Petrobank Energy and Resources Ltd.

Facilities: Design one, build many

THAI速 produces upgraded oil

Real Value

2 010 AnnuAl Rep oR t

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.

PRODUCTION BY QUARTER AVERAGE AVERAGE DAILY DAILY PRODUCTION PRODUCTION

COMPANY INTEREST FUNDS FUNDS FLOW FLOW FROM FROM RESERVES & BEST ESTIMATE OPERATIONS OPERATIONS CONTINGENT RESOURCES includes includes Petrominerales Petrominerales

includes Petrominerales includes includes Petrominerales Petrominerales (boepd, thousands) (boepd, (boepd, thousands) thousands)

637

($ ($ millions) millions) Includes only PBG share of each business unit’s reserves excludes Petrominerales (MMboe)

78.7 78.7

90 80

691

728

761

COM 2P

FUNDS FUNDS FLOW FLOW FROM FROM NET PRESENT VALUE (1) CONTINUING CONTINUING OPERATIONS OPERATIONS 2P RESERVES

incl bus incl (MM

excludes excludes Petrominerales Petrominerales ($ billions) ($ ($ millions) millions)

1,252 1,252 757

4.8 4.3

637 637

3.0

48.7 48.7

60 50

697 666 666 697

424

28.7 28.7

415 415

380 380

1.8

8787

5.35.3

175 175

10.2 10.2

0.6

6161

2828

2.2

0606 07

06 ●● Q1

●● Q2

0707 08

0808 09

●● Q3

0909 10

1010

06 060607 070708 080809 090910 1010

●● Q4

● Total proved ● Total probable ● Best estimate contingent resources

Financial Highlights

2 the Asset Base NET PRESENT VALUE

COMPANY COMPANY INTEREST, INTEREST,

Ability Includes6only PBG share of each 2Pthe 2P && BEST BEST ESTIMATE ESTIMATE excludes business CONTINGENT CONTINGENT RESOURCES RESOURCES 10Petrominerales Innovation unit’s reserves (MMboe) (MMboe) 12 Real opportunity ($ billions) 3.5

14 700700

3.0

600600

2.5

500500

2.0

400400

letters to Shareholders

petroBakken overview

petrominerales Historical Summary PRODUCTION PRODUCTION BYBEST BY QUARTER QUARTER HBU RESERVES & ESTIMATE

0607 06

0708 07

0809 08

0910 09

1010

operations Statistical Review includes includes Petrominerales Petrominerales CONTINGENT RESOURCES

(boepd, (boepd, thousands) thousands) (MMboe) Management’s Discussion and Analysis

Management’s Report

669 668Statements 90 90 661 Consolidated Financial

655

our Real Commitment

notes 80 80 to the Consolidated Financial Statements

petrobank Values

IBC

Corporate Information 70493 70

COMPANY PROVED PROVED INTEREST PLUS PLUS PROBABLE PROBABLE 2P RESERVES RESERVES RESERVES PER PER SHARE SHARE includes (boe) only (boe)PBG share of each business unit’s reserves includes Petrominerales (MMboe) 2.1 2.1 236

1.91.9 197

60 60

157

50 50

1.11.1

●H ●P ●P ●P

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

Contents 1

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

2.22.2

SummaRy of ReSultS (1) Q4 2010

2010

2009

2008

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

Financial ($000s, except where noted)

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

0.01

0.20

0.77

1.67

Per share – basic ($)

Per share – basic ($) – diluted ($) Net income (loss) attributable to Petrobank shareholders (3) Per share – basic ($) – diluted ($)

0.01

0.20

0.73

1.59

(35,612)

115,785

145,079

244,482

(0.34)

1.11

1.64

2.97

(0.34)

1.03

1.52

2.76

262,758

811,871

394,023

545,833

Capital expenditures PetroBakken Heavy Oil Business Unit (“HBU”) Total capital expenditures from continuing operations Total assets

37,521

121,492

76,019

82,332

300,279

933,363

470,042

628,165

6,402,586

5,766,568

2,361,707

Common shares outstanding, end of period (000s) Basic

106,236

93,617

83,525

Diluted (4)

110,046

108,596

99,043

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

67.00

65.28

58.97

86.78

9.84

9.34

8.55

10.03

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

Oil and natural gas revenue

(6)

Royalties Production expenses Operating netback (2) (5) (7)

8.97

8.18

7.38

8.76

48.19

47.76

43.04

67.99

34,754

35,109

22,648

15,369

Average daily production PetroBakken – oil and NGL (bbls) 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.

2010 Annual Report 1

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 2 petrobank energy and Resources ltd.

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

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.

Petrobank lands Waseca channel Horizontal oil well Channel edge Existing THAI™ oil well Planned THAI™ oil well Kerrobert facility

Kerrobert Petrobank’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. 2010 Annual Report 3

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

BRITISH COLUMBIA

MANITOBA

SASKATCHEWAN

ALBERTA

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

“the initial May River facility

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

will be located roughly two

THAI oil by the end of July.

kilometres from the existing

May River/Conklin

BRITISH

ALBERTA

SASKATCHEWAN

From its beginning as an experimental field projectSASKATCHEWAN in 2006, the Conklin MANITOBA pilot project has been an

COLUMBIA Conklin pilot. We have

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

already received contingent

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

project approval from

including injecting enriched oxygen, multi-THAI , direct oxidization of H 2S, CO2 co-injection and partial

Alberta environment.”

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. ALBERTA

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

Waupisoo Pipeline

MANITOBA

Statoilhydro

upgraded bitumen. The

Athabasca Pipeline advanced small-footprint, MEG

Broker Nexen/Opti

Nexen/Opti

Meg Christina Lake

A B Cenovus Leismer Broker Broker

Conklin KNOC

MEG

AA BB

Glover

Devon Enermark

Petrobank lands May River Phase 1 Conklin Pilot Pipelines Highway 881 Other in-situ projects Town of Conklin

4 petrobank energy and Resources ltd.

Cenovus Christina Lake

Devon Jackfish

Stone Petroleum

Southern Pacific

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

modular design elements used in this facility will

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 BRITISH

Canada and worldwide. COLUMBIA

ALBERTA

MANITOBA

SASKATCHEWAN

Dawson Petrobank’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 ALBERTA

SASKATCHEWAN

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

SASKATCHEWAN MANITOBA COLUMBIA 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.

Penn West

SASKATCHEWAN

Channel Edge

ALBERTA

MANITOBA

Petrobank

Baytex

CRaig BudRiS Operations Manager Petrobank 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 lands Channel edge Existing horizontal oil well Planned THAI™ oil well Channel edge 2010 Annual Report 5

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 initiallyin-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.

6 petrobank energy and Resources ltd.

RTER

COMPANY INTEREST RESERVES & BEST ESTIMATE CONTINGENT RESOURCES

COMPANY INTEREST 2P RESERVES

NET PRESENT VALUE 2P RESERVES (1)

Includes only PBG share of each “our Kerrobert project started producing slightly business unit’s reserves

includes only PBG share of each business unit’s reserves includes Petrominerales (MMboe)

($ billions)

excludes Petrominerales

upgraded heavy (MMboe) oil in January, 2010. production from 761

4.8

757

this project continued to 728improve throughout 2010.”

(MM

236

4.3

691

COM HBU CON

197 157

3.0

486

424

In conjunction with Petrobank’s 2009 reserves assessment, our independent reserves evaluator, 1.8

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

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

inception. The data was used to establish the effectiveness and reliability of THAI as an economic 09

10 ●● Q4

recovery process. As part of this evaluation, McDaniel concluded that the total exploitable bitumen-in06

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

● PBG’s ownership PBN ● Total probable With the improvements that we have made to THAI operating procedures in 2010,ofMcDaniel has ● Best estimate contingent resources

● PBG’s ownership of PMG

● PMG spun-off PBG shareholders revised the total exploitable bitumen-in-place for THAI to be approximately 1.7to billion barrels, or

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

728

761

includes Petrominerales business unit’s reserves (MMboe) includes Petrominerales (MMboe)

669 668 661 655 4.8 236 236 757 Our Kerrobert project began producing upgraded heavy oil in January, 2010. Production from this 197 4.3 project continued of the 493 to improve throughout 2010; we made significant changes to the operations 197 157

635

599

486

84barrels and 4.8 million able to assign proved and proved plus probable (“2P”) reserves of 3.0 million

2.2

barrels, and proved plus probable plus possible (“3P”) reserves of 8.550million barrels. These initial 1.8 84

0.8

reserves assignments represent 16%, 26%, and 46% recovery factors, respectively. Reserve recognition 06

ng obable resources

3.0

Split out below

655

500

Total probable ontingent resources

08 84

07Split out 08below 09

● Total proved ● Total probable NET PRESENT VALUE ● Best estimate contingent resources

2P RESERVES & BEST ESTIMATE CONTINGENT RESOURCES

Operations Supervisor

excludes Petrominerales ($ billions) 5

As Operations Supervisor within the Heavy Oil Business Unit, COMPANY INTEREST NET PRESENT VALUE 4 I help to coordinate and supervise the day to day activities within 2P RESERVES & BEST ESTIMATE HBU’S BEST ESTIMATE our operations group. I am next slated to head to the Dawson RESOURCE CONTINGENT RESOURCES CONTINGENT excludes Petrominerales 3 (MMbbls) project near Peace River.

($ billions)

As Petrobank has grown and expanded, it has maintained 635 its 2 6.2 small company atmosphere which I believe has made for a more 599 5.6 gratifying workplace. Our THAI® technology is interesting and 1 exciting to4.3 develop, and I work with a group of people that are all 486 passionate about achieving the same goal. 0

● HBU ● PBG’s share of PBN

John Vinette

157 06

CONTINGENT RESOURCES 3

197

● HBU ● PBN HBU NET PRESENT VALUE PMG 2P ● RESERVES & BEST ESTIMATE ● PMG spun-off to PBG shareholders (1)

($ billions)

08Having 09the chance 10 07 at08 to get in on the THAI®06technology the

599

2.2 ● Proved ● Probableground PBG’s ownership of PBN level and watching and helping●it HBU grow●into a commercially ● Best estimate contingent resources ● PBG’s ownership of PMG viable technology has been exciting. As●the technology and the PMG reserves spun-off to PBG shareholde 0.8 at 8% (1) Before tax, discounted Company develop, I look forward to new● challenges and projects. HBU best estimate contingent reserves

● Proved ● Probable ● Best 50 estimate contingent resources

gent resources

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

includes only PBG share of each business unit’s reserves includes Petrominerales (MMboe) 236

300

COMPANY INTEREST 2P RESERVES

600

100

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

200

(MMbbls)

400

669

● HBU ● PBG’s ownership of PBN HBU RESERVES & BEST ESTIMATE ● PBG’s ownership of PMG CONTINGENT RESOURCES ● PMG spun-off to PBG shareholders

700

S & BEST ESTIMATE RESOURCES

668

● Total proved ● Total probable ● Best estimate contingent resources

BEST ontingent resources(1) T RESOURCES

2.8

07 0.6

6.2

5.6 560

4.3

157 sustained economic production rates.3.0 Thanks to our operational success at Kerrobert, McDaniel was

● To ● To ● Be

excludes Petrominerales ($ billions)

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

COMPANY INTEREST NETESTIMATE PRESENT VALUE HBU’S BEST 2P RESERVES & BEST ESTIMATE CONTINGENT RESOURCES (MMbbls) CONTINGENT RESOURCES

business reserves onlyunit’s PBG share of each estimates. Our(MMboe) efforts during 2010 were directed at achieving and includes maintaining economic production

rates at our two pilot projects.

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

and that if Petrobank could show sustained THAI® In 2009, McDanielNET stated that THAI EREST COMPANY INTEREST PRESENT VALUE ® works (1) EST ESTIMATE economic production 2P RESERVES RESERVES COMPANY INTEREST HBU 2P RESERVES & BEST ESTIMATE levels, then McDaniel would be able to assign THAI® based reserves and resource RESOURCES only PBG share of each ($ billions) RESOURCES 2Pincludes RESERVES each CONTINGENT

usiness share of each serves nerales

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

● HBU OPERATING ● PBN NETBACKS ($/boe)● PMG ● PMG spun-off to PBG shareholders

● HBU FUNDS FLOW ● PBG’s share of PBN

FROM OPERATIONS ($ millions)

● Total proved 2010 Annual Report 7 ● Total probable ● Best estimate contingent re

“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.”

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

® Another key attribute of THAI® that McDaniel validated was the value of in-situ upgrading. Based on environmental benefits of THAI will be fully recognized.

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.

Cindy BoeRdyK, Plant Operator – Conklin Pilot Plant My 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.

8 petrobank energy and Resources ltd.

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 selfsufficient, 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 wellpair 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.

2010 Annual Report 9

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

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.

Benefits

From 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. 10 petrobank energy and Resources ltd.

Native bitumen 8° API Viscosity 550,000 centipoise

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

aRChon 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.

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.

2010 Annual Report 11

the size of the prize

Heavy Oil + Natural Bitumen in Place

trillion barrels

• For the foreseeable future, the world will rely on hydrocarbons, especially oil, to meet its energy demand. We

Light/Medium Oil in Place

trillion barrels

New technologies, such as THAI®, are the key to unlocking this vast resource.

are rapidly depleting reserves of easy

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

to produce, light, sweet crude – it

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

is estimated that 1 trillion barrels

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

remain (USGS)

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

• Heavy oil and bitumen, however, is an

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

abundant resource for the future –

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

estimated at 9 trillion barrels (USGS)

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.“ 12 petrobank energy and Resources ltd.

Expansion throughout Canada Of 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® Worldwide The 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

gReg deuChaR Project Manager – May River As 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.

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. 2010 Annual Report 13

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

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 shortterm 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.

14 petrobank energy and Resources ltd.

“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.“

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 underperforming 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 underperformance 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

2010 Annual Report 15

“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.”

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

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

each Cardium well location and precipitated a return of energy industry

technology holds the promise of unlocking resource in a more economical

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

and environmentally responsible way, and it has worldwide application.

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

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

Bakken formation. PetroBakken’s Cardium results are starting to

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

crystallize; our Bakken production has matured as a significant cash

intellectual property, to more clearly demonstrate to the market the

generating engine for the Company and we are now enviably positioned

incredible potential of this game-changing technology.

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.

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

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

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

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

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

conventional heavy oil resources in Alberta and Saskatchewan, we own

rewarding than anything else we know of.

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

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 16 petrobank energy and Resources ltd.

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

Realizing the potential of thai® 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”, 2010 Annual Report 17

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

“A milestone achievement for this past year

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

was the formal THAI® reserve recognition from

cash flow in the near term.

our reserve auditors, McDaniel.” 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

18 petrobank energy and Resources ltd.

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

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

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

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

we are able to employ innovative technology to increase value.

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

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

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.

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

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

evaluated starting in 2011.

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

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

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.

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 . Chris J. Bloomer Senior Vice President and Chief Operating Officer, Heavy Oil and Director March 29, 2011 2010 Annual Report 19

to the community 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 Duncanâ&#x20AC;&#x2122;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 Petrobankâ&#x20AC;&#x2122;s teams in operations, drilling, construction, safety and environment.

20 petrobank energy and Resources ltd.

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

“petrobank will continue

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

engaging communities

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

throughout the operational

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

lifespan of our projects, from

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

our initial consultations

2010 Community Update:

right through to final land

Conklin:

reclamation. We seek

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

to ensure that affected

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

communities remain informed

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

and are comfortable with our

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

operations and future plans.”

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.

2010 Annual Report 21

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.

“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.”

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.

“our dedication to

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

innovation introduced the

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

tHAI® technology and its

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

environmental benefits to

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

the world.”

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.

22 petrobank energy and Resources ltd.

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

PetRoBanK ViSion & ValueS n

We focus on innovatively creating long-term shareholder value.

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

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

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

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

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

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

safety risks and costs. Petrobank believes that minimizing the social and financial effects of injuries helps strengthen our business. The program consists of a thirdparty 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.

2010 Annual Report 23

50 40

300

28.7

200

100

5.3 06

10.2

175 06

61 07

PRODUCTION BY QUARTER

COMPANY INTEREST, 2P & BEST ESTIMATE CONTINGENT RESOURCES

includes Petrominerales (boepd, thousands)

475

424

400

113

200

475

700

COMPANY INTEREST, 2P & BEST ESTIMATE CONTINGENT RESOURCES

41.7

● 0 ● 06 ● RESERV ● ●●

N 2

In bu in ($

NET

Inclu excl unit ($ bi

26.3

(boe)

2.2

2.1 1.9

3.5 3.0 2.5

100

5.5

1.1

0.7 06

2.0

1.5

171

NET PRESENT VALUE 2P RESERVES

Includes only PBG share 144of each business unit’s reserves includes Petrominerales ($ billions)

700

●30HBU ● ● PBG’s o ●20PMG res ● HBU be

PROVED PLUS PROBABLE RESERVES PER SHARE

17.8

(MMboe)

(boepd, thousands)

1.0

● .5 ● Proved●d ● Proved u 0 ● Probabl 06

● Pr ● Pr ● Be

(th

NET EST

($ bi

4.8

4.1

26.3

600

(MMboe)

424

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

●● Q4

PRODUCTION

AVERAGE DAILY PRODUCTION PER MILLION COMMON SHARES

10 ●● Q4

●07 HBU ● PBG’s 08 ownership 09 of PBN10 ● PBG’s ownership of PMG ● Oil and NGL ● Natural gas ● PMG reserves spun-off to PBG shareholders ● HBU best estimate contingent resources

●● Q1 PBakken ●● Q2 Graphs ●● Q3

● PBG share of each of the business unit’s reserves. 2010 excludes PMG ● PMG reserves spun-off to PBG shareholders ● HBU best estimate contingent resources

includes only PBG share of each business unit's production (boe)

● PBN production ● PMG production

100

●● Q3

200

300

41.7 COMPANY INTEREST, 2P & BEST ESTIMATE CONTINGENT RESOURCES

300

(boepd, thousands)

400

70 500

600

500

294

700

28 06 06

600

(MMboe)

● PBN production 87 ● PMG production

PRODUCTION

AVERAGE DAILY PRODUCTION PER MILLION COMMON SHARES

establishing momentum

●● Q1 Graphs ●● Q2 PBakken

● PBG share of each of the business unit’s reserves. 2010 excludes PMG 07 08 09 10 ● PMG reserves spun-off to PBG shareholders ● HBU best estimate contingent resources

includes only PBG share of each business unit's production (boe)

500

Formed in late 2009 through294the combination of Petrobank’s Canadian Business

2.8

17.8

400

Unit and the acquisition of TriStar, PetroBakken has emerged as one of the few 300 large development companies operating in the200Western Canadian Sedimentary 113 71

5.5 Basin with assets and operations primarily focused on light oil. 100 0

07through 08 four09 10 Units. 07 08 09main10 PetroBakken’s activity is06concentrated in three areas of western06 Canada Business

Southeast

● PBN production Saskatchewan contains our ● PMG production

Bakken and Conventional

traditionally been our largest and most active base of operations.

● HBU ●07PBG’s ownership of PBN 08 09 10 Saskatchewan Business ● PBG’s ownership of PMGUnits and has ● Oil and NGL ● Natural gas ● PMG reserves spun-off to PBG shareholders Through the Bakken light oil resource play ● HBU best estimate contingent resources

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

1.860

40 0.5

31 0.6 06

08 09 10 ●07 Proved developed producing ● Proved Proved developed undeveloped ● Probable ● producing ● Proved undeveloped & non-producing ● Probable

● H0

LAND POSITION

NET

(1)● Be

PBakken Graphs

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 RESERVES PRODUCTION (boepd, thousands)

(MMboe)

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

($ bi

(thousands of acres)

171

Pembina oil field near Drayton Valley, Alberta, but41.7 also includes the more exploratory Cardium plays around Garrington and Lochend. The Cardium play will generate the majority of PetroBakken’s 144production growth

1,659

1,650

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 plays26.3 throughout Alberta. Our development investments during 2010 were in our Bakken and Cardium light oil resource plays, 17.8

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

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 ability31 to invest in natural gas when the

585 400

0.8

5.5

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 08 gas, investment 09 10in these plays allows 07 us to 08deliver strong 09 10 economic environment 07 than natural operating ● Oil and NGL ● Natural gas

netbacks and significant cash flow growth for future investment. 24 petrobank energy and Resources ltd.

● Proved developed producing ● Proved undeveloped & non-producing ● Probable

● Undeveloped ● Developed

● Pr ● Pr ● Pr

tion ction

0.7 06

30 ● HBU ● PBG’s ownership of PBN

● PBG’s ownership of PMG 20 ● PMG reserves spun-off to PBG shareholders ● HBU best estimate contingent resources

●● Q3 phs

.5 0

EST, ATE SOURCES

41.7

2.2

1,659

($ billions)

(MMboe)

31 0.6

669

655

8ership of PBN 09 10 f PMG ● Natural gas n-off to PBG shareholders contingent resources 08

1.0

● Total proved ● Total probable ● Best estimate contingent resources

4.8

600

400

2.8

3.0

2.4

COMPANY INTEREST 2P RESERVES

includes only PBG share of each business unit’s reserves includes Petrominerales (MMboe) 236

0.8 84 06 07 08 09 50 ●07 Proved ●08 Probable 09

10 10

600

400 300

585

1.5 1

200

400 0.5

ped09 producing 10 loped ● Probable producing

d & non-producing

•

07 08 09 10 $16.0 million and06the issuance of approximately 5.5 million PetroBakken common shares.

07 08estimate 09 07● Proved 08● Probable 09 10 ● HBU best contingent 10 resources ● Best estimate contingent resources On April 1, 2010, PetroBakken acquired all of the issued and outstanding shares of Result Energy Inc. for ● Proved developed producing Before tax, discounted at 8% ● (1) Undeveloped ● Developed ● Proved undeveloped cash consideration (net of cash acquired) of $141.2 million and the issuance of approximately 11.2 million ● Probable

47.76

for cash consideration of approximately $88.7 million, assumption of bank indebtedness of approximately 0

43.04

67.99

49.75

0.8 • On March 12, 2010, PetroBakken acquired all the issued and outstanding shares of Rondo Petroleum Inc. 100 08

●07 Proved ●08 Probable 09 10 ● Best estimate contingent resources ● Operating netback (1) Before tax, discounted at 8% ● Production expenses ● Royalties

PetroBakken common shares. OPERATING NETBACKS

NET PRESENT VALUE Operational Highlights

($/boe)

($ billions)

res)

• Our production averaged 41,688 boepd during 2010, compared with 26,333 boepd during 2009. Fourth

FUNDS FLOW FROM OPERATIONS ($ millions)

quarter production averaged 41,333 boepd, up slightly from the 40,095 boepd in third quarter of 2010. 1,659

1,650

4.1

646

• Nearly 85 percent of our 2010 production is high-netback light oil. 3.7

• We achieved a 99 percent success rate in the field drilling 239 net wells, the majority of which were oil wells located in central Alberta’s Cardium play, or in southeastern Saskatchewan.

417

395

2011 Activity Forecast • Capital budget of $800 million with approximately 75 percent of the budget directed to drilling and 1.5 completions operations in our central Alberta Cardium and southeast Saskatchewan light oil plays. 0.8

47.76

43.04

67.99

● Developed

49.75

• Drill 207 net wells; 95 net Cardium wells, 75 net Bakken wells and 30 net Mississippian wells in southeast Saskatchewan.

• Balance of drilling targeting new oil focused resource plays or natural gas drilling in northeast British Columbia to

● Proved developed producing ● Proved undeveloped preserve acreage. ● Probable

157

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

$74.9 million.

(

197

1.5

($ billions)

500

2 C

HBU NET PRESENT VALUE 2P RESERVES & BEST ESTIMATE CONTINGENT RESOURCES (1)

4.1 3.7

●H ●P ●P ● PH

4.1

($/boe)

(MMbbls) 700

● HBU ● PBN ● PMG OPERATING ● PMG spun-offNETBACKS to PBG shareholders

HBU RESERVES & BEST ESTIMATE CONTINGENT RESOURCES

1,650

● Best estimate contingent resources ● Proved developed producing ● Proved undeveloped ●06Probable 07 08 09 10

• On February 25, 2010, PetroBakken acquired all the issued and outstanding shares of Berens Energy

2.8

700

($ billions) Split out below

1,659

Significant Acquisitions

3.7

NET PRESENT VALUE

(thousands of acres)

($ billions)

HBU RESERVES & BEST ESTIMATE

● Proved developed producing ● Proved undeveloped ● Probable ● Best estimate contingent resources

2010 Highlights

4.1

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

Undeveloped ● Developed (1)●Before tax, discounted at 8%

NET PRESENT VALUE BEST ESTIMATE CONTINGENT RESOURCES (1)

G 144 share of each eserves nerales

08 09 10 ● 07 HBU best estimate contingent resources

LAND POSITION

200

07Proved developed 08 09 10 ● producing Proveddeveloped undeveloped ● Probable ●●Proved producing 0● Proved undeveloped & non-producing ● Probable 06 07 08 09 10

171

100

es/share s/share es/share o PBG shareholders

VALUE

300

585

493 400 0.5

NET ● HBUPRESENT VALUE ($PBG’s billions) Split outownership below ● of PBN ● PBG’s ownership of PMG ● PMG spun-off to PBG shareholders

500

668

● Total proved ● Total probable ● Best estimate contingent resources

1,650

1.5

0.6 06

2.8 ESTIMATE HBU RESERVES & BEST CONTINGENT2.4 RESOURCES 661 1.4

(1) Before tax, discounted at 8%

3.0

2.5 2.0

07 1.8

● HBU best estimate contingent resources

NET PRESENT VALUE BEST ESTIMATE CONTINGENT RESOURCES (1)

60 1.8

3.0

2.8

3.5

● Total probable ● Best estimate contingent resources

excludes Petrominerales business Transgas pipeline unit’s reserves

2.1

.8 1.9

(thousands of acres)

Bilateral HZ wells 171 NET PRESENT VALUE PBN facilities 2P RESERVES Includes onlyarea PBG share 144of each Bakken development

($ billions)

LAND POSITION ● Total proved

business unit’s reserves

26.3

● Proved developed producing ● Proved undeveloped ● Probable

includes Petrominerales Enbridge pipelines ($ billions) 4.8 NET PRESENT VALUE PBN pipelines Includes only PBG share 4.1 of each

PROBABLE R SHARE

● Proved developed producing ● Proved undeveloped ● Probable 06 estimate 07 contingent 08 resources 09 10 ● Best

(MMboe)

ands)

1.0

0 ● HBU 2P reserves/share 2P reserves/share PBN lands● PBN 06 2P reserves/share 07 08 09 10 ● PMG RESERVES PMGQ1spun-off ●● ●● to Q2PBG shareholders ●● Q3 ●● Q4 Bakken HZ●wells

●● Q4

424

1.5

● Operating netback ● Production expenses ● Royalties

2010 Annual Report 25

SH BIA

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.

Technology Evolution 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 ALBERTA

SASKATCHEWAN

MANITOBA

to unlock hydrocarbon resources in the Cardium.

Bakken Business Unit PetroBakken is currently the second largest landholder in Saskatchewanâ&#x20AC;&#x2122;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.

Bakken Development Area

ALBERTA

SASKATCHEWAN

SH BIA

SASKATCHEWAN

PBN lands Bakken HZ wells Bilateral HZ wells PBN facilities Bakken development area Enbridge pipelines PBN pipelines SASKATCHEWAN

Transgas pipeline

26 petrobank energy and Resources ltd.

MANITOBA

BRITISH COLUMBIA

ALBERTA

SASKATCHEWAN

MANITOBA

pembina Cardium light oil Resource play

ALBERTA

SASKATCHEWAN

BRITISH COLUMBIA

SASKATCHE

Cardium CU Legend PBN Cardium lands Cardium producing wells

Cardium Business Unit

ALBERTA

After 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

“We SASKATCHEWAN continue to be at the

MANITOBA

forefront of pioneering and modifying new, cost-effective

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

completion techniques in

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

both our conventional and

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

unconventional plays.”

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 Unit We 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 Unit The 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.

2010 Annual Report 27

historical summary

2002

2003

2004

2005

2006

Petrominerales IPO Colombian production: 2,600 bopd

Acquisition of Colombian assets provides foundation for LABU

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

28 petrobank energy and Resources ltd.

2007

2008

PMG makes initial Corcel discovery

2009

2010

2011

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.

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

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

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.

2010 Annual Report 29

FUNDS OPERAT

AVERAGE DAILY PRODUCTION includes Petrominerales (boepd, thousands)

includes P ($ million

78.7

TOTAL COMPANY

48.7

Petrobank’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 28.7 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 patented10.2 THAI technology; it was the

5.3

first such reserves to be recognized from our technology.

06results07to this 08 As Petrominerales was spun-off to shareholders at December 31, 2010, the following consolidated tables include only date.

FUNDS FLOW FROM OPERATIONS

AVERAGE DAILY PRODUCTION

average daily production includes Petrominerales (boepd, thousands)

PetroBakken Bakken Conventional (SE SK) Cardium (central AB) NE BC / Other AB Total PetroBakken Per basic share (1) Petrominerales Guatiquia Corcel Neiva Orito 5.3 Casimena Others 06 Total Petrominerales Per basic share (1) Total Company Per basic share (1)

78.7 24,472

48.7

Natural Gas (Mcf) 2010 Average Q4 2010

22,859 6,595 4,175 1,125 34,754 0.19

6,842 2,463 1,332 35,109 0.20

FUNDS FLOW FROM CONTINUING OPERATIONS

includes Petrominerales

Oil & NGL (bbl) ($ millions) 2010 Average Q4 2010

6,711 2,521 12,761 17,480 39,473 697 666 0.23

1,252

excludes Petrominerales Total (boe) ($ millions)

2010 Average

Q4 2010

6,778 25,591 COMPANY INTEREST, 1,854 7,262 2P & BEST ESTIMATE 14,752 4,590 CONTINGENT RESOURCES 16,090 4,245 (MMboe) 415 39,474 41,688 700 0.22 0.24

23,989 6,904 6,634 3,806 41,333 380 0.23

637

includes P (boepd, tho 90 80

600

28.7

10.2

19,901 9,336 3,432 2,825 1,027 10 506 37,027 0.24 72,136 0.44

14,447 9,747 3,883175 2,532 61 1,417 06 1,11607 33,142 0.20 67,896 0.39

08 0939,473 0.23

PLUS PROBABLE AVERAGEPROVED DAILY PRODUCTION RESERVES PERSHARES SHARE PER MILLION COMMON

includes Petrominerales (boepd, thousands)

(boe) includes only PBG share of each business unit's production (boe)

pre-operating stage,(MMboe) and accordingly, revenues net of royalties and operating700 costs, are recorded as capitalized costs as

opposed to being 600 recognized in net income.

● HBU best estimate contingent resources

PRODUCTION BY QUARTER

2P & BEST ESTIMATE daily production asCONTINGENT operations are RESOURCES considered to be in the

19,901 14,447 60 87 9,336 9,747 400 50 3,432 3,883 40 300 28 2,825 2,532 30 200 1,027 1,417 20 1,116 100 10 06 506 07 08 09 10 37,027 33,142 0 0 06 07 08 09 10 0.20 06 0.24 ●● Q1 ● PBG share of each of the business 39,474 78,715 74,475 unit’s reserves. 2010 excludes PMG 0.22 0.48 0.43 ● PMG reserves spun-off to PBG shareholders 500

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

Heavy Oil BusinessCOMPANY Unit volumes are excluded from average INTEREST,

PRODUC

COMPAN 2P & BES CONTING (MMboe)

4752.1

4241.9

2.2

700 600

70 500

400

300

200

100

● PBG share of each of the business unit’s reserves. 2010 excludes PMG ● PMG reserves spun-off to PBG shareholders ● HBU best estimate contingent resources 30 petrobank energy and Resources ltd.

AVERAGE DAILY PRODUCTION

500

294 1.1

400 300

0.7 113

200 100

06 ●● Q1

07 ●● Q2

●● Q3

COMPANY INTEREST,

10 ●● Q4

07 06

08 07

09 08

10 09

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

PBakken Graphs

NET PRESENT VALUE

● HBU ● ● PBG’s ow ● PMG res ● HBU bes

PANY INTEREST FUNDS FLOW FROM CONTINUING OPERATIONS S BEST ESTIMATE Petrominerales NGENT excludes RESOURCES

PRODUCTION BY QUARTER

($ millions)

ls)

635

599

COMPANY INTEREST RESERVES & BEST ESTIMATE CONTINGENT RESOURCES

includes Petrominerales (boepd, thousands)

560

($ billions)

Includes only PBG share of each business unit’s reserves excludes Petrominerales (MMboe)

637

NET PRESE 2P RESERV

691

728

761

757

70 60

415

380

424

1.8

net present value, before tax, forecast prices (millions) (1) 30

PetroBakken ($) 2,135 2,845 4,142 06 07 ● Total proved

08 06

Developed producing Proved Proved +08 probable 09 10 07 09(2P) 10 Best estimate contingent resources

provedAVERAGE DAILY PRODUCTION probable includes Petrominerales estimate contingent resources (boepd, thousands)

10 0

Q1 FROM ●● Q2 FUNDS●● FLOW OPERATIONS

09 ●● Q3

10 ●● Q4

($ millions)

415 661

2.5

175

611.0

Proved Proved + probable (2P) .5 06 07Best estimate 08 09 10 resources 06 07 08 09 10 contingent 0 Total proved reserves per basic share 06 07 08 09 06 07 08 09 10 06 07 08 09 10 Proved + probable reserves per basic share ● Proved developed producing ● HBU 2P●reserves/share Total proved

● PMG spun-

668 380

669

06 10

includes Petr (MMboe)

655

50 40

PetroBakken 87 (Mboe) 66,183 103,028 171,377 07 08 0.97 06 07 1.61

2.0 1.5

● PBG’s owne includes Petromine ● thousands) PBG’s owne (boepd,

493

(1) Company 28.7 interest reserves and resources by business unit, forecast prices

10.2 Developed producing

09 08

(2) 30 HBU Total Company (Mbbl) 20 (Mboe) 575 39,623 84 10 3,032 63,819 50 0196,521 95,409 10 06 07 560,131 560,131 ●● Q1 0.60 06 ●● Q2 07 09 0.03 10 0.90 1.85 ● HBU

● Total proved ● Total probable ● Best estimate contingent resources

● Proved undeveloped ● Probable ● PBN 2P●reserves/share Total probable (1) Company interest reserves and resources represent the● working interest share including resources royalty interests in reserves and resources before deduction of royalty obligations. Best estimate contingent ● PMG 2P ●reserves/share Best estimate contingent resources (2) total to Company includes only petrobank’s 59% share of petroBakken reserves as at December 31, 2010. ● PMG spun-off PBG shareholders

● PBN ● PMG ● PMG spun-

Split out below

PRODUCTION BY QUARTER NET PRESENT VALUE BEST includes ESTIMATE Petrominerales CONTINGENT RESOURCES (1)

NET PRESENT VALUEVALUE COMPANY INTEREST, NET PRESENT RESERVES 2P2P & BEST ESTIMATE 2P RESERVES (1) Includes($only PBG share of each CONTINGENT RESOURCES billions) 700

business unit’s reserves (MMboe) includes Petrominerales ($ billions)

4.1

600

(boepd, thousands) ($ billions)

4.8

4.890

4.3

2.8

3.0

2.4

PRODUCTION BY

PetroBakken HBU Total Company (2)(1) Net present v at ($) ($) ($) discounted and at 8% for 90 1,162 1,966 637 2 2,446 6 HBU RESERVES & BEST ESTIMATE 80 1,449 COMPANY CONTINGENT 3,371 RESOURCES585 2,574 2P RESERV 70 includes only (MMboe) 2,088 2,088 business unit

78.7 1,252 Developed producing Proved PROVED PLUS PROBABLE NET PRESENT VALUE COMPANY INTEREST RESERVES PER Includes only PBG share of each HBU’S BEST ESTIMATE Proved + SHARE probable (2P) excludes Petrominerales business (boe) CONTINGENT RESOURCES Best estimate contingent resources unit’s reserves (MMbbls) ($ billions) 48.7 2.2 at 10% for petroBakken and at 8% for the HBu. (1) net present values are discounted 2.1 3.5 697 635 includes only petrobank’s 59% share of petroBakken 666 (2) total Company reserves as at December 31, 2010. 599 599 1.9 560 3.0

5.30.7

FUNDS FLOW FROM ● Total probable CONTINUING OPERATIONS

Best estimate contingent resources excludes●Petrominerales ($ millions)

net present value, after tax, forecastincludes pricesPetrominerales (millions) (1)

486 1.1

HBU Total Company ($) ($) 0.6 2 1,262 6 1,685 724 3,168 06 09 10 3,000 3,000 ● HBU (2)

PROVED PLUS PROBABLE HBU RESERVES & BEST ESTIMATE RESERVES PER SHARE CONTINGENT RESOURCES (boe)

NET PRESENT V HBU NET P Includes PBG s 2Ponly RESERV excludes Petromine CONTINGEN

(MMbbls)

2.1

700

unit’s ($ reserves billions) ($ billions)

2.2

3.5

1.9

600

3.0

70 500

2.8

400

1.8

300

3.0

1.4

0.6

06 06

0706 07

0.5

20 10

0807 08

0908 09

1009 10

● PBG share of each of the business HBU ● Proved●developed producing unit’s reserves. 2010 excludesofPMG PBG’s ownership PBN ● Proved●undeveloped ● Probable ● PMG reserves spun-off to PBG ● PBG’s ownership ofshareholders PMG ● HBU best● estimate contingent resources 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 AVERAGE DAILY PRODUCTION

PER MILLION COMMON SHARES LANDonly POSITION includes PBG share of each (thousands acres) business unit'sof production (boe)

1.1

06 ●● Q1

07 06

08 07

09 08

10 09

300

1.5

200

1.0

100

●● Q2 ●● Q3 ●● Q4 ● HBU best estimate contingent resources (1) Before tax, discounted at 8%

COMPANY INTEREST, 2P & BEST ESTIMATE NET PRESENT VALUE CONTINGENT RESOURCES (MMboe)($ billions)

07 06

2.0

0.7

200 100

400

1.8

2.5

500

08 07

09 08

10 09

● HBU 2P ● reserves/share Proved ● Probable ● PBN 2P ● reserves/share Best estimate contingent resources ● PMG 2P reserves/share ● PMG spun-off to PBG shareholders

NET PRESENT VALUE 2P RESERVES NETBACKS IncludesOPERATING only PBG share of each ($/boe) business unit’s reserves includes Petrominerales

0607

070

● Proved developed ● Proved ● ● Proved undevelop ● Best estim ● Best estimate con

(1) Before tax, di

NET PRESENT V ESTIMATE CONT

2010 Annual Report 31 FUNDS FLO

($ billions)

FROM OPE ($ millions)

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 Average Gross 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 COMPANY INTEREST NET PRESENT VALUE COMPANY INTEREST COMPANY INTEREST COMPANY INTEREST NET PRESENT VALUE (1) (1) 2P RESERVES RESERVES & BEST ESTIMATE 2P103.6 RESERVES 51.8 2P RESERVES HBU’S United States -2P RESERVES 103.6 BEST ESTIMATE 51.8 50 includes only PBG share of($each CONTINGENT RESOURCES only PBG share of each ($ billions) billions) CONTINGENT1,204.4 RESOURCESincludes PetroBakken Includes only PBG share of each 714.2 445.6 1,573.0 2,287.2 1,650.0 72 business unit’s reserves business unit’s reserves (MMbbls) includes Petrominerales0.1 includes business unit’s reserves Saskatchewan 0.1 27.5 27.5 27.6 Petrominerales 27.6 100 (MMboe) (MMboe) excludes Petrominerales Alberta 0.5 0.5 66.4 66.4 66.9 66.9 100 (MMboe) 4.8 4.8 236 236 HBU 0.6 0.6 93.9 93.9 94.5 94.5 100 757 635 761 599 599 728 4.3 Total Company 4.3 714.8 446.2 1,666.9 1,298.3 2,381.7 1,744.5 73 560 691 197 197

net asset value (millions, except shares outstanding and per share amounts) 157

3.0

Basic 106,236

486

Petrobank common 424 shares outstanding (000s) 1.8

0.6

06 10

1.8

$ PetroBakken (2) 50 reserves (3) Heavy Oil Business Unit - proved plus probable 0.6 Heavy Oil Business Unit - best estimate contingent reserves (3) (4) Working capital surplus Stock options, deferred common shares, directors deferred common shares and incentive shares (5) 07 08 08 09 10 0609 0710 0609 0710 08 09 06 10 07 06 07 08 Total net asset value $

157

COMP HBU’S CONTI

(MMbb

Diluted (1) 110,046

486

Per basic Per diluted Value share 84share 2,384 $ 22.44 $ 21.66 724 50 6.82 6.58 3,000 28.24 27.26 2 0.02 0.02 56 0.51 08 09 06 10 07 08 09 10 6,166 $ 57.52 $ 56.03

HBU ● HBU ●●●Q4 ● HBU ● Total proved ● Total proved ● HBU Includes 3.8 stockprobable options, deferred common●shares, sharesownership and incentive ● PBG’s(1)ownership of million PBN ● PBG’s ofshares. PBN PBN directors deferred common ● Total probable ● Total ● PBN ● PBG’s(2)ownership of PMG ● PBG’s ownership of PMG ● PMG ● Bestownership estimateofcontingent Best estimate contingent resources ● PMG shares. Calculated using●closing market price on December 31, 2010 of $21.71 per petroBakken share multiplied by petrobank’s 109.8 millionresources petroBakken ● PMG spun-off to PBG shareholders ● PMG spun-off to PBG shareholders ● PMG spun-off to PBG shareholders ● PMG spun-off to PBG shareholders (3) proved plus probable reserves plus best estimate contingent resources using forecast prices discounted at 8% (before tax).

● Total ● Total ● Best e

(1) Net present values Corporate are before and tax and (1) Net present values are before tax and (4) Includes the Heavy oil Business unit. discounted at 10% for PBN and PMG, discounted at 10% for PBN and PMG, Assumes 3.8 million stock options, deferred common shares, directors deferred common shares incentive and at(5) 8% for the HBU and at 8% and for the HBU shares are exercised.

COMPANY INTERESTHBU RESERVES & BEST ESTIMATENET PRESENT VALUE INTEREST COMPANY 2P RESERVES2P&RESERVES BEST ESTIMATE CONTINGENTincludes RESOURCES only PBG share of each

h 2P RESERVES CONTINGENT RESOURCES ness includes only PBG share(MMboe) of each business unit’s reserves includes Petrominerales (MMboe) 669 661 236 668

157

business unit’s reserves excludes Petrominerales includes Petrominerales ($ billions) (MMboe) 655

5.6

197 493

0609

10 07

● HBU ● Total proved ● Total probable ble ● PBN ● Best estimate contingent resources ources● PMG ● PMG spun-off to PBG shareholders 32 petrobank energy and Resources ltd.

Split out below

236

6.2

635

197

599

560

5.6

6.2

4.3

486

2.2

0.8 06 10

excludes Petrominerales ($ billions)

(MMbbls)

157

4.3

COMPANY INTEREST NET PRESENT VALUE 2P RESERVES & BEST ESTIMATE HBU’S BEST ESTIMATE CONTINGENTCONTINGENT RESOURCES RESOURCES

0.8 07

0608

0709

0810

● HBU ● HBU PBN ● PBG’s share of●PBN ● PMG ● PMG spun-off to PBG shareholders

Split out below

08 06

09 07

10 08

● Total proved ● HBU ● Total probable● PBG’s share of PBN ● Best estimate contingent resources

Split out below

PetroBakken 2010 drilling program Gross PetroBakken Oil wells Natural gas wells Dry Service wells Total PetroBakken Success rate

Exploration

7.0 1.0 0.0 – 8.0 100%

Net 6.5 1.0 0.0 – 7.5 100%

Development Gross Net

Gross

311.0 3.0 3.0 – 317.0 99%

318.0 4.0 3.0 – 325.0 99%

226.1 2.7 3.0 – 231.8 99%

Total

Net 232.6 3.7 3.0 – 239.3 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 (Mbbl) 50,888 80,866 136,153

Developed producing Proved Proved + probable (2P)

Natural Gas (MMcf) 63,790 94,337 148,754

NGL (Mbbl) 3,807 5,414 8,871

Company Interest (1) (Mboe) 66,183 103,028 171,377

Royalty Interests (Mboe) 857 1,025 1,561

(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)

PetroBakken reserves at December 31, 2009 2010 production, net of royalty income Acquisitions Net additions and revisions PetroBakken reserves at December 31, 2010 PetroBakken year-over-year increase in reserves PetroBakken production replacement

Developed Producing 59,415 (15,031) 3,283 17,662 65,326 10% 139%

Proved 89,470 (15,031) 5,344 22,220 102,003 14% 183%

Proved + Probable 143,638 (15,031) 6,817 34,393 169,816 18% 274%

0% 3,044 4,073 6,707

After Tax 5% 10% 2,355 1,966 3,038 2,446 4,472 3,371

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

PetroBakken net present value – forecast prices ($ millions) As at December 31, 2010 Developed producing Total proved Proved + probable

0% 3,355 4,765 8,368

Before Tax 5% 10% 2,574 2,135 3,541 2,845 5,521 4,142

15% 1,849 2,392 3,326

15% 1,711 2,059 2,713

2010 Annual Report 33

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 PetroBakken Capital expenditures ($000) Acquisition/(Disposition) capital ($000) (3) Total capital Less: land value Total capital excluding land value Change in FDC ($000) (4) Proved Proved plus probable Total costs ($000) Proved Proved plus probable Net reserve additions/revisions (Mboe) Proved Proved plus probable FD&A costs ($/boe) (5) Proved Proved plus probable FD&A costs excluding land ($/boe) (5) Proved Proved plus probable For the year ended December 31, 2009 FD&A costs ($/boe) (5) Proved Proved plus probable FD&A costs excluding land ($/boe) (5) Proved Proved plus probable For the three years ended December 31, 2010 FD&A costs ($/boe) (5) Proved Proved plus probable FD&A costs excluding land ($/boe) (5) Proved Proved plus probable

F&D

Acquisitions (2)

Dispositions

FD&A

781,523 781,523 94,751 686,772

714,305 714,305 352,002 362,303

(133,632) (133,632) (133,632)

781,523 580,673 1,362,196 446,753 915,443

44,932 116,303

133,724 173,837

(22,835) (32,540)

155,821 257,600

826,455 897,826

848,029 888,142

(156,467) (166,172)

1,518,017 1,619,796

22,220 34,393

13,608 21,235

(8,264) (14,419)

27,564 41,209

$ $

37.19 26.11

$ $

62.32 41.82

$ $

18.93 11.52

$ $

55.07 39.31

$ $

32.93 23.35

$ $

36.45 25.25

$ $

18.93 11.52

$ $

38.86 28.47

$ $

45.22 33.02

$ $

46.81 32.42

$ $

43.57 32.89

$ $

46.83 32.48

$ $

40.52 30.37

$ $

42.97 29.96

$ $

43.57 32.89

$ $

42.56 29.81

$ $

36.17 27.41

$ $

49.63 34.12

$ $

27.94 18.38

$ $

46.31 33.29

$ $

30.74 23.66

$ $

41.31 28.77

$ $

27.94 18.38

$ $

38.29 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.

34 petrobank energy and Resources ltd.

COMPANY COMPANY INTEREST INTEREST RESERVES RESERVES & BEST & BEST ESTIMATE ESTIMATE CONTINGENT CONTINGENT RESOURCES RESOURCES

691691

4.8 4.8

761761 757757

(MMbbls) (MMbbls)

236236

4.3 4.3

Heavy Oil Business Unit (“HBU”)

COMPANY COMPANY INT HBU’S HBU’S BEST BES ES CONTINGENT CONTINGEN R

includes includes onlyonly PBGPBG share share of each of each business business unit’s unit’s reserves reserves includes includes Petrominerales Petrominerales (MMboe) (MMboe)

($ billions) ($ billions)

Includes Includes onlyonly PBGPBG share share of each of each business business unit’s unit’s reserves reserves excludes excludes Petrominerales Petrominerales (MMboe) (MMboe)

728728

COMPANY COMPANY INTEREST INTEREST 2P RESERVES 2P RESERVES

NETNET PRESENT PRESENT VALUE VALUE (1) (1) 2P RESERVES 2P RESERVES

635635

197197 157157

3.0 3.0

486486

424424

Company interest reserves and resources – forecast prices

1.8 1.8

THAI proved and proved plus probable reserves recognized for the Kerrobert heavy oil project are 3.0 million barrels84 and844.8 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% 50 50to 95.4 million barrels at December 31, 2010. 0.6 0.6

As at December 31, 2010 Proved developed producing 06 06 07 07 08 08 09 09 10 10 Proved ● Total ● Total proved proved Proved + probable (2P) ● Total ● Total probable probable Proved + probable +contingent possible ● Best ● Best estimate estimate contingent resources resources

● Q4

HBU HBU RESERVES RESERVES & BEST & BEST ESTIMATE ESTIMATE

COMPANY COMPANY INTEREST INTEREST

(MMboe) (MMboe)

includes includes onlyonly PBGPBG share share of each of each

business business unit’s unit’s reserves reserves hBu net present value – forecast prices ($ millions) includes includes Petrominerales Petrominerales

6682010 668 669669 655655 66166131, As at December

(MMboe) (MMboe) Before Tax

0% 20 2,405 3,163

Proved 493493reserves Proved + probable reserves Proved + probable + possible reserves Low estimate contingent resources Best estimate contingent resources High estimate contingent resources

SplitSplit out below out below

HBU HBU RESERVES RESERVES & BEST & BEST ESTIMATE ESTIMATE CONTINGENT CONTINGENT RESOURCES RESOURCES (MMbbls) (MMbbls)

7,591 2,785 2.2 2.2 10,506 3,796 15,243 0.8 0.84,971

898 1,386 1,810

06 06 07 07 08 08 09 09 10 10

HBU HBU NETNET PRESENT PRESENT VALUE VALUE 2P RESERVES 2P RESERVES & BEST & BEST ESTIMATE ESTIMATE (1) (1) CONTINGENT CONTINGENT RESOURCES RESOURCES

NETNET PRESENT PRESENT VALUE VALUE 2P RESERVES 2P RESERVES & BEST & BEST ESTIMATE ESTIMATE CONTINGENT CONTINGENT RESOURCES RESOURCES

SplitSplit out below out below

($ billions) ($ billions) 3

300 300 1

1,461 2,088 2,693

● HBU ● HBU ● PBG’s ● PBG’s share share of PBN of PBN

400 400

200 200

1,450 2,067 2,615

After Tax 6.2 6.2 5% 8% 10% 5.6 5.6 11 6 4 4.3 4.3585 885 450 1,117 746 583

0% 20 1,902 2,470

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

600 600 500 500

10% 4 555 722

06 06 07 07 08 08 09 09 10 10

06 06 07 07 08 08 09 09 10 10 ● Total ● Total proved proved ● Total ● Total probable probable ● Best ● Best estimate estimate contingent contingent resources resources

700 700

2,190 3,000 3,794

473,964 560,131 697,221

excludes excludes Petrominerales Petrominerales ($ billions) ($ billions)

236236

5% 8% 197 197 11 6 157157 1,102 724 1,405 929

10,180 84 3,923 84 14,088 5,258 50 50 20,413 6,821

473,964 560,131 697,221

NETNET PRESENT PRESENT VALUE VALUE 2P RESERVES 2P RESERVES & BEST & BEST ESTIMATE ESTIMATE CONTINGENT CONTINGENT RESOURCES RESOURCES

(2)CONTINGENT Bitumen reserve and resource estimates have been based on SAGD technology. 2P RESERVES 2P RESERVES CONTINGENT RESOURCES RESOURCES

(1) (1) CES URCES

ources es

● PMG ● PMG spun-off spun-off to PBG to PBG shareholders shareholders

(1) Net (1)present Net present values values are before are before tax and tax and discounted discounted at 10% atfor 10%PBN for PBN and PMG, and PMG, and at and 8%at for8%the forHBU the HBU

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

06 06 07 07 08 08 09 09 10 10 ● HBU ● HBU ● PBG’s ● PBG’s ownership ownership of PBN of PBN ● PBG’s ● PBG’s ownership ownership of PMG of PMG ● PMG ● PMG spun-off spun-off to PBG to PBG shareholders shareholders

Low estimate contingent resources Best estimate contingent resources High estimate contingent resources

Heavy Oil Bitumen Total (Mbbl)(1) (Mbbl)(2) (Mbbl) 575 575 06 06 07 07 08 08 09 09 10 10 06 06 07 07 3,032 3,032 ● HBU ● HBU ● Total proved prove 4,837 90,572 95,409 ● Total ● PBN ● PBN ● Total ● Total probable proba 8,513 101,512 110,025 ● PMG ● PMG ● Best ● Best estimate estima c

excludes excludes Petrominerales Petrominerales ($ billions) ($ billions) 5

100 100 0

06 06 07 07 08 08 09 09 10 10

● Proved ● Proved ● Probable ● Probable ● Best ● Best estimate estimate contingent contingent resources resources

06 06 07 07 08 08 09 09 10 10

● Proved ● Proved ● Probable ● Probable ● Best ● Best estimate estimate contingent contingent resources resources (1) Before (1) Before tax, discounted tax, discounted at 8%at 8%

06 06 07 07 08 08 09 09 10 10

● HBU ● HBU ● PBG’s ● PBG’s ownership ownership of PBN of PBN ● PBG’s ● PBG’s ownership ownership of PMG of PMG ● PMG ● PMG reserves reserves spun-off spun-off to PBG to PBG shareholder shareholder ● HBU ● HBU bestbest estimate estimate contingent contingent reserves reserves

2010 Annual Report 35

The

Real Value of Petrobank

talent and experience

petrobank energy and Resources ltd.

Compression/coolers

Control room oil treater Recycle pump tankage area Vapour recovery unit Clean oil cooler Gas separator

Inlet headers pipeline right of way

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

2010 Annual Report

existing farmland

MD&A

Management’s Discussion And Analysis Summary of Results(1) Peter Cheung, Vice President Finance and Chief Financial Officer

Financial ($000s, except where noted) Oil and natural gas revenue from continuing operations Funds flow from continuing operations(2) Per share – basic ($) – diluted ($) Net income from continuing operations Per share – basic ($) – diluted ($) Net income (loss) attributable to Petrobank shareholders(3) Per share – basic ($) – diluted ($) Capital expenditures PetroBakken Heavy Oil Business Unit (“HBU”) Total capital expenditures from continuing operations Total assets Common shares outstanding, end of period (000s) Basic Diluted(4) Operations PetroBakken operating netback ($/boe)(2) (5) Oil and NGL revenue ($/bbl)(6) Natural gas revenue ($/Mcf)(6) Oil and natural gas revenue(6) Royalties Production expenses Operating netback(2) (5) (7) Average daily production PetroBakken – oil and NGL (bbls) PetroBakken – natural gas (Mcf) Total conventional (boe)(5) (8)

Q4 2010

2010

2009

2008

258,359 155,344 1.46 1.46 1,315 0.01 0.01 (35,612) (0.34) (0.34)

1,008,556 636,754 6.10 5.96 21,308 0.20 0.20 115,785 1.11 1.03

575,588 380,016 4.29 3.94 68,559 0.77 0.73 145,079 1.64 1.52

585,800 415,059 5.05 4.56 137,272 1.67 1.59 244,482 2.97 2.76

262,758 37,521 300,279 6,402,586

811,871 121,492 933,363 6,402,586

394,023 76,019 470,042 5,766,568

545,833 82,332 628,165 2,361,707

106,236 110,046

93,617 108,596

83,525 99,043

75.19 3.96 67.00 9.84 8.97 48.19

72.77 4.22 65.28 9.34 8.18 47.76

64.27 4.40 58.97 8.55 7.38 43.04

92.80 8.06 86.78 10.03 8.76 67.99

34,754 39,474 41,333

35,109 39,473 41,688

22,648 22,110 26,333

15,369 14,436 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. 36 Petrobank Energy and Resources Ltd.

MD&A

Forward-Looking Statements In 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 forwardlooking 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 forwardlooking 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 Measures This 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 Units During 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”.

Comparatives Comparisons 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. 2010 Annual Report 37

MD&A

Net Income Throughout 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 • On December 31, 2010, Petrobank and Petrominerales completed a corporate reorganization which resulted in Petrobank shareholders receiving 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. • On October 8, 2010, Petrobank acquired the remaining 50 percent interest in the Dawson heavy oil project from Shell Canada Ltd. The Company received $2.8 million cash in January 2011 upon regulatory approval of the project. PetroBakken • Fourth quarter production decreased slightly to 41,333 barrels of oil equivalent per day (“boepd”) compared to 45,621 boepd in the fourth quarter 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. • Operating netbacks (excluding hedging activity) averaged $48.19 per boe in the fourth quarter of 2010, an increase of three percent compared to the fourth quarter of 2009, primarily due to higher benchmark oil prices. • PetroBakken drilled 77.4 net wells in the quarter, the majority of which were drilled in southeast Saskatchewan, particularly the Bakken play, however activity levels increased in the Cardium play in the fourth quarter as lease conditions improved.

2010 Highlights and Significant Transactions • On September 30, 2010, Petrobank completed the acquisition of Baytex Energy Ltd.’s 50 percent interest in the Kerrobert heavy oil project for cash consideration of $18.1 million. • On January 8, 2010, Petrobank completed an early conversion offering which resulted in US$250.7 million principal amount of 5.125% convertible debentures due July 10, 2015 being exercised prior to maturity. Upon the conversion, a total of 7,452,099 Petrobank common shares were issued. On April 23, 2010, the remaining US$149.3 million principal amount of Petrobank’s 5.125% convertible debentures was early converted. An aggregate of US$27.4 million was paid and 3,920,446 common shares were issued. On May 10, 2010, the remaining US$5.1 million principal amount of Petrobank’s 3% convertible debentures was early converted into 179,009 common shares. As a result of these three events, there are no longer any Petrobank convertible debentures outstanding. • Funds flow from continuing operations increased 68 percent to $636.8 million in 2010 primarily as a result of PetroBakken’s increased production and higher operating netbacks. On a per basic and diluted share basis, funds flow from operations increased 42 percent and 52 percent, respectively. • Net income from continuing operations decreased by 69 percent to $21.3 million in 2010. The decrease is due mainly to the inclusion of a foreign exchange gain of $57.8 million in 2009, which resulted from the translation of Petrobank’s U.S. dollar convertible debentures. • Net income attributable to Petrobank shareholders decreased by 20 percent to $115.8 million in 2010. The decrease is due mainly to the recognition of a $70.1 million accumulated other comprehensive loss resulting from the historic translations of Petrominerales U.S. dollar amounts in the consolidated financial statements, recorded in net income upon the spin-off of Petrominerales. PetroBakken • PetroBakken’s production increased 58 percent to 41,688 boepd in 2010 from 26,333 boepd in 2009 primarily due to the acquisition of TriStar Oil and Gas Ltd. on October 1, 2009. • On January 25, 2010, PetroBakken issued US$750 million of convertible debentures. The debentures are convertible into common shares of PetroBakken at a conversion price that is adjusted for dividends paid. Based on dividends declared to February 2011, the conversion price was $37.74 per share. The convertible debentures have an annual coupon rate of 3.125 percent and mature in February 2016. • On February 25, 2010, PetroBakken acquired all of the issued and outstanding shares of Berens Energy Ltd. (“Berens”) for cash consideration of $252.8 million and the assumption of bank indebtedness of approximately $74.9 million. There was a working capital deficiency of $16.6 million at the acquisition date. • On March 12, 2010, PetroBakken acquired all of the issued and outstanding shares of Rondo Petroleum Inc. (“Rondo”) 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. There was a working capital deficiency of $22.2 million at the acquisition date.

38 Petrobank Energy and Resources Ltd.

MD&A

• On April 1, 2010, PetroBakken acquired all of the issued and outstanding shares of Result Energy Inc. (“Result”) for cash consideration (net of cash acquired) of $141.2 million and the issuance of approximately 11.2 million PetroBakken common shares. There was working capital of $2.7 million at the acquisition date. • During the year ended December 31, 2010, PetroBakken closed divestitures representing approximately 3,800 boepd of production (50 percent natural 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. • On May 17, 2010, PetroBakken commenced a normal course issuer bid (“NCIB”) pursuant to which PetroBakken is authorized to purchase up to 9,431,255 common shares. The NCIB will end on May 18, 2011 or an earlier time if the NCIB is completed or terminated at PetroBakken’s election. As of March 7, 2011, 1,680,400 common shares have been repurchased under the NCIB for $36.4 million.

Subsequent Events • On January 4, 2011, Petrobank entered into a new three year $200 million credit agreement with a syndicate of lenders.

Financial And Operational Review The 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, 2010 2009 Change PetroBakken Oil and NGL (bbls) Natural gas (Mcf) Total PetroBakken (boe)

34,754 39,474 41,333

38,796 40,951 45,621

(10%) (4%) (9%)

Years ended December 31, 2010 2009 35,109 39,473 41,688

Change

22,648 22,110 26,333

55% 79% 58%

Production increased by 58 percent for the year ended December 31, 2010, primarily due to the acquisition of TriStar on October 1, 2009. In the fourth 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 capital program. PetroBakken drilled 239.3 net wells in 2010 (2009 – 117.3), with 77.4 net wells drilled in the fourth quarter (2009 – 64.8). In 2010, 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 approximately 5,600 boepd of production starting in late February 2010. Non-core property dispositions (approximately 5,700 boepd of production) were completed between December 2009 and April 2010 and more than offset the acquired production on a year-to-date total and average basis.

2010 Annual Report 39

MD&A

Average January production is estimated at 41,400 boepd based on field estimates. In the Cardium, PetroBakken now has 27 net wells waiting to be completed or brought on production. Average Benchmark and Realized Prices

WTI (US$/bbl) WTI ($/bbl) AECO natural gas ($/Mcf) US$ per C$1 PetroBakken – oil and NGL Realized price per bbl ($/bbl) Oil price discount as a % of WTI PetroBakken – natural gas Realized price per Mcf ($/Mcf)

Three months ended December 31, 2010 2009 Change 85.18 76.19 12% 86.24 80.47 7% 3.64 4.50 (19%) 0.99 0.95 4%

Years ended December 31, 2010 2009 79.53 61.80 81.87 70.57 4.00 3.95 0.97 0.88

Change 29% 16% 1% 10%

76.31 14%

71.63 11%

7% 27%

73.96 11%

64.27 9%

15% 22%

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.

Revenue The 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

276,334 (26,803) 8,828 258,359 (17,975) (7%)

575,588 366,251 66,717 1,008,556 432,968 75%

PetroBakken December 31, 2009 Sales volume Realized prices December 31, 2010 $ change in revenue % change in revenue

Net Realized Prices Three months ended December 31, 2010 2009 Change PetroBakken Gross revenue Transportation expense Total revenue, net of transportation Gross revenue ($/boe) Transportation expense ($/boe) Realized price, net of transportation ($/boe)

Years ended December 31, 2010 2009

Change

258,359 3,593 254,766 67.94 0.94

276,334 3,297 273,037 65.84 0.79

(7%) 9% (7%) 3% 19%

1,008,556 15,270 993,286 66.28 1.00

575,588 8,820 566,768 59.89 0.92

75% 73% 75% 11% 9%

67.00

65.05

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.

40 Petrobank Energy and Resources Ltd.

MD&A

Royalties

PetroBakken(1) PetroBakken – $ per boe PetroBakken – royalties as a % of realized price

Three months ended December 31, 2010 2009 Change 37,479 42,565 (12%) 9.84 10.14 (3%) 15%

16%

(6%)

Years ended December 31, 2010 2009 142,064 82,151 9.34 8.55 14%

Change 73% 9%

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 in Saskatchewan, the first 37,740 barrels of production from horizontal wells receive a royalty incentive but incur Saskatchewan Resource Surcharge of 1.7 percent. On Crown land in Alberta, horizontal oil wells are subject to a maximum 5 percent royalty rate for 18 to 48 months depending on well length. Gain (Loss) on Risk Management Contracts Three months ended December 31, 2010 2009 Change Realized gain (loss): Crude oil derivative contracts Natural gas derivative contracts Interest rate swap contracts Foreign exchange contracts Unrealized gain (loss): Crude oil derivative contracts Natural gas derivative contracts Interest rate swap contracts Foreign exchange contracts Gain (loss) on risk management contracts

Year ended December 31, 2010 2009

Change

(1,017) 1,210 (327) (134)

2,952 (31) (2,119) 2,332 3,134

85% -

(2,925) 5,117 (2,414) (222)

23,984 (31) (2,313) 2,332 23,972

(4%) -

(16,244) (1,357) 639 (16,962)

(11,836) 210 (328) (1,343) (13,297)

(37%) (28%)

(8,347) (428) 571 (8,204)

(40,926) 210 118 (1,343) (41,941)

80% 384% 80%

(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:

Risk management asset (liability), December 31, 2009 Unrealized gain (loss) Contracts acquired Risk management asset (liability), December 31, 2010

Crude Oil

Natural Gas

Interest

Year ended

(6,488)

470

(118)

(6,136)

(8,347) -

(428) 1,980

571 (688)

(8,204) 1,292

(14,835)

2,022

(235)

(13,048)

2010 Annual Report 41

MD&A

At December 31, 2010, PetroBakken recorded a $14.8 million liability related to crude oil price risk management contracts. The following is a summary of crude oil derivative contracts in place as at December 31, 2010: Crude Oil Price Risk Management Contracts – WTI(1) Term Jan. 1, 2011 – Dec. 31, 2011 Jan. 1, 2011 – Dec. 31, 2011 Jan. 1, 2011 – Jun. 30, 2011 Jan. 1, 2011 – Jun. 30, 2012 Jul. 1, 2011 – Dec. 31, 2012 Jan. 1, 2012 – Jun. 30, 2013

Volume (bopd) 2,500 4,500 1,000 2,000 1,000 500

Average Price ($/bbl) $78.00 floor/$95.40 ceiling $76.11 floor/$101.43 ceiling $75.00 floor/$104.53 ceiling $75.00 floor/$99.59 ceiling $75.00 floor/$98.25 ceiling $75.00 floor/$109.00 ceiling

Benchmark C$ WTI US$ WTI US$ WTI US$ WTI US$ WTI 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: Term Jan. 1, 2012 – Jun. 30, 2013 Jul. 1, 2012 – Jun. 30, 2013

Volume (bopd) 2,500 1,000

Average Price ($/bbl) $75.00 floor/$121.93 ceiling $75.00 floor/$117.45 ceiling

Benchmark US$ WTI US$ WTI

Volume (bopd) 10,000 5,500 2,000

Average Price ($/bbl) $76.14 floor/$99.42 ceiling $75.00 floor/$111.98 ceiling $75.00 floor/$119.19 ceiling

Benchmark US$ WTI US$ WTI US$ WTI

The average of the above volumes is as follows: Term 2011 2012 2013

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 Jan. 1, 2011 – Mar. 31, 2011 Jan. 1, 2011 – Dec. 31, 2011

Volume (GJ/d) 2,000 2,000

Price ($/GJ) $6.00 $6.02

Type Fixed Price Swap Fixed Price Swap

At December 31, 2010, PetroBakken recorded a $0.2 million liability related to the following interest rate swap contracts: Term Jan. 2011 – Feb. 2011 Jan. 2011 – Apr. 2011 Jan. 2011 – Jan. 2012 Jan. 2011 – Jan. 2012 Jan. 2011 – Feb. 2012 Jan. 2011 – Feb. 2012 Jan. 2011 – Apr. 2012 Jan. 2011 – Jun. 2012

Notional Principal/Month C$40 million C$50 million C$50 million C$50 million C$25 million C$25 million C$50 million C$25 million

Fixed Annual Rate (%) 2.390% 1.050% 1.620% 1.653% 1.540% 1.510% 1.300% 2.094%

Production Expenses

PetroBakken PetroBakken – $ per boe

Three months ended December 31, 2010 2009 Change 34,126 34,535 (1%) 8.97 8.23 9%

Years ended December 31, 2010 2009 124,481 70,913 8.18 7.38

Change 76% 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 light oil production. Operating costs in PetroBakken’s core area of southeast Saskatchewan averaged $8.15 per boe in the fourth quarter and $7.12 per boe in 2010, as compared to $6.71 per boe and $6.36 per boe, respectively, in 2009. Central Alberta production expenses averaged $8.51 per boe in the fourth quarter and $8.75 for the first nine months of 2010, with limited comparative information prior to these periods. 42 Petrobank Energy and Resources Ltd.

MD&A

General and Administrative Expenses Three months ended December 31, 2010 2009 Change 3,393 1,272 167%

HBU and Corporate

Change 111%

8,572

5,557

54%

33,233

15,253

118%

11,965

6,829

75%

41,865

19,353

116%

2.25

1.32

70%

2.18

1.59

37%

PetroBakken Total general and administrative expense PetroBakken – $ per boe

Years ended December 31, 2010 2009 8,632 4,100

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 Three months ended December 31, 2010 2009 Change 2,629 2,152 22% 5,450 6,191 (12%)

HBU and Corporate PetroBakken Total stock-based compensation expense

8,079

8,343

(3%)

Years ended December 31, 2010 2009 9,505 6,274 22,888 18,650 32,393

24,924

Change 51% 23% 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

HBU and Corporate PetroBakken Total interest expense

Three months ended December 31, 2010 2009 Change 161 4,238 (96%) 21,071 11,547 82% 21,232 15,785 35%

Years ended December 31, 2010 2009 1,900 13,314 75,611 18,699 77,511 32,013

Change (86%) 304% 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, and capital expenditures. On average, bank debt outstanding was $767.5 million in the fourth quarter of 2010 as compared to $861.4 million in the fourth quarter of 2009 and $602.5 million in 2010 as compared to $349.0 million in 2009.

2010 Annual Report 43

MD&A

Foreign Exchange Loss (Gain)

HBU and Corporate PetroBakken Total foreign exchange loss (gain)

Three months ended December 31, 2010 2009 Change 25 (8,504) (19,917) 1,105 (19,892) (7,399) 169%

Years ended December 31, 2010 2009 (8,769) (57,753) (19,541) 1,105 (28,310) (56,648)

Change (85%) (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

HBU and Corporate PetroBakken Total DD&A expense PetroBakken – $ per boe

Three months ended December 31, 2010 2009 Change 220 155 42% 134,113 142,523 (6%) 134,333 142,678 (6%) 35.27 33.96 4%

Years ended December 31, 2010 2009 656 411 525,403 303,714 526,059 304,125 34.53 31.60

Change 60% 73% 73% 9%

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)

HBU and Corporate PetroBakken Total future income taxes (recovery)

Three months ended December 31, 2010 2009 Change 1,519 1,325 15% 1,798 (33,653) 3,317 (32,328) -

Years ended December 31, 2010 2009 (3,333) (3,514) 31,450 (24,027) 28,117 (27,541)

Change (5%) -

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 Three months ended December 31, 2010 2009 Change PetroBakken Net income attributable to NCI

6,238

12,019

(48%)

Years ended December 31, 2010 2009 18,187 12,019

Change

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. 44 Petrobank Energy and Resources Ltd.

51%

MD&A

Capital Expenditures

HBU PetroBakken (“PBN”) Total capital expenditures

Three months ended December 31, 2010 2009 Change 37,521 15,554 141% 262,758 177,278 48% 300,279 192,382 56%

Years ended December 31, 2010 2009 121,492 76,019 811,871 394,023 933,363 470,042

Change 60% 106% 99%

Q4 2010 Capital Expenditures By Type Drilling and completions Facilities Land Seismic Pilot capital Asset acquisition Other (1) Total capital expenditures

HBU 14,936 13,831 504 82 6,864 1,304 37,521

PBN 207,637 39,643 7,195 303 371 7,609 262,758

Total 222,573 53,474 7,699 385 6,864 371 8,913 300,279

(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 Drilling and completions Facilities Land Seismic Pilot capital Asset acquisition Other (1) Total capital expenditures

HBU

PBN

Total

24,644 28,243 504 6,028 31,148 18,057 12,868 121,492

568,905 91,245 94,751 6,359 30,348 20,263 811,871

593,549 119,488 95,255 12,387 31,148 48,405 33,131 933,363

(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% interest in our Kerrobert project from Baytex Energy Ltd., operating expenditures in excess of revenues relating to the two well-pairs drilled at 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.

2010 Annual Report 45

MD&A

Goodwill There were no changes to goodwill in the fourth quarter. The total goodwill increase for the year is $457.7 million, which includes goodwill from PetroBakken’s acquisitions of Berens, Rondo, and Result. Goodwill as at December 31, 2010 was $1,518.6 million.

Summary Of Quarterly Results Q4 Financial ($000s except where noted) Oil and natural gas revenue from continuing operations Funds flow from continuing operations(1) Per share – basic ($) – diluted ($) Net income (loss) from continuing operations Per share – basic ($) – diluted ($) Net income (loss) attributable to Petrobank shareholders Per share – basic ($) – diluted ($) Capital expenditures PetroBakken HBU Total from continuing operations PetroBakken Operations Operating netbacks by product Crude oil and NGL sales price, ($/bbl)(3) (5)

2009 Q3

258,359

228,537

245,954

275,706

276,334

101,316

102,452

95,486

155,344 1.46 1.46 1,315 0.01 0.01

139,325 1.31 1.31 3,003 0.03 0.03

153,714 1.46 1.43 (14,524) (0.14) (0.14)

188,371 1.88 1.77 31,514 0.31 0.31

166,833 1.80 1.59 20,740 0.22 0.22

64,243 0.71 0.67 35,315 0.38 0.37

75,959 0.90 0.85 21,928 0.26 0.26

72,981 0.88 0.83 (9,424) (0.11) (0.11)

(35,612)

27,848

41,050

82,499

57,108

54,846

34,667

(1,542)

(0.34) (0.34)

0.26 0.25

0.39 0.35

0.82 0.76

0.61 0.56

0.59 0.56

0.41 0.40

(0.02) (0.02)

262,758 37,521 300,279

241,309 49,385 290,694

122,688 10,652 133,340

185,116 23,934 209,050

177,278 15,554 192,832

107,820 26,737 134,557

38,901 12,318 51,219

70,024 21,410 91,434

Royalties Production expenses Operating netback(1) (4) Natural gas sales price, ($/Mcf)(3) Royalties Production expenses Operating netback(1) (4) Oil equivalent sales price, ($/boe)(3) Royalties Production expenses Operating netback(1) (2) (4) Average daily production Crude oil and NGL (bbls)(5) Natural gas (Mcf) Total (boe)(2)

75.19 10.94 9.56 54.69 3.96 0.66 0.98 2.32 67.00 9.84 8.97 48.19

68.43 9.67 8.88 49.88 3.82 0.62 1.00 2.20 60.63 8.64 8.38 43.61

70.98 10.36 7.89 52.73 4.11 0.60 1.03 2.48 62.86 9.17 7.59 46.10

76.08 10.56 7.95 57.57 5.20 0.60 1.12 3.48 70.41 9.68 7.80 52.93

71.63 11.26 8.45 51.92 4.61 0.63 1.16 2.82 65.05 10.14 8.23 46.68

67.65 10.75 7.05 49.85 3.55 0.54 0.93 2.08 60.66 9.62 6.83 44.21

62.22 7.97 6.66 47.59 3.91 0.67 0.95 2.29 56.64 7.40 6.52 42.72

34,754 39,474 41,333

33,230 41,193 40,095

34,852 44,469 42,263

37,654 32,662 43,098

38,796 40,951 45,621

15,185 16,177 17,881

16,761 16,906 19,579

(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.

46 Petrobank Energy and Resources Ltd.

2010 Q3

48.57 5.39 6.98 36.20 5.35 0.78 0.90 3.67 46.81 5.32 6.81 34.68 19,722 14,179 22,085

MD&A

Significant factors influencing quarterly results were: • PetroBakken light oil and natural gas production since the fourth quarter of 2009 increased significantly over prior quarters, mainly due to the 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. • PetroBakken base production declines and delays in bringing production on stream resulted in a decline in liquids from the fourth quarter of 2009 to the third quarter of 2010. • PetroBakken production increased three percent in the fourth quarter of 2010 compared to the third quarter of 2010 primarily as a result of new Cardium wells brought on production. • Crude oil benchmark prices have generally improved throughout 2009 and into 2010, contributing to improving operating netbacks, revenue and funds 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. • Capital expenditures increased from 2009 as we advanced the HBU development projects and PetroBakken expanded its drilling program considerably 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. • PetroBakken production expenses increased in the fourth quarter of 2009 with the acquisition of TriStar but declined in the first and second quarters of 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 Operations The 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 • Production was 33,142 barrels of oil per day (“bopd”) in the fourth quarter of 2010, a 35 percent increase from the same period in 2009. • Petrominerales generated a strong operating netback of $49.52 per barrel in the fourth quarter of 2010, a one percent decrease over the same period in 2009. • To support high impact Llanos Basin focused growth objectives, Petrominerales committed to a 9.65 percent stake of the Oleducto Bicentenario de Colombia pipeline. Completion of the project is expected by the end of 2012 or the beginning of 2013. 2010 Highlights and Significant Transactions • Petrominerales increased crude oil production to 37,027 bopd, a 66 percent gain over 2009. • Petrominerales generated a strong operating netback of $51.63 per barrel in 2010, a 21 percent increase over 2009. • Petrominerales was the most active exploration company in Colombia in 2010, drilling 16 exploration wells, representing 15 percent of all exploration wells drilled in Colombia in 2010. • Petrominerales exploration acreage in Peru increased significantly to 5.4 million net acres. • Petrominerales raised US$550 million through a convertible bond issuance in August. The bonds are convertible into common shares of Petrominerales, have an annual coupon of 2.625 percent and mature in August 2016. • Starting in the second quarter, Petrominerales initiated a quarterly dividend of $0.125 per share ($0.50 per share annualized).

2010 Annual Report 47

MD&A

The operating results for this discontinued operation for the periods noted are shown in the following table: Three months ended December 31, 2010 2009 Change Financial Revenues Oil sales Royalties Interest income Expenses Production Purchased oil Transportation General and administrative and acquisition costs Stock-based compensation Interest Foreign exchange loss (gain) Depletion, depreciation and accretion Income before taxes and NCI Current taxes (recovery) Future income taxes Net income before NCI Income applicable to NCI Net income from discontinued operations Cumulative loss on translation of Petrominerales Total impact on net income Operations Capital expenditures Net realized prices ($/bbl) WTI Sales price(1) Transportation Realized price US$ discount as a percent of WTI Reconciliation of changes in revenue Sales volume variance Price variance Oil revenue from third party oil purchases $ change in revenue % change in revenue Operating netback ($/bbl)(2) Oil revenue(3) Royalties Production expenses Operating netback Average daily production – oil (bbls)(4)

Years ended December 31, 2010 2009 Change

253,723 (36,113) 473 218,083

169,687 (16,820) 15 152,882

50% 115% 3,053% 43%

1,078,857 (116,482) 1,020 963,395

518,086 (47,297) 411 471,200

108% 146% 148% 104%

39,031 12,703 19,512 8,022 3,077 11,558 (8,373) 62,727 148,257 69,826 (17,994) 36,537 51,283 18,134 33,149

18,952 16,027 4,076 1,156 2,614 (2,143) 44,205 84,887 67,995 2,752 10,488 54,755 18,387 36,368

106% 22% 97% 166% 342% 291% 42% 75% 3% 248% (6%) (1%) (9%)

112,854 66,096 91,193 26,326 11,580 25,898 7,758 271,590 613,295 350,100 35,574 63,483 251,043 86,490 164,553

65,738 53,537 13,686 5,167 11,534 9,346 177,780 336,788 134,412 10,234 11,588 112,590 36,070 76,520

72% 70% 92% 124% 125% (17%) 53% 82% 160% 248% 448% 123% 140% 115%

70,076

(36,927)

36,368

94,477

76,520

23%

164,760

86,566

90%

519,883

320,815

62%

86.24

80.47

81.87

70.57

16%

81.53 6.60 74.93 13%

72.03 6.80 65.23 19%

13% (3%) 15% (32%)

75.62 6.82 68.80 16%

63.11 6.52 56.59 18%

20% 5% 22% (11%)

38,858 32,475 12,703 84,036 50%

68,010 16,528 84,538 99%

(43%) 96% (1%) (49%)

376,529 115,903 68,339 560,771 108%

258,607 (104,789) 153,818 42%

46% 265% 157%

74.93 12.21 13.20 49.52 33,142

65.23 7.14 8.05 50.04 24,555

15% 71% 64% (1%) 35%

68.80 8.72 8.45 51.63 37,027

56.59 5.76 8.01 42.82 22,360

22% 51% 5% 21% 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).

48 Petrobank Energy and Resources Ltd.

MD&A

Average Daily Production Production 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 Prices The 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’s 2010 average realized oil price of $68.80 per barrel increased 22 percent mainly due to a 16 percent increase in the benchmark WTI price and the narrowing of the Vasconia crude discount to WTI. The fourth quarter realized oil price of $74.93 per barrel increased 15 percent due to a seven 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. Transportation costs increased to $6.60 per barrel, a 37 percent increase in the fourth quarter mainly due to trucking a larger portion of volumes 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.

Revenue Oil revenue in 2010 increased 108 percent due to a 63 percent increase in sales volumes of produced oil and 22 percent increase in realized crude oil prices. 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.

Royalties Royalties 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 Expenses In 2010, production expenses increased 106 percent during the quarter and 72 percent for the year, primarily due to higher production levels and increased per barrel costs. On a per barrel basis, production expenses increased to $13.20 and to $8.45 per barrel for the fourth quarter and the year ended. The 2010 increase is primarily related to higher water handling costs and a one-time cost at Orito charged by the field operator.

General and Administrative Expenses The 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 Expenses The 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 Expense In 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) The Colombian peso devaluated six percent relative to the U.S. dollar in the fourth quarter, from 1,800:1 at September 30, 2010 to 1,914:1 at December 31, 2010. This change in exchange rates resulted in an $8.4 million foreign exchange gain primarily on Colombian peso denominated accounts 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 which resulted in a $7.8 million foreign exchange loss. Changes in the Colombian peso exchange rate also impact Petrominerales’ U.S. dollar denominated expenses and expenditures as approximately 65 percent of expenditures are incurred in Colombian pesos.

2010 Annual Report 49

MD&A

Depletion, Depreciation and Accretion (“DD&A”) Expense DD&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 Expense Petrominerales’ pre-tax income is subject to the Colombian statutory income tax rate of 33 percent. In addition, an equity tax is charged on equity capitalization levels in Colombia. Petrominerales had an effective tax rate of 26 percent in the fourth quarter of 2010 and 28 percent for the year. 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 Interest The 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 Expenditures Expenditures in the fourth quarter relate to facilities costs at the Corcel central processing facility to increase fluid handling, and installation of flowlines 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.

Commitments The 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 HBU and Corporate Office operating leases Capital leases PetroBakken Office operating leases Drilling and completion rigs Total Company

< 1 Year

1-3 Years

3-5 Years

Thereafter

Total

3,533 838

9,018 1,159

9,391 583

15,237 -

37,179 2,580

4,834 8,605 17,810

12,382 17,701 40,260

13,744 6,902 30,620

25,852 41,089

56,812 33,208 129,779

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.

50 Petrobank Energy and Resources Ltd.

MD&A

Liquidity and Capital Resources 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 and liquidity:

Working capital surplus (deficit) Bank debt – principal Convertible debentures – principal amount (US$) Common share capital(1) Credit facility Available credit capacity

HBU and Corporate $ 1,942 $ $ -

Petrobank PetroBakken Consolidated $ (193,590) $ (191,648) $ 829,788 $ 829,788 $ 750,000 $ 750,000

$ 1,359,382 $ 3,147,238 $ 200,000 (2) $ 1,200,000 $ 200,000 (2) $ 370,212

$ 1,359,382

(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 Corporate At 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.

PetroBakken PetroBakken’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. As at December 31, 2010, PetroBakken had $829.8 million of bank debt drawn on a $1.2 billion credit facility. PetroBakken’s credit facility is with a 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 EBITDA to 4:1, and limit secured debt to 50% of total liabilities plus total equity. PetroBakken is in compliance with all of these covenants. On January 25, 2010, PetroBakken issued convertible debentures with an annual coupon of 3.125 percent for gross proceeds of US$750 million. The convertible debentures have a financial covenant that limits the amount of security and encumbrances to 35% of PetroBakken’s total assets. PetroBakken is in compliance with this covenant. Proceeds from the issuance of the convertible debenture were used to repay all outstanding bank debt. In February 2010, PetroBakken made a $327.7 million cash payment, including repayment of bank debt, for the acquisition of Berens. In March 2010, PetroBakken made a $104.7 million cash payment, including repayment of bank debt, for the acquisition of Rondo, and in April 2010, PetroBakken made a net $141.2 million cash payment for the acquisition of Result. PetroBakken closed non-core property dispositions for net proceeds of $133.6 million.

2010 Annual Report 51

MD&A

In addition to the financial resources noted above, other possible sources of funds available to PetroBakken include the following: • Funds flow from operations; • Increases under the existing credit facility; • Issuance of common shares of PetroBakken; • Issuance of subordinated or convertible debt; • Sale of producing or non-producing assets. Cash generated from a sale may be reduced by any required debt payments; and • Monetization of risk management assets. PetroBakken expects to satisfy ongoing working capital requirements with funds flow from operations, cash and available credit.

Capital Plan HBU 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 Data The 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 Uncertainties Petrobank 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. Management believes it is neither appropriate nor possible to eliminate 100% of our exposure to fluctuations in commodity prices. The Company monitors 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.

52 Petrobank Energy and Resources Ltd.

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 risk and credit risk. Management believes it is neither appropriate nor possible to eliminate 100% of the Company’s exposure to these risks. As described in 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.

2010 Annual Report 53

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: PetroBakken Crude oil Natural gas Currency Interest rate

(millions) US$1.00/bbl WTI reference price (assuming 35,000 bopd) 1,000 bopd of production @ US$85/bbl WTI $1.00/Mcf AECO reference price (assuming 39 MMcf/d) 10.0 MMcf per day of production @ $4.00/Mcf AECO US$0.01 in exchange rate 1% change in interest rate

$ $ $ $ $ $

9.7 21.4 12.2 11.9 8.5 5.3

Critical Accounting Policies and Estimates The 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.

54 Petrobank Energy and Resources Ltd.

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 Policies There 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 In February 2008, the CICA’s Accounting Standards Board confirmed the convergence of Canadian GAAP with International Financial Reporting 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”. Petrobank commenced its IFRS Conversion Project in late 2008 by completing an initial scoping phase, and has established a project plan and project team, which includes key finance staff, management, external advisors and the audit committee.

2010 Annual Report 55

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 Accounting policies and procedures:

Milestones

Progress

• Identify differences between

• Senior management approval and

• Accounting policy alternatives

Canadian GAAP and IFRS.

• Revise and finalize accounting policies under IFRS.

• Identify potential adjustments to initial and subsequent IFRS financial statements.

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.

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.

• Senior management approval and audit committee review of pro forma financial statements by Q4 2010.

• Quantify the effects of converting

• 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

to IFRS.

statements and notes have been prepared.

Training and communication:

• Develop and deliver targeted

• Training to be provided to relevant

• Key employees involved with

• Ensure internal and external

• Impacts of converting to IFRS

• Quarterly disclosure of project

IFRS training to employees and management. stakeholders receive ongoing appropriate communications.

employees prior to changeover date.

communicated prior to changeover.

implementation have completed training throughout the year. 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.

• Impacts of contracts identified. • Taxation impacts identified by Q4 2010.

currently underway by individuals experienced with taxation.

taxation. IT systems:

• Identify changes required to IT

• Necessary changes to IT systems

• Implement solution for capturing

• Solution for capturing financial

financial information under Canadian GAAP and IFRS during the year of transition to IFRS.

to have a significant impact on current contracts.

• Analysis of taxation impacts is

• Identify impacts of conversion on

systems and implement solutions.

• Adoption of IFRS is not expected

implemented by changeover date. 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.

56 Petrobank Energy and Resources Ltd.

• 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 Property, Plant and Equipment

Summary of Exemption Available

• 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.

2010 Annual Report 57

MD&A

Expected Areas of Significance The 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 Impairment of Assets (“IAS 36”)

Impact of Policy Adoption

• 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.

58 Petrobank Energy and Resources Ltd.

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 Policies Certification 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.

Outlook In 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. 2010 Annual Report 59

Financial Statements

Management’s Report Management 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 Calgary, Canada March 14, 2011

60 Petrobank Energy and Resources Ltd.

Vice President Finance & Chief Financial Officer

Financial Statements

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 Statements Management 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 Responsibility Our 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.

Opinion In 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

2010 Annual Report 61

Financial Statements

Consolidated Balance Sheets (Thousands of Canadian dollars) As at December 31, Assets Current assets Cash and cash equivalents Accounts receivable Prepaid expenses Risk management assets (Note 13) Future income tax asset (Note 10) Assets of discontinued operations (Note 18)

Capital assets (Note 3) Goodwill (Note 4) Assets of discontinued operations (Note 18) Total assets Liabilities and Shareholders’ Equity Current liabilities Accounts payable and accrued liabilities Current portion of capital lease obligations (Note 13) Risk management liabilities (Note 13) Future income tax liabilities (Note 10) Liabilities of discontinued operations (Note 18)

Bank debt (Note 6) Convertible debentures (Note 7) Capital lease obligations (Note 13) Other long-term liabilities Asset retirement obligations (Note 9) Risk management liabilities (Note 13) Future income tax liabilities (Note 10) Liabilities of discontinued operations (Note 18) Total liabilities Commitments and contingencies (Note 16) Shareholders’ equity Petrobank shareholders’ equity Common shares (Note 5) Convertible debentures (Note 7) Contributed surplus (Note 5) Paid-in capital (Note 5) Paid-in capital related to discontinued operations (Note 5) Accumulated other comprehensive loss (Note 5) Retained earnings Total Petrobank shareholders’ equity Non-controlling interest (“NCI”) (Note 11) NCI of discontinued operations (Note 1) Total shareholders’ equity Total liabilities and shareholders’ equity

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 62 Petrobank Energy and Resources Ltd.

2010

17,468 163,311 12,027 2,231 3,455 198,492

2009

71,026 145,849 18,182 782 125,694 361,533

4,685,461 1,518,633 $ 6,402,586

3,723,543 1,060,981 620,511 $ 5,766,568

$ 376,012 838 12,682 608 390,140

$ 370,379 2,694 191,946 565,019

824,845 567,140 1,831 5,170 66,252 2,597 533,350 2,391,325

748,185 348,957 3,961 62,059 3,442 443,181 46,452 2,221,256

1,359,382 37,516 840,772 217,017 2,454,687 1,556,574 4,011,261 $ 6,402,586

880,183 76,811 33,436 747,029 128,895 (29,894) 455,344 2,291,804 1,069,805 183,703 3,545,312 $ 5,766,568

Financial Statements

Consolidated Statements Of Operations And Retained Earnings (Thousands of Canadian dollars, except per share amounts) Years ended December 31, Revenues Oil and natural gas Royalties Loss on risk management contracts (Note 13) Interest income

2010

2009

$ 1,008,556 $ 575,588 (142,064) (82,151) (8,426) (17,969) 101 224 858,167 475,692

Expenses Production Transportation General and administrative Acquisition (Note 4) Stock-based compensation Interest (Note 8) Foreign exchange gain Depletion, depreciation and accretion

Income from continuing operations before taxes and NCI Future income tax expense (recovery) (Note 10) Net income from continuing operations Less: Net income attributable to NCI (Note 11) Net income from continuing operations attributable to Petrobank shareholders Net income from discontinued operations (net of tax of $99.1 million for 2010, $14.2 million for 2009) (Note 18) Cumulative loss on translation of Petrominerales’ financial statements (Note 5) Net income attributable to Petrobank shareholders

124,481 15,270 41,865 1,286 32,393 77,511 (28,310) 526,059 790,555

70,913 8,820 19,353 19,155 24,924 32,013 (56,648) 304,125 422,655

67,612 28,117 39,495 18,187 21,308 164,553 (70,076) 115,785

53,037 (27,541) 80,578 12,019 68,559 76,520 145,079

Retained earnings, beginning of year Conversion of convertible debentures, net of tax (Note 7) Spin-off of Petrominerales (Note 1) Retained earnings, end of year

455,344 334,410 (59,011) (24,145) (295,101) $ 217,017 $ 455,344

Earnings per share (Note 5) Basic earnings from continuing operations Basic earnings from discontinued operations Basic earnings per share

$ $ $

0.20 0.91 1.11

$ $ $

0.77 0.87 1.64

Diluted earnings per share from continuing operations Diluted earnings per share from discontinued operations Diluted earnings per share

$ $ $

0.20 0.83 1.03

$ $ $

0.73 0.79 1.52

See accompanying notes to these consolidated financial statements.

Consolidated Statements Of Comprehensive Income (Thousands of Canadian dollars) Years ended December 31, Net income attributable to Petrobank shareholders Other comprehensive income: Unrealized loss on translation of Petrominerales’ financial statements (Note 5) Comprehensive income attributable to Petrobank shareholders

2010 $ 115,785

2009 $ 145,079

$ 115,785

(72,742) 72,337

See accompanying notes to these consolidated financial statements. 2010 Annual Report 63

Financial Statements

Consolidated Statements Of Cash Flow (Thousands of Canadian dollars) Years ended December 31, Operating Activities Net income attributable to Petrobank shareholders Net income from discontinued operations Cumulative loss on translation of Petrominerales Depletion, depreciation and accretion Unrealized loss on risk management contracts (Note 13) Unrealized foreign exchange gain Stock-based compensation Accretion on convertible debentures Net income attributable to NCI Future income tax expense (recovery) Realized foreign exchange loss related to financing (Note 7) Amortization of deferred financing costs and other assets Acquisition related expenses (Note 4) Asset retirement obligations settled (Note 9) Changes in non-cash working capital (Note 15) Net cash provided by operating activities from continuing operations Net cash provided by operating activities from discontinued operations Financing Activities Issuance (repayment) of bank debt Early conversion of convertible debentures – including costs (Note 7) Issuance (repurchase) of convertible debentures – net of costs Financing costs relating to bank debt Dividends paid by PetroBakken Issuance (repurchase) of common shares Realized loss on foreign exchange contract (Note 7) Amortization of obligations under gas sale contract Changes in non-cash working capital (Note 15) Net cash provided by financing activities from continuing operations Net cash provided by financing activities from discontinued operations Investing Activities Expenditures on capital assets Acquisitions (Note 4) Proceeds from dispositions (Note 4) Dividends received by Petrobank Spin-off of Petrominerales (Note 18) Sale of interest in Petrominerales Changes in non-cash working capital (Note 15) Net cash provided by investing activities from continuing operations Net cash provided by investing activities from discontinued operations Effect of exchange rate changes on cash and cash equivalents Net change in cash and cash equivalents Cash and cash equivalents, beginning of year Cash and cash equivalents, end of year Cash and cash equivalents consist of: Continuing operations Cash Cash equivalents Discontinued operations Cash Cash equivalents

See accompanying notes to these consolidated financial statements.

64 Petrobank Energy and Resources Ltd.

2010

2009

$ 115,785 $ 145,079 (164,553) (76,520) 70,076 526,059 304,125 8,204 41,941 (43,057) (61,063) 32,393 24,924 27,036 5,873 18,187 12,019 28,117 (27,541) 18,184 4,851 4,565 8,585 (4,528) (1,971) 636,754 380,016 (80,775) 23,909 555,979 403,925 602,115 311,889 1,158,094 715,814 (16,845) (29,317) 769,651 (2,250) (177,205) (22,890) (18,184) (827) (628) 501,505 552,117 1,053,622

88,518 (36,244) 452,837 (11,638) (41,246) 14,324 (827) 16,143 481,867 (20,019) 461,848

(933,363) (482,749) 133,632 129,878 (719,369) 41,563 (1,830,408) (471,874) (2,302,282) (27,481) (118,047)

(470,042) (607,042) 178,849 26,352 106,107 (50,522) (816,298) (328,723) (1,145,021) 693 33,334

135,515 17,468

102,181 $ 135,515

$ $

7,438 10,030

$ $

33,231 37,795

$ $

5,378 59,111

Notes

Notes To The Consolidated Financial Statements As 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 Presentation Petrobank 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% owned by Petrobank as at December 31, 2010, is focused on 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% of the results of PetroBakken; the 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 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 Policies Consolidation These 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 Uncertainty The 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.

2010 Annual Report 65

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 Assets All 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 nonproductive 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 in a change in the rate of depletion of more than 20%. 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 Combinations The 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.

Goodwill Goodwill 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.

66 Petrobank Energy and Resources Ltd.

Notes

Asset Retirement Obligations The 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 Interest On October 1, 2009, PetroBakken, acquired TriStar Oil and Gas Ltd. (“TriStar”) and created a new publicly listed company, PetroBakken Energy Ltd., which is a Bakken and Cardium-focused, light oil exploration and production company. Throughout 2010, Petrobank’s ownership ranged from 58% to 64% of PetroBakken, the remaining percentage of which is reflected on the consolidated balance sheet within NCI. PetroBakken’s earnings or losses are 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 Instruments All 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.

Derivatives The 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 Operations A 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 Recognition Revenues from the sale of crude oil, natural gas and natural gas liquids are recognized when title passes to the customer.

Foreign Currency Translation The 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. 2010 Annual Report 67

Notes

Comprehensive Income Comprehensive 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 Share The 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 inthe-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 Compensation The 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 ShareBased 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 Taxes The 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 Contracts The 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 Debentures The 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.

68 Petrobank Energy and Resources Ltd.

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 Assistance The 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 Credits Investment 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 Shares The 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 Equivalents Cash and cash equivalents include investments and deposits with a maturity of three months or less when purchased.

Inventory Petrominerales’ 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 Oil and natural gas assets PetroBakken HBU Other assets

December 31, 2009 Oil and natural gas assets PetroBakken HBU Other assets

Cost

Accumulated Depletion and Depreciation

Net Book Value

$ 5,247,880 570,174 25,066 $ 5,843,120

$ 1,145,620 12,039 $ 1,157,659

$ 4,102,260 570,174 13,027 $ 4,685,461

Cost

Accumulated Depletion and Depreciation

Net Book Value

$ 3,898,602 444,649 16,911 $ 4,360,162

$ 628,355 8,264 $ 636,619

$ 3,270,247 444,649 8,647 $ 3,723,543

2010 Annual Report 69

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). At December 31, 2010, oil and natural gas assets of $1,163.3 million (2009 – $751.8 million) relating to PetroBakken’s unproved properties in Canada, and $570.2 million (2009 – $444.6 million) relating to the Heavy Oil Business Unit unproved properties, have been excluded from the depletion calculation. 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 2011 2012 2013 2014 2015 Thereafter % change

WTI Crude Oil (1) (US$/bbl) 88.40 89.14 88.77 88.88 90.22 1.5%

AECO Natural Gas (1) ($/Mcf) 4.04 4.66 4.99 6.58 6.69 1.5%

US$/C$ 0.93 0.93 0.93 0.93 0.93 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 Dispositions PetroBakken Corporate Acquisitions Result Energy Inc. On April 1, 2010, PetroBakken acquired all of the issued and outstanding shares of Result Energy Inc. (“Result”) for $441.8 million, net of cash and 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 Capital assets Working capital Asset retirement obligations Fair value of financial instruments Goodwill Future income tax liability Total net assets acquired

Amount $ 261,334 2,672 (1,784) 440 204,758 (22,902) $ 444,518

Consideration paid Cash (net of cash acquired) PetroBakken common shares issued (11,232,904) Total purchase price

Amount $ 141,230 $ 303,288 $ 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.

70 Petrobank Energy and Resources Ltd.

Notes

Rondo Petroleum Inc. On March 12, 2010, PetroBakken acquired all of the issued and outstanding shares of Rondo Petroleum Inc. (“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: Net assets acquired Capital assets Working capital deficiency Bank debt (net of cash acquired) Asset retirement obligations Goodwill Future income tax liability Total net assets acquired

Amount $ 205,677 (22,214) (16,033) (1,967) 107,195 (33,690) $ 238,968

Consideration paid Cash PetroBakken common shares issued (5,524,471) Total purchase price

Amount 88,702 150,266 $ 238,968 $

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: Net assets acquired Capital assets Working capital deficiency Bank debt (net of cash acquired) Asset retirement obligations Fair value of financial instruments Goodwill Future income tax liability Total net assets acquired

Amount $ 216,946 (16,660) (74,873) (3,351) 852 145,699 (15,796) $ 252,817

Consideration paid Cash Total purchase price

Amount $ 252,817 $ 252,817

2010 Annual Report 71

Notes

The impact of the above three acquisitions on goodwill for the year ended December 31, 2010 is:

Goodwill Balance at December 31, 2009 Additional amounts recognized from business combinations occurring during the period (see above) Balance at December 31, 2010

HBU and Corporate $ 28,119 -

PBN $ 1,032,862 457,652

Total $ 1,060,981 457,652

$ 1,490,514

$ 1,518,633

28,119

TriStar Oil & Gas Ltd. On October 1, 2009, PetroBakken acquired all of the issued and outstanding shares of TriStar for a total cost of $2.8 billion, including TriStar bank debt and 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: Net assets acquired Capital assets Working capital deficiency Bank debt (net of cash acquired) Asset retirement obligations Fair value of financial instruments Goodwill Future income tax liability Total net assets acquired

Amount $ 2,165,577 (83,625) (351,551) (47,277) 2,901 997,810 (294,447) $ 2,389,388

Consideration paid Cash PetroBakken common shares issued (61,762,500) Total purchase price

Amount $ 584,455 1,804,933 $ 2,389,388

Asset Divestitures During the year ended December 31, 2010, PetroBakken closed divestitures representing approximately 3,800 barrels of oil equivalent (“boepd”) of production (50% natural 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. In 2009, PetroBakken disposed of 2,000 boepd (70% natural gas) in Alberta for net proceeds of $178.8 million.

Acquisition Costs During 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 and the remaining $8.6 million settled with PetroBakken shares.

72 Petrobank Energy and Resources Ltd.

Notes

Note 5 – Share Capital The 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.

Authorized Unlimited number of common shares. Unlimited number of preferred shares, issuable in series. Common Shares Common Share Continuity Balance at December 31, 2008 Issued upon conversion of debentures (Note 7) Costs associated with conversion of debentures Tax effect of share issue costs Exercise of stock options Transfer from contributed surplus related to stock options exercised Tax benefit renounced to shareholders Balance at December 31, 2009 Issued upon conversion of debentures (Note 7) Costs associated with conversion of debentures Tax effect of share issue costs Exercise of stock options and deferred common shares Cancelled shares from prior plan of arrangement Transfer from contributed surplus related to stock options and deferred common shares exercised Balance at December 31, 2010

Number 83,525,394 8,595,925 1,495,639 93,616,958 11,551,554

Amount 574,060 291,246 (2,863) 792 14,324 5,092 (2,468) $ 880,183 467,739

(11,647)

1,131,614 (63,793)

3,067 14,615 -

5,425

106,236,333

$ 1,359,382

Contributed Surplus Changes in Contributed Surplus Balance at December 31, 2008 Stock-based compensation Transfer from contributed surplus related to stock options and deferred common shares exercised Balance at December 31, 2009 Stock-based compensation Transfer from contributed surplus related to stock options and deferred common shares exercised Balance at December 31, 2010

Amount 19,795 18,733 (5,092) $ 33,436 9,505 (5,425) $ 37,516 $

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 Balance at December 31, 2008 Changes in ownership interest in PetroBakken Changes in ownership interest in Petrominerales Balance at December 31, 2009 Change in ownership interest in PetroBakken Spin-off of Petrominerales Balance at December 31, 2010

Amount 747,029 128,895 $ 875,924 $

93,743 (128,895) $ 840,772

2010 Annual Report 73

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) Balance at December 31, 2008 Unrealized loss on translation of Petrominerales’ financial statements Balance at December 31, 2009 Unrealized loss on translation of Petrominerales’ financial statements Spin-off of Petrominerales Balance at December 31, 2010

Amount 42,848 (72,742) $ (29,894) (40,182) 70,076 $ $

Stock Options The Company has established a stock option plan whereby the Company may grant stock options to its directors, officers, employees and consultants. The plan allows for the issuance of up to 5% of the outstanding common shares of the Company. The exercise price of each option is no less than the five 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

Opening Granted Exercised Forfeited Cancelled Closing

Weighted Average Stock Exercise Price Options 4,091,079 $ 10.71 927,194 24.02 (1,116,814) 0.60 (701,942) 13.73 3,199,517 $ 17.44

2009 Weighted Average Stock Exercise Price Options 6,596,076 $ 6.40 1,010,499 22.01 (1,495,639) 0.69 (1,989,857) 9.41 (30,000) 28.52 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.

74 Petrobank Energy and Resources Ltd.

Notes

The following summarizes information about stock options outstanding as at December 31, 2010:

Range of Exercise Prices 0.05 2.53 – 3.61 4.93 – 9.41 12.67 – 15.96 17.23 – 23.73 28.48 – 30.03 33.68 – 38.47

Number 307,950 605,001 182,000 222,000 820,441 807,500 254,625 3,199,517

Stock Options Outstanding WeightedWeighted-Average Average Remaining Exercise Price Contractual Life (Years) 4.9 $ 0.05 4.9 2.55 4.0 6.47 7.0 14.89 5.4 20.86 6.3 29.19 5.0 35.63 5.5 $ 17.44

Stock Options Exercisable WeightedAverage Exercise Price Number 280,950 $ 0.05 209,974 2.57 118,500 6.98 153,000 15.90 40,875 17.60 150,250 28.77 953,549 $ 9.29

Deferred Common Share Compensation Plan The 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:

Opening Granted Issued upon spin-off of Petrominerales Exercised Closing

2010 204,310 21,819 177,512 (14,800) 388,841

2009 146,810 57,500 204,310

Directors Deferred Common Shares In 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 Balance at December 31, 2009 Granted Issued upon spin-off of Petrominerales Forfeited Balance at December 31, 2010

Number 100,844 113,673 (4,893) 209,624

2010 Annual Report 75

Notes

Stock-Based Compensation The 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, All Share-Based Rights Risk free interest rate Dividend rate Expected volatility Stock options Expected life (years) Fair value Deferred common shares Expected life (years) Fair value Directors deferred common shares Expected life (years) Fair value Incentive shares Expected life – incentive shares (years) Fair value of incentive shares granted

2010

2009

2.25% 0% 33%

1.75% – 2.25% 0% 25% – 47.5%

2–4 12.47

2–4 10.60

8 53.89

8 24.15

8 40.03

2.75 – 3.75 $ 40.44

Stock based compensation also includes expenses related to PetroBakken’s stock options, incentive shares and deferred common shares.

Earnings Per Share The 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. Years ended December 31, Net income from continuing operations attributable to Petrobank shareholders adjustments Basic earnings Interest expense on Petrobank’s convertible debentures, net of tax Impact of PetroBakken dilution on net income Diluted earnings from continuing operations Net income from discontinued operations Cumulative loss on translation of Petrominerales’ financial statements Impact of Petrominerales dilution on net income Diluted earnings Weighted average common share adjustments Basic Effect of convertible debentures Effect of Share-Based Rights Diluted

2010

2009

21,308 $ 68,559 2,303 (82) (45) $ 21,226 $ 70,817 164,553 76,520 (70,076) (7,144) (386) $ 108,559 $ 146,951

104,403,209 963,939 105,367,148

88,494,213 6,929,579 940,137 96,363,929

Note 6 – Bank Debt HBU and Corporate Petrobank’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.

76 Petrobank Energy and Resources Ltd.

Notes

PetroBakken PetroBakken 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.

Bank debt outstanding Deferred financing costs Bank debt

HBU and Petrobank Corporate (1) PetroBakken Consolidated $ - $ 829,788 $ 829,788 $ - $ (4,943) $ (4,943) $ - $ 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 Debentures HBU and Corporate 3.0% Convertible Debentures In May 2007, Petrobank issued US$250 million of debentures convertible into common shares of Petrobank at a conversion price of US$28.49 per debenture. The debentures had an annual coupon of 3.0% and were to mature in May 2012. In June 2009, convertible debentures with a face value of US$244.9 million were converted into common shares and $289.2 million (net of costs) 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. In May 2010, Petrobank forced conversion of the remaining 3.0% debentures, upon which 179,009 common shares were issued and $6.0 million was 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 Petrobank at a conversion price of US$38.08 per debenture and had an annual coupon rate of 5.125%. Interest on the debentures is payable semi-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$400 million issuance resulted in $377.9 million being classified as a liability and $75.5 million being classified as equity. In 2010 the debentures were converted into a total of 11,372,545 common shares and $450.1 million (net of costs) was credited to share capital. Petrobank paid $29.3 million to debenture holders and issued 868,988 more shares than per the original debenture agreement in order to early convert their holdings 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.

PetroBakken On January 25, 2010, PetroBakken issued US$750 million of convertible debentures maturing in February 2016. The debentures are convertible into common shares of PetroBakken and have an annual coupon rate of 3.125% and an initial conversion price of US$39.61 per debenture. The conversion price is subject to change in certain circumstances including dividends paid by PetroBakken. Due to dividends paid to PetroBakken shareholders from February 2010 to February 2011, the conversion price has been adjusted to US$37.74 per debenture. Upon conversion based on the current conversion price, a total of 19,827,814 common shares may be issued, however PetroBakken has the option to repay the debentures in cash. 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$750 million issuance resulted in $577 million being classified as a liability and $194 million being classified as equity. The liability portion will accrete 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.

2010 Annual Report 77

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 million realized foreign exchange loss in the first quarter of 2010. The following table summarizes the liability component of the debentures at December 31, 2010:

Balance of liability component, December 31, 2008 Accretion Conversion into common shares(1) Liability component of debenture issuance(2) Changes in exchange rate Balance of liability component, December 31, 2009 Liability component of debenture issuance Accretion Conversion into common shares(1) Change in exchange rate Balance of liability component, December 31, 2010

HBU PetroBakken Total $ 248,909 $ - $ 248,909 11,658 11,658 (228,464) (228,464) 377,918 377,918 (61,064) (61,064) $ 348,957 $ - $ 348,957 577,153 577,153 1,503 25,533 27,036 (342,940) (342,940) (7,520) (35,546) (43,066) $ - $ 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 Expense Interest expense includes the following: Years ended December 31, Cash interest Accretion on convertible debentures Amortization of deferred financing costs Capitalized interest related to Conklin project(1) Interest expense

2010 48,606 $ 27,036 4,851 (2,982) 77,511 $

2009 28,901 11,658 4,565 (13,111) 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 Obligations The 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:

Asset retirement obligations, beginning of year Obligations incurred Obligations acquired Obligations disposed Obligations settled Accretion expense Changes in estimated future cash flows Asset retirement obligations, end of year

2010 62,059 $ 3,770 9,515 (9,935) (4,528) 5,018 353 66,252 $

2009 15,471 2,404 47,277 (3,349) (1,971) 2,227 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 total undiscounted amount of estimated cash flows required to settle the obligations at December 31, 2010 is $13.7 million (2009 – $11.7 million) for the obligations in our HBU, and $204.8 million (2009 – $188.7 million) for the obligations in PetroBakken.

78 Petrobank Energy and Resources Ltd.

Notes

Note 10 – Income Taxes The 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: Years ended December 31, Income from continuing operations before taxes and NCI Canadian statutory income tax rate Expected tax expense Increase (decrease) in income tax provision resulting from: Stock-based compensation Non-deductible accretion on convertible debentures Non-deductible transaction costs and other expenses Non-taxable foreign exchange gain(1) Permanent difference associated with dispositions Change in estimates and other Provision for taxes Consisting of: Current taxes Future income taxes

2010 67,612 28.51% 19,276

9,357 7,423 7,227 1,703 534 5,815 (6,246) (8,854) (42,903) (2,031) (6,106) 28,117 $ (27,541)

$ $

28,117

$ $

2009 53,037 29.00% 15,381

(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,

Capital assets Income taxable in subsequent periods Convertible debentures(1) Investment tax credits Non-capital losses Share issue costs Asset retirement obligations Risk management contracts(2) Obligations under gas sale contract Other

2010 Future Income Future Income Tax Assets Tax Liabilities $ - $ 517,116 166,325 8,849 103,698 23,926 17,218 3,555 1,360 542 $ 159,148

6,210 $ 689,651

2009 Future Income Future Income Tax Assets Tax Liabilities $ - $ 391,772 135,059

8,849 40,933 18,901 16,113 1,782 1,069 1,309 88,956

4,524 $ 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-capital losses in Canada totalling $395.9 million (2009 – $157.6 million), which expire between 2011 and 2030. PetroBakken expects to use a portion of these losses to shelter partnership income that is taxable in 2011.

2010 Annual Report 79

Notes

Note 11 – Non-Controlling Interest (NCI) The components of the Company’s NCI in PetroBakken, Petrobank’s 59% owned subsidiary as at December 31, 2010 (2009 – 64%), is as follows: PetroBakken (1) $ 1,066,489 12,019 6,191 (41,246) 26,352 $ 1,069,805 18,187 22,888 194,113 (36,424) 359,802 (177,205) 105,408 $ 1,556,574

Balance at December 31, 2008 Acquisition of TriStar Attributable income Stock-based compensation Dividends paid or declared by PetroBakken Dividends received or receivable by Petrobank Balance at December 31, 2009 Attributable income Stock-based compensation Issuance of convertible debentures Common shares repurchased Changes in ownership interest(2) Dividends paid or declared by PetroBakken Dividends received or receivable by Petrobank Balance at December 31, 2010

(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 Management The 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:

Working capital surplus (deficit) Bank debt – principal Convertible debentures – principal amount (US$) Common share capital(1) Credit facility Available credit capacity

HBU and Corporate $ 1,942 $ $ -

Petrobank PetroBakken Consolidated $ (193,590) $ (191,648) $ 829,788 $ 829,788 $ 750,000 $ 750,000

$ 1,359,382 $ 200,000 (2) $ 200,000 (2)

$ 3,147,238 $ 1,200,000 $ 370,212

$ 1,359,382

HBU and Corporate 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 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. The spin-off of Petrobank’s ownership in Petrominerales (Notes 1 and 18) and the early conversion of the majority of Petrobank’s 3% and 5.25% convertible debentures (Note 7), have resulted in significant changes to Petrobank’s capital structure during 2010.

80 Petrobank Energy and Resources Ltd.

Notes

PetroBakken PetroBakken 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 outstanding convertible debenture in Canadian dollars) to EBITDA to 4:1, and limit secured debt to 50% of total liabilities plus total equity. 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 convertible debenture agreement stipulates that the ratio of secured debt to total assets is not to exceed 35%. PetroBakken had positive cash flow from operations for the year ended December 31, 2010 and a credit facility with $370.2 million of available capacity as at December 31, 2010.

Note 13 – Financial Instruments and Financial Risk Management The 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 Risk A 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: Dec. 31, 2010

Dec. 31, 2009

Oil and natural gas customers

$ 144,952

$ 138,007

Other Total

18,359 $ 163,311

7,842 $ 145,849

As at

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 million allowance for doubtful accounts as at December 31, 2010 (2009 – $1.8 million).

2010 Annual Report 81

Notes

The Company’s accounts receivables are aged as follows: 2010 $ 155,452 7,859 $ 163,311

As at December 31, Not past due Past due Total

2009 $ 139,814 6,035 $ 145,849

Liquidity Risk The 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 Accounts payable and accrued liabilities Capital lease obligations(1) PetroBakken bank debt – principal PetroBakken convertible debentures – principal (US$) Total(2)

< 1 Year $ 376,012 839 $ 376,851

1-3 Years 1,234 829,788

$ 831,022

3-5 Years $ 1,135 $ 1,135

Thereafter $ 750,000 $ 745,950

Total $ 376,012 3,208 829,788 750,000 $ 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 Risk Market 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 of financial derivatives. The Company’s policy is to only enter into commodity contracts considered appropriate to a maximum of 50% of forecasted production volumes.

82 Petrobank Energy and Resources Ltd.

Notes

PetroBakken had the following crude oil price risk management contracts outstanding at December 31, 2010: Crude Oil Price Risk Management Contracts – WTI(1) Term Jan. 1, 2011 – Dec. 31, 2011 Jan. 1, 2011 – Dec. 31, 2011 Jan. 1, 2011 – Jun. 30, 2011 Jan. 1, 2011 – Jun. 30, 2012 Jul. 1, 2011 – Dec. 31, 2012 Jan. 1, 2012 – Jun. 30, 2013

Volume (bopd) 2,500 4,500 1,000 2,000 1,000 500

Average Price ($/bbl) $78.00 floor/$95.40 ceiling $76.11 floor/$101.43 ceiling $75.00 floor/$104.53 ceiling $75.00 floor/$99.59 ceiling $75.00 floor/$98.25 ceiling $75.00 floor/$109.00 ceiling

Benchmark C$ WTI US$ WTI US$ WTI US$ WTI US$ WTI 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: Term Jan. 1, 2012 – Jun. 30, 2013 Jul. 1, 2012 – Jun. 30, 2013

Volume (bopd) 2,500 1,000

Average Price ($/bbl) $75.00 floor/$121.93 ceiling $75.00 floor/$117.45 ceiling

Benchmark US$ WTI 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 Jan. 1, 2011 – Mar. 31, 2011 Jan. 1, 2011 – Dec. 31, 2011

Volume (GJ/d) 2,000 2,000

Price ($/GJ) $6.00 $6.02

Type Fixed Price Swap Fixed Price Swap

The fair value of the commodity risk management contract liability as at December 31, 2010 is $12.8 million (December 31, 2009 – $6.0 million). If forecast crude oil prices had been 10% lower on December 31, 2010, with all other variables held constant, the change in the fair value of the risk 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). If forecast natural gas prices had been 10% lower on December 31, 2010, with all other variables held constant, the change in the 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 Jan. 2011 – Feb. 2011 Jan. 2011 – Apr. 2011 Jan. 2011 – Jan. 2012 Jan. 2011 – Jan. 2012 Jan. 2011 – Feb. 2012 Jan. 2011 – Feb. 2012 Jan. 2011 – Apr. 2012 Jan. 2011 – Jun. 2012

Notional Principal/Month C$40 million C$50 million C$50 million C$50 million C$25 million C$25 million C$50 million C$25 million

Fixed Annual Rate (%) 2.390% 1.050% 1.620% 1.653% 1.540% 1.510% 1.300% 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 rates had been 1% higher at December 31, 2010, net income attributable to Petrobank shareholders would have increased by $1.6 million (2009 – $3.2 million) due to the change in fair value of the interest rate swaps.

2010 Annual Report 83

Notes

Fair Value of Financial Derivative Contracts The following table summarizes the change in the fair value of PetroBakken’s derivative contracts:

Risk management asset (liability), as at December 31, 2009 Unrealized gain (loss) Contracts acquired Risk management asset (liability), as at December 31, 2010

Crude Oil Natural Gas Interest Total (6,488) $ 470 $ (118) $ (6,136) (8,347) (428) 571 (8,204) 1,980 (688) 1,292 $ (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 Current Risk management asset Risk management liability Non-current Risk management asset Risk management liability Net risk management asset (liability)

- $ (12,318)

2,022 -

(2,517) $ (14,835) $

2,022

Crude Oil Current Risk management asset Risk management liability Non-current Risk management asset Risk management liability Net risk management asset (liability)

Natural Gas

Interest $

Natural Gas

- $ (3,046)

470

(3,442) (6,488) $

470

Years ended December 31, Realized gain (loss) on risk management contracts: Crude oil derivative contracts Natural gas derivative contracts Interest rate swap contracts Foreign exchange contracts

42 42 (80) (2,597) (235) $ (13,048) December 31, 2009

- $ (118)

(2,694)

(118) $

(3,442) (6,136)

2010 $

Unrealized gain (loss) on risk management contracts: Crude oil derivative contracts Natural gas derivative contracts Interest rate swap contracts Foreign exchange contracts Loss on risk management contracts

167 $ 2,189 (364) (12,682)

Interest $

December 31, 2010

(2,925) $ 5,117 (2,414) (222)

2009 23,984 (31) (2,313) 2,332 23,972

(8,347) (40,926) (428) 210 571 118 (1,343) (8,204) (41,941) (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 Instruments The 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 longterm 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:

84 Petrobank Energy and Resources Ltd.

Notes

Financial Instrument Assets Held For Trading Cash and cash equivalents(1) Loans and Receivables Accounts receivable Other Liabilities Accounts payable and accrued liabilities Risk management liabilities (net) Capital lease obligations Bank debt Convertible debentures Obligations under gas sale contract

Carrying Value

Fair Value

Gain / (Loss)

Interest Expense

Revenue

17,468

163,311

376,012 13,048 2,669 824,845 567,140 1,516

376,012 13,048 2,669 829,788 729,375 (4) 2,559 (7)

(8,426)(2) - 17,362 (5) -

27,513 (3) 48,051 (6) -

827 (8)

(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. • L evel 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. • L evel 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. • L evel 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data. Assessment of the significance of a particular input to the fair value measurement requires 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 Financing Technology Partnerships Canada (“TPC”), an Industry Canada initiative, will invest $9.0 million towards the development and field demonstration of the Company’s THAI® technology at the Conklin Project. Under the TPC funding commitment, TPC agreed to contribute 20.134% of eligible expenditures for 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 payments beginning May 1, 2010. The second stream is based on 0.6% of Whitesands Insitu Partnership revenues (excluding initial project revenues) 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 earned after January 1, 2008 with initial payments beginning May 1, 2009. If, as of December 31, 2017 the cumulative royalty paid from the three royalty 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. 2010 Annual Report 85

Notes

Note 15 – Changes in Non-Cash Working Capital 2010

Years ended December 31, Change in: Accounts receivable Prepaid expenses Accounts payable and accrued liabilities Other

2009

$ (17,462) $ (98,837) 6,155 (13,893) 5,633 184,267 2,036 1,618 (3,638) 73,155 (36,202) (83,625) $ (39,840) $ (10,470)

Working capital deficiencies acquired (Note 4)

Changes relating to: Attributable to operating activities Attributable to financing activities Attributable to investing activities Other cash flow information: Cash taxes paid Cash interest paid Cash interest received

$ (80,775) $ 23,909 $ (628) $ 16,143 $ 41,563 $ (50,522) $ $ $

48,281 106

$ $ $

28,180 28

Note 16 – Commitments and Contingencies The following is a summary of the estimated costs required to fulfill the Company’s remaining contractual commitments at December 31, 2010: Type of Commitment HBU and Corporate Office operating leases ($) Capital leases ($) PetroBakken Office operating leases ($) Drilling and completion rigs ($) Total Commitments

2011

2012

2013

2014

2015

Thereafter

Total

3,533 838

4,424 578

4,594 581

4,681 486

4,710 97

15,237 -

37,179 2,580

4,834 8,605 $ 17,810

5,345 9,003 $ 19,350

7,037 8,698 $ 20,910

7,063 6,902 $ 19,132

6,681 $ 11,488

25,852 $ 41,089

56,812 33,208 $ 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.

86 Petrobank Energy and Resources Ltd.

Notes

Note 17 â&#x20AC;&#x201C; Segmented Information 2010

Years ended December 31, PetroBakken

Petrominerales

Revenues Oil and natural gas $ 1,008,556 $ Royalties (142,064) Loss on risk management contracts (8,426) Interest income 858,066 Expenses Production 124,481 Transportation 15,270 General and administrative 33,233 Acquisition related 1,286 Stock-based compensation 22,888 Interest 75,611 Foreign exchange loss (gain) (19,541) Depletion, depreciation 525,403 and accretion 778,631 Income (loss) from continuing 79,435 operations before taxes and NCI Future income taxes (recovery) 31,450 Net income (loss) from continuing 47,985 operations Income attributable to NCI 18,187 Net income (loss) from continuing operations attributable to $ 29,798 Petrobank shareholders Net income from discontinued operations (net of tax of $99.1 million for 2010, $14.2 million for 2009) Cumulative loss on translation of Petrominerales Net income (loss) attributable to Petrobank shareholders Identifiable assets Goodwill Capital expenditures Dividends paid or declared (received or receivable)

2009 HBU and Corporate

$ 101 101

Total

PetroBakken

Petrominerales

$ 1,008,556 $ 575,588 $ (142,064) (82,151) (8,426) (17,969) 101 211 858,167 475,679 -

HBU and Corporate

Total

$ 13 13

$ 575,588 (82,151) (17,969) 224 475,692

8,632 9,505 1,900 (8,769)

124,481 15,270 41,865 1,286 32,393 77,511 (28,310)

70,913 8,820 15,253 19,155 18,650 18,699 1,105

4,100 6,274 13,314 (57,753)

70,913 8,820 19,353 19,155 24,924 32,013 (56,648)

656

526,059

303,714

411

304,125

11,924

790,555

456,309

(33,654)

422,655

(11,823)

67,612

19,370

33,667

53,037

(3,333)

28,117

(24,027)

(3,514)

(27,541)

(8,490)

39,495

43,397

37,181

80,578

18,187

12,019

$ (8,490) $ 21,308

$ 31,378

$ -

$ 37,181

$ 68,559

164,553

76,520

(70,076)

$ 29,798

$ 94,477

$ (8,490) $ 115,785

$ 31,378

$ 76,520

$ 37,181

$ 145,079

$ 5,768,795 $ 1,490,514 $ 811,871

$ $ $ -

$ 633,791 $ 28,119 $ 121,492

$ 6,402,586 $ 1,518,633 $ 933,363

$ 4,480,604 $ 1,032,862 $ 394,023

$ 746,205 $ $ -

$ 539,759 $ 28,119 $ 76,019

$ 5,766,568 $ 1,060,981 $ 470,042

$ 177,205

$ -

$ (129,878) $ 47,327

$ 41,246

$ -

$ (26,352) $ 14,894

2010 Annual Report 87

Notes

Note 18 – Discontinued Operations As 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: Years ended December 31, Revenues Oil and natural gas Royalties Interest income Expenses Production Purchased oil Transportation General and administrative Acquisition costs Stock-based compensation Interest Foreign exchange loss Depletion, depreciation and accretion

Income before taxes Current taxes Future income taxes Net income before NCI Income attributable to NCI Net income from discontinued operations

2010

2009

$ 1,078,857 $ 518,086 (116,482) (47,297) 1,020 411 963,395 471,200 112,854 66,096 91,193 25,112 1,214 11,580 25,898 7,758 271,590 613,295

65,738 53,537 13,686 5,167 11,534 9,346 177,780 336,788

350,100 35,574 63,483 251,043 86,490 $ 164,553

134,412 10,234 11,588 112,590 36,070 $ 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, Assets Current assets Cash and cash equivalents Accounts receivable and other current assets Other assets Capital assets Total assets Liabilities Current liabilities Accounts payable and accrued liabilities Convertible debentures

2009

Asset retirement obligations Future income tax Total liabilities

7,063 39,389 $ 238,398

88 Petrobank Energy and Resources Ltd.

65,928 59,766 125,694 27,832 592,679 $ 746,205

$ 111,537 80,409 191,946

Corporate Information Directors

Head Office

Chris J. Bloomer Calgary, Alberta, Canada

Petrobank Energy and Resources Ltd. 1900, 111 – 5th Avenue S.W. Calgary, Alberta, Canada T2P 3Y6

Ian S. Brown(2) (4) Calgary, Alberta, Canada

Tel: 403 750 4400 Fax: 403 266 5794

Louis L. Frank North Woodstock, New Hampshire, U.S.A.

Website: www.petrobank.com E-mail: ir@petrobank.com

M. Neil McCrank(1) (3) (4) Calgary, Alberta, Canada

Computershare Trust Company of Canada 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 Calgary, Alberta, Canada (3)

(1) (2) (3) (4)

Member of the Compensation Committee Member of the Audit Committee Member of the Reserves Committee Member of the Nominating Committee

Officers John 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: ir@petrobank.com or by telephone at 403 750 4400.

Registrar And Transfer Agents

Legal Counsel McCarthy Tétrault LLP Calgary, Alberta, Canada

Bankers The Toronto-Dominion Bank Calgary, Alberta, Canada

Auditors Deloitte & Touche LLP Calgary, Alberta, Canada

Reserve Engineers DeGoyler and MacNaughton Dallas, Texas, U.S.A. McDaniel & Associates Consultants Ltd. Calgary, Alberta, Canada Sproule Associates Limited Calgary, Alberta, Canada

Exchange Listing The Toronto Stock Exchange SYMBOL: PBG

Securities Filings www.sedar.com

Annual General Meeting The 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.

Forward-Looking Statements & Disclosures

Certain information provided in this Annual Report constitutes forwardlooking 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.

Abbreviations 1P 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

Net Present Values (NPV) Estimated values of future net revenue disclosed in this Annual Report do not necessarily represent fair market values.