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PetroBakken Energy Ltd. 2010 Annual Report

PetroBakken Energy Ltd. Fifth Avenue Place, East Tower, 800, 425 â&#x20AC;&#x201C; 1st Street S.W. Calgary, Alberta T2P 3L8 TEL: 403.268.7800 FAX: 403.268.7808

www.petrobakken.com TSX: PBN

PetroBakken Energy Ltd. is an oil and gas exploration and production company combining light oil Bakken and Cardium resource plays with conventional light oil assets, delivering industry leading operating netbacks, strong cash flows and production growth. PetroBakken is applying leading edge technology to a multi-year inventory of Bakken and Cardium light oil development locations, along with a significant inventory of opportunities in the Horn River and Montney gas resource plays in northeast BC. Our strategy is to deliver accretive production and reserves growth, along with an attractive dividend yield. PetroBakken was formed in the fall of 2009 through the spin-out of the Canadian Business Unit (CBU) from Petrobank Energy Resources Ltd. In conjunction with this formation, we acquired TriStar Oil and Gas Ltd., quickly establishing ourselves with significant light oil and natural gas resource plays and a production and reserve base of more than 80% light oil. PetroBakken trades on the Toronto Stock Exchange under the symbol PBN. PetroBakken’s foundation has been built on the culture of continuously experimenting and modifying technology in an effort to increase production and reserves from our assets and improve capital efficiencies. Our understanding and knowledge base has grown through drilling and completing more than 700 horizontal wells with multi-stage fracture completions. This approach has taken us from drilling single leg horizontal wells with 8 stage fracture stimulations in the Bakken play to now drilling bilateral horizontal wells (a vertical well with two horizontal legs) with 15 stage fracture stimulations per leg, resulting in capital efficiencies with significant improvements in production and reserves.

Contents 2 Innovation 4 Expertise 6 Resources 8 Letter to Shareholders 11 Financial Highlights 12 Operations 14 Technology 16 Business Units 24 Community 26 Operations Statistical Review 29 Values 30 Management’s Discussion and Analysis 48 Management’s Report & Auditor’s Report 50 Consolidated Financial Statements 53 Notes to the Consolidated Financial Statements ibc Corporate Information

41,688

boepd 2010 average production

RESERVES

4.1 billion

AVERAGE DAILY PRODUCTION PER MILLION COMMON SHARES

FUNDS FLOW FROM OPERATIONS

mmboe

$ millions

171.4 143.6

boe

Net present value (10% discount, before taxes)

646.3

161.9 416.6

222.8

153.2

394.8

PetroBakken continued to develop and apply innovative technical solutions to our 59.5

operations through 2010. In addition to establishing a new core area in Alberta’s

30.5

Cardium play and continuing to develop our extensive asset base in southeast 08

Saskatchewan, we also fully implemented our new bilateral well design and began

● Proved Developed Producing ● Proved Undeveloped & Non-producing ● Probable

testing enhanced oil recovery methods in the Bakken.

PRODUCTION BY QUARTER PRODUCTION PRODUCTION boed (thousands)

FUNDS FLOWRESERVES FROM RESERVES OPERATIONSmmboe BY QUARTER mmboe

boepd (thousands) boepd (thousands)

NET PRESENT FUNDS VALUE FLOWFLOW FUNDS $ billions FROMFROM OPERATIONS OPERATIONS

$ millions

$ millions $ millions

171.4 171.4

200

41.7 41.7

4.1 646.3 646.3

143.6 143.6 40

3.7

150

26.3 26.3

416.6 416.6 394.8 394.8

100

17.8 17.8

59.5 59.5 50

5.5

10 08 07

1.5

30.5 30.5

0.8

08 ●● Q1

09 ●● Q2

RESERVES VALUE

08 09

09 10

Oil and NGL Natural Gas Gas ●●●Q3 Q4 ●NGL ●●● Oil and ● Natural

●● Q1

0709 07 08

10 08 09

09 10

● Proved Developed ●● Q2 ●● Q3 Developed ●●Producing Q4 Producing ● Proved ● Proved Undeveloped & Non-producing ● Proved Undeveloped & Non-producing ● Probable ● Probable

RESERVES MIX

LAND PO FUNDS FLOWFLOW FROMFROM thousand FUNDS 2010 Annual Report 1 OPERATIONS BY QUARTER OPERATIONS BY QUAR

boed (thousands) boed (thousands) 50

● Proved Developed Producing ● Proved Undeveloped ● Probable

RESERVES mmboe PRODUCTION BY QUARTER PRODUCTION BY QUARTER

mmboe Net present value $000 PROVED + PROBABLE RESERVES PROVED + PROBABLE RESERVES Proved plus probable discounted 10% before tax PER SHARE PER SHARE (boe) (boe)

08 0908 09 1009 10

$ millions $ millions 200

200

Innovation

Learning through our experience and developing for the future.

2 PetroBakken Energy Ltd.

Incremental oil and gas production in Canada increasingly derives from the application of new technologies to resource plays that were previously technically uneconomic. Technology and innovation are therefore a key part of everything that we do. We are constantly revising our practices and operating methods in order to maximize our efficiencies and to get the most oil out of the ground. Drawing upon the deep knowledge and expertise of our employees, we continually strive to improve our operations both in the office and in the field. The continual evolution of our horizontal drilling and multi-stage fracturing techniques â&#x20AC;&#x201C; from early pioneering of horizontal multi-stage fractured wells in the Canadian Bakken, through to the development of our bilateral horizontal wells â&#x20AC;&#x201C; allows us to continually develop newer and better methods of extracting oil. We are now adapting these techniques for use in different reservoirs. Although our methods will continuously evolve, the desire to adapt to our challenges remains the same.

2010 Annual Report 3

Expertise

Growth and development through knowledge and experience.

Our people are the key to our strength. We are fortunate to have a dedicated team of professionals that strive to continuously improve our Company. PetroBakken’s success is a result of our team identifying new exploitable play-types, building an impactful position on those opportunities and applying new technologies that are repeatable in their full cycle development. The expertise and innovation of our team members has led to many advances in the pursuit of oil throughout western Canada. Many of these innovations have now become industry standard practices for the development of light oil, and natural gas, in the Western Canadian Sedimentary Basin (“WCSB”). As we execute and produce results for our shareholders, we depend on the skill and proficiency of all our staff and contractors to sustain and surpass our hard-earned reputation for operational excellence. 4 PetroBakken Energy Ltd.

26.3 416.6 17.8

130

59.5 30.5

5.5

● Oil and NGL ● Natural Gas

● Proved Developed Producing ● Proved Undeveloped & Non-producing ● Probable

Bakken bilaterals drilled

394.8

47.76

PRODUCTION BY QUARTER

PROVED + PROBABLE RESERVES PER SHARE

FUNDS FLOW F OPERATIONS B

boed (thousands)

$ millions

(boe)

200

/boe

Operating netback

40 150

325

Wells drilled in 2010 06

100

FPO Numbers 20

50 10

$ millions

08 ●● Q1

As a drilling engineer on PetroBakken’s Cardium team, I am responsible for the planning and engineering of our Cardium drilling programs. RESERVES MIX RESERVES VALUE

AVERAGE DAILY PRODUCTION OPERATING NETBACKSPER MILLION $/boe COMMON SHARES boe

161.9

153.2

394.8

Net present value $000

mmboe

Proved plus probable discounted 10% before tax PetroBakken is fast paced and aggressive in our operations, which is different than some of 222.8 the organizations that I have worked with in the past. Team members here are very approachable 8.9 and great to work with, and we are encouraged 24.8 REGULATION $1,297 with new to experiment technologies. The BAR company as a whole$2,135 isn’t afraid WIDTH !!! to try new things and test new operational methods.

43.04

47.76

67.99

49.75

$710

●● Q2

Drilling Engineer

646.3

416.6

●● Q1 ●● Q2 ●● Q3 ●● Q4 Jeremy Kwasnecha

● HBU Reserves (boe) ● CBU Reserves (boe) ● LABU Reserves (bbls)

FUNDS FLOW FROM OPERATIONS

08 10

I love the intensity of my job. The oil and gas industry is changing rapidly, and PetroBakken is very often outpacing it, meaning that there is rarely a dull moment in our office. 09

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

136.2

● Light and Medium Oil ● NGL ● Natural Gas

● Operating Netback ● Production Expenses ● Royalties 2010 Annual Report 5

The foundation upon which we build value.

Resources

Having a strong long-term resource base is a necessity when building a strong company. We donâ&#x20AC;&#x2122;t just consider our resources as being our land base, reserves and infrastructure; our resources are also our people and their extensive collective expertise, knowledge and experience base.

6 PetroBakken Energy Ltd.

REGULATION BAR WIDTH !!!

171.4

More than

mmboe Proved plus probable reserves

2,300 drilling locations

Marivi Molina

4.1

Geophysicist

As a geophysicist with PetroBakken, I am responsible for evaluating and interpreting seismic data in order to pick future economic drilling locations; and to review all planned locations to ensure that our drilling programs are as successful as possible. PetroBakken is a different kind of company in that we are very aggressive in our growth, but we also invest the time and resources necessary to get the best results. We work as a team with all the technical disciplines, and are proactive about attaining and using geology, geophysics and engineering in order to develop plays and drilling profitable programs.

ducing

WELLS DRILLED

LAND POSITION

net

thousands of acres

3.7 1,659

3.0

1,650

The knowledgeable and experienced people combined with my job along with the learning that I get to do every day keeps my job very exciting and fulfilling.

Constant and continual innovation in all areas of our operations amplifies our long-term growth potential. Our innovation and expertise have helped us to maximize our production and reserves, and to expand into new 232.6 core areas, such as our emerging Cardium play.

585 400

We continue to assess and evaluate new resource opportunities to further sustain our long-term production growth and development ● Oil

● Gas

drilling inventory. 07

● Dry

● Undeveloped ● Developed

2010 Annual Report 7

Letter to Shareholders

Focused on resource growth

Since PetroBakken was created in the fall of 2009, our activity levels have remained high as we continue to build an exploration and production Company focused on light oil resource plays. During the year, we completed the integration of two large organizations and acquired three smaller companies, creating a brand new business unit along the way. With growth in cash flow and multiple opportunities to repeatedly drill light oil resource plays, we increased field operations and the size of our organization considerably in order to effectively manage our expanding production and asset base. Operationally and financially, PetroBakken saw improvements in 2010 compared to the prior year. The Companyâ&#x20AC;&#x2122;s year-overyear funds flow from operations increased 64 percent to $646.3 million in 2010, or $3.51 per share, from $394.8 million in 2009. We also maintained our financial flexibility through a convertible debenture issue, twice increased our credit capacity during the year and evolved it to a covenant-based facility. Our average production for 2010 increased 58 percent year-over-year to 41,688 boepd. Our proved plus probable reserves of 171 mmboe increased 18 percent over 2009, and replaced our 2010 production by 274 percent. We were able to reduce our finding and development costs (excluding acquisitions and dispositions) by more than twenty percent compared to 2009 to $26/boe, and generated an operating recycle ratio of 1.8 times.

8 PetroBakken Energy Ltd.

“By quickly assimilating nearly 180 net sections of land with Cardium potential, our new Cardium Business Unit provided us with a solid basis for long-term growth.” R. Gregg Smith President and Chief Operating Officer

John D. Wright Chairman and Chief Executive Officer

Designed to be a new, light oil-focused exploration and development

In 2011, we will significantly ramp up activity in our Cardium play,

company based in western Canada, PetroBakken began operations in

spending more in this area than in any other, including the Bakken. We

the fall of 2009 by acquiring TriStar Oil and Gas and combining it with

expect to drill 95 net wells, capitalizing on the efficiencies we gained in

Petrobank’s Canadian Business Unit. This combination brought together

completion techniques in 2010, primarily through slick water fracture

a large land and production base in southeast Saskatchewan’s Bakken play,

stimulations. While we will continue to experiment and innovate with

along with other assorted light oil and natural gas assets in Saskatchewan,

technology, our advancements to date have lowered our overall well costs

Alberta and British Columbia. To add substantial assets and opportunities

by about $0.4 million compared to prior industry practice, while producing

in another major resource play, we made three corporate acquisitions in

equal, and typically better, results.

early 2010. The purchases of Berens Energy, Result Energy and Rondo Petroleum in the first quarter of 2010 gave us an extensive land base with significant upside potential in central Alberta’s new and emerging Cardium resource play.

Remaining Focused on Existing Plays While making this substantial commitment in the Cardium has expanded our growth potential, we are still actively investing in our existing plays in southeastern Saskatchewan. We are the second largest Bakken landholder

The Birth of a New Play

with more than 325 net sections of land containing over 900 remaining

When we began to consider expanding into the Cardium, we identified

drilling locations, and this area is currently the source of the majority of our

numerous geological and operational similarities to the Bakken. We felt

production. During 2010 we drilled 140 net wells, 121 of which were our new

that our Bakken development expertise could be applied effectively to this

bilateral design in the Bakken. The results from this innovative bilateral well

emerging play. By quickly assimilating nearly 180 net sections of land with

design have firmly established the viability of down-spacing on our Bakken

Cardium potential, our new Cardium Business Unit provided us with a

land. Our average Bakken production for 2010 was more than 25,000 boepd.

solid basis for long-term growth. We continued to expand our Cardium land base throughout the year, and by February 2011, this business unit controlled more than 240 net sections of Cardium land leases with more than 650 drilling locations and proved plus probable reserves at the end of 2010 of 43 million barrels of oil equivalent. Our December 2010 average production from our Cardium Business Unit was just over 7,300 boepd and this has increased to more than 9,500 boepd in February 2011. PetroBakken is now the second largest holder of Cardium land rights and we are actively developing the play and refining our methods for exploiting this potential. We had as many as ten drilling rigs active on our Cardium lands during 2010 and this drilling activity took our Cardium Business Unit reserves from effectively zero to 25 percent of our proved plus probable reserves by the end of the year. This play is poised to provide PetroBakken with our second key growth platform; complementing our considerable southeast Saskatchewan land and production base.

We expanded our infrastructure on our Bakken lands through the addition of new facilities, and upgrading existing facilities to handle more volume. Infrastructure, including oil and gas processing facilities, gathering systems and pipeline access is vital to effective operations in the Bakken. By increasing our infrastructure investments in our Bakken play, we are able to maintain lower operating costs and improve the economics of our projects. During 2010, PetroBakken began experimenting with enhanced oil recovery methods in the Bakken. We temporarily shut-in one Bakken well in February 2010 for a two day CO2 injection cycle, which was followed by a two-month soaking period. The positive response to the stimulation was apparent by April 2010, when we saw large boosts in production from the two offsetting wells. This increased production has continued, and as of March 2011, average daily production from these two wells was still exceeding pre-stimulation levels by 50 percent. Our next step for this project will be to commence up to five natural gas EOR Bakken projects in 2011.

2010 Annual Report 9

“2011 is set to be another exciting year for PetroBakken. Southeast Saskatchewan has developed into an excellent, reliable production platform for us, providing strong fund flow from operations, while the Cardium will provide medium term growth and long-term production opportunities.”

We expect natural gas to be at least as effective as CO2 in an EOR scheme, with the added benefit of being readily available and non-corrosive. We look forward to updating our shareholders on our EOR developments later in the year. PetroBakken’s southeast Saskatchewan operations go beyond the Bakken. Our Conventional Business Unit oversees the development of our large inventory of conventional light oil Mississippian assets in the region. Wells in the various pools in this area are typically low-risk, long life producers delivering relatively high netbacks and steady cash flow, especially at higher oil prices. Development in the area is usually less costly when compared to the Bakken, as the wells are not typically fracture stimulated. PetroBakken’s average production from our conventional southeast Saskatchewan play during 2010 was more than 7,200 boepd.

Leveraging our Potential 2011 is set to be another exciting year for PetroBakken. Southeast Saskatchewan has developed into an excellent, reliable production platform for us, providing strong funds flow from operations, while the Cardium will provide medium term growth and long-term production opportunities. We are also continuing to establish positions in new plays that should enhance our ability to continue to deliver long-term growth. PetroBakken is committing more of our capital budget to the Cardium than any other play in our inventory this year, and we plan to greatly increase production from the Cardium. Bakken development will also continue to be strong with new wells drilled along with further development of our natural gas-based enhanced oil recovery projects. We would like to thank all of our shareholders, our Board of Directors and our staff for believing in PetroBakken’s future, and for taking us to where we are today. 2010 provided challenges as well as many opportunities. While we are disappointed with the performance of our share price, we have increased the light oil opportunities available to the Company and our team’s innovation, expertise and commitment have enabled us to pioneer new technologies for developing some of western Canada’s most exciting new resource plays, while building long-term value for our shareholders. We are looking forward to a strong year in 2011 and beyond.

R. Gregg Smith

John D. Wright

President and Chief Operating Officer

Chairman and Chief Executive Officer

March 25, 2011

10 PetroBakken Energy Ltd.

Financial Highlights ($000s, except where noted)

Q4 2010

2010

2009

2008

258,359

1,008,556

575,588

585,800

160,817

646,316

394,819

416,628

0.85

3.51

3.15

3.79

Financial Oil and natural gas revenue Funds flow from operations

(1)

Per share

- basic ($)

- diluted ($)

(2)

Net income

0.80

3.27

3.14

3.79

15,078

47,985

43,397

186,349

Per share

- basic ($)

0.08

0.26

0.35

1.70

- diluted ($)

0.08

0.26

0.34

1.70

262,758

811,871

394,023

545,833

Total assets

5,768,795

4,480,604

1,318,090

Net debt(1)

1,023,378

912,703

416,335

Long-term financial liabilities(4)

1,396,098

753,970

318,332

45,076

177,205

41,246

0.24

0.96

0.24

187,140

171,856

109,800

215,011

177,991

109,800

75.19

72.77

64.27

92.80

Capital expenditures(3)

Dividends Per share ($) Common shares, end of period (000) Basic Diluted

(2)

Operations Operating netback ($/boe except where noted)(5) Oil and NGL revenue ($/bbl)(6) Natural gas revenue ($/mcf)

(6)

Oil, NGL and natural gas revenue(6)

3.96

4.22

4.40

8.06

67.00

65.28

58.97

86.78

Royalties

9.84

9.34

8.55

10.03

Production expenses

8.97

8.18

7.38

8.76

48.19

47.76

43.04

67.99

Oil and NGL (bbls)

34,754

35,109

22,648

15,369

Natural gas (mcf)

39,474

39,473

22,110

14,436

Total (boe)

41,333

Operating netback

(1) (7)

Average daily production(5)

41,688

26,333

17,775

Proved plus Probable Reserves (mmboe, WI)

171.4

143.6

59.5

Undeveloped Land (net acres)

1,204

1,262

464

(1) Non-GAAP measure. See “Non-GAAP Measures” section within the MD&A. (2) Consists of common shares, stock options, deferred common shares, incentive shares and convertible debentures as at the period end date. Assumes 109,800,001 common shares were outstanding in 2008 and first nine months of 2009. (3) Prior to property dispositions. (4) Includes credit facility, liability portion of the convertible debenture, long-term risk management liabilities, and obligations under gas sale contract. (5) Six Mcf of natural gas is equivalent to one barrel of oil equivalent (“boe”). (6) Net of transportation expenses. (7) Excludes hedging activities.

2010 Annual Report 11

Western Canada

Operations Overview

PBN lands Bakken HZ wells Bilateral HZ wells PBN facilities

Bakken development area

PetroBakken is a conventional, light oil focused, exploration and development company Enbridge pipelines with operations located in two of the largest light oil resource plays in western Canada. PBN pipelines Transgas pipeline We combine long-life Bakken reserves in Saskatchewan with significant Cardium production

growth potential in Alberta along with natural gas development opportunities in the Horn River and Montney resource plays in northeast British Columbia. Formed in late 2009 through the combination of Petrobank’s Canadian Business Unit and the acquisition of TriStar Oil and Gas, PetroBakken has emerged as one of the few large development companies operating in the Western Canadian Sedimentary Basin with assets and operations primarily focused on light oil. PetroBakken’s activity is concentrated in three main areas of western Canada through four Business Units. Southeast Saskatchewan contains our Bakken and Conventional Saskatchewan Business Units and has traditionally been our largest and most active base of operations. Through the Bakken light oil resource play and our conventional Mississippian light oil opportunities, these Business Units now generate significant excess cash flow which we use to fund growth investment in our other plays. Our Cardium Business Unit in central Alberta is poised to become PetroBakken’s new premier growth opportunity and will receive the majority of our 2011 drilling budget. Our Cardium light oil resource play is primarily focused around the Pembina oil field near Drayton Valley, Alberta, but also includes the more exploratory Cardium plays around Garrington and Lochend. The Cardium play will generate the majority of PetroBakken’s production growth over the medium term. Our BC/Alberta Business Unit contains our northeast British Columbia natural gas resource plays in the Horn River and Montney. In addition, this Business Unit is also building exposure to other potential oil-focused resource plays throughout Alberta.

12 PetroBakken Energy Ltd.

Dale Gulewicz 2010 Highlights Significant Acquisitions • On February 25, 2010, PetroBakken acquired all 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. • On March 12, 2010, PetroBakken acquired all 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. • 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.

Completions Superintendant I supervise all of our completions operations in our southeast Saskatchewan plays. My position also sees me creating these completions programs, and supervising their execution. PetroBakken is quite different from some of the other companies that I have worked for in that we are 100 percent technology driven from the ground up. We have developed new drilling and completions technologies, which have really opened up our tight oil plays, such as the Bakken in southeast Saskatchewan. As a company, we are constantly pushing forward to develop the next latest and greatest technology that will further expand our operations.

Operational Highlights • Our production averaged 41,688 boepd during 2010, compared with 26,333 boepd during 2009. Fourth quarter production averaged 41,333 boepd, up slightly from the 40,095 boepd in third quarter of 2010. • Nearly 85 percent of our 2010 production is high-netback light oil. • 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.

1.2 million acres of land in western Canada

Our development investments during 2010 were in our Bakken and Cardium light oil resource plays, where the majority of our 239 net wells were drilled during the year. We allocated minimal drilling and maintenance capital to our natural gas resource opportunities because of the current low commodity price for natural gas. This approach has enabled us to maintain our ability to invest in natural gas when the economic environment is more lucrative, while remaining focused on our oil opportunities. With over 84% of our production, reserves, and drilling inventory being light oil, which currently enjoy a much better economic environment than natural gas, investment in these plays allows us to deliver strong operating netbacks and significant cash flow growth for future investment. With more than 2,300 potential locations on our 1.2 million acres of undeveloped land in western Canada, PetroBakken is poised for continued growth from our Cardium play, underpinned by a solid baseline of production from southeast Saskatchewan. Our 2011 capital budget has been set at $800 million, with approximately 75% of the budget directed to the drilling and completion operations, almost exclusively in our Cardium and southeast Saskatchewan light oil plays. Overall, we plan on drilling 207 net wells with 95 net wells in the Cardium play, 75 net wells in the Bakken, and 30 net wells in our Mississippian plays. The balance of drilling will be targeting new oil-focused resource plays as well as minor gas drilling in northeast British Columbia to preserve our extensive acreage position. 2010 Annual Report 13

Technology Continuous evaluation of new technologies is a large part of our drilling and development success at PetroBakken. We have been recognized as a leader in implementing and evolving high-intensity fracture stimulation technologies that have unlocked production and reserves in the Bakken formation. We continue at the forefront of pioneering and modifying new, cost-effective completion techniques in both our conventional and unconventional plays. Recently we have begun to apply our experience with these technologies to unlock further hydrocarbon potential in the Cardium. Fracture stimulation of an oil or gas well involves injecting specially designed fluids and sand under high pressure into the well bore to crack the dense, low-permeability rock, enabling the flow of trapped oil or gas through fractured channels. In the Bakken, we found that earlier well designs often caused a higher influx of water to flow in from surrounding formations, due to fracing out of zone. This resulted in lower oil recovery rates. In an effort to fix this problem, we tested a variety of improvements to initial industry approaches, ultimately landing on a profitable efficient solution. To-date, we have modified the fluids and proppants used, the injection rates and the pressure environment, as well as other aspects of the completion. The end result is that our multi-stage fracture stimulations in horizontal wells are now unlocking these tight oil and gas formations with greater efficiency and yielding promising production results. Our innovation and pioneering use of technology has helped PetroBakken to realize several technological firsts. PetroBakken was one of the first operators to successfully drill a 1,400 metre-long horizontal multi-stage fractured well in the Bakken, and the first to increase the fracture density from 8 to 20 fracs on a single leg well. We were also the first to experiment with bilateral horizontal wells; effectively doubling the number of fractures with costs only 30% higher than a single leg well. To-date, bilateral wells have recovered at least 25% more oil than single lateral wells in the first 365 days of production. PetroBakken has been at the leading edge of horizontal multi-stage fracturing in the Bakken. We are now bringing this approach to the Cardium.

14 PetroBakken Energy Ltd.

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.

The Evolution of Completions: Bakken 3.0 In the early days of multi-stage fracturing, we would apply eight-stage fractures to long (1,400 m) horizontal wells. This approach was taken in an effort to obtain greater reservoir contact. We then intensified this completion method by drilling shorter (800 m) horizontal wells and applying the same number of fractures. This method ensured that drilling two short horizontal wells would provide the same horizontal coverage as a single long horizontal, but would effectively double the fracture density in the reservoir. We called this drilling and completion method Bakken 1.0. As technologies improved we evolved our completions method to Bakken 2.0, in which were able to complete long horizontal wells with 15 to 20 stage fractures. This eliminated the need for the two vertical well bores and two surface locations required for two short wells. From there we have moved to Bakken 3.0, in which we drill bilateral horizontal wells â&#x20AC;&#x201C; two horizontal legs drilled from a single vertical well bore â&#x20AC;&#x201C; and apply 15 fractures per leg. Bakken 3.0 allows us to down-space our Bakken acreage in a more capital efficient manner and is now our standard drilling and completions method for the majority of our Bakken wells going forward.

Slick Water Fracturing In the Cardium play, PetroBakken quickly shifted away from oil-based fracing to the use of slick water fracing, a stimulation process where a specially designed water and sand proppant solution is injected into a horizontal well under high pressure to enable the flow of trapped oil through the fracture channels created. Many in the industry have been using oil-based fracs, a technique that is typically used when there is concern with damaging the reservoir matrix with the completion fluid, which we believed not to be an issue. Our reservoir analysis of the Cardium and the observation that competitors are successfully implementing secondary recovery through water flooding in the vertically drilled portion of the pool convinced us that the oil-based fracing only contributed additional completion costs. We have now concluded that our experimentation with a variety of fracture completions clearly demonstrates that slick water fluid provides better results in most Cardium reservoir applications than fracing with foamed water, gelled water, or oil. Through this methodology we observe higher success rates of frac initiation within each well and overall higher initial production; leading, we anticipate, to higher longer life, ultimate reserves. Moving forward, PetroBakken will continue to utilize and experiment with enhanced slick water fracing techniques on the Cardium wells we drill to maximize the value of each well. Technological evolution of drilling and completion methods will continue to be a very important part of our operations as we continue to grow and expand to new core areas. We will continue to innovate and develop our expertise throughout all of our play areas in order to maximize our production and reserves potential. 2010 Annual Report 15

The Bakken Business Unit

Southeastern Saskatchewan’s Bakken resource play is a significant light oil hydrocarbon accumulation where our economics have steadily improved over the past five years; with experience and execution expertise gained in our horizontal drilling and multi-stage fracture stimulation programs. The Bakken play is very prolific throughout the Williston Basin and is located primarily in Saskatchewan, North Dakota and eastern Montana. In both Canada and the United States, the Bakken formation has relatively low permeability, but in Canada it is a thinner geological section and is located at shallower depths. Independent reserve evaluators typically estimate five million barrels of exploitable petroleum-initially-in-place per section of land in the greater play area, with current proved plus probable reserve recovery assigned at approximately 10% to 12%. With continued solid well performance and enhancement of drilling and recovery technologies, we expect these recovery factors could increase another 5% prior to any potential enhancement from enhanced oil recoveries (“EOR”). PetroBakken is currently the second largest landholder in Saskatchewan’s Bakken play with more than 210,000 net undeveloped acres containing over 900 drilling locations. Our extensive acreage position in the Bakken fairway, combined with low production expenses and a visionary royalty regime in Saskatchewan, provides a platform for continued success in this play. During 2010, PetroBakken drilled 140 net wells, 121 of which were bilateral wells, with a 99 percent success rate. Our average Bakken production for 2010 was over 25,000 boepd.

Bakken Operations Our operational success in the Bakken is driven by our depth of expertise in applying technologies such as horizontal drilling with multi-stage fracture stimulation completions. We are continuously innovating and evolving the efficiency of our horizontal drilling and fracture stimulation methods, used to crack dense tight reservoir rock and allow trapped oil to flow. Greater fracture intensity along the entire length of a horizontal well bore increases both productivity and the expected ultimate reserve recoveries. Our methodology of controlled multiple fracture stimulations maximizes exposure to the reservoir while minimizing the risk of fracturing out of zone and into water-bearing zones above the Bakken formation, as was common in earlier approaches. Our latest drilling and extraction strategy, designed to optimize results in the Bakken formation, is to drill 1,400 metre-long bilateral horizontal wells – two horizontal legs drilled out from one vertical well bore. This dual-leg tactic provides increased exposure to this relatively low permeability reservoir with 15 fracture stimulations per horizontal leg, or 30 fracture stimulations per well. In the subsurface, the exposure to the reservoir is identical to the drilling of two separate horizontal wells with multi-stage fracture stimulations. However, with the capital efficiency of a bilateral well, we can place two horizontal legs in a quarter section of reservoir for approximately $2.6 million versus $4 million with two single wells, significantly improving project economics. We intend to apply this drilling and completion strategy to the majority of our remaining inventory of 900 well locations in the Bakken. 16 PetroBakken Energy Ltd.

Bakken Development Area

PBN lands Bakken HZ wells BRITISH COLUMBIA

ALBERTA

SASKATCHEWAN

Bilateral HZ wells MANITOBA

PBN facilities Bakken development area Enbridge pipelines PBN pipelines Transgas pipeline

ALBERTA

SASKATCHEWAN

BRITISH COLUMBIA

SASKATCHEWAN

Bakken Infrastructure One of the keys to our success in the Bakken play is our investment in infrastructure, including oil and gas processing facilities, gathering systems, and pipeline access, which helps to control operational costs. Building and enhancing our infrastructure allows us to maintain our low-cost advantage while supporting field expansion as we develop the Bakken resource base to its fullest potential. By establishing centralized facilities in the Midale, Viewfield, Creelman,

â&#x20AC;&#x153;Building and enhancing our infrastructure

Handsworth, and Freestone areas we have created a cost-effective infrastructure to capture additional value from the ALBERTA

allows us to

gas and natural gas liquids associated with our Bakken light oil operations. As our network of facilities grew, in 2010

maintain our MANITOBA

we expanded our Midale gas processing facility from 8 mmcfpd to 12.5 mmcfpd to allow us to conserve and market the

low-cost advantage

SASKATCHEWAN

increased volume of gas and natural gas liquids. The growth of our infrastructure, including oil and gas processing facilities, gathering systems and pipelines will be timed to match future drilling plans. This will help us maintain low operating costs and improve our project economics.

while supporting field expansion.â&#x20AC;?

Bakken EOR Pilot Projects PetroBakken plans to spend $20 million in 2011 on pilot EOR projects in the Bakken to increase reserve recovery from existing wells. The concept is simple; we plan to inject a fluid or a gas into the tight reservoir rock to displace a higher quantity of oil out of the reservoir. In practice, this presents a number of challenges. The Bakken siltstone has microscopic porosity and very low permeability. Multi-stage fractures enhance primary recovery but increase the risk that injected fluids can by-pass portions of the reservoir, leaving these areas un-swept. Certain fluids, including water based systems, are difficult to inject at commercial rates without bypassing pay zones. Gasses are easier to inject, but some, like CO2, present problems with miscibility and corrosion. After laboratory analysis and computer simulations, PetroBakken has concluded that natural gas would be more effective in an EOR scheme than fluids such as water, because the formation has a higher relative permeability to gas and therefore should sweep the tight Bakken reservoir more efficiently. In 2010 PetroBakken successfully field tested this concept by first using CO2 as a proxy for natural gas. One well was shut-in in February 2010 for a two day CO2 stimulation followed by a two month soaking period. By April 2010, response to the stimulation was evident in offsetting wells with large boosts in production. By March 2011 production continued to exceed pre-stimulation levels by 50% and cumulatively we have recovered an incremental 11,000 bbl of light oil. PetroBakken will continue monitoring this CO2 test and we will have up to five natural gas EOR projects commencing in 2011. Two pilot injection wells have already been drilled, and the first well recently began natural gas injection, with the second well scheduled to begin injection in the third quarter of 2011. Initial results are expected to be released in the fourth quarter. The majority of the natural gas used for these EOR projects will come from our own production facilities and is expected to be recovered and sold at a later date, which further enhances the full cycle economics of EOR. 2010 Annual Report 17

MANITOB

Conventional The Saskatchewan Conventional Business Unit In addition to PetroBakkenâ&#x20AC;&#x2122;s extensive Bakken play in southeastern Saskatchewan, we also manage a large inventory of conventional light oil Mississippian plays. By focusing our development on the prolific Frobisher, Alida and Tilston formations, we continue to build on our current production base and capture significant upside through our extensive drilling inventory in these conventional Mississippian oil pools. While lacking the same repeatability of resource style plays, wells in these pools are characterized by relatively low-risk, long-life production, high-netbacks and steady cash flows, and consequently offer attractive investment opportunities. These horizontal wells are generally less expensive to drill and complete when compared to Bakken or Cardium wells, because they are drilled into higher quality reservoir rock, and do not require multi-stage fracture stimulations. Typical new wells in these Mississippian/Jurassic-age light oil pools generate initial production rates of 100 boepd and contribute proved plus probable reserves of 80,000 boe.

18 PetroBakken Energy Ltd.

Conventional Mississippian Formations

SE Sask Conv Legend PBN lands BRITISH COLUMBIA

ALBERTA

SASKATCHEWAN

PBN wells MANITOBA Tilston subcrop Alida subcrop Frobisher subcrop Midale subcrop Bakken development area Map shows PBN wells only

ALBERTA

SASKATCHEWAN

BRITISH

COLUMBIA “As we complete our facility upgrades, we can

SASKATCHEWAN

increase our pace of drilling on these plays.”

ALBERTA SASKATCHEWAN

MANITOBA

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.

2010 Annual Report 19

ALBERTA

MANITOBA

SASKATCHEWAN

ALBERTA

SASKATCHEWAN

The Cardium SASKATCHEWAN

MANITOBA

Business Unit

EDMONTON EDM Pembina

Armed with our knowledge and experience in exploiting the tight, light oil resource in the Bakken, we began 2010 intent on expanding our operations to another major light oil resource play. PetroBakken recognized the growth potential, and play-type similarity in central Alberta’s Cardium play.

MANITOBA

SASKATCHEWAN

We targeted the Cardium as our second major growth platform. Based on extensive geological mapping, we identified that the Cardium would produce best through horizontal, multi-stage fractured wells, and we knew that our staff could apply our extensive in-house skill set to fully exploit the Cardium. We consolidated a strong land position in the Cardium through three major acquisitions during the first quarter of 2010.

G arrin Garrington

The first of PetroBakken’s strategic Cardium transactions was the acquisition of Berens Energy, which was announced in early January and closed in February, 2010. This acquisition provided PetroBakken with access to over 70 gross (40 net) sections of land and more than 100 net potential Cardium drilling locations.

L oche Lochend

30 km

CALGARY CA AL

AB Cardium Legend Cardium Light Oil Resource Play

Associated with the land base were more than 11 mmboe of proved plus probable reserves, including PetroBakken’s first Cardium reserves, with significant future growth potential. Our second Cardium transaction was announced late January, 2010 and the acquisition of Result Energy closed April 1st. The Result acquisition was twice the size of the Berens transaction, gaining PetroBakken over 150 gross (105 net) sections of Cardium light oil prospective land. More than 300 net Cardium

PBN Cardium lands

locations had already been identified on these lands; a number which increased as our drilling program

Cities

progressed throughout the year. The acquisition also provided us with more than $120 million in tax pools,

Cardium producing wells

more than 1,300 boepd of net production and a further 3 mmboe of proved plus probable reserves. We then took the opportunity to solidify our Cardium holdings with one more strategic corporate acquisition in March, 2010, when we purchased Rondo Petroleum. This transaction netted us more than 24 gross (23 net) sections of land in the core of the Cardium light oil fairway, including lands directly offsetting acreage acquired in the Berens and Result acquisitions. These lands contain some of the thickest sections of the Cardium reservoir on the west side of the Pembina Cardium field. Through this acquisition we also gained four, 100% owned, pipeline connected facilities, approximately 1,200 boepd of production, more than $55 million of tax pools and an additional 11 mmboe of proved plus probable reserves.

20 PetroBakken Energy Ltd.

Pembina Cardium Light Oil Resource Play

Cardium CU Legend PBN Cardium lands Cardium producing wells

“PetroBakken expects to spend a significant portion of our 2011 capital budget, approximately $345 million, to drill and commence production from approximately 95 net wells in the Cardium.”

Growing our Second Major Resource Play After establishing this significant position in the highly lucrative Cardium play through our acquisitions in early 2010, as well as additional land sales and asset deals, we set out to develop and exploit our Cardium assets through an aggressive drilling program in the latter half of the year. This program consisted of a capital budget of $210 million, with which we drilled 55 net Cardium wells and brought 40 net wells on production. Our experience and comfort with innovation quickly led us to alter previous industry completion techniques and move from oil-based fracture stimulations to water-based stimulations. The result was lower costs and better well results. After completing our three corporate acquisitions, we were well positioned when the Alberta government provided new royalty incentives to encourage horizontal drilling. These changes brought more than $1 million of economic value per drilling location, further enhancing the economics of our Cardium acquisitions and encouraging an active drilling program. From a standing start we have created a Cardium-focused Business Unit that holds more than 240 net sections of Cardium prospective land with over 650 drilling locations, 43 million barrels of oil equivalent of proved plus probable reserves and production of 7,300 boepd by the end of 2010. This year PetroBakken expects to spend a significant portion of our 2011 capital budget, approximately $345 million, to drill and commence production from approximately 95 net wells in the Cardium. We intend to direct significant investments to this area through the foreseeable future, as we build this light oil resource play into a substantial and growing production base for the Company, and demonstrate the value of

Stephanie Hay Senior Landman In my position as a senior landman with PetroBakken I am involved with all mineral land negotiations for West Pembina in our Cardium Business Unit. This can range from assessing asset acquisitions and planning land sale bids in our growing Cardium field and other new emerging plays to interacting with our drilling, exploration, and land teams, and also talking to third parties about potential land deals. PetroBakken’s teams are incredible to work with! We have been able to build a team that has put together a complete new focus area and drilled 75 gross wells during its first 9 months in existence. Every day at PetroBakken I can expect to work on something different. We are constantly growing our opportunity base and looking for the next big play.

the material land position that we built in 2010. 2010 Annual Report 21

The 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. Northeast British Columbia The Horn River and Monias natural gas resource plays in northeastern British Columbia provide PetroBakken with long-term natural gas exposure in our asset portfolio. Resource plays such as these are large, low-porosity/low-permeability reservoirs that require special completions techniques to exploit effectively. Depending on the completions techniques chosen, wells in these plays can be re-fractured multiple times during their lifetimes with consecutive results potentially achieving levels near the initial rate of flow, after each fracture stimulation. Each production increase is typically followed by a steep decline which then levels out to a steady, long-term production base. PetroBakken is not presently focused on developing these plays due to the current economic environment surrounding natural gas production. All of the development on our northeastern B.C. gas plays in 2010 was done to preserve land title, a trend which will continue through 2011 when we plan to drill three title-preserving wells in the area.

22 PetroBakken Energy Ltd.

Horn River Gas Resource Play

Monias Gas Resource Play

BRITISH COLUMBIA

ALBERTA

Horn River Monias Legend Horn River

â&#x20AC;&#x153;With over 340 net drilling locations,

PBN lands Pipelines

the Horn River should prove to be

All-season roads

an excellent source of long-term

Summer roads

production growth for PetroBakken in the right natural gas price environment.â&#x20AC;?

Monias

Monias BRITISH COLUMBIA

PBN facilities Spectra facility PBN gas wells PBN new drills

Our 17 sections of land (100 percent working interest) in the Monias area of northeastern British Columbia offer existing Montney production with significant upside potential. We drilled our first Montney well in February 2009 followed by our second well in September 2009. We drilled our second well as a long (1,600 m) bilateral, allowing us to take advantage of drilling and completion expertise gained in the Bakken. In both laterals we targeted the prolific upper portion of the 135 metre thick, gas saturated Montney. With more than 60 locations

ALBERTA

targeting upper or lower Montney production at Monias, we are well positioned to grow our natural gas portfolio once prices support ongoing development.

Horn River 84 net sections of land in the Horn River area of northeastern British Columbia further positions us for long-term growth in gas production once the North American natural gas market improves. As with our Monias land, all of our Horn River drilling for the foreseeable future will target land preservation. With over 340 net drilling locations, the Horn River should prove to be an excellent source of long-term production growth for PetroBakken in the right natural gas price environment.

Emerging Resource Plays As we continue to expand our business opportunities, we have been building meaningful land exposures to potentially new, oil-focused resource plays, primarily through crown land sales. Consistent with leveraging our expertise in developing plays that require the use of horizontal wells with multi-stage frac completions, we are sourcing opportunities that require the same style of development. While these opportunities are at an early stage, they represent areas of potential material future growth for PetroBakken.

2010 Annual Report 23

Community A commitment that pays dividends.

At PetroBakken, our commitment to the communities that we operate in, to the health and safety of our employees, and to the environment, influences everything we do. We are committed to do our best every day to meet or exceed environmental legislation and regulations. We recognize that oil and gas operations have an impact on the environment and we strive to minimize that impact by adhering to industry leading practices and creating new, innovative ways of doing business that are friendlier to our surroundings. We have a deep respect for the natural environments in which we operate and we strive to ensure all of our operations are carefully managed to reduce our impact on the world around us. A portion of our annual capital program is allocated to the reclamation and abandonment of our wells and facilities as they reach the end of their economic lives. We design our drilling operations and facilities in ways that are able to minimize our environmental footprint, and we encourage a philosophy of environmental respect in all of our operations; from the employment of efficient, low-impact drilling technologies, to the capture of waste gas and natural gas liquids associated with light oil production.

24 PetroBakken Energy Ltd.

TELUS World of Science Sponsorship PetroBakken 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. PetroBakken is looking forward to promoting energy and innovation related science education at the TELUS World of Science in partnership with Petrobank 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.”

All of PetroBakken’s personnel and contract staff are keenly aware of the importance of safe operations. Our training programs allow our people to develop in-depth skills to manage employee and environmental protection. As we continue to grow, all of our employees are encouraged to respect our values and to be good stewards of land, air, water, wildlife and people. PetroBakken constantly strives to be a good and welcome neighbour in all of the areas in which we operate. Our employees are our local ambassadors to the communities in which they live and work. We encourage community engagement with all of our employees and contractors. We also ask them to create awareness of our operations whenever possible. Our deep respect for people, the environment and our communities allows us to create and maintain strong operations for the benefit of all stakeholders.

2010 Annual Report 25

Operations Review

NET PRESENT VALUE

Operations Statistical Review

$ billions

Production Highlights

4.1 3.7

• PetroBakken’s 2010 average production increased 58% to 41,688 boepd from 26,333 boepd in 2009. • In January 2011, average production was estimated at approximately 41,400 boepd. • PetroBakken drilled 325 gross wells (318 oil wells, 4 gas wells and 3 dry & abandoned (“D&A”) wells) and 231.8 net wells (226.1 oil, 2.7 gas and 3.0 D&A) in 2010. The oil wells were in southeast Saskatchewan and Central Alberta, while all of these gas wells were in the Monias and Horn River unconventional gas plays in northeast British Columbia. 1.5

Average Daily Production

0.8 forth the Company’s average daily production volumes by province for the three and 12 months ended December 31, 2010. The following table sets

10 ●● Q4

Lt/Med Oil and NGL (bbl)(1) 2010 Average Q4 2010 07 08 09 10 Saskatchewan 30,983 29,142 ● Proved Developed Producing Alberta 3,700 5,210 ● Proved Undeveloped British Columbia ● Probable 95 90 Manitoba 331 312 Total PetroBakken 35,109 34,754

Gas (Mcf) 2010 Average 9,232 26,531 3,710 39,473

Q4 2010 8,632 27,205 3,638 39,475

Total (BOE) 2010 Average 32,522 8,122 713 331 41,688

Q4 2010 30,581 9,744 696 312 41,333

(1) NGLs and heavy oil have been included with light/medium oil, as they are not considered to be material.

RESERVES

WELLS DRILLED

LAND POSITION

mmboe

net

thousands of acres

3.7

Drilling 2010

20091,659

Oil (net)

232.6

113.3

186.9

Gas (net) Service 68.3(net) Successful (net) Dry (net) Total (net) Success rate 36.8

3.7 236.3 3.0 239.3 99%

2.5 115.8 1.5 117.3 585 99%

2.0 2.9 191.8 2.0 193.8 99%

66.2

3.0

1,650 2008

232.6

400

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

● Oil

As at December 31, 2010 (000s of acres) Gross

Saskatchewan Alberta British Columbia Manitoba Northwest Territories United States - Montana Total PetroBakken

26 PetroBakken Energy Ltd.

08 Developed

● Undeveloped ● Developed

Net

Gross

Undeveloped

● Gas

● Dry

Total

Net

Gross

Net

Avg. working interest (%)

275.4

172.3

742.2

612.1

1,017.6

784.4

365.5

229.3

557.8

404.4

923.3

633.7

68.8

41.6

110.9

85.9

179.7

127.5

4.5

2.4

52.1

48.0

56.6

50.4

6.4

2.2

6.4

2.2

103.6

51.8

103.6

51.8

714.2

445.6

1,573.0

1,204.4

2,287.2

1,650.0

161.9 161.9 161.9 153.2 153.2 153.2 Operations Review

416.6 416.6 416.6 394.8 394.8 394.8 59.5 59.559.5

Reserves Highlights

30.5 30.530.5

Highlights of PetroBakken’s 2010 reserves are as follows: • Proved plus probable (“2P”) reserves increased by 18% to 171.4 million barrels of oil equivalent at December 31, 2010. • 2010 production was replaced 2.7 times as a result of increases in reserves from operations and acquisitions.

07 07 07 08 08 08 09 09 09 10 10 10

08 08 08 09 09 09 10 10 10

• Our new entry into the Cardium play in Alberta during 2010, through three corporate acquisitions and our initial drilling campaign, has yielded

● Proved Developed Producing ● Proved Developed Producing ● Proved Developed Producing incremental reserve additions of ● Proved Undeveloped & Non-producing ● Proved Undeveloped & Non-producing ● Proved Undeveloped &2P Non-producing ● Probable ● Probable ● Probable

43 MMboe.

• Net present value (“NPV”) (before tax, discounted at 10%) of 2P reserves increased by 14% to $4.1 billion. • 2P FD&A costs were $39.31 per boe, including the three corporate acquisitions, asset divestitures and changes in future development costs. Excluding net acquisitions and divestitures, our 2P finding and development (“F&D”) costs were $26.11 per boe. 2010 Reserves (Company interest, forecast prices)

PRODUCTION QUARTER PRODUCTION BYBY QUARTER PRODUCTION BY QUARTER

FUNDS FLOW FROM FUNDS FLOW FROM FUNDS FLOW FROM Gas (mmcf) OPERATIONS QUARTEROil (mbbl) OPERATIONS BYBY QUARTER OPERATIONS BY QUARTER

boed (thousands) (thousands) boedboed (thousands) 50 50 50

Proved developed producing Proved Proved plus probable

63,790 $ millions $ millions $ millions

$ billions $ billions $ billions

50,888 80,866 136,153

94,337 148,754

200 200200

NET PRESENT VALUE NET PRESENT VALUE NET PRESENT VALUE NGL (mbbl) Total (mboe) 66,183 103,028 171,377

3,807 5,414 8,871

4.1 4.14.1 40 40 40

30 30 30

20 20 20

10 10 10

2010 Reserve Reconciliation (working interest, forecast prices, mboe) 150 150150

Opening Production Net acquisitions Net additions Closing Year over year increase Production reserve replacement

3.7 3.73.7 Proved Proved + Probable 89,470 143,638 (15,031) (15,031) 5,344 6,817 22,220 34,393 102,003 1.51.5 169,816 1.5 14% 18% 183% 274% 0.8 0.8 0.8

Developed Producing 59,412 (15,031) 3,283 17,662 65,326 10% 139%

100 100100

50 50 50

2010 Reserves net present value (forecast prices, $000) 0

0 0

08 08 08

09 09 09

10 10 10

Proved producing Q1 ●● ●● Q2 ●● Q3 ●● Q1 Q2 ●● Q3 ●● Q4 Q4 ●● ●● Q1 ●● ●● Q2developed Q3 ●● Q4 ●● Proved Proved plus probable

RESERVES VALUE RESERVES VALUE RESERVES VALUE

Net present value $000 present value $000 Net Net present value $000 discounted 10% before discounted before discounted 10% 10% before tax taxtax

0% 3,355.3

0 0

085%08 08

09 09 0910%

2,574.1 Q1 ●● ●● Q2 ●● Q3 ●● ●● Q1 ●● Q2 ●● Q3 1,849.3 Q4 Q4 ●● Q1 ●● Q22,135.0 Q3 ●● ●● Q4 ●●

0% 3,043.6

4,765.3

3,541.1

2,844.8

2,392.2

4,072.5

8,367.7

5,521.1

4,141.6

3,325.6

6,707.4

RESERVES MIX RESERVES RESERVES MIXMIX

mmboe mmboe mmboe Proved plus probable Proved probable Proved plusplus probable

8.9 8.98.9

After Tax 07 08 08 08 10% 10 10 07 07 5% 09 09 09 10 15% 2,355.2 1,965.7 1,711.0 ● Proved Developed Producing ● Proved Developed Producing ● Proved Developed Producing ● Proved Undeveloped ● Proved Undeveloped ● Proved Undeveloped 3,037.6 2,445.6 2,059.1 ● Probable ● Probable ● Probable 4,471.5

3,370.9

RESERVES RESERVES RESERVES

2,713.0

LAND LAND PO LAND POSIT

mmboe mmboe mmboe

thousa thousand thousands of

24.8 24.824.8

$1,297 $1,297 $1,297

68.3 68.368.3

$2,135 $2,135 $2,135 $710 $710 $710

Before Tax 10 10 10 15%

136.2 136.2 136.2

66.2 66.266.2

36.8 36.836.8

58 400400400

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

●and Light and Medium ● Light and Medium ● Light Medium Oil Oil Oil ● NGL ● NGL ● NGL ● Natural ● Natural ● Natural Gas GasGas

07 07 07 08

● Unde ● Undevel ● Undeveloped

2010 Annual Report 27

Operations Review

Finding, Development and Acquisition Costs (“FD&A”) PetroBakken had an active drilling program in 2010 and achieved 2P F&D costs of $26.11/boe (2009: $33.02/boe) on our 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) (2009: $32.48/boe). A significant portion of the acquisitions included land value associated with the Cardium light oil resource play, which generated 2P acquisition FD&A metrics of $41.82/boe, including land value (2009: $32.42/boe), and $25.25/boe excluding land value (2009: $29.96/boe). In addition, FDC represents $8.19/boe of our 2P acquisition FD&A ($4.22/boe on corporate 2P FD&A). The land value and FDC associated with the acquisitions represent potential future reserves additions and over time we expect the overall 2P FD&A for the Cardium area will not exceed $25.00/ boe. Disposition activity has driven up corporate FD&A in 2010 by approximately 20%, as we sold gas weighted non-core properties at an average price of $11.52/boe. Overall, our non-core disposition program (including our December 2009 transaction) generated $312 million of net proceeds at an average 2P reserve value of of $18.38/boe.

PetroBakken FD&A Costs (1) For the year ended December 31, 2010 Capital expenditures (unaudited $000) Capital expenditures ($000) Acquisition/(Disposition) capital ($000) (4) Total Capital Less: Land value Total capital excluding land value

F&D

Acquisitions (2)

Dispositions

FD&A (5)

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) (166,712)

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

(3)

Change in Future Development Costs (FDC) ($000) Total Proved Proved plus probable (2P) Total costs ($000) Total Proved Proved plus probable (2P) Net reserve additions/revisions (mboe) Total Proved Proved plus probable (2P) FD&A costs ($/boe) (5) (Including Land) Proved Proved plus probable (2P) FD&A costs ($/boe) (excluding land) Proved Proved plus probable (2P) For the year ended Dec .21, 2009 FD&A costs ($/boe) (5) (Including Land) Proved Proved plus probable FD&A costs ($/boe) (5) (Excluding Land) Proved Proved plus probable (2P) For the three years ended Dec. 21, 2010 FD&A costs ($/boe) (5) (Including Land) Proved Proved plus probable (2P) FD&A costs ($/boe) (5) (Excluding Land) Proved Proved plus probable (2P)

(1) The aggregate of the exploration and development 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 and development costs related to reserve 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. (3) The Company’s annual audit of our consolidated financial statements is not yet complete and accordingly all financial amounts are management’s best estimates which are unaudited and subject to change. (4) 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. (5) The Company uses FD&A as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions.

28 PetroBakken Energy Ltd.

PetroBakken

Values

We focus on innovatively creating long-term shareholder value.

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

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

e act with honesty and integrity, conducting ourselves in an ethically and morally W 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.

2010 Annual Report 29

MD&A

Management’s Discussion And Analysis Summary of Annual Results

Peter D. Scott, Senior Vice President and Chief Financial Officer

Financial ($000s, except where noted) Oil and natural gas revenue Funds flow from operations(1) Per share – basic ($) – diluted ($)(2) Net income Per share - basic ($) – diluted ($) Capital expenditures(3) Total assets Net debt(1) Long-term financial liabilities(4) Dividends Per share ($) Common shares, end of period (000) Basic Diluted(2) Operations Operating netback ($/boe except where noted)(5) Oil and NGL revenue ($/bbl)(6) Natural gas revenue ($/mcf)(6) Oil, NGL and natural gas revenue(6) Royalties Production expenses Operating netback(1) (7) Average daily production(5) Oil and NGL (bbls) Natural gas (mcf) Total (boe)

Q4 2010

2010

2009

2008

258,359 160,817 0.85 0.80 15,078 0.08 0.08 262,758 5,768,795 1,023,378 1,396,098 45,076 0.24

1,008,556 646,316 3.51 3.27 47,985 0.26 0.26 811,871 5,768,795 1,023,378 1,396,098 177,205 0.96

575,588 394,819 3.15 3.14 43,397 0.35 0.34 394,023 4,480,604 912,703 753,970 41,246 0.24

585,800 416,628 3.79 3.79 186,349 1.70 1.70 545,833 1,318,090 416,335 318,332 -

187,140 215,011

171,856 177,991

109,800 109,800

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

The following Management’s Discussion and Analysis (“MD&A”) is dated March 7, 2011 and should be read in conjunction with the audited consolidated financial statements and accompanying notes of PetroBakken Energy Ltd. (“PetroBakken”, “we” or “our” or the “Company”) as at and for the years ended December 31, 2010 and 2009. 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. 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 of oil equivalent based on an energy equivalency conversion method primarily attributable at the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, especially if used in isolation.

Basis of Presentation PetroBakken was incorporated in Alberta on July 30, 2009 as a 100% wholly-owned subsidiary of Petrobank Energy and Resource Ltd (“Petrobank”). PetroBakken was capitalized with Petrobank’s Canadian Business Unit (“CBU”) assets and obligations. In return, Petrobank received 109.8 million common shares of PetroBakken. As PetroBakken and the CBU assets were under common control, the consolidated financial statements have been presented on a continuity-of-interest basis of accounting and represent the activities of the above noted entities from the date each commenced operations. The consolidated financial statements presented for comparative purposes reflect the financial position, results of operations and cash flows as if PetroBakken had been consolidated with the CBU assets since inception. 30 PetroBakken Energy Ltd.

MD&A

Acquisition of TriStar On October 1, 2009, PetroBakken acquired all of the issued and outstanding common shares of TriStar Oil & Gas Ltd. (“TriStar”) pursuant to a plan of arrangement, whereby TriStar shareholders received aggregate consideration of $584.5 million in cash and 62.1 million common shares of PetroBakken (including shares issued to financial advisors), representing approximately 36% of the total PetroBakken shares outstanding on October 1, 2009. As at December 31, 2010, Petrobank retained a 59% ownership interest in PetroBakken.

Forward-Looking Statements This MD&A and the accompanying summary of results contain forward-looking statements. More particularly, they contain forward-looking statements concerning potential exploration and development activities, the potential for enhanced recovery and production and the reduction of operating costs from the application of completion and recompletion activities and the construction of facilities, expected production growth, future dividend payments, anticipated sources of funding for capital and operating activities and the preparation for and potential impact of the implementation of International Financial Reporting Standards. The forward-looking statements are based on certain key expectations and assumptions, including expectations and assumptions concerning the availability of capital, the success of future drilling, completion, recompletion and development activities, the performance of existing wells, the performance of new wells, prevailing commodity prices and economic conditions, the availability of labour and services, weather and access to drilling locations, the geological nature of the formations targeted and prevailing accounting standards. Although we believe that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because we can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, reliance on industry partners, availability of equipment and personnel, uncertainty surrounding timing for drilling and completion activities resulting from weather and other factors, changes in applicable regulatory regimes and health, safety and environmental risks, commodity price and exchange rate fluctuations and general economic conditions). Certain of these risks are set out in more detail in this MD&A and our Annual Information Form which has been filed on SEDAR and can be accessed at www.sedar.com.

Non-GAAP Measures This report contains financial terms that are not considered measures under Canadian generally accepted accounting principles (“GAAP”), such as funds flow from operations, net debt and operating netback. These measures are commonly utilized in the oil and gas industry and are considered informative for management and stakeholders. Specifically, funds flow from operations reflects cash generated from operating activities before changes in non-cash working capital. Management considers funds flow from operations important as it helps evaluate performance and demonstrate the ability to generate sufficient cash to fund future growth opportunities, pay dividends and repay debt. Net debt includes bank debt outstanding plus current liabilities less current assets and is used to evaluate PetroBakken’s financial leverage. Profitability relative to commodity prices per unit of production is demonstrated by an operating netback. Operating netback reflects revenues less royalties, transportation costs, and production expenses divided by production for the period. Funds flow from operations, net debt 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 operations or other measures of financial performance calculated in accordance with GAAP.

Significant 2010 Transactions 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 reduced for dividends paid. Based on dividends paid to February 2011, the conversion price is $37.74 per share. The convertible debentures have an annual coupon rate of 3.125% and mature in February 2016. On February 25, 2010, PetroBakken acquired all 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 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. 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. 2010 Annual Report 31

MD&A

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. On May 17, 2010, PetroBakken commenced a normal course issuer bid (“NCIB”) pursuant to which the Company 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 the Company’s election. As of the date of the MD&A, 1,680,400 common shares have been repurchased under the NCIB for $36.4 million.

Financial And Operating Review The acquisition of TriStar on October 1, 2009 has significantly impacted financial and operating results for 2010. (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.) Average Daily Production

Oil and NGL (bbls) Natural gas (mcf) Total (boe)

Three months ended December 31, 2010 2009 Change 34,754 38,796 (10%) 39,474 40,951 (4%) 41,333 45,621 (9%)

Year ended December 31, 2010 2009 35,109 22,648 39,473 22,110 41,688 26,333

Change 55% 79% 58%

Production increased by 58% for the year ended December 31, 2010, primarily due to the acquisition of TriStar on October 1, 2009. In the fourth quarter, the 9% decrease in production was the result of natural production declines, which more than offset production additions as weather related delays restricted our ability to access leases and bring on additional production. The 2010 production additions came from drilling our light oil properties in southeast Saskatchewan and the Cardium play in central 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% in 2010. Drilling activity increased significantly in 2010, as compared to the prior year, commensurate with the increase in oil prices allowing for a larger capital program. We 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, our drilling has been mainly focused in southeast Saskatchewan for both Bakken and conventional Mississippian light oil opportunities. Drilling in the Cardium play commenced in the third quarter. Wet weather in the third and early fourth quarter delayed completions operations, particularly in the Cardium, which also delayed production additions. The Company had 15.5 net Cardium wells waiting to be completed or brought on production at December 31, 2010. In the Bakken, the Company 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 reservoir surrounding 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, we 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. Average January production is estimated at 41,400 boepd based on field estimates. In the Cardium we now have 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$1 Oil and NGL Realized price per bbl ($/bbl) US$ discount as a % of WTI Natural gas Realized price per mcf ($/mcf)

32 PetroBakken Energy Ltd.

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%

Year 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%)

MD&A

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 US dollar. The fourth quarter of 2010 also experienced wider price differentials to WTI as Canadian sourced crude experienced restrictions as a result of Enbridge 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 December 31, 276,334 (26,803) 8,828 258,359 (17,975) (7%)

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

Year ended December 31, 575,588 366,251 66,717 1,008,556 432,968 75%

Net Realized Prices

Revenue Transportation expense Total revenue, net of transportation expense Gross revenue ($/boe) Transportation costs ($/boe) Realized price, net of transportation expense ($/boe)

Three months ended December 31, 2010 2009 Change 258,359 276,334 (7%) 3,593 3,297 9%

Year ended December 31, 2010 2009 1,008,556 575,588 15,270 8,820

Change 75% 73%

254,766

273,037

(7%)

993,286

566,768

75%

67.94 0.94

65.84 0.79

3% 19%

66.28 1.00

59.89 0.92

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 our 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. Royalties

Royalties(1) $ per boe Royalties as a % of realized price, net of transportation costs

Three months ended December 31, 2010 2009 Change 37,379 42,565 (12%) 9.84 10.14 (3%) 15%

16%

(6%)

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

Change 73% 9%

14%

(1) Royalties include the Saskatchewan Resource Surcharge determined as a percentage of sales from our Saskatchewan Crown lands.

Royalties decreased in the fourth quarter due to production declines and a lower effective 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%. On Crown lands in Alberta, horizontal oil wells are subject to a maximum 5% royalty rate for 18 to 48 months depending on well length.

2010 Annual Report 33

MD&A

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. The Company’s risk management activities are conducted pursuant to the Company’s risk management policies that have been approved by the Board of Directors. The majority of our financial commodity derivative contracts are option-based contracts and as such their fair value at a particular point in time is affected by underlying commodity prices, expected commodity price volatility and the duration of the contract. The fair value of fixed price derivative contracts at a particular point in time is determined by the expected future settlements of the underlying commodity or interest rate. At December 31, 2010, the fair value of financial derivative contracts was a liability of $13.0 million. The fair value of this liability represents the estimated amount required to settle PetroBakken’s outstanding contracts at December 31, 2010 and will be different than what will eventually be realized. The gain or loss on risk management contracts is made up of two components; the realized component reflects actual settlements that occurred during the period, and the unrealized component represents the change in the fair value of contracts during the period. The unrealized loss on risk management contracts in the fourth quarter and in 2010 was primarily the result of the fluctuations in expected future WTI prices. The following table summarizes the change in and the fair value of derivative contracts: Crude Oil (6,488) (8,347) (14,835)

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

Natural Gas 470 (428) 1,980 2,022

Interest (118) 571 (688) (235)

Total (6,136) (8,204) 1,292 (13,048)

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 (1) Prices are the volume weighted average prices for the period.

34 PetroBakken Energy Ltd.

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

MD&A

The following is a summary of 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 average of the above volumes is as follows: Term

Volume (bopd)

Average Price ($/bbl)(1)

Benchmark

2011 2012 2013

10,000 5,500 2,000

$76.14 floor/$99.42 ceiling $75.00 floor/$111.98 ceiling $75.00 floor/$119.19 ceiling

US$WTI US$WTI US$WTI

(1) Canadian dollar contracts are converted at an exchange rate of $0.9946.

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)

Price ($/GJ)

Type

2,000 2,000

$6.00 $6.02

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

Production expenses $ per boe

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

Year 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 us to add liquids rich natural gas production and reserves associated with Bakken light oil production. Operating costs in our 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. General and Administrative Expenses

General and administrative expenses $ per boe

Three months ended December 31, 2010 2009 Change 8,572 5,557 54% 2.25 1.32 70%

Year ended December 31, 2010 2009 33,233 15,253 2.18 1.59

Change 118% 37%

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.

2010 Annual Report 35

MD&A

Stock-Based Compensation Expenses

Stock-based compensation expenses

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

Year ended December 31, 2010 2009 22,888 18,650

Change 23%

Stock-based compensation expenses relate to stock options, deferred common shares and incentive shares granted. Starting in the fourth quarter of 2009, this expense relates to PetroBakken securities granted to employees and directors following the incorporation of the Company and the acquisition of TriStar. For the first nine months of 2009, this expense relates to historical Petrobank securities that were granted to employees involved with CBU operations. The calculation of this non-cash expense is based on the fair value of stock options, deferred common shares and incentive shares granted, amortized over the vesting period of the option and incentive share or immediately upon grant of the deferred common share. Interest and Other Expense

Cash interest and other expense Amortization of deferred financing costs Accretion of the convertible debentures Interest expense

Three months ended December 31, 2010 2009 Change 12,735 7,449 71%

Year ended December 31, 2010 2009 45,229 13,958

Change 224%

1,329

4,062

(67%)

4,849

4,530

7,007 21,071

11,511

83%

25,533 75,611

18,488

309%

Interest expense includes interest on bank debt, fees on letters of credit, amortization of deferred financing costs, interest on the convertible debentures, and accretion on convertible debentures. 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. Foreign Exchange Gain (Loss)

Foreign exchange gain (loss)

Three months ended December 31, 2010 2010 2009 Change 19,917 (1,105) -

Year ended December 31, 2010 2009 19,541 (1,105)

Change -

The Company recognizes foreign exchange gains/losses primarily due to the appreciation/depreciation of the Canadian dollar relative to the U.S. dollar. Our convertible debentures are denominated in U.S. dollars, as a result the vast majority of unrealized foreign exchange gains and losses relate to the change in the foreign exchange rate compared to the rate at the end of the previous period. In the current quarter this would be the rate at the end of the third quarter, for 2010 this is the rate established when the debentures were issued. A stronger Canadian dollar at December 31, 2010 compared to the rate at September 30, 2010 resulted in a foreign exchange gain for the quarter. The foreign exchange rate at December 31, 2010 was higher than the rate on January 25, 2010 when the debentures were issued which resulted in an unrealized gain in 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 (â&#x20AC;&#x153;DD&Aâ&#x20AC;?) Expense

DD&A expense $ per boe

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

Year ended December 31, 2010 2009 525,403 303,714 34.53 31.60

Change 73% 9%

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

Future income tax expense (recovery) 36 PetroBakken Energy Ltd.

Three months ended December 31, 2010 2009 Change 1,798 (33,653) -

Year ended December 31, 2010 2009 31,450 (24,027)

Change -

MD&A

The Companyâ&#x20AC;&#x2122;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 benefitted from a recovery associated with a property disposition.

Net Income As summarized in the table below, the decrease in fourth quarter net income is primarily due to lower sales volumes, losses on risk management contracts, and higher interest and future income tax expense, offset by higher prices, lower royalty, DD&A, and acquisition expense, and a foreign exchange gain related to the convertible debentures. The increase in net income for 2010 is primarily due to higher sales volumes as a result of the TriStar, Berens, Rondo, and Result acquisitions, higher WTI prices, higher unrealized gains on risk management contracts, a foreign exchange gain related to the convertible debentures, and lower acquisition related expense offset by higher royalties, realized losses on risk management contracts, production expenses, general and administrative expense, interest expense, DD&A expense, and future income tax expense. Reconciliation of Changes in Net Income

Net income: December 31, 2009 Increase (decrease) due to: Sales volumes Realized prices Royalties Realized loss on risk management contracts Unrealized gain (loss) on risk management contracts Production expenses General and administrative Foreign exchange gain Interest and other DD&A expense Future income taxes Acquisition related Other(1) Net income: December 31, 2010

Three months ended December 31, 33,385

Year ended December 31, 43,397

(26,803)

366,251

8,828

66,717

5,186 (3,268) (3,665) 409 (3,015) 21,022 (9,560) 8,410 (35,451) 19,155

(59,913) (24,194) 33,737 (53,568) (17,980) 20,646 (57,123) (221,689) (55,477) 17,869

445 15,078

(10,688) 47,985

(1) Includes transportation expense and stock based compensation expense.

Funds Flow from Operations The decrease in funds flow from operations in the fourth quarter of 2010 is primarily due to production decreases and higher interest expense, partially offset by higher prices, and lower royalties and acquisition expenses. Funds flow from operations increased in 2010 primarily due to production increases, higher realized prices, and lower acquisition expenses, partially offset by higher royalties, production expenses, interest expenses, G&A expenses, and a realized loss on risk management contracts. Reconciliation of Changes in Funds Flow From Operations Funds flow from operations: December 31, 2009 Increase (decrease) due to: Sales volumes Realized prices Royalties Realized portion of risk management contracts Production expenses Cash interest expense General and administrative Cash acquisition related costs Other (1) Funds flow from operations: December 31, 2010

Three months ended December 31, 173,566

Year ended December 31, 394,819

(26,803) 8,828 5,186 (3,268) 409 (5,286) (3,015) 10,570 630 160,817

366,251 66,717 (59,913) (24,194) (53,568) (31,271) (17,980) 9,284 (3,829) 646,316

(1) Includes transportation expenses, realized FX gain and asset retirement obligations settled.

2010 Annual Report 37

MD&A

The following table shows the reconciliation of funds flow from operations to cash flow from operating activities for the periods noted: Three months ended December 31, 2010 2009 Change Funds flow from operations: Non-GAAP Changes in non-cash working capital Cash flow from operating activities: GAAP

Year ended December 31, 2010 2009

Change

160,817

173,566

(7%)

646,316

394,819

64%

(25,128)

(1,660)

(1,414%)

(84,661)

(6,876)

(1,131%)

135,689

171,906

(21%)

561,655

387,943

45%

Capital Expenditures

Capital expenditures

Three months ended December 31, 2010 2009 Change 262,758 177,278 48%

Year ended December 31, 2010 2009 811,871 394,023

Change 106%

Capital Expenditures by Type

Drilling, completions and recompletions Land Facilities Seismic Other (1) Capital expenditures before acquisitions Asset acquisitions Total capital expenditures Dispositions

Three months ended December 31, 2010 2009 207,637 137,029 7,195 3,125 39,643 24,237

Year ended December 31, 2010 2009 568,905 271,055 94,751 40,670 91,245 53,692

303

6,359

3,284

7,609 262,387 371 262,758 3,571

4,764 169,166 8,112 177,278 178,849

20,263 781,523 30,348 811,871 133,632

17,210 385,911 8,112 394,023 178,849

Net wells pending completion and/or tie-in Net wells drilled 35.7 (1) 2.8 (2) 8.1 2.8 32.6 (3) 15.5 1.0 2.0 77.4 23.1

Dry and abandoned wells 1.0 1.0

Success Rate 100% 88% 100% 100% 99%

Net wells pending completion and/or tie-in Net wells drilled 140.2 (1) 2.8 (2) 42.1 2.8 55.0 (3) 15.5 2.0 2.0 239.3 23.1

Dry and abandoned wells 1.0 2.0 3.0

Success Rate 99% 95% 100% 100% 99%

(1) Includes health, safety and environmental expenditures, capitalized salaries, office furniture and fixtures, and leasehold improvements.

Net Drilling Activity, for the three months ended December 31, 2010

Business Unit Bakken Conventional Cardium BC/Other AB Total (1) Includes 25.1 net bilateral wells. (2) Does not include 14.9 wells where fracs have been delayed. (3) Includes 1.7 non-Cardium formation wells.

Net Drilling Activity, for the year ended December 31, 2010

Business Unit Bakken Conventional Cardium BC/Other AB Total (1) Includes 121.3 net bilateral wells. (2) Does not include 14.9 net wells where fracs have been delayed. (3) Includes 1.7 non-Cardium formation wells.

38 PetroBakken Energy Ltd.

MD&A

The majority of capital expenditures in the fourth quarter and 2010 were focused on drilling, completions, and recompletions. Most of this activity was focused in Southeast Saskatchewan, particularly in the Bakken play, however activity levels did increase in the Cardium play in the fourth quarter as lease conditions improved. Compared to 2009, there were 12.6 additional wells drilled in the fourth quarter and 122.0 additional wells drilled in 2010. The majority of facilities expenditures in the fourth quarter and 2010 were comprised of costs to tie-in additional wells, and the expansion of gathering systems to our five major facilities in southeast Saskatchewan. Activity in the Cardium area resulted in the majority of land and property acquisitions in 2010. Goodwill There were no changes to goodwill in the fourth quarter. The total goodwill increase for the year is $457.6 million, which includes goodwill from the Berens, Rondo, and Result acquisitions. Goodwill as at December 31, 2010 was $1,490.5 million.

Summary Of Quarterly Results Financial ($000s except where noted) Total assets Net debt(1) Capital expenditures Dividends Per share Oil and natural gas revenue Net income (loss) Per share – basic Per share – diluted Fund flow from operations(1) Per share – basic Per share – diluted(6) Operations Operating netbacks by product Crude oil and NGL sales price ($/bbl)(3) (5)

2010 Q3

2009 Q3

5,768,795 1,023,378 262,758 45,076 0.24 258,359 15,078 0.08 0.08 160,817 0.85 0.80

5,613,332 857,318 241,309 45,177 0.24 228,537 9,194 0.05 0.05 140,761 0.75 0.71

75.19

68.43

70.98

76.08

71.63

67.65

62.22

48.57

10.94 9.56

9.67 8.88

10.36 7.89

10.56 7.95

11.26 8.45

10.75 7.05

7.97 6.66

5.39 6.98

54.69 3.96 0.66 0.98 2.32 67.00 9.84 8.97 48.19

49.88 3.82 0.62 1.00 2.20 60.63 8.64 8.38 43.61

52.73 4.11 0.60 1.03 2.48 62.86 9.17 7.59 46.10

57.57 5.20 0.60 1.12 3.48 70.41 9.68 7.80 52.93

51.92 4.61 0.63 1.16 2.82 65.05 10.14 8.23 46.68

49.85 3.55 0.54 0.93 2.08 60.66 9.62 6.83 44.21

47.59 3.91 0.67 0.95 2.29 56.64 7.40 6.52 42.72

36.20 5.35 0.78 0.90 3.67 46.81 5.32 6.81 34.68

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

19,722 14,179 22,085

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(2) Crude oil and NGL’s (bbls)(5) Natural gas (mcf) Total (boe)

5,507,569 5,084,280 4,480,604 1,421,233 697,726 565,645 912,703 11,750 122,688 185,116 177,278 107,820 45,265 41,687 41,246 0.24 0.24 0.24 245,954 275,706 276,334 101,316 (15,388) 39,101 33,385 9,864 (0.08) 0.23 0.19 0.09 (0.08) 0.23 0.19 0.09 155,687 189,051 173,566 72,102 0.83 1.09 1.01 0.66 0.78 1.00 1.01 0.66

1,297,287 1,309,251 366,745 430,451 38,901 70,024 102,452 95,486 (31) 179 (0.00) 0.00 (0.00) 0.00 75,891 73,260 0.69 0.67 0.69 0.67

(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. (3) Net of transportation expenses. (4) Excludes hedging activities. (5) Heavy oil has been included in crude oil as it is not considered material. (6) Consists of common shares, stock options, deferred common shares, incentive shares and convertible debentures as at the period end date. Assumes 109,800,001 were outstanding in the first nine months of 2009.

2010 Annual Report 39

MD&A

Significant factors influencing quarterly results were: • 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. Gas production also increased in the second and third quarters of 2010 due to production associated with the Berens acquisition. • Base production declines and delays in bringing production on stream resulted in a decline in liquids production from the fourth quarter of 2009 to the third quarter of 2010. • 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 haven’t had as great an impact on results due to the Company’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 have increased from 2009 as we expanded our drilling program considerably with higher funds flow from operations as a result of higher production and improved oil prices. Fourth quarter 2010 capital expenditures increased approximately 10% compared to the third quarter of 2010 as we continued our drilling program in Saskatchewan and Cardium activity in Alberta increased with improved lease conditions. • 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.

Commitments 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 Office leases Drilling and completion rigs Total

2011 $4,834 8,605 $13,439

2012 $5,345 9,003 $14,348

2013 $7,037 8,698 $15,735

2014 $7,063 6,902 $13,965

2015 $6,681 $6,681

Thereafter $25,852 $25,852

Total $56,812 33,208 $90,020

Subsequent to December 31, 2010 the Company 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.

Liquidity and Capital Resources PetroBakken’s strategy is to provide a reasonable dividend yield to shareholders while delivering an accretive growth-oriented business plan. We are 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 our $1.2 billion credit facility. Our 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 US base rate plus an applicable margin for US dollar advances. The applicable margin charged by the bank is based on a sliding scale ratio of PetroBakken’s debt to earnings before interest, taxes, depletion, depreciation and amortization (“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. The Company is in compliance with all of these covenants. On January 25, 2010, PetroBakken issued convertible debentures with an annual coupon of 3.125% for gross proceeds of US$750 million. The convertible debenture has a financial covenant that limits the amount of security and encumbrances to 35% of our total assets. The Company 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, the Company made a $327.7 million cash payment, including repayment of bank debt, for the acquisition of Berens. In March 2010, the Company made a $104.7 million cash payment, including repayment of bank debt, for the acquisition of Rondo, and in April 2010 the Company made a net $141.2 million cash payment for the acquisition of Result. We closed non-core property dispositions for net proceeds of $133.6 million.

40 PetroBakken Energy Ltd.

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 our 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. We expect to satisfy ongoing working capital requirements with funds flow from operations, cash and available credit. Capital Plan The capital plan is focused on the development of our Bakken and conventional Mississippian light oil properties in southeast Saskatchewan, development of our Cardium light oil properties acquired in Central Alberta, exploration and development of our northeast British Columbia properties, and leveraging our significant undeveloped land base into new resource opportunities. The capital plan is expected to be financed through operations and available financial resources. Dividends The Company currently pays a monthly dividend of $0.08 per share or the equivalent of $0.96 per share per annum. The dividend represented 27% of the 2010 funds flow from operations. The dividend is expected to remain the same in 2011 and to be funded from operations.

Transactions with Related Parties The Company is party to a management services agreement with Petrobank providing for certain executive functions as well as other services, including administration, financial, treasury, accounting, information technology, human resources support and office space for PetroBakken employees. The fee is based on a negotiated value for services provided. Amounts paid to Petrobank under this agreement totalled $0.6 million for the three months ended December 31, 2010 (2009 - $0.8 million) and $2.5 million for 2010 (2009 – $0.8 million) and were recorded as general and administrative expense.

Outstanding Share Data As at the date of this MD&A there are 187,171,868 PetroBakken common shares outstanding, an increase of 30,831 from December 31, 2010 due to the exercise of incentive and deferred common shares. At the date of this MD&A there were 6,027,708 stock options, 2,095,423 incentive shares, and 41,518 deferred common shares outstanding.

Risks and Uncertainties PetroBakken is exposed to a variety of risks including, but not limited to: competitive, operational, political, environmental, and financial risks. Commodity prices are PetroBakken’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 PetroBakken’s cash flows, but may also result in changes to the borrowing capacity under PetroBakken’s credit facility as assessed by the lenders. Management believes it is neither appropriate nor possible to eliminate 100% of the exposure to fluctuations in commodity prices. PetroBakken monitors market conditions and may selectively utilize derivative instruments to reduce exposure to commodity price movements. The oil and gas industry is intensely competitive. Competition is particularly intense in the acquisition of prospective oil and gas properties, oil and natural gas reserves, and land and resources. Competitors include companies larger than PetroBakken, with greater access to financial resources. PetroBakken’s future success is driven, in large part, by its 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. PetroBakken manages 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. PetroBakken 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 personnel and 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.

2010 Annual Report 41

MD&A

PetroBakken is 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. PetroBakken has a detailed emergency response plan to deal with potential incidents and maintains 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 PetroBakken’s operations. PetroBakken is subject to extensive governmental and environmental approvals and regulations in its operating jurisdictions. Delays in obtaining regulatory approvals could result in project delays and the inability to meet contractual obligations. Changes to these regulations could increase the costs of conducting business in these jurisdictions. Environmental risks inherent in the oil and gas industry are subject to increasingly stringent legislation and regulation. PetroBakken 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. PetroBakken’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 PetroBakken’s oil and gas activities. PetroBakken 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 PetroBakken’s exposure to these risks. As described in Note 12 to the 2010 PetroBakken consolidated financial statements, PetroBakken monitors market conditions and may periodically utilize derivative instruments to mitigate these risks. To the extent revenues, expenditures, financial assets and financial liabilities are denominated in or strongly linked to the US dollar are not equivalent; PetroBakken is exposed to exchange rate risk. The convertible debenture is US dollar denominated. Revenues in Canada are largely determined by US dollar reference prices. PetroBakken is not currently using exchange rate derivatives to manage exchange rate risks. PetroBakken is exposed to fluctuations in short-term interest rates on amounts drawn under its floating-rate bank facilities due to fluctuations in market interest rates. PetroBakken monitors market conditions and may selectively utilize derivative instruments to reduce exposure to interest rate movements.

Sensitivities PetroBakken’s earnings and funds flow from operations 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: Crude oil Natural gas Currency Interest rate

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

(millions) $9.7 $21.4 $12.2 $11.9 $8.5 $5.3

Critical Accounting Policies and Estimates PetroBakken’s consolidated financial statements are prepared in accordance with Canadian GAAP, which require management to make judgments, estimates and assumptions, which may have a significant impact on the financial statements. A summary of PetroBakken’s significant accounting policies can be found in Note 3 to PetroBakken’s 2010 consolidated financial statements. The following is a discussion of those accounting policies and estimates that are considered critical in the determination of PetroBakken’s financial results. Capital Assets — Full Cost Accounting PetroBakken follows the full cost method of accounting as described in Note 3 to the consolidated financial statements. Alternatively, PetroBakken 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. 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. PetroBakken has elected to follow the full cost method and it is the method most commonly followed in Canada.

42 PetroBakken Energy Ltd.

MD&A

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 centres 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 PetroBakken 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. 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. PetroBakken’s lenders also use reserve estimates to assess the lending value under the secured credit facility. Changes to the reserve estimates can result in increases or decreases to the lending value, which may impact PetroBakken’s financial position. Asset Retirement Obligations PetroBakken recognizes the estimated fair value of future retirement obligations associated with capital assets as a liability. PetroBakken 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 at fair value, 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. Future Income Taxes PetroBakken 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 Recent and Pending Accounting Pronouncements 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”. PetroBakken commenced its IFRS Conversion Project in 2009 by completing an initial scoping phase, and has established a project plan and project team, which includes key finance staff, management, external advisors and audit committee. 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:

2010 Annual Report 43

MD&A

IFRS Conversion Project Phase Accounting policies and procedures:

Milestones

Progress

• Identify differences between Canadian

• Senior management approval and audit

• Accounting policy alternatives have been

GAAP and IFRS.

• Revise and finalize accounting policies under IFRS.

• Identify potential adjustments to

initial and subsequent IFRS financial statements.

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.

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 of the board of directors 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 are expected to be completed in Q1 2011.

Financial statement preparation:

• Prepare first-time adoption reconciliations required under IFRS 1.

• Prepare financial statements and note

• Senior management approval and audit

committee review of pro forma financial statements by Q4 2010.

disclosures in compliance with IFRSs.

• Quantify the effects of converting to IFRS.

• Draft opening balance sheet and

transition note disclosure has been prepared and were reviewed by the audit committee during Q4 2010. Final approvals are expected to be completed in Q1 2011.

• Draft quarterly information has been

prepared for Q1 – Q3 2010. The company is in the process of finalizing draft Q4 2010 quarterly information.

• IFRS compliant financial statements and notes have been prepared.

Training and communication:

• Develop and deliver targeted IFRS training

• Training to be provided to relevant

• Ensure internal and external

• Impacts of converting to IFRSs

to employees and management. stakeholders receive ongoing appropriate communications.

employees prior to changeover date. communicated prior to changeover.

• Key employees involved with

implementation have completed training throughout the year.

• Quarterly disclosure of project status in MD&A.

• Policy decisions are being communicated to individuals affected and additional training is being provided as required.

Business Impacts:

• Identify impacts of conversion on

contracts including financial covenants and compensation arrangements.

• Impacts of contracts identified by Q3 2010. • Taxation impacts identified by Q1 2011.

• Identify impacts of conversion on taxation.

• Adoption of IFRS is not expected to have a material impact on current contracts.

• Analysis of taxation impacts is currently

underway by individuals experienced with taxation.

IT Systems:

• Identify changes required to IT systems

• Necessary changes to IT systems

• Implement a system for capturing

• Solution for capturing financial

and implement solutions.

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

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 (“ICFR”) and disclosure controls and procedures (“DC&P”) and implement any necessary changes.

44 PetroBakken Energy Ltd.

• Internal controls over IFRSs changeover process in place and tested prior to change over.

• Relevant internal controls are being assessed as work progresses.

• Specific controls have been established in relation to the IFRS changeover process.

MD&A

Significant identified differences between Canadian GAAP and IFRS that will impact PetroBakken are: property, plant and equipment, exploration and evaluation assets, depletion and depreciation, impairment testing, share based payments 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 PetroBakken’s current expectations. The project team is currently determining the financial statement impact of these standards. First-time Adoption of IFRS (“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 PetroBakken 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 not apply IFRS 2 to equity instruments granted which vested before the Company’s date of transition to IFRS.

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 that actual IFRS adjustment. The following transition impacts will also result in an adjustment to the balance in future income tax on transition.

2010 Annual Report 45

MD&A

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 writedowns 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.

• 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, PetroBakken 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.

• PetroBakken 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. On January 1, 2010 the value of the 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.

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 PetroBakken 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 PetroBakken 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.

46 PetroBakken Energy Ltd.

MD&A

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 PetroBakken’s oil and natural 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 PetroBakken’s financial statements under Canadian GAAP.

Under Canadian GAAP the discount rate used to measure the asset retirement obligation is the creditadjusted risk free rate. IFRS allows the use of the risk free rate when the cash flows associated are risk adjusted.

• PetroBakken expects to use the risk-free rate to determine the asset retirement obligation,

which would result in an increase to the asset retirement obligation of approximately $65 million with the adjustment recorded to retained earnings. A portion of the asset retirement obligation relates to the 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.

Regulatory Policies Certification of Disclosures in Interim Filings In accordance with National Instruments (NI) 52-109 of the CSA, 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 PetroBakken is made known to the certifying officers by others; (ii) information required to be disclosed by PetroBakken 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 at December 31, 2010.

2010 Annual Report 47

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 judgment, 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 D. Scott

Chairman & Chief Executive Officer

Senior Vice President & Chief Financial Officer

Calgary, Canada March 7, 2011

48 PetroBakken Energy Ltd.

Financial Statements

Independent Auditor’s Report To the Shareholders of PetroBakken Energy Ltd.: We have audited the accompanying consolidated financial statements of PetroBakken Energy Ltd. (the “Company”), which comprise the consolidated balance sheets as at December 31, 2010 and 2009 and the consolidated statements of operations, comprehensive income and retained earnings 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 7, 2011 Calgary, Alberta

2010 Annual Report 49

Financial Statements

Consolidated Balance Sheets (Thousands of Canadian dollars) 2010

As at December 31, Assets Current assets Cash and cash equivalents Accounts receivable Prepaid expenses Risk management assets (Note 12) Future income tax asset (Note 9)

Capital assets (Note 4) Goodwill (Note 5) Total assets Liabilities and Equity Current liabilities Accounts payable and accrued liabilities Risk management liabilities (Note 12) Future income tax liabilities (Note 9)

Bank debt (Note 6) Convertible debentures (Note 7) Other long-term liabilities Asset retirement obligations (Note 8) Risk management liabilities (Note 12) Future income tax liabilities (Note 9)

Shareholders’ equity Common shares (Note 10) Convertible debentures (Note 7) Contributed surplus (Note 10) Retained earnings Total liabilities and equity

Commitments and contingencies (Note 14). Subsequent events (Note 7, note 12 and note 14). See accompanying notes to these consolidated financial statements. Signed on Behalf of the Board:

Ian Brown John D. Wright Director Chairman and Chief Executive Officer

50 PetroBakken Energy Ltd.

147,339 11,151 2,231 3,455 164,176

2009

24,569 126,899 16,722 782 168,972

4,114,105 1,490,514 $ 5,768,795

3,278,770 1,032,862 $ 4,480,604

$ 344,476 12,682 608 357,766

$ 323,254 2,694 325,948

824,845 567,140 5,170 60,258 2,597 494,285 2,312,061

748,185 3,961 57,248 3,442 389,997 1,528,781

3,147,238 194,113 24,262 91,121 3,456,734 $ 5,768,795

2,717,098 6,191 228,534 2,951,823 $ 4,480,604

Financial Statements

Consolidated Statements Of Operations, Comprehensive Income And Retained Earnings (Thousands of Canadian dollars) Years ended December 31, Revenues Oil and natural gas Royalties

2010

2009

$ 1,008,556 $ 575,588 (142,064) (82,151)

Loss on risk management contracts (Note 12) Expenses Production Transportation General and administrative Acquisition (Note 5) Stock-based compensation Interest and other Foreign exchange (gain) loss Depletion, depreciation and accretion

Income before taxes

(8,426)

(17,969)

858,066

475,468

124,481 15,270 33,233 1,286 22,888 75,611 (19,541) 525,403 778,631

70,913 8,820 15,253 19,155 18,650 18,488 1,105 303,714 456,098

79,435

19,370

31,450 47,985

Future income tax expense (recovery) (Note 9) Net income and comprehensive income

Retained earnings, beginning of year

$ 228,534

$ 226,383

(177,205)

(41,246)

Cash dividends paid or declared Repurchase of common shares (Note 10) Retained earnings, end of year

Basic earnings per share (Note 10) Diluted earnings per share (Note 10)

$ $

(24,027) 43,397

(8,193) 91,121 $ 228,534 0.26 0.26

$ $

0.35 0.34

See accompanying notes to these consolidated financial statements.

2010 Annual Report 51

Financial Statements

Consolidated Statements Of Cash Flow (Thousands of Canadian dollars) Years ended December 31, Operating Activities Net income Depletion, depreciation and accretion Future income tax expense (recovery) Unrealized loss on risk management contracts Unrealized foreign exchange gain Stock-based compensation Accretion on convertible debentures Realized foreign exchange loss related to financing (Note 7) Amortization of deferred financing costs Acquisition related expenses (Note 5) Asset retirement obligations settled

2010 $

Changes in non-cash working capital (Note 13) Financing Activities Repurchase of common shares (Note 10) Issuance (repayment) of bank debt Issuance of convertible debentures – net of costs Realized loss on foreign exchange contract (Note 7) Financing costs relating to bank debt Amortization of obligations under gas sale contract Dividends Net investment - Petrobank Energy and Resources Ltd. Changes in non-cash working capital (Note 13) Investing Activities Expenditures on capital assets Corporate acquisitions (Note 5) Proceeds from dispositions Changes in non-cash working capital (Note 13) 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: Cash Cash equivalents Other cash flow information: Cash interest paid

See accompanying notes to these consolidated financial statements.

52 PetroBakken Energy Ltd.

2009

47,985 $ 43,397 525,403 303,714 31,450 (24,027) 8,204 41,941 (35,546) 22,888 18,650 25,533 18,184 4,849 4,530 8,585 (2,634) (1,971) 646,316 394,819 (84,661) (6,876) 561,655 387,943 (36,424) (16,845) 769,651 (18,184) (2,250) (827) (177,205) (628) 517,288

88,518 (11,576) (827) (41,246) 420,606 16,143 471,618

(811,871) (482,749) 133,632 57,476 (1,103,512) (24,569) 24,569 $ - $

(394,023) (584,455) 178,849 (36,231) (835,860) 23,701 868 24,569

$ $

1,769 22,800

45,182

15,525

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 unless otherwise noted)

Note 1 – Basis of Presentation PetroBakken Energy Ltd. (“PetroBakken” or the “Company”) was incorporated in Alberta on July 30, 2009 as a 100% wholly-owned subsidiary of Petrobank Energy Resources Ltd. (“Petrobank”). PetroBakken was capitalized with Petrobank’s Canadian Business Unit (“CBU”) assets and obligations. In return, Petrobank received 109.8 million common shares of PetroBakken. As PetroBakken and the CBU assets were under common control, these consolidated financial statements have been presented on a continuity-of-interest basis of accounting and represent the activities of the above noted entities from the date each commenced operations. The consolidated financial statements presented for comparative purposes reflect the financial position, results of operations and cash flows as if PetroBakken has been consolidated with the CBU assets since inception. On October 1, 2009, PetroBakken acquired all the issued and outstanding common shares of TriStar Oil & Gas Ltd. (“TriStar”) pursuant to a plan of arrangement, whereby TriStar shareholders received aggregate consideration of $584.5 million in cash, and 62.1 million common shares of PetroBakken (including 293,798 shares issued to financial advisors) representing 36% of the total PetroBakken shares outstanding on October 1, 2009. Subsequent to the transaction and as at December 31, 2009, Petrobank retained a 64% ownership interest in PetroBakken. As at December 31, 2010 this interest has decreased to 59%. It is important to the note that the financial statements herein reflect TriStar’s assets, liabilities, and operating results for the period following the close of the transaction on October 1, 2009. The consolidated financial statements are stated in Canadian dollars and have been prepared in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”). The preparation of the financial statements in conformity with GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the period. Actual results could differ from those estimates and assumptions. In the opinion of management, these financial statements have been prepared within the reasonable limits of materiality and within the framework of the significant accounting policies summarized below.

Note 2 – Changes in Accounting Policies Pending Accounting Pronouncements The Accounting Standards Board has confirmed the convergence of Canadian GAAP with International Financial Reporting Standards (“IFRS”) will be effective January 1, 2011. The Company has developed a project plan in order to ensure successful implementation within the required timeframe.

Note 3 – Significant Accounting Policies Consolidation These consolidated financial statements include the accounts of the Company and its subsidiaries as at and for the years ended December 31, 2010 and 2009. All subsidiaries are wholly-owned and their operations are fully reflected in the consolidated financial statements. All intercompany transactions and balances are eliminated upon consolidation.

Measurement Uncertainty The preparation of financial statements in conformity 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 53

Notes

Amounts recorded for depletion, depreciation and accretion costs and amounts used for ceiling test impairment calculations are based on estimates of oil and natural gas reserves and future costs required to develop those reserves. Goodwill impairment is based on 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. These 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. 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 mcf to one barrel of oil, 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 order to test impairment. Management 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 centreâ&#x20AC;&#x2122;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 centreâ&#x20AC;&#x2122;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 has been recorded at cost and is not amortized. Goodwill is tested for impairment at least annually or whenever events or circumstances indicate that goodwill is impaired. If goodwill is impaired the carrying value is reduced to the estimated fair value and an impairment loss is recorded in net income. No impairment to goodwill has been recorded to date.

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 liability is based on the estimated costs to abandon and reclaim the 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.

54 PetroBakken Energy Ltd.

Notes

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 our 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. Transaction costs related to bank debt 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 Oil and natural gas operations may be conducted jointly with others and accordingly these 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.

Comprehensive Income Comprehensive income consists of net income and other comprehensive income (“OCI”). OCI includes gains and losses resulting from 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 equity comprised of the cumulative amounts of OCI. Amounts included in AOCI are reclassified to income when realized. The Company has not recorded any OCI.

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 uses the treasury stock method in computing the weighted average number of diluted common shares outstanding. This method assumes that the proceeds on exercise of in-the-money stock options, incentive shares and deferred common shares 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 using the prevailing conversion price on the balance sheet date.

Stock-Based Compensation The Company accounts for stock-based compensation using the fair-value method of accounting for stock options, incentive shares and deferred common shares (collectively referred to as “Rights”) granted to directors, officers and employees using the Black-Scholes option-pricing model. Stock-based compensation expense is recorded and reflected as stock-based compensation expense over the vesting period with a corresponding amount reflected in contributed surplus. Stock-based compensation expense is calculated as the estimated fair value for the related Rights at the time of grant, amortized over their vesting period. When 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.

Income Taxes The liability method of accounting has been followed for income taxes. Under this method, future income tax assets or liabilities are recorded to reflect loss carryforwards 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.

2010 Annual Report 55

Notes

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 debentures 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. The equity component of the convertible debentures is presented within 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. Upon conversion of the debentures into common shares by the holders, the debt and equity components would be transferred to common share capital. Upon repayment of the debentures in cash, the debt component would be derecognized and the equity portion transferred to contributed surplus.

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 business. Management may use a variety of instruments to manage these exposures. For transactions where hedge accounting is not applied, we account for such instruments using the fair value method by initially recording an asset or liability, and recognize 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. Management 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 management had not designated any of its outstanding financial instruments as hedges.

Cash and Cash Equivalents Cash and cash equivalents include investments and deposits with a maturity of three months or less when purchased.

Note 4 – Capital Assets December 31, 2010 Oil and natural gas assets Other assets

December 31, 2009 Oil and natural gas assets Other assets

Cost $ 5,247,880 23,651 $ 5,271,531

Accumulated Depletion and Depreciation $ 1,145,620 11,806 $ 1,157,426

Net Book Value $ 4,102,260 11,845 $ 4,114,105

Cost $ 3,898,602 16,787 $ 3,915,389

Accumulated Depletion and Depreciation $ 628,355 8,264 $ 636,619

Net Book Value $ 3,270,247 8,523 $ 3,278,770

At December 31, 2010, oil and natural gas assets included $1,163.3 million (2009 – $751.8 million) relating to unproved properties.

56 PetroBakken Energy Ltd.

Notes

An impairment test calculation was performed at December 31, 2010 in which the estimated undiscounted future net cash flows associated with the proved reserves exceeded the carrying amount. In determining the undiscounted future net cash flows, the Company utilized benchmark pricing forecasts from its reserve evaluator. The benchmark prices used in their forecasts at December 31, 2010 are outlined in the following table: WTI Year 2011 2012 2013 2014 2015 Thereafter % change

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 5 – Acquisitions and Dispositions 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 the Company. 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) 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 financial statements based on information then available. Amendments may be made to these amounts as values subject to estimate are finalized.

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 the Company. 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.

2010 Annual Report 57

Notes

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 Common shares issued (5,524,471) Total purchase price

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

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 the Company. 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

58 PetroBakken Energy Ltd.

Notes

The impact of the above three acquisitions on goodwill for the year ended December 31, 2010 is: Cost Balance at December 31, 2009 Additional amounts recognized from business combinations occurring during the period (see above) Balance at December 31, 2010

Amount $ 1,032,862 457,652 $ 1,490,514

TriStar Oil & Gas Ltd. On October 1, 2009, PetroBakken acquired all of the issued and outstanding shares of TriStar Oil & Gas Ltd. (“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 on 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 the Company. 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 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 $ 2,165,577 (83,625) (351,551) (47,277) 2,901 997,810 (294,447) $ 2,389,388

Consideration paid Cash 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 approximately 2,000 boepd of Alberta production (70% natural gas) 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.

2010 Annual Report 59

Notes

Note 6 – Bank Debt The Company 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 earnings before interest, depletion, depreciation and amortization (“EBITDA”). The facility is secured by a $2.0 billion demand debenture and a securities pledge on the Company’s assets. As at December 31, Bank debt outstanding Deferred financing costs Bank debt

2010 2009 $ 829,788 $ 755,727 (4,943) (7,542) $ 824,845 $ 748,185

Note 7 – Convertible Debentures 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 for dividends paid by the Company. Due to dividends paid to shareholders of PetroBakken 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 the Company has an 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. The US 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. The Company entered into currency swap agreements prior to the date of issue and the actual Canadian dollar proceeds received by the Company resulted in an $18.2 million realized foreign exchange loss in the first quarter of 2010. The following table summarizes the change in the liability component of the convertible debentures:

Liability component of debenture at issuance – January 25, 2010 Accumulated accretion Accumulated gain in exchange rate Liability component at December 31, 2010

$ 577,153 25,533 (35,546) $ 567,140

Note 8 – 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 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

60 PetroBakken Energy Ltd.

2010 57,248 $ 3,122 7,752 (9,935) (2,634) 4,596 109 60,258 $

2009 11,170 2,243 47,277 (3,349) (1,971) 1,878 57,248

Notes

The obligations have been calculated using an inflation rate of two percent 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 45 years in the future and are expected to be funded from general resources of the Company at the settlement date. The total undiscounted amount of estimated cash flows required to settle the obligations at December 31, 2010 is $204.8 million (2009 – $188.7 million).

Note 9 – Future Income Taxes The provision for future income taxes differs from the amount that would have been expected by applying expected statutory corporate income tax rates to income before future income taxes. The principal reasons for this difference are as follows: Years ended December 31, Income before future income taxes Canadian statutory income tax rate Expected tax expense Increase (decrease) in income tax provision resulting from: Stock-based compensation Accretion of convertible debentures Non-taxable capital gains(1) Non-deductible transaction costs and other expenses Permanent difference associated with dispositions Change in estimates and other Provision for future income taxes

2010 79,435 29.04% 23,068

2009 19,370 30.04% 5,819

6,647 5,603 6,798 (5,161) 530 5,805 (42,903) (432) 1,649 31,450 $ (24,027)

(1) Consists of non-taxable portion (50%) of unrealized foreign exchange gain on convertible debentures.

The components of the Company’s future income tax assets and liabilities arising from temporary differences and loss carry-forwards are as follows: As at December 31,

Capital assets Income taxable in subsequent years Non-capital losses Asset retirement obligations Risk management contracts(1) Obligations under gas sale contract Share issuance and financing costs Convertible debentures(2)

2010 Future Income Future Income Tax Assets Tax Liabilities $ - $ 426,532 167,433 79,509 -

2009 Future Income Future Income Tax Assets Tax Liabilities $ - $ 347,205 79,698 11,556 -

15,689

14,910

3,555 1,360 8,624 $ 108,737

6,210 $ 600,175

1,782 1,069 8,371 37,688

$ 426,903

(1) 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). (2) Unrealized foreign exchange gain on convertible debentures is taxed as a capital gain (50%) upon conversion or settlement.

The Company has reflected its future income tax liability net of future tax assets on the balance sheet. As at December 31, 2010, the Company had noncapital losses totalling $301.0 million (2009 – $40.1 million), which expire between 2011 and 2030. The Company expects to use a portion of these losses to shelter partnership income that is taxable in 2011.

2010 Annual Report 61

Notes

Note 10 – Share Capital Authorized The authorized capital of PetroBakken consists of an unlimited number of PetroBakken Class A Shares without nominal or par value, an unlimited number of Class B Shares without nominal or par value and an unlimited number of Preferred Shares without nominal or par value. Class B Shares hold equal voting rights as Class A Shares and are convertible into Class A Shares on a one for one basis at no extra cost.

Normal course issuer bid Pursuant to the Company’s Normal Course Issuer Bid (“NCIB”), as approved by the Toronto Stock Exchange (“TSX”) on May 17, 2010, the Company is authorized to purchase up to 9,431,255 common shares, subject to daily trading restrictions, representing approximately 5% of the issued and outstanding common shares at the date of implementation of the NCIB. The Company is authorized to make purchases during the period of May 17, 2010 to May 18, 2011, or until such earlier time as the NCIB is completed or terminated at the option of the Company. Any common shares PetroBakken purchases under the NCIB will be purchased on the open market through the facilities of the TSX or other exchanges at the prevailing market price at the time of the transaction. Common shares acquired under the NCIB are cancelled. A copy of the notice filed by PetroBakken with the TSX can be obtained by shareholders at no charge by contacting PetroBakken. During the year ended December 31, 2010, the Company repurchased and cancelled a total of 1,680,400 PetroBakken common shares under the NCIB, at an average cost of $21.68 per share. Of the $36.4 million paid, $28.2 million reduced the book value of the common shares and the remaining $8.2 million has been recorded as a reduction to retained earnings. Common Shares Class A Common Share Continuity Balance at December 31, 2008 Additional net investment by Petrobank Issued upon acquisition of TriStar (Note 5) Issued in lieu of cash for acquisition costs (Note 5) Balance at December 31, 2009

Number 94,835,642

Amount $

11,004

61,762,500 293,798 156,891,940

481,629 1,804,933 8,585 $ 2,306,151

Number 14,964,358

Amount $ 410,947

Total of Class A and Class B Common Shares Balance at December 31, 2009

Number 171,856,298

Amount $ 2,717,098

Class A Common Share Continuity Balance at December 31, 2009 Issued upon acquisition of Rondo (Note 5) Issued upon acquisition of Result (Note 5) Exercise of incentive shares and deferred common shares Repurchase of common shares Transfer from contributed surplus related to incentive shares and deferred common shares exercised Balance at December 31, 2010

Number Amount 156,891,940 $ 2,306,151 5,524,471 150,266 11,232,904 303,288 207,146 10 (1,680,400) (28,241) 4,817 172,176,061 $ 2,736,291

Class B Common Share Continuity Balance at December 31, 2008 and 2009

Class B Common Share Continuity Balance at December 31, 2009 and 2010

Number 14,964,358

Amount $ 410,947

Total of Class A and Class B Common Shares Balance at December 31, 2010

Number 187,140,419

Amount $ 3,147,238

62 PetroBakken Energy Ltd.

Notes

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

Amount 6,191 $ 6,191 22,888 (4,817) $ 24,262 $

Stock Options Options granted under the stock option plan have an exercise price that 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 the 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 the grant. The following is a continuity of stock options outstanding: 2010

Opening

Stock Options 4,161,500

2009

Weighted Average Exercise Price $ 34.15

Stock Options -

Weighted Average Exercise Price $ -

Granted

3,495,495

23.66

4,466,000

34.18

Forfeited Closing

(1,626,712) 6,030,283 $

32.24 25.15

(304,500) 4,161,500 $

34.54 34.15

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

Range of Exercise Prices 18.83 – 23.00 23.01 – 23.50 23.51 – 34.54

Number 813,800 3,823,733 1,392,750 6,030,283

Weighted Average Remaining Contractual Life (years) 4.9 5.1 8.1 5.8

Weighted Average Exercise Price $ 20.52 23.12 33.39 $ 25.15

As at December 31, 2010, there were 277,750 stock options exercisable into Class A common shares at a weighted average exercise price of $34.48 per share. In September 2010, the Company modified the terms of certain non-executive stock options that resulted in the exercise price on 2,275,688 options being reduced from a weighted average of $32.47 to $23.12 with a new four year vesting period and five year expiry, and the forfeiture of 758,563 options with a weighted average exercise price of $32.47. The incremental fair value attributed to the modification is recorded as stock-based compensation over the vesting period of the modified options.

Incentive Shares The incentive plan allows holder to received one common share upon payment of $0.05 per share. Incentive share terms are determined by the Company’s Board of Directors but typically, incentive shares vest evenly over a period of four years from the date of grant and expire between five and 10 years from the date of grant. Up to 4.0 million incentive shares have been approved for issuance under the plan. The following is a continuity of incentive shares outstanding:

Opening Granted Exercised Forfeited Closing

2010 1,971,384 784,291 (206,419) (390,046) 2,159,210

2009 2,082,656 (111,272) 1,971,384

As at December 31, 2010, there were 551,492 incentive shares exercisable into Class A common shares at $0.05 per share. The remaining incentive shares vest over four years. 2010 Annual Report 63

Notes

Deferred Common Shares The deferred common shares were granted to certain directors. The holders of the deferred common shares are entitled to receive one common share upon payment of $0.05 per share. The deferred common shares vest after three year or immediately upon resignation or retirement, and expire 10 years from the date of grant. Up to 1.0 million deferred common shares have been approved for issuance under the plan. The following is a continuity of deferred common shares outstanding:

Opening Granted Exercised Closing

2010 1,751 41,112 (727) 42,136

2009 1,751 1,751

Holders of deferred common shares are entitled to receive one Class A common share upon payment of $0.05 per share.

Stock-Based Compensation The fair value of PetroBakken incentive shares, 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, Risk free interest rate Annual dividend per share Expected life – incentive shares (years) Expected life – stock options (years) Expected life – deferred common shares (years) Average fair value at grant date – incentive shares Average fair value at grant date – options Average fair value at grant date – deferred common shares Expected volatility

2010 2.25% $0.96 3.75 3.75 8.0 $23.51 $5.37 $19.97 25% - 28%

2009 2.25% $0.96 0.75 – 3.75 3.75 8.0 $31.52 $5.63 $27.61 25%

Stock-based compensation expense for the year ended December 31, 2010 totalled $22.9 million (2009 - $18.7 million).

Earnings Per Share The following table summarizes the weighted average number of common shares (Class A and Class B) used in calculating basic and diluted earnings per share. No net income adjustments were required. Years ended December 31, Weighted average common shares outstanding, basic Effect of: Incentive shares Deferred common shares Weighted average common shares outstanding, diluted

2010 184,343,194

2009 125,441,588

650,866 42,049 185,036,109

365,657 1,749 125,808,994

In determination of the weighted average number of diluted common shares outstanding for the year ended December 31, 2010, a total of 6,030,283 stock options were excluded because the effect would be anti-dilutive. The 19,638,649 common shares that could be issued upon conversion of the debenture were also considered anti-dilutive and were excluded from the weighted average number of diluted shares for the year ended December 31, 2010.

Note 11 – 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. The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying assets. The Company considers its capital structure to include common share capital, bank debt outstanding, convertible debentures and working capital. In order to maintain or adjust the capital structure, from time to time the Company may issue common shares, debt or other securities, sell assets or adjust capital spending to manage current and projected debt levels.

64 PetroBakken Energy Ltd.

Notes

As at December 31, Working capital deficit Bank debt - principal Convertible debentures – principal amount (US$) Common share capital Credit facility Available credit capacity

2010 $ 193,590 829,788 750,000 3,147,238 1,200,000 $ 370,212

2009 $ 156,976 755,727 2,717,098 900,000 $ 144,273

The Company 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 bank 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 bank debt to annualized earnings before interest, taxes and non-cash items as a key indicator of the Company’s leverage and to monitor the strength of the balance sheet. In order to facilitate the management of this ratio, the Company prepares annual budgets, which are updated as necessary depending on varying factors including current and forecast commodity prices, changes in capital structure, execution of the Company’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. The Company is in compliance with all covenants under its credit facility agreement. The credit facility has financial covenants that limit the ratio of secured debt (defined as total amount drawn on the credit facility) to earnings before interest, taxes, depreciation and amortization (“EBITDA”) to 3:1, limit the ratio of total debt (defined as total amount drawn on the 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. The Company 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%. The Company 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 12 – 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 objectives, policies and processes for measuring and managing risk. Further quantitative disclosures are included throughout these financial statements. The Board of Directors of PetroBakken have 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 it faces and may utilize financial instruments to mitigate these risks.

Credit Risk A substantial portion of our accounts receivable is with customers and joint-venture participants in the oil and natural gas industry and is 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, the Company’s accounts receivables consisted of $139.7 million (December 31, 2009 – $120.0 million) from oil and natural gas customers and $7.6 million (December 31, 2009 – $6.9 million) of other trade receivables. At December 31, 2010, oil, natural gas and NGL production is being sold to a number of oil and gas marketers. Accounts receivable from oil and natural gas marketers are normally collected 25 days after the month of production. The Company’s policy to mitigate credit 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. 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 material collection issues with its oil and natural gas marketers or joint interest partners. The carrying amount of accounts receivable and cash and cash equivalents represent the Company’s maximum credit exposure. PetroBakken had a $1.9 million allowance for doubtful accounts as at December 31, 2010 (December 31, 2009 – $1.8 million).

2010 Annual Report 65

Notes

PetroBakken’s accounts receivables are aged as follows: 2010 $ 142,580 4,759 $ 147,339

As at December 31, Not past due Past due Total

2009 $ 123,425 3,474 $ 126,899

Liquidity Risk The Company’s approach to managing liquidity is to ensure 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 a revolving credit facility, as outlined in Note 6, which 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. The following are the contractual maturities of financial liabilities at December 31, 2010: Financial Liability Accounts payable and accrued liabilities Risk management liabilities Bank debt – principal Convertible debentures – principal (US$) Total(1)

< 1 Year $ 344,476 12,682 $ 357,158

1-3 Years 2,597 829,788 -

Thereafter $ 750,000

Total $ 344,476 15,279 829,788 750,000

$ 832,385

$ 745,950

$ 1,935,493

(1) 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 uses derivative instruments to manage market risk. The Board of Directors of PetroBakken has approved a hedging policy and periodically reviews the results of all risk management activities and all outstanding positions.

Foreign Currency Risk The Company is exposed to fluctuations in the exchange rate between the Canadian dollar and the US dollar. Crude oil, and to a certain extent, natural gas prices are based upon reference prices denominated in US dollars, while the majority of the Company’s expenses are denominated in Canadian dollars. The Company also has a convertible debenture with semi-annual interest payments based in US dollars. When appropriate, the Company may enter into agreements to fix the exchange rate of Canadian dollars to US dollars in order to manage exchange rate risks. The Company had no forward exchange rate contracts in place as at December 31, 2010. At December 31, 2010, if the Canadian dollar had depreciated five percent against the United States dollar with all other variables held constant, net income would have been $24.7 million lower for the year ended December 31, 2010 (2009 – $0.2 million), due to the period end valuation of US 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 facility. Lower commodity prices can also reduce the Company’s ability to raise capital. Crude oil prices are impacted by world economic and political 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. It has been PetroBakken’s policy to only enter into commodity contracts considered appropriate to a maximum of 50% of forecasted production.

66 PetroBakken Energy Ltd.

Notes

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 is a summary of 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 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 that was $24.8 million higher for the year then ended (2009 – $20.6 million). If 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 that was $0.2 million higher for the year then ended (2009 – $0.5 million).

Long-Term Physical Gas Sale Contract The Company 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. The Company 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 due to fluctuations in market interest rates. 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 as 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 would have increased by $2.7 million (2009 – $5.0 million) due to the change in fair value of the interest rate swaps.

2010 Annual Report 67

Notes

Fair Value of Financial Derivative Contracts The following table summarizes the change in 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 (6,488) (8,347) (14,835)

Natural Gas 470 (428) 1,980 2,022

Interest (118) 571 (688) (235)

Total (6,136) (8,204) 1,292 (13,048)

The net risk management asset (liability) consists of current and non-current assets and liabilities. The tables below summarize the components of the net risk management asset (liability) as at December 31, 2010 and 2009:

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

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

Crude Oil

Natural Gas

Interest

December 31, 2010

(12,318)

2,022 -

167 (364)

2,189 (12,682)

(2,517) (14,835)

2,022

42 (80) (235)

42 (2,597) (13,048)

Crude Oil

Natural Gas

Interest

December 31, 2009

(3,046)

470

(118)

(2,694)

(3,442) (6,488)

470

(118)

(3,442) (6,136)

2010 â&#x20AC;&#x192;$

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

â&#x20AC;&#x192;$

(2,925) â&#x20AC;&#x192;$ 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) â&#x20AC;&#x192;$ (17,969)

The unrealized gain (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 during the period.

68 PetroBakken Energy Ltd.

Notes

Fair Value of Financial Instruments The Company’s financial instruments include cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, risk management liabilities, bank debt, convertible debentures and obligations under the gas sale contract 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: Financial Instrument Accounts receivable Accounts payable and accrued liabilities Risk management liability (net) Bank debt Convertible debentures Obligations under gas sale contract

Carrying Value 147,339 344,476 13,048 824,845 567,140 1,516

Fair Value 147,339 344,476 13,048 829,788 729,375 (7) (2,559)(6)

Gain/ (Loss) (8,426)(1) - 17,362 (4) -

Interest Expense 27,513 (2) 48,051 (5) -

Revenue 827 (7)

(1) Included in loss on risk management contracts on the statement of operations, comprehensive income, and retained earnings. The unrealized loss of $8.2 million is included on the statement of cash flow. (2) Included in interest expense on the statement of operations and retained earnings. The effective yield on bank debt at December 31, 2010 was 3.5% (December 31, 2009 – 3.6%). (3) The fair value of the convertible debentures is estimated based on market transactions close to December 31, 2010. (4) Included in foreign exchange gain on the statement of operations, comprehensive income, and retained earnings. The unrealized gain of $35.5 million is included on the statement of cash flow. (5) Included in interest expense on the statement of operations, comprehensive income, and retained earnings. Accretion of $25.5 million is included on the statement of cash flow. The effective yield on the convertible debenture is 9.0%. (6) 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. (7) Included in oil and natural gas revenues on the statement of operations, comprehensive income, and retained earnings. The amortization of obligations under gas sale contract is included on the statement of cash flow.

The Company classifies the fair value of risk management contracts according to the following hierarchy based on the amount of observable inputs used to value the instrument: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy level. The 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 bears interest at a floating rate and accordingly fair value approximates the carrying amount.

2010 Annual Report 69

Notes

Note 13 – Changes in Non-Cash Working Capital 2010

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

2009

$ (20,440) $ (81,795) 5,571 (13,521) 21,222 150,359 2,036 1,618 8,389 56,661 (36,202) (83,625) $ (27,813) $ (26,964)

Working capital acquired (Note 5) Changes relating to: Attributable to operating activities Attributable to financing activities Attributable to investing activities

$ (84,661) $ (6,876) $ (628) $ 16,143 $ 57,476 $ (36,231)

Note 14 – 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 Office leases Drilling and completion rigs Total

2011 $4,834 8,605 $13,439

2012 $5,345 9,003 $14,348

2013 $7,037 8,698 $15,735

2014 $7,063 6,902 $13,965

2015 $6,681 $6,681

Thereafter $25,852 $25,852

Total $56,812 33,208 $90,020

Subsequent to December 31, 2010 the Company 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.

Note 15 – Related Party Transactions The Company is party to a management services agreement with Petrobank Energy and Resources Ltd. (“Petrobank”) providing for certain executive functions as well as other services, including administration, financial, treasury, accounting, information technology, human resources support and office space for PetroBakken employees. The fee is based on a negotiated value for services provided. Amounts paid to Petrobank under this agreement totalled $2.5 million for the year ended December 31, 2010 (2009 – $0.8 million) and were recorded as general and administrative expense.

70 PetroBakken Energy Ltd.

Corporate Information Directors

Head Office

Ian Brown(1) Calgary, Alberta

PetroBakken Energy Ltd. Fifth Avenue Place, East Tower 800, 425 – 1 Street S.W. Calgary, Alberta T2P 3L8

Martin Hislop(1) Calgary, Alberta Craig Lothian(2) (3) Regina, Saskatchewan Kenneth McKinnon(1) (3) Calgary, Alberta Corey C. Ruttan Calgary, Alberta Dan Themig(2) Calgary, Alberta John D. Wright(2) Calgary, Alberta (1) Member of the Audit Committee (2) Member of the Reserves Committee (3) Member of the Compensation Committee

Officers John D. Wright Chairman and Chief Executive Officer R. Gregg Smith President and Chief Operating Officer Mary Bulmer Vice President, Corporate Services

Tel: (403) 268-7800 Fax: (403) 268-7808 Website www.petrobakken.com Email: ir@petrobakken.com

Registrar And Transfer Agents Olympia Trust Company 2300, 125 - 9 Avenue SW Calgary, Alberta T2G 0P6 TEL: (403) 261-0900 FAX: (403) 265-1455

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

Lawrence Fisher Vice President, Land

Sproule Associates Limited Calgary, Alberta, Canada

Andrea Hatzinikolas Corporate Secretary

Exchange Listing

Peter Hawkes Vice President, Exploration William A. Kanters Vice President, Business Development and Corporate Planning Rene LaPrade Senior Vice President, Operations Doreen Scheidt Controller

The Toronto Stock Exchange SYMBOL: PBN

Securities Filings www.sedar.com Information requests and other investor relations inquiries can be directed to ir@petrobakken.com or by telephone at (403) 268-7800. Additional corporate information can be obtained through PetroBakken’s website at www.petrobakken.com

1P 2P bbl/day bbl(s) bcf boe bopd boepd GJ km mbbl

proved proved + probable barrels per day barrel(s) billion cubic feet barrel of oil equivalent barrels of oil per day barrels of oil equivalent per day gigajoules kilometres thousand barrels

Certain statements contained in this Annual Report constitute forward-looking statements. In particular, this Annual Report may contain forward-looking statements pertaining to the following: the performance characteristics of the Company’s oil and gas properties; oil and gas production levels; the size of the oil and gas reserves; projections of market prices and costs; supply and demand for oil and gas; treatment under governmental regulatory regimes and tax laws; future exploration and development activities and capital expenditure budgets; enhanced oil recovery projects and anticipated results therefrom; future drilling locations, anticipated recovery factors and the success of new completion methods. With respect to forward looking statements contained in this Annual Report, the Company has made assumptions regarding: oil and gas production levels; the performance of our wells and EOR projects; commodity prices; general economic and financial market conditions; availability of labour and drilling equipment and access to drilling locations; timing and amount of capital expenditures; government regulation in the areas of taxation, royalty rates and environmental protection; and the obtaining of necessary regulatory approvals. The actual results could differ materially from those anticipated in these forward-looking statements as a result of the following risk factors and those risk factors set forth elsewhere in this Annual Report: volatility in market prices for oil and gas; fluctuation in foreign currency exchange rates; financial resources of the Company; risks inherent in oil and gas operations (including operational risks, environmental risks, delays or changes of plans in respect of exploration and development activities and access to equipment, personnel and drilling locations); uncertainties associated with estimating oil and gas reserves; competition for, among other things, capital, acquisitions of reserves and undeveloped lands; geological, technical, drilling and processing problems; changes in legislation, including changes in environmental or tax laws and government incentive programs relating to the oil and gas industry; and the other factors discussed under the heading “Risk Factors” in the Company’s annual information form. Statements relating to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this Annual Report are expressly qualified by this cautionary statement. Further, any forward-looking statement is made only as of a certain date, and the Company undertakes no obligation to update any forwardlooking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events, except as may be required by applicable securities laws. New factors emerge from time to time, and it is not possible for management of the Company to predict all of these factors and to assess in advance the impact of each such factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.

Barrels Of Oil Equivalent

Disclosure provided herein in respect of barrels of oil equivalent (boe) 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.

Annual General Meeting

Peter D. Scott Senior Vice President and Chief Financial Officer

Abbreviations

Forward-Looking Statements

The annual general meeting of shareholders of PetroBakken Energy Ltd. will be held on Wednesday, May 25, 2011, at 9:00 a.m. (MST) (11:00 a.m. EST) in the Main Floor Ballroom at the Metropolitan Centre, 333 – 4th Avenue S.W., Calgary, Alberta.

mboe mcf mmcf mcfpd mmcfpd NPV NGL section Sproule WI WTI

thousand barrels of oil equivalent thousand cubic feet million cubic feet mcf per day million cubic feet per day net present value natural gas liquids 640 acres or one square mile Sproule Associates Limited working interest West Texas Intermediate

innovation expertise resources

The

Impact of Repeatability

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