actual settlements that occurred during

the period, and the unrealized component represents the change in the fair value of contracts during the period. The unrealized loss on risk management

contracts in the fourth quarter and in 2010 was primarily the result of the fluctuations in expected future WTI prices.

The following table summarizes the change in and the fair value of derivative contracts:

Crude Oil Natural Gas Interest Year ended

Risk management asset (liability), December 31, 2009

(6,488) 470 (118) (6,136)

Unrealized gain (loss) (8,347) (428) 571 (8,204)

Contracts acquired - 1,980 (688) 1,292

Risk management asset (liability), December 31, 2010

(14,835) 2,022 (235) (13,048)

MD&A


AtDecember31,2010,PetroBakkenrecordeda$14.8millionliabilityrelatedtocrudeoilpriceriskmanagementcontracts.Thefollowingisasummaryof

crude oil derivative contracts in place as at December 31, 2010:

Crude Oil Price Risk Management Contracts – WTI(1)

Term Volume (bopd) Average Price ($/bbl) Benchmark

Jan. 1, 2011 – Dec. 31, 2011 2,500 $78.00 floor/$95.40 ceiling C$ WTI

Jan. 1, 2011 – Dec. 31, 2011 4,500 $76.11 floor/$101.43 ceiling US$ WTI

Jan. 1, 2011 – Jun. 30, 2011 1,000 $75.00 floor/$104.53 ceiling US$ WTI


Jul. 1, 2011 – Dec. 31, 2012 1,000 $75.00 floor/$98.25 ceiling US$ WTI

Jan. 1, 2012 – Jun. 30, 2013 500 $75.00 floor/$109.00 ceiling US$ WTI

(1) Prices are the volume weighted average prices for the period.

The following crude oil derivative contracts were entered into subsequent to December 31, 2010:



Jul. 1, 2012 – Jun. 30, 2013 1,000 $75.00 floor/$117.45 ceiling US$ WTI

The average of the above volumes is as follows:


2011 10,000 $76.14 floor/$99.42 ceiling US$ WTI



At December 31, 2010, PetroBakken recorded a $2.0 million asset related to the following natural gas price risk management contracts:

Natural Gas Price Risk Management Contracts – AECO

Term Volume (GJ/d) Price ($/GJ) Type

Jan. 1, 2011 – Mar. 31, 2011 2,000 $6.00 Fixed Price Swap

Jan. 1, 2011 – Dec. 31, 2011 2,000 $6.02 Fixed Price Swap

At December 31, 2010, PetroBakken recorded a $0.2 million liability related to the following interest rate swap contracts:

Term Notional Principal/Month Fixed Annual Rate (%)

Jan. 2011 – Feb. 2011 C$40 million 2.390%

Jan. 2011 – Apr. 2011 C$50 million 1.050%

Jan. 2011 – Jan. 2012 C$50 million 1.620%

Jan. 2011 – Jan. 2012 C$50 million 1.653%

Jan. 2011 – Feb. 2012 C$25 million 1.540%

Jan. 2011 – Feb. 2012 C$25 million 1.510%

Jan. 2011 – Apr. 2012 C$50 million 1.300%

Jan. 2011 – Jun. 2012 C$25 million 2.094%

Production Expenses


2010 2009 Change 2010 2009 Change

PetroBakken 34,126 34,535 (1%) 124,481 70,913 76%

PetroBakken – $ per boe 8.97 8.23 9% 8.18 7.38 11%

In 2010, the increase in production expenses on an absolute and per boe basis was primarily as a result of the increase in higher cost production associated

with the TriStar acquisition. Production expenses decreased in the fourth quarter due to lower production; however, on a per boe basis they increased in

the quarter because the fixed component percentage of production expenses increased as production declined. These increases were partially offset by cost

efficiencies gained during the quarter due to the expansion of facilities infrastructure in southeast Saskatchewan and company wide field operating cost

reduction initiatives in 2010. These facilities have also allowed PetroBakken to add liquids rich natural gas production and reserves associated with Bakken

lightoilproduction.OperatingcostsinPetroBakken’scoreareaofsoutheastSaskatchewanaveraged$8.15perboeinthefourthquarterand$7.12perboe

in2010,ascomparedto$6.71perboeand$6.36perboe,respectively,in2009.CentralAlbertaproductionexpensesaveraged$8.51perboeinthefourth

quarterand$8.75forthefirstninemonthsof2010,withlimitedcomparativeinformationpriortotheseperiods.

MD&A


General and Administrative Expenses


2010 2009 Change 2010 2009 Change

HBU and Corporate 3,393 1,272 167% 8,632 4,100 111%

PetroBakken 8,572 5,557 54% 33,233 15,253 118%

Total general and administrative expense

11,965 6,829 75% 41,865 19,353 116%


HBU AND CORPORATE

General and administrative costs increased in the fourth quarter and 2010 primarily due to additional personnel and office costs as a result of expanding

operations, and increased professional and public company fees incurred by Petrobank as a result of the spin-off of Petrominerales.

PETROBAKKEN

General and administrative costs increased in the fourth quarter and 2010 on an absolute and per boe basis due primarily to additional personnel and office

costs as a result of expanding operations and consulting costs associated with the integration of operations and assets.

Stock-Based Compensation Expenses


2010 2009 Change 2010 2009 Change

HBU and Corporate 2,629 2,152 22% 9,505 6,274 51%

PetroBakken 5,450 6,191 (12%) 22,888 18,650 23%

Total stock-based compensation expense

8,079 8,343 (3%) 32,393 24,924 30%

Stock-based compensation expenses relate to stock options, deferred common shares, directors deferred common shares and incentive shares (collectively,

“the rights”) granted. The calculation of this non-cash expense is based on the fair value of the rights granted, amortized over the vesting period of the

option or incentive shares, or immediately upon grant of the deferred common shares and directors deferred common shares.

Starting in the fourth quarter of 2009, PetroBakken’s expense relates to PetroBakken rights granted to employees and directors following the incorporation

of PetroBakken and the acquisition of TriStar. For the first nine months of 2009, PetroBakken’s expense relates to historical Petrobank rights that were

granted to employees involved with CBU operations.

Interest Expense


2010 2009 Change 2010 2009 Change

HBU and Corporate 161 4,238 (96%) 1,900 13,314 (86%)

PetroBakken 21,071 11,547 82% 75,611 18,699 304%

Total interest expense 21,232 15,785 35% 77,511 32,013 142%

Interest expense includes interest on bank debt and convertible debentures, fees on letters of credit, standby fees, amortization of deferred financing costs,

and accretion on convertible debentures.

HBU AND CORPORATE

Following the early conversion of Petrobank’s remaining convertible debentures into common shares in the second quarter, interest expense was reduced to

only the amortization of deferred financing costs and bank standby fees.

PETROBAKKEN

Interest expense increased in the fourth quarter and 2010 primarily as a result of interest expense and accretion on the convertible debentures that were

issued on January 25, 2010. Interest expense for 2010 also increased due to higher bank debt outstanding throughout the year. Bank debt was repaid at

the end of January 2010 when the convertible debentures were issued, and increased throughout 2010 to fund the Berens, Rondo, and Result acquisitions,

andcapitalexpenditures.Onaverage,bankdebtoutstandingwas$767.5millioninthefourthquarterof2010ascomparedto$861.4millioninthefourth

quarter of 2009 and $602.5 million in 2010 as compared to $349.0 million in 2009.

MD&A


Foreign Exchange Loss (Gain)


2010 2009 Change 2010 2009 Change

HBU and Corporate 25 (8,504) - (8,769) (57,753) (85%)

PetroBakken (19,917) 1,105 - (19,541) 1,105 -

Total foreign exchange loss (gain) (19,892) (7,399) 169% (28,310) (56,648) (50%)

HBU AND CORPORATE

The Company recognized foreign exchange gains in the twelve months ended December 31, 2010 due to an appreciation of the Canadian dollar relative to

the U.S. dollar upon conversion of Petrobank’s remaining U.S. dollar denominated convertible debentures into common shares. As of December 31, 2010,

there are no Petrobank convertible debentures outstanding.

PETROBAKKEN

As PetroBakken’s convertible debentures are denominated in U.S. dollars, the vast majority of unrealized foreign exchange gains and losses relate to the

change in the foreign exchange rate at year end compared to the rate at the end of the previous period. Due to the appreciation of the Canadian dollar

relative to the U.S. dollar over the course of 2010, this resulted in an unrealized gain for the three and twelve month periods ending December 31, 2010.

This gain was partially offset by a realized loss on currency swap transactions in the first quarter when debenture proceeds were converted to Canadian

dollars.

Depletion, Depreciation and Accretion (“DD&A”) Expense


2010 2009 Change 2010 2009 Change

HBU and Corporate 220 155 42% 656 411 60%

PetroBakken 134,113 142,523 (6%) 525,403 303,714 73%

Total DD&A expense 134,333 142,678 (6%) 526,059 304,125 73%


PETROBAKKEN

DD&A decreased in the fourth quarter due to declines in production. On a unit of production basis DD&A increased in the fourth quarter due to capital

expenditures incurred where the full benefit of reserve additions are not expected until future periods. DD&A increased on both an absolute and unit of

production basis in 2010 due primarily to the TriStar and Cardium focused corporate acquisitions, partially offset by reserves associated with drilling in the

year and performance additions from bilateral Bakken wells.

Future Income Taxes (Recovery)


2010 2009 Change 2010 2009 Change

HBU and Corporate 1,519 1,325 15% (3,333) (3,514) (5%)

PetroBakken 1,798 (33,653) - 31,450 (24,027) -

Total future income taxes (recovery) 3,317 (32,328) - 28,117 (27,541) -

HBU AND CORPORATE

The fourth quarter and 2010 future income taxes are relatively consistent with income earned after adjustments for non-deductible and non-taxable items.

PETROBAKKEN

PetroBakken’s future income tax expense for the fourth quarter is relatively consistent with income earned adjusted for non-deductible tax items. The

future income tax expense for 2010 is higher than expected largely due to the effect of a realized foreign exchange loss incurred in the first quarter for

which the tax benefit has not yet been recognized. In the fourth quarter of 2009, the future income tax recovery benefited from a recovery associated

with a property disposition.

Net Income Attributable to Non-Controlling Interest


2010 2009 Change 2010 2009 Change

PetroBakken

Net income attributable to NCI 6,238 12,019 (48%) 18,187 12,019 51%

The net income attributable to NCI represents the NCI share of PetroBakken’s net income. The NCI share in PetroBakken averaged approximately

41 percent in the fourth quarter and 40 percent in 2010.

MD&A


Capital Expenditures


2010 2009 Change 2010 2009 Change

HBU 37,521 15,554 141% 121,492 76,019 60%

PetroBakken (“PBN”) 262,758 177,278 48% 811,871 394,023 106%

Total capital expenditures 300,279 192,382 56% 933,363 470,042 99%

Q4 2010 Capital Expenditures By Type

HBU PBN Total

Drilling and completions 14,936 207,637 222,573

Facilities 13,831 39,643 53,474

Land 504 7,195 7,699

Seismic 82 303 385

Pilot capital 6,864 - 6,864

Asset acquisition - 371 371

Other(1) 1,304 7,609 8,913

Total capital expenditures 37,521 262,758 300,279

(1) Includes health, safety and environmental, capitalized salaries, office furniture and fixtures and leasehold improvements.

HBU AND CORPORATE

The majority of HBU expenditures in the fourth quarter of 2010 focused on our Kerrobert project and include drilling and facility upgrade costs relating

to our 10 well-pair expansion project, and operating expenses in excess of revenues on our existing two horizontal wells. Additional HBU expenditures

in the quarter include workovers and operating expenses at Conklin, and engineering and procurement costs for the May River project. Currently, the

business unit operations are considered to be in the pre-operating stage and as a result, operating expenses net of revenues and interest are capitalized.

PETROBAKKEN

The majority of capital expenditures in the in the fourth quarter were focused on drilling, completions and recompletions, primarily in southeast

Saskatchewan, particularly in the Bakken play, and in the Cardium play as lease conditions improved. Drilling, completions, and recompletions

expenditures increased over the prior year due to additional wells drilled and brought on production. There were 12.6 additional wells drilled in the fourth

quarter compared to the same period in 2009. The majority of facilities expenditures in the fourth quarter were comprised of costs to tie-in additional

wells, and the expansion of gathering systems to PetroBakken’s five major facilities in southeast Saskatchewan.

2010 Capital Expenditures By Type

HBU PBN Total

Drilling and completions 24,644 568,905 593,549 Facilities 28,243 91,245 119,488

Land 504 94,751 95,255

Seismic 6,028 6,359 12,387

Pilot capital 31,148 - 31,148

Asset acquisition 18,057 30,348 48,405 Other(1) 12,868 20,263 33,131

Total capital expenditures 121,492 811,871 933,363

(1) Includes health, safety and environmental, capitalized salaries and office furniture and fixtures. HBU also includes $3.0 million of capitalized cash interest.

HBU AND CORPORATE

HBU expenditures in 2010 include initial costs associated with our 10 well-pair expansion for the Kerrobert project, the acquisition of the remaining

50% interestinourKerrobertprojectfromBaytexEnergyLtd.,operatingexpendituresinexcessofrevenuesrelatingtothetwowell-pairsdrilledat

Kerrobert in 2009, operating costs in excess of revenues related to our Conklin Project, procurement costs for the May River project, and capitalized

interest and general and administrative expenses. Currently, the business unit operations are considered to be in the pre-operating stage and as a result,

operating expenses net of revenues and interest are capitalized.

PETROBAKKEN

Expenditures in 2010 were focused on drilling, completions and recompletions. Most of this activity was focused in southeast Saskatchewan, particularly

in the Bakken play. Compared to 2009, there were 122.0 additional wells drilled in 2010. The majority of facilities expenditures in 2010 were comprised

of costs to tie-in additional wells, and the expansion of gathering systems to PetroBakken’s five major facilities in southeast Saskatchewan. Activity in the

Cardium area resulted in the majority of land and project acquisitions in 2010.

MD&A


GoodwillTherewerenochangestogoodwillinthefourthquarter.Thetotalgoodwillincreasefortheyearis$457.7 million,whichincludesgoodwillfrom

PetroBakken’sacquisitionsofBerens,Rondo,andResult.GoodwillasatDecember31,2010was$1,518.6 million.

Summary Of Quarterly Results2010 2009

Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1

Financial ($000s except where noted)

Oil and natural gas revenue from continuing operations

258,359 228,537 245,954 275,706 276,334 101,316 102,452 95,486

Funds flow from continuing operations(1) 155,344 139,325 153,714 188,371 166,833 64,243 75,959 72,981

Per share – basic ($) 1.46 1.31 1.46 1.88 1.80 0.71 0.90 0.88

– diluted ($) 1.46 1.31 1.43 1.77 1.59 0.67 0.85 0.83

Net income (loss) from continuing operations 1,315 3,003 (14,524) 31,514 20,740 35,315 21,928 (9,424)

Per share – basic ($) 0.01 0.03 (0.14) 0.31 0.22 0.38 0.26 (0.11)

– diluted ($) 0.01 0.03 (0.14) 0.31 0.22 0.37 0.26 (0.11)


(35,612) 27,848 41,050 82,499 57,108 54,846 34,667 (1,542)

Per share – basic ($) (0.34) 0.26 0.39 0.82 0.61 0.59 0.41 (0.02)

– diluted ($) (0.34) 0.25 0.35 0.76 0.56 0.56 0.40 (0.02)


PetroBakken 262,758 241,309 122,688 185,116 177,278 107,820 38,901 70,024

HBU 37,521 49,385 10,652 23,934 15,554 26,737 12,318 21,410

Total from continuing operations 300,279 290,694 133,340 209,050 192,832 134,557 51,219 91,434

PetroBakken Operations

Operating netbacks by product

Crude oil and NGL sales price, ($/bbl)(3) (5) 75.19 68.43 70.98 76.08 71.63 67.65 62.22 48.57

Royalties 10.94 9.67 10.36 10.56 11.26 10.75 7.97 5.39

Production expenses 9.56 8.88 7.89 7.95 8.45 7.05 6.66 6.98

Operating netback(1) (4) 54.69 49.88 52.73 57.57 51.92 49.85 47.59 36.20

Natural gas sales price, ($/Mcf)(3) 3.96 3.82 4.11 5.20 4.61 3.55 3.91 5.35

Royalties 0.66 0.62 0.60 0.60 0.63 0.54 0.67 0.78


Operating netback(1) (4) 2.32 2.20 2.48 3.48 2.82 2.08 2.29 3.67

Oil equivalent sales price, ($/boe)(3) 67.00 60.63 62.86 70.41 65.05 60.66 56.64 46.81

Royalties 9.84 8.64 9.17 9.68 10.14 9.62 7.40 5.32


Operating netback(1) (2) (4) 48.19 43.61 46.10 52.93 46.68 44.21 42.72 34.68


Crude oil and NGL (bbls)(5) 34,754 33,230 34,852 37,654 38,796 15,185 16,761 19,722

Natural gas (Mcf) 39,474 41,193 44,469 32,662 40,951 16,177 16,906 14,179

Total (boe)(2) 41,333 40,095 42,263 43,098 45,621 17,881 19,579 22,085

(1) Non-GAAP measure. See “Non-GAAP Measures” section within the MD&A.

(2) Six Mcf of natural gas is equivalent to one barrel of oil equivalent (“boe”).

(3) Net of transportation expenses.

(4) Excludes hedging activities.

(5) Heavy oil has been included in crude oil as it is not considered material.

MD&A


Significant factors influencing quarterly results were:

• PetroBakkenlightoilandnaturalgasproductionsincethefourthquarterof2009increasedsignificantlyoverpriorquarters,mainlyduetothe

acquisition of TriStar on October 1, 2009. PetroBakken gas production also increased in the second and third quarters of 2010 due to production

associated with the Berens acquisition.

• PetroBakkenbaseproductiondeclinesanddelaysinbringingproductiononstreamresultedinadeclineinliquidsfromthefourthquarterof2009

to the third quarter of 2010.

• PetroBakkenproductionincreasedthreepercentinthefourthquarterof2010comparedtothethirdquarterof2010primarilyasaresultofnew

Cardium wells brought on production.

• Crudeoilbenchmarkpriceshavegenerallyimprovedthroughout2009andinto2010,contributingtoimprovingoperatingnetbacks,revenueandfunds

flow from operations. Natural gas prices have oscillated more over this time period, however, they have not had as great an impact on results due to

PetroBakken’s relatively low gas production weighting. Compared to the third quarter of 2010, fourth quarter 2010 netbacks increased primarily due to

increased WTI prices.

• Capitalexpendituresincreasedfrom2009asweadvancedtheHBUdevelopmentprojectsandPetroBakkenexpandeditsdrillingprogramconsiderably

with higher funds flow from operations as a result of higher production and improved oil prices. PetroBakken fourth quarter 2010 capital expenditures

increased approximately 10 percent compared to the third quarter of 2010 due to the drilling program in Saskatchewan and Cardium activity in Alberta

increasing with improved lease conditions.

• PetroBakkenproductionexpensesincreasedinthefourthquarterof2009withtheacquisitionofTriStarbutdeclinedinthefirstandsecondquartersof

2010 due to non-core property dispositions and field optimization. In the third and fourth quarters of 2010, production expenses increased due to lower

production caused by drilling delays but consistent fixed costs.

Net Income from Discontinued OperationsThe following applies to Petrominerales only. The spin-off of this business unit occurred on December 31, 2010. Petrominerales’ operations have been

accounted for as discontinued operations in accordance with Canadian GAAP on a retroactive basis and the results as at December 31, 2009 and for the

year ended December 31, 2009 have been amended accordingly.

Q4 2010 Highlights

• Productionwas33,142 barrelsofoilperday(“bopd”)inthefourthquarterof2010,a35 percentincreasefromthesameperiodin2009.

• Petromineralesgeneratedastrongoperatingnetbackof$49.52perbarrelinthefourthquarterof2010,aone percentdecreaseoverthesameperiod

in 2009.

• TosupporthighimpactLlanosBasinfocusedgrowthobjectives,Petromineralescommittedtoa9.65 percentstakeoftheOleductoBicentenario

de Colombia pipeline. Completion of the project is expected by the end of 2012 or the beginning of 2013.

2010 Highlights and Significant Transactions

• Petromineralesincreasedcrudeoilproductionto37,027 bopd,a66 percentgainover2009.

• Petromineralesgeneratedastrongoperatingnetbackof$51.63 per barrelin2010,a21 percentincreaseover2009.

• PetromineraleswasthemostactiveexplorationcompanyinColombiain2010,drilling16 explorationwells,representing15 percentofallexploration

wells drilled in Colombia in 2010.

• PetromineralesexplorationacreageinPeruincreasedsignificantlyto5.4millionnetacres.

• PetromineralesraisedUS$550 millionthroughaconvertiblebondissuanceinAugust.ThebondsareconvertibleintocommonsharesofPetrominerales,

have an annual coupon of 2.625 percent and mature in August 2016.

• Startinginthesecondquarter,Petromineralesinitiatedaquarterlydividendof$0.125pershare($0.50pershareannualized).

MD&A


The operating results for this discontinued operation for the periods noted are shown in the following table:


2010 2009 Change 2010 2009 Change

FinancialRevenues Oil sales 253,723 169,687 50% 1,078,857 518,086 108%

Royalties (36,113) (16,820) 115% (116,482) (47,297) 146%

Interest income 473 15 3,053% 1,020 411 148%

218,083 152,882 43% 963,395 471,200 104%

Expenses Production 39,031 18,952 106% 112,854 65,738 72%

Purchased oil 12,703 - - 66,096 - -

Transportation 19,512 16,027 22% 91,193 53,537 70%

General and administrative and acquisition costs 8,022 4,076 97% 26,326 13,686 92%

Stock-based compensation 3,077 1,156 166% 11,580 5,167 124%

Interest 11,558 2,614 342% 25,898 11,534 125%

Foreign exchange loss (gain) (8,373) (2,143) 291% 7,758 9,346 (17%)

Depletion, depreciation and accretion 62,727 44,205 42% 271,590 177,780 53%

148,257 84,887 75% 613,295 336,788 82%

Income before taxes and NCI 69,826 67,995 3% 350,100 134,412 160%

Current taxes (recovery) (17,994) 2,752 - 35,574 10,234 248%

Future income taxes 36,537 10,488 248% 63,483 11,588 448%

Net income before NCI 51,283 54,755 (6%) 251,043 112,590 123%

Income applicable to NCI 18,134 18,387 (1%) 86,490 36,070 140%

Net income from discontinued operations 33,149 36,368 (9%) 164,553 76,520 115%

Cumulative loss on translation of Petrominerales

70,076 - - 70,076 - -

Total impact on net income (36,927) 36,368 - 94,477 76,520 23%

Operations Capital expenditures 164,760 86,566 90% 519,883 320,815 62%

Net realized prices ($/bbl) WTI 86.24 80.47 7% 81.87 70.57 16%

Sales price(1) 81.53 72.03 13% 75.62 63.11 20%

Transportation 6.60 6.80 (3%) 6.82 6.52 5%

Realized price 74.93 65.23 15% 68.80 56.59 22%

US$ discount as a percent of WTI 13% 19% (32%) 16% 18% (11%)

Reconciliation of changes in revenue Sales volume variance 38,858 68,010 (43%) 376,529 258,607 46%

Price variance 32,475 16,528 96% 115,903 (104,789) -

Oil revenue from third party oil purchases 12,703 - - 68,339 - -

$ change in revenue 84,036 84,538 (1%) 560,771 153,818 265%

% change in revenue 50% 99% (49%) 108% 42% 157%

Operating netback ($/bbl)(2)

Oil revenue(3) 74.93 65.23 15% 68.80 56.59 22%

Royalties 12.21 7.14 71% 8.72 5.76 51%

Production expenses 13.20 8.05 64% 8.45 8.01 5%

Operating netback 49.52 50.04 (1%) 51.63 42.82 21%

Average daily production – oil (bbls)(4) 33,142 24,555 35% 37,027 22,360 66%

(1) Excludes revenues associated from purchased oil.

(2) Non-GAAP measure. See “Non-GAAP Measures” section within this MD&A.

(3) Net of transportation expenses and excludes revenue from purchased oil.

(4) Actual production sold for the fourth quarter of 2010 was 32,138 bopd (Q4 2009 – 25,607 bopd), and for the year ended December 31, 2010 was 36,612 bopd (2009 – 22,490 bopd).

MD&A


Average Daily ProductionProduction for the fourth quarter and the year ended December 31, 2010 increased 35 and 66 percent, respectively, primarily due to drilling successes on

Petrominerales’ Guatiquia, Casimena and Neiva acreage, offset by natural production declines at Corcel and Orito.

Average Benchmark and Realized PricesThe majority of Petrominerales’ production is priced in relation to the Colombian Vasconia crude oil stream. The discount between Vasconia and

WTI narrowed from seven percent of WTI in 2009 to four percent in 2010, consistent with the general narrowing of heavy crude oil differentials. The

Company’s2010averagerealizedoilpriceof$68.80 perbarrelincreased22 percentmainlyduetoa16 percentincreaseinthebenchmarkWTIpriceand

thenarrowingoftheVasconiacrudediscounttoWTI.Thefourthquarterrealizedoilpriceof$74.93perbarrelincreased15percentduetoaseven percent

increase in WTI combined with lower Vasconia crude discount and lower pipeline and marketing fees.

The majority of Petrominerales’ oil production is trucked to various offloading stations for sale except for the Orito and Neiva fields that are connected to

pipelines.Transportationcostsincreasedto$6.60 per barrel,a37 percentincreaseinthefourthquartermainlyduetotruckingalargerportionofvolumes

to more distant offloading stations. Colombia has experienced significant growth in recent years. This has led to restricted capacity at certain offloading

stations and pipeline segments in the Llanos Basin.

RevenueOilrevenuein2010increased108 percentduetoa63 percentincreaseinsalesvolumesofproducedoiland22percentincreaseinrealizedcrudeoilprices.

Fourth quarter oil revenue increased 50 percent over the comparable quarter due to a 26 percent increase in sales volume of produced oil and an 15 percent

increase in crude oil prices.

RoyaltiesRoyalties increased 115 percent in the fourth quarter and 146 percent in the year primarily due to higher production and higher WTI prices combined with

the start of high price participation payments on Candelilla production in August 2010. As a result, royalties on a per barrel basis and as percentage

of realized oil prices increased in both the fourth quarter and the year.

Production ExpensesIn2010,productionexpensesincreased106percentduringthequarterand72 percentfortheyear,primarilyduetohigherproductionlevelsandincreased

perbarrelcosts.Onaperbarrelbasis,productionexpensesincreasedto$13.20andto$8.45 per barrelforthefourthquarterandtheyearended.The2010

increase is primarily related to higher water handling costs and a one-time cost at Orito charged by the field operator.

General and Administrative ExpensesThe increases in general and administrative expenses for the fourth quarter and the year was primarily due to higher staff levels, inflation in Colombia

combined with the appreciation of the Colombian Peso, office costs associated with Petrominerales’ expanding operations and professional fees associated

with Petrominerales’ Colombian stock exchange listing.

Stock-Based Compensation ExpensesThe 2010 expense increased over 2009 mainly due to higher grants during the year, combined with an increase in the fair value per grant as a result of a

higher Petrominerales stock price.

Interest Income and ExpenseIn 2010, interest income on cash and cash equivalents increased due to higher cash balances, specifically in the fourth quarter due to the proceeds received

from the US$550 million convertible debentures issued on August 25, 2010.

Interest expense for the fourth quarter and the year was higher mainly due to higher standby fees associated with the Company’s US$150 million secured

bank facility (effective December 30, 2009) and higher expenses from the US$550 million convertible debentures issued in August 2010.

Foreign Exchange Loss (Gain)TheColombianpesodevaluatedsixpercentrelativetotheU.S.dollarinthefourthquarter,from1,800:1atSeptember 30, 2010to1,914:1at

December31,2010.Thischangeinexchangeratesresultedinan$8.4 millionforeignexchangegainprimarilyonColombianpesodenominatedaccounts

payable and future income tax liabilities. During the year ended December 31, 2010, the Colombian peso appreciated six percent relative to the U.S. dollar

whichresultedina$7.8 millionforeignexchangeloss.ChangesintheColombianpesoexchangeratealsoimpactPetrominerales’U.S.dollardenominated

expenses and expenditures as approximately 65 percent of expenditures are incurred in Colombian pesos.

MD&A


Depletion, Depreciation and Accretion (“DD&A”) ExpenseDD&A expense in the fourth quarter increased 42 percent due to a 35 percent production increase and a 13 percent increase in the per barrel depletion

rate. On a per barrel basis, the depletion rate was higher due to higher finding and development costs related to proved reserves. For the year ended

December 31, 2010, DD&A expenses increased 53 percent mainly due to a 66 percent increase in production as the per barrel depletion rate was fairly

consistent with 2009.

Tax ExpensePetrominerales’ pre-tax income is subject to the Colombian statutory income tax rate of 33 percent. In addition, an equity tax is charged on equity

capitalizationlevelsinColombia.Petromineraleshadaneffectivetaxrateof26 percentinthefourthquarterof2010and28 percentfortheyear.The

effective tax rates are lower than the Colombian statutory income tax rate largely as a result of enhanced tax allowances for the acquisition of fixed assets

and immediate tax deductions available from the Company’s significant exploration program. The 2010 effective tax rates are higher than 2009 primarily

due to a lower rate for enhanced tax allowances (2010 rate was 30 percent, 2009 rate was 40 percent).

Net Income Attributable to Non-Controlling InterestThe net income attributable to NCI represents the NCI share of Petrominerales’ net income. The NCI share in Petrominerales averaged approximately

35 percent in the fourth quarter and 2010.

Capital ExpendituresExpenditures in the fourth quarter relate to facilities costs at the Corcel central processing facility to increase fluid handling, and installation of flow-

lines to connect Guatiquia production to the Corcel central processing facility. Petrominerales drilling and completion costs related to 14 wells in the

fourth quarter. Seismic costs in the quarter related to the acquisition of 233 square kilometres of 3D on the Guatiquia and Chiguiro Este Blocks. Other

expenditures include civil construction costs related to a number of exploration wells and other 2011 drilling locations.

Capital expenditures in 2010 include drilling and completions costs associated with 46 exploration and development wells and two water disposal wells,

facilities costs to expand the Corcel central processing facility to increase fluid handling capacity to 140,000 barrels of fluid per day, and facilities costs

associated with increasing fluid handling capacity as a result of various discoveries. Seismic costs include 3D seismic acquisition in the Corcel and Chiguiro

blocks in Colombia, and in Peru. Petrominerales also acquired an additional interest in Block 126 in Peru and began incurring costs related to the 2011

drilling program. Other costs include civil construction costs related to exploration wells.

CommitmentsThe following is a summary of the estimated costs required to fulfill the Company’s remaining contractual commitments as at December 31, 2010:

Type of Obligation < 1 Year 1-3 Years 3-5 Years Thereafter TotalHBU and Corporate

Office operating leases 3,533 9,018 9,391 15,237 37,179 Capital leases 838 1,159 583 - 2,580PetroBakken

Office operating leases 4,834 12,382 13,744 25,852 56,812 Drilling and completion rigs 8,605 17,701 6,902 - 33,208Total Company 17,810 40,260 30,620 41,089 129,779

Subsequent to December 31, 2010 PetroBakken entered into a sub-lease with a third party, which will result in the reduction of commitments between

2011 and 2015 by an estimated $5.5 million.

MD&A


Liquidity and Capital ResourcesPetrobank and PetroBakken manage their capital structure independently and generate their own cash flows, and have the ability to fund their operations

through the issuance of secured and unsecured debt as well as equity financing. The table below outlines the composition of Petrobank’s consolidated

capital structure and liquidity:

HBU andCorporate PetroBakken

PetrobankConsolidated

Working capital surplus (deficit) $ 1,942 $ (193,590) $ (191,648)Bank debt – principal $ - $ 829,788 $ 829,788Convertible debentures – principal amount (US$) $ - $ 750,000 $ 750,000Common share capital(1) $ 1,359,382 $ 3,147,238 $ 1,359,382Credit facility $ 200,000 $ 1,200,000

Available credit capacity $ 200,000 $ 370,212

(1) The common share capital of PetroBakken eliminates upon consolidation of these financial statements.

(2) In January 2011, Petrobank’s HBU and Corporate operating segment entered into a three year $200 million credit agreement with a syndicate of lenders.

HBU and CorporateAt December 31, 2010, independent of PetroBakken, Petrobank on a standalone basis had no bank debt outstanding and a working capital surplus of $1.9 million.

Petrobank manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying

assets. Petrobank considers its capital structure to include common share capital, convertible debentures, bank debt and working capital. In order to maintain or

adjust the capital structure, from time to time Petrobank may issue common shares or other securities, obtain project financing, sell assets or adjust our capital

spending to manage current and projected debt levels. Based on Petrobank’s current ownership and PetroBakken’s intentions of paying an annual dividend of

$0.96 per PetroBakken share, Petrobank expects to receive $105 million of dividends annually from PetroBakken, paid monthly. Petrobank can also raise funds by

selling a portion of our ownership in PetroBakken or by issuing additional debt secured by this interest.

Petrobank expects to satisfy ongoing working capital requirements with cash, available credit, and dividends received from PetroBakken.

PetroBakkenPetroBakken’s strategy is to provide a reasonable dividend yield to shareholders while delivering an accretive growth-oriented business plan. PetroBakken

is focused on securing appropriate levels of capitalization to support this business strategy.

AsatDecember31,2010,PetroBakkenhad$829.8millionofbankdebtdrawnona$1.2 billioncreditfacility.PetroBakken’screditfacilityiswitha

syndicate of banks and has an initial maturity date of June 3, 2011, extendable by the lenders for an additional year. If the lenders were to not extend

the term, the drawn amount would become due on June 3, 2012. A review of the facility was completed in the second quarter of 2010 and resulted in

a $100 million increase in the credit facility to $1.0 billion and a change from a borrowing base to covenant based facility with no semi-annual review.

In the fourth quarter the credit facility was increased by an additional $200 million to $1.2 billion. The amount of the facility is based on, among other

things, reserves, results from operations, current and forecasted commodity prices and the current economic environment. The credit facility provides that

advances may be made by way of direct advances, banker’s acceptances, or standby letters of credit/guarantees. Direct advances bear interest at the bank’s

prime lending rate plus an applicable margin for Canadian dollar advances, and at the bank’s U.S. base rate plus an applicable margin for U.S. dollar

advances. The applicable margin charged by the bank is based on a sliding scale ratio of PetroBakken’s debt to EBITDA. The facility is secured by a

$2.0 billion demand debenture and a securities pledge on the Company’s assets. The credit facility has financial covenants that limit the ratio of secured

debt to EBITDA to 3:1, limit the ratio of total debt (total debt defined as facility debt plus the value of outstanding debentures in Canadian dollars) to

EBITDAto4:1,andlimitsecureddebtto50%oftotalliabilitiesplustotalequity.PetroBakkenisincompliancewithallofthesecovenants.

OnJanuary25,2010,PetroBakkenissuedconvertibledebentureswithanannualcouponof3.125percentforgrossproceedsofUS$750million.The

convertibledebentureshaveafinancialcovenantthatlimitstheamountofsecurityandencumbrancesto35%ofPetroBakken’stotalassets.PetroBakkenis

in compliance with this covenant. Proceeds from the issuance of the convertible debenture were used to repay all outstanding bank debt. In February 2010,

PetroBakkenmadea$327.7millioncashpayment,includingrepaymentofbankdebt,fortheacquisitionofBerens.InMarch2010,PetroBakkenmadea

$104.7millioncashpayment,includingrepaymentofbankdebt,fortheacquisitionofRondo,andinApril2010,PetroBakkenmadeanet$141.2million

cash payment for the acquisition of Result. PetroBakken closed non-core property dispositions for net proceeds of $133.6 million.

(2)

(2)

MD&A


In addition to the financial resources noted above, other possible sources of funds available to PetroBakken include the following:

• Fundsflowfromoperations;

• Increasesundertheexistingcreditfacility;

• IssuanceofcommonsharesofPetroBakken;

• Issuanceofsubordinatedorconvertibledebt;

• Saleofproducingornon-producingassets.Cashgeneratedfromasalemaybereducedbyanyrequireddebtpayments;and

• Monetizationofriskmanagementassets.

PetroBakken expects to satisfy ongoing working capital requirements with funds flow from operations, cash and available credit.

Capital PlanHBU activity in 2011 will focus on: drilling and completion of the 10 well-pair expansion for the Kerrobert project; the initial development of the Dawson

project in the Peace River region of Alberta; additional resource evaluation, including oil sands evaluation wells and 3D seismic work which will further

identify the reservoir over the May River project area and finalize well placement and areas for future expansion; and procurement of long lead items for the

first phase of the May River project.

PetroBakken’s capital plan is focused on the development of Bakken and conventional Mississippian light oil properties in southeast Saskatchewan,

development of Cardium light oil properties in Central Alberta, exploration and development of the northeast British Columbia properties, and leveraging

our significant undeveloped land base into new resource opportunities.

Outstanding Share DataThe number of Petrobank shares outstanding at the date of this MD&A is 106,251,649, an increase of 15,316 shares from December 31, 2010, all of which

relates to the exercise of stock options.

Risks and UncertaintiesPetrobank is exposed to a variety of risks including, but not limited to: competitive, operational, political, environmental, and financial risks.

Commodity prices are the Company’s most significant financial risk. Crude oil prices are influenced by global supply and demand, OPEC policy and

worldwide political events. Natural gas prices in Canada are influenced primarily by North American supply and demand and to a lesser extent by local

market conditions. Weather events and conditions also play a major role in the supply and demand of both commodities. Fluctuations in commodity prices

not only affect the Company’s cash flows, but may also result in changes to the borrowing capacity under our credit facilities as assessed by the lenders.

Managementbelievesitisneitherappropriatenorpossibletoeliminate100%ofourexposuretofluctuationsincommodityprices.TheCompanymonitors

market conditions and may selectively utilize derivative instruments to reduce exposure to commodity price movements.

The Company is exposed to exploration risk. The volume of production from oil and natural gas properties generally declines as reserves are depleted, with

the rate of decline depending on reservoir characteristics. The Company’s proved reserves will decline as reserves are produced from its properties unless

it is able to acquire or develop new reserves. The business of exploring for, developing or acquiring reserves is capital intensive and is subject to numerous

estimates and interpretations of geological and geophysical data. There can be no assurance the Company’s future exploration, development and acquisition

activities will result in additional proved reserves. To manage this risk, we employ highly experienced geologists and geophysicists, use technology and 3D

seismic as primary exploration tools and focus our exploration efforts in known hydrocarbon producing basins.

The oil and gas industry is intensely competitive. Competition is particularly intense in the acquisition of prospective oil and gas properties, oil and gas

reserves, and land and resources. Competitors include companies larger than Petrobank, with greater access to financial resources. The Company’s future

success is driven, in large part, by our ability to find and exploit new oil and natural gas reserves at reasonable costs and reinvestment ratios. The process

of evaluating prospects and estimating oil and natural gas reserves is complex and subject to significant uncertainty. Actual operating results, including

production performance, will vary from those estimated, possibly materially. We mitigate these risks by maintaining a focused asset base with high working

interests and by hiring qualified professionals, including independent reserve engineers, with appropriate industry experience. Petrobank also competes

with other oil and gas companies in attempting to secure drilling rigs and other equipment necessary for drilling and completion of wells. Such equipment

may be in short supply from time to time. Similarly, equipment and other materials necessary to construct production and transmission facilities may be in

short supply from time to time.

We are exposed to a number of operational risks inherent in the industry including accidents, well blowouts, uncontrolled flows, labour strikes and

environmental risks. Operational risks are managed using prudent field operating procedures. We have detailed emergency response plans to deal

with potential incidents and maintain a comprehensive insurance program to reduce the risk of significant economic loss; however, not all risks can be

eliminated. Losses resulting from the occurrence of these risks could have a material adverse impact on our operations.

MD&A


We currently have operations only in Canada, but from time to time may evaluate projects internationally. To help mitigate the risks associated with

operating in foreign jurisdictions, we seek to operate in regions where the petroleum industry is a key component of the economy. Petrobank believes

that management’s experience operating both domestically and internationally helps reduce these risks. Some countries in which we may operate may be

considered politically and economically unstable. Operating internationally, the Company and our personnel may be subject to security risks, but through

effective security and social programs, Petrobank believes these risks can be effectively managed. It is difficult to obtain insurance coverage to protect

against terrorist incidents and as a result, the Company’s insurance program excludes this coverage. Consequently, terrorist incidents in the future could

have a material adverse impact on our operations.

Petrobank’s THAI® projects entail risks incremental to those of conventional oil and gas operations. Although other operators have utilized the individual

processes involved in the THAI® technology in the past, the technology’s configuration of wells, processes and operating procedures is a new combination,

and thus Petrobank is subject to unknown operational risks. Other risks associated with the project include: the THAI® technology will prove unsuccessful

or commercially unviable; and, unknown future regulatory or commodity market factors will make the technology uneconomic. However, management

believes that the technology can be a step change in heavy oil and insitu oil sands recovery technology and would address many of the existing risks and

economic challenges currently facing the oil sands industry in Canada and heavy oil industry globally.

The Company is subject to extensive governmental and environmental approvals and regulations in its operating jurisdictions. Before proceeding with

most major development projects, Petrobank must obtain regulatory approvals and maintain the approval in good standing over the course of the project.

The regulatory approval process involves stakeholder consultation, environmental impact assessments and public hearings, among other factors. Failure

to obtain regulatory approvals, or failure to obtain them on a timely basis, could result in project delays, abandonment, or restructuring of projects and

increased costs, all of which could negatively impact future earnings and cash flow. Failure to maintain approvals, licenses, permits and authorization in

good standing could result in the imposition of fines, production limitations or suspension orders.

Environmental risks and hazards inherent in the oil and gas industry are subject to increasingly stringent legislation and regulation. Compliance with

such legislation and regulation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may

be material. The Company operates in accordance with all relevant environmental legislation and strives to minimize the environmental impact of its

operations by providing for safety and environmental issues in all of its business plans.

Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially

increased capital expenditures and operating costs. There has been much public debate with respect to Canada’s alternative strategies with respect to climate

change and the control of greenhouse gases. Implementation of strategies for reducing greenhouse gases could have a material impact on the nature of

oil and gas operations, including those of the Company. Given the evolving nature of the issues related to climate change and the control of greenhouse

gases and resulting requirements, it is not possible to predict either the nature of those requirements or the impact on the company and its operations and

financial condition.

The Company’s operations are subject to political and economic uncertainties. Specifically, governments may change royalties and taxes which could have a

material adverse impact on the economics of the Company’s oil and gas activities.

Petrobank is exposed to normal financial risks inherent within the oil and gas industry, including commodity price risk, exchange rate risk, interest rate

riskandcreditrisk.Managementbelievesitisneitherappropriatenorpossibletoeliminate100%oftheCompany’sexposuretotheserisks.Asdescribedin

Note 13 to the consolidated financial statements, the Company monitors market conditions and may periodically utilize derivative instruments to mitigate

these risks.

The Company is exposed to exchange rate risk to the extent revenues and expenditures denominated in or strongly linked to the U.S. dollar are not

equivalent to the Canadian dollar. Revenues in Canada are largely determined by U.S. dollar reference prices. The Company is not currently using

exchange rate derivatives to manage exchange rate risks.

Petrobank is exposed to fluctuations in short-term interest rates on amounts drawn under its floating-rate bank facilities. The Company monitors market

conditions and may selectively utilize derivative instruments to reduce exposure to interest rate movements.

In connection with the spin-off of Petrominerales, the Company received a tax ruling from the Canada Revenue Agency which confirmed the spin-off was

non-taxable to Petrobank. However, there are a number of constraints in the Income Tax Act (Canada), which, if breached, could cause the spin-off to be

re-characterized as a taxable transaction. These rules continue to have potential application even now, after the spin-off has been completed.

In addition to the foregoing risks, readers are directed to the section entitled, “Risk Factors” in the Company’s AIF.

MD&A


Sensitivities The Company’s earnings and cash flow are sensitive to changes in crude oil and natural gas prices, exchange rates and interest rates.

The following factors demonstrate the expected impact on annualized before tax funds flow from operations excluding the effect of hedging for 2011:

Change of: (millions)PetroBakken

Crude oil US$1.00/bbl WTI reference price (assuming 35,000 bopd) 1,000 bopd of production @ US$85/bbl WTI

$ 9.7 $ 21.4

Natural gas $1.00/Mcf AECO reference price (assuming 39 MMcf/d) 10.0 MMcf per day of production @ $4.00/Mcf AECO

$ 12.2 $ 11.9

Currency US$0.01 in exchange rate $ 8.5Interest rate 1% change in interest rate $ 5.3

Critical Accounting Policies and EstimatesThe Company’s financial statements are prepared in accordance with Canadian GAAP, which require management to make judgements, estimates and

assumptions, which may have a significant impact on the financial statements. A summary of the Company’s significant accounting policies can be found

in Note 2 to the Company’s 2010 consolidated financial statements. The following is a discussion of those accounting policies and estimates that are

considered critical in the determination of the Company’s financial results.

Capital Assets — Full Cost Accounting

The Company follows the full cost method of accounting as described in Note 2 to the consolidated financial statements. Alternatively, the Company could

follow the successful efforts method of accounting whereby all costs related to non-productive wells are expensed in the period in which they are incurred.

Operating costs, net of revenues in relation to activities that are considered to be in the development stage, are capitalized. Judgement is required to

determine whether operations are in the development stage. The factors considered include whether commercially viable production levels have been

achieved on a consistent basis. Once the operations are no longer considered to be in the development stage, revenue is recognized and operating costs are

recorded in net income during the year.

Under the full cost method of accounting, capitalized costs are subject to a country-by-country cost centre impairment test. Under the successful efforts

method of accounting, the costs aggregated on a property-by-property basis and the carrying value of each property is subject to an impairment test. These

policies may result in a different carrying value for capital assets and a different net income. The Company has elected to follow the full cost method and it

is the method most commonly followed in Canada.

Under full cost accounting, a limit is placed on the carrying value of the net capitalized costs in each cost centre in order to test impairment. Impairment

exists when the carrying value of developed properties of a cost centre exceeds the estimated undiscounted future net cash flows associated with the cost

centre’s proved reserves. Costs relating to undeveloped properties are subject to individual impairment assessments until it can be determined whether

or not proved reserves exist. If impairment is determined to exist, the costs carried on the balance sheet in excess of the discounted future net cash flows

associated with the cost centre’s proved plus probable reserves are charged to net income.

Goodwill

Goodwill is tested for impairment whenever an event or circumstance occurs that may reduce the fair value of a business unit below its carrying amount,

and at least annually. If goodwill is impaired the carrying value is reduced to the estimated fair value and an impairment loss is recorded in net income.

MD&A


Reserve Estimates

Reserve estimates can have a significant impact on net income and the carrying value of capital assets. The process of estimating reserves requires significant

judgement based on available geological, geophysical, engineering, and economic data, projected rates of production, estimated commodity price forecasts

and the timing of future expenditures, all of which are subject to interpretation and uncertainty. Reserve estimates impact net income through depletion

expense and the application of impairment tests. Revisions or changes in reserve estimates can have either a positive or a negative impact on net income and

can impact the carrying amount of capital assets.

The Company’s lenders also use reserve estimates to assess the borrowing bases under the secured bank credit facilities. Changes to the reserve estimates

can result in increases or decreases to the borrowing bases, which may impact the Company’s financial position.

Asset Retirement Obligations

The Company recognizes the estimated fair value of future retirement obligations associated with capital assets as a liability. The Company estimates the

liability based on the estimated costs to abandon and reclaim its net ownership in tangible long-lived assets such as wells and facilities and the estimated

timing of the costs to be incurred in future periods. Actual payments to settle the obligations may differ from estimated amounts.

Convertible Debentures

Upon issuance, the Company’s convertible debentures are classified into equity and financial liability components on the balance sheet. The financial

liability component is recorded at fair value, and the equity component is the residual between the net proceeds and the financial liability component. The

financial liability, net of issuance costs, is accreted, which is included within interest expense over the life of the debentures using the effective interest rate

method. The equity component represents the fair value of the conversion right granted to the holder, which remains a fixed amount over the term of the

related debentures. Where the Company’s subsidiary has issued convertible debentures, the fair value of the conversion right is presented within NCI in the

consolidated balance sheet.

Upon conversion of Petrobank debentures into common shares by the holders, the debt and equity components are transferred to common share capital,

while debentures issued by Petrobank’s subsidiaries are transferred to NCI.

Upon repayment of Petrobank debentures in cash, the debt component is derecognized and the equity portion transferred to contributed surplus. If

Petrobank settles the debt portion through the issuance of shares, the redemption value of the debt portion is credited to share capital. Upon repayment of

any of Petrobank’s subsidiaries debentures in cash, the debt component is derecognized with no adjustment to NCI.

Future Income Taxes

The Company recognizes a future income tax liability based on estimates of temporary differences between the book and tax value of its assets. An estimate

is also used for both the timing and tax rate upon reversal of the temporary differences. Actual differences and timing of the reversals may differ from

estimates, impacting the future income tax balance and net income.

Changes in Accounting PoliciesThere have been no changes to the Company’s critical accounting policies and estimates in the three and twelve months ended December 31, 2010.

International Financial Reporting Standards

InFebruary2008,theCICA’sAccountingStandardsBoardconfirmedtheconvergenceofCanadianGAAPwithInternationalFinancialReporting

Standards (“IFRS”) will be required for interim and annual financial statements effective for fiscal years beginning on or after January 1, 2011, including

comparatives for 2010 and an opening balance sheet at January 1, 2010 showing the changes from Canadian GAAP to IFRS.

IFRS uses a conceptual framework similar to Canadian GAAP, but prescribes certain differences for recognition, measurement and disclosure principles

which are outlined below under “Potential Impacts of IFRS Adoption”.

PetrobankcommenceditsIFRSConversionProjectinlate2008bycompletinganinitialscopingphase,andhasestablishedaprojectplanandproject

team, which includes key finance staff, management, external advisors and the audit committee.

MD&A


The Company’s project plan broken out by accounting policies and procedures, financial statement preparation, training and communication, business

impacts, IT systems and control environment is as follows:

Key Activity Milestones ProgressAccounting policies and procedures:

• Identify differences between Canadian GAAP and IFRS.

• Revise and finalize accounting policies under IFRS.

• Identify potential adjustments to initial and subsequent IFRS financial statements.

• Senior management approval and audit committee review of policy decisions by Q4 2010.

• Approval of IFRS policies and opening balance sheet by senior management to be completed during Q4 2010.

• Accounting policy alternatives have been analyzed and recommendations made for all key accounting policy decisions. These accounting policies have been approved by management and were reviewed by the audit committee during Q4 2010.

• Draft opening balance sheet and transition note disclosure has been prepared and were reviewed by the audit committee during Q4 2010. Final approvals will be completed in Q1 2011.

Financial statement preparation:

• Prepare first-time adoption reconciliation required under IFRS 1.

• Prepare financial statements and note disclosures in compliance with IFRSs.

• Quantify the effects of converting to IFRS.

• Senior management approval and audit committee review of pro forma financial statements by Q4 2010.

• Draft opening balance sheet and transition note disclosure has been prepared and were reviewed by the audit committee during Q4 2010. Final approvals will be completed in Q1 2011.

• IFRS compliant financial statements and notes have been prepared.

Training and communication:

• Develop and deliver targeted IFRS training to employees and management.

• Ensure internal and external stakeholders receive ongoing appropriate communications.

• Training to be provided to relevant employees prior to changeover date.

• Impacts of converting to IFRS communicated prior to changeover.

• Key employees involved with implementation have completed training throughout the year.

• Quarterly disclosure of project status in MD&A.

• Policy decisions are being communicated to individuals affected and additional training is being provided as required.

Business impacts:

• Identify impacts of conversion on contracts including financial covenants and compensation arrangements.

• Identify impacts of conversion on taxation.

• Impacts of contracts identified.

• Taxation impacts identified by Q4 2010.

• Adoption of IFRS is not expected to have a significant impact on current contracts.

• Analysis of taxation impacts is currently underway by individuals experienced with taxation.

IT systems:

• Identify changes required to IT systems and implement solutions.

• Implement solution for capturing financial information under Canadian GAAP and IFRS during the year of transition to IFRS.

• Necessary changes to IT systems implemented by changeover date.

• Solution for capturing financial information under multiple sets of accounting principles implemented by Q4 2010.

• Required changes to IT systems are identified and tracked as IFRS work progresses.

• Work has been completed on transitioning our current system to run IFRS for the first quarter of 2011.

Control environment:

• For all changes to policies and procedures identified, assess effectiveness of internal controls over financial reporting and disclosure controls and procedures and implement any necessary changes.

• Internal controls over IFRS changeover process in place and tested prior to changeover.

• Relevant internal controls are being assessed as work progresses.

• Specific controls have been established in relation to the IFRS changeover process.

MD&A


Significant differences that have been identified between Canadian GAAP and IFRS that will impact Petrobank and its subsidiaries are: property,

plant and equipment, exploration and evaluation assets, depletion and depreciation, impairment testing, share based payments, financial instruments

and decommissioning liabilities, as well as increased disclosure requirements. The majority of adjustments required on transition to IFRS will be made

retrospectively against opening retained earnings at the date of transition. Certain IFRS standards may be modified, and as a result, the impact may

be different than Petrobank’s current expectations. The project team is currently determining the financial statement impact of these standards on the

consolidated financial statements.

First-time Adoption of IFRSs (“IFRS 1”)The transition to IFRS requires the Company to apply IFRS 1, which prescribes requirements for preparing IFRS-compliant financial statements in the

first reporting period after the changeover date (January 1, 2010). IFRS 1 includes a requirement for retrospective application of each IFRS as if they were

always in effect. IFRS 1 also mandates certain exemptions for retrospective application and provides optional exemptions from retrospective application to

ease the transition to IFRS in the transition year. The most significant IFRS 1 exemptions that are expected to apply to the Company upon adoption are

summarized in the following table:

Area of IFRSs Summary of Exemption AvailableProperty, Plant and Equipment • In July 2009, the International Accounting Standards Board approved amendments and

released “Additional Exemptions for First-time Adopters” which prescribes transitional exemptions for oil and gas companies following full cost accounting. The amendment allows an entity that used full cost accounting under Canadian GAAP to elect, at its time of adoption, to measure exploration and evaluation assets at the amount determined under the Canadian GAAP and to measure oil and natural gas assets in the development or production phases by allocating the amount determined under Canadian GAAP for those assets to the underlying assets pro rata using reserve volumes or reserve values as of the date of transition, subject to an impairment test as prescribed under IFRS. This exemption will allow Petrobank to apply IFRS to its full cost pools on a prospective basis, from date of transition to IFRS.

• The Company expects to utilize the exemption and elect on date of transition to report items of property, plant and equipment at cost and expects to allocate property, plant and equipment pro rata using reserve values.

Share-Based Payments • The Company may elect to not apply IFRS 2, “Share-Based Payments”, to equity instruments which vested before the Company’s date of transition to IFRS.

• The Company expects to elect to not apply IFRS 2 to equity instruments granted which vested before the Company’s date of transition to IFRS.

MD&A


Expected Areas of SignificanceThe key areas where we expect accounting policies may differ and where accounting policy decisions are necessary that may impact the Company’s

consolidated financial statements are set out in the following table. The following transition impacts are estimates and may not reflect the actual IFRS

adjustment. The following transition impacts will also result in an adjustment to the balance in future income tax on transition.

Accounting Policy Area Impact of Policy AdoptionImpairment of Assets (“IAS 36”)

• IFRS uses the concept of cash generating units to accumulate asset carrying costs to test and measure impairment. IFRS will require impairment testing to be performed at the cash generating unit level, which is lower than the current cost center level. In addition, IAS 36 uses a one-step approach for testing and measuring asset impairments, with asset carrying values being compared to the higher of: value-in-use and fair value less costs to sell. Value in use is defined as the amount equal to the present value of future cash flows expected to be derived from the asset. In the absence of an active market, fair value less costs to sell may also be determined using discounted cash flows. The use of discounted cash flows under IFRS to test and measure asset impairment differs from Canadian GAAP, which uses undiscounted cash flows to test and measure impairment. This may result in more frequent write-downs in the carrying amounts of assets under IFRS because the asset carrying amounts previously supported under Canadian GAAP were based on undiscounted cash flows. However, under IAS 36, impairment losses that were previously recognized may be reversed where circumstances change such that the impairment is reduced. This differs from Canadian GAAP, which prohibits the reversal of previously recognized impairment losses.

• Petrobank expects to record an adjustment of between $200 and $250 million on its HBU assets on the adoption of IFRS and in accordance with its policy under IFRS 6, “Exploration and Evaluation Expenditures”, and IAS 36.

• PetroBakken expects that the adoption of IAS 36 along with the adoption of IFRS 5, “Non-current Assets held for Sale and Discontinued Operations”, will result in impairment on the Alberta non-core divestiture packages. As management had a plan in place to dispose of the packages prior to December 31, 2009 these assets would be considered assets held for sale under IFRS. As the assets no longer have a value in use the recoverable amount is required to be measured at the fair value less costs to sell. The fair value less costs to sell was lower than the carrying value which is expected to result in impairment under IAS 36. The impairment amount is expected to be approximately $50 million with the adjustment recorded to retained earnings. The remaining amount related to the assets held for sale at January 1, 2010, expected to be approximately $140 million, was reclassified to a separate line item on the balance sheet from exploration and evaluation assets and property, plant and equipment.

Exploration and Evaluation Expenditures (“IFRS 6”)

• Oil and gas companies are required to account for exploration and evaluation expenditures in accordance with IFRS 6, which permits a number of accounting policy choices. For example, this standard addresses the recognition, measurement, presentation and disclosure requirements for costs incurred in the exploration phase. Unlike Canadian GAAP, IFRS requires the identification and presentation of exploration and evaluation expenditures to be separated from developed and producing assets. In addition, Petrobank will be required to perform an impairment test on exploration and evaluation expenditures when there is a determination that the expenditures have resulted in a technically feasible and commercially viable project. At that time, the expenditures would be tested for impairment, and then transferred to the developed and producing assets category.

• The Company will adopt the IFRS 1 exemption which will allow the value of the exploration and evaluation assets to be consistent with the Canadian GAAP historical net book value.

• Upon adoption date, all HBU assets will be in the exploration and evaluation phase. The value of PetroBakken’s exploration and evaluation assets is expected to be approximately $680 million, which primarily consists of undeveloped land. IFRS 6 will also result in additional disclosures in the notes to the consolidated financial statements.

MD&A


Property, Plant, and Equipment (“IAS 16”)

• IFRS and Canadian GAAP contain the same basic principles of accounting for property, plant and equipment. However IAS 16 requires costs recognized as property plant and equipment to be allocated to the significant components of the asset and to amortize each significant component separately. This is a departure from Canadian GAAP for full cost oil and gas companies, and may increase the number of components to be amortized separately, and could impact the amount of amortization expense. Under Canadian GAAP, depletion of oil and natural gas assets is required to be calculated using proved reserves. Under IFRS, there is no guidance as to what reserve basis should be used for depletion. Under IAS 16, companies have the choice to account for property, plant and equipment under the cost model, or the revaluation model.

• It is expected that Petrobank will choose and apply the cost model to account for its property, plant and equipment after transition to IFRS; therefore, there is not expected to be a transition impact of adoption of IAS 16.

• It is expected Petrobank will deplete oil and natural gas assets using proved plus probable reserves. This has no impact on transition but will result in lower depletion going forward.

Decommissioning Costs (“IAS 37”)

• Under IFRS, the recognition criteria for contingent liabilities are much more explicit than Canadian GAAP and may potentially require the booking of additional liabilities associated with the asset retirement obligations of the Company’s oil and gas assets than under Canadian GAAP. Liabilities for decommissioning and restoration are recognized for both legal and constructive obligations. At a reporting period when there is a change in the current market discount rate, IFRS requires retroactive adjustment to the estimated liability, whereas under Canadian GAAP all adjustments are made on a prospective basis.

• Changes in the estimated timing of cash flows necessary to discharge the obligation are added to or deducted from the cost of the related asset and the adjusted amounts are amortized prospectively over the estimated useful life of the asset.

• In addition, the unwinding of the discount arising from the passage of time is recognized as a financing cost and not a part of depletion expense as is currently presented in the Company’s financial statements under Canadian GAAP.

• Under Canadian GAAP the discount rate used to measure the asset retirement obligation is the credit-adjusted risk free interest rate. The risk free rate will be used by the Company under IFRS, which will result in an increase to the HBU’s asset retirement obligation of approximately $4 million, and an increase to PetroBakken’s asset retirement obligation of approximately $65 million, with the adjustment recorded to retained earnings. A portion of the asset retirement obligation relates to the PetroBakken Alberta non-core divestiture package and therefore under IFRS will be considered a liability held for sale. This amount will be reclassified to a separate line on the balance sheet and is expected to be approximately $15 million.

Financial Instruments (“IAS 32”)

• Under IFRS, convertible bonds with a cash settlement option are considered to have a financial derivative component embedded within the host debt contract. As a result, the conversion option has to be accounted for as a derivative financial liability under IFRS, as opposed to as equity in accordance with Canadian GAAP. The derivative must be recorded at fair value each period, with changes recorded through profit and loss. A derivative financial liability of between $200 and $250 million is expected to be recorded at transition.

Regulatory PoliciesCertification of Disclosures in Annual Filings

In accordance with Multilateral Instrument 52-109 of the Canadian Securities Administrators, the Company annually issues a “Certification of Annual

Filings” (“Certification”). The Certification requires certifying officers to state that they are responsible for establishing and maintaining disclosure controls

and procedures (“DC&P”) and internal control over financial reporting (“ICFR”).

The Certification requires certifying officers to state that they designed DC&P, or caused it to be designed under their supervision, to provide reasonable

assurance that: (i) material information relating to Petrobank is made known to the certifying officers by others; (ii) information required to be disclosed by

Petrobank in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods

specified under Canadian securities legislation. In addition, the Certification requires certifying officers to state that they have designed ICFR, or caused

it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial

statements for external purposes.

The certifying officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company’s DC&P and ICFR and, based

on such evaluation, concluded that the Company maintained effective DC&P and ICFR as of December 31, 2010.

OutlookIn addition to the plans discussed in this MD&A, please see the Company’s and PetroBakken’s recent news releases and 2010 Annual Reports which are

expected to be released in April 2011.

Financial Statements


Management’s ReportManagement is responsible for the integrity and objectivity of the information contained in this report and for the consistency between the consolidated

financial statements and other financial and operating data contained elsewhere in this report. The accompanying consolidated financial statements have

been prepared by management in accordance with accounting principles generally accepted in Canada using estimates and careful judgement, particularly

in those circumstances where transactions affecting a current period are dependent upon future events. The accompanying consolidated financial

statements have been prepared using policies and procedures established by management and fairly reflect the Company’s financial position, results of

operations and changes in financial position, within Canadian generally accepted accounting principles. Management has established and maintains a

system of internal controls that is designed to provide reasonable assurance that assets are safeguarded from loss or unauthorized use and the financial

information is reliable and accurate.

The Company’s external auditors, Deloitte & Touche LLP, have examined the consolidated financial statements. Their examination provides an

independent view as to management’s discharge of its responsibilities insofar as they relate to the fairness of reported financial results and the financial

condition of the Company.

The Audit Committee of the Board of Directors has reviewed in detail the consolidated financial statements with management and the external auditors.

The Audit Committee has reported its findings to the Board of Directors who have approved the consolidated financial statements.

John D. Wright Peter Cheung

President & Chief Executive Officer Vice President Finance & Chief Financial Officer

Calgary, Canada

March 14, 2011



Independent Auditor’s Report

To the Shareholders of Petrobank Energy and Resources Ltd.:We have audited the accompanying consolidated financial statements of Petrobank Energy and Resources Ltd. (the “Company”), which comprise the

consolidated balance sheets as at December 31, 2010 and 2009, and the consolidated statements of operations and retained earnings, comprehensive

income and cash flow for the years then ended, and the notes to the consolidated financial statements.

Management’s Responsibility For The Consolidated Financial StatementsManagement is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally

accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial

statements that are free from material misstatement, whether due to fraud or error.

Auditor’s ResponsibilityOur responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with

Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to

obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The

procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial

statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and

fair presentation of the consolidated 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 consolidated

financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

OpinionIn our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at

December 31, 2010 and 2009 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally

accepted accounting principles.

“Deloitte & Touche LLP”

Chartered Accountants

March 14, 2011

Calgary, Alberta



Consolidated Balance Sheets(Thousands of Canadian dollars)As at December 31, 2010 2009AssetsCurrent assets

Cash and cash equivalents $ 17,468 $ 71,026

Accounts receivable 163,311 145,849 Prepaid expenses 12,027 18,182 Risk management assets (Note 13) 2,231 - Future income tax asset (Note 10) 3,455 782 Assets of discontinued operations (Note 18) - 125,694

198,492 361,533

Capital assets (Note 3) 4,685,461 3,723,543 Goodwill (Note 4) 1,518,633 1,060,981 Assets of discontinued operations (Note 18) - 620,511 Total assets $ 6,402,586 $ 5,766,568Liabilities and Shareholders’ EquityCurrent liabilities Accounts payable and accrued liabilities $ 376,012 $ 370,379 Current portion of capital lease obligations (Note 13) 838 - Risk management liabilities (Note 13) 12,682 2,694 Future income tax liabilities (Note 10) 608 - Liabilities of discontinued operations (Note 18) - 191,946

390,140 565,019

Bank debt (Note 6) 824,845 748,185Convertible debentures (Note 7) 567,140 348,957Capital lease obligations (Note 13) 1,831 -Other long-term liabilities 5,170 3,961Asset retirement obligations (Note 9) 66,252 62,059Risk management liabilities (Note 13) 2,597 3,442Future income tax liabilities (Note 10) 533,350 443,181Liabilities of discontinued operations (Note 18) - 46,452Total liabilities 2,391,325 2,221,256Commitments and contingencies (Note 16)Shareholders’ equity Petrobank shareholders’ equity Common shares (Note 5) 1,359,382 880,183 Convertible debentures (Note 7) - 76,811 Contributed surplus (Note 5) 37,516 33,436 Paid-in capital (Note 5) 840,772 747,029 Paid-in capital related to discontinued operations (Note 5) - 128,895 Accumulated other comprehensive loss (Note 5) - (29,894) Retained earnings 217,017 455,344 Total Petrobank shareholders’ equity 2,454,687 2,291,804 Non-controlling interest (“NCI”) (Note 11) 1,556,574 1,069,805 NCI of discontinued operations (Note 1) - 183,703Total shareholders’ equity 4,011,261 3,545,312Total liabilities and shareholders’ equity $ 6,402,586 $ 5,766,568

Subsequent events (Notes 6, 12 and 16)

See accompanying notes to these consolidated financial statements.

Signed on behalf of the Board:

John D. Wright Ian S. Brown

Director Director



Consolidated Statements Of Operations And Retained Earnings(Thousands of Canadian dollars, except per share amounts)Years ended December 31, 2010 2009

Revenues Oil and natural gas $ 1,008,556 $ 575,588

Royalties (142,064) (82,151)

Loss on risk management contracts (Note 13) (8,426) (17,969)

Interest income 101 224

858,167 475,692

Expenses Production 124,481 70,913

Transportation 15,270 8,820

General and administrative 41,865 19,353

Acquisition (Note 4) 1,286 19,155

Stock-based compensation 32,393 24,924

Interest (Note 8) 77,511 32,013

Foreign exchange gain (28,310) (56,648)

Depletion, depreciation and accretion 526,059 304,125

790,555 422,655

Income from continuing operations before taxes and NCI 67,612 53,037

Future income tax expense (recovery) (Note 10) 28,117 (27,541)

Net income from continuing operations 39,495 80,578

Less: Net income attributable to NCI (Note 11) 18,187 12,019

Net income from continuing operations attributable to Petrobank shareholders 21,308 68,559

Net income from discontinued operations (net of tax of $99.1 million for 2010, $14.2 million for 2009) (Note 18) 164,553 76,520

Cumulative loss on translation of Petrominerales’ financial statements (Note 5) (70,076) -

Net income attributable to Petrobank shareholders 115,785 145,079

Retained earnings, beginning of year 455,344 334,410

Conversion of convertible debentures, net of tax (Note 7) (59,011) (24,145)

Spin-off of Petrominerales (Note 1) (295,101) -

Retained earnings, end of year $ 217,017 $ 455,344

Earnings per share (Note 5) Basic earnings from continuing operations $ 0.20 $ 0.77

Basic earnings from discontinued operations $ 0.91 $ 0.87

Basic earnings per share $ 1.11 $ 1.64

Diluted earnings per share from continuing operations $ 0.20 $ 0.73

Diluted earnings per share from discontinued operations $ 0.83 $ 0.79

Diluted earnings per share $ 1.03 $ 1.52


Consolidated Statements Of Comprehensive Income(Thousands of Canadian dollars)Years ended December 31, 2010 2009

Net income attributable to Petrobank shareholders $ 115,785 $ 145,079

Other comprehensive income:

Unrealized loss on translation of Petrominerales’ financial statements (Note 5) - (72,742)

Comprehensive income attributable to Petrobank shareholders $ 115,785 $ 72,337




Consolidated Statements Of Cash Flow(Thousands of Canadian dollars)Years ended December 31, 2010 2009Operating Activities Net income attributable to Petrobank shareholders $ 115,785 $ 145,079 Net income from discontinued operations (164,553) (76,520) Cumulative loss on translation of Petrominerales 70,076 - Depletion, depreciation and accretion 526,059 304,125 Unrealized loss on risk management contracts (Note 13) 8,204 41,941 Unrealized foreign exchange gain (43,057) (61,063) Stock-based compensation 32,393 24,924 Accretion on convertible debentures 27,036 5,873 Net income attributable to NCI 18,187 12,019 Future income tax expense (recovery) 28,117 (27,541) Realized foreign exchange loss related to financing (Note 7) 18,184 - Amortization of deferred financing costs and other assets 4,851 4,565 Acquisition related expenses (Note 4) - 8,585 Asset retirement obligations settled (Note 9) (4,528) (1,971) 636,754 380,016 Changes in non-cash working capital (Note 15) (80,775) 23,909 Net cash provided by operating activities from continuing operations 555,979 403,925 Net cash provided by operating activities from discontinued operations 602,115 311,889

1,158,094 715,814Financing Activities Issuance (repayment) of bank debt (16,845) 88,518 Early conversion of convertible debentures – including costs (Note 7) (29,317) (36,244) Issuance (repurchase) of convertible debentures – net of costs 769,651 452,837 Financing costs relating to bank debt (2,250) (11,638) Dividends paid by PetroBakken (177,205) (41,246) Issuance (repurchase) of common shares (22,890) 14,324 Realized loss on foreign exchange contract (Note 7) (18,184) - Amortization of obligations under gas sale contract (827) (827) Changes in non-cash working capital (Note 15) (628) 16,143 Net cash provided by financing activities from continuing operations 501,505 481,867 Net cash provided by financing activities from discontinued operations 552,117 (20,019)

1,053,622 461,848Investing Activities Expenditures on capital assets (933,363) (470,042) Acquisitions (Note 4) (482,749) (607,042) Proceeds from dispositions (Note 4) 133,632 178,849 Dividends received by Petrobank 129,878 26,352 Spin-off of Petrominerales (Note 18) (719,369) - Sale of interest in Petrominerales - 106,107 Changes in non-cash working capital (Note 15) 41,563 (50,522) Net cash provided by investing activities from continuing operations (1,830,408) (816,298) Net cash provided by investing activities from discontinued operations (471,874) (328,723)

(2,302,282) (1,145,021)Effect of exchange rate changes on cash and cash equivalents (27,481) 693Net change in cash and cash equivalents (118,047) 33,334

Cash and cash equivalents, beginning of year 135,515 102,181Cash and cash equivalents, end of year $ 17,468 $ 135,515Cash and cash equivalents consist of:Continuing operations Cash $ 7,438 $ 33,231 Cash equivalents $ 10,030 $ 37,795Discontinued operations Cash $ - $ 5,378 Cash equivalents $ - $ 59,111


Notes


Notes To The Consolidated Financial StatementsAs at and for the years ended December 31, 2010 and 2009

(All tabular amounts are expressed in thousands of Canadian dollars, except share amounts or as otherwise noted)

Note 1 – Formation of the Company and Basis of PresentationPetrobank Energy and Resources Ltd. (the “Company” or “Petrobank”) is a public company listed on the Toronto Stock Exchange and incorporated under

the Business Corporations Act (Alberta). Petrobank is engaged in the exploration for and development and production of oil and natural gas in the Western

Canadian Sedimentary Basin.

During 2010, the Company was comprised of three business units: the Heavy Oil Business Unit (“HBU”), PetroBakken Energy Ltd. (“PetroBakken”

or “PBN”), which in previous years and quarters was described as the Canadian Business Unit (“CBU”), and Petrominerales Ltd. (“Petrominerales”), which

in previous years and quarters was described as the Latin American Business Unit (“LABU”). Where segmented information is provided throughout these

financial statements, the HBU is combined with activities performed at the Petrobank corporate level.

The HBU is operating the Kerrobert heavy oil project and Conklin oil sands project using Petrobank’s patented THAI® technology. The Kerrobert and

Conklin projects are in the pre-operating stage and accordingly all expenses, net of revenues, are capitalized.

PetroBakken,59%ownedbyPetrobankasatDecember 31, 2010,isfocusedonconventionaloilandgasoperationsthroughoutwesternCanadawitha

primary focus on light oil developments from the Bakken formation in southeast Saskatchewan and in the Cardium play in Alberta. Petrobank results

include100%oftheresultsofPetroBakken;theminorityinterestshare,whichPetrobankdoesnotown,isrecordedasincomeattributabletoNCIonthe

consolidated statements of operations and retained earnings and as paid-in capital and NCI on the consolidated balance sheets. Results for PetroBakken

are reported on a continuity of interest basis and as such incorporate Petrobank’s CBU operations for the periods prior to the formation of legal subsidiary

PetroBakken Energy Ltd. (TSX: PBN) in October 2009.

Petrominerales is focused on oil exploration and production in Colombia and Peru. On December 31, 2010, Petrobank and Petrominerales (TSX: PMG),

completed a corporate reorganization which resulted in Petrobank shareholders receiving Petrobank’s proportionate interest in Petrominerales. Pursuant

to this spin-off, a new Alberta corporation was formed (“New Petrominerales”) which acquired all the outstanding shares of Petrominerales. Petrobank

shareholders received 0.6142 shares of New Petrominerales and one replacement common share of Petrobank for each Petrobank common share held.

Petrobank has no continuing involvement in this business unit subsequent to the spin-off. As such, the results of operations of Petrominerales are presented

as discontinued operations in the accompanying Consolidated Statements of Operations for all periods prior to the spin-off. Unless otherwise noted, all

disclosures in the notes accompanying the Consolidated Financial Statements reflect only continuing operations.

Assets and liabilities of Petrominerales, including NCI, were derecognized by Petrobank at carrying value on the date of the spin-off transaction. No gain

or loss was recognized on the distribution of these operations to Petrobank shareholders. An adjustment was recorded to retained earnings to remove

Petrominerales’ net assets from the consolidated balance sheet and to remove Petrobank’s investment in Petrominerales.

Note 2 – Significant Accounting PoliciesConsolidationThese consolidated financial statements are presented in accordance with Canadian generally accepted accounting principles (“GAAP”) and include the

accounts of the Company and its subsidiaries as at and for the years ended December 31, 2010 and 2009. Inter-company transactions and balances are

eliminated upon consolidation.

Measurement UncertaintyThe preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported

amounts of assets and liabilities and disclosure of contingent assets and liabilities as at the date of the balance sheets as well as the reported amounts of

revenues, expenses, and cash flows during the periods presented. Such estimates relate primarily to unsettled transactions and events as of the date of the

financial statements. Actual results could differ materially from estimated amounts.

Notes


Amounts recorded for depletion and depreciation and amounts used for ceiling test impairment calculations are based on estimates of crude oil and natural

gas reserves and future costs required to develop those reserves. Goodwill impairment may be indicated by a number of factors including but not limited to

the equity market value of the Company, the net present value of reserves and valuation of comparable peer companies. Stock-based compensation is based

upon expected volatility and option life estimates. Asset retirement obligations are based on estimates of abandonment costs, timing of abandonment,

inflation and interest rates. The provision for income taxes is based on judgements in applying income tax law and estimates on the timing, likelihood and

reversal of temporary differences between the accounting and tax bases of assets and liabilities. These estimates are subject to measurement uncertainty and

changes in these estimates could materially impact the financial statements of future periods.

Capital AssetsAll costs related to the acquisition, exploration and development of oil and natural gas properties are capitalized. Such costs include land and lease

acquisition costs, annual charges on non-producing properties, geological and geophysical costs, costs of drilling and equipping productive and non-

productive wells, and carrying costs.

Operating costs, net of revenues, in relation to the Heavy Oil Business Unit are capitalized. Judgement is required to determine whether operations

continue to be in the development stage. The factors considered include whether commercially viable production levels have been achieved on a consistent

basis. Once the operations are no longer considered to be in the development stage, revenue is recognized and operating costs are recorded in net income

during the year.

Prior to the commencement of commercial operations, the Company may capitalize interest costs in relation to its development projects.

Gains and losses are not recognized upon disposition of oil and natural gas properties unless crediting the proceeds against accumulated costs would result

inachangeintherateofdepletionofmorethan20%.

Capitalized costs are accumulated in cost centres on a country-by-country basis and are depreciated and depleted using the unit-of-production method

based upon estimated proved reserves before royalties, as determined by independent engineers. Costs subject to depletion include estimated costs to

develop proved reserves and exclude estimated salvage value. Reserve and production volumes of oil and natural gas are converted to common units on the

equivalency basis of six thousand cubic feet (“Mcf”) to one standard oil barrel (“bbl”), reflecting the approximate relative energy content. Costs relating to

undeveloped properties are excluded from the depletion base until it is determined whether or not proved reserves exist or if impairment of such costs has

occurred. These unproved properties are assessed at least annually to determine whether impairment has occurred.

Depreciation of corporate and other fixed assets is calculated using the declining balance method at a rate of 30 percent.

A limit is placed on the carrying value of the net capitalized costs in each cost centre in order to test impairment. The Company is required to perform this

impairment test at least annually. An impairment loss may be indicated when the carrying value of a cost centre exceeds the estimated undiscounted future

net cash flows associated with the cost centre’s proved reserves. If there is indication of an impairment loss, the costs carried on the balance sheet in excess

of the discounted future net cash flows associated with the cost centre’s proved plus probable reserves are charged to depletion, depreciation and accretion

on the statement of operations. Reserves are determined pursuant to National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities. The

Company does not capitalize indirect general and administrative overhead costs.

Business CombinationsThe purchase price used in a business combination is based on the fair value at the date of exchange. All acquisition costs incurred by the Company are

expensed as incurred. Contingent liabilities are recognized at fair value at the date of acquisitions, and subsequently remeasured at each reporting period

until settled. Any negative goodwill is recognized as a charge to net income.

GoodwillGoodwill represents the excess of the purchase price over the fair value of net identifiable assets on the acquisition of a business. Goodwill has been

recorded at cost and is not amortized. Potential impairment is identified when the carrying value of the reporting unit, including allocated goodwill,

exceeds its fair value. Goodwill impairment is tested annually, or when indications of impairment exist and is measured as the excess of the carrying

amount of the reporting unit’s allocated goodwill over the implied fair value of the goodwill based on the fair value of the assets and liabilities of the

reporting unit. The impairment loss is recorded in the statement of operations.

Notes


Asset Retirement ObligationsThe Company recognizes the estimated fair value of future retirement obligations associated with capital assets as a liability in the period in which they are

incurred, normally when the asset is purchased or developed. The Company estimates the liability based on the estimated costs to abandon and reclaim

its net ownership interest in all wells and facilities and the estimated timing of the costs to be incurred in future periods. This estimate is evaluated on a

periodic basis and any adjustment to the estimate is applied prospectively. The change in net present value of the future retirement obligations due to the

passage of time is expensed as accretion. The asset retirement cost, which is the fair value of the asset retirement obligations at the inception of the assets,

is capitalized as part of the cost of the related long-lived asset and amortized using the unit-of production method. Actual retirement obligations settled

during the period reduce the asset retirement liability.

Non-Controlling InterestOn October 1, 2009, PetroBakken, acquired TriStar Oil and Gas Ltd. (“TriStar”) and created a new publicly listed company, PetroBakken Energy Ltd.,

whichisaBakkenandCardium-focused,lightoilexplorationandproductioncompany.Throughout2010,Petrobank’sownershiprangedfrom58%to

64%ofPetroBakken,theremainingpercentageofwhichisreflectedontheconsolidatedbalancesheetwithinNCI.PetroBakken’searningsorlossesare

included in the Company’s net income and adjusted to reflect the portion attributable to the NCI.

When there is a book to fair value difference on the recognition of NCI or changes in non-controlling ownership interest, the difference is recorded as

paid-in capital, a separate component within shareholders’ equity.

Financial InstrumentsAll financial assets and liabilities are recognized on the balance sheet when the Company becomes a party to the contractual provisions of the instrument

and are initially recognized at fair value. Subsequent measurement of the financial instruments is based on their classification. Each financial instrument is

classified into one of the following categories: financial assets and financial liabilities held for trading; loans or receivables; financial assets held to maturity;

financial assets available for sale; and other financial liabilities. The classification depends on the characteristics and the purpose for which the financial

instruments were acquired. Except in very limited circumstances, the classification of financial instruments is not subsequently changed. Financial

instruments carried at fair value on the balance sheet include cash and cash equivalents and risk management contracts. Realized and unrealized gains and

losses on financial assets and liabilities carried at fair value are recognized in net income in the periods such gains and losses arise. Transaction costs related

to these financial assets and liabilities are included in net income when incurred. Financial instruments carried at cost or amortized cost include accounts

receivable, accounts payable and accrued liabilities, bank debt, convertible debentures and other long term liabilities. Transaction costs are included in net

income when incurred for these types of financial instruments except for bank debt and convertible debentures. Transaction costs related to bank debt and

convertible debentures are included with the initial fair value and the instrument is carried at amortized cost using the effective interest rate method. When

bank debt is nil these costs are recorded as other assets. Gains and losses on financial assets and liabilities carried at cost or amortized cost are recognized in

net income when these assets or liabilities settle.

DerivativesThe Company may use derivative financial instruments to manage fluctuations in commodity prices, foreign currency exchange rates and interest rates.

These derivative instruments are recorded at fair value at the balance sheet date and any changes in fair value are recorded in net income during the period

of change unless the requirements for hedge accounting are met.

Joint OperationsA substantial portion of the Company’s oil and natural gas operations are conducted jointly with others and accordingly these consolidated financial

statements reflect only the Company’s proportionate interest in such activities.

Revenue RecognitionRevenues from the sale of crude oil, natural gas and natural gas liquids are recognized when title passes to the customer.

Foreign Currency TranslationThe Company translates foreign currency denominated assets and liabilities of its self-sustaining foreign operations into Canadian dollars at the exchange

rate in effect at the balance sheet date, while revenues and expenses are translated using average monthly rates. Translation gains and losses relating to the

self-sustaining foreign operations are deferred and included in an accumulated other comprehensive income (loss) account in shareholders’ equity until the

time that such self sustaining foreign operations are disposed. Upon disposal, the accumulated other comprehensive income (loss) balance is recognized in

net income.

Monetary assets and liabilities denominated in a currency other than the Canadian dollar are translated at the rates of exchange in effect at the balance

sheet date while revenues and expenses are translated at transaction date exchange rates. Exchange gains or losses are included in the determination of net

income as foreign exchange gain or loss.

Notes


Comprehensive IncomeComprehensive income consists of net income and other comprehensive income (“OCI”). OCI includes gains and losses resulting from the translation of

the Company’s net investments in self-sustaining foreign operations and the effective portion of derivatives used as a hedging item in a cash flow hedge or

net investment hedge. Accumulated other comprehensive income (“AOCI”) is a separate component of shareholders’ equity comprised of the cumulative

amounts of OCI. Other comprehensive income amounts included in AOCI are reclassified to income when realized.

Earnings Per ShareThe Company computes basic earnings per share using net income divided by the weighted-average number of common shares outstanding. The Company

computes diluted earnings per share using net income adjusted for interest expense on the convertible debentures and the impact of PetroBakken’s and

Petrominerales’ dilution on net income divided by the weighted-average number of diluted common shares outstanding. The Company uses the treasury

stock method in computing the weighted-average number of diluted common shares outstanding. This method assumes that proceeds on the exercise of in-

the-money stock options, deferred common shares, directors deferred common shares and incentive shares (collectively referred to as “Share-Based Rights”)

are used to repurchase the Company’s common shares at the average market price during the relevant period. The number of diluted common shares

outstanding also reflects the potential dilution that would occur if the convertible debentures were converted into common shares at the beginning of the

period, or when they were issued.

Stock-Based CompensationThe Company accounts for stock-based compensation using the fair-value method of accounting for Stock Awards granted to directors, officers, employees

and consultants using the Black-Scholes option-pricing model. Stock-based compensation expense is recorded for Share-Based Rights granted, with a

corresponding amount reflected in contributed surplus. Stock-based compensation expense is calculated as the estimated fair value of the related Share-

Based Rights at the time of grant, amortized over their vesting period. When Share-Based Rights are exercised, the associated amounts previously recorded

as contributed surplus are reclassified to common share capital. The Company has not incorporated an estimated forfeiture rate for stock options that will

not vest; rather, the Company accounts for actual forfeitures as they occur. Stock-based compensation expense recognized by PetroBakken is recorded as an

adjustment to NCI.

Income TaxesThe Company accounts for income taxes using the liability method. Under this method, the Company records a future income tax asset or liability to

reflect loss carry forwards and any difference between the accounting and tax bases of assets and liabilities, using substantively enacted income tax rates.

The effect on future tax assets and liabilities of a change in tax rates is recognized in net income in the period in which the change occurs. Future income

tax assets are only recognized to the extent it is more likely than not that sufficient future taxable income will be available to allow the future income tax

asset to be realized.

Risk Management ContractsThe Company is exposed to market risks resulting from fluctuations in commodity prices, foreign currency exchange rates and interest rates in the normal

course of its business. The Company may use a variety of instruments to manage these exposures. For transactions where hedge accounting is not applied,

the Company accounts for such instruments using the fair value method by initially recording an asset or liability, and recognizing changes in the fair value

of the instruments in income as gains or losses on risk management contracts. Fair values of financial instruments are determined from third party quotes

or valuations provided by independent third parties. Any realized gains or losses on risk management contracts are recognized in income in the period

they occur.

The Company may elect to use hedge accounting when there is a high degree of correlation between the price movements in the financial instruments and

the items designated as being hedged and has documented the relationship between the instruments and the hedged item as well as its risk management

objective and strategy for undertaking hedge transactions. At December 31, 2010, the Company had not designated any of its outstanding financial

instruments as hedges.

Convertible DebenturesThe Company presents outstanding convertible debentures in their debt and equity component parts on the consolidated balance sheet. The debt

component represents the total discounted present value of the semi-annual interest obligations to be satisfied by cash and the principal payment due at

maturity, using the rate of interest that would have been applicable to a non-convertible debt instrument of comparable term and risk at the date of issue.

This results in an accounting value assigned to the debt component of the convertible debentures which is less than the principal amount due at maturity.

The debt component presented on the balance sheet increases over the term of the debenture to the full face value of the outstanding debentures at

maturity. The difference, accretion on convertible debentures, is reflected as increased interest expense with the result that adjusted interest expense reflects

the effective yield of the debt component of the convertible debentures.

Notes


The equity component of the convertible debentures is presented under shareholders’ equity in the consolidated balance sheet. The equity component

represents the residual between the principal amount of the debenture less expenses, less the fair value of the debt component, which remains a fixed

amount over the term of the related debentures. Expenses are prorated to each component. Where the Company’s subsidiary has issued convertible

debentures, the fair value of the conversion right is presented within NCI in the consolidated balance sheet.

Upon conversion of Petrobank debentures into common shares by the holders, the debt and equity components are transferred to common share capital,

while debentures issued by Petrobank’s subsidiaries are transferred to NCI.

Upon repayment of Petrobank debentures in cash, the debt component would be derecognized and the equity portion transferred to contributed surplus.

If Petrobank settles the debt portion through the issuance of shares, the redemption value of the debt portion is credited to share capital. Upon repayment

of any of Petrobank’s subsidiaries debentures in cash, the debt component is derecognized with no adjustment to NCI.

Government AssistanceThe Company records the benefit of government assistance as a reduction in the related capital expenditures as they are incurred and when there is

reasonable assurance of collection.

Investment Tax CreditsInvestment tax credits arise as a result of incurring qualified scientific research and development expenditures (“SR&ED”), and are recorded as a reduction

of the related expenses or capital expenditures when there is reasonable assurance of collection.

Flow-Through Common SharesThe Company has financed a portion of its exploration activities in Canada through the issuance of flow-through shares. Under the terms of these shares,

the tax attributes of the related expenditures are renounced to subscribers. To recognize the foregone tax benefits, share capital is reduced and a future

income tax liability is recorded in the period in which the related tax attributes are renounced.

Cash and Cash EquivalentsCash and cash equivalents include investments and deposits with a maturity of three months or less when purchased.

InventoryPetrominerales’ crude oil inventory, which is included in current assets of discontinued operations, consists of production in transit or in storage tanks at

the balance sheet date, and is valued at the lower of cost, using the weighted average cost method, or net realizable value. Costs include direct and indirect

expenditures incurred in bringing the crude to its existing condition and location.

Note 3 – Capital Assets

December 31, 2010 Cost

AccumulatedDepletion and

Depreciation Net Book ValueOil and natural gas assets PetroBakken $ 5,247,880 $ 1,145,620 $ 4,102,260 HBU 570,174 - 570,174Other assets 25,066 12,039 13,027

$ 5,843,120 $ 1,157,659 $ 4,685,461

December 31, 2009 Cost

AccumulatedDepletion and

Depreciation Net Book Value

Oil and natural gas assets

PetroBakken $ 3,898,602 $ 628,355 $ 3,270,247

HBU 444,649 - 444,649

Other assets 16,911 8,264 8,647

$ 4,360,162 $ 636,619 $ 3,723,543

Notes


The Company capitalized interest related to its Conklin project totalling $3.0 million for the year ended December 31, 2010 (2009 – $13.1 million).

AtDecember 31, 2010,oilandnaturalgasassetsof$1,163.3million(2009–$751.8million)relatingtoPetroBakken’sunprovedpropertiesinCanada,and

$570.2 million(2009–$444.6 million)relatingtotheHeavyOilBusinessUnitunprovedproperties,havebeenexcludedfromthedepletioncalculation.

An impairment test calculation was performed for the Canadian cost centre at December 31, 2010 in which the estimated undiscounted future net cash

flows associated with the proved reserves exceeded the carrying amounts. In determining the undiscounted future net cash flows for the cost centre, the

Company utilized benchmark pricing forecasts from reserve evaluators. The benchmark prices used in their forecasts at December 31, 2010 are outlined in

the following table:

Year

WTI Crude Oil

(US$/bbl)

AECO Natural Gas

($/Mcf) US$/C$

2011 88.40 4.04 0.93

2012 89.14 4.66 0.93

2013 88.77 4.99 0.93

2014 88.88 6.58 0.93

2015 90.22 6.69 0.93

Thereafter % change 1.5% 1.5% nil

(1) Actual prices used in the impairment tests were adjusted for crude oil quality differentials, natural gas heat content, transportation and marketing costs specific to the Company’s operations.

Note 4 – Acquisitions and DispositionsPetroBakken Corporate AcquisitionsResult Energy Inc.

OnApril1,2010,PetroBakkenacquiredalloftheissuedandoutstandingsharesofResultEnergyInc.(“Result”)for$441.8 million,netofcashand

working capital acquired. The common shares issued were valued using the share price of PetroBakken on April 1, 2010. Result was a publicly traded

company with the majority of its production and prospect inventory in the Cardium formation in west central Alberta. As such, goodwill consists largely

of the strategic benefit that the increased presence in the Cardium formation will bring to PetroBakken. None of the goodwill recognized is expected to be

deductible for income tax purposes. The consolidated statement of operations includes the results of operations for the period following the closing of the

transaction on April 1, 2010, these amounts have not been disclosed separately below as it is impracticable to do so as operations were consolidated on the

acquisition date.

This transaction has been accounted for using the purchase method whereby the assets acquired and the liabilities assumed are recorded at fair value. The

following table summarizes the net assets acquired pursuant to the acquisition:

Net assets acquired Amount

Capital assets $ 261,334

Working capital 2,672

Asset retirement obligations (1,784)

Fair value of financial instruments 440

Goodwill 204,758

Future income tax liability (22,902)

Total net assets acquired $ 444,518

Consideration paid Amount

Cash (net of cash acquired) $ 141,230

PetroBakken common shares issued (11,232,904) $ 303,288

Total purchase price $ 444,518

The above amounts are estimates, which were made by management at the time of the preparation of these interim financial statements based on

information then available. Amendments may be made to these amounts as values subject to estimate are finalized.

(1) (1)

Notes


Rondo Petroleum Inc.

OnMarch12,2010,PetroBakkenacquiredalloftheissuedandoutstandingsharesofRondoPetroleumInc.(“Rondo”)for$277.2 million,including

Rondo bank debt net of cash acquired and working capital deficiency assumed. The common shares issued were valued using the share price of

PetroBakken on March 12, 2010. Rondo was a private company with the majority of its production and prospect inventory in the Cardium formation. As

such, goodwill consists largely of the strategic benefit that increased presence in the Cardium formation will bring to PetroBakken. None of the goodwill

recognized is expected to be deductible for income tax purposes. The consolidated statement of operations includes the results of operations for the period

following the closing of the transaction on March 12, 2010, these amounts have not been disclosed separately below as it is impracticable to do so as

operations were consolidated on the acquisition date.

This transaction has been accounted for using the purchase method whereby the assets acquired and the liabilities assumed are recorded at fair value.

The following table summarizes the net assets acquired pursuant to the acquisition:



Working capital deficiency (22,214)

Bank debt (net of cash acquired) (16,033)


Goodwill 107,195




Cash $ 88,702

PetroBakken common shares issued (5,524,471) 150,266


The above amounts are estimates, which were made by management at the time of the preparation of these financial statements based on information then

available. Amendments may be made to these amounts as values subject to estimate are finalized.

Berens Energy Ltd.

On February 25, 2010, PetroBakken acquired all of the issued and outstanding shares of Berens Energy Ltd. (“Berens”) for $344.4 million, including

Berens bank debt net of cash acquired and working capital deficiency assumed. Berens was a publicly traded company with production primarily from

properties in Alberta and the majority of its prospect inventory in the Cardium formation in west central Alberta. As such, goodwill consists largely of the

strategic benefit that the initial presence in the Cardium formation of Alberta will bring to PetroBakken. None of the goodwill recognized is expected to be

deductible for income tax purposes. The consolidated statement of operations includes the results of operations for the period following the closing of the

transaction on February 25, 2010; these amounts have not been disclosed separately as it is impracticable to do so as operations were consolidated on the

acquisition date.

This transaction has been accounted for using the purchase method whereby the assets acquired and the liabilities assumed are recorded at fair value.

The following table summarizes the net assets acquired pursuant to the acquisition:






Fair value of financial instruments 852

Goodwill 145,699




Cash $ 252,817


The above amounts are estimates, which were made by management at the time of the preparation of these financial statements based on information then

available. Amendments may be made to these amounts as values subject to estimate are finalized.

Notes


The impact of the above three acquisitions on goodwill for the year ended December 31, 2010 is:

Goodwill HBU and

Corporate PBN Total

Balance at December 31, 2009 $ 28,119 $ 1,032,862 $ 1,060,981

Additional amounts recognized from business combinations occurring during the period (see above)

- 457,652 457,652

Balance at December 31, 2010 $ 28,119 $ 1,490,514 $ 1,518,633

TriStar Oil & Gas Ltd.

OnOctober1,2009,PetroBakkenacquiredalloftheissuedandoutstandingsharesofTriStarforatotalcostof$2.8billion,includingTriStarbankdebtand

working capital deficiency assumed. The common shares issued were valued using an implied value based on the share price of TriStar at October 1, 2009

due to the fact that PetroBakken had not commenced trading on October 1, 2009. TriStar was a publicly traded company with the majority of its production

from the light oil properties in southeast Saskatchewan. As such, goodwill consists largely of the strategic benefit that the increased presence in southeast

Saskatchewan will bring to PetroBakken. None of the goodwill recognized is expected to be deductible for income tax purposes.

This transaction has been accounted for using the purchase method whereby the assets acquired and the liabilities assumed are recorded at fair values. The

following table summarizes the net assets acquired pursuant to the acquisition:


Capital assets $ 2,165,577




Fair value of financial instruments 2,901

Goodwill 997,810


Total net assets acquired $ 2,389,388


Cash $ 584,455

PetroBakken common shares issued (61,762,500) 1,804,933

Total purchase price $ 2,389,388

Asset DivestituresDuringtheyearendedDecember 31, 2010,PetroBakkencloseddivestituresrepresentingapproximately3,800barrelsofoilequivalent(“boepd”)of

production(50%naturalgas)inAlbertafornetproceedsof$133.6million.Ofthisamount,$5.2millionwasclosedduringthefourthquarter,less

$1.6millionofpostclosingadjustmentsrelatedtopriorperioddispositions.In2009,PetroBakkendisposedof2,000boepd(70%naturalgas)inAlberta

fornetproceedsof$178.8million.

Acquisition CostsDuring the year ended December 31, 2010, PetroBakken incurred cash transaction costs of $1.3 million related to the Result, Rondo and Berens

acquisitions. In 2009, transaction costs of $19.2 million were incurred upon the acquisition of TriStar, of which $10.6 million were settled with cash

andtheremaining$8.6millionsettledwithPetroBakkenshares.

Notes


Note 5 – Share CapitalThe equity account balances at December 31, 2010, and 2009 include only those of the Petrobank parent entity. PetroBakken’s equity account balances

eliminate upon consolidation of these financial statements.

AuthorizedUnlimited number of common shares.

Unlimited number of preferred shares, issuable in series.

Common Shares

Common Share Continuity Number Amount

Balance at December 31, 2008 83,525,394 574,060

Issued upon conversion of debentures (Note 7) 8,595,925 291,246

Costs associated with conversion of debentures - (2,863)

Tax effect of share issue costs - 792

Exercise of stock options 1,495,639 14,324

Transfer from contributed surplus related to stock options exercised - 5,092

Tax benefit renounced to shareholders - (2,468)

Balance at December 31, 2009 93,616,958 $ 880,183

Issued upon conversion of debentures (Note 7) 11,551,554 467,739

Costs associated with conversion of debentures - (11,647)

Tax effect of share issue costs - 3,067

Exercise of stock options and deferred common shares 1,131,614 14,615

Cancelled shares from prior plan of arrangement (63,793) -

Transfer from contributed surplus related to stock options and deferred common shares exercised

- 5,425

Balance at December 31, 2010 106,236,333 $ 1,359,382

Contributed Surplus

Changes in Contributed Surplus Amount

Balance at December 31, 2008 $ 19,795

Stock-based compensation 18,733

Transfer from contributed surplus related to stock options and deferred common shares exercised (5,092)



Transfer from contributed surplus related to stock options and deferred common shares exercised (5,425)


Paid-in Capital

As a result of the spin-off of Petrominerales, paid-in capital associated with historic changes in ownership in Petrominerales has been derecognized at

December 31, 2010.

Changes in Paid-in Capital Amount

Balance at December 31, 2008 $ -

Changes in ownership interest in PetroBakken 747,029

Changes in ownership interest in Petrominerales 128,895


Change in ownership interest in PetroBakken 93,743

Spin-off of Petrominerales (128,895)


Notes


Accumulated Other Comprehensive Income (Loss)

The accumulated other comprehensive income balance, all of which relates to translation of Petrominerales’ U.S. dollar account balances on consolidation

to the Company’s reporting currency, has been reclassified to net income at December 31, 2010.

Changes in Accumulated Other Comprehensive Income (Loss) Amount


Unrealized loss on translation of Petrominerales’ financial statements (72,742)

Balance at December 31, 2009 $ (29,894)

Unrealized loss on translation of Petrominerales’ financial statements (40,182)

Spin-off of Petrominerales 70,076


Stock OptionsThe Company has established a stock option plan whereby the Company may grant stock options to its directors, officers, employees and consultants.

Theplanallowsfortheissuanceofupto5%oftheoutstandingcommonsharesoftheCompany.Theexercisepriceofeachoptionisnolessthanthefive

day weighted average trading price of the Company’s common shares on the Toronto Stock Exchange prior to the date of grant. Stock option terms are

determined by the Company’s Board of Directors but typically, options vest evenly over a period of four years from the date of grant and expire between

five and 10 years after the date of grant.

As a result of the spin-off of Petrominerales, following the close of trading on December 31, 2010, the exercise price of outstanding stock options were

reduced by the fair market value of Petrobank’s interest in Petrominerales. Where the exercise price would have been reduced below $0.05, incentive shares

were issued to replace the corresponding value. Additional deferred common shares, directors deferred common shares and incentive shares were also

granted to compensate holders for the decrease in the share price. There was no change to the estimated fair value of outstanding Share-Based Rights as a

result of the adjustments. The 2009 weighted average option exercise prices have been restated in the following table for comparative purposes.

The following is a continuity of stock options outstanding:

2010 2009

StockOptions

WeightedAverage

Exercise PriceStock

Options

WeightedAverage

Exercise Price

Opening 4,091,079 $ 10.71 6,596,076 $ 6.40

Granted 927,194 24.02 1,010,499 22.01

Exercised (1,116,814) 0.60 (1,495,639) 0.69

Forfeited (701,942) 13.73 (1,989,857) 9.41

Cancelled - - (30,000) 28.52

Closing 3,199,517 $ 17.44 4,091,079 $ 10.71

In October 2009, all employees and officers that were previously employed by Petrobank’s Canadian Business Unit became employees and officers

of PetroBakken. Employees and officers were authorized to exercise all in-the-money stock options that vested prior to December 31, 2009 up until

January 22, 2010. All of the employees’ and officers’ unvested Petrobank stock options as at December 31, 2009 were forfeited. Those employees and

officers were granted PetroBakken incentive shares.

Notes


The following summarizes information about stock options outstanding as at December 31, 2010:

Stock Options Outstanding Stock Options Exercisable

Range ofExercisePrices Number

Weighted-AverageRemaining

Contractual Life (Years)

Weighted-Average

Exercise Price Number

Weighted-Average

Exercise Price

0.05 307,950 4.9 $ 0.05 280,950 $ 0.05

2.53 – 3.61 605,001 4.9 2.55 209,974 2.57

4.93 – 9.41 182,000 4.0 6.47 118,500 6.98

12.67 – 15.96 222,000 7.0 14.89 153,000 15.90

17.23 – 23.73 820,441 5.4 20.86 40,875 17.60

28.48 – 30.03 807,500 6.3 29.19 150,250 28.77

33.68 – 38.47 254,625 5.0 35.63 - -

3,199,517 5.5 $ 17.44 953,549 $ 9.29

Deferred Common Share Compensation PlanThe Company has a deferred share compensation plan whereby the Company may grant deferred common shares to its directors, officers and employees.

The plan allows holders to receive one common share upon payment of $0.05 per share. The deferred common shares typically vest after three years or

immediately upon resignation or retirement, and expire 10 years from the date of grant. Up to 0.5 million deferred common shares have been approved

for issuance under this plan.

The following is a continuity of deferred common shares outstanding:

2010 2009

Opening 204,310 146,810

Granted 21,819 57,500

Issued upon spin-off of Petrominerales 177,512 -

Exercised (14,800) -

Closing 388,841 204,310

Directors Deferred Common SharesIn 2010, shareholders approved a non-employee directors deferred common share plan. The plan allows the holder to receive one common share upon the

vesting and payment of $0.05 per share exercise price. The directors deferred common shares granted typically vest after three years from the date of grant

and expire 10 years after the date of grant. Up to 0.5 million directors deferred common shares have been approved for issuance under this plan.

The Company granted 6,123 directors deferred common shares during 2010, and issued an additional 5,143 directors deferred common shares at

December 31, 2010 as a result of the spin-off of Petrominerales.

Incentive Shares In the second quarter of 2010, shareholders approved an incentive plan for directors, officers, service providers and employees. The plan allows the holder to

receive one common share upon the vesting and payment of $0.05 per share exercise price. The terms of the incentive shares granted are determined by the

Company’s Board of Directors but typically, incentive shares vest over four years from the date of grant and expire between five and 10 years after the date

of grant. Up to 0.5 million incentive shares have been approved for issuance under this plan.

Incentive Share Continuity Number

Balance at December 31, 2009 -

Granted 100,844

Issued upon spin-off of Petrominerales 113,673

Forfeited (4,893)

Balance at December 31, 2010 209,624

Notes


Stock-Based CompensationThe fair values of Petrobank stock options and deferred common shares granted have been estimated on their respective grant dates using the Black-Scholes

option-pricing model using the following assumptions:

Years ended December 31, 2010 2009

All Share-Based Rights

Risk free interest rate 2.25% 1.75% – 2.25%

Dividend rate 0% 0%

Expected volatility 33% 25% – 47.5%

Stock options

Expected life (years) 2 – 4 2 – 4

Fair value $ 12.47 $ 10.60

Deferred common shares

Expected life (years) 8 8

Fair value $ 53.89 $ 24.15

Directors deferred common shares

Expected life (years) 8 -

Fair value $ 40.03 $ -

Incentive shares

Expected life – incentive shares (years) 2.75 – 3.75 -

Fair value of incentive shares granted $ 40.44 $ -

Stock based compensation also includes expenses related to PetroBakken’s stock options, incentive shares and deferred common shares.

Earnings Per ShareThe following tables provide a reconciliation of the numerators and the denominators of the basic and diluted per share computations for income

attributable to Petrobank shareholders, before and after discontinued operations.


Net income from continuing operations attributable to Petrobank shareholders adjustmentsBasic earnings $ 21,308 $ 68,559

Interest expense on Petrobank’s convertible debentures, net of tax - 2,303

Impact of PetroBakken dilution on net income (82) (45)

Diluted earnings from continuing operations $ 21,226 $ 70,817

Net income from discontinued operations 164,553 76,520

Cumulative loss on translation of Petrominerales’ financial statements (70,076) -

Impact of Petrominerales dilution on net income (7,144) (386)

Diluted earnings $ 108,559 $ 146,951

Weighted average common share adjustmentsBasic 104,403,209 88,494,213

Effect of convertible debentures - 6,929,579

Effect of Share-Based Rights 963,939 940,137

Diluted 105,367,148 96,363,929

Note 6 – Bank DebtHBU and CorporatePetrobank’s HBU and Corporate operating segment closed a $200 million secured credit facility on January 4, 2011 with a syndicate of lenders. The

credit facility has an initial term of three years, but may, at the request of the Company and if agreed to by a majority of lenders, be extended beyond the

initial term. The credit facility bears interest at the Canadian prime rate or U.S. base rate (for Canadian dollar and U.S. dollar borrowings, respectively),

plus a margin based on collateral value of Petrobank’s ownership in PetroBakken. The credit facility is secured by a portion of the Company’s shares of

PetroBakken and a general security assignment on other corporate assets and stipulates that the HBU and Corporate operating segment must maintain

a coverage ratio of not less than 2:1. Coverage ratio is defined in the agreement as earnings before interest, depletion, depreciation and amortization

(“EBITDA”) divided by interest expense.

Notes


PetroBakkenPetroBakken maintains a covenant based revolving credit facility with a syndicate of banks. The facility’s lending amount was increased during the fourth

quarter of 2010 from $1.0 billion to $1.2 billion following a review by the lenders. The current term for the facility ends June 3, 2011 and can be extended

by the lenders for an additional year. If the lenders were not to extend the term, the drawn amount would become due on June 3, 2012. The credit facility

bears interest at the prime rate plus a margin based on a sliding scale ratio of PetroBakken’s debt to EBITDA. The facility is secured by a $2.0 billion

demand debenture and a securities pledge on the Company’s assets.

HBU and Corporate PetroBakken

PetrobankConsolidated

Bank debt outstanding $ - $ 829,788 $ 829,788

Deferred financing costs $ - $ (4,943) $ (4,943)

Bank debt $ - $ 824,845 $ 824,845

(1) Deferred financing costs of $0.1 million (2009 – $0.1 million) related to HBU and Corporate have been included in prepaid expenses at December 31, 2010 as no debt was outstanding to offset the costs against.

Note 7 – Convertible DebenturesHBU and Corporate3.0% Convertible Debentures

InMay 2007,PetrobankissuedUS$250 millionofdebenturesconvertibleintocommonsharesofPetrobankataconversionpriceofUS$28.49per

debenture.Thedebentureshadanannualcouponof3.0%andweretomatureinMay2012.

InJune 2009,convertibledebentureswithafacevalueofUS$244.9 millionwereconvertedintocommonsharesand$289.2million(netofcosts)was

credited to share capital. Petrobank paid $36.2 million (including costs) to debenture holders to convert their holdings into common shares. As a result,

the Company recorded a $24.1 million, net of tax, reduction in retained earnings relating to the early conversion.

InMay2010,Petrobankforcedconversionoftheremaining3.0%debentures,uponwhich179,009 commonshareswereissuedand$6.0 millionwas

credited to share capital.

5.125% Convertible Debentures

In July 2009, Petrobank issued US$400 million of convertible debentures maturing in July 2015. The debentures were convertible into common shares of

PetrobankataconversionpriceofUS$38.08perdebentureandhadanannualcouponrateof5.125%.Interestonthedebenturesispayablesemi-annually

in cash or common shares.

The debentures were initially classified as a liability net of the fair value of the conversion feature which was classified as shareholders’ equity. The

US$400millionissuanceresultedin$377.9 millionbeingclassifiedasaliabilityand$75.5millionbeingclassifiedasequity.

In2010thedebentureswereconvertedintoatotalof11,372,545commonsharesand$450.1 million(netofcosts)wascreditedtosharecapital.Petrobank

paid$29.3 milliontodebentureholdersandissued868,988moresharesthanpertheoriginaldebentureagreementinordertoearlyconverttheirholdings

into common shares. As a result, the Company recorded a $59.0 million, net of tax, reduction in retained earnings relating to the early conversion.

PetroBakkenOnJanuary25,2010,PetroBakkenissuedUS$750millionofconvertibledebenturesmaturinginFebruary2016.Thedebenturesareconvertibleinto

commonsharesofPetroBakkenandhaveanannualcouponrateof3.125%andaninitialconversionpriceofUS$39.61perdebenture.Theconversionprice

is subject to change in certain circumstances including dividends paid by PetroBakken. Due to dividends paid to PetroBakken shareholders from

February2010toFebruary2011,theconversionpricehasbeenadjustedtoUS$37.74perdebenture.Uponconversionbasedonthecurrentconversion

price,atotalof19,827,814commonsharesmaybeissued,howeverPetroBakkenhastheoptiontorepaythedebenturesincash.

The debentures have been classified as a liability net of the fair value of the conversion feature which has been classified as shareholders’ equity. The

US$750millionissuanceresultedin$577 millionbeingclassifiedasaliabilityand$194 millionbeingclassifiedasequity.Theliabilityportionwillaccrete

up to the principal balance at maturity. The accretion and the interest paid are expensed as interest expense in the consolidated statement of operations. If

the debentures are converted to common shares, the relative portion of the value of the conversion feature under shareholders’ equity will be reclassified to

common share capital along with the principal amounts converted.

(1)

Notes


The U.S. dollar denominated convertible debentures are initially translated for accounting purposes based on the Canadian dollar exchange rate on the

date of issue. Subsequent to the date of issue, the debt component of the convertible debentures is translated for accounting purposes based on the

Canadian dollar exchange rate as at the balance sheet date. Any change is recorded as unrealized foreign exchange gain or loss for the period. PetroBakken

entered into currency swap agreements prior to the date of issue and the actual Canadian dollar proceeds received by PetroBakken resulted in an

$18.2 millionrealizedforeignexchangelossinthefirstquarterof2010.

The following table summarizes the liability component of the debentures at December 31, 2010:

HBU PetroBakken Total

Balance of liability component, December 31, 2008 $ 248,909 $ - $ 248,909

Accretion 11,658 - 11,658

Conversion into common shares(1) (228,464) - (228,464)

Liability component of debenture issuance(2) 377,918 - 377,918

Changes in exchange rate (61,064) - (61,064)

Balance of liability component, December 31, 2009 $ 348,957 $ - $ 348,957

Liability component of debenture issuance - 577,153 577,153

Accretion 1,503 25,533 27,036

Conversion into common shares(1) (342,940) - (342,940)

Change in exchange rate (7,520) (35,546) (43,066)

Balance of liability component, December 31, 2010 $ - $ 567,140 $ 567,140

(1) The conversion value represents the carrying amount of the liability portion on the conversion date.

(2) The fair value of the equity component on the date of issuance is reflected as NCI on the consolidated balance sheet.

Note 8 – Interest ExpenseInterest expense includes the following:


Cash interest $ 48,606 $ 28,901

Accretion on convertible debentures 27,036 11,658

Amortization of deferred financing costs 4,851 4,565

Capitalized interest related to Conklin project(1) (2,982) (13,111)

Interest expense $ 77,511 $ 32,013

(1) Capitalized interest includes $3.0 million of cash and $nil of non-cash accretion (2009 – $7.3 million and $5.8 million, respectively).

Note 9 – Asset Retirement ObligationsThe total future asset retirement obligations were estimated by management based on the Company’s net ownership interest in all wells, gathering lines

and facilities, estimated costs to reclaim and abandon the wells, gathering lines and facilities and the estimated timing of the costs to be incurred in

future periods.

Changes to asset retirement obligations were as follows:

2010 2009

Asset retirement obligations, beginning of year $ 62,059 $ 15,471

Obligations incurred 3,770 2,404

Obligations acquired 9,515 47,277

Obligations disposed (9,935) (3,349)

Obligations settled (4,528) (1,971)

Accretion expense 5,018 2,227

Changes in estimated future cash flows 353 -

Asset retirement obligations, end of year $ 66,252 $ 62,059

The obligations have been calculated using an inflation rate of two percent per annum and discounted using a credit-adjusted risk free rate of eight percent

per annum. Most of these obligations are not expected to be paid for several years, extending up to 29 years in the future for the HBU and 45 years in the

future for PetroBakken, and are expected to be funded from general resources of the Company and its subsidiaries, at their respective settlement dates. The

totalundiscountedamountofestimatedcashflowsrequiredtosettletheobligationsatDecember 31, 2010is$13.7million(2009–$11.7million)forthe

obligationsinourHBU,and$204.8 million(2009–$188.7 million)fortheobligationsinPetroBakken.

Notes


Note 10 – Income TaxesThe provision for income taxes differs from the amount that would have been expected by applying expected statutory corporate income tax rates to income

from continuing operations before taxes and NCI. The principal reasons for this difference are as follows:


Income from continuing operations before taxes and NCI $ 67,612 $ 53,037

Canadian statutory income tax rate 28.51% 29.00%

Expected tax expense $ 19,276 $ 15,381

Increase (decrease) in income tax provision resulting from:


Non-deductible accretion on convertible debentures 7,227 1,703

Non-deductible transaction costs and other expenses 534 5,815

Non-taxable foreign exchange gain(1) (6,246) (8,854)

Permanent difference associated with dispositions - (42,903)

Change in estimates and other (2,031) (6,106)

Provision for taxes $ 28,117 $ (27,541)

Consisting of:

Current taxes $ - $ -

Future income taxes $ 28,117 $ (27,541)

(1) Consists of non-taxable portion (50%) of foreign exchange gains on convertible debentures.

The components of the Company’s future income tax assets and liabilities arising from temporary differences are as follows:

As at December 31, 2010 2009

Future IncomeTax Assets

Future IncomeTax Liabilities

Future IncomeTax Assets

Future IncomeTax Liabilities

Capital assets $ - $ 517,116 $ - $ 391,772

Income taxable in subsequent periods - 166,325 - 135,059

Convertible debentures(1) - 6,210 - 4,524

Investment tax credits 8,849 - 8,849 -

Non-capital losses 103,698 - 40,933 -

Share issue costs 23,926 - 18,901 -

Asset retirement obligations 17,218 - 16,113 -

Risk management contracts(2) 3,555 - 1,782 -

Obligations under gas sale contract 1,360 - 1,069 -

Other 542 - 1,309 -

$ 159,148 $ 689,651 $ 88,956 $ 531,355

(1) Unrealized foreign exchange gains on convertible debentures are taxed as a capital gain (50%) upon conversion or settlement.

(2) Recorded $3.5 million as a current future income tax asset and $0.6 million as a current future income tax liability in 2010 (2009 – $0.8 million current future income tax asset).

The Company has reflected its future income tax liability net of future income tax assets on the balance sheet. As at December 31, 2010, the Company had

non-capitallossesinCanadatotalling$395.9million(2009–$157.6million),whichexpirebetween2011and2030.PetroBakkenexpectstouseaportion

of these losses to shelter partnership income that is taxable in 2011.

Notes


Note 11 – Non-Controlling Interest (NCI)ThecomponentsoftheCompany’sNCIinPetroBakken,Petrobank’s59% ownedsubsidiaryasatDecember 31, 2010(2009–64%),isasfollows:

PetroBakken


Acquisition of TriStar 1,066,489

Attributable income 12,019


Dividends paid or declared by PetroBakken (41,246)

Dividends received or receivable by Petrobank 26,352

Balance at December 31, 2009 $ 1,069,805

Attributable income 18,187


Issuance of convertible debentures 194,113

Common shares repurchased (36,424)

Changes in ownership interest(2) 359,802

Dividends paid or declared by PetroBakken (177,205)

Dividends received or receivable by Petrobank 105,408

Balance at December 31, 2010 $ 1,556,574

(1) On September 30, 2009, Petrobank initially capitalized PetroBakken with its Canadian Business Unit assets and obligations. In return, Petrobank received 109.8 million shares of PetroBakken. After PetroBakken’s acquisition of TriStar (Note 4) on October 1, 2009, Petrobank’s 109.8 million shares represented 64% of PetroBakken’s shares outstanding. The Company did not record a gain or loss on this transaction.

(2) Reflects the book values of the non-controlling interest share related to shares issued in connection with acquisitions and changes in non-controlling interest due to stock options, deferred common shares, and incentive shares exercised in the period.

Note 12 – Capital ManagementThe Company’s policy is to maintain a strong capital base in order to provide flexibility in the future development of the business and maintain investor,

creditor and market confidence. Petrobank and PetroBakken manage their capital structure independently and generate their own cash flows, and have the

ability to fund their operations through the issuance of secured and unsecured debt as well as equity financing. The table below outlines the composition of

Petrobank’s consolidated capital structure:

HBU andCorporate PetroBakken

Petrobank Consolidated

Working capital surplus (deficit) $ 1,942 $ (193,590) $ (191,648)Bank debt – principal $ - $ 829,788 $ 829,788Convertible debentures – principal amount (US$) $ - $ 750,000 $ 750,000Common share capital(1) $ 1,359,382 $ 3,147,238 $ 1,359,382Credit facility $ 200,000(2) $ 1,200,000

Available credit capacity $ 200,000(2) $ 370,212

(1) The common share capital of PetroBakken eliminates upon consolidation of these financial statements.

(2) In January 2011, Petrobank’s HBU and Corporate operating segment entered into a three year $200 million credit agreement with a syndicate of lenders.

HBU and CorporatePetrobank manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the

underlying assets. Petrobank considers its capital structure to include common share capital, convertible debentures, bank debt and working capital. In

order to maintain or adjust the capital structure, from time to time the Company may issue common shares or other securities, obtain project financing,

sell assets or adjust our capital spending to manage current and projected debt levels.

Based on Petrobank’s current ownership and PetroBakken’s payment of an annual dividend of $0.96 per common share, Petrobank expects to receive $105

million of dividends annually from PetroBakken paid monthly. Petrobank can also raise funds by selling a portion of our ownership in PetroBakken or by

issuing additional debt secured by this interest.

The Petrobank legal entity has not paid or declared any dividends since the date of incorporation.

Thespin-offofPetrobank’sownershipinPetrominerales(Notes1and18)andtheearlyconversionofthemajorityofPetrobank’s3%and5.25%

convertibledebentures(Note7),haveresultedinsignificantchangestoPetrobank’scapitalstructureduring 2010.

(1)

Notes


PetroBakkenPetroBakken monitors leverage and adjusts its capital structure based on the ratio of bank debt to annualized earnings before interest, taxes and non-cash

items. At December 31, 2010, the ratio of debt to annualized fourth quarter earnings before interest, taxes and non-cash items was 1.2 to 1, which is within

a range acceptable to management. PetroBakken uses the ratio of debt to annualized earnings before interest, taxes and non-cash items as a key indicator of

PetroBakken’s leverage and to monitor the strength of the balance sheet. In order to facilitate the management of this ratio, PetroBakken prepares annual

budgets, which are updated as necessary depending on varying factors including current and forecast commodity prices, changes in capital structure,

execution of PetroBakken’s business plan and general industry conditions. The annual budget is approved by the PetroBakken Board of Directors and

updates are prepared and reviewed as required.

PetroBakken is in compliance with all covenants on its credit facility agreement. The credit facility has financial covenants that limit the ratio of secured

debt (defined as total drawn on credit facility) to EBITDA to 3:1, limit the ratio of total debt (defined as total drawn on credit facility plus value of

outstandingconvertibledebentureinCanadiandollars)toEBITDAto4:1,andlimitsecureddebtto50%oftotalliabilitiesplustotalequity.

PetroBakken’s convertible debentures are considered to be equity as opposed to debt for capital management purposes. PetroBakken has the option to

repay the principal and interest amount in common shares or cash. PetroBakken is in compliance with the covenants on its convertible debentures. The

convertibledebentureagreementstipulatesthattheratioofsecureddebttototalassetsisnottoexceed35%.

PetroBakkenhadpositivecashflowfromoperationsfortheyearendedDecember 31, 2010andacreditfacilitywith$370.2 millionofavailablecapacity

as at December 31, 2010.

Note 13 – Financial Instruments and Financial Risk ManagementThe Company has exposure to the following risks from its use of financial instruments: credit risk, liquidity risk and market risk. This note presents

information about the Company’s exposure to each of these risks and the Company’s objectives, policies and processes for measuring and managing risk.

Further quantitative disclosures are included throughout these consolidated financial statements.

The Board of Directors has overall responsibility for the establishment and oversight of the Company’s financial risk management framework and monitors

risk management activities. The Company identifies and analyzes the risks faced by the Company and may utilize financial instruments to mitigate

these risks.

Credit RiskA substantial portion of the Company’s accounts receivable are with customers and joint-venture participants in the oil and natural gas industry and are

subject to normal industry credit risks. The carrying amount of accounts receivable reflects management’s assessment of the credit risk associated with these

customers and participants. At December 31, 2010, oil, natural gas and natural gas liquid production of the Company’s Canadian oil production is sold

to a number of oil and gas marketers. The Company’s policy to mitigate the risk associated with these balances is to establish marketing relationships with

large purchasers and, where practical, obtain support in the form of guarantees or letters of credit.

The composition of the Company’s accounts receivable is as follows:

As at Dec. 31, 2010 Dec. 31, 2009

Oil and natural gas customers $ 144,952 $ 138,007

Other 18,359 7,842

Total $ 163,311 $ 145,849

Receivables from oil and natural gas marketers are normally collected 25 to 45 days after the month following production. Receivables from joint-venture

partners related to capital and operating expenses are generally collected between 45 and 90 days after the month of billing. The Company historically has

not experienced any collection issues with its oil and natural gas customers or joint interest partners.

Cash and cash equivalents consist of cash bank balances and short term deposits maturing in less than 90 days. The Company manages the credit exposure

related to short term investments by selecting counter parties based on credit ratings and monitors all investments to ensure a stable return, avoiding

investment vehicles with higher risk such as asset backed commercial paper.

The carrying amount of accounts receivable and cash and cash equivalents represent the Company’s maximum credit exposure. The Company had a

$1.9 millionallowancefordoubtfulaccountsasatDecember 31, 2010(2009–$1.8 million).

Notes


The Company’s accounts receivables are aged as follows:

As at December 31, 2010 2009

Not past due $ 155,452 $ 139,814

Past due 7,859 6,035

Total $ 163,311 $ 145,849

Liquidity RiskThe Company’s approach to managing liquidity is to ensure, as far as possible, that it will have sufficient liquidity to meet its liabilities when due, under

both normal and unusual conditions without incurring unacceptable losses or jeopardizing the Company’s business objectives.

The Company prepares annual capital expenditure budgets, which are monitored and updated as considered necessary. Production is monitored regularly

to provide current cash flow estimates and the Company utilizes authorizations for expenditures on projects to manage capital expenditures. To facilitate

the capital expenditure program, the Company has revolving asset based credit facilities, as outlined in Note 6, that are reviewed semi-annually by

the lenders.

The following are the contractual maturities of financial liabilities at December 31, 2010:

Financial Liability < 1 Year 1-3 Years 3-5 Years Thereafter Total

Accounts payable and accrued liabilities $ 376,012 $ - $ - $ - $ 376,012

Capital lease obligations(1) 839 1,234 1,135 - 3,208

PetroBakken bank debt – principal - 829,788 - - 829,788

PetroBakken convertible debentures – principal (US$) - - 750,000 750,000

Total(2) $ 376,851 $ 831,022 $ 1,135 $ 745,950 $ 1,954,958

(1) Represents the future minimum lease payments under the capital leases. Difference from capital lease obligation disclosed on the balance sheet is due to interest rates of 6.7% to 9.0%.

(2) US$ amounts have been converted using a year-end exchange rate of $0.9946.

Market RiskMarket risk is the risk that changes in market factors, such as foreign exchange rates, commodity prices, and interest rates will affect the Company’s cash

flows, net income, liquidity or the value of financial instruments. The objective of market risk management is to mitigate market risk exposures where

considered appropriate and maximize returns.

The Company may utilize derivative instruments to manage market risk. The Board of Directors periodically reviews the results of all risk management

activities and all outstanding positions.

Foreign Currency Risk

The Company is exposed to foreign currency fluctuations as the convertible debentures are denominated in U.S. dollars. The Company is also exposed as

Canadian revenues are strongly linked to U.S. dollar denominated benchmark prices. When appropriate, the Company may enter into agreements to fix

the exchange rate of Canadian dollars to U.S. dollars in order to manage exchange rate risks.

At December 31, 2010, if the Canadian dollar had depreciated five percent against the U.S. dollar with all other variables held constant, net income

attributable to Petrobank shareholders would have been $14.6 million lower for the year ended December 31, 2010 (2009 – $15.3 million lower), due to

the period end valuation of U.S. dollar denominated risk management contracts outstanding and convertible debentures.

Commodity Price Risk

Changes in commodity prices may significantly impact the results of the Company’s operations and cash generated from operating activities, and can also

impact the Company’s borrowing base under its secured credit facilities. Lower commodity prices can also reduce the Company’s ability to raise capital.

Crude oil prices are impacted by world economic events that dictate the levels of supply and demand. Natural gas prices in Canada are influenced

primarily by North American supply and demand. From time to time the Company may attempt to mitigate commodity price risk through the use

offinancialderivatives.TheCompany’spolicyistoonlyenterintocommoditycontractsconsideredappropriatetoamaximumof50% offorecasted

production volumes.

Notes


PetroBakken had the following crude oil price risk management contracts outstanding at December 31, 2010:

Crude Oil Price Risk Management Contracts – WTI(1)


Jan. 1, 2011 – Dec. 31, 2011 2,500 $78.00 floor/$95.40 ceiling C$ WTI

Jan. 1, 2011 – Dec. 31, 2011 4,500 $76.11 floor/$101.43 ceiling US$ WTI



Jul. 1, 2011 – Dec. 31, 2012 1,000 $75.00 floor/$98.25 ceiling US$ WTI

Jan. 1, 2012 – Jun. 30, 2013 500 $75.00 floor/$109.00 ceiling US$ WTI

(1) Prices are the volume weighted average prices for the period.

The following crude oil derivative contracts were entered into subsequent to December 31, 2010:



Jul. 1, 2012 – Jun. 30, 2013 1,000 $75.00 floor/$117.45 ceiling US$ WTI

The following natural gas price risk management contracts were outstanding as at December 31, 2010:

Natural Gas Price Risk Management Contracts – AECO

Term Volume (GJ/d) Price ($/GJ) Type

Jan. 1, 2011 – Mar. 31, 2011 2,000 $6.00 Fixed Price Swap

Jan. 1, 2011 – Dec. 31, 2011 2,000 $6.02 Fixed Price Swap

ThefairvalueofthecommodityriskmanagementcontractliabilityasatDecember 31, 2010is$12.8 million(December 31, 2009–$6.0 million).

Ifforecastcrudeoilpriceshadbeen10% loweronDecember 31, 2010,withallothervariablesheldconstant,thechangeinthefairvalueoftherisk

management contracts would have resulted in net income attributable to Petrobank shareholders that was $14.6 million higher for the year then ended

(2009–$13.2 million).Ifforecastnaturalgaspriceshadbeen10%loweronDecember 31, 2010,withallothervariablesheldconstant,thechangeinthe

fair value of the risk management contracts would have resulted in net income attributable to Petrobank shareholders that was $0.1 million higher for the

year then ended (2009 – $0.3 million).

Long-Term Physical Gas Sale Contract

PetroBakken is committed to deliver 2,209 GJ per day of natural gas under an escalating price contract which expires on October 31, 2012. The wellhead

price under this contract for the year ended December 31, 2010 was $5.35 per GJ. PetroBakken applies the expected purchase and sale exemption to this

contract and accordingly does not apply hedge accounting principles to this contract.

Interest Rate Risk

The Company is exposed to interest rate cash flow risk on floating interest rate bank debt, to the extent it is drawn, due to fluctuations in market interest

rates and interest rate risk on fixed rate convertible debentures. The remainder of the Company’s financial assets and liabilities are not exposed to interest

rate risk.

PetroBakken had the following interest rate swap contracts in place at December 31, 2010:

Term Notional Principal/Month Fixed Annual Rate (%)

Jan. 2011 – Feb. 2011 C$40 million 2.390%

Jan. 2011 – Apr. 2011 C$50 million 1.050%

Jan. 2011 – Jan. 2012 C$50 million 1.620%

Jan. 2011 – Jan. 2012 C$50 million 1.653%

Jan. 2011 – Feb. 2012 C$25 million 1.540%

Jan. 2011 – Feb. 2012 C$25 million 1.510%

Jan. 2011 – Apr. 2012 C$50 million 1.300%

Jan. 2011 – Jun. 2012 C$25 million 2.094%

The fair value of the interest rate swap contracts as at December 31, 2010 was a liability of $0.2 million (December 31, 2009 – $0.1 million). If interest

rateshadbeen1%higheratDecember 31, 2010,netincomeattributabletoPetrobankshareholderswouldhaveincreasedby$1.6 million

(2009 – $3.2 million) due to the change in fair value of the interest rate swaps.

Notes


Fair Value of Financial Derivative ContractsThe following table summarizes the change in the fair value of PetroBakken’s derivative contracts:

Crude Oil Natural Gas Interest Total

Risk management asset (liability), as at December 31, 2009 $ (6,488) $ 470 $ (118) $ (6,136)

Unrealized gain (loss) (8,347) (428) 571 (8,204)

Contracts acquired - 1,980 (688) 1,292

Risk management asset (liability), as at December 31, 2010 $ (14,835) $ 2,022 $ (235) $ (13,048)

The net risk management asset (liability) consists of current and non-current assets and liabilities. The table below summarizes the components of the net

risk management asset (liability) as at December 31, 2010 and 2009:

Crude Oil Natural Gas InterestDecember 31,

2010

Current

Risk management asset $ - $ 2,022 $ 167 $ 2,189

Risk management liability (12,318) - (364) (12,682)

Non-current

Risk management asset - - 42 42

Risk management liability (2,517) - (80) (2,597)

Net risk management asset (liability) $ (14,835) $ 2,022 $ (235) $ (13,048)

Crude Oil Natural Gas InterestDecember 31,

2009

Current

Risk management asset $ - $ - $ - $ -

Risk management liability (3,046) 470 (118) (2,694)

Non-current

Risk management asset - - - -

Risk management liability (3,442) - - (3,442)

Net risk management asset (liability) $ (6,488) $ 470 $ (118) $ (6,136)


Realized gain (loss) on risk management contracts:

Crude oil derivative contracts $ (2,925) $ 23,984

Natural gas derivative contracts 5,117 (31)

Interest rate swap contracts (2,414) (2,313)

Foreign exchange contracts - 2,332

(222) 23,972

Unrealized gain (loss) on risk management contracts:

Crude oil derivative contracts (8,347) (40,926)

Natural gas derivative contracts (428) 210

Interest rate swap contracts 571 118

Foreign exchange contracts - (1,343)

(8,204) (41,941)

Loss on risk management contracts $ (8,426) $ (17,969)

The unrealized loss represents the change in fair value of the underlying risk management contracts to be settled in the future. The realized gain (loss)

represents the risk management contracts settled in the period.

Fair Value of Financial InstrumentsThe Company’s financial instruments are classified as cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, risk

management liabilities, capital lease obligations, bank debt, convertible debentures and obligations under gas sale contract included within other long-

term liabilities on the balance sheet. The carrying value and fair value of these financial instruments at December 31, 2010 is disclosed below by financial

instrument category, as well as any related gain, loss, expense or revenue for the year ended December 31, 2010:

Notes


Financial Instrument Carrying Value Fair Value Gain / (Loss)Interest

Expense Revenue

Assets Held For Trading

Cash and cash equivalents(1) 17,468 17,468 - - -

Loans and Receivables

Accounts receivable 163,311 163,311 - - -

Other Liabilities

Accounts payable and accrued liabilities 376,012 376,012 - - -

Risk management liabilities (net) 13,048 13,048 (8,426) - -

Capital lease obligations 2,669 2,669 - - -

Bank debt 824,845 829,788 - 27,513 -

Convertible debentures 567,140 729,375 17,362 48,051 -

Obligations under gas sale contract 1,516 2,559 - - 827

(1) The effective yield on cash equivalents at December 31, 2010 was 1.0% (2009 – 0.3%).

(2) Included in loss on risk management contracts on the statement of operations and retained earnings, and statement of comprehensive income. The unrealized loss of $8.2 million representing the change in fair value of the contracts is included on the statement of cash flow.

(3) Included in interest expense net of capitalized interest on the statement of operations and retained earnings and statement of comprehensive income. The amortization of deferred financing costs is included on the statement of cash flow. The effective yield on bank debt before capitalized interest at December 31, 2010 was 3.5% (2009 – 3.6%).

(4) The fair value of the convertible debentures is estimated based on market transactions close to December 31, 2010.

(5) Included in foreign exchange loss (gain) on the statement of operations and retained earnings, and statement of cash flow.

(6) Included in interest expense on the statement of operations and retained earnings and statement of comprehensive income. The non-cash interest expense relating to the accretion of the initial discounts and transaction costs that are netted against the liabilities are included in accretion on convertible debentures on the statement of cash flow. The effective yield on the convertible debentures issued by PetroBakken is 9.0%.

(7) The estimated fair value of the long-term physical gas sale contract is based on AECO forward strip pricing and is in an asset position at December 31, 2010.

(8) Included in oil and natural gas revenues on the statement of operations and retained earnings and statement of comprehensive income. The amortization of obligations under gas sale contract is included on the statement of cash flow.

The Company classifies the fair value of cash and cash equivalents and risk management liabilities according to the following hierarchy based on the

amount of observable inputs used to value the instrument.

• Level1–Quotedpricesareavailableinactivemarketsforidenticalassetsorliabilitiesasofthereportingdate.Activemarketsarethoseinwhich

transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level2–PricinginputsareotherthanquotedpricesinactivemarketsincludedinLevel1.PricesinLevel2areeitherdirectlyorindirectlyobservableas

of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which

can be substantially observed or corroborated in the marketplace.

• Level3–Valuationsinthislevelarethosewithinputsfortheassetorliabilitythatarenotbasedonobservablemarketdata.

Assessment of the significance of a particular input to the fair value measurement requires judgement and may affect the placement within the fair value

hierarchy level.

Cash and cash equivalents are classified as Level 1. The risk management contracts (Level 2) are recorded at their fair value based on quoted market prices

in the futures market on the balance sheet date; accordingly, there is no difference between fair value and carrying value. Due to the short term nature of:

cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities their carrying values approximate their fair values. Bank debt at

December 31, 2010 bears interest at a floating rate of interest and accordingly, fair value approximates the carrying value.

Note 14 – Technology Partnerships Canada and Innovative Energy Technologies Program FinancingTechnology Partnerships Canada (“TPC”), an Industry Canada initiative, will invest $9.0 million towards the development and field demonstration of the

Company’sTHAI®technologyattheConklinProject.UndertheTPCfundingcommitment,TPCagreedtocontribute20.134%ofeligibleexpendituresfor

the Conklin Project to a maximum of $9.0 million, all of which has been recorded as a reduction in capital assets. TPC is entitled to receive a royalty based

on three separate revenue streams. The first stream is based on three percent of the initial Conklin Project revenues earned after January 1, 2006 with initial

paymentsbeginningMay 1, 2010.Thesecondstreamisbasedon0.6%ofWhitesandsInsituPartnershiprevenues(excludinginitialprojectrevenues)earned

after January 1, 2009 with initial payments beginning May 1, 2010. The third stream is based on three percent of all third-party THAI® licensing revenues

earnedafterJanuary 1, 2008withinitialpaymentsbeginningMay 1, 2009.If,asofDecember 31, 2017thecumulativeroyaltypaidfromthethreeroyalty

streams has not reached $26.2 million, royalty payments will continue until $26.2 million has been paid or until December 31, 2022, whichever occurs first.

The Company has received a $10.0 million grant, from the Government of Alberta, in the form of a royalty credit which will offset future Alberta Crown

royalty payments. This program is administered by Alberta Energy’s Innovative Energy Technologies Program. As at December 31, 2010, the Company has

recorded a cumulative benefit of $4.0 million as a reduction of capital assets.

(2)

(3)

(4) (5) (6)

(7) (8)

Notes


Note 15 – Changes in Non-Cash Working CapitalYears ended December 31, 2010 2009

Change in:

Accounts receivable $ (17,462) $ (98,837)

Prepaid expenses 6,155 (13,893)

Accounts payable and accrued liabilities 5,633 184,267

Other 2,036 1,618

(3,638) 73,155

Working capital deficiencies acquired (Note 4) (36,202) (83,625)

$ (39,840) $ (10,470)

Changes relating to:

Attributable to operating activities $ (80,775) $ 23,909

Attributable to financing activities $ (628) $ 16,143

Attributable to investing activities $ 41,563 $ (50,522)

Other cash flow information:

Cash taxes paid $ - $ -

Cash interest paid $ 48,281 $ 28,180

Cash interest received $ 106 $ 28

Note 16 – Commitments and ContingenciesThe following is a summary of the estimated costs required to fulfill the Company’s remaining contractual commitments at December 31, 2010:

Type of Commitment 2011 2012 2013 2014 2015 Thereafter Total

HBU and Corporate

Office operating leases ($) 3,533 4,424 4,594 4,681 4,710 15,237 37,179

Capital leases ($) 838 578 581 486 97 - 2,580

PetroBakken

Office operating leases ($) 4,834 5,345 7,037 7,063 6,681 25,852 56,812

Drilling and completion rigs ($) 8,605 9,003 8,698 6,902 - - 33,208

Total Commitments $ 17,810 $ 19,350 $ 20,910 $ 19,132 $ 11,488 $ 41,089 $ 129,779

In January 2011, PetroBakken sub-leased office space for years 2011 to 2015 which will reduce total office lease commitments by $5.5 million.

The development of certain of the Company’s assets and the success of its operations are dependent on obtaining sufficient financing to fund its working

capital requirements and future capital expenditure commitments. The Company plans to fund these commitments with existing cash balances, funds flow

from operations, available credit facilities, new debt and potentially through the issuance of equity.

The Company is party to certain legal actions arising in the normal course of business, the outcome of which cannot be reasonably determined. In the

opinion of management, the resolution of these matters will not have a material effect on the Company’s financial position or results of operations.

Notes


Note 17 – Segmented InformationYears ended December 31, 2010 2009

PetroBakken PetromineralesHBU and

Corporate Total PetroBakken PetromineralesHBU and

Corporate Total

Revenues Oil and natural gas $ 1,008,556 $ - $ - $ 1,008,556 $ 575,588 $ - $ - $ 575,588

Royalties (142,064) - - (142,064) (82,151) - - (82,151)

Loss on risk management contracts (8,426) - - (8,426) (17,969) - - (17,969)

Interest income - - 101 101 211 - 13 224

858,066 - 101 858,167 475,679 - 13 475,692

Expenses Production 124,481 - - 124,481 70,913 - - 70,913

Transportation 15,270 - - 15,270 8,820 - - 8,820

General and administrative 33,233 - 8,632 41,865 15,253 - 4,100 19,353

Acquisition related 1,286 - - 1,286 19,155 - - 19,155

Stock-based compensation 22,888 - 9,505 32,393 18,650 - 6,274 24,924

Interest 75,611 - 1,900 77,511 18,699 - 13,314 32,013

Foreign exchange loss (gain) (19,541) - (8,769) (28,310) 1,105 - (57,753) (56,648)

Depletion, depreciation and accretion

525,403 - 656 526,059 303,714 - 411 304,125

778,631 - 11,924 790,555 456,309 - (33,654) 422,655

Income (loss) from continuing operations before taxes and NCI

79,435 - (11,823) 67,612 19,370 - 33,667 53,037

Future income taxes (recovery) 31,450 - (3,333) 28,117 (24,027) - (3,514) (27,541)

Net income (loss) from continuing operations

47,985 - (8,490) 39,495 43,397 - 37,181 80,578

Income attributable to NCI 18,187 - - 18,187 12,019 - - 12,019

Net income (loss) from continuing operations attributable to Petrobank shareholders

$ 29,798 - $ (8,490) $ 21,308 $ 31,378 $ - $ 37,181 $ 68,559

Net income from discontinued operations (net of tax of $99.1 million for 2010, $14.2 million for 2009)

- 164,553 - 164,553 - 76,520 - 76,520

Cumulative loss on translation of Petrominerales

- (70,076) - (70,076) - - - -


$ 29,798 $ 94,477 $ (8,490) $ 115,785 $ 31,378 $ 76,520 $ 37,181 $ 145,079

Identifiable assets $ 5,768,795 $ - $ 633,791 $ 6,402,586 $ 4,480,604 $ 746,205 $ 539,759 $ 5,766,568

Goodwill $ 1,490,514 $ - $ 28,119 $ 1,518,633 $ 1,032,862 $ - $ 28,119 $ 1,060,981

Capital expenditures $ 811,871 $ - $ 121,492 $ 933,363 $ 394,023 $ - $ 76,019 $ 470,042

Dividends paid or declared (received or receivable)

$ 177,205 $ - $ (129,878) $ 47,327 $ 41,246 $ - $ (26,352) $ 14,894

Notes


Note 18 – Discontinued OperationsAs described in Note 1, Petrominerales was spun-off to Petrobank shareholders on December 31, 2010. The operating results for this discontinued

operation were as follows:


Revenues Oil and natural gas $ 1,078,857 $ 518,086

Royalties (116,482) (47,297)

Interest income 1,020 411

963,395 471,200

Expenses Production 112,854 65,738

Purchased oil 66,096 -

Transportation 91,193 53,537

General and administrative 25,112 13,686

Acquisition costs 1,214 -


Interest 25,898 11,534

Foreign exchange loss 7,758 9,346

Depletion, depreciation and accretion 271,590 177,780

613,295 336,788

Income before taxes 350,100 134,412

Current taxes 35,574 10,234

Future income taxes 63,483 11,588

Net income before NCI 251,043 112,590

Income attributable to NCI 86,490 36,070

Net income from discontinued operations $ 164,553 $ 76,520

The carrying amounts of the major classes of assets and liabilities for this discontinued operation were as follows in the comparative period:

As at December 31, 2009

AssetsCurrent assets

Cash and cash equivalents $ 65,928

Accounts receivable and other current assets 59,766

125,694

Other assets 27,832

Capital assets 592,679

Total assets $ 746,205LiabilitiesCurrent liabilities

Accounts payable and accrued liabilities $ 111,537

Convertible debentures 80,409

191,946

Asset retirement obligations 7,063

Future income tax 39,389

Total liabilities $ 238,398

Designed by Bryan Mills Iradesso

Corporate Information

DirectorsChris J. Bloomer Calgary, Alberta, Canada

Ian S. Brown(2) (4) Calgary, Alberta, Canada

Louis L. Frank North Woodstock, New Hampshire, U.S.A.

M. Neil McCrank(1) (3) (4) Calgary, Alberta, Canada

Kenneth R. McKinnon(1) (2) Calgary, Alberta, Canada

Jerald L. Oaks(3) Denver, Colorado, U.S.A.

R. Gregg Smith Calgary, Alberta, Canada

Dr. Harrie Vredenburg(1) (2) (4) Calgary, Alberta, Canada

John D. Wright(3) Calgary, Alberta, Canada(1) Member of the Compensation Committee (2) Member of the Audit Committee (3) Member of the Reserves Committee (4) Member of the Nominating Committee

OfficersJohn D. Wright President and Chief Executive Officer

Chris J. Bloomer Senior Vice President and Chief Operating Officer, Heavy Oil

Peter Cheung Vice President Finance and Chief Financial Officer

Andrea Hatzinikolas Assistant Corporate Secretary and General Counsel

Additional corporate information can be obtained through Petrobank’s website at www.petrobank.com

Information requests and other investor relations inquiries can be directed to: [email protected] or by telephone at 403 750 4400.

Head OfficePetrobank Energy and Resources Ltd. 1900, 111 – 5th Avenue S.W. Calgary, Alberta, Canada T2P 3Y6

Tel: 403 750 4400 Fax: 403 266 5794

Website: www.petrobank.com E-mail: [email protected]

Registrar And Transfer AgentsComputershare Trust Company of Canada Calgary, Alberta, Canada

Legal CounselMcCarthy Tétrault LLP Calgary, Alberta, Canada

BankersThe Toronto-Dominion Bank Calgary, Alberta, Canada

AuditorsDeloitte & Touche LLP Calgary, Alberta, Canada

Reserve EngineersDeGoyler and MacNaughton Dallas, Texas, U.S.A.

McDaniel & Associates Consultants Ltd. Calgary, Alberta, Canada

Sproule Associates Limited Calgary, Alberta, Canada

Exchange ListingThe Toronto Stock Exchange SYMBOL: PBG

Securities Filingswww.sedar.com

Annual General MeetingThe Annual and Special Meeting will be held on May 25, 2011 at 2:00 PM (Mountain Time) in the Main Ballroom at The Metropolitan Conference Centre, 333 Fourth Ave S.W., Calgary, Alberta, Canada. All shareholders are cordially invited and encouraged to attend. The meeting will also be webcast. The webcast details will be available on our website in advance of the meeting.

Abbreviations1P proved reserves 2P proved + probable reserves 3P proved + probable + possible reserves ANH National Hydrocarbon Agency (Colombia) bbl/day barrels per day bbl(s) barrel(s) bcf billion cubic feet boe barrel(s) of oil equivalent bopd barrels of oil per day boepd barrels of oil equivalent per day BTU British thermal unit km kilometres Mbbl thousand barrels

Mboe thousand barrels of oil equivalent McDaniel McDaniel & Associates Consultants Ltd. Mcf thousand cubic feet MMcf million cubic feet NPV net present value NGL natural gas liquids PIHC pre-ignition heating cycle SAGD steam assisted gravity drainage section 640 acres or one square mile Sproule Sproule Associates Limited THAI® Toe to Heel Air Injection WI working interest WTI West Texas Intermediate

Forward-Looking Statements & DisclosuresCertain information provided in this Annual Report constitutes forward-looking statements. Specifically, this Annual Report contains forward-looking statements relating to financial results, results from operations, the timing of certain projects, anticipated recovery factors, future oil and gas exploration and development activities, projected levels of in-situ upgrading and resulting oil pricing, potential resource and reserve increases, future production rates, timing for regulatory approvals, capital expenditure programs and the completion of potential licensing agreements. Forward-looking statements are necessarily based upon assumptions and judgments with respect to the future including, but not limited to, the outlook for commodity markets and capital markets, success of future evaluation and development activities, the successful application of technology, prevailing commodity prices, the negotiation of future licensing arrangements, the performance of producing wells and reservoirs, well development and operating performance, general economic and business conditions, weather, and the regulatory and legal environment. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. You can find a discussion of those risks and uncertainties in our Canadian securities filings. Such factors include, but are not limited to: general economic, market and business conditions; fluctuations in oil prices; the results of exploration and development drilling, risks associated with the development and application of early stage technology, recompletions and related activities; timing and rig availability; fluctuation in foreign currency exchange rates; the uncertainty of reserve and resource estimates; changes in environmental and other regulations; risks associated with oil and gas operations; and other factors, many of which are beyond the control of the Company. There is no representation by Petrobank that actual results achieved during the forecast period will be the same in whole or in part as those forecast. Except as may be required by applicable securities laws, Petrobank assumes no obligation to publicly update or revise any forward-looking statements made herein or otherwise, whether as a result of new information, future events or otherwise.

Resources and Contingent Resources In this Annual Report, Petrobank has disclosed estimated volumes of “contingent resources”. “Resources” are oil and gas volumes that are estimated to have originally existed in the earth’s crust as naturally occurring accumulations but are not capable of being classified as “reserves”. “Contingent resources” are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. In respect of the May River project, contingencies include current uncertainties around the specific scope and timing of the development of the project; lack of regulatory approvals; uncertainty regarding marketing plans for production from the subject area; and need for improved estimation of project costs. Contingent resources do not constitute, and should not be confused with, reserves. There is no certainty that it will be commercially viable to produce any portion of the contingent resources on the May River property.

Possible Reserves Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Exploitable Oil-In-Place (EOIP) EOIP is the estimated discovered volume of oil, from known accumulations, before any production has been removed, which is contained in a subsurface stratigraphic interval that meets or exceeds certain reservoir characteristics considered necessary for the application of known recovery technologies. Examples of such reservoir characteristics include continuous net pay, porosity, and mass bitumen content. EOIP is a resources that does not constitute, and should not be confused with, reserves. There is no certainty that it will be commercially viable to produce any portion of the resource.

Petroleum Initially-In-Place (PIIP) The quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered.

BOE Disclosure provided herein in respect of boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent an economic value at the wellhead.

Net Present Values (NPV) Estimated values of future net revenue disclosed in this Annual Report do not necessarily represent fair market values.

Petrobank Energy and Resources Ltd.

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