Tourmaline Oil Corp. Annual Report 2011

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FY2011 Annual Report · Tourmaline Oil Corp.

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ANNUAL INFORMATION FORM

FOR THE YEAR ENDED

DECEMBER 31, 2011

March 26, 2012

TABLE OF CONTENTS

Page

CONVENTIONS ........................................................................................................................................................... 1
CORPORATE STRUCTURE ....................................................................................................................................... 1
DESCRIPTION OF THE BUSINESS ........................................................................................................................... 1
DESCRIPTION OF CORE LONG-TERM GROWTH AREAS ................................................................................... 5
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION .......................................... 7
OTHER BUSINESS INFORMATION ....................................................................................................................... 18
DIVIDENDS ............................................................................................................................................................... 19
DESCRIPTION OF CAPITAL STRUCTURE ........................................................................................................... 20
MARKET FOR SECURITIES .................................................................................................................................... 21
ESCROWED SECURITIES AND SECURITIES SUBJECT TO CONTRACTUAL RESTRICTION ON
TRANSFER ................................................................................................................................................................. 21
DIRECTORS AND OFFICERS .................................................................................................................................. 21
LEGAL PROCEEDINGS AND REGULATORY ACTIONS .................................................................................... 24
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS ........................................... 24
AUDITOR, TRANSFER AGENT AND REGISTRAR .............................................................................................. 24
MATERIAL CONTRACTS ........................................................................................................................................ 25
INTERESTS OF EXPERTS ........................................................................................................................................ 25
INDUSTRY CONDITIONS ........................................................................................................................................ 25
RISK FACTORS ......................................................................................................................................................... 34
AUDIT COMMITTEE INFORMATION ................................................................................................................... 45
ADDITIONAL INFORMATION ............................................................................................................................... 45
SELECTED ABBREVIATIONS ................................................................................................................................ 45
SELECTED CONVERSIONS .................................................................................................................................... 46
FORWARD-LOOKING STATEMENTS ................................................................................................................... 46
CERTAIN RESERVES DATA INFORMATION ...................................................................................................... 49

SCHEDULES

SCHEDULE "A" – GLJ PETROLEUM CONSULTANTS LTD. FORM 51-101F2 REPORT ON RESERVES

SCHEDULE "B" – AJM DELOITTE FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT

DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

QUALIFIED RESERVES EVALUATOR OR AUDITOR

SCHEDULE "C" – REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE
SCHEDULE "D" – AUDIT COMMITTEE MANDATE AND AUDIT COMMITTEE DISCLOSURE

CONVENTIONS

Unless otherwise indicated, any reference in this Annual Information Form to "Tourmaline" or the
"Company" means Tourmaline Oil Corp. Certain other terms used but not defined herein are defined in National
Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and in the Canadian Oil and
Gas Evaluation Handbook Volume I (the "COGE Handbook"). Unless otherwise specified, information in this
Annual Information Form is as at the end of the Company's most recently completed financial year, being
December 31, 2011. All dollar amounts herein are in Canadian dollars, unless otherwise stated. See "Selected
Abbreviations", "Selected Conversions", "Forward-Looking Statements" and "Certain Reserves Data Information".

Name, address and incorporation

CORPORATE STRUCTURE

Tourmaline Oil Corp. was incorporated under the Business Corporations Act (Alberta) (the "ABCA")
under the name "1415065 Alberta Ltd." on July 21, 2008. On August 26, 2008, Tourmaline filed Articles of
Amendment to change its name to "Tourmaline Oil Corp.". On October 24, 2008, Tourmaline filed Articles of
Amendment to: (i) create a new class of shares designated as first preferred shares (the "First Preferred Shares"),
issuable in series, and a new class of shares designated as second preferred shares (the "Second Preferred Shares"),
issuable in series, and amend the terms of the common shares (the "Common Shares"); (ii) remove the "private
company" restrictions; and (iii) change the minimum number of directors of the Company from one to three.
Tourmaline amalgamated with its wholly-owned subsidiaries Pienza Petroleum Inc. ("Pienza") and Vigilant
Exploration Inc. ("Vigilant") on January 1, 2010, amalgamated with its wholly-owned subsidiary Altia Energy Ltd.
("Altia") on January 1, 2011 and amalgamated with its wholly-owned subsidiary Cinch Energy Corp. ("Cinch") on
January 1, 2012, in each case continuing as Tourmaline Oil Corp.

Tourmaline's head office is located at Suite 3700, 250 – 6th Avenue S.W., Calgary, Alberta T2P 3H7 and

its registered office is located at Suite 2400, 525 – 8th Avenue S.W., Calgary, Alberta T2P 1G1.

Intercorporate relationships

The following diagram illustrates the intercorporate relationship between Tourmaline and its material
subsidiary, the percentage of votes attached to all voting securities of the subsidiary beneficially owned, or
controlled or directed, directly or indirectly, by Tourmaline and the jurisdiction of incorporation of the subsidiary.

Tourmaline Oil Corp.
(Alberta)

90.6%

Exshaw Oil Corp.
(Alberta)

Overview

DESCRIPTION OF THE BUSINESS

Tourmaline is a Canadian intermediate crude oil and natural gas exploration and production company
focused on long-term growth through an aggressive exploration, development, production and acquisition program
in the Western Canadian Sedimentary Basin ("WCSB"). Tourmaline commenced active operations in the fall of
2008 with the objective of building a successful Canadian intermediate crude oil and natural gas exploration,

development and production company with a long-term business strategy similar to that of Duvernay Oil Corp.
("Duvernay") and Berkley Petroleum Corp. ("Berkley"), companies previously founded and managed by certain
key members of Tourmaline's senior management team. Through a series of strategic acquisitions, farm-ins and land
acquisitions combined with its active capital exploration and development program, Tourmaline has increased
current production to the 52,000 – 53,000 Boe/d range. The Company has assembled an extensive undeveloped land
position with a large, multi-year drilling inventory and operating control of important natural gas processing and
transportation infrastructure in two core long-term growth areas – the Alberta Deep Basin and the Greater Peace
River High.

To date, the Company has raised approximately $1.6 billion through private placement equity financings
and public offerings, approximately $354 million of which was raised from Tourmaline's directors, officers,
employees and their associates, and strategically completed 22 acquisitions to cost-effectively build its current
production and extensive land position. The acquisitions have complemented an aggressive exploration,
development and production program that is intended to be the Company's primary long-term growth engine.

Management believes that the location, size, concentration and other attributes of the Company's two core
long-term growth areas provide an opportunity for the Company to achieve operating cost, reserve recovery,
deliverability and production efficiencies through a large-scale, repeatable capital exploration and development
program. Tourmaline is aggressively executing this program using principally 3D seismic data to identify drilling
locations for multi-stage fracture stimulations of vertical and horizontal wells. A key component of Tourmaline's
long-term business strategy has always been to be one of the lowest cost operators within its core areas. In
Tourmaline's view, striving to be a low cost operator is especially important in the current natural gas price
environment.

Business Strategy

Tourmaline's long-term business strategy is to increase shareholder value by building an extensive asset
base over two to three core exploration and production areas and exploiting and developing these areas to increase
reserves, production and cash flows at an attractive return on invested capital. The Company seeks to execute this
strategy by: aggressively drilling and developing its extensive undeveloped land position; adopting and employing
advanced drilling and completion techniques; enhancing returns by focusing on operational and cost efficiencies;
pursuing strategic acquisitions with significant potential synergies; and undertaking wildcat exploration drilling for
new pool discoveries.

General Development of the Business

2009

During the first half of 2009, Tourmaline took advantage of a relatively weak natural gas price environment
and its strong balance sheet to complete a series of asset acquisitions in the Alberta Deep Basin. Management
believes that the acquired assets have considerable additional reserve and production potential and the Company
developed a parallel long-term plan to enhance and control the associated natural gas infrastructure facilities. Eight
such asset transactions were completed during 2009, providing Tourmaline with a strong production base and an
extensive inventory of future potential drilling locations. To fund these acquisitions, the Company raised
approximately an additional $348.4 million through two private placement equity financings in 2009.

Tourmaline established a second core exploration and production area in the Greater Peace River High (as
defined herein) area of Alberta and north east British Columbia ("NEBC") during the second half of 2009 and early
2010 through the Pienza, Exshaw Oil Corp. ("Exshaw"), Vigilant and Altia acquisitions. Pienza, Exshaw and
Vigilant were acquired in 2009 and Altia was acquired in early 2010. These transactions allowed Tourmaline to
establish a strong position in the Montney play area, another play area where Tourmaline's management and
technical staff have had extensive technical experience and have had historical success. Within the Greater Peace
River High, Tourmaline has also assembled a large land position and drilling location inventory in the Sunrise-
Dawson area of NEBC, which is considered by management to be the optimum Montney play area in the entire
NEBC Montney trend. To complement these acquisitions, Tourmaline also entered into a joint venture with a

Canadian intermediate producer in the Elmworth area of Alberta, another attractive developing Montney play area
within the Greater Peace River High.

The third main component of the Company's Greater Peace River High core exploration and production
area is the Spirit River area of Alberta. This area, acquired pursuant to the Exshaw acquisition, features crude oil and
natural gas accumulations in 10 separate horizons, all of which have attractive future development inventories. The
main pool, the Charlie Lake formation, has up to 40 vertical and 50 horizontal drilling locations, which are included
in the Company's drilling location inventory.

2010

Tourmaline completed a private placement equity financing in March of 2010, raising approximately $224
million. This financing provided the Company with the funds required to pursue additional, sizeable asset
acquisitions that were available for sale during the first half of 2010.

In June 2010, Tourmaline completed an acquisition of crude oil and natural gas assets in the Alberta Deep
Basin. Pursuant to this acquisition, Tourmaline acquired from a senior Canadian producer approximately 4,000
Boe/d of production and 462 gross (356 net) sections of developed and undeveloped lands in the Alberta Deep
Basin. This acquisition consolidated the Company's position as one of the largest producers and land and drilling
inventory holders in the entire Alberta Deep Basin.

In August 2010, Tourmaline completed a private placement equity financing of "flow-through" Common

Shares for aggregate proceeds of $25.3 million.

On November 1, 2010, Tourmaline acquired additional petroleum and natural gas properties and related

assets in the Alberta Deep Basin for a cash purchase price of approximately $50.4 million.

In November and December of 2010, Tourmaline completed its initial public offering and a concurrent

private placement raising approximately $259.3 million.

2011

On March 8, 2011, Tourmaline completed a private placement of 1,580,000 "flow-through" Common

Shares at a price of $30.00 per share for aggregate proceeds of approximately $47.4 million.

On May 17, 2011, Tourmaline completed a public offering of 6,325,000 Common Shares and a concurrent
private placement of 500,000 Common Shares at a price of $25.50 per share for aggregate proceeds of
approximately $174.0 million.

On July 12, 2011, Tourmaline acquired all of the outstanding shares of Cinch in consideration for the

issuance of 6,363,523 Common Shares.

In October, 2011, Tourmaline completed a public offering of 4,600,000 Common Shares and a concurrent
private placement of 300,000 Common Shares at a price of $33.00 per share for aggregate proceeds of
approximately $161.7 million.

On December 1, 2011, Tourmaline completed a public offering of 1,200,000 "flow-through" Common
Shares and a concurrent private placement of 161,500 "flow-through" Common Shares at a price of $41.00 per share
for aggregate proceeds of approximately $55.8 million.

Recent Developments

The Company entered 2012 operating a fleet of nine drilling rigs which was reduced to six by early March
and no rigs will be active during the second quarter spring break-up period. During the third and fourth quarter of

2012, the Company plans on operating a total of six drilling rigs: four in the Alberta Deep Basin; one in NEBC; and
one at Spirit River.

During the December 2011 and January 2012 timeframe, Tourmaline constructed a new 25 mmcfpd gas
processing facility at Musreau in the Alberta Deep Basin and expanded the existing gas plant at Sunrise in NEBC
from 35 mmcfpd to 75 mmcfpd.

On March 14, 2012, Tourmaline announced a private placement financing of up to 1,390,000 "flow-
through" Common Shares at a price of $28.80 per share for aggregate gross proceeds of up to $40,032,000. This
private placement is expected to close on or about April 4, 2012.

Potential Acquisitions and Financings

Tourmaline continues to evaluate potential acquisitions of all types of petroleum and natural gas and other
energy-related assets and/or companies as part of its ongoing acquisition program. Tourmaline is regularly in the
process of evaluating several potential acquisitions at any one time, which individually or together could be
material. As of the date hereof, Tourmaline has not reached agreement on the price or terms of any potential material
acquisition. Tourmaline cannot predict whether any current or future opportunities will result in one or more
acquisitions for Tourmaline. In addition, Tourmaline may, in the future, complete financings of equity or debt
(which may be convertible into equity) for purposes that may include financing of acquisitions, Tourmaline's
operations and capital expenditures and repayment of indebtedness.

Acquisition Summary

The Company did not complete any significant acquisitions during its most recently completed financial

year for which disclosure is required under Part 8 of National Instrument 51-102.

The following table summarizes the Company's key acquisitions since inception.

Acquisition Summary

Date

Acquisition

Areas

April 30, 2009 .............. Alberta Deep Basin acquisition
August 28, 2009 ........... Wild River acquisition
September 15, 2009 ...... Pienza acquisition(3)
November 10, 2009 ...... Exshaw acquisition
November 10, 2009 ...... Vigilant acquisition(3)
January 14, 2010 .......... Altia acquisition(4)
June 1, 2010 .................. Greater Hinton acquisition
July 12, 2011 ................ Cinch acquisition(5)

Hinton/Musreau/ Narraway
Wild River/ Harley/ Olsen/Sundance
Sunrise NEBC
Peace River Arch
Musreau/Chime/ Whitecourt
Dawson NEBC
Greater Hinton
Dawson/Musreau-Kakwa

Purchase
Price
(MM$)(1)
$103.0
$145.9
$50.0
$131.8
$47.5
$100.8
$275.0
$211.1
$1,065.1

Production(2)
(Boe/d)

2,350
2,550
350
2,510
650
1,500
4,000
3,700
17,610

Undeveloped Land
Gross
Acres
86,072
44,196
23,348
56,960
92,734
122,600
266,849
134,274
827,033

Net
Acres
27,466
24,016
15,980
41,718
88,538
56,980
204,560
87,580
546,838

Notes:

(1)
(2)
(3)

(4)

(5)

These amounts reflect the purchase price paid in cash and/or Common Shares and associated transaction costs.
Estimated production as at the effective date of the acquisition.
Subsequent to the Pienza and Vigilant acquisitions, Tourmaline amalgamated with Pienza and Vigilant on
January 1, 2010 under the ABCA, continuing as Tourmaline Oil Corp.
Subsequent to the Altia acquisition, Tourmaline amalgamated with Altia on January 1, 2011 under the ABCA,
continuing as Tourmaline Oil Corp.
Subsequent to the Cinch acquisition, Tourmaline amalgamated with Cinch on January 1, 2012 under the ABCA,
continuing as Tourmaline Oil Corp.

Summary of Equity Financings

The following table summarizes the equity financings completed by the Company since commencement of

active operations as well as Company insider, employee and associate participation in such equity financings.

Summary of Equity Financings

Date

Financings

October 27, 2008 ....................
December 17, 2008 .................
May 28, 2009 ..........................
November 10, 2009 ................
March 19, 2010 .......................
August 12, 2010......................
November 23, 2010 ................
March 8, 2011 .........................
May 17, 2011 ..........................
October 12, 2011 ....................
December 1, 2011 ...................

Shares Issued
50,500,000(1)
2,500,000(2)
14,000,000(3)
13,543,624(4)
11,950,000(5)
1,150,000(6)
12,350,000(7)
1,580,000(8)
6,825,000(9)
4,900,000(10)
1,361,500(11)

120,660,124

Total Gross
Proceeds
$301,000,000
$25,000,000
$140,000,000
$208,404,360
$223,920,000
$25,300,000
$259,350,000
$47,400,000
$174,037,500
$161,700,000
$55,821,500
$1,621,933,360

Insider, Employee and
Associate Participation(12)
Gross
Subscriptions
$147,000,000
$12,500,000
$30,000,000
$47,904,360
$36,720,000
$6,600,000
$17,850,000
$11,400,000
$12,750,000
$9,900,000
$6,621,500
$339,245,860

Percentage of
Gross Proceeds
48.8%
50.0%
21.4%
23.0%
16.4%
26.1%
6.9%
24.1%
7.3%
6.1%
11.9%
20.9%

Notes:

(1)

(2)
(3)
(4)

(5)

(6)
(7)

(8)
(9)

(10)

(11)

(12)

Private placement of 15,000,000 Common Shares at $3.50 per share and 35,500,000 Common Shares at $7.00 per
share.
Private placement of 2,500,000 flow-through Common Shares at $10.00 per share.
Private placement of 14,000,000 Common Shares at $10.00 per share.
Private placement of 11,793,624 Common Shares at $15.00 per share and 1,750,000 flow-through Common Shares at
$18.00 per share.
Private placement of 9,500,000 Common Shares at $18.00 per share and 2,450,000 flow-through Common Shares at
$21.60 per share.
Private placement of 1,150,000 flow-through Common Shares at $22.00 per share.
Initial public offering of 12,350,000 Common Shares at $21.00 per share which includes the issuance of 1,500,000
Common Shares issued pursuant to the exercise of the underwriters' over-allotment option (completed on
December 23, 2010) and 850,000 Common Shares issued pursuant to a concurrent private placement to certain
executive officers.
Private placement of 1,580,000 flow-through Common Shares at $30.00 per share.
Public offering of 6,825,000 Common Shares at $25.50 per share which includes the issuance of 825,000 Common
Shares issued pursuant to the exercise of the underwriters' over-allotment option and 500,000 Common Shares issued
pursuant to a concurrent private placement to certain executive officers.
Public offering of 4,900,000 Common Shares at $33.00 per share which includes the issuance of 600,000 Common
Shares issued pursuant to the exercise of the underwriters' over-allotment option (completed on October 19, 2011) and
300,000 Common Shares issued pursuant to a concurrent private placement to certain executive officers.
Public offering of 1,361,500 flow-through Common Shares at $41.00 per share which includes 161,500 Common
Shares issued pursuant to a concurrent private placement to certain executive officers.
Represents percentage of insider, employee and associate participation for the total amount raised by the Company,
which has been calculated based on the percentage of Common Shares issued to directors, officers, employees and
other service providers of the Company and certain family, friends and business associates of the foregoing relative to
the total number of Common Shares issued in each financing.

DESCRIPTION OF CORE LONG-TERM GROWTH AREAS

The following is a description of Tourmaline's two core long-term growth areas – an area within the WCSB
approximately 250 km west of Edmonton, Alberta (the "Alberta Deep Basin") and an area within the WCSB
extending from Grande Prairie, Alberta to approximately 30 km southwest of Fort St. John, NEBC (the "Greater
Peace River High").

Alberta Deep Basin Core Area

The Alberta Deep Basin core area is a multi-objective tight natural gas sand play area with up to 15
separate lower Cretaceous tight natural gas sand reservoirs. Tourmaline's target exploration and production area is in
that portion of the Alberta Deep Basin where the entire lower Cretaceous stratigraphic section is gas saturated. The
primary vehicle for accessing these extensive reserves in stacked sandstones is multi-stage fracture stimulation in
horizontal and vertical well-bores. Tourmaline uses 3D seismic data to select the majority of its drilling locations,

and management believes it is an industry leader in adopting and adapting the improving drilling and completion
technologies. The majority of the Company's working interest lands have already received approval for down-
spacing at four vertical wells per section.

Certain formations within the lower Cretaceous stack of tight sand reservoirs in the Alberta Deep Basin are
more amenable to horizontal drilling (including the Cardium, Wilrich, and Fahler-Notikewin Formations).
Accordingly, each section in the Alberta Deep Basin core area are expected to include one or two targeted multi-
phase stimulated horizontal wells in the Company's long-term development plan. Management estimates that up to
3,600 gross horizontal drilling locations exist in the Alberta Deep Basin which are currently being assessed as part
of the ongoing drilling program. These horizontal drilling locations have been included in the Company's drilling
locations inventory. Future evaluation of these "embedded" resource plays is an important component of the 2012
capital exploration and development program, with several horizontal wells planned. When developed, these
embedded resource plays will utilize the natural gas infrastructure being constructed for ongoing development and
downspacing.

The assets acquired pursuant to the Greater Hinton Acquisition in June of 2010 consisted of production of
approximately 4,000 Boe/d, proved plus probable reserves of approximately 30 MMboe and significant working
interests in over 462 sections of land. Management believes the Greater Hinton Acquisition further solidified the
Company as one of the leading natural gas producers in the Alberta Deep Basin.

Tourmaline has ownership interests in six natural gas plants in the Alberta Deep Basin, five of which, the
Wild River 14-20 plant (70% owned), the Hinton 6-32 gas plant (100% owned), the Minehead 15-12 plant (100%
owned), the Anderson 1-9 plant (100% owned) and the Musreau 8-13 plant (100% owned), are operated by
Tourmaline. In addition, Tourmaline owns and operates a substantial compression and dehydration facility at Horse
capable of processing approximately 50 MMcf/d of natural gas. Tourmaline's goal is to be one of the lowest-cost,
most efficient operators in the Alberta Deep Basin, and during the next 12 to 18 months, the Company plans to
optimize and systematically reduce costs of operating the assets acquired in 2009, 2010 and 2011 as well as the new
properties being developed.

Tourmaline has assembled a land portfolio in the Alberta Deep Basin that is over four times larger than that
held by Duvernay at the time of its sale (approximately 1,800 gross sections at an average 75% working interest
compared to approximately 450 gross sections). The Company also has a recompletion inventory of over 100 wells
in the Alberta Deep Basin.

In the Alberta Deep Basin, Tourmaline drilled 29 natural gas wells in 2009, drilled 49 gross natural gas
wells as well as 10 recompletions in 2010 and drilled 52 gross natural gas wells in 2011. Tourmaline's net
production in the Alberta Deep Basin is currently estimated at approximately 36,000 Boe/d with further production
growth anticipated through the balance of the year. The Company estimates that it currently has approximately
5,500 Boe/d awaiting tie-in, all of which was included as proved reserves in the Consolidated Reserve Report (as
defined herein) as proved developed producing, proved developed non-producing or proved undeveloped reserves.
Year-end 2011 proved plus probable reserves were 163.5 MMboe in the Alberta Deep Basin, with approximately
258 drilling locations recognized in the Consolidated Reserve Report.

Greater Peace River High Core Area

Tourmaline has assembled its second core exploration and production area in the Greater Peace River High
where the primary focus is liquids rich natural gas in the Triassic Montney formation. Industry participants have
been pursuing Triassic Montney plays and reservoirs in the WCSB for over four decades. Exploration and
production of the Montney has evolved over time from conventional reservoirs in the south east portion of the play
area in Alberta to unconventional Montney reservoirs in the Peace River Arch area of Alberta and NEBC.
Technological developments, including the drilling of horizontal multi-stage fracture stimulation wells, have
allowed access to the thickest, highest pressured and highest deliverability Montney in the NEBC play area. It is in
this Groundbirch/Sunrise/Dawson area of the Peace River Arch where senior management of Tourmaline gained
extensive experience with Duvernay and where Tourmaline has concentrated its exploration and production
program.

The Company has assembled its large Montney position primarily through the acquisitions completed in
2009, 2010 and 2011. In NEBC, Tourmaline has an inventory of over 300 horizontal Montney development drilling
locations in the Sunrise/Dawson area, making the Company one of the largest participants in this resource play. In
the Greater Peace River High, Tourmaline has drilled 41 Montney multi-stage fracture stimulated horizontal natural
gas wells, 20 Charlie Lake horizontal oil wells and one vertical oil well to date with an additional 13 Montney
horizontal wells planned for the balance of 2012, and an additional 10 Charlie Lake horizontal oil wells in Spirit
River.

Complementing this growing Montney drilling inventory in NEBC is a series of high deliverability/low
operating cost sweet Mississippian Kiskatinaw and Wabamun natural gas pools. Management believes that these
deeper pools also have considerable exploration and production potential and will be the subject of ongoing
exploration and development in 2012 and 2013. In addition, Tourmaline has completed the construction of an
operated natural gas processing facility and gathering system which was expanded during 2011 from 35 mmcfpd to
75 mmcfpd of processing capacity.

In the Alberta portion of the Greater Peace River High area, Tourmaline has secured access to
approximately 80 gross (38.75 net) sections of prospective acreage in the rapidly developing Montney play at
Elmworth through a joint venture with a Canadian intermediate oil and gas company. There are approximately 200
drilling locations on this land block which are included in the Company's drilling inventory. Three Tourmaline-
operated horizontal delineation wells have been drilled to date in advance of a more substantial development drilling
plan. Complementing this Montney project in Alberta is the Company's producing complex at Spirit River, Alberta.
The majority of the production at Spirit River is derived from oil and natural gas-charged reservoirs of the Triassic
Charlie Lake formation. This area, currently producing approximately 4,500 Boe/d, has a large inventory of vertical
and horizontal development drilling prospects in the Charlie Lake formation as well as attractive plays in several
other formations.

Tourmaline's total net production in the Greater Peace River High area is currently estimated at

approximately 16,500 Boe/d and year-end 2011 proved plus probable reserves were 106.3 MMboe.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Date of Statement

The statement of reserves data and other oil and gas information set forth below is dated March 26, 2012

and effective as at December 31, 2011.

Disclosure of Reserves Data

The reserves data set forth below is based upon the report of GLJ Petroleum Consultants Ltd. ("GLJ")
dated effective December 31, 2011, with a preparation date of February 27, 2012 (the "GLJ Reserve Report") and
the report of AJM Deloitte ("AJM") dated effective December 31, 2011, with a preparation date of February 29,
2012 (the "AJM Reserve Report"), which are contained in the consolidated report of GLJ dated effective
December 31, 2011, with a preparation date of February 29, 2012 (the "Consolidated Reserve Report"). The
Consolidated Reserve Report evaluated, as at December 31, 2011, the crude oil, NGL and natural gas reserves of
Tourmaline, its then consolidated subsidiary Cinch and its current consolidated subsidiary Exshaw.

GLJ evaluated in the GLJ Reserve Report approximately 66% of the assigned total proved plus probable
reserves and 63% of the total proved plus probable future net revenue discounted at 10%. AJM evaluated in the
AJM Reserve Report approximately 34% of the assigned total proved plus probable reserves and 37% of the total
proved plus probable future net revenue discounted at 10%. AJM evaluated in the AJM Reserve Report the
Company's Greater Hinton property located in the Alberta Deep Basin and Exshaw's properties, which are located in
the Alberta portion of the Peace River High. AJM incorporated the GLJ forecast price and cost assumptions in their
evaluation. GLJ evaluated in the GLJ Reserve Report the balance of the Company's properties.

GLJ prepared the Consolidated Reserve Report by consolidating the GLJ Reserve Report with the AJM
Reserve Report adjusted to apply certain of GLJ's assumptions and methodologies used in the preparation of the
GLJ Reserve Report to the AJM Reserve Report including GLJ's pricing and cost assumptions. Accordingly, the
consolidated reserves information below varies from the reserve information that would be derived from a simple
arithmetic summation of the GLJ Reserve Report and the AJM Reserve Report. Also due to rounding, certain
columns may not add.

In accordance with NI 51-101, the Consolidated Reserve Report and the AJM Reserve Report include
100% of the reserves and future net revenue attributable to Exshaw's properties, without reduction to reflect the
9.4% third-party minority interest in Exshaw. Accordingly, the reserves data for the Company's consolidated
reserves set forth below, which has been derived from the Consolidated Reserve Report, reflects 100% of Exshaw's
reserves and future net revenue without reduction to reflect the third-party minority interest. Approximately 0.7% of
the assigned total proved plus probable reserves and 1.4% of the total proved plus probable future net revenue
discounted at 10% in the Consolidated Reserve Report is attributable to the 9.4% third-party minority interest in
Exshaw.

The Consolidated Reserve Report has been prepared in accordance with the standards contained in the
COGE Handbook and the reserve definitions contained in NI 51-101 and the COGE Handbook. Additional
information not required by NI 51-101 has been presented to provide continuity and additional information which
Tourmaline believes is important to readers of this Annual Information Form. GLJ and AJM were engaged to
provide evaluations of proved and proved plus probable reserves and no attempt was made to evaluate possible
reserves.

All of the Company's consolidated reserves are in Canada and, more specifically in the provinces of Alberta

and British Columbia.

The applicable Reports on Reserves Data by Independent Qualified Reserves Evaluators in Form 51-101F2
and the Report of Management and Directors on Oil and Gas Disclosure in Form 51-101F3 are attached as
Schedules A through C to this Annual Information Form.

There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL
reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set
forth in this Annual Information Form are estimates only. In general, estimates of economically recoverable oil and
natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and
assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing
and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of
regulation by governmental agencies and future operating costs, all of which may vary materially from actual
results. For those reasons, estimates of the economically recoverable crude oil, NGL and natural gas reserves
attributable to any particular group of properties, classification of such reserves based on risk of recovery and
estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers
at different times, may vary. The Company's actual production, revenues, taxes and development and operating
expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.

The information relating to the Company's crude oil, NGL and natural gas reserves contains forward-
looking statements relating to future net revenues, forecast capital expenditures, future development plans and costs
related thereto, forecast operating costs, anticipated production and abandonment costs. See "Forward-Looking
Statements", "Certain Reserves Data Information", "Industry Conditions" and "Risk Factors – Reserves Estimates".

Reserves and Future Net Revenue Data (Forecast Prices and Costs)

Summary of Crude Oil and Natural Gas Reserves and
Net Present Values of Future Net Revenue
as of December 31, 2011
Forecast Prices and Costs

Reserves Category
Proved Developed Producing ...........................
Proved Developed Non-Producing ..................
Proved Undeveloped ........................................

Total Proved Reserves ......................................
Total Probable Reserves ...................................

Total Proved Plus Probable Reserves ..............

Light and Medium Crude Oil

Natural Gas

NGL

Company
Gross
(Mbbls)
1,931
234
4,089

6,254
4,677
10,931

Company
Net
(Mbbls)
1,470
191
3,073

Company
Gross
(MMcf)
360,389
33,648
388,420

Company
Net
(MMcf)
319,876
30,966
349,229

4,734
3,520
8,254

782,457
633,486
1,415,942

700,071
564,434
1,264,505

Company
Gross
(Mbbls)
5,162
488
6,537

12,186
10,690
22,876

Company
Net
(Mbbls)
3,720
386
5,242

9,348
8,167
17,515

Net Present Values Of Future Net Revenue ($000s)

Reserves Category
Proved Developed Producing .............
Proved Developed Non-Producing .....
Proved Undeveloped ...........................
Total Proved Reserves .......................
Total Probable Reserves ....................
Total Proved Plus Probable
Reserves .............................................

Before Future Income Taxes Discounted at
(%/year)
10
1,006,993
78,416
641,630
1,727,040
970,450

5
1,250,460
98,883
961,361
2,310,704
1,633,903

15
849,891
64,593
447,299
1,361,783
631,785

0
1,671,205
131,552
1,549,295
3,352,052
3,224,956

20
740,408
54,706
319,615
1,114,728
434,588

After Future Income Taxes Discounted at (1)
(%/year)
10
1,006,993
78,416
538,187
1,623,596
711,656

5
1,250,460
98,883
789,516
2,138,859
1,215,375

15
849,891
64,593
381,061
1,295,545
454,605

0
1,671,205
131,552
1,238,692
3,041,449
2,421,553

20
740,408
54,706
275,174
1,070,288
305,237

Unit Value Before
Income Tax
Discounted
at 10%/year

($/Mcfe)
2.87
2.28
1.61
2.20
1.53

($/Boe)
17.21
13.67
9.65
13.21
9.18

6,577,007

3,944,607

2,697,489

1,993,568

1,549,317

5,463,002

3,354,235

2,335,253

1,750,150

1,375,525

1.90

11.40

Note:

(1)

The after-tax net present value of the Company's oil and gas properties reflects the tax burden on the properties on a
stand-alone basis. It does not consider the corporate tax situation, or tax planning. It does not provide an estimate of
the value at the level of the corporation, which may be significantly different. The Company's financial statements and
the management's discussion and analysis should be consulted for information at the level of the corporation.

Total Future Net Revenue ($000s)
(Undiscounted)
as of December 31, 2011
Forecast Prices and Costs

Reserves Category
Proved ............................
Proved Plus Probable .....

Revenue
6,483,299
12,608,442

Royalties
857,999
1,671,663

Operating
Costs
1,410,476
2,745,688

Development
Costs
814,593
1,539,166

Future Net
Revenue
Before
Deducting
Future
Income Tax
Expenses
3,352,052
6,577,007

Future Net
Revenue
After
Future
Income
Tax
Expenses(1)
3,041,449
5,463,002

Future
Income
Tax
Expenses
310,603
1,114,005

Abandonment
and
Reclamation
Costs
48,179
74,919

Note:

(1)

Future Net Revenue
by Production Group
as of December 31, 2011
Forecast Prices and Costs

Reserves Category

Production Group

Proved Reserves

Light and Medium Crude Oil ................................................................

Proved Plus Probable

Natural Gas (including by-products but excluding solution gas) .........
Total ......................................................................................................

Light and Medium Crude Oil ................................................................
Natural Gas (including by-products but excluding solution gas) .........
Total ......................................................................................................

Reconciliation of Changes in Reserves

Future Net
Revenue Before
Income Taxes
(discounted at
10%/year)
($000s)

259,347
1,467,693
1,727,040
410,554
2,286,935
2,697,489

Unit Value
(discounted at
10%/year)

($/Mcfe)

($/Boe)

4.63
2.01
2.20
4.20
1.73
1.90

27.80
12.09
13.21
25.18
10.39
11.40

Reconciliation of Gross Reserves
by Principal Product Type
Forecast Prices and Costs

Light and Medium Crude Oil

Natural Gas

Proved
(Mbbl)
3,870
19
3,025
0
0
(242)
19
0
0
(437)
6,254

Proved
(Mbbl)
7,962
29
3,116
514
44
(783)
2,043
(27)
(1)
(710)
12,186

Probable
(Mbbl)
2,609
40
2,452
0
0
(428)
6
0
0
0
4,677

NGL

Probable
(Mbbl)
5,512
90
4,633
173
8
(765)
1,048
(8)
(0)
0
10,690

Proved
Plus
Probable
(Mbbl)
6,479
58
5,477
0
0
(670)
25
0
0
(437)
10,931

Proved
Plus
Probable
(Mbbl)
13,474
119
7,749
687
51
(1,549)
3,090
(35)
(1)
(710)
22,876

Proved
Plus
Probable
(MMcf)
829,365
2,055
486,161
22,520
3,969
21,923
118,519
(11,762)
(249)
(56,558)
1,415,942

Proved
Plus
Probable
(Mbbl)
158,181
519
94,252
4,440
713
1,435
22,868
(1,995)
(42)
(10,574)
269,797

Probable
(MMcf)
342,272
1,603
258,878
5,395
616
(10,364)
37,891
(2,765)
(41)
0
633,486

BOE

Probable
(Mbbl)
65,166
396
50,230
1,072
111
(2,919)
7,368
(469)
(7)
0
120,948

Proved
(MMcf)
487,093
451
227,283
17,125
3,353
32,286
80,628
(8,998)
(208)
(56,558)
782,457

Proved
(Mbbl)
93,015
123
44,022
3,368
602
4,354
15,500
(1,526)
(35)
(10,574)
148,849

Factors
December 31, 2010 ..............
Discoveries ........................
Extensions ..........................
Infill Drilling ......................
Improved Recovery ...........
Technical Revisions ...........
Acquisitions .......................
Dispositions .......................
Economic Factors ..............
Production ..........................
December 31, 2011 ...............

Factors
December 31, 2010 .............
Discoveries ......................
Extensions ........................
Infill Drilling ....................
Improved Recovery .........
Technical Revisions .........
Acquisitions .....................
Dispositions .....................
Economic Factors ............
Production ........................
December 31, 2011 .............

Notes to Reserves Data Tables:

(1)
(2)

Columns may not add due to rounding.
Tourmaline has no unconventional reserves (bitumen, synthetic crude oil, natural gas from coal or heavy oil).

(3)

The crude oil, NGL and natural gas reserve estimates in this Annual Information Form are based on the definitions and
guidelines contained in the COGE Handbook.

GLJ Reserve Report Pricing Assumptions

Summary of Pricing and Inflation Rate Assumptions
Forecast Prices and Costs (1)

Crude Oil and Natural Gas Liquids Pricing

NYMEX WTI Near
Month Futures
Contract Crude Oil
at Cushing
Oklahoma

Constant
2012
$
$US/Bbl

Then
Current
$US/
Bbl

ICE
BRENT
Near
Month
Futures
Contract
Crude
Oil FOB
North
Sea Then
Current
$Cdn/Bbl

Bow
River
Crude
Oil
Stream
Quality
at
Hardisty
Then
Current
$Cdn/Bbl

Light,
Sweet
Crude Oil
(40 API,
0.3%S) at
Edmonton
Then
Current
$Cdn/Bbl

Bank of
Canada
Average
Noon
Exchange
Rate
$US/$Cdn(3)

Heavy
Crude
Oil
Proxy
(12 API)
at
Hardisty
Then
Current
$Cdn/Bbl

Light
Crude
Oil (35
API,
1.2%S)
at
Cromer
Then
Current
$Cdn/Bbl

Medium
Crude
Oil (29
API,
2.0%S)
at
Cromer
Then
Current
$Cdn/Bbl

WCS
Stream
Quality
at
Hardisty
Then
Current
$Cdn/Bbl

Alberta Natural Gas Liquids
(Then Current Dollars)

Spec
Ethane
$Cdn/Bbl

Edmonton
Propane
$Cdn/Bbl

Edmonton
Butane
$Cdn/Bbl

Edmonton
Pentanes
Plus
$Cdn/Bbl

0.980

97.00

105.00

97.00

105.00

97.00

105.00

97.00

105.00

97.00

105.00

98.04

100.00

105.00

96.12

100.00

102.00

94.23

100.00

92.38

100.00

90.57

100.00

90.00

101.35

90.00

103.38

90.00

105.45

97.96

101.02

102.40

104.47

106.58

90.00

107.56

108.73

83.27

84.35

85.50

87.23

89.00

90.79

81.61

82.63

83.75

85.44

87.16

88.92

72.37

73.60

74.51

75.54

77.09

78.67

80.28

93.06

94.96

93.95

95.23

97.16

99.12

101.12

90.12

92.94

91.93

93.18

95.07

96.99

98.95

10.50

10.98

11.61

12.72

11.46

13.67

15.26

16.85

18.43

20.02

20.84

21.25

21.70

22.14

58.78

60.61

61.44

62.68

63.95

65.24

76.41

78.80

79.87

81.49

83.13

84.81

107.76

108.09

105.06

106.49

108.65

110.84

113.08

90.00 +2.0%/yr

+2.0%/yr

Year

Inflation(2)
%

2012 Q1 .........

2012 Q2 .........

2012 Q3 .........

2012 Q4 .........

2.00

2012 Full Year

2.00

2013 ...............

2014 ...............

2015 ...............

2016 ...............

2017 ...............

2018 ...............

2019 ...............

2020 ...............

2021 ...............

2022+.............

2.00

Henry Hub Nymex
Near Month Contract

Constant
2012 $
$US/
MMbtu

Then Current
$US/MMbtu

Midwest
Price @
Chicago
Then
Current
$US/
MMbtu

AECO/
NIT
Spot
Then
Current
$Cdn/
MMbtu

Spot

Constant
2011 $
$/MMbtu

Then
Current
$MMbtu

Natural Gas and Sulphur Pricing

Alberta Plant Gate

Saskatchewan Plant Gate

British Columbia

ARP $/
MMbtu

Aggregator
$/MMbtu

Alliance
$/MMbtu

SaskEnergy
$/MMbtu

Spot
$MMbtu

Sumas
Spot
$US/
MMbtu

Westcoast
Station 2
$/MMbtu

Spot Plant
Gate
$MMbtu

Sulphur
FOB
Vancouver
$US/LT

Alberta
Sulphur at
Plant Gas
$Cdn/LT

3.50

3.65

3.85

4.20

3.80

4.41

4.81

5.18

5.54

5.89

6.00

3.50

3.65

3.85

4.20

3.80

4.50

5.00

5.50

6.00

6.50

6.76

6.89

7.03

7.17

3.60

3.75

3.95

4.30

3.90

4.60

5.10

5.60

6.10

6.60

6.86

6.99

7.13

7.27

3.21

3.35

3.54

3.86

3.49

4.13

4.59

5.05

5.51

5.97

6.21

6.33

6.46

6.58

3.02

3.16

3.34

3.66

3.29

3.85

4.21

4.56

4.89

5.21

5.32

3.02

3.16

3.34

3.66

3.29

3.93

4.39

4.84

5.30

5.75

5.99

6.11

6.23

6.36

2.96

3.09

3.27

3.58

3.23

3.85

4.30

4.74

5.19

5.64

5.87

5.98

6.11

6.23

2.89

3.02

3.20

3.50

3.15

3.76

4.20

4.64

5.08

5.51

5.74

5.85

5.98

6.10

2.36

2.50

2.70

3.04

2.65

3.33

3.82

4.31

4.80

5.29

5.55

5.67

5.81

5.95

3.06

3.19

3.37

3.68

3.33

3.95

4.40

4.84

5.29

5.74

5.97

6.08

6.21

6.33

3.15

3.29

3.48

3.80

3.43

4.07

4.53

4.99

5.45

5.91

6.15

6.27

6.40

6.52

3.20

3.35

3.55

3.90

3.50

4.20

4.70

5.20

5.70

6.20

6.46

6.59

6.73

6.87

3.01

3.15

3.34

3.66

3.29

3.93

4.39

4.85

5.31

5.77

6.01

6.13

6.26

6.38

2.86

3.00

3.18

3.50

3.14

3.78

4.23

4.69

5.14

5.60

5.84

5.95

6.08

6.21

200.00

161.08

200.00

161.08

200.00

161.08

200.00

161.08

200.00

161.08

175.00

135.57

150.00

110.06

125.00

127.50

130.05

132.65

135.30

138.01

84.55

87.10

89.70

92.36

95.06

97.83

Year

2012 Q1 ......

2012 Q2 ......

2012 Q3 ......

2012 Q4 ......

2012 Full Year

2013 ............

2014 ............

2015 ............

2016 ............

2017 ............

2018 ............

2019 ............

2020 ............

2021 ............

2022+..........

6.00

+2.0%/yr

+2.0%/yr +2.0%/yr

5.32 +2.0%/yr

+2.0%/yr

+2.0%/yr +2.0%/yr

+2.0%/yr

+2.0%/yr +2.0%/yr

Notes:

(1)
(2)
(3)

Pricing assumptions provided by GLJ as used in the GLJ Reserve Report.
Inflation rates used for forecasting prices and costs.
Exchange rates used to generate the benchmark reference prices in this table.

During the year ended December 31, 2011, the Company received the following weighted average prices,
excluding the gains and losses on financial instruments, in respect of its production: natural gas – $3.84/Mcf; NGL –
$76.89/bbl; and oil – $94.45/bbl. The overall weighted average price received by Tourmaline on an oil equivalent
basis was $30.29/Boe.

Additional Information Relating to Reserves Data

The additional information contained in this section pertains to Tourmaline and Exshaw on a
consolidated basis and references to Tourmaline include Exshaw (without reduction to reflect the 9.4% third-
party minority interest in Exshaw). See "Disclosure of Reserves Data".

Undeveloped Reserves

The following tables set forth the proved undeveloped reserves and the probable undeveloped reserves,
each by product type, attributed to Tourmaline's properties as at the end of the financial years ended
December 31, 2011, 2010 and 2009.

Proved Undeveloped Reserves

Light and Medium Crude
Oil
(Mbbls)

First
Attributed(1)
716
2,043
2,809

Total at
Year-end
716
2,711
4,089

Natural Gas
(MMcf)

NGL
(Mbbls)

Boe
Oil Equivalent
(Mbbls)

First
Attributed
74,099
173,291
168,228

Total at
Year-end
74,099
234,358
388,420

First
Attributed
847
3,934
2,753

Total at
Year-end
847
4,801
6,537

First
Attributed
13,913
34,859
33,600

Total at
Year-end
13,913
46,572
75,362

Year
2009 .............
2010 .............
2011 .............

Note:

(1)

"First Attributed" refers to reserves first attributed at year-end of the corresponding fiscal year.

It is anticipated that most of the proved undeveloped locations will be drilled by December 31, 2014.

Probable Undeveloped Reserves

Light and Medium Crude
Oil
(Mbbls)

First
Attributed(1)

1,669
24
2,433

Total at
Year-end
1,669
1,623
3,347

Natural Gas
(MMcf)

NGL
(Mbbls)

Boe
Oil Equivalent
(Mbbls)

First
Attributed
77,937
185,671
309,203

Total at
Year-end
77,937
259,414
506,049

First
Attributed

885
3,228
6,078

Total at
Year-end
885
4,518
8,947

First
Attributed
15,544
34,197
60,044

Total at
Year-end
15,544
49,377
96,635

Year
2009 .............
2010 .............
2011 .............

Note:

(1)

"First Attributed" refers to reserves first attributed at year-end of the corresponding fiscal year.

It is anticipated that most of the future development capital associated with the probable undeveloped

reserves will be incurred by December 31, 2015.

In general, once proved and/or probable undeveloped reserves are identified, they are scheduled into
Tourmaline's development plans. Normally, Tourmaline plans to develop its proved and probable undeveloped
reserves within two years. A number of factors that could result in delayed or cancelled development are as follows:

changing economic conditions (due to pricing, operating and capital expenditure fluctuations); changing technical
conditions (production anomalies such as water breakthrough or accelerated depletion); multi-zone developments
(delay of a prospective formation completion until the initial completion is no longer economic); a larger
development program may need to be spread out over several years to optimize capital allocation and facility
utilization; and surface access issues (landowners, weather conditions and/or regulatory approvals). See "Risk
Factors" and "Industry Conditions".

Significant Factors or Uncertainties

The process of estimating reserves is complex. It requires significant judgments and decisions based on
available geological, geophysical, engineering and economic data. These estimates may change substantially as
additional data from ongoing development activities and production performance becomes available and as
economic conditions impacting oil and gas prices and costs change. The reserves estimates contained in this Annual
Information Form are based on current production forecasts, prices and economic conditions.

As circumstances change and additional data becomes available, reserve estimates also change. Estimates
made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are
often required due to changes in well performance, prices, economic conditions and governmental restrictions.

Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is
an inferential science. As a result, the subjective decisions, new geological or production information and a changing
environment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end oil and
natural gas prices and reservoir performance. Such revisions can be either positive or negative.

Other than as discussed above and the various risks and uncertainties that participants in the oil and natural
gas industry are exposed to generally, Tourmaline is unable to identify any important economic factors or significant
uncertainties that will affect any particular components of the reserves data disclosed in this Annual Information
Form. See "Risk Factors" and "Industry Conditions".

Future Development Costs

The following table sets forth development costs deducted in the estimation of Tourmaline's future net

revenue attributable to the reserve categories noted below ($000s):

Year
2012 ...................
2013 ...................
2014 ...................
2015 ...................
2016 ...................
2017 ....................
Thereafter ...........
Total ...................

Undiscounted Forecast Prices and Costs

Proved Reserves

Proved Plus
Probable Reserves

331,224
202,339
236,258
37,069
7,568
0
135
814,593

487,022
447,891
361,414
179,149
63,555
0
135
1,539,166

Tourmaline expects that the capital listed in the preceding table will be funded through its existing cash

balance, expected cash flow from operations and completed financings.

Other Oil and Natural Gas Information

Crude Oil and Natural Gas Wells

The following table sets forth the number and status of wells in which Tourmaline had a working interest as

at December 31, 2011, that Tourmaline considers capable of production.

Alberta(1) .......................................................
British Columbia(1) .......................................
Total .............................................................

Crude Oil Wells(1)

Natural Gas Wells(1)

Producing

Gross
60
1
61

Net
55.0
0.2
55.2

Non-Producing(2)
Net
Gross
3.1
4
0.0
0
3.1
4

Producing

Gross
449
39
488

Net
308.2
32.7
340.9

Non-Producing(2)
Net
Gross
83.8
119
32.1
45
115.9
164

Notes:

(1)
(2)

(3)

All of Tourmaline's wells are located onshore.
The non-producing oil wells and natural gas wells capable of production but which are not currently producing will be
re-evaluated with respect to future product prices, proximity to facility infrastructure, design of future exploration and
development programs and access to capital,
Includes wells of Exshaw (without reduction to reflect the 9.4% third-party minority interest in Exshaw).

For a general description of Tourmaline's important properties, facilities and installations, see "Description

of Core Long-Term Growth Areas".

Properties with no Attributable Reserves

The following table sets out Tourmaline's developed and undeveloped unproved properties as at

December 31, 2011, in which Tourmaline has an interest.

Alberta .................................................................
British Columbia .................................................
Saskatchewan ......................................................
Total(1) .................................................................

Developed Acres

Gross
296,883
28,741
–
325,624

Net
184,034
17,824
–
201,858

Undeveloped Acres
Net
Gross
857,998
1,065,718
91,768
132,895
65,754
73,737
1,015,520
1,272,350

Total Acres

Gross
1,362,601
161,636
73,737
1,597,974

Net
1,042,032
109,592
65,754
1,217,378

Note:

(1)

Includes developed and undeveloped unproved properties of Exshaw (without reduction to reflect the 9.4% third-party
minority interest in Exshaw).

The following table sets out Tourmaline's developed and undeveloped unproved properties as at March 16,

2012, in which Tourmaline has an interest.

Alberta .................................................................
British Columbia .................................................
Saskatchewan .......................................................
Total(1) ..................................................................

Developed Acres

Undeveloped Acres

Total Acres

Gross
310,470
28,029
–
338,499

Net
191,935
17,353
–
209,288

Gross
1,049,359
123,304
73,737
1,246,400

Net
843,675
86,203
65,754
995,632

Gross
1,359,829
151,333
73,737
1,584,899

Net
1,035,610
103,556
65,754
1,204,920

Note:

(1)

Includes developed and undeveloped unproved properties of Exshaw without reduction to reflect the 9.4% third-party
minority interest in Exshaw).

There are no material work commitments in respect of Tourmaline's unproved properties. Tourmaline
expects that rights to explore, develop and/or exploit up to 56,000 net acres (88 net sections) of its undeveloped land
holdings could expire by December 31, 2012.

Significant Factors or Uncertainties Relevant to Properties With No Attributed Reserves

See "Additional Information Relating to Reserves Data – Significant Factors or Uncertainties" above.

Additional Information Concerning Abandonment and Reclamation Costs

Tourmaline uses its internal historical costs to estimate its abandonment and reclamation costs when
available. The costs are estimated on an area-by-area basis. The industry's historical costs are used when available.
If representative comparisons are not readily available, an estimate is prepared based on the various regulatory
abandonment requirements. As at December 31, 2011, Tourmaline had 575 net wells for which it expects to
eventually incur abandonment and reclamation costs by 2028.

The total abandonment and reclamation costs in respect of proved and probable reserves using forecast
prices are $74.9 million (undiscounted) and $12.0 million (discounted at 10%). One hundred percent of such
amounts were deducted as abandonment and reclamation costs in estimating Tourmaline's future net revenue in
respect of proved and probable reserves as disclosed above.

The following table sets forth abandonment and reclamation costs deducted in the estimation of

Tourmaline's future net revenue:

Forecast Prices and Costs (Total Proved plus Probable) (000s)

Year
2012 ....................................................
2013 ....................................................
2014 ...................................................
Thereafter ..........................................
Total .................................................

Abandonment and
Reclamation Costs
(Undiscounted)

Abandonment and
Reclamation Costs
(Discounted at 10%)

436
405
747
73,330
74,918

415
351
588
10,608
11,962

Tourmaline expects to pay approximately $1.2 million in the next three financial years in respect of its

abandonment and reclamation costs,

Tax Horizon

Tourmaline has no current tax expense and, based on current reserve forecasts, will be able to realize the
benefit of its non-capital losses and expects to remain non-taxable through at least 2014. Tourmaline has
approximately $2,125 million of tax pools available as at December 31, 2011, which can be used to offset taxable
income in future years.

Capital Expenditures

The following table summarizes capital expenditures (including corporate acquisitions and capitalized

general administrative expenses) related to Tourmaline's activities for the year ended December 31, 2011:

Exploration, drilling and completions ..................................................
Development, equipping and facilities .................................................
Property and corporate acquisitions(1)(2) ................................................
Equipment and facilities .......................................................................
Geological and geophysical ...................................................................
Other (including capitalized G&A) .......................................................
Total(3) ...................................................................................................

$000's
471,108
127,751
107,248
99,301
12,864
10,684
828,956

Notes:

(1)

Approximately $61.9 million of the property acquisition expenditures were for proved properties and approximately
$45.4 million of the property acquisition expenditures were for unproved properties.

(2)

(3)

Excludes non-cash corporate acquisition of Cinch which resulted in increased property, plant and equipment of $182.8
million and Exploration and Evaluation assets of $87.1 million.
Includes capital expenditures related to Exshaw (without reduction to reflect the 9.4% third-party minority interest in
Exshaw).

Exploration and Development Activities

The following table sets forth the gross and net exploratory and development wells in which Tourmaline

participated in the year ended December 31, 2011:

Natural Gas .......................
Oil .....................................
Service ..............................
Dry ....................................
Total(1) ..............................

Exploratory Wells
Net
16.3
1.0
–
–
17.3

Gross
17
1
–
–
18

Development Wells

Gross
61
10
–
–
71

Net
45.4
10.0
–
–
55.4

Note:

(1)

Includes wells in which Exshaw participated (without reduction to reflect the 9.4% third-party minority interest in
Exshaw).

See "Description of Core Long-Term Growth Areas" and "Description of the Business" for a description of

Tourmaline's exploration and development plans.

Production Estimates

The following table sets out the volume of Tourmaline's production estimated for the year ended
December 31, 2012 as evaluated by GLJ and AJM, which is reflected in the estimate of future net revenue disclosed
in the tables contained under "Disclosure of Reserves Data" above.

Light and Medium
Crude Oil

Natural Gas

NGL

Oil Equivalent
Total

Company
Gross
(bbl/d)
2,893
3,296

Company
Net
(bbl/d)
2,476
2,817

Company
Gross
(Mcf/d)
266,134
306,759

Company
Net
(Mcf/d)
243,042
280,935

Company
Gross
(bbl/d)
4,152
4,832

Company
Net
(bbl/d)
3,564
4,187

Company
Gross
(bbl/d)
51,400
59,254

Company
Net
(bbl/d)
46,546
53,827

Reserves Category
Proved ...........................................
Proved Plus Probable ...................

Notes:

(1)

(2)
(3)

No one field accounted for 20 percent or more of Tourmaline's estimated 2012 production in the Consolidated Reserve
Report.
Numbers may not add due to rounding.
Includes Exshaw production (without reduction to reflect the 9.4% third-party minority interest in Exshaw).

Production History

The following tables summarize certain information in respect of average production, product prices

received, royalties paid, operating expenses and resulting netback for the periods indicated below:

Quarter Ended
2011(4)

December 31

September 30

June 30

March 31

Average Daily Production(1) ......................................
Light and Medium Crude Oil (Bbl/d) ...............
Natural Gas (Mcf/d) ..........................................
NGL (Bbls/d) .....................................................
Combined (Boe/d) .............................................
Average Price Received ............................................
Light and Medium Crude Oil (S/bbl) ................

3,411
200,403
1,101
37,912

97.88

2,687
185,414
757
34,347

90.02

2,391
151,634
600
28,263

1,714
125,374
698
23,308

97.84

89.32

Quarter Ended
2011(4)

December 31

September 30

June 30

Natural Gas ($/Mcf) ..........................................
NGL ($/bbl) .......................................................
Combined ($/Boe) .............................................
Royalties Paid ............................................................
Light and Medium Crude Oil ($/bbl) ................
Natural Gas ($/Mcf) ..........................................
NGL ($/bbl) .......................................................
Combined ($/Boe) .............................................
Production Costs (includes transportation) ...............
Light and Medium Crude Oil ($/bbl) ................
Natural Gas ($/Mcf) ..........................................
NGL ($/bbl)(2) ....................................................
Combined ($/Boe) .............................................
Netback Received ($/Boe)(3) ....................................

3.76
78.07
30.95

11.24
0.12
17.07
2.15

12.91
1.14
–
7.41
21.39

4.25
76.34
31.67

15.28
0.19
18.16
2.63

15.23
1.20
–
7.83
21.21

4.38
86.21
33.61

12.09
0.01
12.85
1.36

11.67
1.23
–
7.72
24.52

March 31
4.48
67.48
32.68

12.86
0.13
12.80
2.02

14.96
1.18
–
7.67
22.99

Notes:

(1)
(2)

(3)
(4)

Before deduction of royalties.
NGL volumes are derived from natural gas production, as such all the related operating costs are attributed to the
production of natural gas.
Netbacks are calculated by subtracting royalties and operating costs from revenues.
Includes Exshaw (without reduction to reflect the 9.4% third-party minority interest in Exshaw).

The following table sets forth the average daily production volumes for the year ended December 31, 2011

for each of the important fields comprising Tourmaline's assets.

Alberta Deep Basin .................................
Other Alberta properties ..........................
British Columbia properties.....................
Total(1) ....................................................

Note:

Light and Medium
Crude Oil
(Bbls/d)
924
1,216
416
2,556

Natural Gas
(Mcf/d)
121,327
8,538
36,101
165,966

NGL (Bbls/d)

459
14
317
790

Boe (Boe/d)
21,604
2,653
6,750
31,007

(1)

Includes Exshaw (without reduction to reflect the 9.4% third-party minority interest in Exshaw).

For the year ended December 31, 2011, approximately 70% of Tourmaline's gross revenue was derived

from natural gas production and approximately 30% was derived from crude oil and NGL production.

Forward Contracts and Marketing

Other than the following, Tourmaline is not bound by any agreement (including any transportation
agreement), directly or through an aggregator, under which it is precluded from fully realizing, or may be protected
from the full effect of, future market prices for crude oil or natural gas.

The Company's commodity hedging policy has been established with the Board of Directors authorizing
management to hedge up to 50% of current production. For the fourth quarter of 2011, Tourmaline produced 200.4
MMcf/d. In the first quarter of 2012, an average of 10.4 (5%) MMcf/d is sold forward at an average fixed price of
$5.15 per Mcf. For the full year 2012, an average of 7.0 (3%) MMcf/d is sold forward at an average fixed price of
$5.20 per Mcf. In a similar manner, an average of 2.8 (1%) MMcf/d is sold forward at an average fixed price of
$4.72 per Mcf for 2013.

Forward sales of crude oil at fixed prices constitute less than 15% of the Company's fourth quarter 2011 oil

and NGL production.

In addition, Tourmaline's transportation obligations or commitments for future physical deliveries of crude
oil and natural gas do not exceed Tourmaline's expected related future production from its proved reserves,
estimated using forecast prices and costs, as disclosed in this Annual Information Form.

Specialized Skill and Knowledge

OTHER BUSINESS INFORMATION

Tourmaline employs individuals with various professional skills in the course of pursuing its business plan.
These professional skills include, but are not limited to, geology, geophysics, engineering, financial and business
skills, which are widely available in the industry. Drawing on significant experience in the oil and gas business,
Tourmaline believes its management team has a demonstrated track record of bringing together all of the key
components to a successful exploration and production company: strong technical skills; expertise in planning and
financial controls; ability to execute on business development opportunities; capital markets expertise; and an
entrepreneurial spirit that allows Tourmaline to effectively identify, evaluate and execute on value added initiatives.

Competitive Conditions

The oil and natural gas industry is very competitive. The Canadian Association of Petroleum Producers
estimates that there are over 1,000 exploration and production companies in Canada. Tourmaline controls less than
one percent of the business in western Canada, but where it is active (see "Description of Core Long-Term Growth
Areas"), Tourmaline believes it has a strong competitive position.

Companies operating in the petroleum industry must manage risks which are beyond the direct control of
company personnel. Among these risks are those associated with exploration, environmental damage, commodity
prices, foreign exchange rates and interest rates.

The oil and natural gas industry is intensely competitive and Tourmaline competes with a substantial
number of other entities, many of which have greater technical or financial resources. With the maturing nature of
the WCSB, the access to new prospects is becoming more competitive and complex.

Tourmaline attempts to enhance its competitive position by operating in areas where it believes its technical
personnel are able to reduce some of the risks associated with exploration, production and marketing because they
are familiar with the areas of operation. Management believes that Tourmaline will be able to explore for and
develop new production and reserves with the objective of increasing its cash flow and reserve base. See "Risk
Factors – Competition".

Cycles

The Company's business is generally cyclical. The exploration for and the development of oil and natural
gas reserves is dependent on access to areas where drilling is to be conducted. Seasonal weather variation, including
"freeze-up" and "break-up", affect access in certain circumstances. See "Risk Factors – Seasonality".

Environmental Protection

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of
provincial and federal legislation. Compliance with such legislation may require significant expenditures or result in
operational restrictions. Breach of such requirements may result in suspension or revocation of necessary licenses
and authorizations, civil liability for pollution damage and the imposition of material fines and penalties, all of
which might have a significant negative impact on earnings and overall competitiveness of the Company. For a
description of the financial and operational effects of environmental protection requirements on the capital
expenditures, earnings and competitive position of Tourmaline see "Industry Conditions – Environmental
Regulation" and "Risk Factors – Environmental".

Employees

At December 31, 2011, Tourmaline had 99 full time employees and seven consultants located at its Calgary
office, and 20 full time employees and 48 contract operators in various field locations. Tourmaline currently has 102
full time employees and seven consultants located at its Calgary office, and 20 full time employees and 50 contract
operators in various field locations.

Reorganizations

Other than disclosed under "General Development of the Business", Tourmaline has not completed any
material reorganization within the three most recently completed financial years or completed during the current
financial year. No material reorganization is currently proposed for the current financial year. See "General
Development of the Business".

Environmental, Health and Safety Policies

The Company supports environmental protection and employee health and safety by integrating the
essential principles and practices through its environmental management systems and employee occupational health
and safety programs. The Company promotes safety and environmental awareness and protection through the
implementation and communication of the Company's environmental management and employee occupational
health and safety programs, policies and procedures. Committee structures are established in the Company's
operations which are designed to allow for employee participation and development of policies and programs which
provide employees with job orientation, training, instruction and supervision to assist them in conducting their
activities in an environmentally responsible and safe manner.

The Company develops emergency response teams and preparedness plans in conjunction with local
authorities, emergency services and the communities in which it operates in order to effectively respond to an
environmental incident should it arise. Environmental assessments are undertaken for new projects or when
acquiring new properties or facilities in order to identify, assess and minimize environmental risks and operational
exposures. The Company conducts audits of operations to confirm compliance with internal standards and to
stimulate improvement in practices where needed. Documentation is maintained to support internal accountability
and measure operational performance against recognized industry indicators to assist in achieving the objectives of
the described policies and programs.

The Company also faces environmental, health and safety risks in the normal course of its operations due to
the handling and storage of hazardous substances. The Company's environmental and occupational health and safety
management systems are designed to manage such risks in the Company's business and allow action to be taken to
mitigate the extent of any environmental, health or safety impacts from such operations. A key aspect of these
systems is the performance of annual environmental and occupational health and safety audits.

DIVIDENDS

The Company has never declared or paid any cash dividends on the Common Shares. The Company
currently intends to retain future earnings, if any, for future operations, expansion and debt repayment. Any decision
to declare and pay dividends will be made at the discretion of the Board of Directors and will depend on, among
other things, the Company's results of operations, current and anticipated cash requirements and surplus, financial
condition, contractual restrictions and financing agreement covenants, solvency tests imposed by corporate law and
other factors that the Board may deem relevant.

In addition to the foregoing, the Company's ability to pay dividends now or in the future may be limited by
covenants contained in the agreements governing any indebtedness that the Company has incurred or may incur in
the future including the terms of the Company's credit facilities. Tourmaline's credit facility prohibits Tourmaline
from declaring or paying any dividends (excluding stock dividends) to any of its shareholders or returning any
capital (including by way of dividend) to any of its shareholders.

DESCRIPTION OF CAPITAL STRUCTURE

General Description of Capital Structure

The authorized share capital of Tourmaline consists of an unlimited number of Common Shares and an

unlimited number of First Preferred Shares and an unlimited number of Second Preferred Shares.

The following is a summary of the rights, privileges, restrictions and conditions attaching to the shares in

Tourmaline's share capital.

Common Shares

Tourmaline is authorized to issue an unlimited number of Common Shares without nominal or par value.
Holders of Common Shares are entitled to one vote per share at meetings of shareholders of Tourmaline. Subject to
the rights of the holders of First Preferred Shares and Second Preferred Shares and any other shares having priority
over the Common Shares, holders of Common Shares are entitled to dividends if, as and when declared by the Board
of Directors and upon liquidation, dissolution or winding-up to receive the remaining property of Tourmaline.

First Preferred Shares

The First Preferred Shares are issuable in series and will have such rights, restrictions, conditions and

limitations as the Board of Directors may from time to time determine. No First Preferred Shares have been issued.

Tourmaline is authorized to issue an unlimited number of First Preferred Shares without nominal or par
value. Holders of First Preferred Shares are entitled to receive dividends if, as and when declared by the Board of
Directors, in priority to holders of Common Shares and Second Preferred Shares. In the event of a liquidation,
dissolution or winding-up of Tourmaline, holders of the First Preferred Shares are entitled to receive a rateable share
of all distributions made in priority to the holders of the Common Shares and Second Preferred Shares.

Second Preferred Shares

The Second Preferred Shares are issuable in series and will have such rights, restrictions, conditions and
limitations as the Board of Directors may from time to time determine. No Second Preferred Shares have been
issued.

Tourmaline is authorized to issue an unlimited number of Second Preferred Shares without nominal or par
value. Holders of Second Preferred Shares are entitled to receive dividends if, as and when declared by the Board of
Directors subject to the preference of First Preferred Shares but in priority to holders of Common Shares. In the
event of a liquidation, dissolution or winding-up of Tourmaline, holders of the Second Preferred Shares are entitled
to receive a rateable share of all distributions made, subject to the preference of holders of First Preferred Shares but
in priority to holders of Common Shares.

Constraints

There are currently no constraints imposed on the ownership of securities of the Company to ensure that

Tourmaline has a required level of Canadian ownership.

Ratings

Tourmaline has not asked for and received a stability rating, or to the knowledge of Tourmaline, has
received any other kind of rating, including, a provisional rating, from one or more approved rating organizations for
securities of Tourmaline that are outstanding and which continue in effect.

MARKET FOR SECURITIES

Trading Price and Volume

The Common Shares trade on the Toronto Stock Exchange (the "TSX") under the symbol TOU. The
following table sets forth the price ranges and volume traded on the TSX on a monthly basis for each month of the
most recently completed financial year:

Common Shares

Price Range

High
($/share)

Low
($/share)

2011
January .............................................
February ...........................................
March ...............................................
April .................................................
May ..................................................
June ..................................................
July ..................................................
August .............................................
September ........................................
October ............................................
November ........................................
December .........................................

24.89
25.00
26.99
27.79
29.99
32.07
35.70
35.96
34.77
34.99
34.53
31.71

21.44
23.60
23.90
24.03
26.05
28.01
31.25
29.50
28.55
26.35
27.00
26.25

Trading
Volume

10,315,096
4,843,544
7,884,445
5,436,734
19,269,742
18,173,167
10,375,673
10,481,234
10,071,222
8,568,137
5,402,585
10,693,796

Prior Sales

The following table provides details regarding each class of securities of the Company that are outstanding
but not listed or quoted on a market place that have been issued by the Company during the most recently completed
financial year.

Options Granted During 2011

Date of Issuance
January 15, 2011 ..................................................
February 15, 2011 ................................................
March 15, 2011 ....................................................
April 15, 2011 ......................................................
May 15, 2011 .......................................................
June 15, 2011 .......................................................
August 15, 2011 ...................................................
October 15, 2011 ..................................................
December 15, 2011 ..............................................

Number of Options

90,000
110,000
150,000
40,000
100,000
685,000
555,000
82,000
1,956,024

Exercise Price of
Options
$22.27
$24.09
$25.38
$25.14
$26.82
$29.93
$30.76
$32.78
$28.16

ESCROWED SECURITIES AND SECURITIES SUBJECT TO
CONTRACTUAL RESTRICTION ON TRANSFER

To the Company's knowledge, as of December 31, 2011, no securities of Tourmaline are held in escrow or

subject to a contractual restriction on transfer.

Name, Occupation and Security Holding

DIRECTORS AND OFFICERS

The names, province or state, and country of residence, positions and offices held with the Company, and
principal occupation of the directors and executive officers of the Company are set out below and, in the case of
directors, the period each has served as a director of the Company.

Name, Province and
Country of Residence

Position Held

Principal Occupation for the Last Five Years

Director Since

Michael L. Rose
Alberta, Canada

Chairman, President and Chief
Executive Officer

William D. Armstrong(4)(5)
Colorado, United States

Director

Lee Baker(3)(4)(5)
Alberta, Canada

Director

Robert W. Blakely(1)(2)(3)(5)
Ontario, Canada

Kevin Keenan(4)
Alberta, Canada

Phillip A.
Lamoreaux(1)(2)(3)(4)(5)
California, United States

Director

Andrew B. MacDonald(1)(2)(5)
British Columbia, Canada

Director

Chairman, President and Chief Executive Officer of
Tourmaline since August 2008. Prior thereto,
Chairman, President and Chief Executive Officer of
Duvernay, an oil and gas company.

President and Chief Executive Officer of Armstrong
Oil & Gas Inc., an oil and gas exploration and
production company.

President and Chief Executive Officer of Nordegg
Resources Inc., an oil and gas company, since
March 2008. Prior thereto, President and Chief
Executive Officer of RSX Energy Inc., an oil and
gas company.

President of Likrilyn Capital Corporation, an
investment management company.

Independent businessman since November 2009.
Prior thereto, Vice President, Operations and Chief
Operating Officer of Exshaw. Prior thereto,
President of Manor House Venture Partners Inc.

Managing Member of Lamoreaux Capital
Management LLC, an investment management
company.

Independent businessman since January 2009. Prior
thereto, Co-Head of Canadian Equities and Portfolio
Manager with Phillips, Hager & North Investment
Management, an investment management company.

August 6, 2008

October 27, 2008

March 22, 2011

October 27, 2008

September 9, 2010

March 22, 2011

Director

Chairman and Chief Executive Officer of
Paramount Resources Ltd., an oil and gas company.

October 27, 2008

Clayton H. Riddell
Alberta, Canada

Brian G. Robinson
Alberta, Canada

Director and Vice President,
Finance and Chief Financial
Officer

Robert N. Yurkovich(6)
Alberta, Canada

Director and Executive Vice
President, Exploration

Stanley Nowek
Alberta, Canada

Vice President, Operations and
Chief Operating Officer

Ronald J. Hill
Alberta, Canada

Vice President, Exploration

Drew E. Tumbach
Alberta, Canada

Vice President, Land and
Contracts

W. Scott Kirker
Alberta, Canada

Secretary and General Counsel

Director and Vice President, Finance and Chief
Financial Officer of Tourmaline since August 2008.
Prior thereto, Vice President, Finance and Chief
Financial Officer of Duvernay.

Director and Executive Vice President, Exploration
of Tourmaline since October 2008. Prior thereto,
Vice President, Exploration of Duvernay.

Vice President, Operations and Chief Operating
Officer of Tourmaline since October 2008. Prior
thereto, Vice President, Operations and Chief
Operating Officer of Duvernay.

Vice President, Exploration of Tourmaline since
November 2009. Prior thereto, Senior Geologist at
Tourmaline and Duvernay.

Vice President, Land and Contracts of Tourmaline
since October 2008. Prior thereto, Vice President,
Land and Contracts of Duvernay.

Secretary and General Counsel of Tourmaline since
August 2008. Prior thereto, Manager Corporate
Affairs of Duvernay.

October 27, 2008

N/A

Notes:

(1)
(2)
(3)

(4)

(5)
(6)

Member of the Audit Committee. Mr. Blakely is the Chairman of the Audit Committee.
Member of the Compensation Committee. Mr. Blakely is the Chairman of the Compensation Committee.
Member of the Corporate Governance Committee. Mr. Lamoreaux is the Chairman of the Corporate Governance
Committee.
Member of the Reserves, Safety and Environmental Committee. Mr. Keenan is the Chairman of the Reserves, Safety
and Environmental Committee.
Independent director.
Mr. Yurkovich is part time in his capacity as Executive Vice President, Exploration.

All of the Company's directors' terms of office will expire at the earliest of their resignation, the close of the
next annual shareholder meeting called for the election of directors, or on such other date as they may be removed
according to the ABCA. Each director will devote the amount of time as is required to fulfill his obligations to the
Company. The Company's officers are appointed by and serve at the discretion of the Board of Directors.

As of the date of this Annual Information Form, the directors and executive officers of Tourmaline, as a
group, beneficially owned, or controlled or directed, directly or indirectly, 34,660,870 Common Shares or
approximately 22% of the issued and outstanding Common Shares.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

Cease Trade Orders

To the knowledge of the Company, except as described below, no director or executive officer of the
Company (nor any personal holding company of any of such persons) is, as of the date of this Annual Information
Form, or was within 10 years before the date of this Annual Information Form, a director, chief executive officer or
chief financial officer of any company (including the Company), that: (a) was subject to a cease trade order
(including a management cease trade order), an order similar to a cease trade order or an order that denied the
relevant company access to any exemption under securities legislation, in each case that was in effect for a period of
more than 30 consecutive days (collectively, an "Order"), that was issued while the director or executive officer
was acting in the capacity as director, chief executive officer or chief financial officer; or (b) was subject to an Order
that was issued after the director or executive officer ceased to be a director, chief executive officer or chief
financial officer and which resulted from an event that occurred while that person was acting in the capacity as
director, chief executive officer or chief financial officer.

Mr. Clayton Riddell is a director and executive officer of Paramount Resources Ltd. ("Paramount"). From
1992 to 2008, Paramount was the general partner of T.T.Y. Paramount Partnership No. 5 ("TTY"), a limited
partnership, which was an unlisted reporting issuer in certain provinces of Canada. TTY was established in 1980 to
conduct oil and gas exploration and development but had not carried on active operations since 1984 and had only
nominal assets. A cease trade order against TTY was issued by the Autorité des marches financiers in 1999 for
failing to file the June 30, 1998 interim financial statements in Québec. The cease trade order was revoked on
April 9, 2008. TTY was dissolved on July 21, 2008.

Bankruptcies

To the knowledge of the Company, no director or executive officer of the Company (nor any personal
holding company of any of such persons), or shareholder holding a sufficient number of securities of the Company
to affect materially the control of the Company: (a) is, as of the date of this Annual Information Form, or has been
within the 10 years before the date of this Annual Information Form, a director or executive officer of any company
(including the Company) that, while that person was acting in that capacity, or within a year of that person ceasing
to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency
or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver
manager or trustee appointed to hold its assets; or (b) has, within the 10 years before the date of this Annual
Information Form, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or
become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver,
receiver manager or trustee appointed to hold the assets of the director, executive officer or shareholder.

Penalties or Sanctions

regulatory body that would likely be considered important to a reasonable investor in making an investment
decision.

Conflicts of Interest

Certain officers and directors of the Company are also officers and/or directors of other entities engaged in
the oil and gas business generally. As a result, situations may arise where the interest of such directors and officers
conflict with their interests as directors and officers of other companies. The resolution of such conflicts is governed
by applicable corporate laws, which require that directors act honestly, in good faith and with a view to the best
interests of the Company. Conflicts, if any, will be handled in a manner consistent with the procedures and remedies
set forth in the ABCA. The ABCA provides that in the event that a director has an interest in a contract or proposed
contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from
voting on any matter in respect of such contract or agreement unless otherwise provided by the ABCA.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

Legal Proceedings

There are no legal proceedings Tourmaline is or was a party to, or that any of its property is or was the
subject of, during Tourmaline's financial year, nor are any such legal proceedings known to Tourmaline to be
contemplated, that involves a claim for damages, exclusive of interest and costs, exceeding 10% of the current assets
of Tourmaline.

Regulatory Actions

There are no:

(a)

(b)

(c)

penalties or sanctions imposed against Tourmaline by a court relating to securities legislation or
by a securities regulatory authority during Tourmaline's financial year;

other penalties or sanctions imposed by a court or regulatory body against Tourmaline that would
likely be considered important to a reasonable investor in making an investment decision; and

settlement agreements Tourmaline entered into before a court relating to securities legislation or
with a securities regulatory authority during Tourmaline's financial year.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

There is no material interest, direct or indirect, of any: (a) director or executive officer of Tourmaline; (b)
person or company that beneficially owns, or controls or directs, directly or indirectly, more than 10% of any class
or series of Tourmaline's voting securities; and (c) associate or affiliate of any of the persons or companies referred
to in (a) or (b) above in any transaction within the three most recently completed financial years or during the
current financial year that has materially affected or is reasonably expected to materially affect Tourmaline other
than that Messrs. Rose and Keenan, directors of Tourmaline, were directors and shareholders, and Mr. Keenan was
also an officer, of Exshaw at the time of the Company's acquisition of Exshaw.

AUDITOR, TRANSFER AGENT AND REGISTRAR

The Company's auditors are KPMG LLP, Chartered Accountants, Suite 2700, 205 – 5th Avenue S.W.,

Calgary, Alberta T2P 4B9.

The transfer agent and registrar for the Common Shares is Canadian Stock Transfer Company, Inc. at its

principal offices in Calgary, Alberta and Toronto, Ontario.

MATERIAL CONTRACTS

Except for contracts entered into in the ordinary course of business, the Company has not entered into any
material contracts within the most recently completed financial year, or before the most recently completed financial
year which are still in effect.

Names of Experts

INTERESTS OF EXPERTS

The only persons or companies who are named as having prepared or certified a report, valuation,
statement or opinion described or included in a filing, or referred to in a filing, made by the Company under
National Instrument 51-102 during, or relating to the Company's most recently completed financial year and whose
profession or business gives authority to such report, valuation, statement or opinion, are:

•
•

KPMG LLP, Tourmaline's independent auditors; and
GLJ and AJM, Tourmaline's independent reserve evaluators (collectively, the "Reserve Evaluators").

Interests of Experts

To the Company's knowledge, no registered or beneficial interests, direct or indirect, in any securities or
other property of the Company or of one of the Company's associates or affiliates (i) were held by any of the
Reserve Evaluators or by the "designated professionals" (as defined in Form 51-102F2) of the Reserve Evaluators,
when the Reserve Evaluators prepared their respective reports, valuations, statements or opinions referred to herein
as having been prepared by such Reserve Evaluators, (ii) were received by any of the Reserve Evaluators or the
designated professionals of the Reserve Evaluators after such Reserve Evaluator prepared the report, valuation,
statement or opinion in question, or (iii) is to be received by any of the Reserve Evaluators or the designated
professionals of the Reserve Evaluators.

None of the Reserve Evaluators nor any director, officer or employee of any of the Reserve Evaluators is or
is expected to be elected, appointed or employed as a director, officer or employee of the Company or of any
associate or affiliate of the Company.

KPMG LLP has advised the Company that they are independent within the meaning of the Rules of

Professional Conduct of the Institute of Chartered Accountants of Alberta.

INDUSTRY CONDITIONS

Companies operating in the oil and natural gas industry are subject to extensive regulation and control of
operations (including land tenure, exploration, development, production, refining and upgrading, transportation, and
marketing) as a result of legislation enacted by various levels of government and with respect to the pricing and
taxation of oil and natural gas through agreements among the governments of Canada, Alberta and British
Columbia, all of which should be carefully considered by investors in the oil and gas industry. It is not expected that
any of these regulations or controls will affect the Company's operations in a manner materially different than they
will affect other oil and natural gas companies of similar size. All current legislation is a matter of public record and
the Company is unable to predict what additional legislation or amendments may be enacted. Outlined below are
some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry in
western Canada.

Pricing and Marketing

Oil

The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that
the market determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The

specific price depends in part on oil quality, prices of competing fuels, distance to market, value of refined products,
the supply/demand balance and contractual terms of sale. Oil exporters are also entitled to enter into export
contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude
oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the
"NEB"). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires
an exporter to obtain an export licence from the NEB.

Natural Gas

The price of the vast majority of natural gas produced in western Canada is now determined through highly
liquid market hubs such as the Alberta "NIT" (Nova Inventory Transfer) hub rather than through direct negotiation
between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the
Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the
export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada.
Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to
20 years (in quantities of not more than 30,000 m3/day) must be made pursuant to an NEB order. Any natural gas
export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or for a larger quantity
requires an exporter to obtain an export licence from the NEB.

The governments of Alberta and British Columbia also regulate the volume of natural gas that may be
removed from those provinces for consumption elsewhere based on such factors as reserve availability,
transportation arrangements and market considerations.

The North American Free Trade Agreement

The North American Free Trade Agreement ("NAFTA") among the governments of Canada, the United States and
Mexico became effective on January 1, 1994. In the context of energy resources, Canada continues to remain free to
determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any
export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of goods
of the party maintaining the restriction as compared to the proportion prevailing in the most recent 36 month period;
(ii) impose an export price higher than the domestic price (subject to an exception with respect to certain measures
which only restrict the volume of exports); and (iii) disrupt normal channels of supply. All three signatory
countries are prohibited from imposing a minimum or maximum export price requirement in any circumstance
where any other form of quantitative restriction is prohibited. The signatory countries are also prohibited from
imposing a minimum or maximum import price requirement except as permitted in enforcement of countervailing
and anti-dumping orders and undertakings. NAFTA requires energy regulators to ensure the orderly and equitable
implementation of any regulatory changes and to ensure that the application of those changes will cause minimal
disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution
arrangements, all of which are important for Canadian oil and natural gas exports.

Royalties and Incentives

General

In addition to federal regulation, each province has legislation and regulations which govern royalties,
production rates and other matters. The royalty regime in a given province is a significant factor in the profitability
of oil sands projects, crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on
production from lands other than Crown lands are determined by negotiation between the mineral freehold owner
and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Royalties
from production on Crown lands are determined by governmental regulation and are generally calculated as a
percentage of the value of gross production. The rate of royalties payable generally depends in part on prescribed
reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or
quality of the petroleum product produced. Other royalties and royalty-like interests are, from time to time, carved
out of the working interest owner's interest through non-public transactions. These are often referred to as
overriding royalties, gross overriding royalties, net profits interests, or net carried interests.

Occasionally the governments of the western Canadian provinces create incentive programs for exploration
and development. Such programs often provide for royalty rate reductions, royalty holidays or royalty tax credits
and are generally introduced when commodity prices are low to encourage exploration and development activity by
improving earnings and cash flow within the industry.

Alberta

Producers of oil and natural gas from Crown lands in Alberta are required to pay annual rental payments,
currently at a rate of $3.50 per hectare, and make monthly royalty payments in respect of oil and natural gas
produced.

Royalties are currently paid pursuant to "The New Royalty Framework" (implemented by the Mines and
Minerals (New Royalty Framework) Amendment Act, 2008) and the "Alberta Royalty Framework", which was
implemented in 2010.

Royalty rates for conventional oil are set by a single sliding rate formula which is applied monthly and
incorporates separate variables to account for production rates and market prices. Effective January 1, 2011, the
maximum royalty payable under the royalty regime was set at 40%. The royalty curve for conventional oil
announced on May 27, 2010 amends the price component of the conventional oil royalty formula to moderate the
increase in the royalty rate at prices higher than $535/m3 compared to the previous royalty curve.

Royalty rates for natural gas under the royalty regime are similarly determined using a single sliding rate
formula incorporating separate variables to account for production rates and market prices. Effective January 1,
2011, the maximum royalty payable under the royalty regime was set at 36%. The royalty curve for natural gas
announced on May 27, 2010 amends the price component of the natural gas royalty formula to moderate the increase
in the royalty rate at prices higher than $5.25/GJ compared to the previous royalty curve.

Oil sands projects are also subject to the Alberta's royalty regime. Prior to payout of an oil sands project,
the royalty is payable on gross revenues of an oil sands project. Gross revenue royalty rates range between 1-9%
depending on the market price of oil, determined using the average monthly price, expressed in Canadian dollars, for
WTI crude oil and Cushing, Oklahoma: rates are 1% when the market price of oil is less than or equal to $55 per
barrel and increase for every dollar of market price of oil increase to a maximum of 9% when oil is priced at $120 or
higher. After payout, the royalty payable is the greater of the gross revenue royalty based on the gross revenue
royalty rate of 1-9% and the net revenue royalty based on the net revenue royalty rate. Net revenue royalty rates
start at 25% and increase for every dollar of market price of oil increase above $55 up to 40% when oil is priced at
$120 or higher. In addition, concurrently with the implementation of the New Royalty Framework, the Government
of Alberta renegotiated existing contracts with certain oil sands producers that were not compatible with the current
royalty regime.

Producers of oil and natural gas from freehold lands in Alberta are required to pay annual freehold
production taxes. The level of the freehold production tax is based on the volume of monthly production and a
specified rate of tax for both oil and gas.

The Innovative Energy Technologies Program (the "IETP"), which is currently in place, has the stated
objectives of increasing recovery from oil and gas deposits, finding technical solutions to the gas over bitumen issue,
improving the recovery of bitumen by in-situ and mining techniques and improving the recovery of natural gas from
coal seams. The IETP provides royalty adjustments to specific pilot and demonstration projects that utilize new or
innovative technologies to increase recovery from existing reserves.

The Government of Alberta currently has in place two royalty programs, both of which commenced in
2008 and are intended to encourage the development of deeper, higher cost oil and gas reserves. A five-year
program for conventional oil exploration wells over 2,000 metres provides qualifying wells with up to a $1 million
or 12 months of royalty relief, whichever comes first, and a five-year program for natural gas wells deeper than
2,500 metres provides a sliding scale royalty credit based on depth of up to $3,750 per metre. On May 27, 2010, the
natural gas deep drilling program was amended, retroactive to May 1, 2010, by reducing the minimum qualifying

depth to 2,000 metres, removing a supplemental benefit of $875,000 for wells exceeding 4,000 metres that are
spudded subsequent to that date, and including wells drilled into pools drilled prior to 1985, among other changes.

On November 19, 2008, the Government of Alberta announced the introduction of a five-year program of
transitional royalty rates with the intent of promoting new drilling. The five-year transition option is designed to
provide lower royalties at certain price levels in the initial years of a well's life when production rates are expected
to be the highest. Under this program, companies drilling new natural gas or conventional deep oil wells (between
1,000 and 3,500 m) are given a one-time option, on a well-by-well basis, to adopt either the new transitional royalty
rates or those outlined in the royalty regime. These options expired on February 15, 2011 and on January 1, 2014,
all producers operating under the transitional royalty rates will automatically become subject to the royalty regime.
The revised royalty curves for conventional oil and natural gas will not be applied to production from wells
operating under the transitional royalty rates.

On March 3, 2009, the Government of Alberta announced a three-point incentive program in order to
stimulate new and continued economic activity in Alberta. One aspect of the program was a drilling royalty credit
program which provided up to a $200 per metre royalty credit for new wells. The drilling credit program applied to
wells that were drilled between April 1, 2009 and March 31, 2010 and has not been extended for wells drilled after
March 31, 2010. Another aspect of the program was a new well royalty program which provided for a maximum
5% royalty rate for eligible new wells for the first twelve (12) productive months or until the regulated "volume cap"
was reached. The New Well Royalty Regulation, providing for the permanent implementation of this incentive
program, was approved by an Order-in-Council on March 17, 2011.

In addition to the foregoing, the Government of Alberta has implemented certain initiatives intended to
accelerate technological development and facilitate the development of unconventional resources (the "Emerging
Resource and Technologies Initiative"). Specifically:

• Coalbed methane wells will receive a maximum royalty rate of 5% for 36 producing months on up to

750 MMcf of production, retroactive to wells that began producing on or after May 1, 2010;

• Shale gas wells will receive a maximum royalty rate of 5% for 36 producing months with no limitation

on production volume, retroactive to wells that began producing on or after May 1, 2010;

• Horizontal gas wells will receive a maximum royalty rate of 5% for 18 producing months on up to 500

MMcf of production, retroactive to wells that commenced drilling on or after May 1, 2010; and

• Horizontal oil wells and horizontal non-project oil sands wells will receive a maximum royalty rate of
5% with volume and production month limits set according to the depth of the well (including the
horizontal distance), retroactive to wells that commenced drilling on or after May 1, 2010.

The Emerging Resource and Technologies Initiative will be reviewed in 2014, and the Government of
Alberta has committed to providing industry with three years notice at that time if it decides to discontinue the
program.

British Columbia

Producers of oil and natural gas from Crown lands in British Columbia are required to pay annual rental
payments, currently at a rate of $3.50 per hectare, and make monthly royalty payments in respect of oil and natural
gas produced. The amount payable as a royalty in respect of oil depends on the type and vintage of the oil, the
quantity of oil produced in a month and the value of that oil. Generally, oil is classified as either light or heavy and
the vintage of oil is based on the determination of whether the oil is produced from a pool discovered before
October 31, 1975 ("old oil"), between October 31, 1975 and June 1, 1998 ("new oil"), or after June 1, 1998
("third-tier oil"). The royalty calculation takes into account the production of oil on a well-by-well basis, the
specified royalty rate for a given vintage of oil, the average unit selling price of the oil and any applicable royalty
exemptions. Royalty rates are reduced on low productivity wells, reflecting the higher unit costs of extraction, and
are the lowest for third-tier oil, reflecting the higher unit costs of both exploration and extraction.

The royalty payable in respect of natural gas produced on Crown lands is determined by a sliding scale
formula based on a reference price, which is the greater of the average net price obtained by the producer and a
prescribed minimum price. For non-conservation gas (not produced in association with oil), the royalty rate depends
on the date of acquisition of the oil and natural gas tenure rights and the spud date of the well and may also be
impacted by the select price, a parameter used in the royalty rate formula to account for inflation. Royalty rates are
fixed for certain classes of non-conservation gas when the reference price is below the select price. Conservation
gas is subject to a lower royalty rate than non-conservation gas as an incentive for the production and marketing of
natural gas which might otherwise have been flared.

Producers of oil and natural gas from freehold lands in British Columbia are required to pay monthly
freehold production taxes. For oil, the level of the freehold production tax is based on the volume of monthly
production. For natural gas, the freehold production tax is determined using a sliding scale formula based on the
reference price similar to that applied to natural gas production on Crown land, and depends on whether the natural
gas is conservation gas or non-conservation gas.

British Columbia maintains a number of targeted royalty programs for key resource areas intended to
increase the competitiveness of British Columbia's low productivity wells. These include both royalty credit and
royalty reduction programs, including the following:

•

Summer Royalty Credit Program providing a royalty credit of 10% of drilling and completion costs up
to $100,000 for wells drilled between April 1 and November 30 of each year, intended to increase
summer drilling activity, employment and business opportunities in northeastern British Columbia;

• Deep Royalty Credit Program providing a royalty credit equal to approximately 23% of drilling and
completion costs for vertical wells with a true vertical depth greater than 2,500 metres and horizontal
wells with a true vertical depth greater than 2,300 metres;

• Deep Re-Entry Royalty Credit Program providing royalty credits for deep re-entry wells with a true

vertical depth greater than 2,300 metres and a re-entry date subsequent to December 1, 2003;

• Deep Discovery Royalty Credit Program providing the lesser of a 3-year royalty holiday or
283,000,000 m3 of royalty free gas for deep discovery wells with a true vertical depth greater than
4,000 metres whose surface locations are at least 20 kilometres away from the surface location of any
well drilled into a recognized pool within the same formation with a spud date after November 30,
2003;

• Coalbed Gas Royalty Reduction and Credit Program providing a royalty reduction for coalbed gas
wells with average daily production less than 17,000 m3 as well as a royalty credit for coalbed gas
wells equal to $50,000 for wells drilled on Crown land and a tax credit equal to $30,000 for wells
drilled on freehold land;

• Marginal Royalty Reduction Program providing royalty reductions for low productivity natural gas
wells with average monthly production under 25,000 m3 during the first 12 production months and
average daily production less than 23 m3 for every metre of marginal well depth;

• Ultra-Marginal Royalty Reduction Program providing additional royalty reductions for low
productivity shallow natural gas wells with a true vertical depth of less than 2,500 metres in the case of
vertical wells, and a total vertical depth of less than 2,300 metres in the case of a horizontal well,
average monthly production under 60,000 m3 during the first 12 production months and average daily
production less than 11.5 m3 (development wells) or 17 m3 (exploratory wildcat wells) for every 100
metres of marginal well depth; and

• Net Profit Royalty Reduction Program providing reduced initial royalty rates to facilitate the
development and commercialization of technically complex resources such as coalbed gas, tight gas,

shale gas and enhanced-recovery projects, with higher royalty rates applied once capital costs have
been recovered.

Oil produced from an oil well that is located on either Crown or freehold land and completed in a new pool
discovered subsequent to June 30, 1974 may also be exempt from the payment of a royalty for the first 36 months of
production or 11,450 m3 of production, whichever comes first.

The Government of British Columbia also maintains an Infrastructure Royalty Credit Program (the
"Infrastructure Royalty Credit Program") which provides royalty credits for up to 50% of the cost of certain
approved road construction or pipeline infrastructure projects intended to improve, or make possible, the access to
new and underdeveloped oil and gas areas. In 2009, 2010 and 2011, the Government of British Columbia awarded
$120 million in royalty credits to oil and gas companies under the Infrastructure Royalty Credit Program.

On August 6, 2009, the Government of British Columbia announced an oil and gas stimulus package
designed to attract investment in and create economic benefits for British Columbia. The stimulus package includes
four royalty initiatives related primarily to natural gas drilling and infrastructure development. British Columbia's
existing Deep Royalty Credit Program was permanently amended for wells spudded after August 31, 2009 by
increasing the royalty deduction on deep drilling for natural gas by 15% and extending the program to include
horizontal wells drilled to depths of between 1,900 and 2,300 metres. An additional $50 million was also allocated
to be distributed through the Infrastructure Royalty Credit Program to stimulate investment in oilfield-related road
and pipeline construction.

Land Tenure

Crude oil and natural gas located in the western provinces is owned predominantly by the respective
provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant
to leases, licences, and permits for varying terms, and on conditions set forth in provincial legislation including
requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be
privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms
and conditions as may be negotiated.

Each of the provinces of Alberta and British Columbia has implemented legislation providing for the
reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the
primary term of a lease or license. On March 29, 2007, British Columbia's policy of deep rights reversion was
expanded for new leases to provide for the reversion of both shallow and deep formations that cannot be shown to
be capable of production at the end of their primary term.

Alberta also has a policy of "shallow rights reversion" which provides for the reversion to the Crown of
mineral rights to shallow, non-productive geological formations for all leases and licenses. For leases and licenses
issued subsequent to January 1, 2009, shallow rights reversion will be applied at the conclusion of the primary term
of the lease or license. Holders of leases or licences that have been continued indefinitely prior to January 1, 2009
will receive a notice regarding the reversion of the shallow rights, which will be implemented three years from the
date of the notice. Leases and licences that were granted prior to January 1, 2009 but continued after that date are
not subject to shallow rights reversion until they reach the end of their primary term and are continued (at which
time deep rights reversion will be applied); thereafter, the holders of such agreements will be served with shallow
rights reversion notices based on vintage and location similar to leases and licences that were already continued as
of January 1, 2009. The order in which these agreements will receive reversion notices will depend on their vintage
and location, and the Government of Alberta had anticipated that the receipt of reversion notices for older leases and
licenses would commence in April 2011. However, on April 14, 2011, the Government of Alberta announced it was
deferring serving shallow rights reversion notices and will revisit the decision in spring 2012.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of
provincial and federal legislation, all of which is subject to governmental review and revision from time to time.

Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced
in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. In addition,
such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial
authorities. Compliance with such legislation can require significant expenditures and a breach of such
requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for
pollution damage, and the imposition of material fines and penalties.

In December, 2008, the Government of Alberta released a new land use policy for surface land in Alberta,
the Alberta Land Use Framework (the "ALUF"). The ALUF sets out an approach to manage public and private land
use and natural resource development in a manner that is consistent with the long-term economic, environmental and
social goals of the province. It calls for the development of region-specific land use plans in order to manage the
combined impacts of existing and future land use within a specific region and the incorporation of a cumulative
effects management approach into such plans.

The Alberta Land Stewardship Act (the "ALSA") was proclaimed in force in Alberta on October 1, 2009
and provides the legislative authority for the Government of Alberta to implement the policies contained in the
ALUF. Regional plans established pursuant to the ALSA will be deemed to be legislative instruments equivalent to
regulations and will be binding on the Government of Alberta and provincial regulators, including those governing
the oil and gas industry. In the event of a conflict or inconsistency between a regional plan and another regulation,
regulatory instrument or statutory consent, the regional plan will prevail. Further, the ALSA requires local
governments, provincial departments, agencies and administrative bodies or tribunals to review their regulatory
instruments and make any appropriate changes to ensure that they comply with an adopted regional plan. The
ALSA also contemplates the amendment or extinguishment of previously issued statutory consents such as
regulatory permits, leases, licenses, approvals and authorizations for the purpose of achieving or maintaining an
objective or policy resulting from the implementation of a regional plan. Among the measures to support the goals
of the regional plans contained in the ALSA are conservation easements, which can be granted for the protection,
conservation and enhancement of land; and conservation directives, which are explicit declarations contained in a
regional plan to set aside specified lands in order to protect, conserve, manage and enhance the environment.

On August 29, 2011 the Government of Alberta released a revised draft of the Lower Athabasca Regional
Plan (the "Revised LARP") updating its prior draft of April 5, 2011 (the "Draft LARP"). The Revised LARP,
while establishing several conservation areas of the Athabasca region, has changed the boundaries of certain
conservation areas outlined in the Draft LARP with the result that fewer oil sands leases appear to be impacted.
Consistent with the Draft LARP, as the intention of the Revised LARP is to manage the areas to minimize or prevent
new land disturbance, activities associated with oil sands development are considered incompatible with the intent to
manage such conservation areas. However, references to the cancellation of existing tenures have been removed
from the Revised LARP and the Revised LARP now contemplates that the conservation areas will be created
pursuant to existing legislation rather than the previously contemplated regulations. Existing conventional
petroleum and natural gas rights will not be affected, although the Revised LARP raises some question as to whether
new conventional leases and licenses will be granted in the conservation areas in the future. The planning process is
also underway for a regional plan for the South Saskatchewan Region.

Climate Change Regulation

Federal

In December 2002, the Government of Canada ratified the Kyoto Protocol ("Kyoto Protocol"), which
requires a reduction in greenhouse gas ("GHG") emissions by signatory countries between 2008 and 2012. The
Kyoto Protocol officially came into force on February 16, 2005 although on December 12, 2011 Canada formally
withdrew from the Kyoto Protocol.

On April 26, 2007, the Government of Canada released "Turning the Corner: An Action Plan to Reduce
Greenhouse Gases and Air Pollution" (the "Action Plan") which set forth a plan for regulations to address both
GHGs and air pollution. An update to the Action Plan, "Turning the Corner: Regulatory Framework for Industrial
Greenhouse Gas Emissions" was released on March 10, 2008 (the "Updated Action Plan"). The Updated Action
Plan outlines emissions intensity-based targets which will be applied to regulated sectors on either a facility-specific,

sector-wide or company-by-company basis. Facility-specific targets apply to the upstream oil and gas, oil sands,
petroleum refining and natural gas pipelines sectors. Unless a minimum regulatory threshold applies, all facilities
within a regulated sector will be subject to the emissions intensity targets.

The Updated Action Plan makes a distinction between "Existing Facilities" and "New Facilities". For
Existing Facilities, the Updated Action Plan requires an emissions intensity reduction of 18% below 2006 levels by
2010 followed by a continuous annual emissions intensity improvement of 2%. "New Facilities" are defined as
facilities beginning operations in 2004 and include both greenfield facilities and major facility expansions that (i)
result in a 25% or greater increase in a facility's physical capacity, or (ii) involve significant changes to the processes
of the facility. New Facilities will be given a 3-year grace period during which no emissions intensity reductions
will be required. Targets requiring an annual 2% emissions intensity reduction will begin to apply in the fourth year
of commercial operation of a New Facility. Further, emissions intensity targets for New Facilities will be based on a
cleaner fuel standard to encourage continuous emissions intensity reductions over time. The method of applying this
cleaner fuel standard has not yet been determined. In addition, the Updated Action Plan indicates that targets for the
adoption of carbon capture and storage ("CCS") technologies will be developed for oil sands in-situ facilities,
upgraders and coal-fired power generators that begin operations in 2012 or later. These targets will become
operational in 2018, although the exact nature of the targets has not yet been determined.

Given the large number of small facilities within the upstream oil and gas and natural gas pipeline sectors,
facilities within these sectors will only be subject to emissions intensity targets if they meet certain minimum
emissions thresholds. That threshold will be (i) 50,000 tonnes of CO2 equivalents per facility per year for natural
gas pipelines; (ii) 3,000 tonnes of CO2 equivalents per facility per year for the upstream oil and gas facility; and (iii)
10,000 boe/d/company. These regulatory thresholds are significantly lower than the regulatory threshold in force in
Alberta, discussed below. In all other sectors governed by the Updated Action Plan, all facilities will be subject to
regulation.

Four separate compliance mechanisms are provided for in the Updated Action Plan in respect of the above

targets:

(a)

(b)

(c)

Regulated entities will be able to use Technology Fund contributions to meet their emissions
intensity targets. The contribution rate for Technology Fund contributions will increase over time,
beginning at $15 per tonne of CO2 equivalent for the 2010 to 2012 period, rising to $20 in 2013,
and thereafter increasing at the nominal rate of GDP growth. Maximum contribution limits will
also decline from 70% in 2010 to 0% in 2018. Monies raised through contributions to the
Technology Fund will be used to invest in technology to reduce GHG emissions. Alternatively,
regulated entities may be able to receive credits for investing in large-scale and transformative
projects at the same contribution rate and under similar requirements as described above.

The offset system is intended to encourage emissions reductions from activities outside of the
regulated sphere, allowing non-regulated entities to participate in and benefit from emissions
reduction activities. In order to generate offset credits, project proponents must propose and
receive approval for emissions reduction activities that will be verified before offset credits will be
issued to the project proponent. Those credits can then be sold to regulated entities for use in
compliance or non-regulated purchasers that wish to either purchase the offset credits for
cancellation or banking for future use or sale.

Under the Updated Action Plan, regulated entities were able to purchase credits created through
the Clean Development Mechanism of the Kyoto Protocol which facilitates investment by
developed nations in emissions-reduction projects in developing countries. The purchase of such
Emissions Reduction Credits will be restricted to 10% of each firm's regulatory obligation, with
the added restriction that credits generated through forest sink projects will not be available for use
in complying with the Canadian regulations. However, with the recent withdrawal from the Kyoto
Protocol, the future use of this mechanism may not occur.

(d)

Finally, a one-time credit of up to 15 million tonnes worth of emissions credits will be awarded to
regulated entities for emissions reduction activities undertaken between 1992 and 2006. These
credits will be both tradable and bankable.

From December 7 to 18, 2009, government leaders and representatives met in Copenhagen, Denmark and
agreed to the Copenhagen Accord, which reinforces the commitment to reducing GHG emissions contained in the
Kyoto Protocol and promises funding to help developing countries mitigate and adapt to climate change. Another
meeting of government leaders and representatives in 2010 resulted in the Cancun Agreements wherein developed
countries committed to additional measures to help developing countries deal with climate change. Neither the
Copenhagen Accord nor the Cancun Agreements establish binding GHG emissions reduction targets. In response to
the Copenhagen Accord, the Government of Canada indicated that it will seek to achieve a 17% reduction in GHG
emissions from 2005 levels by 2020.

Although draft regulations for the implementation of the Updated Action Plan were intended to become
binding on January 1, 2010, only draft regulations pertaining to carbon dioxide emissions from coal-fired generation
of electricity have been proposed to date. Further, representatives of the Government of Canada have indicated that
the proposals contained in the Updated Action Plan will be modified to ensure consistency with the direction
ultimately taken by the United States with respect to GHG emissions regulation. As a result, it is unclear to what
extent, if any; the proposals contained in the Updated Action Plan will be implemented.

The United States Environmental Protection Agency (the "EPA") has indicated its intention to impose
GHG emissions standards for fossil fuel-fired power plants by specifying that it will issue final regulations by May
26, 2012, and with respect to refineries, specifying that it will issue proposed regulations by December 10, 2011 and
finalized regulations by November 10, 2012. The EPA did not meet the December 10, 2011 deadline and it is
unclear whether the EPA will also miss the finalized regulations deadline.

Alberta

Alberta enacted the Climate Change and Emissions Management Act (the "CCEMA") on December 4,
2003, amending it through the Climate Change and Emissions Management Amendment Act which received royal
assent on November 4, 2008. The CCEMA is based on an emissions intensity approach similar to the Updated
Action Plan and aims for a 50% reduction from 1990 emissions relative to GDP by 2020.

Alberta facilities emitting more than 100,000 tonnes of GHGs a year are subject to compliance with the
CCEMA. Similar to the Updated Action Plan, the CCEMA and the associated Specified Gas Emitters Regulation
make a distinction between "Established Facilities" and "New Facilities". Established Facilities are defined as
facilities that completed their first year of commercial operation prior to January 1, 2000 or that have completed
eight or more years of commercial operation. Established Facilities are required to reduce their emissions intensity
to 88% of their baseline for 2008 and subsequent years, with their baseline being established by the average of the
ratio of the total annual emissions to production for the years 2003 to 2005. New Facilities are defined as facilities
that completed their first year of commercial operation on December 31, 2000, or a subsequent year, and have
completed less than eight years of commercial operation, or are designated as New Facilities in accordance with the
Specified Gas Emitters Regulation. New Facilities are required to reduce their emissions intensity by 2% from
baseline in the fourth year of commercial operation, 4% of baseline in the fifth year, 6% of baseline in the sixth year,
8% of baseline in the seventh year, and 10% of baseline in the eighth year. Unlike the Updated Action Plan, the
CCEMA does not contain any provision for continuous annual improvements in emissions intensity reductions
beyond those stated above.

The CCEMA contains compliance mechanisms that are similar to the Updated Action Plan. Regulated
emitters can meet their emissions intensity targets by contributing to the Climate Change and Emissions
Management Fund (the "Fund") at a rate of $15 per tonne of CO2 equivalent. Unlike the Updated Action Plan,
CCEMA contains no provisions for an increase to this contribution rate. Emissions credits can be purchased from
regulated emitters that have reduced their emissions below the 100,000 tonne threshold or non-regulated emitters
that have generated emissions offsets through activities that result in emissions reductions in accordance with
established protocols published by the Government of Alberta.

On December 2, 2010, the Government of Alberta passed the Carbon Capture and Storage Statutes
Amendment Act, 2010, which deemed the pore space underlying all land in Alberta to be, and to have always been,
the property of the Crown and provided for the assumption of long-term liability for carbon sequestration projects by
the Crown, subject to the satisfaction of certain conditions.

British Columbia

In February, 2008, British Columbia announced a revenue-neutral carbon tax that took effect July 1, 2008.
The tax is consumption-based and applied at the time of retail sale or consumption of virtually all fossil fuels
purchased or used in British Columbia. The current tax level is $25 per tonne of CO2 equivalent. It is scheduled to
increase to $30 per tonne of CO2 equivalent on July 31, 2012. In order to make the tax revenue-neutral, British
Columbia has implemented tax credits and reductions in order to offset the tax revenues that the Government of
British Columbia would otherwise receive from the tax.

On April 3, 2008, British Columbia introduced the Greenhouse Gas Reduction (Cap and Trade) Act (the
"Cap and Trade Act") which received royal assent on May 29, 2008 and partially came into force by regulation of
the Lieutenant Governor in Council. Unlike the emissions intensity approach taken by the federal government and
the Government of Alberta, the Cap and Trade Act establishes an absolute cap on GHG emissions. Although more
specific details of British Columbia's cap and trade plan have not yet been finalized, on January 1, 2010, new
reporting regulations came into force requiring all British Columbia facilities emitting over 10,000 tonnes of CO2
equivalents per year to begin reporting their emissions. Facilities reporting emissions greater than 25,000 tonnes of
CO2 equivalents per year are required to have their emissions reports verified by a third party. Regulations
pertaining to proposed offsets and emissions trading are currently in the consultation stage.

RISK FACTORS

Investors should carefully consider the risk factors set out below and consider all other information contained
herein and in the Company's other public filings before making an investment decision.

Natural Gas and Oil Prices and Markets

The prices of oil and natural gas prices may be volatile and subject to fluctuation. Any material decline in
prices could result in a reduction of the Company's net production revenue. The economics of producing from some
wells may change as a result of lower prices, which could result in reduced production of oil or natural gas and a
reduction in the volumes of the Company's reserves. The Company might also elect not to produce from certain
wells at lower prices. All of these factors could result in a material decrease in the Company's expected net
production revenue and a reduction in its oil and natural gas acquisition, development and exploration activities.
Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of
and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond the control of the
Company. These factors include economic conditions, in the United States, Canada and Europe, the actions of
OPEC, governmental regulation, political stability in the Middle East, Northern Africa and elsewhere, the foreign
supply of oil and natural gas, risks of supply disruption, the price of foreign imports and the availability of
alternative fuel sources. Any substantial and extended decline in the price of oil and natural gas would have an
adverse effect on the Company's carrying value of its reserves, borrowing capacity, revenues, profitability and cash
flows from operations and may have a material adverse effect on the Company's business, financial condition,
results of operations and prospects.

Oil and natural gas prices are expected to remain volatile for the near future as a result of market
uncertainties over the supply and the demand of these commodities due to the current state of the world economies,
OPEC actions, and sanctions imposed on certain oil producing nations by other countries and the ongoing credit and
liquidity concerns. Volatile oil and natural gas prices make it difficult to estimate the value of producing properties
for acquisitions and often cause disruption in the market for oil and natural gas producing properties, as buyers and
sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the
return on acquisitions and development and exploitation projects.

The marketability and price of oil and natural gas that may be acquired or discovered by the Company is
and will continue to be affected by numerous factors beyond its control. The Company's ability to market its oil and
natural gas may depend upon its ability to acquire space on pipelines that deliver natural gas to commercial markets.
The Company may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines
and processing and storage facilities and operational problems affecting such pipelines and facilities as well as
extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of
oil and natural gas and many other aspects of the oil and natural gas business.

Exploration, Development and Production Risks

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and
careful evaluation may not be able to overcome. The long-term commercial success of the Company depends on its
ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual
addition of new reserves, any existing reserves the Company may have at any particular time, and the production
therefrom will decline over time as such existing reserves are exploited. A future increase in the Company's
reserves will depend not only on its ability to explore and develop any properties it may have from time to time, but
also on its ability to select and acquire suitable producing properties or prospects. No assurance can be given that
the Company will be able to continue to locate satisfactory properties for acquisition or participation therein.
Moreover, if such acquisitions or participations are identified, management of the Company may determine that
current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations
uneconomic. There is no assurance that further commercial quantities of oil and natural gas will be discovered or
acquired by the Company.

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also
from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling,
completing (including hydraulic fracturing), operating and other costs. Completion of a well does not assure a profit
on the investment or recovery of drilling, completion and operating costs. Drilling hazards or environmental
damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the
production from successful wells. These conditions include delays in obtaining governmental approvals or consents,
shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation
capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance
operations can contribute to maximizing production rates over time, production delays and declines from normal
field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels
to varying degrees.

Oil and natural gas exploration, development and production operations are subject to all the risks and
hazards typically associated with such operations, including fire, explosion, blowouts, cratering, sour gas releases,
spills or other environmental hazards, each of which could result in substantial damage to oil and natural gas wells,
production facilities, other property and the environment or personal injury. In particular, the Company may explore
for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result in personal
injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could
result in liability to the Company. Oil and natural gas production operations are also subject to all the risks typically
associated with such operations, including encountering unexpected formations or pressures, premature decline of
reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these
risks may have a material adverse effect on the Company's business, financial condition, results of operations and
prospects. In accordance with industry practice, the Company is not fully insured against all risks, nor are all risks
insurable. Although the Company maintains liability insurance in an amount that it considers consistent with
industry practice, the nature of certain risks is such that liabilities could exceed policy limits or not be covered, in
either event the Company could incur significant costs.

Global Financial Crisis

Recent market events and conditions, including disruptions in the international credit markets and other
financial systems and the American and European sovereign debt levels have caused significant volatility in
commodity prices. These conditions have caused a decrease in confidence in the global credit and financial markets
and have created a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price

transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions by governments,
concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers
and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline
substantially. This volatility may in the future affect the Company's ability to obtain equity or debt financing on
acceptable terms.

Market Price of Common Shares

The trading price of securities of oil and natural gas issuers is subject to substantial volatility. This
volatility is often based on factors both related and unrelated to the financial performance or prospects of the issuers
involved. The market price of the Common Shares of the Company could be subject to significant fluctuations in
response to variations in the Company's operating results, financial condition, liquidity and other internal factors.
Factors that could affect the market price of the Common Shares of the Company that are unrelated to the
Company's performance include domestic and global commodity prices and market perceptions of the attractiveness
of particular industries. The price at which the Common Shares of the Company will trade cannot be accurately
predicted.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

The Company considers acquisitions and dispositions of businesses and assets in the ordinary course of
business. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and
integrating operations and procedures in a timely and efficient manner as well as the Company's ability to realize the
anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of
the Company. The integration of acquired businesses may require substantial management effort, time and
resources and may divert management's focus from other strategic opportunities and operational matters.
Management continually assesses the value and contribution of services provided and assets required to provide
such services. In this regard, non-core assets may be periodically disposed of, so that the Company can focus its
efforts and resources more efficiently. Depending on the state of the market for such non-core assets, certain
non-core assets of the Company, if disposed of, could be expected to realize less than their carrying value on the
financial statements of the Company.

Operational Dependence

Other companies operate some of the assets in which the Company has an interest. As a result, the
Company has limited ability to exercise influence over the operation of those assets or their associated costs, which
could adversely affect the Company's financial performance. The Company's return on assets operated by others
therefore depends upon a number of factors that may be outside of the Company's control, including the timing and
amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants,
the selection of technology and risk management practices.

Project Risks

The Company manages a variety of small and large projects in the conduct of its business. Project delays
may delay expected revenues from operations. Significant project cost over-runs could make a project uneconomic.
The Company's ability to execute projects and market oil and natural gas depends upon numerous factors beyond the
Company's control, including:

•
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•
•

•
•

the availability of processing capacity;
the availability and proximity of pipeline capacity;
the availability of storage capacity;
the availability of, and the ability to acquire, water supplies needed for drilling and hydraulic
fracturing, or the Company's ability to dispose of water used or removed from strata at a reasonable
cost and within applicable environmental regulations;
the supply of and demand for oil and natural gas;
the availability of alternative fuel sources;

•
•
•
•
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•
•
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the effects of inclement weather;
the availability of drilling and related equipment;
unexpected cost increases;
accidental events;
currency fluctuations;
changes in regulations;
the availability and productivity of skilled labour; and
the regulation of the oil and natural gas industry by various levels of government and governmental
agencies.

Because of these factors, the Company could be unable to execute projects on time, on budget or at all, and

may not be able to effectively market the oil and natural gas that it produces.

Gathering and Processing Facilities and Pipeline Systems

The Company delivers its products through gathering, processing and pipeline systems some of which it
does not own. The amount of oil and natural gas that the Company can produce and sell is subject to the
accessibility, availability, proximity and capacity of these gathering, processing and pipeline systems. The lack of
availability of capacity in any of the gathering, processing and pipeline systems, and in particular the processing
facilities, could result in the Company’s inability to realize the full economic potential of its production or in a
reduction of the price offered for the Company’s production. Any significant change in market factors or other
conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new
infrastructure systems and facilities could harm the Company's business and, in turn, the Company’s financial
condition, results of operations and cash flows.

A portion of the Company's production may, from time to time, be processed through facilities owned by
third parties and over which the Company does not have control. From time to time these facilities may discontinue
or decrease operations either as a result of normal servicing requirements or as a result of unexpected events. A
discontinuation or decrease of operations could materially adversely affect the Company's ability to process its
production and to deliver the same for sale.

Reliance on Key Personnel

The Company's success depends in large measure on certain key personnel. The loss of the services of
such key personnel may have a material adverse effect on the Company's business, financial condition, results of
operations and prospects. The Company does not have any key person insurance in effect for the Company. The
contributions of the existing management team to the immediate and near term operations of the Company are likely
to be of central importance. In addition, the competition for qualified personnel in the oil and natural gas industry is
intense and there can be no assurance that the Company will be able to continue to attract and retain all personnel
necessary for the development and operation of its business. Investors must rely upon the ability, expertise,
judgment, discretion, integrity and good faith of the management of the Company.

Competition

The petroleum industry is competitive in all its phases. The Company competes with numerous other
entities in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural
gas. The Company's competitors include oil and natural gas companies that have substantially greater financial
resources, staff and facilities than those of the Company. The Company's ability to increase its reserves in the future
will depend not only on its ability to explore and develop its present properties, but also on its ability to select and
acquire other suitable producing properties or prospects for exploratory drilling. Competitive factors in the
distribution and marketing of oil and natural gas include price and methods and reliability of delivery and storage.
Competition may also be presented by alternate fuel sources.

Regulatory

Oil and natural gas operations (exploration, production, pricing, marketing and transportation) are subject
to extensive controls and regulations imposed by various levels of government, which may be amended from time to
time. See "Industry Conditions". Governments may regulate or intervene with respect to exploration and
production activities, prices, taxes, royalties and the exportation of oil and natural gas. Such regulations may be
changed from time to time in response to economic or political conditions. The implementation of new regulations
or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for crude
oil and natural gas and increase the Company's costs, either of which may have a material adverse effect on the
Company's business, financial condition, results of operations and prospects. In order to conduct oil and natural gas
operations, the Company will require licenses from various governmental authorities. There can be no assurance
that the Company will be able to obtain all of the licenses and permits that may be required to conduct operations
that it may wish to undertake.

Hydraulic Fracturing

Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure
into rock formations to stimulate hydrocarbon (oil and natural gas) production. The use of hydraulic fracturing is
being used to produce commercial quantities of oil and natural gas from reservoirs that were previously
unproductive. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to
operational delays, increased operating costs or third party or governmental claims, and could increase the
Company's costs of compliance and doing business as well as delay the development of oil and natural gas resources
from shale formations which are not commercial without the use of hydraulic fracturing. Restrictions on hydraulic
fracturing could also reduce the amount of oil and natural gas that the Company is ultimately able to produce from
its reserves.

Environmental

All phases of the oil and natural gas business present environmental risks and hazards and are subject to
environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental
legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various
substances produced in association with oil and natural gas operations. The legislation also requires that wells and
facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory
authorities. Compliance with such legislation can require significant expenditures and a breach of applicable
environmental legislation may result in the imposition of fines and penalties, some of which may be material.
Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger
fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural
gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may
require the Company to incur costs to remedy such discharge. Although the Company believes that it will be in
material compliance with current applicable environmental regulations, no assurance can be given that
environmental laws will not result in a curtailment of production or a material increase in the costs of production,
development or exploration activities or otherwise have a material adverse effect on the Company's business,
financial condition, results of operations and prospects.

Climate Change

The Company's exploration and production facilities and other operations and activities emit greenhouse
gases and require the Company to comply with greenhouse gas emissions legislation in Alberta and British
Columbia or that may be enacted in other provinces. The Company may also be required comply with the regulatory
scheme for greenhouse gas emissions ultimately adopted by the federal government, which regulations are expected
to be consistent with the regulatory scheme for greenhouse gas emissions adopted by the United States. The direct
or indirect costs of these regulations may have a material adverse effect on the Company's business, financial
condition, results of operations and prospects. The future implementation or modification of greenhouse gases
regulations, whether to meet the limits regulated by the Copenhagen Accord or as otherwise determined, could have
a material impact on the nature of oil and natural gas operations, including those of the Company. Given the
evolving nature of the debate related to climate change and the control of greenhouse gases and resulting

requirements, it is not possible to predict the impact on the Company and its operations and financial condition. See
"Industry Conditions – Climate Change Regulation".

Variations in Foreign Exchange Rates and Interest Rates

World oil and natural gas prices are quoted in United States dollars and the price received by Canadian
producers is therefore affected by the Canadian/U.S. dollar exchange rate, which will fluctuate over time. In recent
years, the Canadian dollar has increased materially in value against the United States dollar. Material increases in
the value of the Canadian dollar negatively impact the Company's production revenues. Future Canadian/United
States exchange rates could accordingly impact the future value of the Company's reserves as determined by
independent evaluators.

To the extent that the Company engages in risk management activities related to foreign exchange rates,

there is a credit risk associated with counterparties with which the Company may contract.

An increase in interest rates could result in a significant increase in the amount the Company pays to

service debt, which could negatively impact the market price of the Common Shares of the Company.

Substantial Capital Requirements

The Company anticipates making substantial capital expenditures for the acquisition, exploration,
development and production of oil and natural gas reserves in the future. As future capital expenditures will be
financed out of cash generated from operations, borrowings and possible future equity sales, the Company's ability
to do so is dependent on, among other factors, the overall state of the capital markets, the Company’s credit rating (if
applicable), interest rates, tax burden due to new tax laws and investor appetite for investments in the energy
industry and the Company's securities in particular. Further, if the Company's revenues or reserves decline, it may
not have access to the capital necessary to undertake or complete future drilling programs. There can be no
assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these
requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms
acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a
material adverse effect on the Company's business financial condition, results of operations and prospects.

Additional Funding Requirements

The Company's cash flow from its reserves may not be sufficient to fund its ongoing activities at all times
and from time to time, the Company may require additional financing in order to carry out its oil and natural gas
acquisition, exploration and development activities. As a result of the global economic volatility, the Company,
along with many other oil and natural gas entities, may, from time to time, have restricted access to capital and
increased borrowing costs. Failure to obtain such financing on a timely basis could cause the Company to forfeit its
interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If the
Company's revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it will
affect the Company's ability to expend the necessary capital to replace its reserves or to maintain its production. To
the extent that external sources of capital become limited or unavailable or available on onerous terms, the
Company's ability to make capital investments and maintain existing assets may be impaired, and its assets,
liabilities, business, financial condition and results of operations may be materially and adversely affected as a
result. In addition, the future development of the Company's petroleum properties may require additional financing
and there are no assurances that such financing will be available or, if available, will be available upon acceptable
terms. Failure to obtain any financing necessary for the Company's capital expenditure plans may result in a delay in
development or production on the Company’s properties.

Credit Facility Arrangements

The Company currently has a credit facility and the amount authorized thereunder is dependent on the
borrowing base determined by its lenders. The Company is required to comply with covenants under its credit
facility which may, in certain cases, include certain financial ratio tests, which from time to time either affect the

availability, or price, of additional funding and in the event that the Company does not comply therewith the
Company's access to capital could be restricted or repayment could be required. The failure of the Company to
comply with such covenants, which may be affected by events beyond the Company's control, could result in the
default under the Company's credit facility which could result in the Company being required to repay amounts
owing thereunder. Even if the Company is able to obtain new financing, it may not be on commercially reasonable
terms or terms that are acceptable to the Company. If the Company is unable to repay amounts owing, the lenders
under the credit facility could proceed to foreclose or otherwise realize upon the collateral granted to them to secure
the indebtedness. The acceleration of the Company's indebtedness under one agreement may permit acceleration of
indebtedness under other agreements that contain cross default or cross-acceleration provisions. In addition, the
Company's credit facility may, from time to time, impose operating and financial restrictions on the Company that
could include restrictions on, the payment of dividends, repurchase or making of other distributions with respect to
the Company's securities, incurring of additional indebtedness, provision of guarantees, the assumption of loans,
making of capital expenditures, entering into of amalgamations, mergers, take-over bids or disposition of assets,
among others.

The Company's borrowing base is determined and re-determined by the Company's lenders based on the
Company's reserves, commodity prices, applicable discount rate and other factors as determined by the Company's
lenders. A material decline in commodity prices could reduce the Company's borrowing base, therefore reducing
the funds available to the Company under the credit facility which could result in a portion, or all, of the Company's
bank indebtedness be required to be repaid.

Issuance of Debt

From time to time the Company may enter into transactions to acquire assets or shares of other
organizations. These transactions may be financed in whole or in part with debt, which may increase the Company's
debt levels above industry standards for oil and natural gas companies of similar size. Depending on future
exploration and development plans, the Company may require additional debt financing that may not be available
or, if available, may not be available on favourable terms. Neither the Company's articles nor its by-laws limit the
amount of indebtedness that the Company may incur. The level of the Company's indebtedness from time to time,
could impair the Company's ability to obtain additional financing on a timely basis to take advantage of business
opportunities that may arise.

Hedging

From time to time the Company may enter into agreements to receive fixed prices on its oil and natural gas
production to offset the risk of revenue losses if commodity prices decline. However, to the extent that the
Company engages in price risk management activities to protect itself from commodity price declines, it may also be
prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to
manage price risk. In addition, the Company’s hedging arrangements may expose it to the risk of financial loss in
certain circumstances, including instances in which:

•

production falls short of the hedged volumes;

there is a widening of price-basis differentials between delivery points for production and the
delivery point assumed in the hedge arrangement;

the counterparties to the hedging arrangements or other price risk management contracts fail to
perform under those arrangements; or

a sudden unexpected event materially impacts oil and natural gas prices.

Similarly, from time to time the Company may enter into agreements to fix the exchange rate of Canadian
to United States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value
compared to the United States dollar; however, if the Canadian dollar declines in value compared to the United
States dollar, the Company will not benefit from the fluctuating exchange rate.

Availability of Drilling Equipment and Access

Oil and natural gas exploration and development activities are dependent on the availability of drilling and
related equipment (typically leased from third parties) in the particular areas where such activities will be conducted.
Demand for such limited equipment or access restrictions may affect the availability of such equipment to the
Company and may delay exploration and development activities.

Title to Assets

Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties
or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the
chain of title will not arise to defeat the Company's claim which may have a material adverse effect on the
Company's business, financial condition, results of operations and prospects. There may be valid challenges to title,
or proposed legislative changes which affect title, to the oil and natural gas properties the Company controls that, if
successful or made into law, could impair the Company’s activities on them and result in a reduction of the revenue
received by the Company.

Reserve Estimates

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids
reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set
forth herein are estimates only. In general, estimates of economically recoverable oil and natural gas reserves and
the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical
production from the properties, production rates, ultimate reserve recovery, timing and amount of capital
expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental
agencies and future operating costs, all of which may vary materially from actual results. For those reasons,
estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of
properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated
with reserves prepared by different engineers, or by the same engineers at different times may vary. The Company's
actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary
from estimates thereof and such variations could be material.

Estimates of proved reserves that may be developed and produced in the future are often based upon
volumetric calculations and upon analogy to similar types of reserves rather than actual production history.
Recovery factors and drainage areas were estimated by experience and analogy to similar producing pools.
Estimates based on these methods are generally less reliable than those based on actual production history.
Subsequent evaluation of the same reserves based upon production history and production practices will result in
variations in the estimated reserves and such variations could be material.

In accordance with applicable securities laws, the Company's independent reserves evaluator has used
forecast prices and costs in estimating the reserves and future net cash flows as summarized herein. Actual future
net cash flows will be affected by other factors, such as actual production levels, supply and demand for oil and
natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental
regulation or taxation and the impact of inflation on costs.

Actual production and cash flows derived from the Company's oil and natural gas reserves will vary from
the estimates contained in the reserve evaluation, and such variations could be material. The reserve evaluation is
based in part on the assumed success of activities the Company intends to undertake in future years. The reserves
and estimated cash flows to be derived therefrom contained in the reserve evaluation will be reduced to the extent
that such activities do not achieve the level of success assumed in the reserve evaluation. The reserve evaluation is
effective as of a specific effective date and has not been updated and thus does not reflect changes in the Company's
reserves since that date.

Insurance

The Company's involvement in the exploration for and development of oil and natural gas properties may
result in the Company becoming subject to liability for pollution, blow outs, leaks of sour natural gas, property
damage, personal injury or other hazards. Although the Company maintains insurance in accordance with industry
standards to address certain of these risks, such insurance has limitations on liability and may not be sufficient to
cover the full extent of such liabilities. In addition, certain risks are not, in all circumstances, insurable or, in certain
circumstances, the Company may elect not to obtain insurance to deal with specific risks due to the high premiums
associated with such insurance or other reasons. The payment of any uninsured liabilities would reduce the funds
available to the Company. The occurrence of a significant event that the Company is not fully insured against, or
the insolvency of the insurer of such event, may have a material adverse effect on the Company's business, financial
condition, results of operations and prospects.

Geo-Political Risks

The marketability and price of oil and natural gas that may be acquired or discovered by the Company is
and will continue to be affected by political events throughout the world that cause disruptions in the supply of oil.
Conflicts, or conversely peaceful developments, arising in the Middle East, North Africa and other areas of the
world have a significant impact on the price of oil and natural gas. Any particular event could result in a material
decline in prices and therefore result in a reduction of the Company's net production revenue.

In addition, the Company's oil and natural gas properties, wells and facilities could be subject to a terrorist
attack. If any of the Company's properties, wells or facilities are the subject of terrorist attack it may have a material
adverse effect on the Company's business, financial condition, results of operations and prospects. The Company
does not have insurance to protect against the risk from terrorism.

Dilution

The Company may make future acquisitions or enter into financings or other transactions involving the
issuance of securities of the Company which may be dilutive. In addition, existing shareholders of the Company
may in the future wish to reduce their share position in the Company and sell some or all of their shares. The sale of
a substantial number of the Common Shares in the public market, or the perception that such sales may occur, could
adversely affect the prevailing market price of the Common Shares and negatively impact the Company's ability to
raise equity capital in the future.

Management of Growth

The Company may be subject to growth-related risks including capacity constraints and pressure on its
internal systems and controls. The ability of the Company to manage growth effectively will require it to continue
to implement and improve its operational and financial systems and to expand, train and manage its employee base.
The inability of the Company to deal with this growth may have a material adverse effect on the Company's
business, financial condition, results of operations and prospects.

Expiration of Licences and Leases

The Company's properties are held in the form of licences and leases and working interests in licences and
leases. If the Company or the holder of the licence or lease fails to meet the specific requirement of a licence or
lease, the licence or lease may terminate or expire. There can be no assurance that any of the obligations required to
maintain each licence or lease will be met. The termination or expiration of the Company's licences or leases or the
working interests relating to a licence or lease may have a material adverse effect on the Company's business,
financial condition, results of operations and prospects.

Dividends

The Company has not paid any dividends on its outstanding shares. Payment of dividends in the future will
be dependent on, among other things, the cash flow, results of operations and financial condition of the Company,
the need for funds to finance ongoing operations and other considerations as the board of directors of the Company
considers relevant.

Aboriginal Claims

Aboriginal peoples have claimed aboriginal title and rights to portions of western Canada. The Company is
not aware that any claims have been made in respect of its properties and assets; however, if a claim arose and was
successful such claim may have a material adverse effect on the Company's business, financial condition, results of
operations and prospects.

Seasonality

The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns.
Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial
transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby
reducing activity levels. Also, certain oil and natural gas producing areas are located in areas that are inaccessible
other than during the winter months because the ground surrounding the sites in these areas consists of swampy
terrain. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production
activity and corresponding declines in the demand for the goods and services of the Company.

Third Party Credit Risk

The Company may be exposed to third party credit risk through its contractual arrangements with its
current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In
the event such entities fail to meet their contractual obligations to the Company, such failures may have a material
adverse effect on the Company's business, financial condition, results of operations and prospects. In addition, poor
credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to
participate in the Company's ongoing capital program, potentially delaying the program and the results of such
program until the Company finds a suitable alternative partner.

Conflicts of Interest

Certain directors of the Company are also directors of other oil and natural gas companies and as such may,
in certain circumstances, have a conflict of interest requiring them to abstain from certain decisions. Conflicts, if
any, will be subject to the procedures and remedies of the ABCA. See "Directors and Officers – Conflicts of
Interest".

Certain Forward-Looking Information May Prove Inaccurate

Investors are cautioned not to place undue reliance on forward-looking information. By its nature, forward-
looking information involves numerous assumptions, known and unknown risks and uncertainties, of both a general
and specific nature, that could cause actual results to differ materially from those suggested by the forward-looking
information or contribute to the possibility that predictions, forecasts or projections will prove to be materially
inaccurate.

Share Price Volatility

The market price for Common Shares may be volatile and subject to wide fluctuations in response to
numerous factors, many of which are beyond the Company's control, including the following: (i) actual or
anticipated fluctuations in the Company's quarterly results of operations; (ii) actual or anticipated changes in oil and
natural gas prices; (iii) recommendations by securities research analysts; (iv) changes in the economic performance

or market valuations of other companies that investors deem comparable to the Company; (v) addition or departure
of the Company's executive officers and other key personnel; (ii) sales or perceived sales of additional Common
Shares; (vii) significant acquisitions or business combinations, strategic partnerships, joint ventures or capital
commitments by or involving the Company or its competitors; and (viii) news reports relating to trends, concerns,
technological or competitive developments, regulatory changes and other related issues in the Company's industry or
target markets.

Financial markets have experienced significant price and volume fluctuations in the last several years that
have particularly affected the market prices of equity securities of companies and that have, in many cases, been
unrelated to the operating performance, underlying asset values or prospects of such companies. Accordingly, the
market price of the Common Shares may decline even if the Company's operating results, underlying asset values or
prospects have not changed. Additionally, these factors, as well as other related factors, may cause decreases in asset
values that are deemed to be other than temporary, which may result in impairment losses. As well, certain
institutional investors may base their investment decisions on consideration of the Company's environmental,
governance and social practices and performance against such institutions' respective investment guidelines and
criteria, and failure to meet such criteria may result in a limited or no investment in the Common Shares by those
institutions, which could adversely affect the trading price of the Common Shares. There can be no assurance that
continuing fluctuations in the price and volume of publicly traded equity securities will not occur. If such increased
levels of volatility and market turmoil continue, the Company's operations could be adversely impacted and the
trading price of the Common Shares may be adversely affected.

Future Acquisition Activities May Have Adverse Effects

The acquisition of oil and natural gas companies and assets is subject to substantial risks, including the
failure to identify material problems during due diligence, the risk of over-paying for assets and the inability to
arrange financing for an acquisition as may be required or desired. Further, the integration and consolidation of
acquisitions requires substantial human, financial and other resources and, ultimately, the Company's acquisitions
may not be successfully integrated. There can be no assurances that any future acquisitions will perform as expected
or that the returns from such acquisitions will support the indebtedness incurred to acquire them or the capital
expenditures needed to develop them.

Internal Controls

Effective internal controls are necessary for the Company to provide reliable financial reports and to help
prevent fraud. Although the Company undertakes a number of procedures in order to help ensure the reliability of its
financial reports, including those imposed on it under Canadian securities laws, the Company cannot be certain that
such measures will ensure that the Company will maintain adequate control over financial processes and reporting.
Failure to implement required new or improved controls, or difficulties encountered in their implementation, could
harm the Company's results of operations or cause it to fail to meet its reporting obligations. If the Company or its
independent auditors discover a material weakness, the disclosure of that fact, even if quickly remedied, could
reduce the market's confidence in the Company's consolidated financial statements and adversely affect the trading
price of the Common Shares.

Litigation Risks

In the normal course of the Company's operations, it may become involved in, named as a party to, or be
the subject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions,
relating to personal injuries, property damage, property taxes, land rights, the environment and contract disputes.
The outcome of outstanding, pending or future proceedings cannot be predicted with certainty and may be
determined adversely to the Company and as a result, could have a material adverse effect on the Company's assets,
liabilities, business, financial condition and results of operations. Even if the Company prevails in any such legal
proceeding, the proceedings could be costly and time-consuming and may divert the attention of management and
key personnel from the Company's business operations, which could adversely affect its financial condition.

AUDIT COMMITTEE INFORMATION

The Audit Committee has been structured to comply with the requirements of National Instrument 52-110.
The Board has determined that the Audit Committee members have the appropriate level of financial understanding
and industry-specific knowledge to be able to perform their duties. A copy of the Audit Committee mandate and the
additional disclosure required under National Instrument 52-110 is attached to this Annual Information Form as
Schedule "D".

ADDITIONAL INFORMATION

Additional information relating to the Company can be found on SEDAR at www.sedar.com. Additional
information, including directors' and officers' remuneration and indebtedness, principal holders of the Company's
securities and securities authorized for issuance under equity compensation plans is contained in the Company's
information circular for the Company's most recent annual meeting of securityholders that involved the election of
directors. Additional financial information is contained in the Company's financial statements and the related
management's discussion and analysis for the Company's most recently completed financial year.

SELECTED ABBREVIATIONS

In this Annual Information Form, unless otherwise indicated or the context otherwise requires, the

following abbreviations shall have the meaning set forth below:

Crude Oil and Natural Gas Liquids
Bbls/d .................................................... barrels of oil per day
Bbls or Bbl ............................................ barrels of oil
Boe ........................................................ barrel of oil equivalent
Boe/d ..................................................... barrel of oil equivalent per day
$/Bbl ...................................................... Canadian dollars per barrel of oil
$/Boe ..................................................... Canadian dollars per barrel of oil equivalent
Mbbls ....................................................
MBoe .....................................................
Mbbls/d .................................................
MMbbls ................................................. million barrels of oil
MMboe .................................................. million barrels of oil equivalent
MMboe/d ............................................... million barrels of oil equivalent per day
NGL ...................................................... natural gas liquids

thousand barrels
thousand barrels of oil equivalent
thousand barrels of oil per day

thousand cubic feet
thousand cubic feet per day
thousand cubic feet of gas equivalent
thousand cubic feet of gas equivalent per day

Natural Gas
Bcf ......................................................... billion cubic feet
cf ............................................................ cubic feet
Mcf ........................................................
Mcf/d .....................................................
Mcfe ......................................................
Mcfe/d ...................................................
MMbtu................................................... million British thermal units
MMcf .................................................... million cubic feet
MMcf/d ................................................. million cubic feet per day
MMcfe ................................................... million cubic feet of gas equivalent
MMcfe/d ................................................ million cubic feet of gas equivalent per day
$/Mcf ..................................................... Canadian dollars per thousand cubic feet
$/MMbtu ............................................... Canadian dollars per million British thermal units
GJ .......................................................... gigajoule
GJs/d ...................................................... gigajoules per day
$/GJ ....................................................... Canadian dollar per gigajoule

Other

km .......................................................... kilometres
km2 ........................................................
square kilometres
$, $Cdn, Cdn$ or $dollars ..................... Canadian dollars
$000s or M$ ..........................................
thousand dollars
MM$ ...................................................... million dollars
$US or US$ ........................................... United States dollars
2D ..........................................................
3D ..........................................................

two dimensional
three dimensional

SELECTED CONVERSIONS

The following table sets forth certain standard conversions from Standard Imperial Units to the

International System of Units (or metric units).

To Convert From
Mcf
cubic metres
Bbls
cubic metres
feet
metres
miles
kilometres
acres
hectares

cubic metres
cubic feet
cubic metres
Bbls
metres
feet
kilometres
miles
hectares
acres

Multiply By
28.320
35.315
0.159
6.290
0.305
3.281
1.609
0.621
0.405
2.471

FORWARD-LOOKING STATEMENTS

Certain statements contained in this Annual Information Form constitute forward-looking statements.
These statements relate to future events or the Company's future performance. All statements other than statements
of historical fact are forward-looking statements. The use of any of the words "anticipate", "plan", "contemplate",
"continue", "estimate", "expect", "intend", "propose", "might", "may", "will", "shall", "project", "should", "could",
"would", "believe", "predict", "forecast", "pursue", "potential" and "capable" and similar expressions are intended to
identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other
factors that may cause actual results or events to differ materially from those anticipated in such forward-looking
statements. No assurance can be given that these expectations will prove to be correct and such forward-looking
statements included in this Annual Information Form should not be unduly relied upon. These statements speak only
as of the date of this Annual Information Form. In addition, this Annual Information Form may contain forward-
looking statements and forward-looking information attributed to third-party industry sources.

In particular, this Annual Information Form contains, without limitation, forward-looking statements

pertaining to the following:

•
•
•
•
•
•
•
•
•

•
•

the reserve potential of the Company's assets;
the production from the Company's assets;
the Company's growth strategy and opportunities;
the Company's capital exploration and development programs and future capital requirements;
the estimated quantity and value of the Company's proved and probable reserves;
the Company's estimates of future interest and foreign exchange rates;
the Company's environmental considerations;
the Company's expectations regarding commodity prices;
the timing of commencement of certain of the Company's operations and the level of production anticipated
by the Company;
the potential for production disruption and constraints;
supply and demand fundamentals for crude oil and natural gas;

•
•
•
•
•
•

the Company's access to adequate pipeline capacity;
the Company's access to third-party infrastructure;
the Company's drilling and recompletion plans;
industry conditions pertaining to the oil and gas industry;
the Company's plans for, and results of, exploration and development activities;
the planned construction of the Company's gathering, transportation and processing facilities and related
infrastructure;
the timing for receipt of regulatory approvals;
the Company's treatment under governmental regulatory regimes and tax laws;
the Company's expectations regarding having adequate human resource staffing;
the Company's dividend policy;
the number of drilling rigs to be operated by the Company in 2012; and
the timing for completion of financings announced on March 14, 2012.

With respect to forward-looking statements and forward-looking information contained in this Annual

Information Form, assumptions have been made regarding, among other things:

•
•
•

•
•
•
•
•
•
•
•
•
•
•
•

future crude oil and natural gas prices;
the Company's ability to obtain qualified staff and equipment in a timely and cost-efficient manner;
the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which
the Company conducts its business and any other jurisdictions in which the Company may conduct its
business in the future;
the Company's ability to market production of oil and natural gas successfully to customers;
the Company's future production levels;
the applicability of technologies for recovery and production of the Company's reserves;
the recoverability of the Company's reserves;
future capital expenditures to be made by the Company;
future cash flows from production;
future sources of funding for the Company's capital program;
the Company's future debt levels;
geological and engineering estimates in respect of the Company's reserves;
the geography of the areas in which the Company is conducting exploration and development activities;
the impact of competition on the Company; and
the Company's ability to obtain financing on acceptable terms.

Actual results could differ materially from those anticipated in these forward-looking statements as a result

of the risk factors set forth below and included elsewhere in this Annual Information Form, including:

•
•
•
•
•
•
•

•
•
•
•

•
•

operating and capital costs;
the Company's status and stage of development;
general economic, market and business conditions;
volatility in market prices for crude oil and natural gas and hedging activities related thereto;
risks related to the exploration, development and production of oil and natural reserves;
risks related to the timing of completion of the Company's projects;
competition for, among other things, capital, the acquisition of reserves and resources and skilled
personnel;
operational hazards;
actions by governmental authorities, including changes in government regulation and taxation;
environmental risks and hazards;
risks inherent in the exploration, development and production of oil and natural gas which may create
liabilities to the Company in excess of the Company's insurance coverage;
failure to accurately estimate abandonment and reclamation costs;
failure of third parties' reviews, reports and projections to be accurate;

•
•
•
•

•
•
•
•
•
•
•
•
•
•
•
•

•
•

•
•
•

•

the availability of capital on acceptable terms;
political risks;
changes to royalty or tax regimes;
the failure of the Company or the holders of certain licenses or leases to meet specific requirements of such
licenses or leases;
claims made in respect of the Company's properties or assets;
aboriginal claims;
unforeseen title defects;
risks arising from future acquisition activities;
hedging strategies;
potential conflicts of interest;
the potential for management estimates and assumptions to be inaccurate;
restrictions contained in the Company's;
additional indebtedness;
volatility in the market price of the Common Shares of the Company;
the absence of an existing public market for the Common Shares;
the effect that the issuance of additional securities by the Company could have on the market price of the
Common Shares;
failure to engage or retain key personnel;
potential losses which would stem from any disruptions in production, including work stoppages or other
labour difficulties, or disruptions in the transportation network on which the Company is reliant;
uncertainties inherent in estimating quantities of oil and natural gas reserves;
failure to acquire or develop replacement reserves;
geological, technical, drilling and processing problems, including the availability of equipment and access
to properties;
failure by counterparties to make payments or perform their operational or other obligations to the
Company in compliance with the terms of contractual arrangements between the Company and such
counterparties;
current global financial conditions, including fluctuations in interest rates, foreign exchange rates and stock
market volatility; and
the other factors discussed under "Risk Factors" in this Annual Information Form.

Forward looking statements and other information contained herein concerning the oil and gas industry and
the Company's general expectations concerning this industry are based on estimates prepared by management using
data from publicly available industry sources as well as from reserve reports, market research and industry analysis
and on assumptions based on data and knowledge of this industry. However, this data is inherently imprecise,
although generally indicative of relative market positions, market shares and performance characteristics. The
industry involves risks and uncertainties and is subject to change based on various factors.

In addition, information and statements in this Annual Information Form relating to "reserves" are deemed
to be forward-looking information and statements, as they involve the implied assessment, based on certain
estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and that the
reserves described can be profitably produced in the future. See also "Certain Reserves Data Information" below.
Readers are cautioned that the foregoing list of risk factors should not be construed as exhaustive.

Additional information on these and other factors that could affect Tourmaline's operations and financial
results are included in reports on file with Canadian securities regulatory authorities and may be accessed through
the SEDAR website (www.sedar.com).

The forward-looking statements included in this Annual Information Form are expressly qualified
by this cautionary statement and are made as of the date of this Annual Information Form. The Company
does not undertake any obligation to publicly update or revise any forward-looking statements except as
expressly required by applicable securities laws.

CERTAIN RESERVES DATA INFORMATION

The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree
of associated uncertainty. Categories of proved, probable and possible reserves have been established to reflect the
level of these uncertainties and to provide an indication of the probability of recovery.

The estimation and classification of reserves requires the application of professional judgment combined
with geological and engineering knowledge to assess whether or not specific reserves classification criteria have
been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic
and probabilistic estimation methods is required to properly use and apply reserves definitions.

The qualitative certainty levels referred to in the definitions of proved, probable and possible reserves are
applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are
performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which
reserves are presented). Reported reserves should target the following levels of certainty under a specific set of
economic conditions:

(a)

(b)

at least a 90 percent probability that the quantities actually recovered will equal or exceed the
estimated proved reserves; and

at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum
of the estimated proved plus probable reserves.

A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves
categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the
majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically
derived quantitative measure of probability. In principle, there should be no difference between estimates prepared
using probabilistic or deterministic methods.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation

is provided in the COGE Handbook.

In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and
undeveloped categories or to sub-divide the developed reserves for the pool between developed producing and
developed nonproducing. This allocation should be based on the estimator's assessment as to the reserves that will
be recovered from specific wells, facilities and completion intervals in the pool and their respective development
and production status.

In this Annual Information Form:

(a)

(b)

(c)

(d)

the discounted and undiscounted net present value of future net revenues attributable to reserves
do not represent the fair market value of reserves;

there is no assurance that the forecast prices and costs assumptions will be attained and variances
could be material. The recovery and reserve estimates of crude oil, NGL and natural gas reserves
provided in this Annual Information Form are estimates only and there is no guarantee that the
estimated reserves will be recovered. Actual crude oil, natural gas and NGL reserves may be
greater than or less than the estimates provided in this Annual Information Form;

the estimates of reserves and future net revenue for individual properties may not reflect the same
confidence level as estimates of reserves and future net revenue for all properties, due to the
effects of aggregation; and

Boes may be misleading, particularly if used in isolation. A Boe conversion ratio of 6 Mcf : 1 Bbl
is based on an energy equivalency conversion method primarily applicable at the burner tip and

does not represent a value equivalency at the wellhead. Given that the value ratio based on the
current price of crude oil as compared to natural gas is significantly different from the energy
equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of
value.

SCHEDULE "A"

GLJ PETROLEUM CONSULTANTS LTD.
FORM 51-101F2
REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR
AUDITOR

To the board of directors of Tourmaline Oil Corp. (the "Company"):

We have evaluated the Company's reserves data as at December 31, 2011. The reserves data are estimates
of proved reserves and probable reserves and related future net revenue as at December 31, 2011, estimated
using forecast prices and costs.

The reserves data are the responsibility of the Company's management. Our responsibility is to express an
opinion on the reserves data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation
Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers
(Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to
whether the reserves data are free of material misstatement. An evaluation also includes assessing whether
the reserves data are in accordance with principles and definitions in the COGE Handbook.

The following table sets forth the estimated future net revenue (before deduction of income taxes)
attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a
discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year
ended December 31, 2011, and identifies the respective portions thereof that we have audited, evaluated
and reviewed and reported on to the Company's board of directors:

Independent Qualified
Reserves Evaluator

Description and
Preparation Date
of Evaluation
Report

Location of
Reserves (Country
or Foreign
Geographic Area)

Net Present Value of Future Net Revenue
(before income taxes, 10% discount rate - $M)

Audited

Evaluated

Reviewed

Total

GLJ Petroleum Consultants .............

Corporate Summary
February 27, 2012

Canada

1,693,843

In our opinion, the reserves data respectively evaluated by us have, in all material respects, been
determined and are in accordance with the COGE Handbook, consistently applied.

We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances
occurring after their respective preparation dates.

Because the reserves data are based on judgements regarding future events, actual results will vary and the
variations may be material.

EXECUTED as to our report referred to above.

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, February 27, 2012.

ORIGINALLY SIGNED BY

Jodi L. Anhorn M. Sc., P. Eng.
Executive Vice-President & COO

SCHEDULE "B"

AJM DELOITTE
FORM 51-101F2
REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR
AUDITOR

To the Board of Directors of Tourmaline Oil Corp. (the "Company"):

The reserves data are the responsibility of the Company's management. Our responsibility is to express an
opinion on the reserves data based on our evaluation.

The following table sets forth the estimated future net revenue (before deduction of income taxes)
attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a
discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year
ended December 31, 2011, and identifies the respective portions thereof that we have evaluated and
reported on to the Company's management and Board of Directors:

Independent Qualified
Reserves Evaluator or
Auditor

Description and
Preparation Date of
Evaluation Report

AJM Deloitte

Tourmaline Oil Corp.
Reserve Estimation and
Economic Evaluation
February 29, 2012

Location of
Reserves (Country
or Foreign
Geographic Area)

Canada

Net Present Value of Future Net Revenue
(before income taxes, 10% discount rate)

Audited
MM$
-

Evaluated
MM$
$999.40

Reviewed
MM$
-

Total
MM$
$999.40

In our opinion, the reserves data respectively evaluated by us have, in all material respects, been
determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion
on the reserves data that we reviewed but did not audit or evaluate.

We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances
occurring after their respective preparation dates.

Because the reserves data are based on judgements regarding future events, actual results will vary and the
variations may be material.

Executed as to our report referred to above.

AJM Deloitte
Fifth Avenue Place, East Tower
6th Floor, 425 – 1st Street S.W.
Calgary, Alberta T2P 3P8

Original signed by: "Robin G. Bertram"
Robin G. Bertram, P. Eng.
Associate Partner
Execution date: February 29, 2012

SCHEDULE "C"

FORM 51-101F3
REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE

Management of Tourmaline Oil Corp. (the "Company") are responsible for the preparation and disclosure
of information with respect to the Company's oil and gas activities in accordance with securities regulatory
requirements. This information includes reserves data which are estimates of proved reserves and probable reserves
and related future net revenue as at December 31, 2011, estimated using forecast prices and costs.

GLJ Petroleum Consultants Ltd. and AJM Deloitte, each an independent qualified reserves evaluator, has
evaluated the Company's reserves data. The reports of the independent qualified reserves evaluator are presented
below.

The Reserves Committee of the board of directors of the Company has

(a)

(b)

reviewed the Company's procedures for providing information to the independent qualified
reserves evaluators;

met with the independent qualified reserves evaluators to determine whether any restrictions
affected the ability of the independent qualified reserves evaluators to report without reservation;
and

(c)

reviewed the reserves data with management and the independent qualified reserves evaluators.

The Reserves Committee of the board of directors has reviewed the Company's procedures for assembling
and reporting other information associated with oil and gas activities and has reviewed that information with
management. The board of directors has approved

(d)

(e)

the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves
data and other oil and gas information;

the filing of Form 51-102F2 which is the reports of the independent qualified reserves evaluators
on the reserves data; and

(f)

the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual results will vary and the

variations may be material.

DATED as of this 26th day of March, 2012.

(signed)

"Michael L. Rose"
Michael L. Rose
President, Chief Executive Officer and
Director

(signed)

"Brian G. Robinson"
Brian G. Robinson
Vice President, Finance and Chief Financial
Officer

(signed)

"Robert W. Blakely"
Robert W. Blakely
Director

(signed)

"Phillip A. Lamoreaux"
Phillip A. Lamoreaux
Director

SCHEDULE "D"

AUDIT COMMITTEE MANDATE AND AUDIT COMMITTEE DISCLOSURE
AUDIT COMMITTEE MANDATE

Role and Objective

The Audit Committee (the "Committee") is a committee of the board of directors (the "Board") of
Tourmaline Oil Corp. ("Tourmaline" or the "Company") to which the Board has delegated its responsibility for the
oversight of the following:

nature and scope of the annual audit;

the oversight of management's reporting on internal accounting standards and practices;

the review of financial information, accounting systems and procedures;

financial reporting and financial statements,

and has charged the Committee with the responsibility of recommending, for approval of the Board, the audited
financial statements, interim financial statements and other mandatory disclosure releases containing financial
information.

The primary objectives of the Committee are as follows:

To assist directors of Tourmaline ("Directors") in meeting their responsibilities (especially for
accountability) in respect of the preparation and disclosure of the financial statements of the Company and
related matters;

To provide better communication between Directors and external auditors;

To enhance the external auditor's independence;

To increase the credibility and objectivity of financial reports; and

To strengthen the role of the outside Directors by facilitating in depth discussions between Directors on the
Committee, management of Tourmaline ("Management") and external auditors.

Membership of Committee

The Committee will be comprised of at least three (3) Directors or such greater number as the Board may
determine from time to time and all members of the Committee shall be "independent" (as such term is
used in National Instrument 52-110 – Audit Committees ("NI 52-110") unless the Board determines that
the exemption contained in NI 52-110 is available and determines to rely thereon.

The Board may from time to time designate one of the members of the Committee to be the Chair of the
Committee.

All of the members of the Committee must be "financially literate" (as defined in NI 52-110) unless the
Board determines that an exemption under NI 52-110 from such requirement in respect of any particular
member is available and determines to rely thereon in accordance with the provisions of NI 52-110.

D-2

Mandate and Responsibilities of Committee

It is the responsibility of the Committee to:

Oversee the work of the external auditors, including the resolution of any disagreements between
Management and the external auditors regarding financial reporting.

Satisfy itself on behalf of the Board with respect to Tourmaline's internal control systems identifying,
monitoring and mitigating business risks; and ensuring compliance with legal, ethical and regulatory
requirements.

Review the annual and interim financial statements of the Company and related management's discussion
and analysis ("MD&A") prior to their submission to the Board for approval. The process should include
but not be limited to:

•

•
•
•
•
•

•
•

reviewing changes in accounting principles and policies, or in their application, which may have a
material impact on the current or future years' financial statements;
reviewing significant accruals, reserves or other estimates such as the ceiling test calculation;
reviewing accounting treatment of unusual or non-recurring transactions;
ascertaining compliance with covenants under loan agreements;
reviewing disclosure requirements for commitments and contingencies;
reviewing adjustments raised by the external auditors, whether or not included in the financial
statements;
reviewing unresolved differences between Management and the external auditors; and
obtain explanations of significant variances with comparative reporting periods.

Review the financial statements, prospectuses, MD&A, annual information forms ("AIF") and all public
disclosure containing audited or unaudited financial information (including, without limitation, annual and
interim press releases and any other press releases disclosing earnings or financial results) before release
and prior to Board approval. The Committee must be satisfied that adequate procedures are in place for the
review of Tourmaline's disclosure of all other financial information and will periodically assess the
accuracy of those procedures.

With respect to the appointment of external auditors by the Board:

•
•

•

recommend to the Board the external auditors to be nominated;
recommend to the Board the terms of engagement of the external auditor, including the
compensation of the auditors and a confirmation that the external auditors will report directly to
the Committee;
on an annual basis, review and discuss with the external auditors all significant relationships such
auditors have with the Company to determine the auditors' independence;
when there is to be a change in auditors, review the issues related to the change and the
information to be included in the required notice to securities regulators of such change; and
review and pre-approve any non-audit services to be provided to Tourmaline or its subsidiaries by
the external auditors and consider the impact on the independence of such auditors. The
Committee may delegate to one or more independent members the authority to pre-approve
non-audit services, provided that the member(s) report to the Committee at the next scheduled
meeting such pre-approval and the member(s) comply with such other procedures as may be
established by the Committee from time to time

Review with external auditors (and internal auditor if one is appointed by Tourmaline) their assessment of
the internal controls of Tourmaline, their written reports containing recommendations for improvement,
and Management's response and follow-up to any identified weaknesses. The Committee will also review
annually with the external auditors their plan for their audit and, upon completion of the audit, their reports
upon the financial statements of Tourmaline and its subsidiaries.

D-3

Review risk management policies and procedures of the Company (i.e., hedging, litigation and insurance).

Establish a procedure for:

•

the receipt, retention and treatment of complaints received by Tourmaline regarding accounting,
internal accounting controls or auditing matters; and
the confidential, anonymous submission by employees of Tourmaline of concerns regarding
questionable accounting or auditing matters.

Review and approve Tourmaline's hiring policies regarding partners and employees and former partners
and employees of the present and former external auditors of the Company.

The Committee has authority to communicate directly with the internal auditors (if any) and the external
auditors of the Company. The Committee will also have the authority to investigate any financial activity of
Tourmaline. All employees of Tourmaline are to cooperate as requested by the Committee.

The Committee may also retain persons having special expertise and/or obtain independent professional
advice to assist in filling their responsibilities at such compensation as established by the Committee and at the
expense of Tourmaline without any further approval of the Board.

Meetings and Administrative Matters

At all meetings of the Committee every resolution shall be decided by a majority of the votes cast. In case
of an equality of votes, the Chairman of the meeting shall be entitled to a second or casting vote.

The Chair will preside at all meetings of the Committee, unless the Chair is not present, in which case the
members of the Committee that are present will designate from among such members the Chair for
purposes of the meeting.

A quorum for meetings of the Committee will be a majority of its members, and the rules for calling,
holding, conducting and adjourning meetings of the Committee will be the same as those governing the
Board unless otherwise determined by the Committee or the Board.

Meetings of the Committee should be scheduled to take place at least four times per year. Minutes of all
meetings of the Committee will be taken. The Chief Financial Officer of Tourmaline will attend meetings
of the Committee, unless otherwise excused from all or part of any such meeting by the Chairman.

The Committee will meet with the external auditor at least once per year (in connection with the
preparation of the year-end financial statements) and at such other times as the external auditor and the
Committee consider appropriate.

Agendas, approved by the Chair, will be circulated to Committee members along with background
information on a timely basis prior to the Committee meetings.

The Committee may invite such officers, directors and employees of the Company and its subsidiaries as it
sees fit from time to time to attend at meetings of the Committee and assist in the discussion and
consideration of the matters being considered by the Committee.

Minutes of the Committee will be recorded and maintained and circulated to Directors who are not
members of the Committee or otherwise made available at a subsequent meeting of the Board.

The Committee may retain persons having special expertise and may obtain independent professional
advice to assist in fulfilling its responsibilities at the expense of the Company as determined by the
Committee.

D-4

10.

Any members of the Committee may be removed or replaced at any time by the Board and will cease to be
a member of the Committee as soon as such member ceases to be a Director. The Board may fill vacancies
on the Committee by appointment from among its members. If and whenever a vacancy exists on the
Committee, the remaining members may exercise all its powers so long as a quorum remains. Subject to the
foregoing, following appointment as a member of the Committee each member will hold such office until
the Committee is reconstituted.

11.

Any issues arising from these meetings that bear on the relationship between the Board and Management
should be communicated to the Chairman of the Board by the Committee Chair.

Audit Committee Mandate and Terms of Reference

AUDIT COMMITTEE DISCLOSURE

The Board has adopted a written mandate and terms of reference for the Audit Committee, which sets out
the Audit Committee's responsibility for (among other things) reviewing the Company's financial statements and the
Company's public disclosure documents containing financial information and reporting on such review to the Board,
ensuring the Company's compliance with legal and regulatory requirements, overseeing qualifications, engagement,
compensation, performance and independence of the Company's external auditors, and reviewing, evaluating and
approving the internal control and risk management systems that are implemented and maintained by management.
A copy of the Audit Committee mandate and terms of reference is set forth above.

Composition of the Audit Committee and Relevant Education and Experience

The Audit Committee consists of Messrs. Blakely (Chair), Lamoreaux and MacDonald. Each of the
members of the Audit Committee is considered "financially literate" and each is considered "independent" within
the meaning of NI 52-110.

The Company believes that each of the members of the Audit Committee possesses: (a) an understanding
of the accounting principles used by the Company to prepare its financial statements; (b) the ability to assess the
general application of such accounting principles in connection with the accounting for estimates, accruals and
reserves; (c) experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and
level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that
can reasonably be expected to be raised by the Company's financial statements, or experience actively supervising
one or more individuals engaged in such activities; and (d) an understanding of internal controls and procedures for
financial reporting. For a summary of the education and experience of each member of the Audit Committee that is
relevant to the performance of his responsibilities as a member of the Audit Committee, see "Directors and Officers"
in the Annual Information Form.

Pre–Approval Policies and Procedures for the Engagement of Non–Audit Services

The Audit Committee is expected to adopt specific policies and procedures for the engagement of non–

audit services, as described in the mandate of the Audit Committee.

External Audit Service Fees

The following table summarizes the fees paid by the Company and its subsidiaries to its auditors,

KPMG LLP, for external audit and other services during the periods indicated.

Year

2011 .....................
2010 ....................

Audit Fees(1)
($)
325,000
300,000

Audit – Related Fees(2)
($)
405,000
104,000

Tax Fees(3)
($)
10,402
9,450

All Other Fees(4)
($)
72,800
745,000

D-5

Notes:

(1)

(2)

(3)

(4)

Represents the aggregate fees billed by the Company's external auditor in each of the last two fiscal years for audit
services.
Represents the aggregate fees billed in each of the last two fiscal years by the Company's external auditor for assurance
and related services that are reasonably related to the performance of the audit or review of the Company's financial
statements (and not reported under the heading "Audit Fees"). The services comprising the fees disclosed under this
category consisted of the conduct of due diligence procedures in connection with financings and acquisitions
undertaken by the Company.
Represents the aggregate fees billed in each of the last two fiscal years by the Company's external auditor for
professional services for tax compliance, tax advice and tax planning. The services comprising the fees disclosed under
this category consisted of tax consultations and tax compliance services.
Represents the aggregate fees billed in each of the last two fiscal years by the Company's external auditor for products
and services not included under the headings "Audit Fees", "Audit Related Fees" and "'Tax Fees".