Trident Resources S1 IPO registration

Trident Resources (TRR) Inactive S-1IPO registration

As filed with the Securities and Exchange Commission on November 10, 2008

Registration No. 333-

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Trident Resources Corp.

(Exact Name of Registrant as Specified in Its Charter)


Delaware	1311	98-0412788
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

1000, 444 — 7th Avenue S.W.

Calgary, Alberta, Canada T2P 0X8

(403) 770-0333

(Address, Including Zip Code, and Telephone Number, including Area Code, of Registrant’s Principal Executive Offices)

Trident Resources Corp.

3500 South Dupont Highway

Dover, Delaware 19901

(403) 770-0333

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

Copies to:


Kerry E. Berchem Elisabeth Cappuyns		Colin J. Diamond
Akin Gump Strauss Hauer & Feld LLP		White & Case LLP
One Bryant Park		1155 Avenue of the Americas
New York, New York 10036		New York, New York 10036
(212) 872-1000		(212) 819-8200

As soon as practicable after this Registration Statement becomes effective

(Approximate date of commencement of proposed sale to the public)

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule12b-2 of the Exchange Act. (Check one):


Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o

(Do not check if a smaller reporting company)

CALCULATION OF REGISTRATION FEE


	Proposed Maximum		Amount of
Title of Each Class of	Aggregate		Registration
Securities to be Registered	Offering Price(1)(2)		Fee
Common stock, par value US$0.0001 per share	US$	460,000,000.00	US$	18,078.00


(1)		Includes shares issuable upon exercise of the underwriters’ over-allotment option.

(2)		Estimated solely for the purpose of calculating the registration fee in accordance with Rule 457(o) under the Securities Act.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further Amendment that specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED NOVEMBER 10, 2008

PROSPECTUS

Trident Resources Corp.

Shares

Common Stock

This is our initial public offering and no public market exists for our common stock. The initial public offering price of our common stock is expected to be between US$ and US$ per share. We will apply to list our common stock on the New York Stock Exchange under the symbol “TZ.”

We have reserved shares, representing approximately 28.8% of the shares offered by us in this offering, for sale to certain existing holders of our securities pursuant to a right of first refusal agreement dated August 20, 2007, and shares representing approximately % of the shares offered by us in this offering, for sale to certain of our directors and employees and their family members, and certain other persons having business relationships with us. See “Certain Relationships and Related Party Transactions — Agreements Related to Our Securities — Right of First Refusal Agreement” and “Underwriting.”

Investing in our common stock involves a high degree of risk. See “Risk Factors” beginning on page 16.


		Underwriting	Proceeds, Before
		Discounts and	Expenses to Trident
	Price to Public	Commissions	Resources Corp.

Per Share	US$	US$	US$
Total	US$	US$	US$

The underwriters have a30-day option to purchase up to additional shares of common stock from us, solely to cover over-allotments of shares, if any.

Delivery of the shares of common stock will be made on or about , 2009.

The underwriters are offering the shares of common stock as set forth in “Underwriting.”

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.


Deutsche Bank Securities	Jefferies & Company

The date of this prospectus is , 2009.

TABLE OF CONTENTS


	Page No.

PROSPECTUS SUMMARY		1
RISK FACTORS		16
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		35
INDUSTRY AND MARKET DATA		36
EXCHANGE RATE DATA		36
USE OF PROCEEDS		37
DIVIDEND POLICY		38
CAPITALIZATION		39
THE RECAPITALIZATION		40
DILUTION		42
SELECTED HISTORICAL FINANCIAL AND OPERATIONAL INFORMATION		43
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		46
INDUSTRY		65
BUSINESS		68
MANAGEMENT		94
EXECUTIVE COMPENSATION		99
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		118
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		121
DESCRIPTION OF CAPITAL STOCK		126
SHARES ELIGIBLE FOR FUTURE SALE		130
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS		132
UNDERWRITING		134
LEGAL MATTERS		138
EXPERTS		138
WHERE YOU CAN FIND MORE INFORMATION		138
GLOSSARY OF NATURAL GAS AND COALBED METHANE TERMS		A-1
NSAI RESERVE REPORT AS OF JUNE 30, 2008		B-1
INDEX TO FINANCIAL STATEMENTS		F-1
EX-3.1: FOURTH AMENDED AND RESTATED CERTIFICATE OF INCORPORATION
EX-3.2: BYLAWS
EX-4.1: AMENDED AND RESTATED CERTIFICATE OF DESIGNATION
EX-4.2: AMENDED AND RESTATED CERTIFICATE OF DESIGNATION
EX-4.5: REGISTRATION RIGHTS AGREEMENT
EX-4.6: THIRD AMENDMENT & RESTATED REGISTRATION RIGHTS AGREEMENT
EX-4.7: RIGHT OF FIRST REFUSAL AGREEMENT
EX-4.8: AMENDED & RESTATED EXCHANGE RIGHTS AGREEMENT
EX-4.9: FORM OF SERIES A PREFERRED STOCK WARRANT
EX-4.10: FORM OF SERIES B PREFERRED STOCK WARRANT
EX-4.11: FORM OF 2006 LENDER WARRANT
EX-4.12: FORM OF 2007 LENDER WARRANT
EX-4.13: FORM OF 2007 LENDER SYNDICATION WARRANT
EX-4.14: COMMON STOCK PURCHASE WARRANT
EX-4.15: COMMON STOCK PURCHASE WARRANT
EX-21.1: SUBSIDIARIES
EX-23.1: CONSENT OF KPMG LLP
EX-23.2: CONSENT OF RYDER SCOTT COMPANY
EX-23.3: CONSENT OF SPROULE ASSOCIATES LIMITED
EX-23.4: CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC.

You should rely only on the information contained in this prospectus or any free writing prospectus prepared by or on our behalf. We have not authorized any other person to provide you with information that is different. If anyone provides you with different or inconsistent information, you should not rely on it. We are not making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only.

PROSPECTUS SUMMARY

This summary highlights selected information described more fully elsewhere in this prospectus. This summary may not contain all of the information that is important to you. You should read the entire prospectus, including the risks of investing in our common stock discussed in the “Risk Factors” section and our consolidated financial statements and related notes, before making an investment decision with respect to our common stock. References in this prospectus to “we,” “our,” “us,” “Trident” or similar terms mean Trident Resources Corp., a Delaware corporation, and its subsidiaries, unless the context indicates otherwise. References to “TRC” mean Trident Resources Corp. References to “TEC” mean Trident Exploration Corp, a Nova Scotia unlimited liability company, a subsidiary of TRC, and its subsidiaries. We have included as Appendix A to this prospectus a glossary of certain technical terms and abbreviations used in this prospectus that are important to an understanding of our business. In this prospectus, unless otherwise indicated, references to “C$” are to Canadian dollars and references to “US$” are to United States dollars.

TRIDENT RESOURCES CORP.

Overview

We are an independent natural gas production company focused on exploring for and exploiting unconventional natural gas resources, primarily in the Western Canadian Sedimentary Basin, or WCSB. We target coalbed methane, or CBM, in our core producing areas in the Mannville and Horseshoe Canyon CBM plays in Alberta, and shale gas in our emerging Montney Shale play in British Columbia. We are the largest CBM producer in the Mannville and one of the five largest in the Horseshoe Canyon. We also maintain a large exploratory acreage position in selected areas in the Northwestern United States. We intend to add to our existing reserve and production base by increasing our drilling activities in our large acreage positions in the Mannville and Horseshoe Canyon CBM plays, as well as beginning to drill in the Montney Shale play.

We have assembled an extensive property base. As of June 30, 2008, we had natural gas and oil leasehold interests in approximately 1.7 million gross (1.3 million net) acres, of which approximately 80% were undeveloped. Based on the evaluation of approximately 17% of our total net undeveloped acreage, we have identified approximately 1,700 evaluated surface drilling locations, which are locations specifically identified and scheduled by management as an estimate of our near-term multi-year drilling activities on existing acreage over the next five to seven years. Based on a reserve report prepared by the independent petroleum engineers Netherland, Sewell & Associates, Inc., or NSAI, as of June 30, 2008, our estimated proved reserves were 394.9 Bcfe (net), 58.8% of which represented estimated total proved developed reserves. At June 30, 2008, we owned interests in 943 gross (517 net) economic producing wells. Our June 30, 2008 estimated proved reserves are considered to be long-lived with a total proved reserve-to-production-ratio of 13.5 years based on net production in August 2008. As of October 1, 2008, we had four rigs drilling in the Mannville CBM plays and two rigs drilling in the Horseshoe Canyon CBM play. We expect to have one rig begin drilling in the Montney Shale play in the fourth quarter of 2008.

The following table identifies certain information concerning our exploration and production business as of June 30, 2008, unless otherwise noted:


	Estimated
	Net Proved		Daily		Estimated		Estimated		Average
	Reserves		Production		Gross		Net		Working
Area	(Bcfe)(1)		(Mmcfe/d)(2)		Acreage		Acreage		Interest(%)

Mannville, Alberta		166.3		41.6		742,586		550,610		74.2
Horseshoe Canyon, Alberta		228.6		38.6		346,791		213,805		61.7
Montney, B.C.		—		—		12,350		8,645		70.0
U.S.(3)		—		—		537,625		537,625		100.0
Other, Canada		—		—		82,986		33,910		40.9

Total		394.9		80.2		1,722,338		1,344,595		78.1


(1)		Based on the reserve report prepared by NSAI as of June 30, 2008.

(2)		Represents average daily net production in August 2008.

(3)		Consists of our properties located in Washington, Oregon and Idaho.

We have significant expertise in drilling and production techniques in our core areas of operation. The integration and innovation of our development techniques, particularly those related to multilateral development wells, have resulted in what we believe to be lower per-well operating costs and superior production rates compared to other industry participants in each of our core CBM producing areas. We believe we can leverage this expertise to develop other CBM opportunities in the WCSB.

Our senior management team, the majority of which joined us in late 2007 and early 2008, has an average of 25 years experience in the development of unconventional and conventional resources along with extensive exposure to the Canadian market. Todd A. Dillabough, our President, Chief Executive Officer and Chief Operating Officer, has over 24 years of industry experience in the WCSB. He worked with Pioneer Natural Resources Canada, Inc. from 1995 until November 2007, serving ultimately as President, Chief Executive Officer and Chief Operating Officer before that company was sold in November 2007. Alan G. Withey, our Chief Financial Officer, has over 16 years of finance and industry experience and has previously held the position of Chief Financial Officer with two public Canadian oil and gas companies.

We intend to dedicate the majority of our future capital expenditures to further the development and expansion of our core producing properties in the Mannville and Horseshoe Canyon CBM plays. We believe that these concentrated land positions represent a large, low-risk drilling portfolio, with a high probability of generating strong economic returns. We also intend to dedicate a portion of our capital expenditure budget to our activities in the Montney Shale play over the next few years, subject to successful operations in that area. Our estimated 2009 capital budget is C$ million.

Our Areas of Operation

Mannville CBM Plays. We are the largest CBM producer in the Mannville formation in Central Alberta, one of our primary areas of operation. We have been active in this area since 2000 and operated the first commercial project in the Mannville CBM plays in 2005. The Mannville formation extends over a vast area in Central Alberta and, according to the Canadian Society for Unconventional Gas 2007 Energy Evolution report, is estimated to contain up to 300 Tcf of natural gas resource potential, of which 0.02% has been produced to date. We operate approximately 70% of the total producing Mannville CBM assets in Canada. Our core producing CBM acreage is located in the Greater Corbett Creek area of the Mannville CBM plays. We operate the majority of the Greater Corbett Creek area through a joint venture with Nexen Inc., a Canadian-based energy company. We believe that the gas plant and pipeline infrastructure in the Greater Corbett Creek area currently has capacity to substantially match our five-year plan.

We have 128 evaluated surface drilling locations for development over the next five years on our existing acreage in the Greater Corbett Creek area. In each of these locations, we plan to drill multilateral development wells comprising a single vertical wellbore from the surface from which we drill up to four horizontal lateral legs per640-acre section, each targeting a different subsurface location in the main coal seam. Based on information in NSAI’s reserve report of June 30, 2008, the average economic proved undeveloped well in the Mannville CBM plays will have a gross estimated ultimate recovery, or EUR, of 1.8 Bcfe per well. As the field has matured, each new well has required less time to dewater, thereby shortening the period of time to reach peak natural gas production. This acceleration of the commencement of production achieves economics that we believe are in line with the leading resource plays in North America. As of June 30, 2008, we had drilled 306 gross wells and participated in 70 gross non-operated wells in the Mannville CBM plays.

Horseshoe Canyon CBM Play. The Horseshoe Canyon CBM play is a core producing area, and we are one of the five largest producers in this area. We have been active in this area since 2002. The play is currently the most successful commercial CBM play in the WCSB with significant, predictable and repeatable drilling opportunities at low cost and low geological risk. We believe most of our lands are in the most productive part of the entire play as demonstrated by our average peak production rate per well being 63% higher than the average industry rate in the Horseshoe Canyon CBM play. Based on information in NSAI’s reserve report of June 30, 2008, the average economic proved undeveloped well in the Horseshoe Canyon CBM play will have a gross EUR of 0.4 Bcfe per well. As of June 30, 2008, we had drilled 731 gross wells and participated in 87 gross non-operated wells in the Horseshoe Canyon CBM play. The Horseshoe Canyon CBM play produces no appreciable water and we believe it is currently the only significant producing dry coal play in North America. This characteristic has favorable economic implications since these wells do not incur the costs of dewatering and commence production at or near their respective peak rates. We acquired the majority of our lands in the Horseshoe Canyon CBM play through a participation and farm-out agreement with Husky Oil Operations Limited, a subsidiary of a major Canadian conventional operator. The area benefits from extensive existing gas plant and pipeline infrastructure.

We are seeking approval from the Alberta Energy Resources Conservation Board, or ERCB, to downspace from our currently approved four vertical wells per section to eight vertical wells per section, on approximately 475 sections of land, which is consistent with the other leading operators in the play. We have an inventory of over 1,500 evaluated surface drilling locations, representing 400 currently approved surface drilling locations and over 1,100 additional surface drilling locations subject to approval of our downspacing applications. We expect that the applications, which we commenced preparing in the second quarter of 2008, will require approximately one year for regulatory approval.

Montney Shale Gas Play. We own and operate a 70% working interest in lands located in the heart of the natural gas bearing Montney Shale gas trend, which covers a portion of Northeast British Columbia and Northwest Alberta. Two years of third-party unconventional gas production history from the Montney Shale play is currently available and recent third-party wells in the Montney area have resulted in initial production rates of 5-10 Mmcfe/d from single horizontal lateral wells with capital costs of C$5-6 million per well. These results imply economics that we believe to be consistent with the leading resource plays in North America. We believe this area is amenable to the use of the multilateral drilling techniques we have developed in the Mannville CBM plays. We have approximately 12,350 gross (8,645 net) largely contiguous acres in the Montney Shale play. Based on initial geological mapping from offsetting wells, we see exposure to three Montney Shale geological zones that have been produced or tested by industry participants in the area, and a fourth overlying geological zone where a shallower siltstone, called the Doig formation, could possibly be present within our acreage. We have 19 evaluated surface drilling locations in the Montney Shale play. We believe we may be able to exploit these four geological zones beneath these drilling locations and initially we plan to drill into one geological zone with two or three single horizontal lateral legs per well. Based on three lateral wells per section, the spacing would be approximately 216 acres. Depending on our initial drilling results, we may drill into additional zones. According to recently released public information, ARC Energy Trust has drilled the thickest net shale gas pay section in its Montney Shale drilling program to date at 150 feet, on acreage directly offsetting ours.

Other Areas. We own significant natural gas and oil interests in the Columbia River Basin area, which encompasses a thick basalt-capped sedimentary basin (approximately 4 million acres in size according to information recently published by Exxel Energy Corp.), on the Southern border of Washington with Oregon,

and the Snake River Basin area, an interbedded sedimentary and basalt basin on Oregon’s Eastern border with Idaho. Each of these areas is generally characterized as being exploratory in nature. Drilling depths are near 16,000 feet in the Columbia River Basin, and in the Snake River Basin there are two target zones at 3,000 feet and 10,000 feet. These areas reflect higher potential for significant gas discoveries in the event of success.

Gathering and Processing Facilities

We operate five gas processing facilities in the Greater Corbett Creek area and we hold an average 67% ownership interest in those plants. In the Horseshoe Canyon CBM play, we hold an average 48% ownership interest in 14 gas processing facilities and operate six of these plants. In addition, we process some of our gas through a third-party facility, for which we pay processing fees. In the Montney Shale play, we recently negotiated a 25 Mmcfe/d gross (17.5 Mmcfe/d net before royalties) gathering and processing agreement with a third party. This facility will be expanded to process the additional expected volumes of gas. As of June 30, 2008, our total processing capacity was approximately 216 Mmcfe/d for our combined owned facilities and we utilized approximately 47% of that capacity. We intend to build selectively, as required, supplemental treating capacity, pipeline gathering infrastructure and compression facilities to accommodate our long-term growth plans.

Our Strategy

Our primary objective is to achieve long-term growth and maximize stockholder value by pursuing the following strategies:


	•	Execute Targeted Development of Existing Reserve Base and Undeveloped Acreage. We seek to generate long-term reserve and production growth, and enhance net asset value, or NAV, by leveraging our experience and exploiting targeted development opportunities with prudent capital discipline. We intend to concentrate our drilling efforts on the development of the Mannville and Horseshoe Canyon CBM assets and the Montney Shale gas play. Based on current evaluated drilling opportunities and rig deployments, we believe that we have over four years of organic drilling opportunities in the Mannville CBM plays and the Montney Shale gas play and seven years of organic drilling opportunities in the Horseshoe Canyon CBM play.

	•	Continue to Apply Value-Maximizing Drilling and Operating Techniques in the Mannville CBM Plays. We commercialized the first Mannville CBM field in 2005 and have used multilateral drilling techniques to advance commercial exploration and development in this area. Our drilling techniques have accelerated dewatering and gas production with a high degree of economic success. We will seek to replicate our historical results by executing a drilling program that is designed to accelerate dewatering, production rates and cash flow from each well.

	•	Expand Our Proved Reserve Base and Surface Drilling Opportunities on Current Acreage. We believe that most of the Mannville and Horseshoe Canyon CBM acreage is located within the most prolific producing areas of each respective play. We intend to expand proved reserves and surface drilling opportunities on our current acreage through a balanced development and exploratory drilling program and downspacing when appropriate.

	•	Maintain Capital Discipline and Pursue Sustainable Returns. We seek to generate growth in reserves, production and cash flows at attractive rates of return on capital invested and maintain strict capital discipline as we grow our business. We will continue to strive for the lowest capital and operational costs possible. We constantly monitor our portfolio of investments using a range of metrics and seek to maximize returns by directing capital to development opportunities with the highest estimated risk adjusted returns.

	•	Continue to Maintain Operating Flexibility by Controlling Pipelines and Gas Plants. We intend to continue to operate the majority of our production, and control marketing and logistics, from wellhead to the regional sales gas pipelines. We intend to follow this strategy in new areas as well. By controlling gathering and gas plant assets, we believe we will be able to better control overall costs and maintain a high degree of operational flexibility.

	•	Opportunistically Seek Acquisitions in and Around Our Core Geographic Areas where We can Leverage Technology and Drilling and Production Improvements. We seek and evaluate acquisition opportunities in


		and around our core areas in order to optimize our acreage position, enhance NAV, and take advantage of our advanced drilling techniques and our low operating cost structure.

Competitive Strengths

We believe the following competitive strengths will help us successfully execute our strategies:


	•	Significant Resource Potential with Substantial Drilling Inventory and High Working Interest. Our evaluated and unevaluated surface drilling locations and our expected average proved undeveloped EURs imply significant natural gas resource potential beyond our net proved reserves of 394.9 Bcfe as of June 30, 2008. This may be further increased through execution of selected acquisitions that are accretive to our current operations.

	•	Proven, Industry-Leading, Advanced Drilling and Operation Technology. We have adopted and improved advanced techniques in drilling and production operations to create significant and scalable opportunities across current core producing areas as well as new potential areas. In particular, our innovative techniques related to multilateral development wells have contributed significantly to our operating efficiency as evidenced by our faster development period and overall operated cost structure per flowing Mcfe, which we believe is consistently below the average industry operating costs of our conventional and unconventional competitors combined.

	•	Low-Risk Drilling Inventory of Long-Lived Assets in Geographically Concentrated Areas. Resource plays such as the Mannville and the Horseshoe Canyon CBM plays typically display relatively low geological risk over a broad geographical area, as evidenced by our historical gross drilling success rate of more than 97% from 1,419 wells through June 30, 2008. Our June 30, 2008 estimated proved reserves are considered long-lived with a total proved reserve-to-production-ratio of 13.5 years based on net production in August 2008. In addition, each of our asset concentrations is located on acreage that is fairly contiguous in nature and lies within the boundaries of our existing pipeline gathering systems and gas plants, creating significant operating synergies and reducing capital commitments.

	•	High Degree of Operational Control. We operate over 65% of our producing assets in our core producing areas and over 90% of our exploration opportunities. We have control over the gathering, processing and transportation of the majority of our production in the WCSB. This high degree of operating control enables us to implement our proven drilling techniques and well designs, manage our operating costs and capital expenditures, and determine the timing of exploration, development and exploitation activities.

	•	Attractive Cost Structure and Drilling to Production Cycle Time. The integration of our advanced drilling and operation practices in our operated field areas has helped us achieve net operating costs of approximately C$1.30/Mcfe, which are below the industry average of our conventional and unconventional competitors combined. We believe that our cost structure of approximately C$1.40/Mcfe and C$1.20/Mcfe in the Mannville CBM and the Horseshoe Canyon CBM plays, respectively, is significantly lower than that of our direct competitors in the same play. During the first half of 2008, we achieved company-wide operating costs of approximately C$1.80/Mcfe (net after royalties before transportation).

	•	Experienced Management Team and Staff Focused on Delivering Long-Term Stockholder Value. Our senior management has deep industry experience that complements a team with a history of innovation and significant knowledge of our assets. Our team was instrumental in the commercialization of the first Mannville CBM field, while also creating significant positions in other CBM and shale gas plays.

Risk Factors

Investing in our common stock involves significant risks. You should carefully consider the risks described in “Risk Factors” before making a decision to invest in our common stock. If any of these risks actually occurs, our business, financial condition or results of operations would likely be materially adversely affected. In such case, the

trading price of our common stock would likely decline, and you may lose all or part of your investment. The following is a summary of some of the principal risks we face:


	•	natural gas prices are volatile, and a significant decline in natural gas prices could significantly affect our financial results and financial condition and impede our growth;

	•	drilling for and production of CBM and other unconventional natural gas resources involve many business and operating risks, any one of which could materially adversely affect our business;

	•	the unavailability or high cost of drilling rigs, equipment, supplies and personnel could adversely affect our ability to execute, on a timely basis or within our budget, our exploration and development plans;

	•	delays encountered while securing permits related to development in Alberta could adversely affect our ability to execute our exploration, development and production plans on a timely basis or within our budget, including any delays in obtaining downspacing permits from the ERCB;

	•	provincial royalty regimes are a significant factor in the profitability of natural gas production in Canada and changes in these regimes could adversely affect our profitability;

	•	our operations may be adversely affected by Canadian, Alberta and British Columbian legislation and the exercise of discretion by authorities implementing those laws and regulations;

	•	our reserve estimates depend on many assumptions, some of which may prove to be inaccurate, and any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves; and

	•	unless we replace the reserves that we produce through exploration and development, our existing reserves and production will decline, which would adversely affect our business, our financial condition and results of operations.

The Recapitalization

Concurrently with the closing of this offering, we intend to borrow US$ million under a new revolving credit facility and issue US$ of senior notes, which will represent our only borrowings following the closing of this offering. Using the aggregate net proceeds from this offering, the new revolving credit facility and the senior notes, together with cash on hand, we intend to effect a recapitalization, which will result in our capital structure being materially different from our current structure. Following the closing of this offering and our recapitalization, our capital structure will consist solely of outstanding shares of common stock, a new revolving credit facility and new senior notes.

The following transactions, which we refer to collectively as the “recapitalization,” will take place upon the closing of this offering:


	•	We will repay all of the outstanding indebtedness under our existing credit facilities, consisting of the TEC first lien credit agreement, the TEC second lien credit agreement, the TRC 2006 credit agreement and the TRC 2007 subordinated credit agreement, together with related prepayment premiums, fees and expenses.

	•	Our 5,607,559 outstanding shares of Series A and Series B preferred stock, representing all of the outstanding shares of Series A and Series B preferred stock as at June 30, 2008, will be mandatorily redeemed for common stock. The redemption payment to which holders of the preferred stock are entitled will be automatically applied to the exercise price of the preferred warrants to purchase shares of our common stock that were issued as part of a unit with each share of Series A and Series B preferred stock. As a result, the redemption of our preferred stock effectively results in its conversion into shares of our common stock. The number of shares of common stock issuable upon exercise of the warrants will vary depending on the initial public offering price of our common stock in this offering based on an adjustment mechanism that provides holders of the preferred stock with a minimum compounded annual rate of return of 15%. For a description of the adjustment mechanism, see “The Recapitalization — Preferred Stock and Preferred Warrants.” Assuming a closing date for this offering of , 2009 and based on the midpoint of the estimated price range shown on the cover page of this prospectus, we will issue shares of common


		stock upon exercise of the preferred warrants, which includes shares of common stock as payment for accrued dividends and additional shares of common stock to provide the minimum compounded annual rate of return.


	•	The number of shares of our common stock issuable upon exercise of our 2006 and 2007 debt warrants that were issued in connection with the TRC 2006 credit agreement and the TRC 2007 subordinated credit agreement will be subject to upward adjustment. The debt warrants are currently exercisable for 18,150,162 shares of common stock, representing all of the exercisable debt warrants as at June 30, 2008, subject to adjustment based on the number of shares of our common stock issued in connection with the redemption of our preferred stock and the automatic exercise of the preferred warrants. As the number of such shares issued increases, the number of shares issuable upon exercise of the debt warrants increases as a percentage thereof. For a description of the adjustment mechanism, see “The Recapitalization — 2006 and 2007 Debt Warrants.” Based on the midpoint of the estimated price range shown on the cover page of this prospectus, the debt warrants will adjust upon the closing of this offering and become exercisable for shares of common stock upon exercise of the warrants.

As a result of the adjustment mechanism associated with our Series A and Series B preferred stock, the number of shares of common stock outstanding after this offering will vary significantly depending on the initial public offering price. In addition, the number of shares of common stock issuable upon the exercise of our 2006 and 2007 debt warrants will vary depending on the initial public offering price. See “ — Summary Financial Data — Impact of Changes in Net Proceeds from this Offering on the Recapitalization” and “The Recapitalization” for further information.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 1000, 444 — 7th Avenue S.W., Calgary, Alberta, Canada T2P 0X8 and our telephone number at that address is(403) 770-0333. We maintain a website atwww.tridentexploration.ca. Information on our website is not incorporated by reference into, and does not constitute a part of, this prospectus.

The Offering


Common stock offered by us		shares

Common stock to be outstanding immediately after this offering		shares

Use of proceeds		We estimate that the net proceeds from this offering will be approximately US$ , after deducting the underwriting discount and estimated offering expenses. We intend to use the net proceeds from this offering, together with the borrowings under our new revolving credit facility and the issuance of our senior notes, to (i) repay all of the outstanding indebtedness under our existing credit facilities, including related fees, expenses and certain prepayment premiums, and (ii) pay fees and expenses associated with our new revolving credit facility and senior notes. See “Use of Proceeds.”

Proposed NYSE symbol		“TZ”

As a result of the adjustment mechanism associated with our Series A and Series B preferred stock that provides the holders thereof with a minimum compounded annual rate of return of 15%, the number of shares to be outstanding after this offering will vary significantly depending on the initial public offering price of our common stock in this offering. Similarly, the number of shares of common stock issuable upon exercise of our 2006 and 2007 debt warrants will vary depending on the initial public offering price of our common stock in this offering. See “Summary Financial Data — Impact of Changes in Net Proceeds from the Offering on the Recapitalization” and “The Recapitalization.”

The number of shares of common stock to be outstanding immediately after this offering does not include the following amounts, also outstanding at June 30, 2008, except where otherwise noted:


	•	shares of common stock issuable in exchange for (i) vested options to purchase shares of TEC common stock granted to optionholders under TEC’s stock option plan, at a weighted average exercise price of C$ per share of common stock and (ii) outstanding shares of TEC common stock held by third-party TEC stockholders;

	•	shares of common stock issuable upon exercise of outstanding warrants granted to a TRC consultant and pursuant to our 2006 and 2007 debt warrants, at a weighted average exercise price of C$ per share of common stock;

	•	20,000 shares of common stock issuable in exchange for an equal number of shares of TEC common stock issuable upon the exercise of outstanding warrants, at an exercise price of C$4.20 per share of common stock (reduced from 25,000 outstanding shares as at June 30, 2008); and

	•	shares reserved for issuance under our equity incentive plan, under which options to purchase shares have been granted at a weighted average exercise price of US$ per share of common stock.

Unless otherwise indicated, the number of shares of common stock to be outstanding immediately after this offering and all information in this prospectus:


	•	is based on shares of common stock outstanding as of , 2008;

	•	assumes an initial public offering price of US$ per share, the midpoint of the estimated price range shown on the cover page of this prospectus;

	•	assumes no exercise of the underwriters’ option to purchase from us up to additional shares of common stock; and

	•	gives effect to the issuance upon the closing of this offering, assuming a closing date for this offering of , 2009, of shares of common stock pursuant to the automatic exercise of the preferred warrants in connection with the mandatory redemption of our Series A and Series B preferred stock, which includes shares of common stock as payment for accrued dividends and additional shares of common stock to provide the minimum compounded annual rate of return. See “The Recapitalization — Preferred Stock and Preferred Warrants.”

Summary Financial Data

The following tables set forth our summary financial data as of and for each of the periods indicated. We derived the summary financial data as of and for the years ended December 31, 2005, 2006 and 2007 from our audited consolidated financial statements included elsewhere in this prospectus. We derived the summary financial data as of June 30, 2008, and for each of the six-month periods ended June 30, 2007 and 2008 from our unaudited interim consolidated financial statements included elsewhere in this prospectus. We prepared the unaudited information on a basis consistent with that used in preparing our audited consolidated financial statements, and it includes all adjustments, consisting of normal and recurring items, that we consider necessary for a fair presentation of the financial position and results of operations for the unaudited periods.

You should read the following summary financial information in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our historical financial statements, including the notes thereto, included elsewhere in this prospectus.


	Years Ended December 31,									Six Months Ended June 30,
	2005			2006			2007			2007			2008
	(In thousands of Canadian dollars,
	except share and per share data)

Consolidated Statements of Operations and Comprehensive Loss Data:
Revenue:
Production revenue	C$	40,258		C$	139,631		C$	201,993		C$	107,692		C$	110,554
Expenses:
Operating		13,571			43,086			59,450			28,606			29,068
General and administrative		20,177			25,378			20,198			9,336			22,398
Depletion, depreciation and accretion(2)		38,800			766,228			219,243			104,144			32,034

Total expenses		72,548			834,692			298,891			142,086			83,500

Income (loss) from operations:		(32,290	)		(695,061	)		(96,898	)		(34,394	)		27,054
Other income and expenses:
Financing charges		30,088			311,572			(31,838	)		(27,875	)		162,209
Restructuring charges		—			—			20,746			17,198			2,410
Loss (gain) on disposition of equity investment		—			(21,242	)		—			—			423

Total other expense (income)		30,088			290,330			(11,092	)		(10,677	)		165,042

Loss before undernoted items:		(62,378	)		(985,391	)		(85,806	)		(23,717	)		(137,988	)
Taxes:
Capital taxes		1,188			165			156			172			98
Deferred income taxes (recovery)		(13,366	)		(64,633	)		—			—			—

Income tax expense (benefit)		(12,178	)		(64,468	)		156			172			98

Net loss before undernoted items:		(50,200	)		(920,923	)		(85,962	)		(23,889	)		(138,086	)
Loss (earnings) from equity method investment		(400	)		1,663			—			—			—
Minority interests		2,363			786			1,760			—			(1,942	)
Net loss and comprehensive loss:	C$	(48,237	)	C$	(918,474	)	C$	(84,202	)	C$	(23,889	)	C$	(140,028	)
Accretion of Series A preferred stock		(144,482	)		—			—			—			—
Accrued dividends on Series A preferred stock		(21,223	)		(37,370	)		(38,908	)		(19,766	)		(16,187	)
Foreign exchange gain (loss) on Series A preferred stock		16,138			(1,815	)		66,246			37,539			(11,559	)

Net loss and comprehensive loss available to common stockholders	C$	(197,804	)	C$	(957,659	)	C$	(56,864	)	C$	(6,116	)	C$	(167,774	)

Net loss per share of common stock:
Basic and diluted	C$	(8.23	)	C$	(35.18	)	C$	(2.08	)	C$	(0.22	)	C$	(6.13	)

Weighted average number of shares of common stock used in calculating loss per share (thousands):
Basic and diluted		24,043			27,221			27,330			27,330			27,349


	As of December 31,									As of June 30, 2008
													Pro Forma as
	2005			2006			2007			Actual			Adjusted(1)
	(In thousands of Canadian dollars)

Consolidated Balance Sheet Data:
Total current assets	C$	103,120		C$	200,279		C$	212,359		C$	202,794		C$
Property, plant and equipment(2)		879,236			765,449			633,889			663,433
Total assets		993,898			995,498			883,744			900,261
Total current liabilities		123,279			147,915			71,265			72,865
Total liabilities(3)		676,246			1,463,328			1,433,417			1,587,108
Series A preferred stock		368,981			408,166			380,828			408,574
Total stockholders’ deficit		(51,329	)		(875,996	)		(930,501	)		(1,095,421	)


(1)		Gives effect to this offering, and based on an initial public offering price of US$ per share, the midpoint of the estimated price range shown on the cover page of this prospectus, we estimate that we will receive net proceeds from this offering of approximately US$ million, after deducting the underwriting discount and estimated offering expenses. In addition, this information gives effect to the issuance upon the closing of this offering of shares of common stock pursuant to the automatic exercise of the preferred warrants in connection with the mandatory redemption of our Series A and Series B preferred stock, which includes shares of common stock as payment for accrued dividends and additional shares of common stock to provide the minimum compounded annual rate of return. We have assumed a closing date of , 2009 for the purpose of calculating accrued dividends and the minimum compounded annual rate of return. As a result of the adjustment mechanism associated with our Series A and Series B preferred stock that provide for a minimum compounded annual rate of return, the number of shares to be outstanding after this offering will vary significantly depending on the initial public offering price. Similarly, the number of shares of common stock issuable upon exercise of our 2006 and 2007 debt warrants will vary depending on the initial public offering price. A US$1.00 increase (decrease) in the assumed initial public offering price of US$ per share would increase (decrease) the net proceeds to us from this offering by approximately US$ , assuming the number of shares offered, as set forth on the cover page of this prospectus, remains the same and after deducting the underwriting discount and estimated offering expenses payable by us.

(2)		We incurred a ceiling test write-down of C$112.8 million in 2007, compared to a C$682.1 million write-down in 2006 and a C$20.2 million write-down in 2005. In the six months ended June 30, 2008, we did not incur a ceiling test write-down, compared to a C$43.3 million write-down in the same period in 2007. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Full Cost Method of Accounting and the Ceiling Test.”

(3)		Other than under “Pro Forma as Adjusted,” includes the Series B preferred stock and the Series A preferred stock embedded derivative. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Accounting for Derivative Instruments.”


	Years Ended December 31,									Six Months Ended June 30,
	2005			2006			2007			2007			2008
				(In thousands of Canadian dollars)

Consolidated Statements of Cash Flows Data:
Net cash provided by (used for) operating activities	C$	(3,579	)	C$	16,127		C$	55,257		C$	15,119		C$	58,765
Net cash provided by (used for) financing activities		671,436			701,410			91,257			(9,095	)		(33	)
Net cash used for investing activities		(604,979	)		(664,377	)		(128,402	)		(76,826	)		(94,266	)
Other Financial Data:
Capital expenditures		503,064			653,384			89,734			37,633			61,863
EBITDA(1)		8,473			94,858			103,359			52,552			54,313
Adjusted EBITDA(1)		6,510			65,395			122,609			70,375			83,017


(1)		We define EBITDA as income before financing charges (consisting of interest and foreign exchange gains and losses), taxes, depletion, depreciation and accretion. In addition, we define Adjusted EBITDA as EBITDA


		adjusted to reflect (i) restructuring charges, (ii) long-term incentive plan expenses, (iii) loss (gain) on dispositions, (iv) unrealized losses (gains) on commodity contracts, (v) earnings or losses from equity investments and (vi) minority interests. We use EBITDA and Adjusted EBITDA to facilitate a comparison of our operating performance on a consistent basis from period to period that we believe provides a more complete understanding of factors and trends affecting our business than U.S. generally accepted accounting principles, or GAAP, measures alone. Management uses EBITDA and Adjusted EBITDA as a measurement tool for evaluating our actual operating performance compared to budget and prior periods, as well as a tool for determining incentive based compensation. EBITDA and Adjusted EBITDA assist us in comparing our operating performance on a consistent basis because it removes the impact of our capital structure (primarily interest charges), asset base (primarily depreciation and amortization) and items outside the control of our management team (taxes) from our results of operations. We consider EBITDA and Adjusted EBITDA to be an important supplemental measure of our performance and believe it is frequently used by analysts, investors and other interested parties in the evaluation of companies in our industry.

		EBITDA and Adjusted EBITDA should not be considered as a substitute for net income or income from operations, as determined in accordance with GAAP. We compensate for these limitations by relying primarily on our GAAP results and using EBITDA and Adjusted EBITDA only as a supplement to those results. EBITDA and Adjusted EBITDA are not defined by GAAP and you should not consider them in isolation or as a substitute for analyzing our results as reported under GAAP. EBITDA and Adjusted EBITDA have limitations as an analytical tool, including the following:

		• EBITDA and Adjusted EBITDA do not reflect our interest expense;

		• although depreciation and amortization are non-cash expenses in the period recorded, the assets being depreciated and amortized may have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect the cash requirements for such replacements;

		• EBITDA and Adjusted EBITDA do not reflect our tax expense or the cash requirements to pay our taxes; and

		• other companies may calculate EBITDA and Adjusted EBITDA differently, limiting its usefulness as a comparative measure.

		Because of these limitations, EBITDA and Adjusted EBITDA should not be considered as the primary measures of the operating performance of our business. We strongly urge you to review the GAAP financial measures included in this prospectus, our consolidated financial statements, including the notes thereto, and the other financial information contained in this prospectus, and not to rely on any single financial measure to evaluate our business.

		The following is a reconciliation of net loss to EBITDA and Adjusted EBITDA:


	Years Ended December 31,									Six Months Ended June 30,
	2005			2006			2007			2007			2008
	(In thousands of Canadian dollars)

Consolidated Statements of Operations and Comprehensive Loss Data:
Net loss and comprehensive loss	C$	(48,237	)	C$	(918,474	)	C$	(84,202	)	C$	(23,889	)	C$	(140,028	)
Financing charges		30,088			311,572			(31,838	)		(27,875	)		162,209
Income tax expense (benefit)		(12,178	)		(64,468	)		156			172			98
Depletion, depreciation and accretion		38,800			766,228			219,243			104,144			32,034

EBITDA	C$	8,473		C$	94,858		C$	103,359		C$	52,552		C$	54,313

Restructuring charges	C$	—		C$	—		C$	20,746		C$	17,198		C$	2,410
Long-term incentive plan expense		—			—			—			—			12,642
Loss (gain) on disposition		—			(21,242	)		—			—			423
Unrealized losses (gains) on commodity contracts		—			(5,772	)		264			625			11,287
Loss (earnings) from equity investment		400			(1,663	)		—			—			—
Minority interests		(2,363	)		(786	)		(1,760	)		—			1,942

Adjusted EBITDA	C$	6,510		C$	65,395		C$	122,609		C$	70,375		C$	83,017

Impact of Changes in Net Proceeds from this Offering on the Recapitalization

The following table shows the impact of the recapitalization on our pro forma capitalization assuming different initial public offering prices within the estimated price range shown on the cover page of this prospectus. The table assumes no change in the number of shares offered as set forth on the cover page of this prospectus.

Assumed Initial Public Offering Price

Midpoint

of the

− US$1.00

− US$0.50

Range

+US$0.50

+US$1.00

Pro Forma Capitalization as of June 30, 2008

Total outstanding shares of common stock

Shares issuable upon the exercise of the 2006 and 2007 debt warrants

Summary Historical Reserve and Operating Data

The following table presents summary information regarding our estimated net proved reserves as of December 31, 2006 and 2007, and as of June 30, 2008 and certain of our historical operating data for the years ended December 31, 2006 and 2007, and as of June 30, 2008. All calculations of estimated net proved reserves have been made in accordance with the rules and regulations of the Securities and Exchange Commission, and except as otherwise indicated, give no effect to federal or state income tax laws. Our estimated net gas reserves for the years ended December 31, 2006 and 2007 are based on reserve reports prepared by Sproule Associates Limited, or Sproule, independent petroleum engineers dated as of December 31, 2006 and 2007, respectively. Our estimated net gas reserves for the six months ended June 30, 2008 are based on a reserve report prepared by NSAI dated as of June 30, 2008. You should evaluate the data below in conjunction with “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Business — Reserves Summary.”


	As of
	December 31,				As of June 30,
	2006		2007		2008

Reserve Data:
Estimated net proved reserves:
Proved developed producing (Mmcfe)(1)		87,420.6		92,016.6		221,789.0
Proved developed non-producing (Mmcfe)(1)		16,564.2		15,675.0		10,455.9

Total proved developed (Mmcfe)(1)		103,984.8		107,691.6		232,244.9
Proved undeveloped (Mmcfe)(1)		60,307.8		58,416.0		162,695.7

Total proved reserves (Mmcfe)(1)		164,292.6		166,107.6		394,940.6

PV-10 (in millions)(2)	C$	366.9	C$	402.5	C$	1,456.3
Income tax effect discounted at 10% (in millions of C$)		—		—		(169.0	)

Standardized measure of discounted future net cash flows (in millions)(3)	C$	366.9	C$	402.5	C$	1,287.3

Price used for proved reservePV-10 (AECO-C index price in C$ per Mcfe as of December 31 and NGX AB-NIT index price in C$ per Mcfe as of June 30)	C$	6.13	C$	6.52	C$	11.70


	Years Ended						Six Months
	December 31,						Ended June 30,
	2006			2007			2008

Drilling activity:
Gross (net) new wells drilled in period
Productive wells		392 (232	)		75 (35	)		32 (20	)
Dry wells		28 (20	)		7 (5	)		—

Total wells		420 (252	)		82 (40	)		32 (20	)
Operating Data:
Net Production(4):
Mannville, Alberta (Mmcfe)(5)		9,044			14,193			7,366
Horseshoe Canyon, Alberta (Mmcfe)(6)		11,381			14,616			6,843

Total natural gas (Mmcfe)		20,425			28,809			14,209

Average net realized price (C$ per Mcfe)	C$	6.55		C$	7.02		C$	8.57
Expenses (C$ per Mcfe):
Operating(7)	C$	2.11		C$	2.06		C$	2.05
General and administrative		1.24			0.70			1.58
Depletion, depreciation and accretion(8)		4.12			3.18			2.25


(1)		Represents our natural gas and oil reserves and is based on the reserve reports prepared by Sproule as of December 31, 2006 and 2007 and by NSAI as of June 30, 2008. This includes, as of December 31, 2006 and 2007, net proved reserves of oil of 14.8 MBbls and 14.6 MBbls, respectively, and as of June 30, 2008, includes no net proved reserves of oil.


(2)		PV-10 is a non-GAAP measure that represents the present value of estimated future net revenues attributable to our reserves using constant prices, as of the calculation date, discounted at 10% per year on a pre-tax basis.PV-10 was determined based on the market prices for natural gas as of December 31, 2006 and 2007 and as of June 30, 2008. The natural gas prices used for the calculations as of December 31, 2006 and 2007 and as of June 30, 2008 were C$6.13, C$6.52 and C$11.70, respectively. These prices were based on AECO-C prices as of December 31, 2006 and 2007, and NGX AB-NIT as of June 30, 2008, and were adjusted to account for transportation costs and any difference in quality as applicable. The oil prices used for the calculations as of December 31, 2006 and 2007 were C$67.59 and C$93.44, respectively.PV-10 differs from standardized measure of discounted future net cash flows because it does not include the effects of income taxes on future net cash flows.PV-10 does purport to present an estimate of fair market value of our reserves. AlthoughPV-10 is not a financial measure calculated in accordance with GAAP, management believes that the presentation ofPV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to any given company affect the amount of estimated future income taxes, we believe that the use of a pre-tax measure is helpful when comparing companies in our industry.

(3)		Calculated based on our net proved reserves of oil and natural gas. The “standardized measure of discounted future net cash flows” is the present value of our estimated future net cash flows, discounted at 10% per year, calculated using constant pricing, utilizing the same prices that we used to calculatePV-10 as described in footnote (2). The standardized measure of discounted future net cash flows does not purport to present the fair market value of our natural gas reserves and is not indicative of actual future net cash flows.

(4)		Includes oil and natural gas liquid production converted to Mcfe at a ratio of 6 net Mcfe for each net barrel produced. Total net oil and natural gas liquid production for the years ended December 31, 2006 and 2007 and the six months ended June 30, 2008 was 20,295 Bbls, 16,951 Bbls and 15,904 Bbls, respectively. Total net natural gas liquid production for the years ended December 31, 2006 and 2007 and the six months ended June 30, 2008 was 15,588 Bbls, 11,906 Bbls and 11,451 Bbls, respectively.

(5)		Includes conventional net production on the Mannville properties.

(6)		Includes conventional net production and other unconventional natural gas resource play net production (including from the Belly River) on the Horseshoe Canyon properties.

(7)		Operating expenses include costs of field contractors, compression, chemicals and treating supplies, operating overhead and minor well workovers, as well as transportation expenses, which includes costs to move saleable gas from the plant outlet to its ultimate point of sale.

(8)		Depletion, depreciation and accretion expenses per Mcfe do not include ceiling test impairment charges. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Full Cost Method of Accounting and the Ceiling Test.”

RISK FACTORS

You should consider carefully each of the risks described below, together with all of the other information contained in this prospectus, before deciding to invest in shares of our common stock. If any of the following risks were actually to occur, then our business, financial condition or results of operations could be materially affected. In that case, the trading price of our common stock could decline and you could lose all or part of your investment.

Risks Related to Our Business

Natural gas prices are volatile, and a significant decline in natural gas prices could significantly affect our financial results and financial condition and impede our growth.

Our cash flows from operating activities, profitability and revenue depend substantially upon the prices of natural gas, and a drop in prices could significantly affect our financial results and impede our growth. Because approximately 99% of our sales for the year ended December 31, 2007 and for the six months ended June 30, 2008 came from natural gas, our financial results are more sensitive to movements in natural gas prices than those of oil and gas companies that produce balanced portfolios of both oil and gas. Additionally, movements in natural gas prices impact Crown lessor royalties imposed in Alberta, which are based on a sliding scale with higher royalties paid on higher production rate wells and higher gas prices, and lower royalties paid on lower production rate wells and lower gas prices. See “— Provincial royalty regimes are a significant factor in the profitability of natural gas production in Canada and changes in these regimes could adversely affect our profitability.”

Natural gas is a commodity with a price set by broad market forces. Canadian gas prices are generally lower and more volatile than U.S. gas prices. Prices for natural gas fluctuate widely in response to relatively minor changes in the supply and demand for natural gas, market uncertainty and a variety of additional factors beyond our control, such as:


	•	Canadian, U.S. and foreign supply and reserve levels of natural gas;

	•	price, quantity, delivery, location and specific timing of foreign liquid natural gas imports;

	•	inventories in storage;

	•	level of consumer product demand, including a decrease in overall consumer consumption resulting from a general downturn in the economy;

	•	Canadian, U.S. and foreign governmental regulations and taxation;

	•	impact of the Canadian dollar exchange rates on gas and oil prices;

	•	technological advances affecting energy consumption;

	•	removal of the U.S. moratorium on offshore drilling;

	•	transportation and processing costs, proximity and capacity of gas pipelines and other transportation facilities;

	•	price and availability of alternative fuels;

	•	Canadian, U.S. and global economic conditions;

	•	impact of energy conservation efforts;

	•	political and economic conditions in gas and oil producing countries, including embargoes and continued hostilities in the Middle East, West Africa and other sustained military campaigns, acts of terrorism or sabotage;

	•	actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;

	•	supply disruptions due to weather related incidents, including hurricanes; and

	•	increases or decreases in demand due to weather patterns, including heat waves and cold spells.

In the past, natural gas prices have been extremely volatile and we expect this volatility to continue. Gas prices have been at high levels over the past several years compared to prior years. For example, from January 1, 2005 through June 30, 2008 the Natural Gas Exchange’s natural gas index price, or NGX AB-NIT, fluctuated between C$4.50 and C$12.75, with annual average prices of C$8.61 in 2005, C$6.76 in 2006, C$6.53 in 2007 and C$8.65 through June 30, 2008. The NGX AB-NIT as of June 30, 2008 was C$11.70 per Mcfe. If our results of operations for the six months ended June 30, 2008 were calculated using the June 30, 2007 price of C$5.80 per Mcfe, no additional charges or write-downs in the carrying value of our proved reserves would be required. The pre-taxPV-10 of our proved reserves as of June 30, 2008 calculated using the NGX AB-NIT gas price as of June 30, 2007 of C$5.80 per Mcfe is C$616 million for 370.181 Bcfe net of total proved reserves. In addition, if the pre-taxPV-10 of our proved reserves as of June 30, 2008 had been calculated using the NGX AB-NIT gas price as of December 31, 2007 of C$6.52 per Mcfe, it would amount to C$740 million for 376.028 Bcfe net of total proved reserves. There has been a decline in natural gas prices after June 30, 2008 which, if continuing, may adversely affect the carrying value of our proved reserves in the third quarter of 2008. The September 30, 2008 NGX AB-NIT gas price was C$6.12 per Mcfe.

Even relatively modest drops in natural gas prices can significantly affect our financial results and financial condition and impede our growth. Lower natural gas prices may not only decrease our near term cash flow but also may reduce the amount of natural gas that we can produce economically over time because we would delay reinvesting in the future drilling programs set forth in our long-term plans. This could have a material adverse effect on our financial results and financial condition and may result in our having to make substantial downward adjustments to our estimated proved reserves.

Drilling for and production of coalbed methane, or CBM, and other unconventional natural gas resources involve many business and operating risks, any one of which could materially adversely affect our business.

Our business is subject to all of the operating risks associated with drilling for and producing natural gas, including fires, explosions and blow-outs, uncontrollable flows of underground natural gas, uncontrollable flows of formation water, natural disasters, pipe or cement failures, casing collapses, drilling and service tool failures, losses in a well bore, abnormally pressured formations and environmental hazards, such as natural gas leaks, pipeline ruptures and discharges of toxic gases, including releases of gas containing hydrogen sulfide. For example, in 2006, two contractors servicing a well suffered minor injuries as a result of the blow-out of a well plug. If any of these events occur, we could incur substantial losses as a result of loss of life, severe damage to, and destruction of, property, natural resources and equipment, pollution and other environmental damage,clean-up responsibilities, regulatory investigation and penalties, suspension of our operations and repairs to resume operations.

In addition, drilling for and production of CBM and other unconventional natural gas resources poses additional operating risks different from conventional oil and gas production operating risks, including:


	•	higher capital costs than similar depth conventional gas wells because of necessary alternative drilling or completion techniques, water production, treatment and disposal costs, additional compression, or other factors;

	•	relatively long pilot production test times to determine commerciality or optimal practices, as compared to conventional gas fields;

	•	peak production rates, time to reach peak rate, and time that peak rate can be sustained, are subject to substantially greater uncertainty for CBM and other unconventional natural gas wells than conventional natural gas wells;

	•	most CBM wells, including those wells in the Mannville CBM plays, must be dewatered before significant gas production can be achieved, which in some instances can take more than a year;

	•	difficulties associated with producing water, including scale formation, corrosion or backpressure caused by inefficient pumping, restrictions on surface facilities capacity, failure of water disposal wells to adequately handle required volumes of produced water and related dewatering;

	•	difficulties associated with extreme weather conditions including potential freezing;


	•	concerns with production and disposal or use of salt water from some coals;

	•	more wells per section in some instances to optimally and cost-effectively develop reserves;

	•	reduced wellhead pressures needed for production, leading to larger flow lines or additional compression; and

	•	complexity of development of multiple coal seams.

We may drill wells that are unproductive or, although productive, do not produce gas in economic quantities. Unsuccessful drilling activities could result in higher costs without any corresponding revenues. Furthermore, the successful completion of a well does not ensure a profitable return on your investment.

Furthermore, because the unconventional natural gas industry is relatively new in Canada and the United States, operators drilling or producing unconventional natural gas wells may be subject to greater public scrutiny than operators drilling or producing conventional wells. Any problems experienced by others drilling or producing unconventional natural gas wells (even in other basins) might adversely impact us, through additional regulations or greater difficulty in acquiring surface leases, permits or regulatory approvals.

The Horseshoe Canyon wells produce no appreciable water, in contrast to other CBM productive wells that do traditionally produce water. The Horseshoe Canyon wells may become uneconomic in the event that water or other deleterious substances are encountered, which could impair or prevent the production of gas from such well.

These risks could result in unanticipated costs and delays which could materially adversely affect our financial condition and results of operations. In addition, our drilling inventory is subject to the aforementioned risks and may not be as large as we believe.

The unavailability or high cost of drilling rigs, equipment, supplies and personnel could adversely affect our ability to execute, on a timely basis or within our budget, our exploration and development plans.

Our exploration, development and production activities depend on the availability of drilling rigs, equipment, supplies and qualified personnel. There is a finite number of rigs available in Western Canada and the availability of rigs can decrease and costs can increase significantly at times of high drilling activity. Utilization of rigs generally peaks during the winter months. In 2005 and 2006, the utilization rate of rigs was at times above 90%, compared to peak utilization rates of between 65% and 70% in 2007 and between 62% and 65% in 2008. The number of rigs we employ fluctuates throughout the year based on a number of factors, including seasonality. Our two rigs in the Mannville CBM plays are leased under two-year contracts and our other rigs are leased under30-day contracts. We also rely on the availability of other key supplies such as casing, slotted liners, line pipe, vessels, compressors, specialized drilling fluids, specialized completion materials and operational chemicals.

We require personnel with technical expertise to operate drilling and production equipment. In particular, we need crews to operate our contracted rigs and the use of3-D seismic and other advanced technologies requires experienced technical personnel. There has been a shortage of skilled labor in Western Canada for a number of years, including a shortage of rig crews in Alberta, and there is significant competition to recruit available crews. The development of the oil sands industry has increased competition for labor and other resources, resulting in increasing cost pressures in Canada. This competition would likely increase if there is an increase in drilling activity as occurred in 2005 and 2006, which contributed to substantial increases in labor costs for rig crews.

Shortages of key items of equipment or qualified personnel to operate could increase our costs and restrict or delay our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the drilling of new wells or significant increase in labor costs could adversely affect our ability to increase our reserves and production and reduce our revenue. Higher labor costs could cause certain of our projects to become uneconomic and therefore not be implemented, reducing our production. Any of these events could have a material adverse effect on our financial condition and results of operations.

Delays encountered while securing permits related to development in Alberta could adversely affect our ability to execute our exploration, development and production plans on a timely basis or within our budget, including any delays in obtaining downspacing permits from the ERCB.

We are required to obtain permits and other authorizations related to various aspects of our exploration, development and production activities. In particular, one of our key strategic goals in the Horseshoe Canyon CBM play is to downspace to eight vertical wells per section on approximately 475 sections of land. We began the process of applying for downspacing permits in the second quarter of 2008 to the Alberta Energy Resources Conservation Board, or ERCB, which we expect will take approximately one year for full regulatory approval. We also require permits to enable us to cross private lands to commence exploratory drilling activities. These permits are usually available in the ordinary course, but historically we have experienced delays during certain periods because of the large volume of applications being received by regulatory authorities in Alberta. As a result, we have experienced delays in drilling and such delays may continue or worsen in the future. Any such delays in the future, including a delay in our application to downspace wells in the Horseshoe Canyon CBM play, could have a material adverse effect on our revenue growth, financial condition and results of operations.

Provincial royalty regimes are a significant factor in the profitability of natural gas production in Canada and changes in these regimes could adversely affect our profitability.

In Alberta and British Columbia, most of the production of natural gas is subject to Crown lessor royalties that must be paid to the provincial government. In February 2007, the Alberta Government began a review of its royalty regime for conventional oil, natural gas and CBM and oil sands. In October 2007, the Alberta Government released a report titled “The New Royalty Framework” containing the Government’s proposals for Alberta’s new royalty regime, which is scheduled to take effect on January 1, 2009. The proposed royalty regime includes: (i) new, simplified royalty formulas for conventional oil and natural gas that will operate on sliding scales that are determined by commodity prices, well productivity and measured depths of natural gas wells and (ii) a policy of “shallow rights reversion,” the objective of which is for the mineral rights to shallow gas geological formations that are not being developed to revert back to the Government and be made available for resale. Under the proposed regime, new natural gas royalty rates will range from 5% to 50% with rate caps at a natural gas price of C$18.72/Mcfe or at a well productivity of 568 Mcfe/d. It is possible that legislative, regulatory and systems updates will be introduced before changes become fully effective in January 2009. However, we do not expect any such updates to have a material adverse effect on us.

In British Columbia, the royalty reserved to the Crown in respect of natural gas production is determined by a sliding scale based on a reference price, which is the greater of the price obtained by the producer, and a prescribed minimum price. However, when the reference price is below the select price (a parameter used in the royalty rate formula), the royalty rate is fixed. Any future increase in royalty rates may have a material adverse effect on our business, financial condition and results of operations. See “Business — Regulation in Canada — Royalties and Incentives.”

Ownership and operation of our natural gas wells could subject us to environmental claims and liability.

The oil and natural gas industry is subject to extensive environmental regulation pursuant to federal, provincial, and local legislation in Canada and federal, state and local legislation in the United States. A violation of this legislation may result in the imposition of fines, the issuance of “clean up” orders, the loss of necessary permits or other penalties. Liability may also be imposed upon us as an owner or operator of property, regardless of whether we actually caused a problem thereon. Legislation regulating our industry may be changed to impose higher standards and potentially more costly obligations. For example, Canada is a signatory to the United Nations’ Framework Convention on Climate Change and is considering enacting Greenhouse Gas, or GHG, emissions reduction regulations which may have an impact on our business if enacted. In 2007, the Government of Canada announced plans to implement GHG emissions intensity reduction legislation to apply to all upstream gas facilities emitting 3,000 tonnes of GHG emissions or more per year. The proposed legislation, if implemented, will require an 18% reduction from 2006 emissions intensity levels by January 1, 2010, and a 2% annual reduction thereafter for older facilities. New facilities (those whose first year of operation was 2004 or later) will be required to improve their emissions intensity by 2% annually commencing after their third year of operation. This latter reduction covers most of our facilities. In 2007,

Alberta also enacted GHG emissions intensity reduction legislation applicable to large facilities in Alberta, and in 2008, British Columbia introduced a carbon tax and legislation (not yet in force) providing for the establishment of a “cap and trade” system for large emitters of GHGs. The U.S. Congress has been considering legislation that would require substantial reductions in GHG emissionsand/or increase the cost of emitting GHG. Some states and regions in the United States, including California, have implemented programs requiring reductions in GHG emissions. British Columbia, along with a number of states and other provinces, is a member of the Western Climate Initiative, which seeks regional reduction of GHG emissions. Our exploration and production facilities and other operations and activities emit GHGs which will likely subject us to possible future legislation regulating emissions of GHGs. This current and possible future legislation may impact demand for natural gas in Canada and the United States. The direct or indirect costs of this and other future legislation may have a material adverse affect on our business. See “Business — Environmental.”

We are not fully insured against certain environmental risks, either because such insurance is not available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic damages) is not available on economically reasonable terms. Accordingly, our properties may be subject to liability due to hazards that cannot be insured against, or that have not been insured against due to prohibitive premium costs or for other reasons.

We have not established a separate reserve fund for the purpose of funding our estimated future environmental, including reclamation and abandonment obligations. As a result, we may not be able to satisfy these obligations. Any site reclamation or abandonment costs incurred in the ordinary course in a specific period will be funded out of our cash flow from operations. If we are unable to fully fund the cost of remedying an environmental obligation, we might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy, which could have an adverse affect on our financial condition and results of operations.

Our operations may be adversely affected by Canadian, Alberta and British Columbian legislation and the exercise of discretion by authorities implementing those laws and regulations.

All of our production activities currently take place in the Mannville CBM plays and the Horseshoe Canyon CBM play in Alberta, and we intend to commence an exploratory drilling program in the Montney Shale play in British Columbia in the fourth quarter of 2008. We are, therefore, significantly affected by Canadian, Alberta and British Columbian provincial and local legislation governing matters, such as land tenure, prices, royalties, production rates, environmental protection, income and the exportation of natural gas, as well as other matters. The oil and gas industry is also subject to regulation by governmental authorities in such matters as the awarding or acquisition of exploration and production rights, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields (including restrictions on production), deeper rights reversions at the end of the primary term of a lease, expected shallow rights reversion in favor of the Crown, and possibly expropriation or cancellation of land tenure rights.

Government regulations may change from time to time in response to economic or political conditions. For example, in the first quarter of 2008, Alberta enforced CBM regulations that were previously established in late 2007 and we had to shut in 53 wells, 35 of which we operated and 18 of which we did not operate, due to non-compliance with the regulatory data approvals required under the newly established regulations. As of June 30, 2008, 19 wells continued to be shut in, 14 of which we operated and five of which we did not operate. We expect to have the remaining wells operating by the end of the third quarter of 2008, but we may have to shut in additional wells in the future, which could affect our results of operations. The exercise of discretion by governmental authorities under existing laws and regulations and the adoption of new or modification of existing laws and regulations affecting the oil and natural gas industry could reduce demand for natural gas, increase our costs and have a material adverse impact on us.

Non-compliance with Alberta and British Columbian legislation with respect to employees’ health and safety could result in suspension or closure of our operations or the imposition of other penalties against us.

Oil and gas companies operating in Alberta and British Columbia are subject to significant regulation with respect to their employees’ health and safety. Companies in both provinces are required to self-report accidents and infractions, but regular and random audits of operations are also part of the regulatory process. Previous violations of the same requirement are taken into account when assessing penalties and subsequent behavior may be subjected to escalating levels of oversight and loss of operating freedom. Non-compliance with regulations may in the future result in suspension or closure of our operations or the imposition of other penalties against us.

Our reserve estimates depend on many assumptions some of which may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Estimating natural gas reserves is complex and inherently imprecise. It requires interpretation of available technical data and making many assumptions about future conditions, including price and other economic conditions. It also includes projecting production rates and the timing of development expenditures, and analyzing the available geological, geophysical, production and engineering data, knowing that the extent, quality and reliability of this data can vary. This process also requires assumptions relating to ultimate reserve recovery, timing and amount of capital expenditures, marketability of gas, royalty rates, assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. For these reasons, all reserve estimates are to some degree speculative.

Actual future production, natural gas prices, cash flows, taxes, development expenditures, abandonment and reclamation expenditures, general and administrative expenses, operating expenses and quantities of recoverable natural gas reserves may vary significantly from our assumptions and estimates in this prospectus. Therefore, the amount of natural gas that we ultimately recover may differ materially from the estimated quantities and net present value of proved reserves shown in this prospectus and may have a material adverse effect on our financial condition. For example, if gas prices at June 30, 2008 had been C$1.00 less per Mcfe, then thePV-10 of our proved reserves as of June 30, 2008 would have decreased by C$139.6 million, from C$1,456.3 million to C$1,316.7 million, and our proved reserves would have increased by 1.504 Bcfe, from 394.940 Bcfe to 396.444 Bcfe, as a result of the sliding royalty scale in Alberta and British Columbia. At September 30, 2008, the NGX AB-NIT gas price was C$6.12 per Mcfe.

ThePV-10 of our proved reserves is calculated using hedged gas prices and is determined in accordance with the rules and regulations of the Securities and Exchange Commission, or the SEC. Over time, estimates of proved reserves may be periodically adjusted to reflect production history, results of exploration and development, prevailing natural gas prices and other factors, many of which are beyond our control.

The present value of future net cash flows from our proved reserves will not necessarily be the same as the current market value of our estimated proved reserves.

We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate. Actual future net cash flows from our gas properties also will be affected by factors such as:


	•	the actual prices we receive for gas;

	•	our actual operating costs in producing gas;

	•	royalties paid to the provinces of Alberta and British Columbia;

	•	the amount and timing of actual production;

	•	changes to reservoir conditions in the geological formation throughout the life of a CBM gas field;


	•	the amount and timing of our capital expenditures;

	•	supply of and demand for natural gas; and

	•	changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with the Financial Accounting Standards Board’s Statement of Financial Accounting Standards No. 69,Disclosures about Oil and Gas Producing Activities, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the gas industry in general. Both world credit markets and world energy markets have recently been very weak and their continued weakness may adversely affect the gas industry generally and our ability to finance our capital expenditure program at currently budgeted levels.

Unless we replace the reserves that we produce through exploration and development, our existing reserves and production will decline, which would adversely affect our business financial condition and results of operations.

Producing gas reserves are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. CBM production generally increases initially as a consequence of the dewatering process and then declines gradually. Exploration and development are our main methods of replacing and expanding our asset base. We intend to dedicate the majority of our capital expenditure in the immediate future to further developing our core producing properties in the Mannville CBM plays and the Horseshoe CBM play. In addition, beginning in the fourth quarter of 2008, we intend to begin a drilling program in the Montney Shale play with a view to conversion of Montney reserve potential to proved reserves. Our exploration and development activities in these properties and other properties we pursue in the future may not be successful for various reasons. Exploration activities involve numerous risks, including the risk that no commercially productive natural gas reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and tying-in wells are often uncertain. Our exploration and development operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:


	•	inadequate capital resources;

	•	lack of acceptable prospective acreage;

	•	mechanical difficulties such as major gas plant and regional pipeline failures;

	•	unexpected drilling conditions;

	•	pressure or irregularities in formations;

	•	equipment failures or accidents;

	•	lack of storage;

	•	weather conditions;

	•	title problems;

	•	compliance with governmental regulations or required regulatory approvals;

	•	inadequate access to gas gathering and processing infrastructure and capacity;

	•	unavailability or high cost of drilling rigs, equipment or labor;

	•	approvals of third parties;

	•	reductions in natural gas prices; and

	•	limitations in the market for natural gas.

We may be unable to execute our plans to acquire and develop properties in the Mannville CBM plays, the Horseshoe CBM play and the Montney Shale play. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations.

If actual rates of production in the Montney Shale play are lower than, or capital costs per well in the Montney Shale play are higher than, we expect, we may not be able to establish economic wells in this play.

We believe a significant portion of our production growth in the immediate future will come from the Montney Shale play. Our expectation for establishing economic wells in this play is based on seismic analyses and the reported success of third parties in establishing economic wells in the area. We also believe that our leasehold positions are amenable to multilateral wells, which typically have lower capital costs than traditional well designs. All of our activities in the play to date have been exploratory and we do not expect to begin drilling until the fourth quarter of 2008. Wells we establish in the Montney Shale play may not reach the production rates reported by third parties in the play and the capital costs per well may be higher than we anticipate as the multilateral drill techniques we have used in the past may not be equally effective. As a result, we may not be able to establish economic wells in the region and we may not be able to execute our business plan in the Montney Shale play. If we are unable to establish economic wells in the play we would have to seek other opportunities, which could have a material adverse affect on our future prospects.

Competition in the natural gas industry is intense and many of our competitors have resources that are greater than ours.

The Mannville CBM plays, the Horseshoe CBM play and the Montney Shale play are highly competitive environments for acquiring prospects and productive properties, marketing natural gas and securing equipment and trained personnel. Many of our competitors, including large independent oil and natural gas companies, possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to acquire and develop more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional prospects and make commercial discoveries in the future depends on our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. We may be unable to compete successfully in the future to acquire and explore for prospective resource properties, develop reserves, market hydrocarbons, attract and retain quality personnel or raise additional capital. If we are unable to compete effectively, our operating results and financial position may be adversely affected.

We have incurred significant net losses since our inception and may incur additional significant net losses in the future.

We have not been profitable since we started our business. We incurred net losses of C$137.9 million for the six months ended June 30, 2008, C$84.2 million in 2007 and C$918.5 million in 2006. Our capital has been employed in an increasingly expanding natural gas exploration and development program with a focus on finding significant natural gas resources. We are subject to numerous challenges and uncertainties that may impede our ability to ultimately find and commercialize such resources. In addition, the development of unconventional natural gas resources, particularly CBM resources, requires significant capital investments and time prior to the achievement of commercial rates of production. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future.

Properties we acquire in the future may not produce as anticipated, and we may be unable to determine resource potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

Properties we acquire in the future may not produce as expected and may subject us to increased costs and liabilities, including environmental liabilities, which could have a material adverse effect on our financial condition and results of operations. We review acquired properties prior to acquisition in a manner generally consistent with industry practices, but we are not able to identify all potential costs and liabilities nor are we able to review in depth every individual property involved in an acquisition. Ordinarily, we will focus our review efforts on what we perceive to be higher value properties and on properties with known adverse conditions and will sample the remainder. However, even a detailed review of records and the physical properties may not reveal all existing or potential problems or permit us to become sufficiently familiar with the properties to assess fully their condition, any deficiencies, or development potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily identifiable even when an inspection is undertaken.

The significant majority of our producing properties are located in two CBM geographic areas, making us vulnerable to risks associated with having our production concentrated in two geographic areas.

The significant majority of our producing properties are geographically concentrated in two CBM geographic areas in Alberta: the Mannville CBM plays and the Horseshoe Canyon CBM play. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these properties caused by significant governmental regulation in Alberta, transportation capacity constraints, curtailment of production, natural disasters, adverse weather conditions or other events which impact these areas.

Our identified drilling location inventories are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

As of June 30, 2008, only 535 of our 1,700 identified drilling locations were attributable to proved undeveloped reserves. These potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, natural gas prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous identified drilling locations we have will ever be drilled or if we will be able to produce natural gas or oil from these or any other identified drilling locations. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business.

Financial difficulties of, or conflicting investment priorities with, our partners could adversely affect the exploration and development of our projects, particularly with respect to properties in which we have a working interest but which we do not operate.

We operate approximately 65% of the development properties and over 90% of the exploration properties in which we have a working interest but the balance of these properties are operated by our joint venture partners. In particular, we have joint ventures with Nexen Inc., a Canadian energy company, in connection with the exploitation, development and operation of wells in Greater Corbett Creek area of the Mannville CBM plays, and with Husky Oil Operations Limited, a subsidiary of a major Canadian conventional operator, with respect to the Horseshoe Canyon CBM play. We recently had a dispute with one of our joint venture partners which is now fully resolved, but disputes between us and any of our joint venture partners in the future could materially adversely affect our development and production in these areas. As of August 31, 2008, properties in Greater Corbett Creek area accounted for approximately 52% of our total net daily production and properties in the Horseshoe Canyon CBM play accounted for 48% of our total net daily production.

We operate our properties at lower costs than our partners and obtain higher revenue net of royalties after operating expenses in the Mannville CBM plays and the Horseshoe Canyon CBM play respectively of approximately C$1.40 and C$1.20 per Mcfe for the first six months of 2008 from those properties than from our non-

operated properties. Unless we operate our properties, our joint ventures do not provide us with the same realization of our targeted returns on capital in these drilling or developmental activities. Liquidity and cash flow problems encountered by our partners, operators and the co-owners of our properties may lead to a delay in the pace of exploration or development which may be detrimental to a project. Furthermore, our farm-in and joint venture partners may be unwilling or unable to pay their share of the costs of projects as they become due. The success and timing of drilling and other development activities on properties operated by others depend upon a number of factors that are outside of our control, including the timing and amount of capital expenditures, the operator’s expertise and financial resources, the approval of other participants in drilling wells and the selection of technology. Moreover, during times of extreme weather conditions, we have experienced staffing issues with one of our joint venture partners that impacted production and operational maintenance. As a result, during the winter of 2007, a significant number of wells were not on production for approximately three weeks and we incurred additional costs to return them to production. At times, we require the agreement of our partners to advance development and exploration projects. If this agreement is not made, our planned activities can be delayed or the scope of our activities may be altered. Previously, our partners have issued independent operations notices to initiate activity that was not planned or if such activity was planned, the timing of development or exploration was different from our expected timing. We attempt to convince partners to agree with our planned development schedule and generally have been able to develop the fields in accordance with our general plans. Our dependence on operators and other working interest owners for these projects and our reduced ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in these drilling or other development activities.

We have limited protection for our operating practices and depend on the expertise of our employees and contractors.

We use operating practices that management believes are of significant value in developing CBM resources. In particular, we believe that our drilling, completion and production techniques related to multilateral development wells have to date provided us with a competitive advantage. In most cases, patent or other intellectual property protection is unavailable for these practices. Our use of independent contractors in most aspects of our drilling and some completion operations makes the protection of such technology more difficult. Moreover, we rely on the technological and practical expertise of the independent contractors that we retain for our operations. We have no long-term agreements with these contractors, and thus we cannot be sure that we will continue to have access to this expertise. In addition, public record laws in Alberta and British Columbia do not provide confidentiality for our specific industry practices and materials for more than one year with respect to exploratory wells and more than one month with respect to our development drilling and completion techniques. As a result, our competitors may be able to take advantage of expertise that we have developed and we will not be able to prevent them from doing so, which could reduce our competitive advantage.

Our level of indebtedness and the restrictive covenants contained in TRC’s and TEC’s existing and future indebtedness reduce our financial and operational flexibility.

We are leveraged and have substantial debt service obligations. While we will use the net proceeds from this offering to repay our existing debt obligations, we also plan to enter into a new revolving loan facility and issue senior notes. Our current and expected level of indebtedness and the related restrictive covenants affect our operations in several ways, including the following:


	•	a significant portion, approximately 32% of Adjusted EBITDA for the first six months of 2008, of our cash flow must be used to service our indebtedness that is notpaid-in-kind;

	•	it affects our flexibility in planning for, and reacting to, changes in the economy or in our industry and may otherwise impact the decisions we make regarding our current and future operations;

	•	it impairs our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general corporate purposes;

	•	it restricts our ability, among other things, to dispose of assets, pay dividends and enter into specified investments or acquisitions;


	•	a default under our credit facilities could result in required principal payments that we may not be able to meet, resulting in higher penalty interest ratesand/or debt maturity acceleration; and

	•	our level of indebtedness may place us at a competitive disadvantage compared to our competitors that have less debt.

A high level of indebtedness increases the risk that we may default on our debt obligations or defer capital expenditures directed at increasing production and reserves to meet cash interest payments. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the principal and interest on our debt. If we do not have enough money, we may be required to refinance all or part of our existing debt, sell assets or borrow more money, but we may not be able to do so on terms acceptable to us or at all.

In addition, agreements that govern our indebtedness require us to maintain compliance with restrictive covenants, specified financial ratios and satisfy certain financial condition tests. We expect that agreements governing any future indebtedness will contain similar significant covenants, including financial covenants. Our ability to comply with these covenants may be affected by events beyond our control, and, as a result, we may be unable to meet them. In the event of a breach of these covenants and any resulting default, we may be unable to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. Both world credit markets and world energy markets have recently been very weak and their continued weakness may adversely affect the gas industry generally and our ability to finance our capital expenditure program at currently budgeted levels.

Market conditions or operational impediments may hinder our access to natural gas markets or delay our production.

Market conditions or a lack of satisfactory natural gas transportation arrangements may hinder our access to natural gas markets or cause us to delay our production. The availability of a ready market for our natural gas production depends on a number of factors, including the demand for and supply of natural gas, the amount of natural gas in local and North America-wide storage, the inventory within the market and the proximity of our producing wells to pipelines. We do not have any current capacity restraints with respect to storage of our natural gas production nor do we have any current capacity shortfalls in either transportation or gathering/processing. The marketability of our natural gas production depends in substantial part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. We may be required to shut in natural gas wells or delay initial production for lack of a market or because of the inadequacy or unavailability of natural gas pipelines or gathering system capacity. If that occurs, we would be unable to realize revenue from such wells. This could result in considerable delays from the initial discovery of a reservoir to the actual production of the natural gas and realization of cash flow. In addition, temporary outages and shutdowns of the natural gas pipelines upon which we depend to transport our gas periodically occur. These outages may disrupt our ability to produce gas and may hinder our production from affected wells both during the outage and for a period of time after the outage ends. These events would have an adverse impact on our cash flow.

Fluctuations in the value of the Canadian and U.S. dollars may affect the value of our common stock, the level of our debt measured in either currency, as well as our results of operations and financial condition.

The majority of our operations and our principal executive offices are in Canada. Accordingly, although our financial statements are presented in accordance with United States generally accepted accounting principles, or GAAP, our functional currency is the Canadian dollar and we report our results in Canadian dollars. Most of our revenue and expenses are generated and denominated in Canadian dollars. However, the majority of our debt is denominated in U.S. dollars. Any appreciation of the U.S. dollar against the Canadian dollar will increase our debt service costs. In addition, a weakening of the U.S. dollar against the Canadian dollar could increase the cost of our natural gas production relative to U.S. producers. We have sought to reduce the effect of Canadian dollar-U.S. dollar

exchange rate fluctuations by placing US$50 million dollars purchased in the open market in a money market account in the first six months of 2008; however, the dollar value of this transaction may be insufficient to cover all of our interest due. We may choose not to enter into a similar transaction for 2009 or any future years and any such transaction may not perform adequately as a hedging mechanism. Therefore, fluctuations in exchange rates could have an adverse effect on our financial condition and results of operations. In addition, if you are a U.S. stockholder, the value of your investment in us will fluctuate as the U.S. dollar rises and falls against the Canadian dollar. If the U.S. dollar falls in value relative to the Canadian dollar, then any U.S. operations that we may develop in the future would be less profitable to us because any profits reported by our U.S. operations would contribute less to our consolidated Canadian dollar earnings because of the weaker U.S. dollar.

The coalbeds from which we produce methane gas generally contain water, which may hamper our ability to produce gas in commercial quantities as a result of unanticipated water disposal costs.

We are subject to regulations that prohibit the discharge of water produced as part of our CBM gas production operations onto the surface land and otherwise regulate how we handle this water. As is typical of most methane-bearing coalbeds, wells in the Mannville CBM plays produce large volumes of salt water in their earlier years of production in order for the gas to detach from the coal and flow to the well bore. This water must then be re-injected into a deeper saltier water horizon. Our ability to remove and dispose of sufficient quantities of water from the coal seam determines whether or not we can produce gas in commercial quantities. Although the water handling facility is a closed system, the possibility of an uncontrolled release of salt water on the surface is possible. The produced water is sometimes transported with steel pipelines from the lease and injected into off-lease disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability. As a result of these activities we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment.

The Montney Shale gas prospect potentially has acid gases (H₂S and CO₂) present at high enough levels to be hazardous in the event of an uncontrolled gas release.

Hydrogen sulphide (H₂S) is a naturally occurring gas found in oil and natural gas contained in many geological formations. We have identified H₂S in and around the Montney Shale play in British Columbia in both the Montney formation and Doig formation. Other operators testing the Montney formations in the area commonly measure H₂S concentrations of 0.01% or less within a 10 mile radius of our lands, and have measured H₂S concentrations of up to 1.0%. The Doig formation has measured concentrations of H₂S as high as 4.0% within a 10 mile radius of our lands. Concentrations of 0.01% are considered “immediately dangerous to life and health” and require respiratory protection at or above this level for exposed workers. At concentrations of 0.02% and above death is expected within hours and concentrations above 0.07% will cause immediate loss of consciousness with death following in four to six minutes. The largest risk is that of a well blow-out or uncontrolled release of H₂S-bearing natural gas. An uncontrolled release of natural gas can spread rapidly in the atmosphere requiring large areas to be evacuated quickly. If we experience a well blow-out or uncontrolled release of H₂S-bearing natural gas, we could incur substantial losses as a result of loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage,clean-up responsibilities, regulatory investigation and penalties, suspension of our operations and repairs to resume operations.

In addition, reservoirs in both the Montney formation and Doig formation in the Montney Shale play may contain natural gas that is high in acid gas (H₂S and CO₂) content, which must be treated for the removal of H₂S and CO₂ prior to marketing. If we cannot obtain sufficient capacity at sour gas treatment facilities for our natural gas with a high H₂S concentration or at treatment facilities for our natural gas with a high CO₂ concentration, or if the cost to obtain such capacity significantly increases, we could be forced to delay production and development or experience increased production costs which can negatively affect our economics.

The coalbeds from which we produce gas may be drained by offsetting production wells over long periods of time.

Our drilling locations are spaced primarily using640-acre spacing in the Mannville CBM plays and80-acre spacing units in the Horseshoe Canyon CBM play. Producing wells located on the640-acre spacing units contiguous with our drilling locations in the Mannville CBM plays and 80 to160-acre spacing units contiguous with the Horseshoe Canyon CBM play locations may drain the acreage underlying our wells. In certain areas, if a substantial number of productive wells are drilled on spacing units adjacent to our properties, it could have an adverse impact on the economically recoverable reserves of our properties that are susceptible to such drainage.

Under full cost accounting rules, we may be required to write-down the carrying value of our properties.

We use the full cost method of accounting. Under full cost accounting rules, we may be required to write-down the carrying value of our properties when natural gas prices decrease or when other circumstances arise, including when we have substantial downward adjustments of our estimated proved reserves or increases in our estimates of development costs. Specifically, under full cost accounting rules, we are required to perform what we call a “ceiling test” each quarter. The ceiling test provides that capitalized costs, less related accumulated depletion and depreciation and deferred income taxes, may not exceed the “ceiling” of the sum of: estimated future net revenues from proved reserves, discounted at 10% per annum and based on unescalated period-end prices, the lower of cost or estimated fair value of property not being depleted or depreciated, less income tax effects related to differences in the book and tax basis of natural gas properties. If the ceiling is calculated to be less than the net book value of our natural gas properties, then an impairment is deemed to have occurred and a non-cash write-down is required, which could materially impact our financial statements. In the first half of 2008, we did not incur a ceiling test write-down, compared to a C$43.3 million write-down in the first half of 2007. For 2007, we incurred a ceiling test write-down of C$112.8 million, compared to C$682.1 million in 2006. Depending on the magnitude of any future impairments, a ceiling test write-down could significantly reduce our net income or produce a net loss. Ceiling test computations use commodity prices prevailing on the last day of the relevant period, making it impossible to predict the timing and magnitude of any future write-downs. In addition, to the extent that our finding and development costs may increase, we will become more susceptible to ceiling test write-downs in low price environments.

Unforeseen title defects may result in a loss of entitlement to production and reserves.

Ownership of some of our properties could be subject to prior undetected claims or interests. We conduct title reviews from time to time according to industry practice prior to the purchase of most of our natural gas producing properties or the commencement of drilling wells. However, title reviews, if conducted, do not guarantee that an unforeseen defect in the chain of title will not arise to defeat a claim by us. If any such defect were to arise, our entitlement to the production and reserves associated with such properties could be jeopardized, and could have a material adverse effect on our financial condition, results of operations and our ability to timely execute our business plan. Aboriginal peoples have claimed aboriginal title and rights to portions of Western Canada. We are not aware that any claims have been made in respect of our property and assets; however, if a claim arose and was successful, this could have an adverse effect on us and our operations.

With respect to our U.S. lands, it is our practice, in acquiring gas and oil leases, or undivided interests in gas and oil leases, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, we rely upon the judgment of gas and oil lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. Prior to drilling a gas or oil well, however, it is the normal practice in the gas and oil industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed gas or oil well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain work must be done to cure deficiencies in the marketability of the title, and such curative work entails expense. The work might include obtaining affidavits of heirship or causing an estate to be administered. Our failure to obtain these rights may adversely impact our ability in the future to increase production and reserves.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our customers and by counterparties to our derivative contracts, in particular since we have relatively few customers. Some of our customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any unanticipated increase in the nonpayment or nonperformance by our customersand/or counterparties could impact our cash flow.

Certain of our undeveloped leasehold acreage is subject to leases that may expire in the near future.

As of June 30, 2008, we held gas leases on approximately 475,712 net acres in the Mannville CBM plays and Horseshoe Canyon CBM play that are still within their original lease term and are not currently held by production. We typically acquire a four or five-year primary term when the original lease is acquired, with an option to extend the term in specific circumstances prescribed by regulation. Under the terms of the Crown leases which govern these properties, unless we establish commercial production on the properties subject to these leases during their term, these leases will expire. Continuations of expiring non-producing leases are reviewed by the Alberta Department of Energy, or DOE, on a case by case basis. A continuation of an operated lease is generally applied for if technical data demonstrates the possibility of a productive lease in the near-term. Leases covering approximately 154,075 net acres are scheduled to expire between December 31, 2008 and December 31, 2009 and an additional 368,804 net acres are scheduled to expire before December 31, 2010. If our leases expire and we cannot obtain a lease continuation from the DOE, we would lose our right to develop the related properties unless we subsequently nominate and successfully repurchase the impacted leases from the Alberta Government.

Certain lands in Alberta are subject to split title issues with respect to natural gas rights and coal rights.

There are some lands in Alberta (both Crown and freehold lands) where by virtue of the initial grant or through subsequent ownership transfers, as applicable, fee simple title to coal rights and natural gas rights in the same land are held by different parties. On March 28, 2007, the Alberta Energy and Utilities Board, now the ERCB, concluded that, for the purpose of issuing certain well licensing, pooling and holding applications, the owners of natural gas rights also had CBM developmental rights. As a result of this decision and until otherwise ruled by the Alberta Courts, the ERCB will continue granting regulatory approval to produce CBM to the owners of natural gas rights. The owners of coal rights have applied for and were granted leave on November 6, 2007 by the Alberta Court of Appeal to appeal the ERCB’s decision to determine if the ERCB erred in concluding that the holders of natural gas rights should receive regulatory approval to produce CBM. As a result, owners of natural gas rights were able to get regulatory approval to produce CBM, but until the Alberta Court of Appeal made an actual determination of ownership, uncertainty remained as to proper ownership of CBM. Recently however, the appeals filed in respect of the ERCB decision have been abandoned. The appeal period has lapsed and, as such, the ERCB’s decision stands unchallenged. As a result, the ERCB’s current practice of granting well licenses to holders of the underlying natural gas rights is likely to continue. However, there are pending actions filed with the Alberta Court of Queen’s Bench, pursuant to which certain coal producers are asserting legal ownership of CBM rights in freehold lands across Alberta. Currently, approximately 3% of our land holdings in Alberta are subject to these unresolved split title issues, where we hold the natural gas rights. In the event owners of coal rights are granted additional rights, we may lose our rights to the natural gas on those properties and we may have to return any revenue from the sales of such gas, which would adversely affect our results of operations.

Our insurance may not protect us against our business and operating risks. In addition, insurance costs may increase and we may not be able to obtain the same level of coverage in the future.

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. We may choose not to obtain insurance for some risks if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies may increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. We are not fully insured against all

risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. We are not fully insured against certain environmental risks, either because such insurance is not available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic damages) is not available on economically reasonable terms. Accordingly, our properties may be subject to liability due to hazards that cannot be insured against, or that have not been insured against due to prohibitive premium costs or for other reasons. Losses and liabilities from uninsured and under-insured events and delays in the payment of insurance proceeds could reduce the funds available to us for exploration, development and production and could have a material adverse effect on our financial condition and results of operations.

Our derivative activities could result in financial losses or could reduce our earnings.

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of natural gas, we currently enter, and may in the future enter, into derivative instruments for a portion of our natural gas production, including collars and price-fix swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. In addition, our letter of credit exposure is subject to increases if our derivative instruments are not in the money when we record their fair value on our balance sheet. Changes in the fair value of our derivative instruments are recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments. Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:


	•	production is less than expected;

	•	the counter-party to the derivative instrument defaults on its contract obligations; or

	•	there is a change in the expected differential between the underlying price in the derivative instrument and actual prices received.

In addition, these types of derivative arrangements limit the benefit we would receive from increases in the prices for natural gas and may expose us to cash margin requirements.

We are a holding company with no operations separate from our subsidiaries.

We are a holding company with no direct operations. Our ability to meet our obligations is entirely dependent upon our ability to raise capital through the issuance of debt and equity securities and our ability to receive distributions or repayment of loans from our operating subsidiaries. TEC, our principal operating subsidiary, has credit facilities which significantly restrict TEC’s ability to make distributions to us. If we are unable to raise capital through the issuance of debt or equity securities or from distributions or loan repayments from our operating subsidiaries in amounts sufficient to meet our obligations as they come due, our financial condition and results of operation could be materially adversely affected. Both world credit markets and world energy markets have recently been very weak and their continued weakness may adversely affect the gas industry generally and our ability to finance our capital expenditure program at currently budgeted levels.

We must include in our own income, for U.S. federal income tax purposes, our allocable share of any income, gains and losses realized by TEC. TEC is required to make distributions to its shareholders that are intended to be sufficient to enable its shareholders to pay U.S. federal income tax (and a reasonable allowance for state tax), net of allowable credits for Canadian taxes paid, on the income allocated to its shareholders. However, if TEC is unable to make any such required distribution, as a result of restrictions in TEC’s credit facilities, lack of available funds or any other reason, or if the distributions are insufficient, we could incur liability for U.S. tax without having a corresponding source of cash with which to pay the tax. See “— We have incurred significant net losses since our inception and may incur additional significant net losses in the future.”

Risks Related to this Offering and Our Common Stock

We cannot assure you that a market will develop for our common stock or what the price of our common stock will be.

Prior to this offering, there was no public trading market for our common stock, and we cannot assure you that an active trading market for our common stock will develop or be sustained after this offering or how liquid any market that develops might become. We intend to apply to list our common stock on the New York Stock Exchange. The initial public offering price for our common stock offered hereby will be determined by negotiations between the underwriters and us, and may bear no relationship to the price at which our common stock will trade upon the closing of this offering. You may not be able to resell your shares of our common stock above the initial public offering price and may suffer a loss on your investment.

Our stock price may be volatile and your investment in our common stock could suffer a decline in value.

Securities markets worldwide experience significant price and volume fluctuations. This market volatility, as well as general economic, market or political conditions in both Canada and the United States, could reduce the market price of our common stock in spite of our operating performance. In addition, our operating results could be below the expectations of investors and any analysts that chose to cover our common stock. The market price of our common stock could decrease significantly in response to these developments. Accordingly, you may be unable to resell your shares of our common stock at or above the initial public offering price.

Our common stock price may also fluctuate in response to a number of other events, including:


	•	changes in the price of natural gas;

	•	conditions or trends in our industry or the economy generally;

	•	changes in government and environmental regulation;

	•	announcements concerning our business;

	•	our operating and financial performance;

	•	announcements and actions of competitors;

	•	market and industry perception of our success, or lack thereof;

	•	actual or anticipated fluctuations in operating results;

	•	changes in financial estimates by us or by any securities analysts who might cover our stock;

	•	speculation about our business in the press or the investment community;

	•	negative variances between projected and actual operating results and projected versus booked reserves;

	•	stock market price and volume fluctuations of other publicly traded companies and, in particular, those that are in the oil and gas industry;

	•	adverse market reaction to any increased indebtedness we incur in the future;

	•	additions or departures of key personnel;

	•	actions by our stockholders; and

	•	natural disasters, terrorist attacks and acts of war.

In the past, securities class action litigation has often been instituted against companies following periods of volatility in their stock price. This type of litigation could result in substantial costs to us and divert our management’s attention and resources. This could have a material adverse effect on our results of operations and financial condition.

You will experience immediate and substantial dilution of US$ in net tangible book value per share.

The initial public offering price of the shares of our common stock is substantially higher than the pro forma net tangible book value per share of the outstanding common stock. As a result, if we were liquidated for book value immediately following this offering, you would experience immediate and substantial dilution of US$ per share of common stock. We will also have outstanding stock options to purchase shares of our common stock at a weighted average exercise price of US$ per share immediately following the closing of this offering. See “Dilution” for a discussion about how pro forma net tangible book value is calculated.

Future sales of our common stock could reduce our stock price.

Upon the closing of this offering, we will have outstanding shares of common stock (or approximately shares if the underwriters exercise their over-allotment option in full). Of these shares, the shares of common stock offered in this prospectus will be freely tradable without restriction in the public market, unless purchased by our affiliates (as that term is defined in Rule 144 under the Securities Act of 1933, as amended, or the Securities Act). We expect that the remaining shares of common stock will become available for resale in the public market as shown in the chart below. Our officers, directors and the holders of all of our outstanding shares of common stock have signedlock-up agreements pursuant to which they have agreed not to sell, transfer or otherwise dispose of any of their shares for a period of 180 days following the date of this prospectus, subject to certain exceptions and subject to extension in the case of an earnings release or material news or a material event relating to us. The underwriters may, in their sole discretion and without notice, release all or any portion of the common stock subject tolock-up agreements.

Immediately following the closing of this offering, our shares of common stock will become available for resale in the public market as follows:

We have agreed to cause a resale shelf registration statement to be filed (after receipt of a timely demand notice from a holder of registrable securities) within 150 days after the effective date of the registration statement of which this prospectus forms a part, and to cause such shelf registration statement to become effective within 180 days after such effective date pursuant to a registration rights agreement that we have entered into with substantially all of our shareholders. Following the closing of this offering, the holders of outstanding or issuable shares of our common stock will be entitled to include their shares in that shelf registration statement. In addition, the holders of registrable securities have the right to include their shares in registration statements that we may file for ourselves or other stockholders. By exercising their registration rights and selling a large number of shares, these stockholders could cause the price of our common stock to decline. In addition, immediately following this offering, we intend to file a registration statement registering onForm S-8 under the Securities Act shares reserved for issuance under our employee stock option plans and shares held for resale by our existing stockholders that were previously issued under our employee stock option plans (of which shares will not be subject to the180-daylock-up). Sales of a substantial number of shares of our common stock, or the perception that a large number of shares of common stock could be sold, after our initial public offering could depress the market price of our common stock.

See “Shares Eligible for Future Sale” for a more detailed description of the shares that will be available for future sales upon the closing of this offering.

We do not intend to pay, and are currently prohibited by the terms of our credit agreements from paying, dividends on our common stock.

We have never declared or paid any dividends on our common stock. We currently intend to retain any future earnings to finance the development and growth of our business and do not expect to pay any cash dividends on our common stock in the foreseeable future. Any decision to pay cash dividends after this offering will be at the

discretion of our board of directors after taking into account such factors as our financial condition, results of operations, current and anticipated cash needs, the requirements of any future financing agreements, applicable provisions of Delaware law and other factors that our board of directors may deem relevant. Our ability to pay dividends is restricted by our credit facility. In addition, if our board of directors were to declare a dividend, we would be dependent on receiving funds from TEC to pay any such dividend. TEC’s debt instruments restrict its ability to make payments, including dividends, distributions and loans to us, limiting our ability to pay dividends. Until we pay dividends, which we may never do, our stockholders may not be able to receive a return on shares of our common stock, unless the price of our common stock appreciates. You may not receive a return on your investment when you do sell your shares of common stock.

Provisions in our amended and restated certificate of incorporation and our bylaws effective upon the closing of this offering and under Delaware law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock.

The existence of some provisions in our organizational documents effective upon the closing of this offering and under Delaware law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock. The provisions in our amended and restated certificate of incorporation and bylaws that could delay or prevent an unsolicited change in control of our company include board authority to issue preferred stock without the approval of stockholders, limitations on the persons who may call special meetings of the board of directors or acting by written consent in lieu of a meeting, the ability to elect directors by a plurality of the number of votes cast rather than cumulative voting, advance notice requirements for stockholders with respect to director nominations and actions to be taken at annual meetings and the classification of our board into three classes.

Failure by us to achieve and maintain effective internal control over financial reporting could harm our business and operating results, and result in a loss of investor confidence in our financial reports, which could have a material adverse effect on our business and stock price.

Section 404 of the Sarbanes-Oxley Act of 2002, or the Sarbanes-Oxley Act, requires annual management assessments of the effectiveness of our internal control over financial reporting, starting with the second annual report that we file with the SEC, and will likely require in the same report a report by our independent registered public accounting firm on the effectiveness of our internal control over financial reporting. Our management has not yet completed its review of our internal control over financial reporting. In connection with the implementation of the necessary procedures and practices related to internal control over financial reporting, we may identify deficiencies that we may not be able to remediate in time to meet the deadline imposed by the Sarbanes-Oxley Act for compliance with the requirements of Section 404. If we fail to comply with Section 404, we could be subject to regulatory scrutiny and sanctions, our ability to raise revenue could be impaired, investors may lose confidence in the accuracy and completeness of our financial reports and our stock price could be adversely affected.

Substantially all of our assets are in Canada. Certain of our officers upon which we heavily rely, and one of our directors, may not be subject to suit in the United States.

Substantially all of our assets are located in Canada. As a result, it may be difficult or impossible to enforce any judgment obtained in the United States against those assets predicated upon any civil liability provisions of the U.S. federal securities laws. In addition, certain of our officers and one of our directors reside in Canada. As a result, it may be difficult or impossible to effect service of process within the United States upon those individuals, to bring suit against any of those individuals in the United States or to enforce in the U.S. courts any judgment obtained there against any of those individuals predicated upon any civil liability provisions of the U.S. federal securities laws. Investors should not assume that Canadian courts will enforce judgments of U.S. courts against assets located in Canada or any director or officer residing in Canada, including judgments obtained in actions predicated upon the civil liability provisions of the United States federal securities laws or the securities or “blue sky” laws of any state within the United States, or will enforce, in original actions, liabilities against that director predicated upon the U.S. federal securities laws or any such state securities or blue sky laws.

A small number of our stockholders own significant amounts of our common stock and will be able to exert a significant influence over matters requiring a shareholder vote.

We have a number of stockholders who each own a significant amount of our common stock. After giving effect to this offering and without giving effect to the right of first refusal agreement, will beneficially own % of our outstanding common stock, will beneficially own % of our outstanding common stock, will beneficially own % of our outstanding common stock, and will beneficially own % of our outstanding common stock. After giving effect to this offering and assuming these stockholders purchase their respective maximum number of shares pursuant to the right of first refusal agreement, will beneficially own % of our outstanding common stock, will beneficially own % of our outstanding common stock, will beneficially own % of our outstanding common stock, and will beneficially own % of our outstanding common stock. In addition, upon issuance of additional shares of our common stock as payment for accrued dividends and to provide the minimum compounded annual rate of return for our preferred stock, other stockholders may own a significant amount of our common stock. The voting power of any of these stockholders could influence the outcome of matters requiring a stockholder vote, including the election of directors, the adoption or amendment of provisions in our amended and restated certificate of incorporation and bylaws and the approval of mergers and other significant corporate transactions, including a change of control of the company. In addition, our amended and restated certificate of incorporation effective upon the closing of this offering provides that the provisions of Section 203 of the Delaware General Corporation Law, which relate to business combinations with interested stockholders, do not apply to us.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about:


	•	the volatility of gas prices;

	•	discovery, estimation, development and replacement of gas reserves, including our expectations that estimates of our proved reserves will increase;

	•	cash flow, liquidity and financial condition;

	•	business and financial strategy;

	•	plans with respect to our drilling activities, including our ability to leverage our drilling expertise into other drilling opportunities, our intent to increase our development drilling activities to add to our existing CBM reserves and our intent to begin drilling in the Montney Shale play;

	•	the upside potential in the Montney Shale play, including our intent to convert Montney reserve potential to proven reserves;

	•	evaluated drilling opportunities and rig deployments in the Mannville CBM plays, Horseshoe Canyon CBM play and Montney Shale play;

	•	our continued operation of the majority of our production and control over marketing and logistics;

	•	amount, nature and timing of capital expenditures, including future development costs;

	•	availability and terms of capital;

	•	timing and amount of future production of gas;

	•	availability of drilling and production equipment, labor, and gas processing and other services;

	•	marketing of gas;

	•	competition in the gas industry;

	•	the impact of weather and the occurrence of natural disasters such as fires;

	•	governmental regulation of the gas industry, permitting and other legal requirements, including our expectations with respect to permits and royalty laws;

	•	developments in gas-producing countries; and

	•	expansion and other development trends in the gas industry.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in the “Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Industry,” “Business,” and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “would,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” or “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or

implied in the forward-looking statements due to factors listed in the “Risk Factors” section and elsewhere in this prospectus.

All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. The forward-looking statements contained in this prospectus are excluded from the safe harbor protection provided by the Private Securities Litigation Reform Act of 1995 and Section 27A of the Securities Act of 1933, as amended.

INDUSTRY AND MARKET DATA

Industry data and other statistical information used throughout this prospectus are based on independent industry publications, government publications, reports by market research firms or other published independent sources. Some data is also derived from our review of internal surveys, as well as the independent sources listed in this prospectus. Industry publications, studies and surveys generally state that they have been obtained from sources believed to be reliable, although they do not guarantee the accuracy or completeness of such information. While we believe that each of these studies and publications is reliable, we have not independently verified market and industry data from third-party sources. While we believe our internal company research is reliable and the market definitions are appropriate, neither such research nor these definitions have been verified by any independent source.

EXCHANGE RATE DATA

We report our results in Canadian dollars. In this prospectus, unless otherwise indicated, all dollar amounts and references to “C$” are to Canadian dollars and references to “US$” are to United States dollars. On November 7, 2008, the noon buying rate in New York for cable transfers payable in foreign currencies, as certified for customs purposes by the Federal Reserve Bank of New York, was C$1.00 = US$0.8453.

The following table sets forth, for the periods indicated, the period-end, average, high and low noon buying rates in New York for cable transfers payable in foreign currencies, as certified for customs purposes by the Federal Reserve Bank of New York, in Canadian dollars per U.S. dollar. No representation is made that the U.S. dollar amounts have been, could have been or could be converted into Canadian dollars at the noon buying rate on such dates or any other dates.


	Noon Buying Rate
Year Ended December 31,	Period End		Average(1)		High		Low

2003		1.2923		1.4008		1.5750		1.2923
2004		1.2034		1.3017		1.3970		1.1775
2005		1.1656		1.2115		1.2703		1.1507
2006		1.1652		1.1340		1.1726		1.0989
2007		0.9881		1.0742		1.1852		0.9168


Six Months Ended June 30,

2007	1.0634	1.1345	1.1852	1.0579
2008	1.0185	1.0070	1.0294	0.9717


(1)		Determined by averaging the rates on the last business day of each month during the respective period.

USE OF PROCEEDS

Based on an initial public offering price of US$ per share, the midpoint of the estimated price range shown on the cover page of this prospectus, we estimate that we will receive net proceeds from this offering of approximately US$ million, after deducting the underwriting discount and estimated offering expenses. If the underwriters exercise their over-allotment option in full, we estimate that we will receive additional net proceeds of US$ million.

A US$1.00 increase (decrease) in the assumed initial public offering price of US$ per share would increase (decrease) the net proceeds to us from this offering by approximately US$ , assuming the number of shares offered, as set forth on the cover page of this prospectus, remains the same and after deducting the underwriting discount and estimated offering expenses.

The following table sets forth the estimated sources and uses of funds in connection with this offering and the other transactions described below. See “The Recapitalization.”


		Amount
		(US$ in millions)

Sources of Funds:
Common stock offered hereby, net of underwriting discount		$
New indebtedness(1)
Cash on hand

Total sources		$

Uses of Funds:
Prepayment of TEC first lien credit agreement(2)		$
Prepayment of TEC second lien credit agreement(3)
Prepayment of TRC 2006 credit agreement(4)
Prepayment of TRC 2007 subordinated credit agreement(5)
Transaction fees and expenses(6)

Total uses		$


(1)		We expect our new indebtedness will consist of senior notes and a new revolving credit facility.

(2)		The TEC first lien credit agreement has a final maturity date of October 2, 2009 and bears interest at a rate of bank prime plus 1.0% for Canadian or U.S. prime rate loans and LIBOR plus 2.0% for LIBOR loans and provides for a 2.0% fee and discounted proceeds for bankers’ acceptances and undrawn letters of credit.

(3)		The TEC second lien credit agreement has a final maturity date of April 26, 2011 in respect of US$450 million of advances, and April 26, 2012 in respect of US$50 million of advances. On base rate advances, the loan bears interest at the rate of 6.5% plus a base rate equal to the greater of the U.S. Federal Funds Rate plus 0.5% and the prime rate. On eurodollar advances, the rate is LIBOR plus 7.5%.

(4)		The TRC 2006 credit agreement has a final maturity date of November 24, 2011. On base rate advances, the loan bears interest at the rate of 11.0% plus a base rate equal to the greater of the U.S. Federal Funds Rate plus 0.5% and the prime rate. On eurodollar advances, the rate is LIBOR plus 12.0%. Prior to November 24, 2008, we pay interest on the TRC 2006 credit agreement in-kind by capitalization of accrued interest. We may elect to pay interest during the period from November 24, 2008 until November 23, 2009 in cash or in-kind. If we elect to pay interest on the TRC 2006 credit facility during such period in-kind, then on and after November 24, 2008, the interest rates on all loans under the TRC 2006 credit agreement permanently increase by 2.0%.

(5)		The TRC 2007 subordinated credit agreement has a final maturity date of August 31, 2012. On base rate advances, the loan bears interest at the rate of 6.5% plus a base rate equal to the greater of the U.S. Federal


		Funds Rate plus 0.5% and the prime rate. On eurodollar advances, the rate is LIBOR plus 7.5%. Interest is due at maturity, and prior to maturity accrued but unpaid interest bears interest at the same rates as principal.

(6)		Transaction fees and expenses include (i) US$ million of estimated fees and expenses associated with this offering, (ii) US$ of estimated fees and expenses associated with repayment of our existing indebtedness and our new revolving credit facility and senior notes, and (iii) approximately US$ million consisting of prepayment premiums of US$ million with respect to the TEC first lien credit agreement, US$ million with respect to the TEC second lien credit agreement, US$ with respect to the TRC 2006 credit agreement and US$ million with respect to the TRC 2007 subordinated credit agreement.

DIVIDEND POLICY

We do not expect to pay dividends on our common stock in the foreseeable future. Any decision to pay cash dividends after this offering will be at the discretion of our board of directors after taking into account such factors as our financial condition, results of operations, current and anticipated cash needs, the requirements of any future financing agreements, applicable provisions of Delaware law and other factors that our board of directors may deem relevant. Our ability to pay dividends is restricted by the terms of our indebtedness. In addition, if our board of directors were to declare a dividend, we would be dependent on receiving funds from TEC to pay any such dividend. TEC’s debt instruments restrict its ability to make payments, including dividends, distributions and loans to us, limiting our ability to pay dividends. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Liquidity and Capital Resources — Historical Indebtedness and Capital Structure” for a description of these limitations on dividends and other payments.

CAPITALIZATION

The following table presents our capitalization as of June 30, 2008:


	•	on an actual basis; and

	•	on a pro forma as adjusted basis to give effect to:


	•	the issuance and sale by us of shares of common stock in this offering and the application of the net proceeds from this offering, our new revolving credit facility and our senior notes, together with cash on hand, as described in “Use of Proceeds”; and

	•	the issuance upon the closing of this offering assuming a closing date for this offering of , 2009 of shares of common stock pursuant to the automatic exercise of warrants in connection with the mandatory redemption of our Series A and Series B preferred stock, which includes shares of common stock as payment for accrued dividends and additional shares of common stock to provide the minimum compounded annual rate of return. See “The Recapitalization — Preferred Stock and Preferred Warrants.”

This table should be read in conjunction with “Use of Proceeds,” “Selected Historical Financial and Operational Information,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes thereto appearing elsewhere in this prospectus.

In the table below, except for the offering proceeds, we have converted U.S. dollar amounts to Canadian dollar amounts based on the closing exchange rate on June 30, 2008, which was US$1.00 = C$1.0197. In the table below, the offering proceeds have been converted to Canadian dollars based on the average exchange rate in effect on , 2009, which was US$1.00 = C$ .


	As of June 30, 2008
				Pro Forma as
	Actual			Adjusted(1)
	(In thousands of Canadian dollars, except share data)

Short-term debt:
TEC first lien credit agreement		—
Long-term debt, net of discounts:
TEC second lien credit agreement	C$	508,288
TRC 2006 credit agreement		337,910
TRC 2007 subordinated credit agreement		132,725

Total	C$	978,923
New indebtedness:
Revolving credit facility		—
Senior notes		—
Series A preferred stock, US$0.0001 par value, 8,000,000 shares authorized, and 4,993,559 shares issued and outstanding, and no shares issued and outstanding pro forma as adjusted, including amounts classified as long-term liabilities		783,951			—
Series B preferred stock, US$0.0001 par value, 2,000,000 shares authorized, and 614,000 shares issued and outstanding, and no shares issued and outstanding pro forma as adjusted		39,108			—
Stockholders’ deficit:
Common stock, US$0.0001 par value, 2,490,000,000 shares authorized; 28,115,114 shares issued and outstanding and shares issued and outstanding pro forma as adjusted		3
Paid-in capital		306,346
Deficit		(1,401,770	)

Total stockholders’ deficit	C$	(1,095,421	)

Total capitalization	C$	706,561


(1)		Assumes net proceeds to us from this offering of US$ million. A US$1.00 increase (decrease) in the assumed initial public offering price of US$ per share would increase (decrease) pro forma as adjusted paid-in capital and total shareholders’ equity (deficit) by US$ million, assuming the number of shares offered as set forth on the cover page of this prospectus, remains the same and after deducting the underwriting discount and estimated offering expenses.

THE RECAPITALIZATION

Introduction

Concurrently with the closing of this offering, we intend to borrow US$ million under a new revolving credit facility and issue US$ of senior notes, which will represent our only borrowings following the closing of this offering. Using the aggregate net proceeds from this offering, the new revolving credit facility and the senior notes, together with cash on hand, we intend to effect a recapitalization, which will result in our capital structure being materially different from our current structure. The closing of this offering is contingent upon our entering into a new revolving credit facility and completing the senior notes offering on terms acceptable to us, and we reserve the right to withdraw this offering if the terms are unacceptable to us.

Our current capital structure is the result of an accumulation of indebtedness during 2005 through 2007, a period of rapid growth in our operations. As a result of a misalignment of operating performance to leverage accumulation by our previous management during this period of rapid growth, we faced restricted access to capital, further increasing the cost of additional funds. As a result of our need for additional funds to support this growth, each of our auditors’ reports for the years ended 2005 and 2006 contained an explanatory paragraph that our recurring losses from operations and net capital deficit raised substantial doubts about our ability to continue as a going concern. In 2007, we changed our senior management and this concern was resolved with the additional financing we obtained in August 2007 pursuant to the TRC 2007 subordinated credit agreement, together with a budget that sought to demonstrate our ability to meet our obligations as they became due for an extended period.

Indebtedness

Subsequent to the closing of this offering and the incurrence of borrowings under a new revolving credit facility and the issuance of new senior notes, we will repay all of the outstanding indebtedness under the TEC first lien credit agreement, the TEC second lien credit agreement, the TRC 2006 credit agreement and the TRC 2007 subordinated credit agreement, together with related prepayment premiums, fees and expenses. As a result of these transactions, following the closing of this offering, our outstanding indebtedness will consist solely of approximately US$ million of borrowings under our new revolving credit facility and US$ million of senior notes.

For a description of our existing credit facilities, see “Management’s Discussion and Analysis — Liquidity and Capital Resources — Historical Indebtedness and Capital Structure.”

Preferred Stock and Preferred Warrants

We currently have 5,607,559 outstanding shares of Series A and Series B preferred stock, representing all of the issued and outstanding shares of Series A and Series B preferred stock as at June 30, 2008. Upon the closing of this offering, our shares of Series A and Series B preferred stock will be mandatorily redeemed for common stock and we will have no shares of preferred stock outstanding. The redemption payment to which holders of the Series A and Series B preferred stock are entitled will be automatically applied to the exercise price of the preferred warrants to purchase shares of our common stock that were issued as part of a unit with our Series A and Series B preferred stock. As a result, the redemption of our preferred stock will result in the conversion of our Series A and Series B preferred stock into shares of our common stock. We will also issue shares of common stock as payment for accrued dividends on the Series A and Series B preferred stock and to provide the minimum compounded annual rate of return to each holder thereof, as described below.

The number of shares of our common stock issuable upon the exercise of the preferred warrants is subject to adjustment based on the compounded annual rate of return which the holders thereof are entitled to receive at the time of the mandatory redemption of the preferred stock on their initial investment of US$62.50 for the preferred unit (consisting of the shares of the applicable series of preferred stock and the related preferred warrant). In the case of the preferred warrants related to Series A preferred stock, the number of shares issuable upon exercise will be adjusted such that the holder thereof will receive no less than a minimum compounded annual rate of return of 15% and no more than a maximum compounded annual rate of return of 22%. In the case of the preferred warrants related to Series B preferred stock, the number of shares issuable upon exercise will be adjusted such that the holder thereof

will receive an annual compounded return of 15%. For purposes of determining the compounded return to be received by each warrantholder, shares of our common stock will be valued at the initial public offering price without deduction for underwriting or other discounts or expenses. If upon exercise of the preferred warrants a downward adjustment of the number of shares issuable is required, the holder thereof has the option to make a cash payment to us in lieu of such downward adjustment. However, we expect that the number of such shares issuable will be subject to upward adjustment in the case of both series of preferred warrants.

Assuming a closing date for this offering of , 2009 and based on the midpoint of the estimated price range shown on the cover page of this prospectus, we will issue additional shares of our common stock upon exercise of the preferred warrants, which includes shares of common stock for payment of accrued dividends and additional shares of our common stock to provide the minimum compounded annual rate of return. As a result of the adjustment mechanism described above, the number of shares of common stock outstanding after this offering will vary significantly depending on the initial public offering price. See “Summary — Summary Financial Data — Impact of Changes in Net Proceeds from this Offering on the Recapitalization” for further information.

2006 and 2007 Debt Warrants

We currently have 18,150,162 outstanding warrants, all of which were issued and outstanding as at June 30, 2008, to purchase shares of our common stock, issued in connection with the TRC 2006 credit agreement and the TRC 2007 subordinated credit agreement, with a weighted average exercise price of C$ per share of common stock. Upon the closing of this offering, the number of shares of our common stock issuable upon the exercise of these debt warrants and the exercise price of the debt warrants issued in connection with the TRC 2006 credit agreement are subject to adjustment.

In connection with the TRC 2006 credit agreement, we issued 4,500,000 warrants to purchase shares of our common stock, with an exercise price equal to the lower of: C$25.00 per share, 80% of the price per share upon a change of control prior to the consummation of a qualifying initial public offering or 80% of the price per share in a qualifying initial public offering. The number of shares issuable upon the exercise of these warrants is subject to upward adjustment based on the number of shares of common stock issued in connection with the redemption of our Series A and Series B preferred stock and the exercise of the preferred warrants. As the number of such shares increases, the number of shares issuable upon exercise of these warrants increases, in an aggregate amount equal to 10% of the number of such shares in excess of 10 million shares. The exercise price is subject to downward adjustment where the price per share in this offering (minus the underwriters’ discount) is less than C$25.00. The exercise price is reduced by the ratio of (i) our total outstanding equity, and the hypothetical number of shares that would have been sold in this offering at a per share offering price of C$25.00 (minus the underwriters’ discount), assuming net proceeds from this offering remain the same and (ii) our total outstanding equity plus the number of shares sold in this offering.

In connection with the TRC 2007 subordinated credit agreement, we issued 13,650,162 warrants to purchase shares of our common stock, with an exercise price of C$0.0001 per share. The number of shares issuable upon the exercise of these warrants is subject to upward adjustment based on the adjustment to the number of shares issuable upon exercise of the warrants issued in connection with the TRC 2006 credit agreement (as described above), in an aggregate amount equal to 37.94% of such adjustment.

Assuming a closing date for this offering of , 2009 and based on the midpoint of the estimated price range shown on the cover page of this prospectus, the warrants will adjust upon the closing of this offering and become exercisable for shares of our common stock at a weighted average exercise price of C$ per share of common stock. As a result of the adjustment mechanism described above, the number of shares of common stock outstanding after this offering will vary significantly depending on the initial public offering price. See “Summary — Summary Financial Data — Impact of Changes in Net Proceeds from this Offering on the Recapitalization” for further information.

DILUTION

If you purchase shares of our common stock in this offering, you will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. The net tangible book value per share represents the amount of our total tangible assets less our total liabilities, divided by the number of shares of common stock outstanding. For investors in this offering, dilution is the difference between the initial public offering price per share of the common stock in this offering and the pro forma net tangible book value per share of our common stock immediately after completing this offering. Dilution results from the fact that the per share offering price of the common stock is substantially in excess of the net tangible book value per share attributable to the existing stockholders for the currently outstanding common stock.

As of June 30, 2008, our net tangible book value prior to this offering was approximately US$ , or approximately US$ per share, based on shares of common stock outstanding.

After giving effect to the sale of the common stock in this offering at an assumed initial public offering price of US$ per share (the midpoint of the estimated price range shown on the cover of this prospectus) and after deducting the underwriting discount and estimated offering expenses, the pro forma net tangible book value as of June 30, 2008 would have been US$ or US$ per share. This represents an immediate increase in the net tangible book value to existing shareholders of US$ per share and an immediate and substantial dilution of US$ per share to new investors.

The following table illustrates this per share dilution:


Assumed initial public offering price per share		US$
Net tangible book value per share as of June 30, 2008	US$
Increase in pro forma net tangible book value per share attributable to new investors	US$
Net tangible pro forma book value per share after the offering		US$

Dilution per share to new investors		US$

A US$1.00 increase (decrease) in the assumed initial public offering price of US$ per share would increase (decrease) our pro forma net tangible book value per share after this offering by US$ per share and the dilution per share to new investors by US$ per share (i) assuming the number of shares offered by us shown on the cover page of this prospectus remains the same and (ii) after deducting the underwriting discount and estimated offering expenses.

The following table sets forth, as of June 30, 2008, the number of shares purchased from us, the total consideration paid to us and the average price per share paid by our existing stockholders and to be paid by new investors at an assumed initial public offering price of US$ (the midpoint of estimated price range shown on the cover page of this prospectus) and before deducting the underwriting discount and estimated offering expenses.

Shares Purchased

Total Consideration

Average Price

Number

Percent

Amount

Percent

Per Share

Existing stockholders

28,115,114

US$

New investors

US$

Total

100

US$

100

SELECTED HISTORICAL FINANCIAL AND OPERATIONAL INFORMATION

The following table sets forth our selected consolidated financial and operating information as of and for each of the periods indicated. The selected consolidated financial information as of December 31, 2003, 2004, 2005, 2006 and 2007 and for each of the years in the five-year period ended December 31, 2007 is derived from our consolidated financial statements. The consolidated financial statements as of December 31, 2005, 2006 and 2007 and for each of the years in the three-year period ended December 31, 2007, and the report thereon, are included elsewhere in this prospectus. The selected consolidated financial information as of June 30, 2008 and for the six-month periods ended June 30, 2007 and 2008 is derived from our unaudited interim consolidated financial statements included elsewhere in this prospectus. The selected consolidated financial information as of June 30, 2007 is derived from our unaudited interim consolidated balance sheet not included in this prospectus. We prepared the unaudited information on a basis consistent with that used in preparing our audited consolidated financial statements, and it includes all adjustments, consisting of normal and recurring items, that we consider necessary for a fair presentation of the financial position and results of operations for the unaudited periods.

The selected operational information presented below under the caption “— Other Financial Data” is not derived from the consolidated financial statements. Our estimated net gas reserves for the year ended December 31, 2003 are based on a reserve report prepared by Ryder Scott Company, independent petroleum engineers, dated January 1, 2004. Our estimated net gas reserves for the years ended December 31, 2004, 2005, 2006 and 2007 and for the six months ended June 30, 2007 are based on reserve reports prepared by Sproule Associates Limited, independent petroleum engineers, dated as of December 31, 2004, 2005, 2006 and 2007 and June 30, 2007, respectively. Our estimated net gas reserves for the six months ended June 30, 2008, are based on a reserve report prepared by Netherland, Sewell & Associates, Inc. dated as of June 30, 2008.

You should read the following selected consolidated financial and operational information in conjunction with our audited and unaudited consolidated financial statements and the accompanying notes included elsewhere in this prospectus and the section of this prospectus entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	Year Ended December 31,															Six Months Ended June 30,
	2003(1)			2004			2005			2006			2007			2007			2008
	(In thousands of Canadian dollars)

Consolidated Statements of Operations and Comprehensive Loss Data:
Revenue
Production revenue	C$	993		C$	8,873		C$	40,258		C$	139,631		C$	201,993		C$	107,692		C$	110,554
Expenses
Operating		1,263			3,757			13,571			43,086			59,450			28,606			29,068
General and administrative		952			4,834			20,177			25,378			20,198			9,336			22,398
Depletion, depreciation and accretion		408			13,811			38,800			766,228			219,243			104,144			32,034

Total expenses		2,623			22,402			72,548			834,692			298,891			142,086			83,500

Income (loss) from operations:		(1,630	)		(13,529	)		(32,290	)		(695,061	)		(96,898	)		(34,394	)		27,054
Other income and expenses
Financing charges		21			334			41,845			292,941			170,271			87,424			126,800
Restructuring charges		—			—			—			—			20,746			17,198			2,410
Loss (gain) on disposition		—			—			—			(21,242	)		—			—			423
Foreign exchange (gain) loss		(1,157	)		(1,114	)		(11,757	)		18,631			(202,109	)		(115,299	)		35,409

Total other expense (income)		(1,136	)		(780	)		30,088			290,330			(11,092	)		(10,677	)		165,042

Loss before undernoted items:		(494	)		(12,749	)		(62,378	)		(985,391	)		(85,806	)		(23,717	)		(137,988	)


	Year Ended December 31,															Six Months Ended June 30,
	2003(1)			2004			2005			2006			2007			2007			2008
	(In thousands of Canadian dollars)

Taxes
Capital taxes		194			417			1,188			165			156			172			98
Deferred income taxes (recovery)		1,324			(3,584	)		(13,366	)		(64,633	)		—			—			—

Income tax expense (benefit)		1,518			(3,167	)		(12,178	)		(64,468	)		156			172			98

Net loss before undernoted items:		(2,012	)		(9,582	)		(50,200	)		(920,923	)		(85,962	)		(23,889	)		(138,086	)

Loss (earnings) from equity method investment		—			—			(400	)		1,663			—			—			—
Minority interests		(2,331	)		(2,241	)		2,363			786			1,760			—			(1,942	)

Net loss and comprehensive loss	C$	(4,343	)	C$	(11,823	)	C$	(48,237	)	C$	(918,474	)	C$	(84,202	)	C$	(23,889	)	C$	(140,028	)
Accretion of Series A preferred stock		—			—			(144,482	)		—			—			—			—
Accrued dividends on Series A preferred stock		—			—			(21,223	)		(37,370	)		(38,908	)		(19,766	)		(16,187	)
Foreign exchange gain (loss) on Series A preferred stock		—			—			16,138			(1,815	)		66,246			37,539			(11,559	)

Net loss and comprehensive loss available to common stockholders	C$	(4,343	)	C$	(11,823	)	C$	(197,804	)	C$	(957,659	)	C$	(56,864	)	C$	(6,116	)	C$	(167,774	)

Net loss per share of common stock:
Basic and diluted	C$	(0.24	)	C$	(0.54	)	C$	(8.23	)	C$	(35.18	)	C$	(2.08	)	C$	(0.22	)	C$	(6.13	)

Weighted average number of shares of common stock used in calculating loss per share (thousands):
Basic and diluted		17,772			21,911			24,043			27,221			27,330			27,330			27,349


	Year Ended December 31,															Six Months Ended June 30,
	2003(1)			2004			2005			2006			2007			2007			2008
	(In thousands of Canadian dollars)
Consolidated Statements of Cash Flows Data:
Net cash provided by (used for) operating activities	C$	(1,107	)	C$	2,053		C$	(3,579	)	C$	16,127		C$	55,257		C$	15,119		C$	58,765
Net cash provided by (used for) financing activities		67,995			57,506			671,436			701,410			91,257			(9,095	)		(33	)
Net cash used for investing activities		(28,445	)		(91,619	)		(604,979	)		(664,377	)		(128,402	)		(76,826	)		(94,266	)
Other Financial Data
Capital expenditures	C$	30,404		C$	121,098		C$	503,064		C$	653,384		C$	89,734		C$	37,633		C$	61,863
Net production (Mmcfe)		179.6			1,420.8			4,313.9			20,425.0			28,809.5			14,177.0			14,209.0
Daily sales volume
Natural gas (Mcfe/d)(2)		492			3,882			11,819			55,959			78,930			78,327			78,074
Realized prices
Natural gas (per Mcfe).	C$	5.53		C$	6.24		C$	9.33		C$	6.55		C$	7.02		C$	7.64		C$	8.57
Net proved reserves at period end (Mmcfe)(3)		1,317.1			27,595.0			81,954.6			164,292.4			166,107.6			139,808.4			394,940.6
Natural gas (Mmcfe)(3)		1,298.0			27,547.0			81,916.0			164,203.6			166,020.0			139,725.0			394,940.6
Standardized measure of discounted future net cash flows (in thousands)(4)	C$	3,654		C$	71,254		C$	309,994		C$	366,917		C$	402,549		C$	312,823		C$	1,287,344


	As of December 31,													As of June 30,
	2003(1)		2004		2005			2006			2007			2008
	(In thousands of Canadian dollars)

Consolidated Balance Sheet Data:
Total current assets	C$	49,167	C$	21,635	C$	103,120		C$	200,279		C$	212,359		C$	202,794
Property, plant and equipment		71,856		190,078		879,236			765,449			633,889			663,433
Total assets		122,953		213,870		993,898			995,498			883,744			900,261
Total current liabilities		13,595		55,340		123,279			147,915			71,265			72,865
Total liabilities(5)		62,592		131,670		676,246			1,463,328			1,433,417			1,587,108
Redeemable Series A preferred stock		—		—		368,981			408,166			380,828			408,574
Total stockholders’ deficit		60,361		82,200		(51,329	)		(875,996	)		(930,501	)		(1.095,421	)


(1)		In December 2003, we acquired approximately 87% of TEC’s common shares by issuing shares of our common stock to the TEC common shareholders. This was determined to be a non-monetary transaction which did not result in a substantial change in ownership. As a result, the continuity of interests method of accounting as applied whereby the assets and liabilities were transferred at historical cost and our financial statements present the results of operations as if TEC had been our subsidiary since inception.

(2)		Includes oil and natural gas liquid production converted to Mcfe at a ratio of 6 net Mcfe for each net barrel produced. Total net oil and natural gas liquid production for the years ended December 31, 2003, 2004, 2005, 2006 and 2007 and the six months ended June 30, 2007 and 2008 was zero Bbls, 2,965 Bbls, 10,097 Bbls, 20,295 Bbls, 16,951 Bbls, 8,220 Bbls and 15,904 Bbls, respectively.

(3)		This includes, as of December 31, 2003, 2004, 2005, 2006 and 2007, net proved reserves of oil of 3.1 MBbls, 8.0 MBbls, 6.4 MBbls, 14.8 MBbls and 14.6 MBbls respectively, and as of June 30, 2007 and June 30, 2008 we had net proved reserves of oil of 13.9 MBbls and zero MBbls, respectively.

(4)		Calculated based on our net proved reserves of oil and natural gas. The “standardized measure of discounted future net cash flows” is the present value of our estimated future net cash flows, discounted at 10% per year, calculated using constant pricing. The prices used for the calculations as of December 31, 2003, 2004, 2005, 2006 and 2007 and as of June 30, 2008 were C$6.14, C$6.78, C$9.99, C$6.13, C$6.52 and C$11.70, respectively. These prices were based on AECO-C prices as of December 31, 2003 through 2007 and NGX AB-NIT as of June 30, 2008, and were adjusted to account for transportation costs and any difference in quality, as applicable. The oil prices used for the calculations as of December 31, 2003, 2004, 2005, 2006 and 2007, and as of June 30, 2007, were C$41.22, C$41.51, C$68.12, C$67.59, C$93.44, and C$80.04, respectively. The standardized measure of discounted future net cash flows does not purport to present the fair market value of our natural gas reserves and is not indicative of actual future net cash flows.

(5)		Includes the Series B preferred stock and the Series A preferred stock embedded derivative. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Accounting for Derivative Instruments.”

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This management’s discussion and analysis, or MD&A, should be read in conjunction with our consolidated financial statements and related notes and the information under “Selected Historical Financial and Operational Information” included elsewhere in this prospectus. This discussion contains forward-looking statements, based on current expectations and related to future events and our future financial performance, that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those set forth under “Risk Factors.” The volumes of natural gas production presented in this MD&A are net of royalties paid for such production.

Overview

We have assembled an extensive property base. As of June 30, 2008, we had natural gas and oil leasehold interests in approximately 1.7 million gross (1.3 million net) acres, of which approximately 80% were undeveloped. Based on the evaluation of approximately 17% of our total net undeveloped acreage, we have identified approximately 1,700 evaluated surface drilling locations which are locations specifically identified and scheduled by management as an estimate of our near-term multi-year drilling activities on existing acreage over the next five to seven years. Based on a reserve report prepared by the independent petroleum engineers Netherland, Sewell & Associates, Inc., or NSAI, as of June 30, 2008, our estimated proved reserves were 394.9 Bcfe (net), 58.8% of which represented estimated total proved developed reserves. At June 30, 2008, we owned interests in 943 gross (517 net) economic producing wells. Our June 30, 2008 estimated proved reserves are considered to be long-lived with a total proved reserve-to-production-ratio of 13.5 years based on net production in August 2008. As of October 1, 2008, we had four rigs drilling in the Mannville CBM plays and two rigs drilling in the Horseshoe Canyon CBM play. We expect to have one rig begin drilling in the Montney Shale play in the fourth quarter of 2008.

Our core operating areas include the Mannville CBM plays and the Horseshoe Canyon CBM play in the WCSB and the Montney Shale play in British Columbia. The Mannville area represents a significant part of our development and exploration opportunities, with proved reserves as of June 30, 2008 of 166.3 Bcfe (42% of our total proved reserves) and net daily production of 41.6 Mmcfe/d for the month of August 2008 (approximately 52% of our total net daily production for the month). The Horseshoe Canyon area has proved reserves as of June 30, 2008 of 228.6 Bcfe (58% of our total proved reserves) and net daily production of 38.6 Mmcfe/d for the month of August 2008 (48% of our total net daily production). Beginning in the fourth quarter of 2008, we intend to begin our drilling program in the Montney Shale play with a view to converting Montney Shale play reserve potential to proved reserves.

Corporate History

We were incorporated in Delaware in November 2003 as a U.S. holding company for Trident Exploration Corp., or TEC. TEC was incorporated as a Nova Scotia unlimited liability company in September 2001. We currently own, directly and indirectly, approximately 99.2% of TEC’s capital stock.

In early 2002, TEC, together with a significant shareholder of TEC, acquired property in the Corbett Creek area in the Mannville CBM plays through the purchase of Trinity Energy Inc., or Trinity. Trinity had targeted the Corbett Creek area in 2000 and drilled its first four vertical CBM test wells in 2001. The test wells generated encouraging results and Nexen Inc., or Nexen, joined the project as a non-operating funding partner. With C$4.0 million in additional funding, Trinity drilled and evaluated three additional operated test wells.

Following the acquisition of Trinity, TEC formed a joint venture with Husky Oil Operations Limited, or Husky, to explore CBM resources within the Horseshoe Canyon CBM play. TEC’s team of professionals, technology and industry know-how enabled us to identify and begin acquiring our land base of targets for CBM exploration and development. Between 2002 and 2005, we invested significantly in the Mannville, including by expanding our infrastructure. In 2005, we operated the first commercial project in the Mannville CBM play. However, we had to raise additional capital because production did not increase on a timely basis. As a result of low production volume and low gas prices, which impacted our cash flows and result of operations, our equityholders made changes to our board of directors. This resulted in additional financing in August 2007 and the replacement of our senior management team. The majority of our current senior management team joined us in late 2007 and early 2008.

Key Factors and Trends Affecting Our Business

Our revenue, profitability, future growth and the carrying value of our properties are substantially dependent on:


	•	the prevailing price of natural gas;

	•	changes to royalty laws;

	•	our ability to explore for and exploit natural gas resources;

	•	our ability to operate our properties;

	•	the estimated price of our common stock; and

	•	exchange rate fluctuations.

Gas Prices and Revenues

Approximately 99% of our production revenue for the year ended December 31, 2007 and for the six months ended June 30, 2008 consisted of natural gas sales. Accordingly, our financial results are more sensitive to movements in natural gas prices than those oil and gas companies that produce balanced portfolios of both oil and gas. Natural gas prices have been extremely volatile and a majority of our production is currently sold at spot prices. Gas prices have been at high levels over the past several years as compared to prior years. There has been a decline in natural gas prices since June 30, 2008 that, if continuing, will adversely affect the carrying value of our proved reserves in the future.

In general, natural gas prices in Canada are seasonal in nature, with higher prices existing in the winter months (November to March) and lower prices in the summer months (April to October). Unusual weather conditions can impact natural gas prices by spiking consumer demand or flooding the North America gas grid. Natural gas prices are also affected by the amount of gas in local and North America-wide storage, or inventory, within the market. We generally sell our production into a balanced portfolio of current market prices and medium-term sales are actively managed to reduce downside pricing exposure. This strategy has helped to ensure that our capital expenditure programs have consistent funding while maximizing our exposure to upside pricing. For a minority of production volumes toward the end of 2007, we entered into costless collars and fixed price contracts. These contracts extend throughout the 2008 calendar year to February 2009. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.”

Royalties

All of our current production and associated revenues are subject to Alberta royalty laws. The volumes of natural gas production presented in this MD&A are net of royalties paid for such production. The royalty payable on natural gas is determined by a sliding scale based on a reference price, which is the greater of the amount obtained by the producer and a prescribed minimum price. In Alberta, a producer of natural gas is entitled to a credit against the royalties payable to the Crown for low-rate wells, or the productivity discount. In a lower natural gas price environment, we will pay a lower royalty on our production because the sliding scale royalty regime is determined by commodity prices, well productivity and total vertical and horizontal length, or measured depth, of natural gas wells. This has the effect of providing a partial hedge on volumes produced.

In January 2009, a new royalty framework will replace the current system. Under the new royalty framework, the maximum royalty rate for a producing well will increase substantially and the productivity discount for low-rate wells will also increase. In addition, a new credit will apply to wells with measured depth greater than 6,560 feet. The credit increases with measured depth up to a maximum at 13,125 feet or greater. Royalties on revenue derived from our production in the Mannville CBM plays are expected to remain similar to rates under the current framework as a result of new measured depth credits closely offsetting base royalty increases for the majority of our Mannville CBM wells. Royalties from revenue derived from our production in the Horseshoe Canyon CBM play are expected to decrease in 2009 as a result of productivity discount increases under the new framework exceeding the base royalty increases for the majority of the Horseshoe Canyon CBM wells.

Capital Development and Operations

The Horseshoe Canyon CBM play was first declared a commercial success in 2001. Due to these results, we have increased our focus on the area, which is now in a development phase. It is estimated that 30% of the number of wells required for development of the main play within the Horseshoe Canyon CBM play were drilled prior to 2007. The Mannville CBM plays are in the early stages of commercial development when compared to the Horseshoe Canyon CBM play. As a result, we expect per unit operating expenses to decline as we refine operating practices and increase production, providing more efficient usage of existing facilities, thereby contributing to economies of scale. In the Mannville CBM plays, we must pump water out of production zones, which is a significant operating cost that we expect will decrease over time as gas production increases. To date in 2008, we have observed approximately 20% of our operated Mannville CBM wells flowing natural gas and water without the continuous use of pumps, which has reduced our costs related to electricity and pump replacement in this area. The development of wells in the Mannville CBM plays is more sensitive to lower gas prices due to the costs to complete and operate the wells and the delay in achieving production.

Drilling rigs, service rigs, equipment and experienced crews have operated significantly below maximum capacity in the WCSB in 2007 and 2008. In 2005 and 2006, equipment and personnel operated at or near maximum capacity during peak periods, which resulted in escalated industry-wide drilling and service costs. The greater availability of equipment and personnel since 2006 has stemmed cost inflation and enabled us to negotiate changes to existing drilling commitments. In addition, the Canadian regulatory environment has undergone significant changes, particularly related to CBM activities, which have affected areas such as license and permit applications, and environmental and new data submission requirements of the government have increased our operating costs. Increased global demand for raw steel has increased the price of casings, line pipe and vessels fabricated from steel, which we employ in our operations. Finally, our operations are also impacted by seasonality, as road closures to heavy loads occur in the spring months, which can delay our access to drilling locations. These factors have a negative effect on overall operating costs, workloads, and timing of operations.

Operated vs. Non-Operated Properties

We operate approximately 65% of our development properties and over 90% of our exploration properties in which we have a working interest. The balance of our properties are operated by our joint venture partners. We have joint ventures with Nexen in connection with the Mannville CBM plays, and with Husky and a Canadian-based energy company in connection with the Horseshoe Canyon CBM play. To date, we have operated our properties at lower costs than our partners and therefore have had higher revenue net of royalties after operating expenses from these properties. Joint ventures in which we are not the operator do not provide us with the same level of profitability in drilling or developmental activities.

Exchange Rate Fluctuations

We are exposed to foreign exchange rate fluctuations because we report our operating results in Canadian dollars and the majority of our debt is denominated in U.S. dollars. We do not currently hedge our foreign exchange rate exposure. In the first six months of 2008, we placed US$50.0 million purchased in the open market in a money market account to reduce the effect of Canadian dollar-U.S. dollar exchange rate fluctuations upon interest rate payments required by certain of our debt instruments.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based on our consolidated financial statements that have been prepared in accordance with accounting principles generally accepted in the United States, which require us to make assumptions and prepare estimates that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experience and various other assumptions that we believe are reasonable, but our actual results may differ. We evaluate our assumptions and estimates on a regular basis. Our significant accounting policies are described in Note 2 to our consolidated financial statements included elsewhere in this prospectus.

The critical accounting policies used by management in the preparation of our consolidated financial statements are those that are important both to the presentation of our financial condition and results of operations and require significant judgments by management with regards to estimates used. Our critical accounting policies and estimates are described below.

Full Cost Method of Accounting and the Ceiling Test

We follow the full cost method of accounting for natural gas operations. Accordingly, all costs relating to the acquisition, exploration and development of natural gas properties, including leasehold costs, geological and geophysical costs, carrying charges of non-producing interests, costs of drilling both productive and non-productive wells, tangible production equipment costs, and general and administrative, or G&A, costs directly related and necessary to exploration and development activities, are capitalized. In the case of G&A costs, we have to estimate how much time certain employees spend on exploration and development activities versus production or administrative activities. Proceeds from the disposal of natural gas interests are applied against capitalized costs, with no gain or loss recognized in the statement of operations, unless such disposal would alter the rate of depletion by 20% or more.

The sum of net capitalized costs and estimated future development and asset retirement costs is depleted on the unit-of-production method, based on proved gas reserves as determined by independent petroleum engineers. Proved reserves and production volumes are converted to equivalent units on the basis of relative energy content using a ratio of 6,000 cubic feet of natural gas to one barrel of crude oil.

Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed quarterly when conducting the ceiling test, described below, to ascertain whether impairment has occurred. Any amount of impairment assessed is added to the costs to be depleted and depreciated. In many cases, drilling may be completed; however, properties remain classified as unproved properties until such time as gas processing infrastructure is put in place. As a result, an evaluation must be made as to whether the well is awaiting tie-in and thus excluded from the depletion pool, or whether the well is considered a dry hole and therefore should be included in the depletion pool.

We perform what we call a “ceiling test” each quarter. The ceiling test provides that capitalized costs, less related accumulated depletion and depreciation and deferred income taxes, may not exceed the “ceiling” of the sum of: estimated future net revenues from proved reserves, discounted at 10% per annum and based on unescalated period-end prices, the lower of cost or estimated fair value of property not being depleted or depreciated, less income tax effects related to differences in the book and tax basis of natural gas properties.

If the ceiling is calculated to be less than the net book value of our natural gas properties, then an impairment is deemed to have occurred and a non-cash write-down is required, which could materially impact our financial statements. In the first six months of 2008, we did not incur a ceiling test write-down, compared to a C$43.3 million write-down in the first six months of 2007. For 2007, we incurred a ceiling test write-down of C$112.8 million, compared to C$682.1 million in 2006.

There are a number of estimates contained within the ceiling test calculation, including an estimate of the volume of proved reserves. The volume of proved reserves is used to calculate both the estimate of future revenue, as well as depletion and depreciation expense.

Because the ceiling test calculation requires that prices in effect as of the last day of the applicable period are held constant indefinitely, and that a 10% per annum discount factor is applied, the resulting value may not be indicative of the fair value of the reserves. Natural gas prices have historically been volatile. On any particular day at the end of a period, natural gas prices can be either substantially higher or lower than long-term price expectations, which are an indicator of fair value. Therefore, we believe that natural gas property write-downs that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction in the ultimate value of the related reserves.

Natural Gas Reserve Quantities

Our proved reserves reflect quantities of natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic conditions. The process of estimating quantities of natural gas reserves is a subjective process and requires judgment in the evaluation of all available geological, geophysical, engineering and economic data. Estimates are based on a number of variables and assumptions, such as natural gas prices, historical production rates, timing and amount of capital expenditures, operating expenses and regulation by government agencies, all of which are subject to numerous uncertainties and various interpretations. Proved reserve estimates have a material impact on our depletion and depreciation and impairment costs because we calculate depletion and depreciation based on the proportionate amount of our proved reserves that are produced in the relevant period. In addition, estimates for future development costs are made and included in the calculation. We prepare our reserve estimates in accordance with Securities and Exchange Commission guidelines.

We engaged NSAI to evaluate our proved reserves for our reserve report as of June 30, 2008. On August 29, 2008, upon completion of their evaluation, the reserve report was reviewed and approved by the reserves committee of our board of directors.

Income Taxes

Income taxes reported in our financial statements consist of taxes currently payable plus deferred income taxes. We use the asset and liability method of accounting for income taxes. This method requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between financial accounting bases and tax bases of assets and liabilities. Deferred income tax assets and liabilities represent the future tax consequences of those differences, which will either be taxable or deductible when assets are recovered or settled.

Our Canadian resource tax pools of C$1,040 million and our net operating losses of C$194 million exceed our carrying costs by C$571 million as of June 30, 2008. We have not recognized the excess of tax pools over carrying costs in the financial statements.

Accounting for Derivative Instruments

We determined that the minimum and maximum return conversion feature of our Series A preferred stock is an embedded derivative pursuant to Statement of Financial Accounting Standards No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended, or SFAS 133, and the Emerging Issues Task Force’s Issue00-19, orEITF 00-19,Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock. SFAS 133 provides that if certain criteria are met, companies must bifurcate conversion options from their host instruments and account for them as freestanding derivative financial instruments in accordance withEITF 00-19.EITF 00-19 requires freestanding contracts that are settled in a company’s own stock to be designated as an equity instrument, asset or liability. Any contract designated as an asset or a liability must be carried at fair value on a company’s balance sheet, with any changes in fair value recorded in earnings.

Because the Series A preferred stock could theoretically be converted at a certain common stock price into a number of shares of common stock that exceeds our authorized share capital, our convertible securities are considered a liability and recorded at fair market value on our balance sheet, in accordance with the provisions ofEITF 00-19. We reassess the liability classification at each balance sheet date. We also re-measure the liability at

each balance sheet date with the changes in fair market value recognized in the statement of operations in the period when the changes occur.

Changes in the valuation of our common stock price have a material impact on our financial statements, and management estimates the fair value of our common on a continuous basis. We estimate the fair value of our common stock for the purposes of determining the value of the Series A preferred stock embedded derivative, our lenders’ and former consultants’ warrants and certain options using a combination of market and asset-based approaches. Our net asset value is determined by estimating the evaluated recoverable resource and value of unevaluated property, adding current and tangible assets and subtracting current and long-term obligations. Varying discount rates on the long-term assets and estimate ranges for the assessment of unevaluated properties are applied, resulting in a value range. Factoring our convertible securities for dilutive purposes in an iterative process, a range of diluted values per share is determined. Through comparison and factoring, if appropriate, these values take into account markets in both Canada and the United States. This analysis is done on a quarterly basis and takes into account factors that have changed from the time of the last common stock issuance. Other factors affecting our assessment of price include recent purchases or sales of our common stock, if available.

Upon the closing of this offering, all of our Series A preferred stock will be mandatorily redeemed for common stock and the Series A preferred stock embedded derivative will no longer be a liability on our balance sheet.

Results of Operations Data:

The following table contains operating data and should be read in conjunction with the information in “Selected Historical Financial and Operational Information:”


							Six Months Ended
	Years Ended December 31,						June 30,
	2005		2006		2007		2007		2008
	(In thousands of Canadian dollars)

Daily net sales volumes:
Natural gas (Mcfe/d)		11,819		55,959		78,930		78,327		78,074
Realized prices(1):
Natural gas (per Mcfe)	C$	9.33	C$	6.55	C$	7.02	C$	7.64	C$	8.57
Expenses per Mcfe:
Operating(2)	C$	3.15	C$	2.11	C$	2.06	C$	2.02	C$	2.05
General and administrative	C$	4.68	C$	1.24	C$	0.70	C$	0.66	C$	1.58
Depletion, depreciation and accretion(3)	C$	4.31	C$	4.12	C$	3.18	C$	3.24	C$	2.25


(1)		Realized prices exclude unrealized mark-to-market gains and losses on commodity contracts.

(2)		Operating expenses include costs of field contractors, compression, chemicals and treating supplies, operating overhead and minor well workovers, as well as transportation expenses, which includes costs to move saleable gas from the plant outlet to its ultimate point of sale.

(3)		Depletion, depreciation and accretion expenses per Mcfe do not include ceiling test impairment charges for the periods ended.

Six Months Ended June 30, 2008 Compared to the Six Months Ended June 30, 2007

Production Revenue. Production revenue increased by C$2.9 million, or 2.7%, to C$110.6 million during the six months ended June 30, 2008 compared to C$107.7 million during the six months ended June 30, 2007. Increased production at the wellhead contributed C$2.9 million more than in the six months ended June 30, 2007. Natural gas prices realized in the six months ended June 30, 2008 increased by C$0.93 per Mcfe, from C$7.64 per Mcfe to C$8.57 per Mcfe, contributing C$13.5 million in additional revenue compared to the six months ended June 30, 2007. This increase was partially offset by an increase in unrealized losses on our derivative contracts of C$11.3 million, C$10.7 million greater than the C$0.6 million loss in the six months ended June 30, 2007. In

addition, the average royalty rate in the six months ended June 30, 2008 increased by 3.6%, from 13.8% to 17.4%, resulting in a reduction in net production of 3.4 Mmcfe per day, resulting in a decrease in revenues of C$5.3 million for thesix-month period ended June 30, 2008, which is included in the C$110.6 million described above. A one-time royalty credit that applied in the six months ended June 30, 2007 resulted in the lower rate for that period. The combination of increased wellhead volumes and offsetting royalty rate resulted in a slight overall reduction of net production from 78,327 Mcfe/d to 78,074 Mcfe/d.

Operating Expenses. Operating expenses increased by C$0.5 million, or 1.6%, to C$29.1 million in the six months ended June 30, 2008 compared to C$28.6 million in the six months ended June 30, 2007. The increase in operating expenses was entirely due to the increase in the number of producing wells in the six months ended June 30, 2008 versus the six months ended June 30, 2007. Operating expenses on a per unit basis were relatively flat at C$2.05 per Mcfe in the six months ended June 30, 2008 compared to C$2.02 per Mcfe in the six months ended June 30, 2007. The operating cost per unit of production decreased by 2.3% on a before royalty volume basis. Royalty credits described above increased the net production volumes in the six months ended June 30, 2007.

General and Administrative Expenses. G&A expenses increased by C$13.1 million, or 139.9%, to C$22.4 million for the six months ended June 30, 2008 compared to C$9.3 million for the six months ended June 30, 2007. Included in the first six months ended June 30, 2008, we recorded a recovery for stock-based compensation of C$1.2 million compared to a recovery of C$1.1 million in the six months ended June 30, 2007. In the six months ended June 30, 2008, we recorded a charge of C$12.6 million relating to an estimate for compensation relating to a long-term incentive plan, none of which was capitalized. For a more detailed discussion on our long-term incentive plan, see “Executive Compensation — Compensation Discussion and Analysis — Annual Incentive Compensation.” In the six months ended June 30, 2008, we capitalized C$3.6 million, or 13.8%, of G&A expenses compared to C$7.9 million, or 45.9% of G&A expenses in the six months ended June 30, 2007. This reduction in capitalized G&A expenses was partially offset by otherwise lower G&A expenses in the six months ended June 30, 2008 compared to the six months ended June 30, 2007. Excluding charges related to the long-term incentive plan and capitalized G&A, we recorded G&A expenses of C$13.4 million in the six months ended June 30, 2008, $3.8 million lower than the C$17.2 million recorded on the same basis in the six months ended June 30, 2007. This reduction was primarily due to decreased overall staffing levels and related compensation expenses from 2007 to 2008.

Depletion, Depreciation and Accretion Expenses. Depletion, depreciation and accretion, or DD&A, expenses decreased by C$72.1 million, or 69.3%, to C$32.0 million for the six months ended June 30, 2008 compared to C$104.1 million for the six months ended June 30, 2007. In the six months ended June 30, 2007, we charged C$58.1 million in impairments to DD&A expenses. We recorded no charges for impairments in the six months ended June 30, 2008. In addition, as a result of an increased total proved reserve base, as measured by our independent oil and gas engineering firm effective June 30, 2008, our DD&A rate was C$2.25 per Mcfe, C$4.06 per Mcfe, or 64.3%, lower than the C$6.31 per Mcfe recorded in the six months ended June 30, 2007. Excluding impairment charges, the DD&A rate was C$2.25 per Mcfe in the six months ended June 30, 2008, and C$0.99 per Mcfe, or 30.6% lower than the C$3.24 per Mcfe recorded in the six months ended June 30, 2007.

Financing Charges. Financing charges increased by C$39.4 million, or 45.0%, to C$126.8 million in the six months ended June 30, 2008 compared to C$87.4 million in the six months ended June 30, 2007. Changes in the fair value of warrants and options resulted in a C$76.3 million charge in the six months ended June 30, 2008 versus a C$12.7 million recovery in the six months ended June 30, 2007. This was partially offset by a recovery related to a lower valuation of the Series A preferred stock embedded derivative of C$9.9 million compared to a C$43.1 million charge in the six months ended June 30, 2007. Both the fair value of warrants and options and the fair value reduction of the Series A preferred stock embedded derivative are principally related to an increase in the valuation of our common share price in the six months ended June 30, 2008 and a reduction of the common share price in the six months ended June 30, 2007. The estimated fair value of the Series A preferred stock embedded derivative is presented as a liability on the consolidated balance sheet with changes in the fair value recorded in the statement of operations in the period they occur. The fair value of the embedded derivative is calculated each balance sheet date using management’s estimates, including the timing for settling the Series A preferred stock. For a more detailed discussion on the Series A preferred stock embedded derivative, see “— Critical Accounting Policies and Estimates — Accounting for Derivative Instruments.”

The decrease in LIBOR of 2.5% from 5.8% in the six months ended June 30, 2007 to 3.3% in the six months ended June 30, 2008 resulted in a reduction of interest expense of C$9.3 million for the six month period. Interest expenses included in financing charges in the six months ended June 30, 2008 amounted to C$61.6 million, a decrease of C$2.9 million from C$64.5 million for the six months ended June 30, 2007 as a result of the decrease in the LIBOR rate, partially offset by higher average long-term debt balances. In the six months ended June 30, 2008, we capitalized C$9.5 million related to interest expenses incurred to conduct capital expenditure activities compared to C$13.5 million in the six months ended June 30, 2007.

Restructuring Charges. Restructuring charges decreased C$14.8 million, or 86.0%, to C$2.4 million during the six months ended June 30, 2008 compared to C$17.2 million in the six months ended June 30, 2007. In the six months ended June 30, 2008, we reorganized by consolidating five departments and eliminating 18 employee and contract positions. We believe that the reorganization was necessary to provide a more efficient operation and reduce the costs related to efforts that were not providing value. In the six months ended June 30, 2007, we incurred C$17.2 million of costs related to severance, retention and third-party advisors in connection with a similar reorganization. We do not expect to record additional charges in connection with this restructuring of our operations and no amounts relating to this restructuring were due as at June 30, 2008.

Foreign Exchange Loss. In the six months ended June 30, 2008, we recognized a foreign exchange loss of C$35.4 million, partially reversing a C$115.3 million gain in the six months ended June 30, 2007. We are subject to foreign exchange gains or losses because the majority of our debt is denominated in U.S. dollars. Foreign exchange gains or losses recognized relate to the TEC second lien credit agreement, the TRC 2006 credit agreement, the Series A preferred stock embedded derivative, the Series B preferred stock and U.S. dollar denominated cash balances. The loss in the six months ended June 30, 2008 was due to the Canadian dollar weakening relative to the U.S. dollar. The gain in the six months ended June 30, 2007 was due to the Canadian dollar strengthening relative to the U.S. dollar. For more information on exchange rates, see the table set forth in “Exchange Rate Data.”

Income Taxes. At June 30, 2008, the tax basis of our petroleum and natural gas properties exceeded their net book value, resulting in a deferred tax asset, as was the case in 2007 and 2006. We have not recognized the value of this asset in our financial statements, because we have not determined that utilization of this asset is more likely than not. As a result, tax expense in both the six months ended June 30, 2008 and in the six months ended June 30, 2007 was limited to capital taxes and no deferred tax expense or recovery was recorded.

Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006

Production Revenue. Production revenue increased by C$62.4 million, or 44.7%, to C$202.0 million in 2007 compared to C$139.6 million in 2006. Increased production contributed C$54.9 million more than in 2006. Natural gas prices realized in 2007 increased by C$0.47 per Mcfe, from C$6.55 per Mcfe to C$7.02 per Mcfe, contributing C$13.5 million in additional revenue compared to 2006. This increase was partially offset by an increase in unrealized losses on our derivative contracts of C$0.3 million, C$6.0 million greater than the C$5.8 million gain in 2006. In addition, the average royalty rate in 2007 decreased by 3.6%, from 18.6% to 15.0%, primarily due to a one-time royalty credit applied in the period. This rate reduction increased our production by 3.3 Mmcfe per day, resulting in an increase in revenues of C$23.5 million for 2007, which is included in the C$202.0 million described above. The increased wellhead production and a reduction of royalty rate combined to significantly increase the overall net production from 55,959 Mcfe/d to 78,930 Mcfe/d.

Operating Expenses. Operating expenses increased by C$16.4 million, or 38.1%, to C$59.5 million in 2007 compared to C$43.1 million in 2006. The increase in operating expenses was primarily due to an increase in the number of producing wells in 2007 and an increase in the number of workovers compared to 2006. In addition, we incurred incremental operating costs during the year due to regulatory compliance requirements in the Horseshoe Canyon operating area. Operating expenses on a per unit basis decreased slightly during 2007 to C$2.06 per Mcfe in 2007, down 2.4% from C$2.11 per Mcfe in 2006, mainly due to economies of scale that we achieved as we refined our operating practices and increased production. Additionally, horizontal wells in the Mannville CBM plays had favorable production rates that partially offset costs at some of our lower producing pilot projects.

General and Administrative Expenses. G&A expenses decreased by C$5.2 million, or 20.5%, to C$20.2 million in 2007 compared to C$25.4 million for 2006. Included in 2007, we recorded a recovery of C$0.6 million

related to stock-based compensation compared to a charge of C$3.1 million in 2006. This decrease is attributable to a decrease in our overall staff during 2007, and resulting higher forfeitures for stock-based compensation, offset partially by increased staffing costs compared to 2006 due to the competitive oil and gas environment. We reduced our staff by more than 50% during the course of 2007. This decrease was offset by an increase in corporate costs associated with a formal solicitation process for the proposed sale of TRC in January 2007. We incurred additional corporate costs after the close of the TRC 2007 subordinated credit agreement, as we employed various consultants until permanent senior management personnel were recruited. In addition, more G&A was expensed rather than capitalized in 2007 compared to 2006 because of a decline in the level of exploration and development activity. We capitalized C$10.5 million, or 34.2%, of G&A expenses during 2007 compared to C$16.7 million, or 39.7%, during 2006.

Depletion, Depreciation and Accretion Expenses. DD&A expenses decreased by C$547.0 million, or 71.4%, to C$219.2 million in 2007 compared to C$766.2 million in 2006. The decrease was primarily due to ceiling test write-downs in 2007 of C$112.8 million, compared to C$682.1 million in 2006. The impairment charges in 2006 were due to the relatively early stage of our operations in combination with the lower period-end gas prices received that year. We determine the ceiling test at the end of each fiscal quarter exclusively on the basis of our then current proved reserves at period-end prices, and we do not therefore take into account reserves that are not yet proved, but which we believe will become proved in the future. These non-cash impairment charges do not impact our expectation of the cash flow contribution from these properties. Offsetting this decrease was a slight increase in DD&A expenses during the year as a result of more costs being added to the depletable base. For December 31, 2007, a constant dollar price of C$6.27 per Mcfe was used to calculate the ceiling test, resulting in a write-down of C$112.8 million.

Contributing to the DD&A expenses in 2007, we recognized a C$14.7 million impairment charge on our non-depletable assets, consisting of C$10.7 million on compressors included in property, plant and equipment during the year, a C$3.9 million write-off of intangible assets originally generated during the purchase of Rakhit Petroleum Consulting Ltd., as well as a C$0.1 million impairment charge on an investment. We wrote down the compressors to their estimated net realizable value. We recorded no comparable write-downs during 2006.

Financing Charges. Financing charges decreased by C$122.6 million, or 41.9%, to C$170.3 million in 2007 compared to C$292.9 million in 2006. This decrease was due to the recognition of the smaller unrealized loss of C$61.1 million, down 72.2%, on the Series A preferred stock embedded derivative during 2007 compared to the unrealized loss of C$219.8 million during 2006. The estimated fair value of the Series A preferred stock embedded derivative is presented as a liability on the consolidated balance sheet with changes in the fair value recorded in the statement of operations in the period they occur. The fair value of the embedded derivative is calculated each balance sheet date using management’s estimates, including the timing for settling the Series A preferred stock. For a more detailed discussion on the Series A preferred stock embedded derivative, see “— Critical Accounting Policies and Estimates — Accounting for Derivative Instruments.” In addition, during 2007, we recognized C$131.1 million in interest and fees related to our various credit facilities, up 64.9%, compared to C$79.5 million in interest and fees in 2006. This increase was attributed to higher average balances drawn on our secured term loan facility during 2007, to the fact that our subordinated credit facility was outstanding for the entire year compared to only one month in 2006, and to the fact that we had a new unsecured facility from August 2007 to the end of the year. We capitalize interest on unproved properties that are not currently being depleted and depreciated. During 2007, we capitalized C$23.4 million of interest, up 29.3% compared to C$18.1 million in 2006. Offsetting this increase, during 2007 we recognized an unrealized gain on lenders’ warrants of C$12.7 million, up 119.0% compared to C$5.8 million in 2006. The increase relates to a decline in the fair value of our common stock as previously discussed.

Restructuring Charges. During 2007, we incurred an expense of C$20.7 million as a result of significant charges related to our corporate restructuring. This corporate restructuring period began in January 2007. These charges included an aggregate of C$6.0 million of severance payments made to various staff and executive employees, retention payments made to certain staff members and additional directors fees resulting from an increase in the number of board meetings related to the restructuring. In connection with the corporate restructuring, we worked with a number of third party advisors to assist us with human resource, finance and cash management issues, as well as specialized restructuring legal counsel. Throughout this process, we also committed to paying

legal and advisory costs for our various debtholder and stockholder groups. These advisors were paid monthly retainer fees, hourly rates, or a combination of both. In June 2007, we decided to raise additional capital, rather than proceed with a corporate restructuring. From that time, any costs pertaining to the financing were considered deferred financing costs. Upon the closing of the TRC 2007 subordinated credit agreement in August 2007, the restructuring was substantially complete. There were no comparable costs incurred during 2006.

Foreign Exchange (Gain) Loss. In 2007, we recognized a foreign exchange gain of C$202.1 million, more than reversing the loss of C$18.6 million recognized in the same period in 2006. We are subject to foreign exchange gains and losses because the majority of our debt is denominated in U.S. dollars. Foreign exchange gains recognized relate to the TEC second lien credit agreement and the TRC 2006 credit agreement, as well as the Series A preferred stock embedded derivative and Series B preferred stock. The gain in 2007 was due to the significant strengthening of the Canadian dollar relative to the U.S. dollar. In 2006, the loss was due to the slight weakening of the Canadian dollar relative to the U.S. dollar. For more information on exchange rates, see the table set forth in “Exchange Rate Data.”

Income Taxes. At December 31, 2007, our income tax reduction was C$nil, compared to C$64.5 million for the year ended December 31, 2006. The income tax reduction during the year 2006 was primarily due to the ceiling test write-downs during that period.

Due to the ceiling test write-down of our petroleum and natural gas properties, the tax basis of these properties exceeds their net book value. This results in a deferred tax asset that we have not recognized because we have not determined that utilization of this asset is more likely than not.

Year Ended December 31, 2006 Compared to the Year Ended December 31, 2005

Production Revenue. Production revenue increased by C$99.3 million, or 246.4%, to C$139.6 million in 2006 compared to C$40.3 million in 2005. Increased production would have contributed C$150.3 million more than in 2005 at 2005 prices. Natural gas prices realized in 2006 decreased by C$2.78 per Mcfe, from C$9.33 per Mcfe to C$6.55 per Mcfe, offsetting these production gains by C$56.7 million compared to 2006. The overall growth of net revenue was further driven by increases to unrealized gains on our derivative contracts of C$5.8 million compared to C$nil in 2005. In addition, the average royalty rate in 2006 decreased by 2.8%, from 21.4% to 18.6%, primarily due to the lower sliding-scale royalty rate, impacted by an overall lower price environment. This rate reduction increased our production by 1.9 Mmcfe per day, resulting in an increase in revenues of C$12.6 million for 2006, which is included in the C$139.6 million described above. The increased wellhead production and a reduction of royalty rate combined to significantly increase the overall net production from 11,819 Mcfe/d to 55,959 Mcfe/d.

Operating Expenses. Operating expenses increased by C$29.5 million, or 216.9%, to C$43.1 million during 2006 compared to C$13.6 million in 2005. The increase in operating expenses was primarily due to an increase in the number of producing wells in 2006. Operating expenses per unit decreased to C$2.11 per Mcfe in 2006, down 33.0%, from C$3.15 per Mcfe in 2005 mainly due to economies of scale that we achieved as we refined our operating practices and increased production. In 2006, the cost of power consumption on a per unit basis decreased substantially as a greater portion of our drilled wells in the Mannville CBM plays completed dewatering and moved into production.

General and Administrative Expenses. G&A expenses increased by C$5.2 million, or 25.7%, to C$25.4 million during 2006 compared to C$20.2 million for 2005. C$10.6 million of this increase was primarily attributable to the increase in wages and related benefits from the hiring of additional personnel due to increased drilling activities. Offsetting this increase, we charged C$3.1 million related to stock-based compensation in 2006 compared to C$6.2 million in 2005. The lower charge was due to fewer stock option grants in 2006 versus 2005 and increases to our forfeiture rate.

Depletion, Depreciation and Accretion Expenses. DD&A expenses increased by C$727.4 million to C$766.2 million in 2006 compared to C$38.8 million in 2005, due primarily to ceiling test write-downs in 2006 of C$682.1 million compared to C$20.2 million in 2005. These impairment charges were primarily due to the relatively early stage of our operations in combination with the lower period-end gas prices. The ceiling test is determined at the end of each fiscal quarter exclusively on the basis of our then current proved reserves and does not

take therefore into account reserves that are not yet proved but which we believe will become proved in the future. These non-cash impairment charges do not impact our expectation of the cash flow contribution from these properties. For December 31, 2006, a constant dollar price of C$5.96 per Mcfe was used to calculate the ceiling test, resulting in a write-down of C$682.1 million.

Financing Charges. Financing charges increased by 600.7% to C$292.9 million in 2006, compared to C$41.8 million in 2005. During 2006 we recognized an unrealized loss of C$219.8 million on the Series A preferred stock embedded derivative, up 2,013%, compared to an unrealized loss of C$10.4 million recognized in 2005. The estimated fair value of the Series A preferred stock embedded derivative is presented as a liability on the consolidated balance sheet with changes in the fair value recorded in the statement of operations in the period they occur. The fair value of the embedded derivative is calculated on each balance sheet date using management’s estimates, including the timing for settling of the Series A preferred stock and the estimate of the fair value of our common stock. For a more detailed discussion on the Series A preferred stock embedded derivative, see “— Critical Accounting Policies and Estimates —Accounting for Derivative Instruments.”

In 2006, we recognized C$79.5 million in interest and fees on credit facilities related to the TEC first lien credit agreement, the TEC second lien credit agreement, the TRC 2006 credit agreement, and an unsecured term loan facility that was drawn and repaid within the year, up 318.4% compared to C$19.0 million in interest and fees recognized in 2005 related to the TEC first lien credit agreement and the TEC second lien credit agreement. We capitalized interest on unproved properties that were not currently being depleted and depreciated. During 2006, we capitalized C$18.1 million of interest, up 174.2%, compared to C$6.6 million in the prior year.

Foreign Exchange (Gain) Loss. In 2006, we recognized a foreign exchange loss of C$18.6 million compared to a gain of C$11.8 million in the same period in 2005. The increase is primarily due to the timing of cash flows related to debt issuances and repayments, particularly in connection with the TRC 2006 credit facility, which we entered into in November 2006. We are subject to foreign exchange gains or losses primarily because the majority of our debt is denominated in U.S. dollars. Foreign exchange gains and losses are recognized relating to the TEC second lien credit agreement, the TRC 2006 credit agreement, the Series A preferred stock embedded derivative, the Series B preferred stock, and U.S. dollar denominated cash balances. For more information on exchange rates, see the table set forth in “Exchange Rate Data.”

Loss (gain) on Disposition of Equity Investment. In 2006, we recorded a gain of C$21.2 million on the disposition of our equity ownership interest in Ammonite Drilling Ltd. We received C$26.2 million in cash proceeds on the sale.

Income Taxes. At December 31, 2006, our income tax reduction was C$64.5 million, up 428.7%, compared to C$12.2 million for the year ended December 31, 2005. It was established using the statutory U.S. federal rate of 35%. The increase in our income tax benefit is due to the tax effect of the ceiling test write-down in 2006.

For 2006, our effective tax rate was 6.5% compared to 19.5% for 2005. The difference between the statutory U.S. federal rate of 35% and our effective rate was primarily due to non-deductible non-cash financing charges on the Series A preferred stock embedded derivative. These non-deductible permanent differences caused our effective tax rate to be lower than the statutory rate that would have been effective if the costs would have been deductible. Due to the ceiling test write-down in 2006, the tax basis of our properties exceeds their net book value. This results in a deferred tax asset which we have not recognized because we have not determined that utilization of this asset is more likely than not.

Reserve Data


					Six Months
					Ended
					June 30,
	2006		2007		2008

Estimated net proved reserves:
Proved developed producing (Mmcfe)		87,420.6		92,016.6		221,789.0
Proved developed non-producing (Mmcfe)		16,564.2		15,675.0		10,455.9

Total proved developed (Mmcfe)		103,984.8		107,691.6		232,244.9
Proved undeveloped (Mmcfe)		60,307.8		58,416.0		162,695.7

Total proved reserves (Mmcfe)		164,292.6		166,107.6		394,940.6

PV-10 (in millions)(1)	C$	366.9	C$	402.5	C$	1,456.3
Income tax effect discounted at 10% (in millions of C$)		—		—		(169.0	)

Standardized measure of discounted future net cash flows (in millions)(2)	C$	366.9	C$	402.5	C$	1,287.3

Price used for proved reservePV-10 (AECO-C index price in C$ per Mcfe as of December 31 and NGX AB-NIT index price in C$ per Mcfe as of June 30)	C$	6.13	C$	6.52	C$	11.70


(1)		PV-10 is a non-GAAP measure that represents the present value of estimated future net revenues attributable to our reserves using constant prices, as of the calculation date, discounted at 10% per year on a pre-tax basis.PV-10 was determined based on the market prices for natural gas as of December 31 2006 and 2007, and as of June 30, 2008. The natural gas prices used for the calculations as of December 31, 2006 and 2007, and as of June 30, 2008 were C$6.13, C$6.52 and C$11.70, respectively. These prices were based on AECO-C prices as of December 31, 2006 and 2007 and NGX AB-NIT as of June 30, 2008, and were adjusted to account for transportation costs and any difference in quality as applicable. The oil prices used for the calculations as of December 31, 2006 and 2007, were C$67.59 and C$93.44, respectively.PV-10 differs from standardized measure of discounted future net cash flows because it does not include the effects of income taxes on future net cash flows.PV-10 does purport to present an estimate of fair market value of our reserves. AlthoughPV-10 is not a financial measure calculated in accordance with GAAP, management believes that the presentation ofPV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to any given company affect the amount of estimated future income taxes, we believe that the use of a pre-tax measure is helpful when comparing companies in our industry.

(2)		Calculated based on our net proved reserves. The “standardized measure of discounted future net cash flows” is the present value of our estimated future net cash flows, discounted at 10% per year, calculated using constant pricing, utilizing the same prices that we used to calculatePV-10 as described in footnote (2). The standardized measure of discounted future net cash flows does not purport to present the fair market value of our natural gas reserves and is not indicative of actual future net cash flows.

Liquidity and Capital Resources

Our primary sources of cash have been cash flow from operations, equity and debt financings. Our primary uses of cash have been, and we expect will continue to be, acquisitions, exploration for and development of natural gas properties, expenses for continued operations, G&A costs and repayment of principal and interest on outstanding credit facilities.

Subsequent to June 30, 2008, we collected a C$35.1 million receivable from a joint venture partner, representing twelve months of outstanding receivables to June 30, 2008.

As of June 30, 2008, the principal amount of our total indebtedness was US$983.2 million and we had C$5.6 million of letters of credit outstanding. Our credit facilities generally prohibit us from incurring additional indebtedness.

We have financed our operations since 2004 through various equity and debt transactions, including a subordinated credit facility for TEC, a TEC first lien credit agreement, sales of shares of our common stock in private transactions, sales of our Series A preferred stock in private transactions, a TEC second lien credit agreement, sales of our Series B preferred stock in private transactions, the TRC 2006 credit agreement and the TRC 2007 subordinated credit agreement. See “The Recapitalization.”

Historical Indebtedness and Capital Structure

We will use the aggregate net proceeds from this offering, our new revolving credit facility and our senior notes, together with cash on hand, to repay all of the outstanding indebtedness under our TEC first lien credit agreement, TEC second lien credit agreement, TRC 2006 credit agreement and TRC 2007 subordinated credit agreement.

The following is a description of our credit facilities and preferred stock prior to the closing of this offering:

TEC First Lien Credit Agreement. TEC is the borrower under a secured revolving facility with a maximum availability of C$10.0 million, dated as of July 8, 2004, as amended and restated as of December 16, 2005, and as subsequently amended. The revolving facility may be used for revolving loans, bankers’ acceptances and letters of credit. The revolving facility bears interest at a rate of bank prime plus 1% for Canadian or U.S. prime rate loans and LIBOR plus 2.0% for LIBOR loans and provides for a 2.0% fee and discounted proceeds for bankers’ acceptances and undrawn letters of credit. The revolving facility has a commitment fee of 0.5% per annum on undrawn amounts. The revolving facility’s borrowing base is based on the lenders’ assessment of the lending value of the proved reserves of TEC and its material subsidiaries and their respective lending criteria and practices in effect at the time of determination for loans to borrowers in the Canadian petroleum and natural gas industry. The revolving facility is secured by all present and future assets of TEC and its material subsidiaries, and contained certain financial covenants which required a minimum tangible net worth and the maintenance of positive working capital. On April 13, 2006, the revolving facility was amended to remove the positive working capital covenant and on March 18, 2008, the revolving facility was amended to remove the minimum tangible net worth covenant.

At June 30, 2008, we had C$5.6 million of letters of credit outstanding under the revolving facility. The revolving facility expires on October 2, 2009. The revolving facility provides restrictions on TEC, limiting the payment of any dividends or distributions to us for anything other than general corporate expenses incurred in the normal course of business. In the first half of 2008, and in 2007, 2006 and 2005, no cash dividends were paid to us by any of our subsidiaries.

TEC Second Lien Credit Agreement. TEC is the borrower under a second lien credit agreement dated April 25, 2006 for US$500.0 million. This loan matures on April 26, 2011 in respect of term advances of US$450.0 million (and April 26, 2012 in respect of US$50.0 million). On base rate advances, the loan bears interest at the rate of 6.5% plus a base rate equal to the greater of the U.S. Federal Funds Rate plus 0.5% and the prime rate. On eurodollar advances, the rate is LIBOR plus 7.5%. This facility is prepayable at any time, subject to a 2.0% premium if prepaid on or prior to August 20, 2009. This agreement is secured by a second lien on the assets securing the TEC first lien credit agreement and has similar covenants to the first lien credit agreement, and also prohibits us from incurring additional debt, subject to limited exceptions. At June 30, 2008, TEC had US$500 million outstanding under this agreement.

TRC 2006 Credit Agreement. We are the borrower under a credit agreement dated November 24, 2006, for US$270.0 million. This facility matures on November 24, 2011. On base rate advances, the loan bears interest at the rate of 11.0% plus a base rate equal to the greater of the U.S. Federal Funds Rate plus 0.5% and the prime rate. On eurodollar advances, the rate is LIBOR plus 12.0%. Prior to November 24, 2008, we pay interest on the TRC 2006 credit agreement in-kind by capitalization of accrued interest. We may elect to pay interest during the period from November 24, 2008 until November 23, 2009 in cash or in-kind. If we elect to

pay interest on the TRC 2006 credit agreement facility during such period in-kind, then on and after November 24, 2008, the interest rates on all loans under the TRC 2006 credit agreement permanently increase by 2.0%. This facility is prepayable at any time, subject to a 5.0% premium until November 24, 2008, a 2.5% premium from November 25, 2008 to August 19, 2009, and no premium after August 20, 2009. This credit facility is secured by certain present and future assets of TRC and its U.S. subsidiaries. This agreement has similar covenants to the other credit agreements, and also prohibits us from incurring additional debt, subject to limited exceptions. At June 30, 2008, we had US$353.0 million outstanding under this agreement.

TRC 2007 Subordinated Credit Agreement. We are the borrower under an unsecured subordinated credit agreement dated August 20, 2007, for C$120.0 million. This facility matures on August 31, 2012. On base rate advances, the loan bears interest at the rate of 6.5% plus a base rate equal to the greater of the U.S. Federal Funds Rate plus 0.5% and the prime rate. On eurodollar advances, the rate is LIBOR plus 7.5%. Interest is due at maturity, and prior to maturity accrued but unpaid interest bears interest at the same rates as principal. This facility is prepayable at any time, subject to a make-whole premium until August 19, 2009, and after that date, subject to a 1.0% premium. In the case of any prepayment made prior to August 20, 2009 and not later than 90 days after the closing of certain specified transactions (including a sale or all or substantially all assets, certain change of control transactions, and a qualifying initial public offering yielding net proceeds in excess of US$100.0 million), the prepayment premium is 1.0% in lieu of the otherwise applicable make-whole premium. This agreement has similar covenants to the other credit agreements, and also prohibits us from incurring additional debt, subject to limited exceptions. At June 30, 2008, we had US$130.2 million of principal and accrued but unpaid interest outstanding under this agreement.

Preferred Stock and Warrants. We currently have outstanding 5,607,559 shares of Series A and Series B preferred stock, representing all of the issued and outstanding shares of Series A and Series B preferred stock as at June 30, 2008. Each share of preferred stock was issued as part of a unit with a preferred warrant to purchase shares of our common stock. Upon the closing of this offering, all of our shares of preferred stock will be mandatorily redeemed and the preferred warrants will be automatically exercised in connection therewith. The number of shares issuable upon the redemption of the preferred stock and automatic exercise of the preferred warrants is subject to adjustment based on a minimum compounded annual rate of return of 15% which the holders of the preferred units are entitled to receive on their initial investment of US$62.50 in the preferred units. At an assumed closing date of 2009, the holders of the preferred stock are entitled to receive an aggregate of US$ million, payable in shares of our common stock upon exercise of the preferred warrants. For a further description of our preferred stock and preferred warrants, see “The Recapitalization — Preferred Stock and Preferred Warrants.”

Indebtedness Following this Offering

Following this offering, our indebtedness will consist of our new revolving credit facility and our senior notes.

Cash Flows


										Six Months Ended
	Years Ended December 31,									June 30,
	2005			2006			2007			2007			2008
	(In thousands of Canadian dollars)

Net cash provided by (used for) operating activities	C$	(3,579	)	C$	16,127		C$	55,257		C$	15,119		C$	58,765
Net cash provided by (used for) financing activities		671,436			701,410			91,257			(9,095	)		(33	)
Net cash used for investing activities		(604,979	)		(664,377	)		(128,402	)		(76,826	)		(94,266	)

Operating Activities. Cash provided by operating activities in the six months ended June 30, 2008 increased by C$43.7 million, or 289.4%, to C$58.8 million compared to C$15.1 million in the six months ended June 30, 2007. Increased natural gas sales and lower restructuring costs more than offset increased cash operating, financing, and G&A expenses.

Net cash provided by operating activities during 2007 totaled C$55.3 million, up C$39.2 million or 242.6%, from net cash provided by operating activities of C$16.1 million during 2006. Increased natural gas sales, the dominant reason for the increase, and decreased G&A expenses more than offset increased cash operating, interest and restructuring charges.

Net cash provided by operating activities during 2006 totaled C$16.1 million, up C$19.7 million, from the C$3.6 million in net cash used by operating activities in 2005. The increase was due primarily to increased natural gas sales in 2006 above 2005. The significant increase in natural gas sales more than offset the corresponding increase in operating and G&A expenses during the year. Our negative cash flow from operating activities in 2005 was funded from cash provided by financing activities during the year.

Financing Activities. Net cash provided by financing activities in the six months ended June 30, 2008, totaled C$0.03 million, which is a decrease of virtually all of the C$9.1 million of net settlements in the six months ended June 30, 2007, resulting from a lack of significant financing activities during 2008.

Net cash provided by financing activities in 2007 totaled C$91.3 million, down 87.0% or C$610.2 million from 2006 as a result of the debt and equity transactions described above. The C$120 million of gross proceeds raised in 2007 was considerably less than the C$868 million of equity and debt raised in 2006. These transactions are described in more detail in “— Liquidity and Capital Resources — Historical Indebtedness and Capital Structure.”

Net cash provided by financing activities increased in 2006 to C$701.4 million, up 4.5%, from C$671.4 million in 2005. The increase was a result of the debt and equity transactions described herein.

Investing Activities. Our main use of cash for investing activities continues to be for the purchase and acquisition of property, plant and equipment and capitalized G&A costs.

Net cash used by investing activities in the six months ended June 30, 2008 totaled C$94.3 million, up 22.8% compared to C$76.8 million in the six months ended June 30, 2007. The increase is attributable to increased exploration and exploitation activities in the Mannville CBM plays and Horseshoe Canyon CBM play and the commencement of exploration activities in the Montney Shale play in 2008.

Net cash used by investing activities in 2007 totaled C$128.4 million, down 80.7% or C$536.0 million from 2006, and 78.8% or C$476.6 million from 2005. In 2007, we limited our exploration and development programs to a strict focus on the Mannville CBM plays and Horseshoe Canyon CBM play. In 2005 and 2006, we had increased our land position through land auctions and through the acquisition of the working interest of a significant shareholder of TEC in the Greater Corbett Creek area for an aggregate amount of C$202.6 million. At that time, we also entered into negotiated arrangements for the right to earn land from other industry participants by drilling wells. For a further description of our investment activities, see “— Capital Expenditures.”

Capital Expenditures

Over the past three years, we have shifted our capital expenditure activities from a very large capital program to a more modest capital program. In 2005 and 2006, we incurred C$503.1 million and C$653.4 million, respectively, in capital expenditures, which were dominated by drilling and facilities construction activities in our Mannville CBM and Horseshoe Canyon CBM plays. After 2006, we significantly reduced facilities construction because the infrastructure to deliver natural gas production in both our Mannville CBM and Horseshoe Canyon CBM plays was substantially complete. In 2007, we incurred C$89.7 million in capital expenditures, mainly for drilling activities. In the first six months of 2008, we incurred $61.9 million of capital expenditures also, as in 2007, mainly for drilling activities.

Our capital expenditures in the six months ended June 30, 2008 increased to C$61.9 million, up 64.4% from C$37.6 million in the six months ended June 30, 2007, primarily due to higher capital expenditures related to increased drilling and the expansion of certain Mannville CBM facilities in 2008. We also commenced an exploration program on the Montney acreage where we shot and processed3-D seismic imaging over our lands. In the six months ended June 30, 2008, we participated in drilling 32 gross (20 net) wells compared to 17 gross (7 net) wells in the six months ended June 30, 2007.

Our capital expenditures in 2007 decreased to C$89.7 million, down 86.3% from C$653.4 million in 2006. We participated in drilling 84 gross (41 net) wells in 2007, down from 424 gross (254 net) wells in 2006. For the first eight months of the year, we had restricted access to capital, which was alleviated with the additional financing in August 2007.

Capital expenditures increased to C$653.4 million in 2006, up 29.9%, compared to C$503.1 million in 2005. In 2006, we spent C$39.0 million to expand our landholdings through acquisitions and Crown land sales. In addition, in 2006 we drilled 424 gross (254 net) wells compared to 474 gross (288 net) wells in 2005.

In 2008, we plan to continue to explore and exploit our core producing and non-producing properties through the continuing development of the Mannville and Horseshoe Canyon CBM plays and the commencement of drilling of the Montney Shale gas play. If long-term natural gas prices decrease to a level that we deem to be uneconomical, we could reduce, defer or cancel planned capital expenditures. We plan to complete only capital projects we believe would meet our target levels of expected returns and cash flow generation. We continue to monitor and may adjust our capital expenditures in response to operating experience, engineering analysis, and changes in natural gas prices, exploration and development costs, industry conditions and capital resource availability. The unavailability or high cost of drilling rigs, equipment, supplies and personnel, as well as weather and the time required to receive permits, could also affect the timing of our capital expenditures.

Commitments and Contractual Obligations

The following table sets forth our commitments and contractual obligations as at December 31, 2007:


	Payments Due by Period
	Less than						More Than
	1 Year		1-3 Years		4-5 Years		5 Years		Total
	(In thousands of Canadian dollars)

Long-term debt	C$	66,369	C$	224,980	C$	1,343,309	C$	—	C$	1,634,658
Operating lease obligations		2,794		4,759		3,525		1,320		12,398
Drilling obligations		3,641		5,975		—		—		9,616

Total	C$	72,804	C$	235,714	C$	1,346,834	C$	1,320	C$	1,656,672

In addition, as of December 31, 2007, we had US$500.0 million (C$495.7 million) outstanding under the TEC second lien credit agreement which bears interest at a rate of LIBOR plus 7.5% per annum. No principal payments are required before US$450.0 million (C$446.1 million) of the facility matures on April 26, 2011. The balance of US$50.0 million (C$49.6 million) matures on April 26, 2012. In addition, we had US$326.6 million (C$323.8 million) outstanding under the TRC 2006 credit agreement, which bears interest at LIBOR plus 12.0%. Prior to November 24, 2008, we pay interest on the TRC 2006 credit agreement in-kind by capitalization of accrued interest. We may elect to pay interest during the period from November 24, 2008 until November 23, 2009 in cash or in-kind. If we elect to pay interest on the TRC 2006 credit agreement during such period in-kind, then on and after November 24, 2008, the interest rate under the TRC 2006 credit agreement permanently increases to LIBOR plus 14.0%. No principal payments are required until the facility matures on November 24, 2011. Lastly, as of December 31, 2007, we had C$125.8 million outstanding under the TRC 2007 subordinated credit agreement that bears interest at LIBOR plus 7.5%. Interest on the TRC 2007 subordinated credit agreement is due at maturity, and prior to maturity accrued but unpaid interest bears interest at the same rate as principal. To calculate the required obligation under our credit facilities, we utilized the year-end three month LIBOR rate of 4.85% and a one month LIBOR rate of 4.70% and the annual foreign exchange rate of C$1.07/US$1.00 for all periods disclosed. For principal repayment amounts, we used the year-end foreign exchange rate of C$0.99/US$1.00.

On a pro forma basis, after giving effect to this offering, and the incurrence of indebtedness under our new revolving credit facility and our senior notes, and the application of the aggregate net proceeds from this offering as

described in “Use of Proceeds,” our contractual obligations and commitments as of December 31, 2007, would have consisted of the following:

Payments due by Period

Less than

More Than

1 Year

1-3 Years

4-5 Years

5 Years

Total

(In thousands of Canadian dollars)

Long-term debt

Operating lease obligations

Drilling obligations

Total

Off-Balance Sheet Arrangements

We have entered into fixed price physical delivery natural gas sales contracts to mitigate the potential adverse impact of changing commodity prices. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.” We have elected to account for these fixed price physical delivery natural gas sales contracts as normal sales expected in the normal course of business under FAS 138 and accordingly, these contracts are not recorded on the balance sheet.

Related Parties

For information on related party transactions, see “Certain Relationships and Related Party Transactions.”

Quantitative and Qualitative Disclosures About Market Risk

In order to manage our exposure to market risk, we developed a risk management policy. Under this policy, we may enter into agreements, including fixed price, forward price, physical purchase and sales contracts, futures, currency swaps, financial swaps, option contracts, collars and put options subject to the approval of our board of directors. Management periodically evaluates the need to enter into such arrangements upon capital requirements or lending obligations.

Commodity Price Risk

We are exposed to fluctuations in natural gas prices because a substantial portion of our production is currently sold at spot prices, which are extremely volatile. Natural gas commodity prices fluctuate in response to, among other things, Canadian, U.S. and foreign supply/demand and reserve levels, level of consumer demand, Canadian, U.S. and global economic conditions, inventories in storage, import/export balances, government regulations, political and economic conditions in gas and oil producing countries and fluctuations in the availability and price of other replacement energy sources. A significant drop in natural gas commodity prices could materially impact our natural gas sales, the volume of production we could produce economically, require downward adjustments to proved reserves for the first half of 2008 and could materially impact our financial condition. See “Risk Factors — Natural gas prices are volatile and a significant decline in natural gas prices could significantly affect our financial results and financial condition and impede our growth.” Based on our natural gas sales volumes for the first half of 2008, a change of C$1.00 per Mcfe in the weighted-average realized price of natural gas would increase or decrease our six-month natural gas sales by approximately C$22.6 million, after incorporating the effects of hedge activities and risk management contracts. We have entered into several natural gas financial contracts to achieve more predictable cash flows, reduce our exposure to adverse fluctuations in the price of natural gas and comply with the covenants within our credit agreements.

Our hedging activities are conducted pursuant to our risk management policy approved by our board of directors. We use a combination of fixed price forward contracts and financial instruments designed to establish a minimum floor price and a maximum ceiling price. These contracts extend throughout the 2008 calendar year to

February 2009. Our risk management policy provides guidance to reduce the risk exposure to budgeted annual cash flow projections resulting from uncertainty or changes in natural gas prices.

Weighted

Average Price

Contract Type

Volume (GJ/day)

Pricing Point

($/GJ)

Term

Costless Collar(1)

10,000

AECO-C

7.00-C$8.33

July 2008-October 2008

Costless Collar(1)

10,000

AECO-C

7.00-C$7.75

July 2008-September 2008

Fixed Price(2)

12,000-30,500

AECO-C

6.21-C$8.15

July 2008-February 2009


(1)		Costless collar strike prices indicate minimum floor and maximum ceiling.

(2)		Physical delivery.

In August 2008, we entered into natural gas sales contracts to hedge an additional 7,000 GJ per day from September 2008 and October 2008 at fixed prices of C$7.09 per GJ and C$7.27 per GJ, respectively. In September 2008, we entered into additional natural gas sales contracts of 6,200 GJ per day in November 2008 at fixed prices averaging $6.50 per GJ; 6,700 GJ per day in December 2008 at fixed prices averaging C$7.09 per GJ; and 28,600 GJ per day from March 2009 through June 2009 at fixed prices averaging C$7.20 per GJ.

Interest Rate Risk

We are exposed to changes in interest rates, primarily due to the fact that our term loan facilities bear interest at floating rates and also potentially due to our revolving credit facility. We have not entered into any interest rate swaps to limit or manage our exposure to fluctuations in interest rates. A 10% change in the floating interest rate (approximately 0.28%) would change our annual interest expense by approximately C$2.8 million. To calculate the change, we used a LIBOR rate of 2.80% at June 30, 2008, based on our debt balance of US$983.2 million as at June 30, 2008. For the purpose of this calculation we used the June 30, 2008 closing foreign exchange rate of C$1.0197 / US$1.00. While we have sought to reduce the effect of Canadian dollar-U.S. dollar exchange rate fluctuations by placing US$50 million purchased in the open market in a money market account in the first six months of 2008, the dollar value of this transaction may not be sufficient to cover all of our interest due in 2008.

Foreign Currency Risk

We are exposed to foreign currency exchange rate fluctuations on U.S. dollar denominated cash balances, the U.S. dollar denominated term loan facilities, the Series A preferred stock embedded derivative and the Series B preferred stock. We currently do not have fixed rate arrangements to mitigate foreign exchange risk, however we continue to monitor our exposure and may enter into foreign exchange hedges if deemed appropriate. While we have sought in 2008 to reduce the effect of Canadian dollar-U.S. dollar exchange rate fluctuations by placing US$50 million purchased in the open market in a money market account in the first six months of 2008, the dollar value of this transaction may not be sufficient to provide complete protection against the fluctuating currency exposure. Based on the period-end carrying value of our U.S. dollar cash balances of US$43.6 million, our Series A preferred stock embedded derivative, our Series B preferred stock and our outstanding debt of US$853.0 million as at June 30, 2008, a $0.01 change in the C$/US$ exchange rate would result in an approximate change of C$12.2 million for foreign exchange loss (gain). Due to the cyclical nature of the interest rates, this calculation has been prepared without reflecting the potential impact that a change in foreign exchange rates would have on the U.S. dollar denominated interest expense on our outstanding debt. The strengthening of the Canadian dollar by C$0.01 reduces our interest expense by C$1.0 million and the weakening of the Canadian dollar by C$0.01 increases our interest expense by C$1.0 million.

Recently Issued Accounting Standards

In July 2006, the Financial Accounting Standards Board, or FASB, issued Interpretation 48,Accounting for Uncertainty in Income Taxeswith respect to FAS 109Accounting for Income Taxesregarding accounting for and disclosure of uncertain tax positions. This guidance seeks to reduce the diversity in practice associated with certain

aspects of the recognition and measurement related to accounting for income taxes. This interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of this statement did not have a material impact on our results of operations or financial position.

In September 2006, FASB issued Statement 157,Fair Value Measurements, or FAS 157. FAS 157 defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. FAS 157 is effective for fiscal years beginning after November 15, 2007 (and November 15, 2008 for the measurement of non-financial assets and liabilities). We adopted FAS 157 on January 1, 2008 and it did not have a material impact on the consolidated results of operations or financial position.

In February 2007, FASB issued Statement 159,Fair Value Option for Financial Assets and Financial Liabilities, or FAS 159. FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value and applies to other accounting pronouncements that require or permit fair value measurements. FAS 159 is effective for fiscal years beginning after November 15, 2007. We adopted FAS 159 and it did not have a material impact on our consolidated results of operations or financial position.

In December 2007, FASB issued Statement 160,Non-controlling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin No. 51, or FAS 160, which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the non-controlling interest, changes in a parent’s ownership interest and the valuation of retained non-controlling equity instruments when a subsidiary is deconsolidated. The statement also establishes disclosure requirements to clearly identify and distinguish between the interests of the parent and the interest of the non-controlling owners. FAS 160 is effective for fiscal years beginning after December 15, 2008. We plan to implement this standard on January 1, 2009. When adopted, our minority interest positions on the balance sheet will be presented as a component of equity. We do not anticipate a material change to our consolidated results of operations or financial position when this is adopted.

In December 2007, FASB issued Statement 141(R),Business Combinations, or FAS 141R. FAS 141R provides greater consistency in the accounting and financial reporting of business combinations. It requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed, and requires the acquirer to disclose the nature and financial effect of business combination. FAS 141R is effective on a prospective basis for fiscal years beginning after December 15, 2008.

In March 2008, FASB issued Statement 161,Disclosures about Derivative Instruments and Hedging Activities — an Amendment of FASB Statement No. 133, or FAS 161, which expands the disclosure requirements for derivative instruments and hedging activities with respect to how and why entities use derivative instruments, how they are accounted for under FAS 161 and the related impact on financial position, financial performance and cash flows. FAS 161 is effective for fiscal years beginning after November 15, 2008. We plan to implement this standard on January 1, 2009. When adopted, we do not anticipate a material change to our consolidated results of operations or financial position.

In May 2008, FASB issued Statement 162,The Hierarchy of Generally Accepted Accounting Principles, which codifies the sources of accounting principles and the related framework to be utilized in preparing financial statements in conformity with GAAP. We do not anticipate any impact on our consolidated results of operations or financial position when this is adopted.

INDUSTRY

We are an independent natural gas production company focused on exploring for and exploiting unconventional natural gas resources, primarily targeting coalbed methane, or CBM, and shale gas.

Unconventional Natural Gas Resource Plays

Unconventional natural gas resource plays are often found in coal seams, shale formations and low permeability sandstones, and require innovative technology and practices to extract natural gas in commercial quantities. Compared to conventional exploration and exploitation, unconventional natural gas resource plays generally have lower geological risk once the area limits of the play have been defined by drilling, testing and commercial well production. Unconventional natural gas plays present numerous low-risk drilling opportunities that typically result in production levels and reserves within a predictable range.

Both Canada and the United States have a vast potential of unconventional resources that are becoming a meaningful source of natural gas production for North America. According to the 2007 Unconventional Gas Guide published by the Canadian Society for Unconventional Gas, unconventional gas currently accounts for 25% of Canadian natural gas production and 45% of U.S. production, with conventional natural gas production reaching a peak in each country in 2001 and 1973, respectively. We believe that the implications for unconventional resources are significant as conventional natural gas production declines while North American natural gas demand is projected to grow from 25 Tcf in 2006 to 30 Tcf by 2025. Because unconventional resource estimates in Canada are approximated at over 4,000 Tcf, we believe that exploitation of these resources is likely to occur at a rapid pace to meet growing Canadian demand, which is expected to increase from approximately 3 Tcf in 2006 to 4.2 Tcf in 2025. We believe that Canadian production will likely be consumed by increases in U.S. demand as well, because approximately half of Canada’s current estimated natural gas production of 6 Tcf is exported to the United States.

Technological advances in exploring for and exploiting unconventional resource plays have reduced the time needed to commercialize these resources. For example, in the Barnett Shale play in Texas, technical success and operator experience have allowed industry participants to expand the play well beyond initial expectations as operators implemented newly learned and increasingly refined techniques. According to a July 2008 Report from Wood Mackenzie which compares the Barnett Shale and Haynesville plays, the Barnett Shale has increased production from 140 Mmcfe/d in 2000 to 1.3 Bcfe/d in 2005, and to 3.8 Bcfe/d in 2008. Wood Mackenzie reports, in its 2008 Lower 48 NYC Forum presentation, that the percentage of gas recovered from proved reserves, or the recovery factor, from some areas in the Barnett Shale play is as high as 50%, compared to initial estimates of 20%. Advances in technology and completion techniques have resulted in increased initial production rates from plays like the Barnett Shale. Wood Mackenzie calculates that from 2006 to 2007 the average initial production rate for a new Barnett Shale completion increased by 11%. Like the Barnett Shale and other gas plays, a similar exploitation success has begun to occur in the Mannville CBM plays in Central Alberta and in the Montney Shale play in British Columbia.

Coalbed Methane Gas

CBM is natural gas trapped within buried coal seams. CBM is stored, or “adsorbed,” onto the internal surfaces of the coal. In most CBM reservoirs, the naturally occurring cracks, or “cleats,” contain water. This water must be pumped out in a dewatering process, which reduces pressure within the coalbed formation. As pressure within the coalbed formation is reduced, CBM is released through a process called “desorption.” CBM formations typically require dewatering before desorption occurs and commercially viable gas production rates are achieved. In the dewatering process, a submersible pump is set below the coal seam, and water is drawn down from the coal and pumped out. The dewatering process can take several months or years before commercial quantities of CBM are produced, in contrast to conventional gas reservoirs, which produce gas immediately upon completion. The Mannville coals in Central Alberta are typical examples of water bearing coals. Unlike most other commercial CBM plays, the Horseshoe Canyon coals in Southern Alberta are generally water free and produce commercial gas rates immediately after initial fracture completion.

Production Cycle of CBM Wells. The length of time required for a CBM gas well to reach peak production levels is highly variable and difficult to predict in new plays. While a conventional natural gas well typically

decreases in flow as the reservoir pressure is drawn down, a CBM well can increase in flow for up to five years. The length of the increase in flow depends on the natural gas resource potential, well spacing and the geological characteristics of the resource. Over time, CBM well flow reaches a peak production rate and then starts to decline gradually at low annual rates as compared to conventional gas reservoirs. A typical CBM gas well in the Western Canadian Sedimentary Basin, or WCSB, is estimated to produce for a period of approximately 20 to 40 years. CBM differs from conventional gas plays only at the reservoir level, with specific drilling, completion, production and operation techniques and practices. Once CBM wells begin producing, the gas is gathered, transported, marketed and priced in the same manner as conventional natural gas.

The volume of proved reserves attributable to estimated future production varies from time to time. Early in the life of a CBM well, the proved reserves underlying the well are small. After a well has reached its peak production rate, however, the estimated proved reserves attributable to such well generally increase. After production has continued for a period of time sufficient to establish a decline curve, an estimated ultimate recovery for the well can be established. In most cases, gas production is maintained at a stable rate over the initial 12 to 18 month period and then begins to decline.

Factors Affecting CBM Well Production. The main parameters that affect recovery of CBM are coal thickness, gas content, permeability, well spacing density, and water production and disposal. Coal thickness refers to the actual thickness of the coal and is used to estimate how many tons of coal underlie a section of land. Gas content in coal is the volume of gas per unit weight of coal or rock, usually measured in standard cubic feet per ton, or scf/ton. The estimate of the number of tons per section is multiplied by the estimated gas content of such coal (measured per ton) to estimate the natural gas resource potential for the section.

A prerequisite for economic gas flow rates is sufficient coal permeability for gas and water to flow to the wellbore. Permeability is measured by millidarcies, or md, which is a measure of the ability of rock (including coal) to transmit fluids. The higher the md measure is, the greater the permeability. Most gas and water flow through the coal cleat system and other fractures. Cleats are the natural system of fractures that have formed in the coals, usually as a result of the coalification process and influenced by the local geological stresses. Cleat spacing greatly influences permeability and cleat spacing is determined by a complex relationship between coal rank, coal composition, mineral matter content, coalbed thickness and tectonic history. Permeability can be enhanced with fracturing treatments commonly used in well completions. Permeability in water bearing coals has been found to increase as the coals dry out over the long production life of the field areas.

Well spacing density, the distance between producing wells in all reservoirs, is typically based on a combination of the following parameters: natural gas resource potential, permeability, production rate profile, ultimate recovery factor of the natural gas resource potential, capital costs and the optimized economic returns. Each CBM reservoir has a unique combination of these factors that determines the optimized well spacing. It is common for the well spacing to decrease over the development phase in unconventional reservoirs. This is commonly referred to in the industry as “downspacing.” In addition, minimum well spacing is restricted by governmental regulations in the jurisdiction in which the wells are located.

Water production and disposal, depending on the location of the assets, can be a key factor in CBM development. Lining drill holes with casing and cementing holes from water production levels to the surface protects groundwater from risks associated with reservoir stimulation operations and long-term water production within the wellbore. Water produced from oil and gas operations, including CBM operations, is characterized as saline or non-saline depending on the total dissolved solids, or TDS, content. Our operations in the Mannville CBM plays have produced saline water that we immediately injected into deeper reservoirs for disposal, while our operations in the Horseshoe Canyon CBM play produced no appreciable water.

CBM in North America

Canadian CBM represents a large, unconventional natural gas opportunity. An article published by the Canadian Society for Unconventional Gas in the 2008 Unconventional Gas Guide estimates that there is 700 Tcf of Canadian CBM gas resource potential, representing approximately 18% of Canada’s estimated unconventional natural gas resource potential. Wood Mackenzie estimates that CBM reserves in Western Canada are one of the largest untapped natural gas opportunities in North America and the third largest in the world, ranking only behind

Southeast Asia and the Former Soviet Union. These CBM resources are predominantly located in Canada’s WCSB, a vast sedimentary basin underlying 1,400,000 square kilometers (540,000 square miles) of Western Canada including Southwestern Manitoba, Southern Saskatchewan, Alberta, Northeastern British Columbia and the Southwest corner of the Northwest Territories. The WCSB has conventional oil and gas production history dating back to the early 20th century. The WCSB is underlain by numerous coal seams, each group of which may represent a distinct CBM play type. According to the Canadian Society for Unconventional Gas May 2008 Unconventional Gas Guide, CBM represents approximately 18% (900 Mmcfe/d) of Canada’s current estimated unconventional production of 5.1 Bcfe/d, with over 11,000 CBM wells drilled in Alberta at the end of 2007. It is forecast that by 2015, CBM production will grow to over 2,000 Mmcfe/d and the Canadian Society for Unconventional Gas in its 2007 Energy Evolution Guide estimated that by 2025, CBM will account for close to 80% of new drilling activity and 50% of total unconventional natural gas production in Canada. The Horseshoe Canyon CBM play accounts for 92% of current CBM production and the Mannville CBM plays account for 6% of current CBM production. As of May 2008, the Mannville CBM plays are estimated to contain 300 Tcf of natural gas resource potential, while the Horseshoe Canyon is estimated to contain 66 Tcf of natural gas resource potential. We believe that current conditions for CBM development in the WCSB are favorable due to the region’s large existing natural gas resource potential, established oil and gas industry, extensive natural gas plant and pipeline infrastructure (originally installed to support the extensive network of currently producing conventional gas wells), fully integrated regional sales gas pipelines (including export take-away capacity to the United States), and competitive tax and royalty regimes.

Over the past 25 years, CBM in the United States has evolved into a major component of the energy industry, contributing approximately 21% (4.8 Bcfe/d) of the U.S. unconventional gas production in 2006, according to the U.S. Energy Information Administration. According to the Canadian Society for Unconventional Gas May 2008 Unconventional Gas Guide, the CBM production rate in the United States is 5.5 Bcfe/d, compared to 0.9 Bcfe/d in Canada. According to the Society of Petroleum Engineers’ April 2007 Powder River Basin Report, the most active CBM area in the United States is the Powder River basin of Eastern Wyoming, with more than 20,000 wells completed in the last ten years with annual additions of more than 2,000 wells. In its December 2006 Unconventional Hydrocarbons report, Wood Mackenzie estimated that approximately 70% of the lower 48 states CBM reserves are contained in the Rocky Mountain region. The primary U.S. CBM basins in the Western United States include the Black Warrior, San Juan, Raton, Powder River and Uinta-Piceance Basins.

Shale Gas

Shale is another unconventional source of natural gas that has low permeability and thick pay sections generally requiring denser well spacing and larger and more complex fracturing completion techniques to achieve commercial gas production. Advances in fracturing and horizontal drilling techniques, combined with increased gas prices, have made shale gas plays very attractive with generally strong economic returns. Shale gas plays are generally widespread geologic deposits with significant identified natural gas resource potential. The most well known shale gas plays in the United States are the Barnett, Fayetteville, Woodford, Antrim and New Albany and in Canada, the Montney, which is technically a siltstone deposit, and Horn River. According to the U.S. Energy Information Administration’s May 2008 Canada Country Analysis Brief, the Montney Shale play is estimated to contain approximately 50 Tcf of shale gas. According to Wood Mackenzie’s May 2008 Upstream Insight North America-British Columbia’s Horn River Basin Report, recent shale gas reserve announcements by operators put the estimated recoverable gas resources in Western Canada’s Horn River shale play at 18 to 31 Tcf. Wood Mackenzie estimates that this resource base could reach an estimated 37 Tcf.

BUSINESS

Overview

We have assembled an extensive property base. As of June 30, 2008, we had natural gas and oil leasehold interests in approximately 1.7 million gross (1.3 million net) acres, of which approximately 80% were undeveloped. Based on the evaluation of approximately 17% of our total net undeveloped acreage, we have identified approximately 1,700 evaluated surface drilling locations which are locations specifically identified and scheduled by management as an estimate of our near-term multi-year drilling activities on existing acreage over the next five to seven years. Based on a reserve report prepared by the independent petroleum engineers Netherland, Sewell & Associates, Inc., or NSAI, as of June 30, 2008, our estimated proved reserves were 394.9 Bcfe (net), 58.8% of which represented estimated total proved developed reserves. At June 30, 2008, we owned interests in 943 gross (517 net) economic producing wells. Our June 30, 2008 estimated proved reserves are considered to be long-lived with a total proved reserve-to-production-ratio of 13.5 years based on net production in August 2008. As of October 1, 2008, we had four rigs drilling in the Mannville CBM plays and two rigs drilling in the Horseshoe Canyon CBM play. We expect to have one rig begin drilling in the Montney Shale play in the fourth quarter of 2008. The number of rigs we employ at any one time fluctuates throughout the year based on a number of factors, including seasonality.

The following table identifies certain information concerning our exploration and production business as of June 30, 2008 unless otherwise noted:


	Estimated
	Net Proved		Daily		Estimated		Estimated		Average
	Reserves		Production		Gross		Net		Working
Area	(Bcfe)(1)		(Mmcfe/d)(2)		Acreage		Acreage		Interest (%)

Mannville, Alberta		166.3		41.6		742,586		550,610		74.2
Horseshoe Canyon, Alberta		228.6		38.6		346,791		213,805		61.7
Montney, B.C.		—		—		12,350		8,645		70.0
U.S.(3)		—		—		537,625		537,625		100.0
Other, Canada		—		—		82,986		33,910		40.9

Total		394.9		80.2		1,722,338		1,344,595		78.1


(1)		Based on the reserve report prepared by NSAI as of June 30, 2008.

(2)		Represents average daily net production in August 2008.

(3)		Consists of our properties located in Washington, Oregon and Idaho.

Average wells in our core producing areas produce attractive economic returns at a variety of natural gas prices. In 2005, we operated the first commercial project in the Mannville CBM play. As a result of our significant

investment in, and refinement of, drilling technology and techniques, our Mannville wells are currently producing a return profile that we believe is consistent with the leading resource plays in North America. The Horseshoe Canyon CBM play represents a well-established WCSB CBM play that covers a broad geographic area. Low capital costs in this play, and the fact that it is a dry coal play and does not require dewatering, are key contributors to the strong economic profile of wells drilled in the area.

We believe that the Montney Shale play has significant upside potential based on seismic analyses and recent results from wells that have been drilled in the area by other operators, which we believe imply replicable strong single-well economics in the play. The Montney Shale play has only recently begun receiving market recognition for its unconventional natural gas resource potential, with new entrants paying significant premiums to historical acreage prices for a position in the play. We intend to begin our drilling program in the Montney Shale play in the fourth quarter of 2008, with a view to conversion of Montney reserve potential to proved reserves.

The integration and innovation of our development techniques, particularly those related to multilateral development wells, have resulted in what we believe to be lower per-well operating costs and superior production rates compared to other industry participants in each of our core CBM producing areas. We believe that these measurable results demonstrate our expertise in unconventional natural gas reservoir operations. We have used this expertise to develop new exploration opportunities that require the application of disciplined drilling and operating practices in order to achieve long-term commercial success.

Our Strategy

Our primary objective is to achieve long-term growth and maximize stockholder value by pursuing the following strategies:


	•	Execute Targeted Development of Existing Reserve Base and Undeveloped Acreage. We seek to generate long-term reserve and production growth, and enhance net asset value, or NAV, by leveraging our experience and exploiting targeted development opportunities with prudent capital discipline. We intend to concentrate our drilling efforts within our core properties and focus primarily on the development of the Mannville and Horseshoe Canyon CBM plays. We believe that our identified drilling opportunities have average return characteristics consistent with the leading resource plays in North America. We also intend to begin developing our holdings in the Montney Shale gas play and accelerate drilling if initial well results are consistent with our expectations. Two years of third-party unconventional gas production history from the Montney Shale play is currently available and recent third-party wells in the Montney area have resulted in initial production rates of 5-10 Mmcfe/d from single horizontal lateral wells with capital costs ofC$5-6 million per well. These results imply economics we believe also to be consistent with the leading resource plays in North America. As of October 1, 2008, we had four rigs drilling in the Mannville CBM plays and two rigs drilling in the Horseshoe Canyon CBM play. We expect to have one rig begin drilling in the Montney Shale play in the fourth quarter of 2008. Based on current evaluated drilling opportunities and rig deployments, we believe that we have over four years of organic drilling opportunities in the Mannville CBM plays and Montney Shale gas play and seven years of organic drilling opportunities in the Horseshoe Canyon CBM play.

	•	Continue to Apply Value-Maximizing Drilling and Operating Techniques in the Mannville CBM Plays. We commercialized the first Mannville CBM field in 2005 and have used multilateral drilling techniques to advance commercial exploration and development in this area. Our drilling approach has resulted in a drilling success rate of over 98% in the Mannville CBM plays and has been adopted by the majority of Mannville CBM operators. In the Greater Corbett Creek area, our core historical development area within the Mannville CBM plays, we have drilled incremental multilateral wells outwards and radially from more dewatered, developed areas. Our drilling techniques have accelerated dewatering and gas production with a high degree of economic success. As the field has matured, each new well requires less time to dewater, thereby shortening the period of time to reach peak natural gas production. We will seek to replicate our historical results from the Greater Corbett Creek area in other pilot areas in the Mannville CBM plays by executing a drilling program that is designed to accelerate dewatering, production rates and cash flow from each well. We also intend to continue to enhance our drilling and production methodologies to further


		improve the economics of each incremental well drilled through additional acceleration of dewatering and ultimately free flow of natural gas.


	•	Expand Our Proved Reserve Base and Surface Drilling Opportunities on Current Acreage. We believe that most of the Mannville and Horseshoe Canyon CBM acreage is located within the most prolific producing areas of each respective play. We intend to expand proved reserves and surface drilling opportunities on our current acreage through a balanced development and exploratory drilling program and downspacing when appropriate. We believe that these targeted formations generally will deliver high success rates, thereby resulting in strong and predictable growth in proved reserves as we proceed with our drilling program. We have recently commenced the application process for downspacing rights in the Horseshoe Canyon CBM play from 160 acres to the more typical 80 acres and hope to begin receiving approvals from the Alberta Energy Resources Conservation Board, or ERCB, in 2009. If approved by the ERCB, this would increase our evaluated surface drilling locations in the Horseshoe Canyon CBM play from approximately 400 to 1,519, or 280%.

	•	Maintain Capital Discipline and Pursue Sustainable Returns. We seek to generate growth in reserves, production and cash flow at attractive rates of return on capital invested and maintain strict capital discipline as we grow our business. We will continue to strive for the lowest capital and operational costs possible. We constantly monitor our portfolio of investments using a range of metrics and seek to maximize returns on our investments by directing capital to development opportunities with the highest estimated risk adjusted returns.

	•	Continue to Maintain Operating Flexibility by Controlling Pipelines and Gas Plants. We intend to continue to operate the majority of our production, and control marketing and logistics, from wellhead to the regional sales gas pipelines. We intend to follow this strategy in new areas as well. By controlling gathering and gas plant assets, we believe we will be able to better control overall costs and maintain a high degree of operational flexibility. Our operating costs are significantly below the average operating costs of our industry competitors. By marketing the majority of our owned production, we are able to manage risk and exposure to upside pricing and ultimately enhance overall returns.

	•	Opportunistically Seek Acquisitions in and Around Our Core Geographic Areas where We Can Leverage Technology and Drilling and Production Improvements. We seek and evaluate acquisition opportunities in and around our core areas in order to optimize our acreage position, enhance NAV, and take advantage of our advanced drilling techniques and our low operating cost structure. We acquired the Montney Shale position in 2006 through Crown land sales because we identified the Montney Shale play as a candidate for application of multilateral drilling technology, which has demonstrated proven low operating cost results in our current areas of operation. We believe that our multilateral drilling approach has the potential to further improve the economics for the Montney Shale play.

Competitive Strengths

We believe the following competitive strengths will help us successfully execute our strategies:


	•	Significant Resource Potential with Substantial Drilling Inventory and High Working Interest. We currently have a large acreage position in both the Mannville CBM plays (550,610 undeveloped net acres) and Horseshoe Canyon CBM play (136,394 undeveloped net acres, assuming downspacing is approved to80-acre spacing) in Alberta, with a high average working interest position of greater than 50%. We have a substantial drilling inventory with 128 evaluated surface drilling locations in the Mannville CBM plays and 1,519 evaluated surface drilling locations in the Horseshoe Canyon CBM play, with an average gross estimated ultimate recovery, or EUR, per economic proved undeveloped well of 1.8 and 0.4 Bcfe, respectively. The evaluated surface drilling locations represent only 17% of our total acreage position. Additional natural gas resource potential exists in the Montney Shale play with 19 evaluated surface drilling locations. Our evaluated and unevaluated surface drilling locations and our expected average proved undeveloped EURs imply significant natural gas resource potential beyond our net proved reserves of 394.9 Bcfe as of June 30, 2008. This may be further increased through execution of selected acquisitions that are accretive to our current operations.


	•	Proven, Industry-Leading, Advanced Drilling and Operation Technology. We have adopted and improved advanced techniques in drilling and production operations to create significant and scalable opportunities across current core producing areas as well as new potential areas. In particular, our innovative techniques related to multilateral development wells have contributed significantly to our operating efficiency as evidenced by our faster development period and overall operated cost structure per flowing Mcfe consistently below the industry average operating costs of our conventional and unconventional competitors combined. Our industry-leading noise suppression technology has allowed faster permitting and brought new wells to production earlier as a result. By contracting newly constructed, purpose built rigs for our specific field applications, we believe that we can explore and develop our existing reserves and explore for new reserves on a more economic basis with a high degree of operational timing certainty. In the Mannville CBM plays, pad drilling with multilateral wells has reduced our operational footprint by 17 times compared to traditional vertical drilling gas field developments. In the Horseshoe Canyon CBM play, we believe that slant drilling from pads will allow us to significantly reduce our footprint to half the normal development footprint in the case of 80 acre spacing, reduce our capital costs by over 30% and lower our operating costs. We intend to use slant drilling techniques in approximately two-thirds of our Horseshoe Canyon wells going forward.

	•	Low-Risk Drilling Inventory of Long-Lived Assets with Predictable Results. Resource plays such as the Mannville CBM plays and the Horseshoe Canyon CBM play typically display relatively low geological risk over a broad geographical area, as evidenced by our historical gross drilling success rate of 97% from 1,419 wells through June 30, 2008. Our reserves are considered long-lived in nature, as reflected in our total proved reserve-to-production-ratio of 13.5 years as of June 30, 2008. We believe that these characteristics contribute to low-risk, stable and predictable production and cash flow per well. Our experience in our core producing areas provides more certainty and reliability in our results and has enabled us to establish a substantial inventory of repeatable drilling opportunities, which supports low-risk growth in proved reserves, production and cash flow growth.

	•	Geographically Concentrated Land Positions Within the Boundaries of Existing Pipeline and Gas Plant Infrastructure. We consider each of our asset concentrations to be located on acreage that is fairly contiguous in nature and lies within the boundaries of our existing pipeline gathering systems and gas plants. As such, we believe we are well positioned for efficient exploitation and development of our land positions, which is essential for unconventional reservoirs to achieve strong economic returns. Our geographic concentration has allowed us to establish economies of scale in drilling, production and processing operations in order to achieve lower production costs and generate increased cash flows from our core producing assets. In addition, our exploration portfolio of undeveloped lands could yield significant future development and core producing areas if the initial exploratory activities prove successful.

	•	High Degree of Operational Control. We operate over 65% of our producing assets in our core producing areas and over 90% of our exploration opportunities. We have control over the gathering, processing and transportation of the majority of our production through facilities and pipelines in the WCSB. This high degree of operating control enables us to implement our proven drilling techniques and well designs, manage our operating costs and capital expenditures, and determine the timing of exploration, development and exploitation activities.

	•	Attractive Cost Structure and Drilling to Production Cycle Time. Our significant, contiguous undeveloped land positions lie within the boundaries of our existing pipeline gathering systems and gas plants, thereby contributing to lower operating expenditures. The integration of our advanced drilling and operation practices in our operated field areas has helped us achieve net operating costs of approximately C$1.30/Mcfe, which are below the industry average of our conventional and unconventional competitors combined. We believe that our cost structure of approximately C$1.40/Mcfe and C$1.20/Mcfe in the Mannville CBM and the Horseshoe Canyon CBM plays, respectively, is significantly lower than that of our direct competitors in the same play. During the first half of 2008, we achieved company-wide operating costs of approximately C$1.80/Mcfe (net after royalties before transportation).


	•	Experienced Management Team and Staff Focused on Delivering Long-Term Stockholder Value. Our senior management is dedicated to maximizing shareholder value through the efficient allocation of capital to development and exploration opportunities that have the highest estimated risk-adjusted returns. Our senior management has deep industry experience that complements a team with a history of innovation and significant knowledge of our assets. Our team was instrumental in the commercialization of the first Mannville CBM field, while also creating significant positions in other CBM and shale gas plays.

Exploration and Production

We are focused primarily on exploring for and exploiting our significant unconventional resources, with the objective of increasing proved reserves and production across our holdings. Our core producing areas include the Mannville CBM plays and the Horseshoe Canyon CBM play in the WCSB. We also have significant operated leasehold positions in the Montney Shale play and the Northwestern United States.

Our five-year development plan is based on an extensive evaluation of our core assets in the Mannville CBM plays, the Horseshoe Canyon CBM play and the Montney Shale play. Given the scale of our total acreage position, this development plan encompasses less than 20% of our total acreage position. We intend to exploit our entire acreage portfolio as we progress in our drilling program.


													Average
													Working
													Interest (%)		EUR per
													(Before		Suface
													Sliding		Drilling
	Undeveloped Acreage						Surface Drilling Locations						Scale		Location
	Evaluated(1)		Unevaluated		Total(2)		Evaluated(3)		Unevaluated(4)		Total		Royalties)(5)		(Bcfe)(6)

Mannville, Alberta		81,920		532,891		614,811		128		833		961		74		1.8
Horseshoe Canyon, Alberta		121,520		139,214		260,734		1,519		1,740		3,259		62		0.4
Montney, B.C.		12,350		—		12,350		19		—		19		70		N/A	(7)

Total Core Properties		215,790		672,105		887,895		1,666		2,573		4,239		70		N/A


(1)		Evaluated acreage reflects acreage specifically identified and delineated by management as part of its five-year development plan.

(2)		Includes acreage that has been reclassified as undeveloped (instead of developed) as a result of the addition of surface drilling locations permitted by downspacing parameters. The owned and unearned acreage in the: (i) Mannville is 564,070 and 62,880 respectively; (ii) Horseshoe Canyon is 188,065 and 55,937 respectively; and (iii) Montney is 12,350 and zero respectively.

(3)		Evaluated surface drilling locations represent locations specifically identified and scheduled by management as an estimate of our future multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas prices, costs, drilling results and other factors. See “Risk Factors — Risks Related to Our Business.”

(4)		Assumes spacing per surface drilling location as follows: Mannville:640-acre; Horseshoe Canyon:80-acre; Montney:216-acre.

(5)		NSAI’s report of June 30, 2008 reflects royalty rates on our Mannville proved undeveloped reserves of 16.1% and Horseshoe Canyon proved undeveloped reserves of 9.8%, as of June 30, 2008. We estimate royalty rates for our Montney Shale assets of approximately 23.4%, based on the pricing in effect as at June 30, 2008 and constant for all future periods.

(6)		The Mannville and Horseshoe Canyon data is based on the reserve report prepared by NSAI as of June 30, 2008.

(7)		Based on publicly available information prepared by certain investment banks, the EURs per surface drilling location for the Montney Shale area range from 20 to 50 Bcfe.

Mannville CBM Plays

We are the largest CBM producer in the Mannville formation in Central Alberta, one of our primary areas of operation. We have been active in this area since 2000 and operated the first commercial project in the Mannville CBM play in 2005. The Mannville area assets represent a significant part of our development and exploration opportunities, with proved reserves as of June 30, 2008 of 166.3 Bcfe (42% of our total proved reserves) and average net daily production of 43.4 Mmcfe in August 2008 (approximately 52% of our total net daily production for the month). We have identified for development over the next five years 128 evaluated surface drilling locations on our existing acreage in the Greater Corbett Creek area. We believe that these opportunities reflect significant growth potential. In addition, we are conducting exploratory pilot programs to expand our overall exposure in this play.

The Mannville formation extends over a vast area in Central Alberta and, according to the Canadian Society for Unconventional Gas 2007 Energy Evolution report, is estimated to contain up to 300 Tcf of natural gas resource potential, of which less than 0.02% has been produced to date. We operate approximately 70% of the total producing Mannville CBM assets in Canada. We conducted extensive technical and geological analyses prior to building our land position in the Mannville formation and believe, based on these analyses, that the coals in this formation have thick, continuous coal deposits with high gas content and large amounts of natural gas resource potential, and evidence of cleating and fracturing, which indicate the permeability of the coal and peak gas production rates. We combined detailed coal mapping of the Mannville coals with a number of contracted technical studies, including3-D seismic and geological studies designed to provide further geologic overlays. This specific seismic data enhances horizontal lateral targeting and geosteering, and allows us to avoid drilling hazards, thereby improving our overall horizontal lateral drilling success rate.

Our core producing CBM acreage is located in the Greater Corbett Creek area of the Mannville CBM plays and provides for multi-coal pay exploration and development opportunities. The area had historically been largely explored for conventional oil and gas targets and not CBM. The field area has produced more than 59 Bcfe from approximately 506 wells through June 30, 2008. We have operated the exploration for CBM natural gas in the Greater Corbett Creek area since 2000. In 2002, we entered into a joint venture agreement with Nexen Inc., or Nexen, a Canadian energy company, in respect of the Greater Corbett Creek area under which we hold an average 55% ownership interest and Nexen holds an average 45% ownership interest in the lands. Under our joint venture agreement with Nexen, we share revenues, costs, risks and expenses of developing and operating the wells on a pro rata basis. We operate all of our properties covered by this agreement in this area with the exception of the Doris area, which is operated by Nexen. We operate approximately 80% of the current production in the area. As operator, we have established a plan for the full development of the Mannville project areas. The joint venture terminates on the later of the date when no portion of the lands subject to the agreement is jointly owned or the date upon which the title document respecting the lands has terminated and all wells have been plugged or abandoned, all equipment thereon salvaged and final settlement of accounts has occurred.

In July 2005 we, together with Nexen, established the first commercial Mannville CBM field. Our initial pilot programs in the Mannville CBM plays evolved from drilling vertical wells to later drilling single horizontal wells, as we acquired new data. Based on our success with our single horizontal well pilot program, we switched to identifying key areas in the Mannville CBM plays to pursue pilot programs with multilateral development wells which gave us substantially better production profiles from the coals. We have since achieved critical mass in terms of wells drilled and production, while refining drilling techniques to establish self-sustaining single-well economics consistent with some of the most successful unconventional gas resource plays in North America. We recently reached a significant operational milestone with the operated drilling of over 2.6 million feet of multilateral wells in the Mannville CBM plays, which is substantially more than any other operator in those plays. We believe a combination of our access to innovative drilling and completion techniques, our integrated operational practices and our control of the necessary infrastructure will allow us to identify further exploration and development opportunities in these lands.

Mannville Areas of Operation. We have acquired leasehold acreage in the Mannville CBM plays totaling 550,610 net acres. Our operations within the Mannville CBM plays are on properties located in the Greater Corbett Creek area and several additional operating areas throughout Central and Southern Alberta. The Greater Corbett Creek area in Central Alberta was our original land holding and is held in a joint venture with Nexen. It includes the

following operating areas: Corbett, Clearwater, Sandhills, Wedge, Thunder and Doris. The Mannville CBM plays outside of the Greater Corbett Creek area in Central Alberta include Judy Creek/Swan Hills, Heldar and Vega. The Mannville CBM plays in Southern Alberta are divided into three operating areas: Wainwright, Coronation and Fenn. We have amassed our Mannville landholdings through a combination of joint ventures, farm-ins and Crown purchases. Accordingly, our ownership interests throughout the Mannville CBM plays vary depending on the applicable joint venture or farm-in agreement. Our most significant joint venture agreement is with Nexen. Pursuant to these arrangements, our joint venture or farm-in partner funds a portion of the exploration and development costs. The Mannville CBM plays accounted for approximately 52% of our average daily net production for August 2008.

Drilling and Production Methods. We have 128 evaluated surface drilling locations for development over the next five years on our existing acreage in the Greater Corbett Creek area. In each of these locations, we plan to drill multilateral development wells comprising a single vertical wellbore from the surface from which we drill up to four horizontal lateral legs per 640 acre section, each targeting a different subsurface location in the main coal seam. The Mannville CBM wells in the core Greater Corbett Creek area have slotted liners installed and do not require stimulation methods to establish commercial production. The Mannville coals in the core Greater Corbett Creek producing area are generally water bearing and require downhole electrical submersible pumps, or ESPs, to be installed to pump salty formation water and gas from the wells. The ESPs lift large amounts of water in the initial stages of the well’s production life and they are also capable of lifting lesser water amounts in combination with significant gas production during the more mature phase of production. The pumps are replaced over time due to inefficiencies caused by wear and corrosion characteristics of specific areas of the field. The produced water is immediately stripped of natural gas and then injected into a deeper saltier water bearing formation via water disposal wells. The produced gas is transported to operated regional gas plants for processing to the required sales gas delivery specifications before being compressed to sales pipeline pressures for delivery into regional sales pipelines for ultimate delivery to markets.

Based on information in NSAI’s reserve report of June 30, 2008, the average economic proved undeveloped well in the Mannville CBM plays will have a gross EUR of 1.8 Bcfe per well. As the field has matured, each new well has required less time to dewater, thereby shortening the period of time to reach peak natural gas production. Our pilot programs suggest that areas outside of the Greater Corbett Creek area will exhibit similar progression related to dewatering as the areas mature. We are making efforts to further improve on this with higher density pilot drilling in those areas. Our slotted liner design allows for less frequent ESP replacements, resulting in lower operating costs. In addition, dewatering processes and techniques bring reservoirs to self-sufficient production pressure, thereby minimizing the need for ESPs and reducing equipment and electricity costs. This acceleration of the commencement of production achieves economics that we believe are in line with the leading resource plays in North America. As of June 30, 2008, we had drilled 306 gross wells and participated in 70 gross non-operated wells in the Mannville CBM plays.

Recently, some of our newest multilateral well design wells began flowing gas and lifting water without pumping. This is an emerging trend isolated currently to our newest multilateral well design and it reduces operating costs significantly due to lower electrical consumption. We have observed more wells displaying this phenomenon and may experience a field-wide effect in the future, which would dramatically reduce electrical consumption and pump replacements. These components account for approximately 50% of our current operating costs.

Mannville CBM Development. Our development plan is to drill up to four horizontal lateral legs per wellbore into the main Mannville coal seam. Our historical average operated three-lateral well has approximately 15,100 feet of measured depth drilling representing a combination of vertical and horizontal drilling in respect of all wells, or 5,033 feet per lateral. We also currently use two purpose-built multilateral pad drilling rigs under separate two-year contracts for the Mannville CBM plays drilling program. The rigs are designed to move from one multilateral well with a main wellbore, or mother bore, to another on a single pad without having to disassemble, and then demobilize, the entire rig. This has eliminated up to two non-drilling days when moving less than 30 feet between surface well locations. As many as four such mother bores are drilled from each surface pad location developing up to 2,560 acres, or four sections of land. Not only does this save significant time and costs in the operations, but it also enables continuous drilling operations during the traditional “spring break up” in Canada when heavy equipment moves are severely restricted while frost leaves the ground. This approach has resulted in average development costs of C$0.83 million per lateral, including drilling, completing, equipping, tie-in and other ancillary costs. The

pad drilling technique has allowed us to fully develop a field area while reducing our footprint by 17 times on the surface compared to traditional vertical drilling gas field developments. Combined with the application of aggressive noise suppression technology to all field compressors, we are able to initiate new activities quickly because of our good relations with area surface land owners. Since the beginning of 2006, we have brought new wells to production on average within 85 days from the rig release in the Mannville CBM plays.

We are also currently evaluating drilling more and longer laterals to target greater than approximately 18,050 feet of measured depth drilling per well with four laterals, or 4,513 feet per lateral, on each new well to maximize production. We will be able to take advantage of the benefits provided by the Crown’s new royalty program that becomes effective on January 1, 2009, for both our three and four lateral well designs. The program is triggered upon achieving measured depth of 6,560 feet and maximizes at measured depth of 13,125 feet, which we plan to achieve.

We have budgeted C$ million in 2009 for drilling in the Mannville CBM plays, with % allocated to further develop our core Greater Corbett Creek producing assets and the remainder allocated to further establishing our most promising pilot areas. We expect to drill 35 gross wells in the Mannville CBM plays in 2009.

The following table provides additional information concerning our development in the Mannville area as of June 30, 2008:


Estimated
Net Proved	Estimated Net	Gross Proved	Total Gross	Total Net
Developed	Proved	Undeveloped	Evaluated	Evaluated
Reserves	Undeveloped	Drilling	Drilling	Drilling
(Bcfe)(1)	Reserves (Bcfe)	Locations	Locations	Locations	Rigs Working

119.1	50.7	35	128	67	4


(1)		Includes 2.7% of proved developed non-producing reserves in the Mannville area.

Mannville pilot programs. Outside of the core Greater Corbett Creek producing area we have acquired significant land holdings in five future pilot areas that we believe have many key coal characteristics similar to the Greater Corbett Creek producing area. We believe that these areas have the potential to become future core producing areas and represent growth opportunities where we will seek to replicate success from our core producing areas. In the third quarter of 2008, we began a “minipilot” program in some of these pilot areas. As part of this program, we are targeting a single section of land with a well orientation that, in comparison to traditional pilots, would allow dewatering to occur much more quickly, and has the potential to deliver production results more quickly at approximately half the cost. Some of the pilot areas have lower permeability and we are therefore applying advanced multistage isolated fracture completions in the multilateral horizontal wells in these areas.

Horseshoe Canyon CBM Play

The Horseshoe Canyon CBM play is a core producing area and we are one of the five largest producers in this area. The play is currently the most successful commercial CBM play in the WCSB with significant, predictable and repeatable drilling opportunities at low cost and low geological risk. The Horseshoe Canyon CBM play produces no appreciable water and it is currently the only significant producing dry coal play in North America. This characteristic has favorable economic implications since these wells do not incur the costs of dewatering and therefore operate more efficiently than wet coal plays. Given our substantial drilling inventory and a gross EUR of 0.4 Bcfe per average economic proved undeveloped well, we believe that current proved reserves as of June 30, 2008 of 228.6 Bcfe (58% of our total proved reserves) and average net daily production of 38.6 Mmcfe in August, 2008 (48% of our total net daily production) represent only a small percentage of the natural gas resource potential of this area.

Our early mapping of the coal formations in the WCSB identified prospective acreage in areas of the Horseshoe Canyon CBM play where the multiple coal seams generally tend to be highly permeable, relatively continuous and cumulatively very thick. Up to 25 coal seams are completed in a single well. In addition, the shallow coals of the Horseshoe Canyon CBM play generally contain no appreciable water and the area benefits from extensive existing gas plant and pipeline infrastructure. We were an early participant in the Horseshoe Canyon CBM play and were able to

assemble a significant land position through a participation and farm-out agreement with Husky Oil Operations Limited, or Husky, a subsidiary of a major Canadian conventional operator.

We have been active in this area since 2002. The Horseshoe Canyon CBM play had historically been largely explored for conventional oil and gas targets and not CBM. In 2002, a number of operators including EnCana Corporation, Apache Canada Limited, Quicksilver Resources Inc., EOG Resources Canada Inc. and Pioneer Natural Resources Canada, Inc. simultaneously, but independently, established commercial production rates from the Horseshoe Canyon CBM play. According to the Alberta Government’s public production database as of July 2008, the Horseshoe Canyon CBM play has produced more than 592 Bcf before royalties since 2002 with 11,693 wells drilled and 8,557 wells currently producing at 581 Mmcf/d before royalties. According to the National Energy Board’s May 2007 Briefing Note — Overview and Economics of Horseshoe Canyon Coalbed Methane Development at page 17, at December 31, 2006, there was 540 Mmcfe/d of raw production from 7,549 wells drilled in this play. We believe most of our lands are in the most productive part of the entire play largely as a result of our strong geographic positioning and use of aggressive compression. We believe that this is demonstrated by our average Horseshoe Canyon CBM play peak production rate per well being 63% higher than the industry average rate in the Horseshoe Canyon CBM play.

Horseshoe Canyon Area of Operation. The primary operating area in which we are exploiting reservoirs in the Horseshoe Canyon CBM formation is the Greater Rumsey area, which includes Fenn and Drumheller. As of June 30, 2008, we had drilled 731 gross wells and participated in 87 gross non-operated wells targeting the Horseshoe Canyon CBM play. Based on information in NSAI’s reserve report of June 30, 2008, the average economic proved undeveloped well in the Horseshoe Canyon CBM play will have a gross EUR of 0.4 Bcfe per well. Our producing assets in the Horseshoe Canyon CBM play accounted for approximately 48% of our average net daily production for August 2008.

We acquired the majority of these lands through a participation and farm-out agreement with Husky. Pursuant to this agreement Husky has farmed out a proportion of its interest in the lands to us. The majority of the current wells were, and future wells will be, drilled with a promoted cost to us of a pay 70% to earn a 50% working interest in the drilling and completion phase and a pay 50% to earn a 50% working interest in the pipelines and facilities phase. The agreement is perpetual until the parties do not hold their respective lands or the title documents respecting the lands have been terminated. Pursuant to the agreement, we have assumed the duties, obligations and rights of an operator of the wells; however under a separate well and facilities operating agreement, we transferred all work and services ordinarily performed by an operator to Husky, excluding subsurface work. Either party may terminate the well and facilities operating agreement upon 30 days’ notice and we have an additional right to terminate if Husky fails to perform its obligations.

Drilling and Production Methods. We drill vertical wells through multiple layers of coal within the Horseshoe Canyon formation. Commonly up to 25 individual coal seams are penetrated by each vertical well that is completed using fracture techniques. The Horseshoe Canyon CBM play wells are drilled with air and drilling fluids for circulation. Completions involve installing cemented casing, and fracturing the individual coal seams with nitrogen gas breakdown techniques used commonly in this play. The Horseshoe Canyon CBM play production is characterized by aggressive compression of dry gas flowing to regional gas plants for minor processing. The gas is then compressed to sales pipeline minimum pressures for ultimate delivery to the markets. We are currently evaluating the Horseshoe Canyon CBM play for slant drilling techniques by leveraging existing surface locations where previous vertical Horseshoe Canyon wells already have existing metering, compression and pipelines. If successful, these techniques would further reduce the footprint of the future eight well per section development plan, reduce overall producing well costs due to less compression, metering and pipeline tie-ins, and reduce the time from rig release to first production as substantially less activity would be ultimately required to produce any new slant well.

Horseshoe Canyon CBM Play Development. The Horseshoe Canyon CBM play development plan over the next several years aims to balance between developing production and reserves. Lands are currently drilled at slightly less than two vertical wells per section, resulting in approximately 400 drilling locations that could be drilled under current drilling density approvals. We are seeking approval from the ERCB to downspace from our currently approved four vertical wells per section to eight vertical wells per section, on approximately 475 sections of land, which is

consistent with the other leading operators in the play. We have an inventory of over 1,500 evaluated surface drilling locations, representing 400 currently approved surface drilling locations and over 1,100 additional surface drilling locations subject to approval of our downspacing applications. We expect that the applications, which we commenced preparing in the second quarter of 2008, will require approximately one year for regulatory approval. We believe that our development costs per well in the Horseshoe Canyon CBM play, which include drilling, completing and equipping, will be approximately C$390,000 per vertical well and C$340,000 per slant well for future drilling, depending on whether slant drilling or vertical drilling methods are required for the specific future location. The productivity discount under the new Crown royalty program has resulted in lower flat royalty rates for the majority of our wells in the Horseshoe Canyon CBM play. Since the beginning of 2006, we have brought new wells into production on average within 127 days from rig release in the Horseshoe Canyon CBM play.

We have budgeted C$ million in 2009 for drilling in the Horseshoe Canyon CBM play, with approximately 75% allocated to traditional vertical drilling and 25% allocated to slant drilling. We expect to drill 200 gross wells in the Horseshoe Canyon CBM play in 2009.

The following table provides additional information concerning our development in the Horseshoe Canyon area as of June 30, 2008:


Estimated
Net Proved	Estimated Net	Gross Proved	Total Gross	Total Net
Developed	Proved	Undeveloped	Evaluated	Evaluated
Reserves	Undeveloped	Drilling	Drilling	Drilling
(Bcfe)(1)	Reserves (Bcfe)	Locations	Locations	Locations(2)	Rigs Working

113.1	115.5	500	1,519	1,011	1


(1)		Includes 6.5% of proved developed non-producing reserves in the Horseshoe Canyon area.

(2)		Includes locations that we anticipate will be approved for downspacing in the Horseshoe Canyon CBM play.

Montney Shale Gas Play

We own and operate a 70% working interest in lands located in the heart of the natural gas bearing Montney Shale gas trend, which covers a portion of Northeast British Columbia and Northwest Alberta. We believe this area is amenable to the use of the multilateral drilling techniques we have developed in the Mannville CBM plays, which we believe will allow us to improve overall production efficiency and leverage our technology at low cost. We have approximately 12,350 gross (8,645 net) largely contiguous acres in the Montney Shale play. Based on initial geological mapping from offsetting wells, we see exposure to three Montney Shale geological zones that have been produced or tested by industry participants in the area, and a fourth overlying geological zone where a shallower siltstone, called the Doig formation, could possibly be present within our acreage. We have 19 evaluated surface drilling locations in the Montney Shale play. We believe we may be able to exploit these four geological zones beneath these drilling locations and initially we plan to drill into one zone with two or three single horizontal lateral legs per well. The spacing would be approximately 216 acres based on three lateral wells per section. Depending on our initial drilling results, we may drill into additional zones.

While the Montney Shale play has a production history since the 1970’s, the use of new technologies has resulted in recent opportunities that were previously unavailable. Two years of third-party unconventional gas production history from the Montney Shale play is currently available and recent third-party wells in the Montney area have resulted in initial production rates of 5-10 Mmcfe/d from single horizontal lateral wells with capital costs of C$5-6 million per well. According to recently released public information, ARC Energy Trust has drilled the thickest net shale gas pay section in its Montney Shale drilling program to date at 150 feet, on acreage directly offsetting ours. We believe that these positive economic and geologic factors are key contributors to market recognition of the opportunity in the Montney Shale and are evidenced by a variety of recent land sales resulting in undeveloped land bids of approximately C$13,500 per acre.

Drilling and Production Methods. In the Montney Shale play, we plan to drill and case multilateral horizontal wells in the Montney formation at vertical drilling depths of approximately 6,560 feet and conduct multistage propped fracture treatments in the individual horizontal laterals. We are currently applying for permits for pad surface locations across the entire land block. We undertook an operated3-D seismic survey in the first

quarter of 2008 and used this to locate the first two wells on the prospect. Produced gas will flow through an existing newly installed sour raw gas transmission pipeline to a regional sour gas plant for processing before being compressed for delivery to the regional sales gas pipelines for ultimate delivery to markets.

Montney and Doig Formation Development. We intend to target up to three individual Montney Shale gas geological zones identified on our land holdings with the first two horizontal wells to be drilled and tested in the fourth quarter of 2008. We believe that a shallow secondary shale and siltstone gas geological zone target in the Doig formation is present in the general area and we intend to develop that formation if we encounter it while drilling for the deeper Montney formation. We have budgeted C$ million for drilling gross wells in the Montney Shale play in 2009.

In respect of the Montney lands, in March 2008 we entered into an exploratory joint operating agreement with Kerogen Resources Canada, ULC, or Kerogen, in respect of which we hold a 70% working interest and Kerogen holds a 30% working interest to explore, operate and develop certain joint lands pursuant to the joint operating agreement. We are the initial operator of the future wells and facilities under the agreement and will share in the revenues, costs, risks, liabilities and expenses, and own the joint lands, in accordance with our respective working interests. The agreement is perpetual until the parties do not hold the lands jointly or the title documents with respect to the lands have been terminated.

In July 2008, we also entered into a separate agreement with Kerogen under which we and Kerogen share the rights and obligations we have under the gathering and processing agreement with Spectra Energy Midstream, or Spectra, a large midstream company, in proportion to our respective working interests under the joint operating agreement. The term of the July 2008 agreement with Kerogen tracks the term of the gathering and processing agreement with Spectra, which has an initial term of five and a half years and continues on an annual basis thereafter if no notice to terminate has been given by either party prior to the end of the initial term and we are not in default.

We are also currently considering a cashless land swap with two offsetting operators which we believe will allow the most efficient exploitation of the lands with no change to the acreage of our operated lands.

Other Areas

Washington, United States — Columbia River Basin Area. We own significant natural gas and oil interests in the Columbia River Basin area, which encompasses a thick basalt-capped sedimentary basin (approximately 4 million acres in size according to information recently published by Exxel Energy Corp.) on the Southern border of Washington with Oregon. This area is generally characterized as being exploratory in nature. Drilling depths are near 16,000 feet and there is higher potential for significant gas discoveries in the event of success. We believe, based on the data we collected from previous third-party wells in the basin, a natural gas resource potential of approximately 10 Bcfe per well drilled on80-acre spacing is possible.

Delta Petroleum Corp., a U.S. oil and gas company, or Delta, is currently drilling an exploration well approximately two miles offsetting our lands and has licensed a second location offsetting some of our other lands. We and Delta own the majority of this specific sub-basin. According to an August 2008 report by Delta, the well is currently being drilled and is expected to reach total depth in late 2008. If the opportunity becomes available, we will seek to contribute to this well to gain access to the well information. On September 29, 2008, Delta announced in a press release that it had acquired all of EnCana’s land holdings in the basin and entered into a joint venture with Husky Refining Company with plans to drill at least three new wells in the basin. We believe that we are strategically positioned to market gas, as the Williams Northwest Pipeline system is the regional sales natural gas line across the lands, and the Stanfield Gas Hub is immediately South of and directly offsetting the lands. Although there are no gas processing facilities in the area, we believe that reasonable access to this pipelineand/or the Stanfield Gas Hub is possible in the event of a significant gas discovery on our land holdings.

Oregon, United States — Snake River Basin Area. We own significant natural gas and oil interests in the Snake River Basin area, an interbedded sedimentary and basalt basin on Oregon’s Eastern border with Idaho. Like the Columbia River Basin, this area is generally characterized as being exploratory in nature, with two target zones at 3,000 feet and 10,000 feet, and there is higher potential for significant gas discoveries in the event of success. We believe, based on the data we collected from previous third-party wells in the basin, that tight gas reservoirs of

approximately 50 feet in total thickness in the shallow section of the basin exist, and we expect that the deeper zone contains up to 1,000 feet of lacustrine deposits, which are often rich in organic shales.

The Williams Northwest Pipeline system also transacts the Snake River Basin lands but there are no gas processing facilities in the area. We anticipate that reasonable access to this pipeline is possible in the event of a significant gas discovery on our land holdings. The area has not seen significant exploration activity since the early 20th century and, as such, is under-explored. We control approximately one-third of the entire mapped geological basin and believe that we effectively control the remainder of the basin, which is composed of highly fractional fee simple interests that would be difficult to acquire in drillable blocks, and mountainous lands which are largely inaccessible. We have identified two prospective targets: one shallow, above a significant volcanic horizon, and one deep, below the same target. The Snake River Basin area accounts for 2008 budgeted capital expenditures of approximately C$1 million of very early-stage exploration oriented data gathering.

Conventional Gas Production Program. The majority of our existing conventional gas production is within our Cretaceous-aged plays that are above or below the current core CBM producing areas. Our extensive CBM drilling activities have allowed us to gather data from which we have identified specific conventional natural gas plays on our lands.

Belly River. Although the Horseshoe Canyon formation is our primary focus for drilling activities, the underlying Belly River formation consists of similarly interbedded shales, carbonaceous shales, coal, siltstones and sandstones to the overlying Horseshoe Canyon formation. This overall geological system appears to be predominantly gas charged in the permeable coals, shales and sandstones within these two formations containing varying quantities of observable natural gas, which increases the potentially recoverable amount of gas. This type of gas charged system is known as a “continuous” gas accumulation resembling a “box of gas” in simplistic terms. With further technical work we hope to demonstrate in the near future a significant amount of additional resource potential that can deliver commercial quantities of gas. Although our primary focus has been on CBM production from the Horseshoe Canyon coals, we have deepened many vertical Horseshoe Canyon wells to the base of the Belly River formation at relatively minor incremental cost. As a result, we have amassed a database of the associated geological and test data from our operated wells that has enabled us to develop a more comprehensive understanding of this hydrocarbon system.

Gathering and Processing Facilities

Our gathering, compression, processing and transportation facilities consist of the following:


								Working
	Licensed		Capacity		TEC Working			Interest
Plant	Operator		(Mmcfe/d)		Interest(%)			(Mmcfe/d)

Mannville CBM plays
Corbett		Trident		22		60			13
Clearwater		Trident		60		83			50
Sandhills		Trident		60		60			36
Thunder		Trident		24		60			14
Wedge		Trident		18		60			11

Total Mannville CBM plays				184		67			124
Horseshoe Canyon CBM play
Big Valley		Trident		15		100			15
Dry Island		Husky		18		50			9
Elnora		Husky		10		50			5
Equity		Trident		15		58			9
Goose Quill		Husky		18		50			9
Kievers Lake		Trident		4		100			4
McKee Lake		Husky		22		46	(1)		—	(2)
Rowley		Husky		16		40	(1)		—	(2)
Rumsey		Husky		12		—			—
Rumsey North		Trident		10		100			10
Scollard		Trident		10		100			10
South Lone Pine Creek		TAQA North		15		9			1
Tolman		Husky		10		50			5
Wimborne		Trident		15		100			15

Total Horseshoe Canyon CBM play				190		48			92

Total				374		58			216


(1)		Working interest in booster compression at field level.

(2)		We may invest capital into these two existing gas plants owned by competitors to align the current field level infrastructure working interest described in footnote 1. We anticipate that our working interests in these gas plants could become effective over the next 12 months subject to negotiations with Husky, who is the current owner and operator of these gas plants.

As of June 30, 2008, our total processing capacity was approximately 216 Mmcfe/d for our combined owned facilities and we utilized approximately 47% of that capacity. We also operate or own approximately 636 miles of natural gas gathering pipelines in the WCSB area. At June 30, 2008, we operated or owned approximately 89,648 horsepower of gas compression.

Mannville CBM Plays. As of June 30, 2008, we operated five gas processing facilities in the Greater Corbett Creek area and we held an average 67% ownership interest in those plants. We do not currently have any gas processing plants in the Mannville area outside the Greater Corbett Creek area, however, we have firm service agreements for pipeline, gathering and metering capacity to tie our wells into third party facilities. We doubled the capacity at the Sandhills plant to 60 Mmcfe/d during the second quarter of 2008 and recently completed a 50% capacity expansion at the Wedge plant during the third quarter of 2008. As of June 30, 2008, we had 184 Mmcfe/d of gross and 124 Mmcfe/d of net processing capacity, with only 0.2 Mmcfe/d tie-in which is accessed by paying fees.

Horseshoe Canyon CBM Play. As of June 30, 2008, we held an average 48% ownership interest in 14 gas processing facilities and operated six of these plants in the Horseshoe Canyon CBM play. In addition, we are connected to one third-party facility for which we pay fees. We have implemented what we believe to be industry leading noise suppression design in the six plants that we operate. As of June 30, 2008, we had 190 Mmcfe/d of

gross and 92 Mmcfe/d of net processing capacity, with 5.5% of the volumes processed by third party plants which are accessed by paying fees.

In order to reduce the operating costs at our facilities, we provide gathering, compression, processing and treating services to other producers for fees, to the extent that we have under-utilized capacity.

Montney Shale Play. We recently negotiated a 25 Mmcfe/d gross (17.5 Mmcfe/d net working interest before royalties) gathering and processing agreement with Spectra. Spectra will expand its existing facilities to process the additional expected volumes of gas in exchange for payment of a fee based on the commodity delivered that escalates by an agreed amount each year. The gathering and processing agreement is a “deliver or pay” contract which means that we have to pay for delivered gas at a minimum quantity set forth in the agreement (which increases over time) even if the actual delivered quantity is less than this minimum threshold quantity. The required plant expansion is in the fabrication stage and we expect the plant to be in service by the third quarter of 2009. The gathering and processing agreement has an initial term of five and a half years and continues on an annual basis thereafter if no notice to terminate has been given by either party prior to the end of the initial term and we are not in default. Furthermore, in the event of our continuing default for 30 days following a written suspension notice from Spectra within 10 days of the default, or if Spectra determines in its sole discretion that the operation of the gathering and processing facilities ceases to be economic, Spectra may terminate the agreement.

Given the existence of hydrogen sulphide and carbon dioxide levels at approximately 0.1% and 3%, respectively, in the Montney Shale gas zones, we will use specialized metallurgy in pipelines and facilities to resist corrosion during the long-term production scenario. Such equipment is readily available and commonly used in the Canadian gas industry.

We intend to build selectively, as required, supplemental treating capacity, pipeline gathering infrastructure and compression facilities to accommodate our long-term growth plans.

Producing Wells and Acreage

The following table sets forth certain information regarding our ownership of productive wells and total acreage as of June 30, 2008. For purposes of this table, productive wells are wells producing, or capable of producing gas in commercial quantities.


	Productive				Approximate Leasehold Acreage
	Wells				Developed(1)				Undeveloped(2)				Total
Area	Gross		Net		Gross(3)		Net(4)		Gross(3)		Net(4)		Gross(3)(5)		Net(4)

Mannville, Alberta		376		248		190,655		133,073		551,931		417,537		742,586		550,610
Horseshoe Canyon, Alberta		818		457		141,034		78,203		205,757		135,602		346,791		213,805
Montney, B.C.		—		—		—		—		12,350		8,645		12,350		8,645
U.S.		—		—		—		—		537,625		537,625		537,625		537,625
Other, Canada		225		149		5,120		3,840		77,866		30,070		82,986		33,910

Total		1,419		854		336,809		215,116		1,385,529		1,129,479		1,722,338		1,344,595


(1)		Developed acres are acres spaced or assigned to productive wells.

(2)		Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

(3)		A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4)		A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

(5)		Comprising approximately 3.5% of freehold land in Canada and approximately 66% of freehold land in the United States.

Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective initial terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. We believe that the Alberta Department of Energy will grant us renewals in respect of most of the expiring leases on significant acreage surrounding our producing properties, because we expect to have established production or potential productivity on those leased lands. The following table sets forth as of June 30, 2008, the expiration periods of our gross and net acres subject to leases.


	Expiring Acreage
					Horseshoe
	Mannville, Alberta				Canyon, Alberta				Montney, B.C.				U.S.
Twelve Months Ending	Gross		Net		Gross		Net		Gross		Net		Gross		Net

December 31, 2008		42,240		23,936		1,920		960		—		—		—		—
December 31, 2009		156,640		119,437		39,135		34,638		—		—		—		—
December 31, 2010		183,640		161,738		27,720		25,760		—		—		181,306		181,306
December 31, 2011 and later		152,694		101,391		7,120		6,080		12,350		8,645		356,320		356,320

Total		535,214		406,501		75,895		67,438		12,350		8,645		537,626		537,626

Drilling Activity

The table set forth below summarizes our drilling results for the years ended December 31, 2005, 2006 and 2007 and the six months ended June 30, 2008. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.


													Six Months Ended
	Year Ended December 31,												June 30,
	2005				2006				2007				2008
	Gross		Net		Gross		Net		Gross		Net		Gross		Net

Development:
Productive		2		1		63		38		58		28		20		12
Dry		—		—		1		—		—		—		—		—
Exploratory:
Productive		464		281		355		212		26		13		12		8
Dry		8		6		5		4		—		—		—		—
Total:
Productive		466		282		418		250		84		41		32		20
Dry		8		6		6		4		—		—		—		—

We expect to drill and complete, including participation in non-operating drilling, 192 gross (105 net) wells during the year ending December 31, 2008. We have a non-operated drilling forecast for 38 well locations in the Horseshoe Canyon areas.

Reserves Summary

The table set forth below summarizes our natural gas reserves as of the dates indicated and the standardized measure of discounted future net cash flows attributable to these reserves as of those dates, discounted at 10% using constant pricing.

Our interests in our natural gas properties as of June 30, 2008 have been evaluated in reports prepared by the independent engineering firm NSAI, and our interests as of December 31, 2007, 2006 and 2005 have been evaluated by the independent engineering firm Sproule Associates Limited, or Sproule.

Reserve calculations involve the estimate of future net recoverable reserves of oil and natural gas and the timing and amount of future net revenue to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. See “Risk Factors — Our reserve estimates depend on many assumptions some of which may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”


	As of December 31,						As of June 30,
	2005		2006		2007		2008

Estimated net proved reserves:
Proved developed producing (Mmcfe)(1)		39,189.6		87,420.6		92,016.6		221,789.0
Proved developed non-producing (Mmcfe)(1)		7,976.0		16,564.2		15,675.0		10,455.9

Total proved developed (Mmcfe)(1)		47,165.6		103,984.8		107,691.6		232,244.9

Proved undeveloped (Mmcfe)(1)		34,789.0		60,307.8		58,416.0		162,695.7

Total proved reserves (Mmcfe)(1)		81,954.6		164,292.6		166,107.6		394,940.6

PV-10 (in millions)(2)	C$	310.0	C$	366.9	C$	402.5	C$	1,456.3
Income tax effect discounted at 10% (in millions of C$)		0.7		—		—		(169.0	)

Standardized measure of discounted future net cash flows (in millions)(3)	C$	310.7	C$	366.9	C$	402.5	C$	1,287.3

Price used for proved reservePV-10 (AECO-C index price in C$ per Mcfe as of December 31 and NGXAB-NIT index price in C$ per Mcfe as of June 30	C$	9.99	C$	6.13	C$	6.52	C$	11.70


(1)		Represents our natural gas and oil reserves and is based on the reserve reports prepared by Sproule as of December 31, 2005, 2006 and 2007 and by NSAI as of June 30, 2008. This includes, as of December 31, 2005, 2006 and 2007, net proved reserves of oil of 6.4 MBbls, 14.8 MBbls and 14.6 MBbls, respectively, and as of June 30, 2008, includes no net proved reserves of oil.

(2)		PV-10 is a non-GAAP measure that represents the present value of estimated future net revenues attributable to our reserves using constant prices, as of the calculation date, discounted at 10% per year on a pre-tax basis.PV-10 was determined based on the market prices for natural gas as of December 31 2005, 2006 and 2007 and as of June 30, 2008. The natural gas prices used for the calculations as of December 31, 2005, 2006 and 2007, and as of June 30, 2008 were C$9.99, C$6.13, C$6.52 and C$11.70, respectively. These prices were based on AECO-C prices as of December 31, 2005, 2006 and 2007 and NGX AB-NIT as of June 30, 2008 and were adjusted to account for transportation costs and any difference in quality as applicable. The oil prices used for the calculations as of December 31, 2005, 2006 and 2007 were C$68.12, C$67.59 and C$93.44, respectively.PV-10 differs from standardized measure of discounted future net cash flows because it does not include the effects of income taxes on future net cash flows.PV-10 does purport to present an estimate of fair market value of our reserves. AlthoughPV-10 is not a financial measure calculated in accordance with GAAP, management believes that the presentation ofPV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to any given company affect the amount of estimated future income taxes, we believe that the use of a pre-tax measure is helpful when comparing companies in our industry.

(3)		Calculated based on our net proved reserves of oil and natural gas. The “standardized measure of discounted future net cash flows” is the present value of our estimated future net cash flows, discounted at 10% per year, calculated using constant pricing, utilizing the same prices that we used to calculatePV-10 as described in footnote (2). The standardized measure of discounted future net cash flows does not purport to present the fair market value of our natural gas reserves and is not indicative of actual future net cash flows.

The current approved primary well density for our operated area of the Greater Corbett Creek area is one multilateral well per 640 acres section targeting the main Mannville coal seam. Our common multilateral well design is based on three horizontal laterals per 640 acre section. Based on information in NSAI’s reserves report of June 30, 2008, the average economic undeveloped well in the Mannville will have a gross estimated ultimate recovery, or EUR, of 1.8 Bcfe per well. We believe that each of the three individual horizontal laterals will produce approximately 0.6 bcfe or 1/3 of the total EUR in any undeveloped well.

The currently approved primary well density for our operated area of the Horseshoe Canyon CBM play covering the Greater Rumsey is four vertical wells per 640 acre section or one well per 160 acres. NSAI has assigned an average economic total proved reserves of approximately 0.4 Bcfe gross raw per well for all of the Greater Rumsey operating area, based on an average drainage area of 160 acres per well, or four wells per 640 acre section.

Net Production, Sales and Costs

The following table provides summary data with respect to our net production, after deducting royalties, and sales prices of natural gas for the periods indicated and the costs related to such production. Over 99% of our production is natural gas.


							Six Months
							Ended
	Year Ended December 31,						June 30,
	2005		2006		2007		2008

Net Production(1):
Mannville, Alberta (Mmcfe)(2)		1,067		9,044		14,193		7,366
Horseshoe Canyon, Alberta (Mmcfe)(3)		3,247		11,381		14,616		6,843

Total natural gas (Mmcfe)		4,314		20,425		28,809		14,209

Average net realized price (C$ per Mcfe)	C$	9.33	C$	6.55	C$	7.02	C$	8.57
Average production costs(4):	C$	3.15	C$	2.11	C$	2.06	C$	2.05


(1)		Includes oil and natural gas liquid production converted to Mcfe at a ratio of 6 net Mcfe for each net barrel produced. Total net oil and natural gas liquid production for the years ended December 31, 2005, 2006 and 2007 and six months ended June 30, 2008 was 10,097 Bbls, 20,295 Bbls, 16,951 Bbls and 15,904 Bbls, respectively. As of June 30, 2008, there were 14 operating wells and five non-operating wells shut in because the Alberta Government had not validated well compliance, with a total production impact of approximately 1.4 Mmcfe/d working interest. Subsequent to June 30, 2008, data has been submitted with respect to these wells to meet compliance requirements. Net production does not include this 1.4 Mmcfe/d working interest.

(2)		Includes conventional net production on the Mannville properties.

(3)		Includes conventional net production and other unconventional natural gas resource play net production (including from the Belly River) on the Horseshoe Canyon properties.

(4)		Average production costs include field contractors, compression, chemicals and treating supplies, operating overhead and minor well workovers, as well as transportation expenses, which includes costs to move saleable gas from the plant outlet to its ultimate point of sale.

Marketing and Customers

We market the majority of the natural gas production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our natural gas production to purchasers at market prices. During the year ended December 31, 2007, sales to Nexen Marketing, BP Canada Energy Company, Shell Energy North America (Canada) Inc. and TD Commodity & Energy Trading Inc. in the aggregate represented over 90% of our production revenue. For the six months ended June 30, 2008, sales to BP Canada Energy Company, Shell Energy North America (Canada) Inc. and Nexen Marketing purchased in the aggregate represented over 90% of our production revenue. In 2006 and 2007, 100% of our production was sold under short-term contracts (less than 12 months), and in 2008, we expect approximately 100% to be sold under short-term contracts. We normally sell

production to a relatively small number of customers, as is customary in our industry. To the extent these and other customers reduce the volumes of natural gas that they purchase from us and are not replaced by new customers, our revenues and cash available for distribution could decline. However, based on the current demand for natural gas, and the availability of other purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and results of operations because we believe we could sell our production to another customer. Downside prices are minimized and upside pricing exposure preserved in our actively managed portfolio approach to hedging gas production.

Hedging Activities

From time to time, we have entered, and expect to continue to enter, into hedging transactions with unaffiliated third parties with respect to natural gas prices to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in natural gas prices, subject to certain restrictions under our existing credit agreements. For a more detailed discussion of our hedging transactions and our expected hedging policy, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk.”

Environmental and Stakeholder Friendly Practices

We employ a proactive graduated environmental, health and safety, or EH&S, program required by members of the Canadian Association of Petroleum Producers, or CAPP, to address EH&S issues and consider stakeholder interests. The general objectives of this program are to commit to responsible resource development, improve processes and procedures continuously, promote industry-wide best practices, foster innovation in EH&S areas, encourage positive mutual relationships among all stakeholders and methodically benchmark key data to demonstrate status and improvements in key operational areas. All potential EH&S impacts are closely regulated and monitored by regulatory authorities, and we believe we are in material compliance with all requirements. Our company policy is to go beyond the minimum regulated requirements, for example, by systematically identifying possible hazards and risks in our operations and designing appropriate prevention and mitigation procedures. The proactive attitude we have toward mitigating any impacts on area stakeholders is further demonstrated by maximizing noise attenuation in our gas processing facilities and pad drilling full scale field developments where applicable. The pad drilling methods we utilize significantly reduce the overall operational footprint of the full field development scenario in the Mannville CBM plays in the Greater Corbett Creek area. We also drill Horseshoe Canyon CBM play wells using minimum disturbance techniques that do not require lease building, therefore minimizing the overall footprint of the field development. We believe that these practices have helped us establish positive relationships with regulatory bodies, enhanced the willingness of land owners to do business with us and built a high degree of employee satisfaction, all of which we believe add value to our business.

Regulation in Canada

The oil and natural gas industry in Canada is subject to extensive controls and regulation governing its operations (including land tenure, exploration, development, production, refining, transportation and marketing) imposed by legislation enacted by various levels of government. The oil and natural gas industry is also subject to various agreements among the federal and provincial governments with respect to pricing and taxation of oil and natural gas. Although it is not expected that any of these controls, regulations or agreements will affect our operations in a manner materially different than they would affect other oil and gas issuers of similar size operating in Canada, the controls, regulations and agreements should be considered carefully by investors in the oil and gas industry.

The North America Free Trade Agreement

The North American Free Trade Agreement, or 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, so long as any export restrictions do not:


	•	reduce the proportion of energy resources exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period);

	•	impose an export price higher than the domestic price; or

	•	disrupt normal channels of supply.

All three countries are prohibited from imposing minimum or maximum export or import price requirements, with some limited exceptions.

NAFTA contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, which is important for Canadian natural gas exports.

Pricing and Marketing of Natural Gas

Natural gas exported from Canada is subject to regulation by the National Energy Board, or NEB, and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas 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 Mcfe/d) must be made pursuant to a NEB order. Any natural gas export to be made pursuant to a contract of longer duration (up to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export license from the NEB and the issuance of such license requires the approval of the Governor General of Canada acting on the advice of the Federal Cabinet of the Government of Canada and the NEB.

The Government of Alberta also regulates the volumes of natural gas that may be removed from that province for consumption elsewhere based on factors such as reserve availability, transportation arrangements and market considerations.

Royalties and Incentives

General. Each province of Canada has legislation and regulations that govern land tenure, royalties, production rates, environmental protection, and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur, and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is subject to certain provincial mineral taxes. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the 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 and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. Royalty holidays and reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and would increase the net income and funds from operations of such producers. However, the trend in recent years has been for provincial governments to eliminate, amend or allow such incentive programs to expire without renewal, and consequently few such incentive programs are currently operative.

Alberta Royalties. In Alberta, companies are granted the right to explore, produce and develop petroleum and natural gas resources in exchange for royalties, bonus bid payments and rents. The royalties payable to the Alberta Government in respect of natural gas are currently determined by a sliding scale based on a reference price,

the type of natural gas, the quantity produced in a given month and the vintage of the natural gas. The vintage of natural gas is based on various criteria set out in the regulations, but is generally determined based on when the natural gas pools were discovered and natural gas from such pools was recovered. As an incentive for the production and marketing of natural gas which may have been flared, the royalty rate on natural gas produced in association with oil is less than non-associated natural gas. The royalty payable on natural gas varies between 5% and 30%, in the case of new natural gas, and between 5% and 35%, in the case of old natural gas. Natural gas produced from qualifying intervals in eligible natural gas wells spudded or deepened to a depth below 2,500 meters is also subject to a royalty exemption, the amount of which depends on the depth of the well. Under the proposed royalty regime, natural gas royalties will be set by a sliding rate formula sensitive to a combination of price and production volume, and to a lesser extent well depth. New natural gas royalty rates will range from 5% to 50% with rate caps at a natural gas price of C$18.72/Mcfe or at a well productivity of 568 Mcfe/d.

On October 25, 2007, the Alberta Government released the New Royalty Framework report containing the government’s proposals for Alberta’s new royalty regime, scheduled to be effective on January 1, 2009. The proposed royalty regime includes new royalty formulas for conventional oil and natural gas that will operate on sliding scales that are determined by commodity prices and well productivity. In addition, the Alberta Government is intending to implement a shallow rights reversion policy in order to maximize the development of currently undeveloped resources. The policy’s objective is for the mineral rights to shallow gas geological formations that are not being developed to revert back to the Government and be made available for resale. Substantial legislative, regulatory and systems updates will be introduced before changes become fully effective in January 2009.

We expect that recent changes to the royalty framework will impact us positively. In the Mannville CBM plays, the royalty reduction for drilling depth offsets an increase in royalty rates on all current and future wells. In the Horseshoe Canyon CBM play, discounts for CBM productivity rates result in a lower overall royalty expense. The Montney lands in British Columbia are unaffected by the royalty regime.

The implementation of the proposed changes to the royalty regime in Alberta is subject to certain risks and uncertainties. The significant changes to the royalty regime require new legislation, changes to existing legislation and regulation and development of proprietary software to support the calculation and collection of royalties. Additionally, certain proposed changes contemplate further publicand/or industry consultation. There may be modifications introduced to the proposed royalty structure prior to the implementation thereof. See “Risk Factors — Provincial royalty regimes are a significant factor in the profitability of natural gas production in Canada and changes in these regimes could adversely affect our profitability.”

British Columbia Royalties. Producers of natural gas in the Province of British Columbia are required to pay annual rental payments and lessor royalties with respect to British Columbia Crown leases and annual rentals, lessor royalties and production taxes in respect of gas produced from freehold lands. The royalty payable on natural gas pursuant to British Columbia Crown leases is determined by a sliding scale based on a reference price, which is the greater of the price obtained by the producer, and a prescribed minimum price. However, when the reference price is below the select price (a parameter used in the royalty rate formula), the royalty rate is fixed.

On May 30, 2003, the Ministry of Energy and Mines for the Province of British Columbia announced an Oil and Gas Development Strategy for the Heartlands, or the Strategy. The Strategy is a comprehensive program to address road infrastructure, targeted royalties and regulatory reduction, and British Columbia service sector opportunities. In addition, the Strategy is intended to result in economic and employment opportunities for communities in British Columbia’s heartlands.

Some of the financial incentives in the Strategy include:


	•	royalty credits of up to C$30 million annually towards the construction, upgrading, and maintenance of road infrastructure in support of resource exploration and development, with funding contingent upon an equal contribution from industry; and

	•	new royalty rates for low productivity natural gas to enhance marginally economic resource plays, royalty credits for deep gas exploration to locate new sources of natural gas, and royalty credits for summer drilling to expand the drilling season.

On February 27, 2007 the Government of British Columbia unveiled the BC Energy Plan, or the Plan, which sets out a “Vision for Clean Energy Leadership” and includes targets for zero net greenhouse gas emissions and new investments in innovation. The Plan outlines the steps required for all stakeholders to develop realistic and achievable goals for conservation, energy efficiency and clean energy. With regards to the oil and gas industry, among the changes to be implemented are: (i) a new Net Profit Royalty Program; (ii) the creation of a Petroleum Registry; (iii) the establishing of an infrastructure royalty program (combining road and pipeline initiatives and increasing development in under-explored areas); (iv) the elimination of routine flaring at producing wells; (v) the creation of policies and measures for the reduction of emissions; (vi) the development of unconventional resources such as tight gas and coalbed gas; and (vii) the new Oil and Gas Technology Transfer Incentive Program that encourages the research, development and use of innovative technologies to increase recoveries from existing reserves and promotes responsible development of new oil and gas reserves.

In July 2007, the Government of British Columbia made a further announcement regarding the Net Profit Royalty Program. The purpose of the program is primarily to encourage development of unconventional gas (coalbed, shale and tight sand gas) or remote conventional gas resources in the province. The Net Profit Royalty Program will enable producers of these resources to pay lower royalty rates in the initial stages of development and commercialization in exchange for higher royalty rates in later stages of production once projects have recovered their capital investment. The Net Profit Royalty Regulation was enacted on May 8, 2008. The regulation divides the life of a natural gas project into a pre-production phase and three production phases. The net profit royalties payable under the regulation are weighted toward the latter stages of production and increase with the profitability of the project. The royalty rate is 2% of gross revenues until capital costs are recovered and then rises in stages to the greater of 5% of gross revenue and 35% of net revenue. We do not qualify for this program as our production rates are above the maximum eligibility threshold.

Land Tenure

Natural gas located in the Western Canadian 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, licenses, 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.

Worker Safety

Oilfield operations must be carried out in accordance with safe work procedures, rules and policies contained in provincial safety legislation. Such legislation requires that every employer ensures the health and safety of all persons at any of its work sites and all workers engaged in the work of that employer, and that every employer ensure that all of its employees are aware of their duties and responsibilities under the applicable legislation. Such legislation also provides for accident reporting procedures.

Regulation in the United States

Federal Lands

The U.S. Department of the Interior Bureau of Land Management, or BLM, reviews and approves permits and licenses to explore, develop, and produce oil and gas on both Federal and Indian lands. BLM is also responsible for inspection and enforcement of oil and gas wells and other development operations to ensure that lessees and operators comply with lease requirements and BLM regulations.

Washington

The Washington State Department of Natural Resources, through the Division of Geology and Earth Resources, regulates drilling and related activities under the Oil and Gas Conservation Act and the Department of Natural Resources rules.

Oregon

All regulatory aspects of oil and gas drilling activity in Oregon are handled by the Oregon Department of Geology and Mineral Industries and its Oil, Gas & Geothermal Regulatory and Reclamation Program. An annual fee is assessed for all wells. A bond is maintained until the wells are plugged and the site is reclaimed. Samples and records are maintained on all wells, including a sample repository available to all individuals for study of the wells.

Idaho

The Idaho Department of Lands, through the Bureau of Surface and Mineral Resources, regulates the exploration, drilling and production of oil and gas resources under Idaho’s Oil and Gas Conservation Laws, which are located in Title 47 of the Idaho Code. The Idaho Legislature delegated regulatory oversight of this function to the Idaho Oil and Gas Conservation Commission, which consists of the Idaho State Board of Land Commissioners.

Environmental

The oil and natural gas industry is currently subject to environmental regulation pursuant to provincial, federal and local legislation in Canada, and federal, state and local legislation in the United States. Environmental legislation contains restrictions or prohibitions on releases and emissions of various substances produced or utilized in association with oil and gas industry operations. In addition, legislation requires that well, pipeline, and facility sites be abandoned and reclaimed to the satisfaction of governmental authorities.

Applicable environmental laws may also impose remediation obligations upon certain responsible persons with respect to a property designated as a contaminated site. Responsible persons include persons responsible for the substance causing the contamination, persons who caused the release of the substance, and any past or present owner, operator, tenant or other person in possession of the site. Compliance with such legislation may require significant expenditures. A breach of such legislation may result in the imposition of material fines and penalties, the suspension or revocation of necessary permits, licenses and authorizations, civil liability for pollution damage and contamination, or the issuance ofclean-up orders or injunctions.

We have established guidelines and management systems to ensure compliance with environmental legislation. We endeavor to ensure that on an ongoing basis we are in material compliance with environmental requirements and are proactive in this respect. We have designated staff whose responsibility it is to monitor regulatory requirements and their impact on our business, as well as to implement appropriate compliance procedures. We also employ an EH&S manager whose responsibilities include endeavoring to ensure that our operations are carried out in accordance with applicable environmental requirements and that adequate safety precautions are implemented. In addition, we may consult with government and other stakeholders from time to time to influence the development of this regulatory framework either as an individual company or through the CAPP EH&S group as appropriate. See “— Environmental and Stakeholder Friendly Practices.”

We believe we are in material compliance with environmental legislation at this time. We are committed to meeting our responsibilities to protect the environment in all jurisdictions in which our business operates, and will take the steps necessary to endeavor to ensure material compliance with environmental laws.

Alberta

Environmental compliance in Alberta is governed by the Environmental Protection and Enhancement Act (Alberta), or the EPEA, and the Oil and Gas Conservation Act (Alberta), or the OGCA. The EPEA and the OGCA both impose environmental responsibilities on oil and natural gas operators and working interest holders in Alberta, and also provide for the imposition of significant fines and penalties for violations. The EPEA and the OGCA create standards with respect to the release of effluents and emissions, including sulphur dioxide and nitrogen oxide, and set out reporting and monitoring obligations. Dewatering requirements, particularly to the extent that saline water or water containing traces of hydrocarbons is required to be released, stored or disposed of, is impacted by such environmental legislation. Significant penalties may be imposed for non-compliance with environmental legislation.

In addition to general environmental and oil and gas legislation protecting fresh water resources, in Alberta diversions of water and activities related to water, which is regulated as a provincial resource, require appropriate approvals or licenses pursuant to the Water Act (Alberta). Our activities in the Mannville CBM plays produce salt water and require disposal permits to allow us to dispose of produced water in deeper saltier water bearing horizons, or saline acquifers. We regularly request these disposal permits and they are routinely approved by Alberta Environment.

British Columbia

There are a number of British Columbia statutes that address the protection of the environment. Waste disposal, air and effluent emissions, remediation of contaminated sites, and spill reporting are regulated under the Environmental Management Act (British Columbia). New energy projects and modifications to existing energy projects may be subject to environmental review pursuant to the provisions of the Environmental Assessment Act (British Columbia) which provides for public participation in the environmental review. The Oil and Gas Activities Act (British Columbia), which is to come into force by regulation, will add new regulatory powers to enhance the protection of environmental and landowner interests and create a comprehensive compliance and enforcement regime regarding the exploration, development, production, processing and storage of petroleum and natural gas and the operation of pipelines. It will also strengthen the existing penalty structure for offences to include fines of up to C$1.5 million for non-compliance.

Greenhouse Gas Emissions

Canada is a signatory to the United Nations’ Framework Convention on Climate Change and in 2002 ratified the Kyoto Protocol thereunder. The Kyoto Protocol calls for Canada to reduce its GHG emissions nationally to 6% below 1990 levels during the 2008 through 2012 compliance period. Although policy announcements of the Government of Canada have brought into question Canada’s compliance with the Kyoto Protocol requirements, the Kyoto Protocol Implementation Act was enacted in February 2007 in an effort to ensure Canada meets it obligations under the Kyoto Protocol, and remains in force today.

In April 2007, Canada released a national GHG (and other air emissions) reduction plan titled Turning the Corner, accompanied by a proposed regulatory framework, or the Regulatory Framework, containing, among other things, near-term intensity based GHG emissions reduction requirements for industrial emitters and long-term absolute targets. On March 10, 2008 the targets in the Regulatory Framework were confirmed and additional details of pending federal GHG regulations, including the details of the tradable compliance mechanisms and the establishment of a domestic carbon trading market, were announced. The Regulatory Framework indicates that the federal GHG regime will apply to upstream oil and gas producers, potentially including our business.

The Regulatory Framework indicates an 18% intensity based reduction (from 2006 levels) will be required by the end of 2010 for existing facilities, and annual 2% intensity based reductions will be required thereafter. Annual 2% intensity based reductions after a three year commissioning period will apply to new facilities whose first year of operation was 2004 or later. The Regulatory Framework is planned to apply to upstream gas facilities which produce 3,000 tonnes of GHG emissions per year. Our gas plants and some of our larger field compressors are above the threshold for facilities whose first year of operation was 2004 or later and as such we expect these facilities, or a portion of our operations, to be subject to the 2% annual federal GHG emissions reduction requirements. We believe that we can implement a practical GHG emissions reduction program at a modest ongoing cost. The Regulatory Framework conflicts with the provincial regulations currently in place in Alberta and described below. If the Federal and Alberta Governments are able to agree on a harmonized regulated threshold above the current 3,000 tonnes of annual GHG emissions, our cost to comply with these regulations would likely be less than we currently anticipate.

We, like most Canadian industrial facility operators, are currently subject to federal GHG emissions reporting obligations. We have software in place to meet these reporting obligations, and estimate the costs associated with these obligations to be approximately C$20,000 to C$50,000 annually.

On July 1, 2007, the Specified Gas Emitters Regulation came into force under Alberta’s Climate Change and Emissions Management Amendment Act, requiring Alberta facilities which emit more than 100,000 tonnes of GHGs annually to reduce their GHG emissions intensity by 12% (from average2003-2005 levels). We do not

currently own or operate any facilities in Alberta at or above this threshold. The Alberta Government also published a new Climate Change Action Plan in January of 2008 wherein it set an objective to deliver a 50% reduction in GHG emissions by 2050, compared to business as usual, by employing: (i) mandatory carbon capture and storage, or CCS, for certain facilities across all industrial sectors; (ii) energy efficiency and conservation; and (iii) research and investment in clean or green energy technologies, including carbon separation technologies to assist CCS.

The Greenhouse Gas Reduction (Cap and Trade) Act (British Columbia), or Greenhouse Act, which has been passed by the legislature but is not yet in force, provides for the establishment of a “cap and trade” system for large GHG emitters in British Columbia. The cap and trade regulatory system establishes an overall absolute (not intensity based) cap or limit on emissions, while the “trade” part of the system allows regulated emitters to meet their emissions reduction obligations by buying emissions allowances, offset credits or recognized credits from other jurisdictions. Those who can reduce emissions more efficiently are able to sell their surplus units to those who find it more challenging to do so. This system transfers emissions reduction responsibility and management to emitters, while market forces help determine the distribution of reductions. Under the Greenhouse Act, British Columbia will establish the emissions cap for designated large emitters by issuing a limited number of tradable compliance units (emissions allowances) for given periods of time (compliance periods). Each designated emitter will then be required to obtain a number of compliance units equivalent to the amount of GHG emissions it releases within the compliance period. These units must then be surrendered as proof of compliance.

The Carbon Tax Act (British Columbia) provides for a revenue-neutral carbon tax on all fossil fuels purchased or used in the province and sets out tax rates through 2012, beginning at C$10/tonne of CO₂ equivalent in 2008 and increasing by C$5/tonne annually to C$30/tonne in 2012. The tax revenue increases are to be offset by tax reductions.

On January 31, 2008, Canada and Alberta released the final report of a joint Carbon Capture and Storage Task Force, which recommends among others: (i) incorporating CCS into Canada’s clean air regulations; (ii) allocating new funding into projects through a competitive process; and (iii) targeting research to lower the cost of technology. Recent government funding announcements in Canada have also supported the research, development, and potential implementation of CCS in Canada.

Our exploration and production facilities and associated operations and activities emit GHGs. GHG legislation is in early stages of evolution in Canada and United States, and it is relatively early to determine the impact of potential GHG reduction requirements. Mandatory GHG emissions reductions may impose increased costs on our business. It is possible that broader national or regional GHG reduction requirements may directly or indirectly impact natural gas or other fuel markets. Given the evolving nature of the debate related to climate change and the regulation of GHGs, it is not currently possible to predict either the nature of anticipated requirements or the impact on our operations and financial condition at this time.

United States

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will have an environmental assessment prepared that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. Some states have enacted environmental planning requirements similar to NEPA. For example, the State of Washington has enacted the State Environmental Policy Act, or SEPA, which imposes very similar requirements. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA, and all such activities on Washington private or state owned land require governmental permits that are subject to the requirements of SEPA. This process has the potential to delay the development of oil and natural gas projects.

Competition

The natural gas business is highly competitive in the search for and acquisition of additional economic reserves and in the sale of natural gas. Our competitors include international major, independent intermediate and junior sized oil and natural gas companies. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop our properties. These competitors may be able to pay more for properties and may be able to define, evaluate, bid for and purchase a greater number of properties than we can. Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs that allow us to remain competitive. See “Risk Factors — Competition in the natural gas industry is intense and many of our competitors have resources that are greater than ours.”

Seasonality

The volatility of natural gas prices has a significant impact on our financial performance. In general, natural gas prices in Canada are seasonal in nature, with higher prices existing in the winter months (November to March) and lower prices in the summer months (April to October). Natural gas prices are also affected by the amount of gas in local and North America wide storage, or inventory within the market. We generally sell our production into a balanced portfolio of current market prices and medium-term sales actively managed to reduce downside pricing exposure to ensure capital expenditure programs have consistent funding while maximizing the exposure to upside pricing.

Our operations are also impacted by seasonality, as road closures to heavy loads occur in the spring months, which can delay our access to drilling locations. This has less impact on the Mannville CBM operations due to our pad drilling methods with specialized rigs. We are also susceptible to weather delays in the Horseshoe Canyon CBM operations in the summer when heavy rains can occur. This is because we operate using minimal surface disturbance methods, and avoid all-weather drilling leases and access roads to our drilling locations in the Horseshoe Canyon CBM play. In the Mannville CBM plays, we build all-weather access roads to large all-weather production pads that in combination with multilateral drilling techniques have reduced the overall field development footprint by 17 times compared to traditional vertical drilling gas field developments. There are often periods of extreme cold weather that can shut down operations in key areas for, on average, two weeks per year. Equipment becomes brittle in temperatures that can reach minus 58 degrees Fahrenheit or minus 50 degrees Celsius with the wind chill factor, and staff movement in remote field areas is potentially hazardous.

Title to Properties

We believe that we have satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, we make minimal investigation of title at the time we acquire undeveloped properties. We make title investigations and receive title opinions of local counsel only before we commence most drilling operations. We believe that we have satisfactory title to all of our material assets. Although title to our properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or will materially interfere with our use in the operation of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus. See “Risk Factors — Unforeseen title defects may result in a loss of entitlement to production and reserves.” and “Risk Factors — Certain lands in Alberta are subject to split title issues with respect to natural gas rights and coal rights.”

Insurance

We carry insurance coverage to protect our assets at or above the standards typical within the oil and natural gas industry. Insurance levels are determined and acquired by us after considering the perceived risk of loss,

coverage determined appropriate and the overall cost. Coverages currently in place include protection against third party liability, property damage or loss, and, for certain properties, business interruption.

Employees

As of October 1, 2008, we had approximately 92 full time employees and 130 consultants in our Calgary office and field operations. All the officers and members of senior management are our employees and employees of TEC. Pursuant to the terms of a management services agreement, we and TEC may utilize the services of the employees of the other entity, subject to certain conditions set forth therein.

Offices

TEC currently leases approximately 54,238 square feet of office space in Calgary, Alberta, at 1000, 444 — 7th Avenue S.W., where our principal executive offices are located. The monthly rental expense is C$85,876.83 and the lease expires in September 2013. In addition, TEC currently leases approximately 29,231 square feet of office space in Calgary, Alberta, at 401 — 9th Avenue S.W. and sub-leases this space to a third party. The monthly rental expense is C$34,102.84 and the lease expires in December 2009.

Legal Proceedings

From time to time, we are subject to various legal proceedings arising in the ordinary course of business, including proceedings for which we have insurance coverage. As of the date hereof, we are not party to any material legal proceedings.

MANAGEMENT

Directors and Executive Officers

The following table sets forth information about our directors and executive officers as of the date of this prospectus:


Name of Director or Officer	Age		Position Held

Eugene I. Davis		53	Executive Chairman of the Board and Director(1)(3)
Todd A. Dillabough		46	President, Chief Executive Officer, Chief Operating Officer and Director
Kenneth L. Ancell		66	Director(3)
Timothy J. Bernlohr		49	Director(2)
Anthony Caluori		42	Director(2)
John H. Forsgren		62	Director(1)
Marc MacAluso		48	Director(1)(2)(3)
Todd A. Overbergen		43	Director(2)(3)
Alan G. Withey		39	Chief Financial Officer
Tracey Bell		44	Vice President, Marketing
Colin Michael Finn		53	Vice President, Exploration
Jacques G. St. Hilaire		64	Vice President, Exploitation, Reserves and Planning


(1)		Member of our audit committee prior to the closing of this offering.

(2)		Member of our compensation committee prior to the closing of this offering.

(3)		Member of our reserves committee prior to the closing of this offering.

Eugene I. Davis. Eugene I. Davis has served as Executive Chairman of the board of directors since August 2007. Mr. Davis is the Chairman and Chief Executive Officer of PIRINATE Consulting Group, LLC, a privately-held consulting firm that specializes in turn-around management, liquidation and sale management, merger and acquisition consulting, hostile and friendly takeovers, proxy contests and strategic planning advisory services for public and private business entities. From 2001 to 2004, Mr. Davis served in various executive positions at RBX Industries, Inc., a manufacturer of closed cell foam and custom mixed rubber compounds. RBX Industries, Inc. filed a voluntary petition for reorganization under Chapter 11 in March 2004. From 1998 to 1999, Mr. Davis was Chief Operating Officer of Total-Tel USA Communications, Inc., a facilities-based provider of voice, data and internet solutions to commercial and wholesale carrier markets. From 1990 to 1997, Mr. Davis served in various executive positions of Emerson Radio Corporation including President, Vice Chairman and director. He received his B.A. from Columbia University’s Columbia College, a Masters in International Affairs from Columbia University’s School of International Affairs, and a J.D. from Columbia University’s School of Law. Mr. Davis currently serves as the chairman of the board of directors of Atari Inc. (NASDAQ: ATAR) and Atlas Air Worldwide Holdings, Inc. (NASDAQ: AAWW) and is also a member of the following board of directors: American Commercial Lines Inc. (NASDAQ:ACLI); Delta Air Lines, Inc. (NYSE:DAL); Foamex International Inc. (OTC:FMXL.PK); Footstar, Inc. (OTC:FTAR.OB); Knology, Inc. (NASDAQ:KNOL); Silicon Graphics, Inc. (NASDAQ:SGIC); Solutia Inc. (NYSE:SOA) and Viskase Companies, Inc. (OTC:VKSC). Mr. Davis was appointed to our board of directors pursuant to the fourth amended and restated stockholder agreement, as amended, as an appointee of the McNeil Group and a letter agreement of the same date executed in connection with the financing related to the TRC 2007 subordinated credit agreement.

Todd A. Dillabough. Todd A. Dillabough is our President, Chief Executive Officer and Chief Operating Officer and has served in these positions since November 2007. He has been a director since April 15, 2008. Prior to joining our company, Mr. Dillabough was President, Chief Executive Officer, Chief Operating Officer and a director of Pioneer Natural Resources Canada, Inc., an oil and gas exploration and production company, which was sold to TAQA North on November 27, 2007. He received his B.Sc. in Geology from the University of Calgary in

1984. Mr. Dillabough is a professional geologist registered with the Association of Professional Engineers, Geologists and Geophysicists in Alberta and is also a former Governor of the Canadian Association of Petroleum Producers.

Kenneth L. Ancell. Kenneth L. Ancell has been a director since February 2008. Mr. Ancell owns and operates Kenneth L. Ancell PE Inc., an engineering consulting firm. From 1999 to 2005, Mr. Ancell served as Executive Vice President of Tipperary Corp., a coalbed methane and conventional natural gas exploration and production company, where he focused on operation of the company’s Australian project and corporate reserves. He received his degree of Petroleum Engineer from the Colorado School of Mines. Mr. Ancell was appointed to our board of directors pursuant to the fourth amended and restated stockholder agreement, as amended, as an appointee of certain lenders under the TRC 2007 subordinated credit agreement.

Timothy J. Bernlohr. Timothy J. Bernlohr has been a director since March 2007. Mr. Bernlohr is the managing member of TJB Management Consulting, LLC, which specializes in providing project specific consulting services to businesses in transformation, plan administration, and interim executive management. Mr. Bernlohr founded the consultancy in 2005. From 1997 to 2005, Mr. Bernlohr was the President and Chief Executive Officer of RBX Industries, Inc., a manufacturer of closed cell foam and custom mixed rubber components. RBX Industries, Inc., filed a voluntary petition for reorganization under Chapter 11 in March 2004. Prior to joining RBX in 1997, Mr. Bernlohr spent 16 years in the International and Industry Products division of Armstrong World Industries, Inc., a manufacturer of floors, ceilings and cabinets, where he served in a variety of management positions. Mr. Bernlohr is also a member of the board of directors of Atlas Air Worldwide Holdings Inc. (NASDAQ: AAWW) and received his B.A. from Pennsylvania State University. Mr. Bernlohr was appointed to our board of directors pursuant to the fourth amended and restated stockholders agreement, as amended, as an appointee of Aurora Energy Partners, L.P.

Anthony Caluori. Anthony Caluori has been a director since August 2007. Mr. Caluori is a Senior Vice President of Research of Chilton Investment Company. Prior to joining Chilton, he was a director of research at Angelo, Gordon & Co., a privately held registered investment advisor dedicated to alternative investing, where he focused on investments in the leveraged loan, high yield and distressed debt markets and advised parties involved in corporate restructurings and managing distressed debt investments and a managing director of Morgens, Waterfall, Vintiadis & Company, Inc., a financial services firm. Prior to that he focused on restructuring advisory work at the accounting firms of Ernst & Young LLP and Arthur Andersen LLP. Mr. Caluori received his B.B.A. in Accounting and Finance from the Frank G. Zarb School of Business at Hofstra University and is a Certified Public Accountant (inactive) in the State of New York. Mr. Caluori was appointed to our board of directors pursuant to the fourth amended and restated stockholders agreement, as amended, as an appointee of certain lenders under the TRC 2007 subordinated credit agreement.

John H. Forsgren. John H. Forsgren has been a director since November 2007. Mr. Forsgren was the Vice Chairman of the board of directors, Executive Vice President and Chief Financial Officer of Northeast Utilities System, a large utility system operator, until December 2004. Prior to that, he served in various positions including, as a managing director of corporate finance of Chase Manhattan Bank and a vice president-treasurer of The Walt Disney Company, an international family entertainment and media enterprise, and as a Senior Vice President and Chief Financial Officer of Euro-Disney. Mr. Forsgren currently serves as a director of The Phoenix Companies (NYSE: PPX), a manufacturer of life insurance, annuity and investment products, and CuraGen Corporation (NASDAQ: CRGN), a biopharmaceutical company. Mr. Forsgren received his B.A. from Georgetown University, his M.B.A. from Columbia University and his M.S. from the University of Geneva (Switzerland). Mr. Forsgren was appointed to our board of directors pursuant to the fourth amended and restated stockholder agreement, as amended, as an appointee of certain lenders under the TRC 2007 subordinated credit agreement.

Marc MacAluso. Marc MacAluso has been a director since September 2007. Mr. MacAluso was a founding partner of Destiny One, LP and Destiny Oil & Gas LLP, two investment entities. Since 2004 he has been self-employed. From 2001 to 2004, he served as the Chief Executive Officer and Chief Operating Officer of Inland Resources Inc., an oil and gas exploration and production company. Mr. MacAluso spent seven years as senior vice president at TCW Asset Management Company, a privately owned investment manager, where he was involved in all aspects of structured financing transactions for the midstream and upstream oil and gas industry. Mr. MacAluso

received his B.S. in Petroleum Engineering from Texas A&M University and is a registered professional engineer (inactive) in the State of Texas. Mr. MacAluso was appointed to our board of directors pursuant to the fourth amended and restated stockholder agreement, as amended, as an appointee of a majority of the holders of our preferred stock.

Todd A. Overbergen. Todd A. Overbergen has been a director since August 2007. Mr. Overbergen is a director of D. E. Shaw & Co., L.P., a global investment and technology investment firm, and a director of Laminar Direct Capital L.P., a provider of debt and equity capital to small and midsized businesses, where he currently manages the energy investment portfolio. Prior to joining D.E. Shaw, Mr. Overbergen was a principal of Duke Capital Partners, LLC, a merchant banking subsidiary of Duke Energy Corporation focused on providing mezzanine debt, senior debt and equity financing to businesses in the energy industry. Mr. Overbergen previously served on the board of directors of Cougar Hydrocarbons Inc. and the board of managers of EnerVest Olanta LLC. Mr. Overbergen received a B.A. in accounting and finance from Texas A&M University. Mr. Overbergen was appointed to our board of directors pursuant to the fourth amended and restated stockholder agreement, as amended, as an appointee of a majority of the holders of our preferred stock.

Alan G. Withey. Alan G. Withey is our Chief Financial Officer and has served in this position since January 2008. Prior to joining our company, Mr. Withey held positions at oil and gas exploration and production companies Ironhorse Oil & Gas Inc., Cheyenne Energy Inc., Devon Canada Corporation, Chauvco Resources International Ltd., and Pioneer Natural Resources Canada, Inc. From 2005 to 2007, Mr. Withey served as the Vice President of Finance and the Chief Financial Officer for Ironhorse Oil & Gas Inc., a public junior oil and gas company, with its principal properties in Alberta and Saskatchewan in Canada. From 2002 to 2004, he served as the Vice President of Finance and the Chief Financial Officer for Cheyenne Energy Inc., a public junior oil and gas company, with principal properties located in Alberta, Canada. Mr. Withey is also a member of the board of directors of Summus Capital Corp. (TSX Venture Exchange: SS.P). He received his Bachelor of Commerce degree from the University of Calgary. Mr. Withey is a Chartered Accountant (Alberta), a Certified Public Accountant (Illinois) and a Certified Financial Planner (Canada).

Tracey Bell. Tracey Bell has been our Vice President of Marketing since March 2008. From 2006 to 2007, Ms. Bell was the Vice President of Marketing for Pioneer Natural Resources Canada, Inc., an oil and gas exploration and production company. From 1999 to 2006 she served in various positions for Pioneer Natural Resources Canada, Inc., including as Manager of Marketing. Ms. Bell received her B.Sc. in Computer Science from the cooperative program of the University of Waterloo and the University of Calgary.

Colin Michael Finn. Colin Michael Finn is our Vice President, Exploration and has served in this position since March 2008. Mr. Finn joined us in 2002 as Senior Geologist, becoming the Chief Geologist and Director of CBM Assets in 2005. From 2000 to 2002 he served as a Senior Geologist for Trinity Energy, a private oil and gas company. Prior to that he worked for a series of intermediate and small oil and gas companies in a large number of North American Basins. Mr. Finn received his B.Sc. in Geology from the University of Alberta.

Jacques G. St. Hilaire. Jacques G. St. Hilaire is our Vice President of Exploitation, Reserves and Planning and has served in this position since January 2008. Since 2004, Mr. St. Hilaire has served as Vice President, CBM; Manager, CBM; and Geologist at Pioneer Natural Resources Canada, Inc., an oil and gas exploration and production company. From 2002 to 2003 he was a geological consultant for Tasman Exploration Ltd., a consulting company that provides geological services to the oil and gas industry. Mr. St. Hilaire received his B.Sc. in Geological Engineering from Laval University.

Board Structure and Compensation

Composition of our Board of Directors

Our board of directors consists of eight directors. Our fifth amended and restated certificate of incorporation provides that our board of directors will be classified into three classes of directors of approximately equal size upon the closing of this offering. The term of office of the first class of directors, consisting of Messrs. Forsgren and Overbergen, will expire at our 2010 annual meeting of stockholders. The term of office of the second class of directors, consisting of Messrs. Ancell, Dillabough and MacAluso, will expire at our 2011 annual meeting of stockholders. The

term of office of the third class of directors, consisting of Messrs. Bernlohr, Caluori and Davis, will expire at our 2012 annual meeting of stockholders. Our board has determined that Messrs. Ancell, Bernlohr, Caluori, Forsgren, MacAluso and Overbergen are independent under applicable federal securities laws and the listing standards of the New York Stock Exchange. Pursuant to the fourth amended and restated stockholders agreement among all holders of our outstanding capital stock, as amended, which expires upon the closing of this offering, Mr. Bernlohr was appointed by Aurora Energy Partners, L.P., Mr. Caluori was appointed by certain lenders under the TRC 2007 subordinated credit agreement, Mr. Davis was appointed by Mr. Charles S. McNeil, The McNeil Family Irrevocable GST Trust and The Charles S. McNeil Family Trust, Messrs. Ancell and Forsgren were appointed by certain lenders under the TRC 2007 subordinated credit agreement and Messrs. MacAluso and Overbergen were appointed by a majority of the holders of our preferred stock. The stockholders agreement terminates upon the closing of this offering.

Our amended and restated bylaws effective upon the closing of this offering will provide that our board consists of no less than five and no more than thirteen persons. The exact number of members on our board will be determined from time to time by resolution of a majority of our full board. At any board meeting, a majority of the total number of directors then in office will constitute a quorum for all purposes.

Each director will hold office until the annual meeting for the year in which his or her term expires and until his or her successor is duly elected and qualified, subject, however, to such director’s earlier death, resignation, retirement, disqualification or removal. Directors may be removed from office only for cause by the affirmative vote of the holders of a majority of the voting power of all then-outstanding shares of our capital stock that are entitled to vote generally in the election of our directors. Our bylaws will provide that in the case of any vacancies among the directors such vacancy will be filled by the board.

Committees of the Board

Our board has an audit committee, a compensation committee and a reserves committee and, upon the closing of this offering, will establish a nominating and corporate governance committee.

Audit Committee. We established an audit committee on September 17, 2007, which assists our board in fulfilling its oversight responsibilities with respect to our accounting and financial reporting processes. Upon the closing of this offering, the audit committee will monitor (i) the integrity of our financial statements; (ii) the independent auditor’s qualifications, performance and independence and (iii) the compliance with legal and regulatory requirements. This committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board, including: the selection of our independent auditors, the scope of our annual audits, fees to be paid to the independent auditors, the performance of our independent auditors and our accounting practices. In addition, the audit committee oversees our compliance programs related to legal and regulatory requirements. This committee will also review and approve all related-party transactions.

Our audit committee currently consists of Messrs. Forsgren, Davis and MacAluso. Upon the closing of this offering, our audit committee is expected to consist of Messrs. , and . Our board has determined that each of the members of our post-closing audit committee is independent under the rules of the SEC and the listing requirements of the New York Stock Exchange. Mr. Forsgren serves as chairman of this committee and has been determined by our board of directors to be an “audit committee financial expert” under the rules of the SEC.

Compensation Committee. We established a compensation committee on September 17, 2007, which reviews and recommends policies relating to compensation and benefits of our directors and employees and is responsible for approving the compensation of our chief executive officer and other executive officers. Our compensation committee also administers the grant of equity awards under our equity incentive plans. The compensation committee is also responsible for producing the annual report on executive compensation required to be included in our annual proxy materials under the federal securities laws.

Our compensation committee currently consists of Messrs. Bernlohr (Chairman), Caluori, MacAluso and Overbergen. Upon the closing of this offering, our compensation committee is expected to consist of Messrs. , and . Our board has determined that each of the members of our compensation committee is independent under the listing requirements of the New York Stock Exchange.

Reserves Committee. We established a reserves committee on September 17, 2007, which assists our board in respect of disclosure of information with respect to our CBM activities and reserves data and the evaluation or audits of our gas reserves. The reserves committee also assists our board in the evaluation and appointment of independent consultants for the annual evaluation of reserves and the scope of such annual evaluation. Our reserves committee currently consists of Messrs. Ancell (Chairman), Davis, MacAluso and Overbergen which will remain the same after the closing of this offering.

Nominating and Corporate Governance Committee. Upon the closing of this offering, the board intends to establish a nominating and corporate governance committee, which is expected to consist of Messrs. , and . The nominating and corporate governance committee will have the responsibility for identifying individuals qualified to become board members consistent with the criteria established by the board of directors from time to time, recommending director nominees to the board of directors, recommending corporate governance guidelines to the board of directors and overseeing the evaluation of the board of directors and our management.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serve as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of our board of directors. Prior to September 17, 2007, the board of directors determined executive compensation.

Compensation of Directors

Effective February 2008, board members are entitled to an annual fee of US$50,000 and committee chairs receive an additional annual fee of US$25,000. Board and committee members are entitled to an attendance fee of US$1,500 in respect of each board and committee meeting attended in person and US$750 in respect of such meetings attended by phone and are reimbursed for out-of-pocket expenses incurred in connection with attending such meetings.

Corporate Governance Guidelines, Code of Business Conduct and Code of Ethics

Upon the closing of this offering, we intend to adopt Corporate Governance Guidelines and a Code of Business Conduct and Ethics for all directors and executive officers. These documents will be available in print to any stockholder requesting a copy in writing from our corporate secretary at our executive offices set forth in this prospectus.

Indemnification

Our amended and restated certificate of incorporation and bylaws provide that we will indemnify our officers and directors to the fullest extent permitted by law. Additionally, we have entered into separate indemnification agreements with our officers and the members of our board of directors to provide additional indemnification benefits, including the right to receive in advance reimbursements for expenses incurred in connection with a defense for which the officer or director is entitled to indemnification.

Directors’ and Officers’ Liability Insurance

We carry directors’ and officers’ liability insurance. We intend to increase our policy coverage to reflect our status as a publicly traded company.

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Overview of Compensation Program for Fiscal Year 2007

The Compensation Committee of our board of directors, which we refer to in this section as the Committee, is responsible for establishing, implementing and continually monitoring adherence with our compensation philosophy. The Committee works to ensure that the total compensation paid to our executive officers is fair, reasonable and competitive. Generally, the types of compensation and benefits provided to our executive officers, including our named executive officers, are similar to those provided to executive officers at comparable companies in similarly situated positions.

During 2007, we were a company in transition. Rapid growth in operations since 2005 and an increasingly complex capital structure placed difficult new demands on our senior management. In response, our board of directors elected to change the majority of our senior management during 2007. In the first quarter of 2007, Mr. Jonathan Baker, our Chief Executive Officer, and Mr. Richard Meli, our Chief Financial Officer, were replaced by Mr. Murray Rodgers, previously our Vice President of Exploration, and Mr. Randy Neely, previously the Vice President of Finance of one of our subsidiaries, respectively. Upon the closing of the TRC 2007 subordinated credit agreement, both Mr. Rodgers and Mr. Neely unexpectedly terminated their employment with us, relying on a negotiated provision in their employment agreements that allowed them to terminate their employment for any reason during a one-month window (during July 2007 in the case of Mr. Rodgers and during August 2007 in the case of Mr. Neely) and receive a significant severance payment. Mr. David Bradshaw was then contracted on a consulting basis as our interim Chief Executive Officer as we began an external search for a permanent replacement. To assist Mr. Bradshaw during this time and facilitate the integration of senior management going forward, in August 2007, our board of directors appointed Mr. Eugene Davis as our Executive Chairman. In November 2007, we successfully recruited Mr. Todd A. Dillabough as our Chief Executive Officer. In December 2007, we recruited Mr. Alan G. Withey as our Chief Financial Officer, who commenced employment with us in January 2008.

As a result of the changes in our senior management during this transitional period, we had a total of five persons, including Mr. Davis, who served in the role of Chief Executive Officer during 2007, and two persons who served in the role of Chief Financial Officer. Each of these persons is included in the “Summary Compensation Table” below, together with the following individuals who are included based on compensation earned in 2007: Messrs. John Anderson, Gordon MacMahon, Paul O’Donoghue and David Cox (none of whom are currently employed by us). We refer to these individuals collectively as our “named executive officers.”

Compensation Philosophy and Objectives

The Committee believes that the most effective executive compensation program is one that is designed to reward the achievement of our specific annual, long-term and strategic goals, and align the executive officers’ interests with those of our stockholders by rewarding performance above established goals, with the ultimate objective of improving stockholder value. The Committee has simplified and enhanced our compensation practices since 2007 and currently evaluates both performance and compensation with the intention of improving our ability to attract and retain superior employees in key positions with compensation that is competitive relative to the compensation paid to similarly situated executive officers of our Comparison Group (as defined below). To that end, the Committee believes executive compensation packages provided by us to our executive officers, including our named executive officers, should include both cash and stock-based compensation that reward performance as measured against established goals. In periods where stock-based compensation has not been practicable, we have opted to compensate our executive officers using a net asset improvement test. In addition, during 2006 and 2007, we provided certain bonuses to our employees and officers, including some of our named executive officers, to retain them during our transitional period. These bonuses reflect our compensation philosophy that retaining proven talent is paramount to our future success. However, because our transitional period has ended and our new management structure is firmly in place, we do not expect to provide retention bonuses going forward. Rather, our annual incentive compensation program will be based on individual and company performance. In order to incentivize our executive officers to increase stockholder value over the long-term, we intend to implement a new

omnibus stock-based compensation plan in 2009 which will replace our net asset allocation program, or Executive Bonus Plan (described below).

Role of Executive Officers in Compensation Decisions

Due to the management transition that occurred during 2007, the Committee was responsible for all compensation-related decisions, including the review of the performance of our named executive officers, subject to the approval of our board of directors. Going forward, this function will be performed by the Chief Executive Officer, except that the Chief Executive Officer will not review his or her own compensation or performance, which will be reviewed by the Committee. The conclusions reached and recommendations made by the Chief Executive Officer, based on these reviews, including with respect to salary adjustments and annual bonus targets or maximums and actual payout amounts, will be presented to the Committee, which will have the discretion to modify any recommended adjustments or awards to our executive officers, subject to the final approval of our board of directors.

Setting Executive Compensation

Based on our compensation philosophy and objectives, the Committee has structured our annual and long-term incentive cash and stock-based executive compensation programs to motivate our executive officers to achieve the business goals set by us and to reward our executive officers for achieving these goals. In making compensation recommendations, the Committee compares various elements of total compensation against publicly-traded and privately-held companies with similar industry sector and size revenue (which we refer to as the Comparison Group), based on data provided to us by an independent third-party compensation consultant, Mercer Human Resource Consulting Limited. For 2007, our Comparison Group was comprised of the following 36 companies with operating statistics between the 25th and 75th percentiles of $185 million to $344 million in revenue, 11,600 to 22,700 barrels of oil equivalent of oil and natural gas production and staff counts in Canada of between 75 and 150:


Advantage Energy Income Fund Atco Midstream Ltd. Atco Pipelines Ltd. BG International Ltd. Canadian Forest Oil Ltd. Centurion Energy International Inc. Crescent Point Energy Trust Daylight Resources Trust Dominion Exploration Canada Ltd. Enterra Energy Trust Fairborne Energy Ltd. Focus Energy Trust Highpine Oil & Gas Limited Hunt Oil Company of Canada Keyera Energy Management Ltd. Kinder Morgan Canada Inc. Norsk Hydro Canada Oil & Gas Inc. Nuvista Energy Ltd.		Paramount Energy Trust Paramount Resources Limited Pembina Pipeline Income Fund Peyto Energy Trust Pioneer Natural Resources Canada Progress Energy Ltd. Quicksilver Resources Canada Inc. Real Resources Inc. Rife Resources Ltd. Semcams L.P. Sherritt International Corporation Shiningbank Energy Income Fund Signalta Resources Limited Sword Energy Inc. Taylor Gas Liquids Ltd. True Energy Trust Tundira Oil & Gas Limited Vermillion Energy Trust

The Committee generally targets total compensation for our executive officers between the 50th and 75th percentile of compensation paid to similarly situated executive officers of our Comparison Group. We believe that our executive officers’ compensation should be targeted at the higher end of the compensation range paid to similarly situated executive officers in light of the complexity associated with our unconventional assets. However, the Committee may deviate from this percentile target range if it determines that it is warranted by the experience level of the individual executive officer and market factors.

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Executive Compensation Components

The principal components of compensation for our executive officers (including our named executive officers) consist of the following:


	•	base salary;

	•	annual incentive compensation (including retention and discretionary bonuses in 2007 and annual incentive plan awards and discretionary bonuses in 2008);

	•	long-term incentive compensation (including net asset allocation awards under our Executive Bonus Plan as of 2008, stock options and other equity-based awards as of 2009);

	•	retirement, perquisites and other benefits; and

	•	severance payments.

Base Salary

We provide our executive officers and other employees with base salaries to compensate them for services rendered during the fiscal year. Base salaries for our executive officers are determined for each executive based on his or her position and scope of responsibility by using comparative market data. The initial base salary for our executive officers is typically established in their employment agreements. Due to the management transition in 2007, however, not all of our named executive officers entered into formal employment agreements and the base salary for certain of our named executive officers was established through negotiations and reflected in consulting agreements or offer letters. For 2008, all of our current named executive officers, with the exception of Mr. Davis, whose employment terms are contained in an offer letter (as described below), have employment agreements that set forth their initial base salary.

Salary levels are reviewed annually as part of our performance review process as well as upon a promotion or other material change in job responsibility. Merit-based increases to the base salary of an executive officer are based on the Committee’s assessment of the individual’s performance.

In reviewing base salaries for our executive officers, including our named executive officers, the Committee primarily considers:


	•	internal review of the executive’s compensation, both individually and relative to other officers; and

	•	individual performance of the executive.

The Committee reviews these criteria collectively but does not assign a particular weight to each criterion when setting base salaries. Each base salary adjustment is made by the Committee subjectively based upon the foregoing.

During 2007, the base salaries of the following named executive officers were increased: Messrs. Neely from C$250,000 per annum to C$287,500 per annum, O’Donoghue from C$250,000 per annum to C$287,500 per annum, MacMahon from C$240,000 per annum to C$264,000 per annum and Anderson from C$265,000 per annum to C$300,000 per annum. In making its determinations, the Committee considered both the factors listed above and contemporaneous increases in the scope of duties and responsibilities of each executive. Mr. Anderson received his raise on February 7, 2007, coupled with his promotion to Vice President, Production and Chief Operating Officer following the departure of Mr. Cox, his predecessor. Each of Messrs. Neely and O’Donoghue received increases of 15% and Mr. MacMahon received an increase of 10% of base salary following the Committee’s recommendations.

Since many of our named executive officers recently entered into employment agreements establishing their base salaries, as of the date of this offering, the Committee has not approved any increases in the annual base salary of any of the named executive officers that remain in 2008. The Committee plans to conduct its annual review of base salaries in November 2008 for adjustments effective March 1, 2009.

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Annual Incentive Compensation

2007 Retention Bonuses. With respect to 2007, certain of our named executive officers received discretionary bonuses that were designed to enhance retention during our transition period, but the Committee did not establish any target or maximum award amounts. These retention bonuses were established for mid-year and end-of-year periods to provide incentive for our named executive officers to remain with us during our transitional period. Retention bonuses were paid to Messrs. Rodgers, Neely, O’Donoghue, Anderson and MacMahon. Mr. Baker was not employed by us on the dates retention bonuses were paid. Mr. Dillabough’s employment had just commenced at the end of 2007, and Messrs. Cox and Davis, who were under contract at the time of the mid-year retention bonus, were not granted retention bonuses. Mid-year amounts were paid on July 15, 2007 and end-of-year amounts were paid on January 15, 2008. We paid mid-year retention bonuses to our executive officers as follows: Messrs. Rodgers C$92,750, Neely C$75,000, O’Donoghue C$75,000, Anderson C$85,000, and MacMahon C$68,800. Messrs. Anderson and MacMahon also received year-end retention bonuses of C$75,000 and C$72,000 respectively.

2007-2008 Discretionary Bonuses. For 2007, Messrs. Anderson and MacMahon were employed at December 31, 2007 and both were paid a discretionary bonus following the recommendations of the Committee on January 15, 2008. These amounts were in addition to the retention bonuses referenced above. Mr. Anderson was paid C$75,000 and Mr. MacMahon was paid C$66,000 on that date. With respect to 2008, each of our current named executive officers may be entitled to a bonus at the discretion of the Committee based on each named executive officer’s performance. In assessing the individual performance of our named executive officers, the Committee, in its discretion, will consider the recommendations of our Chief Executive Officer (except in determining the Chief Executive Officer’s own bonus) and the following list of factors (which is not exclusive): achievement of internal financial and operating targets, including free cash flow; identification and acquisition of significant new key future growth opportunities; improvement of management and organizational capabilities; and implementation of long-term strategic plans.

Annual Incentive Plan (as of 2008). In addition to the discretionary bonuses noted above, for 2008, we have established an annual incentive plan in which our Chief Executive Officer, Chief Financial Officer and Executive Chairman will participate. Payments under the annual incentive plan will be determined based on performance against measurable annual financial goals. If the applicable performance goals are achieved, the payment of bonuses at target under our annual incentive plan, together with annual base salary and any discretionary bonuses, is designed to deliver annual cash compensation to these executive officers ranging from the 50th to 75th percentiles of the cash compensation of executive officers in the Comparison Group. The annual incentive plan is intended to focus the organization on meeting or exceeding an Adjusted EBITDA performance goal that is set at the beginning of each year and approved by the Committee and subsequently by the board of directors. The Committee uses Adjusted EBITDA as the performance goal because it is a critical metric used by management to direct and measure our business performance and create a proxy for value creation in the absence of equity instruments. We believe that Adjusted EBITDA measures are clearly understood by both our employees and stockholders, and that achievement of the stated goals is a key component in the creation of long-term value for our stockholders. For 2008, the Committee approved an Adjusted EBITDA target of $124.3 million, a 22% increase over the actual Adjusted EBITDA in 2007 of $103.4 million.

In light of the significant responsibilities associated with his position, the employment agreement for Mr. Dillabough contemplates a maximum bonus under the annual incentive plan equal to 100% of his base salary. As Mr. Davis’ offer letter provides for incentive compensation in the same amounts as the compensation paid to the Chief Executive Officer, Mr. Davis is also entitled to a maximum bonus under the annual incentive plan equal to 100% of his base salary. The employment agreement of our Chief Financial Officer, Mr. Withey, contemplates a maximum bonus under the annual incentive plan equal to 50% of his base salary.

The Committee retains the discretion to pay bonuses to our named executive officers and other employees that are in addition to, or in lieu of, the bonuses described in their employment agreements or in the annual bonus plan. These bonuses may be based on company or individual performance goals not reflected in our annual incentive plan or that are purely discretionary.

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Long-Term Incentive Compensation

Executive Bonus Plan (as of 2008). We established an Executive Bonus Plan effective as of December 31, 2007, to provide incentives to eligible employees and members of our board of directors, as determined by our board of directors, to align the interests of certain of our executive officers and directors with our net asset value appreciation interests. Amounts earned by these individuals are in addition to their base salary or director fees and annual incentive plan where applicable and are in recognition of their services rendered during the applicable plan year. The Executive Bonus Plan provides participants with a percentage of our net asset value appreciation with respect to a plan year, excluding net asset value gains based on equity raises or debt-to-equity conversions or other debt restructuring activities. The percentage of net asset value appreciation which is allocable to each eligible individual is evidenced by a written agreement between us and the eligible individual. Participants in the Executive Bonus Plan who are U.S. taxpayers participate in a sub-plan to the Executive Bonus Plan which was designed to comply with Section 409A of the Internal Revenue Code, or the Code. Following the adoption of a new omnibus stock option plan in 2009, the Executive Bonus Plan will terminate.

For the 2008 plan year, our Chief Executive Officer, Chief Financial Officer and Executive Chairman are eligible to participate in the Executive Bonus Plan. Our Executive Chairman Mr. Davis, as a U.S. taxpayer, participates in the U.S. sub-plan. Messrs. Dillabough and Davis are entitled to receive a benefit of 1% of our net asset value appreciation during 2008 and Mr. Withey is entitled to receive a benefit of 0.33% of our net asset value appreciation during the year. Our decision to allocate a greater portion of the net asset value appreciation to Messrs. Dillabough and Davis was based on the relative significance of their duties and responsibilities to us. In addition, each of our directors is entitled to a benefit of 0.20%, and an additional 0.30% benefit may be granted to our executive officers at the discretion of our board of directors. The net asset value appreciation is equal to the net asset value as of December 31 of the current plan year less the highest net asset value for any prior year. This benefit is paid in cash on a monthly basis over the 36 months following the plan year to which the benefit relates, provided the eligible individual remains in service with us. The percentage of net asset value appreciation allocated to an eligible individual for a plan year may be adjusted at certain times during the vesting period, positively or negatively, as determined by our board of directors. Except as otherwise provided below with respect to the U.S. sub-plan, in the event of a change in control or an initial public offering, vesting is accelerated without further adjustment to the allocation of the net asset value appreciation. In the event of a change in control, unpaid benefits are generally paid as soon as practicable following the change in control and, in the event of an initial public offering, the vested but unpaid benefits of participants who remain in service with us are converted to stock of the public company. Under the U.S. sub-plan, vesting is also accelerated upon a change in control and payments are made as soon as practicable thereafter, so long as the change in control is a permissible payment event under Section 409A of the Code. In the case of an initial public offering, vesting is not accelerated unless the participant voluntarily terminates service with us following the offering and the participant’s benefit is not automatically converted to stock. Instead, the Committee may, but need not, permit a U.S. participant to elect, upon the closing of this offering, to have his or her benefit (whether vested or unvested) deemed invested in securities of the public company; however, any such election will not affect the payment timing rules set forth in the U.S. sub-plan. Upon the closing of this offering, Messrs. Dillabough and Withey, who do not participate in the U.S. sub-plan of the Executive Bonus Plan, will experience an immediate vesting of their benefits that will automatically be converted to stock.

Equity-Based Compensation. Some of our named executive officers have previously participated in the Trident Exploration Corp. Stock Option Plan, or the Stock Option Plan, and the Trident Exploration Corp. Deferred Share Unit Plan, or the Deferred Share Unit Plan. We have made no grants under these plans to our named executive officers since 2006 and we do not intend to make any new grants under these plans in the future. For a description of any outstanding equity awards under these plans, see the table entitled “Outstanding Equity Awards at Fiscal Year-End” below. Following the closing of this offering, we intend to adopt a new omnibus stock plan which will provide for the grant of equity-based awards from time to time at the discretion of the Committee.

Retirement, Perquisites and Other Benefits

Retirement Benefits. As of July 1, 2008, our current named executive officers are eligible to participate in our Group Registered Retirement & Savings Plan, which is comprised of a Defined Contribution Pension Plan, a

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Registered Retirement Savings Plan and a Non-Registered Savings Plan. The Registered Retirement Savings Plan is a tax-qualified retirement savings plan pursuant to which all Canadian-based employees are able to contribute on a before-tax basis up to the limit prescribed by the Canada Revenue Agency. We match 100% of the first 4% of each employee’s pay that is contributed to the Registered Retirement Savings Plan. All contributions to the Registered Retirement Savings Plan as well as any matching contributions are fully-vested upon contribution. Once our executive officers and other employees have reached the legislative maximum contribution limits for the Registered Retirement Savings Plan, they may contribute an unlimited amount of after-tax dollars to the Non-Registered Savings Plan.

In addition, our employees, including our current named executive officers, are entitled to participate in our Defined Contribution Pension Plan. Pursuant to the Defined Contribution Pension Plan, we will contribute 4% of the employee’s base salary into a registered pension plan account. These funds vest upon the earlier of an employee’s retirement, death, or the second anniversary of the employee’s participation in the plan. The vested portions remain in a locked-in retirement account until the employee’s retirement date.

Perquisites and Other Benefits. We provide our executive officers with limited perquisites that we and the Committee believe are reasonable and consistent with our overall compensation program to better enable us to attract and retain superior employees for key positions. During 2007, our named executive officers were entitled to certain priority parking privileges and, as part of our health plan, could opt to divert up to C$750 in expenses otherwise covered by our medical and dental plan to prescribed “wellness” expenses. Prescribed wellness expenses include the cost of fitness memberships or fitness training provided by course or by licensed professionals. Our executive officers, like all of our employees, are also eligible for health benefits under our health plan. The Committee periodically reviews the levels of perquisites provided to our executive officers.

Attributed costs of the perquisites described above for each of the named executive officers for fiscal year 2007 are included in column (f) of the “Summary Compensation Table.”

Severance Payments

We generally enter into employment agreements, which provide for severance payments in certain circumstances for certain key employees, including our named executive officers. The employment agreements are designed to promote stability and continuity of senior management. Due to the management transition in 2007, however, not all of our named executive officers that served during the year were party to an employment agreement. Due to the interim nature of his appointment, we entered into a consulting services agreement with Mr. Bradshaw rather than an employment agreement. In addition, Mr. Davis serves pursuant to an executed offer letter, which does not provide for cash severance benefits. As further discussed in the narrative section following the Summary Compensation Table under the heading “—Employment Agreements,” Messrs. Rodgers, Neely and O’Donoghue were able to terminate their employment with us for any reason during July 2007 (in the case of Mr. Rodgers) and August 2007 (in the case of Messrs. Neely and O’Donoghue) and receive severance benefits. The decision to afford these executive officers the option to terminate their employment voluntarily and receive severance reflected our instability at the start of 2007 and our need to promptly fill vacancies at the executive level. In addition to Messrs. Rodgers, Neely and O’Donoghue, Messrs. Baker, Meli and Cox received severance payments from us in connection with their terminations of employment during 2007. Information regarding applicable payments for the named executive officers under their employment or other agreements, as applicable, is provided in the section titled “—Potential Payments upon Termination or Change of Control” below. Severance payment amounts (including how such amounts were determined) are included in column (f) of the “Summary Compensation Table” and the footnotes contained therein.

Tax and Accounting Implications

Accounting for Stock-Based Compensation. In accordance with FASB Statement 123(R), we account for stock-based payments under the Stock Option Plan by estimating the fair value of the stock option on the date of grant using a Black-Scholes option pricing model and charging the fair value in a systematic manner over the vesting period. Assumptions have been made in the calculation of the fair value including expected volatility based on historical market volatility, expected forfeitures based on historical forfeitures and a risk free rate based on the zero-coupon yield curve for Bank of Canada bonds with a term equivalent to the expected term. Attributed costs of

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the amounts charged under this treatment for stock-based compensation for the 2007 period are included in column (e) of the “Summary Compensation Table.”

As noted above, our Executive Bonus Plan includes a sub-plan for our U.S. taxpayers which was designed to comply with Section 409A of the Code.

Summary Compensation Table(1)


									Option		All Other
			Salary			Bonus			Awards(20)		Compensation			Total
Name and Principal Position	Year		(US$)			(US$)			(US$)		(US$)			(US$)
(a)	(b)		(c)			(d)			(e)		(f)			(g)



Todd A. Dillabough, Chief Executive Officer(2)		2007		35,308			—			—		—			35,308

Eugene I. Davis, Executive Chairman(3)		2007		191,600	(13)		—			—		—			191,600

David L. Bradshaw, Interim Chief Executive Officer(4)		2007		144,213			—			—		—			144,213

W. Murray Rodgers, Chief Executive Officer(5)		2007		218,393			86,295	(15)		153,290		1,169,017	(21)		1,626,995

Jonathan Baker, Chief Executive Officer(6)		2007		84,233	(14)		—			—		1,233,017	(22)		1,317,250

Randy Neely, Chief Financial Officer(7)		2007		160,942			69,780	(16)		176,894		898,191	(23)		1,305,807

Rich Meli, Chief Financial Officer(8)		2007		26,500			—			—		1,076,212	(24)		1,102,712

Paul O’Donoghue, Vice President, Corporate and Strategic Development(9)		2007		160,942			69,780	(17)		82,242		901,143	(25)		1,214,107

David Cox, Vice President, Operations and Chief Operating Officer(10)		2007		194,000			—			87,104		794,536	(26)		1,075,640

John Anderson, Vice President, Production and Chief Operating Officer(11)		2007		276,408			218,645	(18)		96,599		5,163	(27)		596,815

Gordon MacMahon, Vice President, Exploration(12)		2007		234,462			192,408	(19)		52,103		696	(28)		479,669


(1)		Compensation paid to Messrs. Dillabough, Bradshaw, Rodgers, Neely, O’Donoghue, Anderson and MacMahon was paid in Canadian dollars. Conversions to U.S. dollars have been calculated at the average annual rate for the year of C$1.0748 for each U.S. dollar.

(2)		Mr. Dillabough has served as our Chief Executive Officer since November 28, 2007.

(3)		To assist Mr. Bradshaw, and also facilitate the integration of senior management going forward, in August 2007, our board appointed Mr. Eugene Davis as our Executive Chairman.

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(4)		Mr. Bradshaw served as our Interim Chief Executive Officer from August 22, 2007 through November 15, 2007.

(5)		Mr. Rodgers served as our Chief Executive Officer from January 31, 2007 through July 31, 2007.

(6)		Mr. Baker served as our Chief Executive Officer until January 31, 2007.

(7)		Mr. Neely served as our Chief Financial Officer from January 31, 2007 through August 21, 2007. Effective January 1, 2008, Mr. Withey serves as our Chief Financial Officer.

(8)		Mr. Meli served as our Chief Financial Officer through January 31, 2007.

(9)		Mr. O’Donoghue served as our Vice President, Corporate and Strategic Development from January 29, 2007 through August 21, 2007.

(10)		Mr. Cox served as our Vice President, Operations and Chief Operating Officer through August 21, 2007.

(11)		Mr. Anderson served as Vice President, Production and Chief Operating Officer of our Canadian subsidiary until March 11, 2008.

(12)		Mr. MacMahon served as Vice President, Exploration of our Canadian subsidiary until March 11, 2008.

(13)		This amount includes US$100,000 of fees earned in the capacity of executive and US$91,600 earned or paid in cash related to Mr. Davis’ service as a director.

(14)		This amount represents US$29,645 in base salary and US$56,650 in fees earned or paid in cash related to Mr. Baker’s service as a director in 2007.

(15)		This amount represents a retention bonus paid on July 15, 2007 in the amount of C$92,750.

(16)		This amount represents a retention bonus paid on July 15, 2007 in the amount of C$75,000.

(17)		This amount represents a retention bonus paid on July 15, 2007 in the amount of C$75,000.

(18)		This amount represents a mid-year retention bonus in the amount of C$85,000 (US$79,084) paid on July 15, 2007, a year-end retention bonus in the amount of C$75,000 (US$69,781) paid on January 15, 2008 and a discretionary bonus in the amount of C$75,000 (US$69,781) also paid on January 15, 2008.

(19)		This amount represents a mid-year retention bonus in the amount of C$68,800 (US$64,012) paid on July 15, 2007, a year-end retention bonus in the amount of C$72,000 (US$66,989) paid on January 15, 2008 and a discretionary bonus in the amount of C$66,000 (US$61,407) also paid on January 15, 2008.

(20)		The amounts in this column reflect the dollar amount of compensation cost recognized for financial statement reporting purposes for the fiscal year ending December 31, 2007 in accordance with Statement of Financial Accounting Standard 123R, or SFAS 123R with respect to stock options granted under the Stock Option Plan, which is described in further detail below.

(21)		This amount represents severance paid in connection with Mr. Rodgers’ termination of employment. Under his employment agreement, Mr. Rodgers was entitled to two times his total cash compensation, which consisted of (i) his annual base salary (C$371,000 or US$345,180), (ii) all incentive bonuses paid to Mr. Rodgers (excluding retention bonus) with respect to 2006 (C$200,000 or US$186,081), and (iii) the cash value of premiums paid by us on Mr. Rodgers’ behalf for all medical, dental, life, and other insurance plans with respect to 2006 ($0). Mr. Rodgers’ total cash compensation was C$571,000 or US$531,262 and thus two times his total cash compensation was C$1,142,000 or US$1,062,523. The difference of US$106,494 is the product of negotiations.

(22)		This amount represents severance paid in connection with Mr. Baker’s termination of employment. Under his employment agreement, Mr. Baker was entitled to two times his total cash compensation, which consisted of (i) his annual base salary (US$400,000), (ii) all incentive bonuses paid to Mr. Baker with respect to 2006 (US$225,000), and (iii) the cash value of premiums paid by us on Mr. Baker’s behalf for all medical, dental, life, and other insurance plans with respect to 2006 (US$16,508). Mr. Bakers’ total cash compensation was US$641,508 and thus two times his total cash compensation was US$1,283,017. The difference of US$50,000 is the product of negotiations.

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(23)		This amount represents severance paid in connection with Mr. Neely’s termination of employment. Under his employment agreement, Mr. Neely was entitled to two times his total cash compensation, which consisted of (i) his annual base salary (C$287,500 or US$267,492), (ii) all incentive bonuses paid to Mr. Neely (excluding retention bonus) with respect to 2006 (C$175,000 or US$162,821), and (iii) the cash value of premiums paid by us on Mr. Neely’s behalf for all medical, dental, life, and other insurance plans with respect to 2006 ($0). Mr. Neely’s total cash compensation was C$462,500 or US$403,313 and thus two times his total cash compensation was C$925,000 or US$860,625. The difference of US$37,566 is the product of negotiations.

(24)		This amount represents severance paid in connection with Mr. Meli’s termination of employment. Mr. Meli was entitled to two times his total cash compensation, which consisted of (i) his annual base salary (US$318,000), (ii) all incentive bonuses paid to Mr. Meli with respect to 2006 (US$200,000), and (iii) the cash value of premiums paid by us on Mr. Meli’s behalf for all medical, dental, life, and other insurance plans with respect to 2006 ($0). Mr. Meli’s total cash compensation was US$518,000 and thus two times his total cash compensation was US$1,036,000. The difference of US$40,212 is the product of negotiations.

(25)		This amount represents severance paid in connection with Mr. O’Donoghue’s termination of employment. Mr. O’Donoghue was entitled to two times his total cash compensation, which consisted of (i) his annual base salary (C$287,500 or US$267,492), (ii) all incentive bonuses paid to Mr. O’Donoghue (excluding retention bonus) with respect to 2006 (C$175,000 or US$162,821), and (iii) the cash value of premiums paid by us on Mr. O’Donoghue’s behalf for all medical, dental, life, and other insurance plans with respect to 2006 ($0). Mr. O’Donoghue’s total cash compensation was C$462,500 or US$403,313 and thus two times his total cash compensation was C$925,000 or US$860,625. The difference of US$40,518 is the product of negotiations.

(26)		This amount represents severance paid in connection with Mr. Cox’s termination of employment. Mr. Cox was entitled to two times his total cash compensation, which consisted of (i) his annual base salary (US$291,000), (ii) all incentive bonuses paid to Mr. Cox with respect to 2006 (US$150,000), and (iii) the cash value of premiums paid by us on Mr. Cox’s behalf for all medical, dental, life, and other insurance plans with respect to 2006 ($0). Mr. Cox’s total cash compensation was US$441,000 and thus two times his total cash compensation was US$882,000. The difference of US$87,464 is the product of negotiations.

(27)		This amount represents a parking allowance that was the product of negotiation when Mr. Anderson was hired.

(28)		This amount represents a wellness reimbursement.

Trident Exploration Corp. Stock Option Plan

We adopted the Stock Option Plan effective as of August 1, 2002. Under the terms of the plan, options may be granted to any director, officer, employee or consultant of TEC, any subsidiary of TEC or certain entities wholly owned by any director, officer, employee or consultant of TEC (or certain family members of those individuals). TEC’s board of directors determines the number of shares subject to each option, the exercise price, expiration date, and other terms and conditions relevant to the option. Unless otherwise determined by the board, the exercise period for an option is ten years. The total number of shares to be granted to any participant under the plan cannot exceed ten percent of the issued and outstanding class A common voting shares of TEC (on a non-diluted basis) on the date the option is granted. Generally, options are non-transferable and non-assignable.

Options will expire and terminate immediately upon a participant’s termination for cause. If, before the expiration of an option in accordance with its terms, the employment or engagement of the participant by TEC or any subsidiary terminates for any reason other than termination for cause, the option may be exercised by the participant.

In the case of certain corporate transactions or changes in our capital stock, we will equitably adjust the outstanding options. If a take-over bid is made for our shares, all options will immediately vest and become exercisable by the participant, and the participant will have the right to exercise the option to purchase all of the shares granted that have not previously been purchased under the option. If certain tag-along offers are made and our stockholders are obligated to sell their shares to the offeror, then all options will immediately vest and become exercisable by the participant.

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The board may amend, suspend or discontinue the plan at any time. However, no amendment may change the manner of determining the exercise price or alter or impair any option previously granted.

Grants of Plan-Based Awards

We did not grant any plan-based equity or non-equity awards to our named executive officers during fiscal year 2007.

Employment Agreements

We generally enter into employment agreements with our executive officers which set forth the terms of their employment. As a result of the management transition in 2007, however, not all of our named executive officers that served during the year were party to an employment agreement. Due to the interim nature of his appointment, we entered into a consulting services agreement with Mr. Bradshaw rather than an employment agreement. In addition, Mr. Davis serves pursuant to an executed offer letter, which sets forth his base salary and other benefits during the term of his employment.

In general, the employment agreements that we have entered into with our named executive officers provide for severance payments in exchange for confidentiality and24-month non-solicitation covenants in our favor, and their execution of a general release of claims against us. In addition to their individual employment arrangements, each of our named executive officers is also a party to an indemnification agreement. The indemnification agreement generally provides for protection of the indemnitee (the named executive officer) from certain legal actions brought by third parties or by or in our right. The indemnitee is entitled to payment of expenses, including attorneys’ fees. The indemnitee is not protected, however, for claims that he initiates, lack of good faith, insured claims, or certain U.S. securities law violations.

Todd A. Dillabough

We entered into an employment agreement with Mr. Dillabough effective as of November 28, 2007, pursuant to which Mr. Dillabough serves as our President and Chief Executive Officer. The employment agreement provides for an indefinite term, subject to termination by us or by Mr. Dillabough in accordance with its terms. Mr. Dillabough receives an annual base salary of C$400,000 and is eligible for an annual bonus of up to 100% of his annual base salary. Mr. Dillabough’s employment agreement also entitles him to participate in the Executive Bonus Plan and any equity-based incentive compensation plans that we establish.

Eugene I. Davis

Pursuant to a letter agreement dated August 22, 2007, Mr. Davis serves as our Executive Chairman. The letter agreement provides for a one-year term, effective as of the closing of the TRC 2007 subordinated credit agreement dated as of August 20, 2007, after which time Mr. Davis will continue as our Executive Chairman but we may terminate his services by providing a 60 day advance written notice, solely upon the written request of a majority in interest of certain lenders with respect to the TRC 2007 subordinated credit agreement. Mr. Davis may terminate his service with us by providing us with ten days’ written notice. However, either we or Mr. Davis may waive our entitlement to notice.

As compensation for his services, Mr. Davis receives US$25,000 per month, director meeting fees, and benefits and perquisites comparable to those provided to our most senior executive officers. Mr. Davis is also eligible for equity and non-equity incentive compensation in the same amounts and under the same terms and conditions as we provide to our Chief Executive Officer.

David L. Bradshaw

We entered into a consulting services agreement with Mr. Bradshaw as of July 26, 2007, pursuant to which Mr. Bradshaw served as our Interim Chief Executive Officer. The agreement provided for a term commencing on August 1, 2007 and ending on October 31, 2007, which was extended to November 15, 2007 pursuant to an amendment dated October 31, 2007, unless terminated earlier by either party. As compensation for his services,

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Mr. Bradshaw received US$30,000 per calendar month plus US$15,000 for a partial month of service in November and a one-time payment of US$50,000 upon signing the agreement. Mr. Bradshaw’s employment with us terminated upon the expiration of the term, as amended, on November 15, 2007. Mr. Bradshaw’s consulting services agreement contained a perpetual confidentiality covenant.

W. Murray Rodgers

We entered into an employment agreement with Mr. Rodgers effective as of January 31, 2007, pursuant to which Mr. Rodgers served as our Chief Executive Officer. The agreement provided for an indefinite term unless terminated earlier by either party. Mr. Rodgers terminated his employment with us by notice dated July 20, 2007 by reason of Constructive Dismissal (as discussed below). As compensation for his services, Mr. Rodgers was entitled to an annual base salary of C$371,000, a retention bonus of C$92,750 upon execution of the agreement and indemnification for legal costs associated with negotiating the agreement up to a maximum of C$20,000. Mr. Rodgers was also eligible to receive bonuses at our sole discretion and to be considered for grants under the Stock Option Plan and Deferred Share Unit Plan.

Mr. Rodgers sent us notice on July 20, 2007, stating his desire to terminate his employment by reason of Constructive Dismissal and Mr. Rodgers ceased being our Chief Executive Officer on July 31, 2007. Mr. Rodgers’ employment agreement contained a definition of “Constructive Dismissal” that allowed him to sever his employment with us for any reason during the month of July 2007 and receive severance payments. Mr. Rodgers was entitled to receive a lump sum severance payment equal to two times his total cash compensation, which consisted of (i) his annual base salary, (ii) all incentive bonuses paid or payable in respect of 2006 (but not the retention bonus), and (iii) the cash value of premiums paid by us on Mr. Rodgers’ behalf for all medical, dental, life, and other insurance plans, that Mr. Rodgers received in 2006.

Jonathan Baker

We entered into an employment agreement with Mr. Baker effective as of January 1, 2005, pursuant to which Mr. Baker served as our President and Chief Executive Officer. Mr. Baker’s employment was at will. The agreement provided that we pay Mr. Baker an annual salary of not less than US$375,000. Mr. Baker was also eligible to receive bonuses at our discretion.

We terminated Mr. Baker’s employment without Cause (as defined below) effective as of January 31, 2007. Mr. Baker was entitled to receive a lump sum severance payment equal to two times his total cash compensation, which consisted of (i) his annual base salary, (ii) all incentive bonuses paid or payable in respect of 2006, and (iii) the cash value of premiums paid by us on Mr. Baker’s behalf for all medical, dental, life, and other insurance plans, that Mr. Baker received in 2006.

For purposes of Mr. Baker’s employment agreement, “Cause” meant Mr. Baker’s (i) conviction for a criminal offense involving fraud or dishonesty against us, (ii) intentional making by Mr. Baker or any member of his family of any material personal profit at our expense without our prior written consent, (iii) willful breach of a material provision of his employment agreement, (iv) serious misconduct incompatible with his duties or prejudicial to our business and goodwill generally or (v) inability to perform his duties pursuant to his employment agreement by reason of a matter solely within his control or by reason of any statute, law, ordinance, regulation, order, judgment or decree that through an act or omission or commission by Mr. Baker rendered him unable to perform his duties pursuant to his employment agreement.

Randy Neely

We entered into an employment agreement with Mr. Neely effective as of January 31, 2007, pursuant to which Mr. Neely served as our Vice President Finance and Chief Financial Officer. The agreement provided for an indefinite term unless terminated earlier by either party. The agreement provided that we pay Mr. Neely an annual salary of no less than C$275,000, a retention bonus of C$75,000 upon execution of the agreement and indemnification for legal costs associated with negotiating the agreement up to a maximum of C$20,000. In addition, Mr. Neely was eligible for discretionary bonuses and grants under the Stock Option Plan and Deferred Share Unit Plan. Mr. Neely terminated his employment with us for “Constructive Dismissal” effective August 21, 2007. Like

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Mr. Rodgers’ agreement, Mr. Neely’s agreement contained a “Constructive Dismissal” definition that allowed him to terminate his employment with us for any reason during August 2007 and receive severance benefits. Mr. Neely was entitled to receive a lump sum severance payment equal to two times his total cash compensation, which consisted of (i) his annual base salary, (ii) all incentive bonuses paid or payable in respect of 2006 (but not the retention bonus), and (iii) the cash value of premiums paid by us on Mr. Neely’s behalf for all medical, dental, life, and other insurance plans, that Mr. Neely received in 2006.

Richard Meli

We entered into an employment agreement with Mr. Meli effective as of January 1, 2005, pursuant to which Mr. Meli served as our Executive Vice President and Chief Financial Officer. The agreement provided for Mr. Meli’s employment at will. Under the agreement, Mr. Meli received an annual base salary of not less than US$300,000. In addition, Mr. Meli was eligible to receive discretionary bonuses. On January 31, 2007, we sent notice to Mr. Meli of our desire to terminate his employment effective immediately without “Cause” (as defined in Mr. Meli’s employment agreement, which definition is the same as in Mr. Baker’s agreement). Mr. Meli was entitled to receive a lump sum severance payment equal to two times his total cash compensation, which consisted of (i) his annual base salary, (ii) all incentive bonuses paid or payable in respect of 2006, and (iii) the cash value of premiums paid by us on Mr. Meli’s behalf for all medical, dental, life, and other insurance plans, that Mr. Meli received in 2006.

Paul O’Donoghue

We entered into an employment agreement with Mr. O’Donoghue effective as of January 31, 2007, pursuant to which he served as our Vice President Corporate and Strategic Development and Corporate Secretary. The agreement provided for an indefinite term unless terminated earlier by either party. The agreement provided for an annual base salary of not less than C$275,000, a retention bonus of C$75,000 upon execution of the agreement and indemnification for legal costs associated with negotiating the agreement up to a maximum of C$20,000. Mr. O’Donoghue was also eligible for discretionary bonuses and grants under the Stock Option Plan and Deferred Share Unit Plan. Mr. O’Donoghue terminated his employment with us for “Constructive Dismissal” effective August 21, 2007. Like Mr. Rodgers’ agreement, Mr. O’Donoghue’s agreement contained a “Constructive Dismissal” definition that allowed him to terminate his employment with us for any reason during August 2007 and receive severance benefits. Mr. O’Donoghue was entitled to receive a lump sum severance payment equal to two times his total cash compensation, which consisted of (i) his annual base salary, (ii) all incentive bonuses paid or payable in respect of 2006 (but not the retention bonus), and (iii) the cash value of premiums paid by us on Mr. O’Donoghue’s behalf for all medical, dental, life, and other insurance plans, that Mr. O’Donoghue received in 2006.

David Cox

We entered into an employment agreement with Mr. Cox effective as of January 1, 2005, pursuant to which he served as our Vice President, Engineering. The agreement provided for at will employment. The employment agreement provided for an annual salary of not less than US$275,000 and discretionary bonuses. We terminated Mr. Cox’s employment without “Cause” (as defined in Mr. Cox’s employment agreement, which definition is the same as in Mr. Baker’s employment agreement) effective as of August 21, 2007. Mr. Cox was entitled to receive a lump sum severance payment equal to two times his total cash compensation, which consisted of (i) his annual base salary, (ii) all incentive bonuses paid or payable in respect of 2006, and (iii) the cash value of premiums paid by us on Mr. Cox’s behalf for all medical, dental, life, and other insurance plans, that Mr. Cox received in 2006.

John Anderson

We entered into an employment agreement with Mr. Anderson effective as of February 1, 2007, pursuant to which Mr. Anderson served as our Vice President, Production and Chief Operating Officer of TEC. The employment agreement provided for an indefinite term, subject to termination by us or by Mr. Anderson in accordance with its terms. Mr. Anderson received an annual base salary of not less than C$300,000 and was eligible

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for an annual bonus of up to 100% of his annual base salary and was eligible to participate in our Stock Option Plan and Deferred Share Unit Plan.

Mr. Anderson’s employment terminated on March 11, 2008.

Gordon MacMahon

We entered into an employment agreement with Mr. MacMahon effective as of January 18, 2006, pursuant to which Mr. MacMahon served as our Vice President, Exploration of TEC. The employment agreement provided for an indefinite term, subject to termination by us or by Mr. MacMahon in accordance with its terms. Mr. MacMahon received an annual base salary of not less than C$200,000 and was eligible for an annual bonus of up to 100% of his annual base salary. Mr. MacMahon’s employment agreement also entitled him to participate in our Stock Option Plan and our Deferred Share Unit Plan.

Mr. MacMahon’s employment terminated on March 11, 2008.

Alan G. Withey

We entered into an employment agreement with Mr. Withey on December 14, 2007, pursuant to which Mr. Withey began serving as our Chief Financial Officer as of January 1, 2008. The employment agreement provides for an indefinite term, subject to termination by us or Mr. Withey in accordance with its terms. Mr. Withey receives an annual base salary of C$300,000 and is eligible for an annual discretionary bonus of up to 50% of his annual base salary.

Mr. Withey’s employment agreement entitles him to participate in any equity-based incentive compensation plans that we establish. As of December 14, 2007, Mr. Withey is entitled to participate in the Executive Bonus Plan and is entitled to receive a percentage allocation of not less than 0.33% of our net asset value appreciation during the applicable fiscal year.

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Outstanding Equity Awards at 2007 Fiscal Year-End

The following table presents information regarding the outstanding option awards held by each named executive officer at the end of fiscal year 2007. None of our named executive officers held stock awards at the end of fiscal year 2007.


	Option Awards(1)
	Number of
	Securities
	Underlying
	Unexercised		Option
	Options(#)		Exercise Price		Option
Name	Exercisable		(US$)		Expiration Date

Todd A. Dillabough		—		—		—
Eugene I. Davis		—		—		—
David L. Bradshaw		—		—		—
		139,751	$	4.20		October 29, 2009
		20,664	$	13.00		October 29, 2009
		20,100	$	14.00		October 29, 2009
		12,500	$	50.00		October 29, 2009
W. Murray Rodgers		2,562	$	53.00		October 29, 2009
Jonathon Baker		—		—		—
		91,627	$	14.00		November 19, 2009
Randy Neely		1,736	$	50.00		November 19, 2009
Richard Meli		—		—		—
		40,000	$	4.20		November 19, 2009
		90,000	$	5.30		November 19, 2009
		20,664	$	13.00		November 19, 2009
Paul O’Donoghue		20,100	$	14.00		November 19, 2009
		28,610	$	4.20		November 19, 2009
		90,000	$	8.40		November 19, 2009
		20,665	$	13.00		November 19, 2009
		20,100	$	14.00		November 19, 2009
David Cox		2,848	$	53.00		November 19, 2009
		30,000	$	16.50		June 8, 2010
John Anderson		10,000	$	50.00		June 8, 2010
Gordon MacMahon		37,500	$	50.00		June 8, 2010


(1)		All of the options reported in this table were granted under our Stock Option Plan.

Option Exercises and Stock Vested in Fiscal Year 2007

None of our named executive officers exercised any options, and no stock vested, in fiscal year 2007.

Potential Payments Upon Termination or Change of Control

Our employment of Messrs. Rodgers, Baker, Neely, Meli, O’Donoghue and Cox terminated during 2007. The formulas for determining their severance amounts are set forth in the descriptions of their employment agreements above and the actual severance paid is included in column (f) of the Summary Compensation Table. Our employment of Messrs. Anderson and MacMahon terminated in March 2008. They are nonetheless included in the table below, assuming that a termination of employment occurred on December 31, 2007. The actual severance paid to these executive officers is included in the descriptions of their employment agreements and in footnotes to the table below. The consulting services agreement and the offer letter we entered into with Messrs. Bradshaw and Davis, respectively, do not provide for severance payments or benefits.

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Assuming an applicable named executive officer’s employment terminated on December 31, 2007 under each of the circumstances listed in the table below, such payments and benefits have an estimated value of:


	Total Cash			Value of Continued
	Severance			Health Benefits		Total
Event	(US$)			(US$)		(US$)

Todd A. Dillabough
Death		—			4,287		4,287
Permanent Disability(1)		186,081			2,144		188,225
Without Just Cause		744,325	(2)		8,575		752,900
For Good Reason		744,325	(2)		4,287		748,612
John Anderson(3)
Without Cause or for Good Reason		844,246			—		844,246
Gordon MacMahon(4)
Without Cause or for Good Reason		736,785			—		736,785


(1)		If Mr. Dillabough’s employment is terminated due to his Permanent Disability, he becomes entitled to continued annual base salary and health benefits until the later of (i) six months from his termination date or (ii) the date he becomes entitled to long-term disability benefits. For the purposes of this calculation we have assumed six months of continued annual base salary and health benefits.

(2)		If Mr. Dillabough’s employment is terminated without Just Cause or for Good Reason, he becomes entitled to a lump sum severance payment equal to two times the sum of Mr. Dillabough’s annual base salary in effect on the termination date plus continued health benefits for Mr. Dillabough and his family for two years (if terminated without Just Cause) or one year (if he terminated his employment for Good Reason).

(3)		If Mr. Anderson’s employment is terminated without Cause or for Good Reason, he becomes entitled to a lump sum severance payment equal to two times the sum of Mr. Anderson’s base salary in effect on the termination date and incentive bonuses paid during our last completed fiscal year (but only if Mr. Baker is not President or Chief Executive Officer of TEC or TRC), plus the cash value of premiums paid on behalf of Mr. Anderson for all medical, dental, life, and other insurance coverage during our last completed fiscal year. Mr. Anderson’s employment terminated on March 11, 2008 and he received severance of C$907,396 or US$844,246.

(4)		If Mr. MacMahon’s employment is terminated without Cause or for Good Reason, he becomes entitled to a lump sum severance payment equal to two times the sum of Mr. MacMahon’s base salary in effect on the termination date and incentive bonuses paid during our last completed fiscal year (but only if Mr. Baker is not President or Chief Executive Officer of TEC or TRC), plus the cash value of premiums paid on behalf of Mr. MacMahon for all medical, dental, life, and other insurance coverage during our last completed fiscal year. Mr. MacMahon’s employment terminated on March 11, 2008 and he received severance of C$791,896 or US$736,785.

Todd A. Dillabough

Pursuant to the terms of his employment agreement, if Mr. Dillabough’s employment is terminated due to his death, Mr. Dillabough’s spouse and dependents will be entitled to a pro-rated portion of his annual bonus and continuation of health benefits for a period of one year. If Mr. Dillabough’s employment is terminated on account of “Permanent Disability” (as defined below), he will be entitled to receive a pro-rated portion of his annual bonus, and continued annual base salary and health benefits until the later of (i) six months from his termination date and (ii) the date that he becomes entitled to long-term disability benefits under our long-term disability plan. If Mr. Dillabough’s employment is terminated by us without “Just Cause” (as defined below), he will become entitled to receive a pro-rated portion of his annual bonus and a lump sum payment equal to two times his annual base salary and Mr. Dillabough, his spouse and dependents will be entitled to continued health benefits for a period of two years following his termination. If Mr. Dillabough terminates his employment for “Good Reason” (as defined below), he will be entitled to receive a pro-rated portion of his annual bonus and a lump sum payment equal to two times his

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annual base salary and Mr. Dillabough, his spouse and dependents will be entitled to continued health benefits for a period of one year following his termination.

For purposes of Mr. Dillabough’s employment agreement, “Permanent Disability” means a mental or physical disability whereby Mr. Dillabough is unable to perform his duties for a cumulative period of four months out of six consecutive calendar months or that Mr. Dillabough is declared by a court to be mentally incompetent or incapable of managing his affairs.

For purposes of Mr. Dillabough’s employment agreement, “Just Cause” means as defined under common law, including Mr. Dillabough’s conviction of, plea of guilty ornolo contendereto, an indictable criminal offense (Canada) or a felony (U.S.), or willful misconduct that is materially economically injurious or damaging to us or our affiliates.

For purposes of Mr. Dillabough’s employment agreement, “Good Reason” means Mr. Dillabough’s failure to be appointed our Chief Executive Officer or our hiring of any officer to serve in a capacity equal to or senior to the position of Chief Executive Officer, other than in the office of Executive Chairman; the assignment by us to Mr. Dillabough of duties that are materially inconsistent with the duties of Chief Executive Officer or a material adverse alteration in the nature of Mr. Dillabough’s duties and responsibilities, reporting obligations, titles or authority; a material reduction by us in Mr. Dillabough’s annual base salary, bonus, aggregate benefits or other perquisites to which Mr. Dillabough is entitled under his employment agreement; the occurrence of a “Change of Control” (as defined below); or a material breach of his employment agreement, if not cured within 30 days after Mr. Dillabough provides us notice.

For purposes of Mr. Dillabough’s employment agreement, a “Change of Control” occurs when (i) any person or group of persons acting jointly, other than our existing shareholders beneficially holds, directly or indirectly, a majority of the voting interests of TRC or obtains the power to elect a majority of the board of directors of TRC; (ii) TEC ceases to be a subsidiary of TRC; (iii) any person or group of persons acting jointly, other than our existing shareholders acquires more than a 50% effective ownership of TEC; or (iv) TEC sells all or substantially all of the assets of TEC, other than to a wholly-owned subsidiary of TRC or TEC, or to a partnership in which either of the foregoing is a partner.

The severance payments and benefits are conditioned upon Mr. Dillabough’s execution and delivery of a release of claims, a form of which is attached as a schedule to his employment agreement.

In addition to the severance payments, in the case of the 1% allocation award granted to Mr. Dillabough under the Executive Bonus Plan for the 2008 plan year, such allocation award (i) will be pro-rated to reflect the actual period between commencement of the plan year and the date of termination, (ii) will immediately vest (to the extent not vested), and (iii) will be payable as soon as practicable following Mr. Dillabough’s involuntary termination, retirement or death, or upon a change of control of TEC. In addition, immediate vesting will occur upon a voluntary termination of service following a Liquidity Transaction (defined as an initial public offering of our common equity or a sale of TECand/or TRC). In the case of a voluntary termination, Mr. Dillabough will not receive any allocation award for the plan year in which the termination of employment occurs. Upon a termination for cause, the current year’s allocation award will be pro-rated to reflect the actual period between commencement of the plan year and the date of termination. No value is included in the table above with respect to the vesting and payment of this award since it had not been granted as of December 31, 2007.

Upon the closing of this offering, Mr. Dillabough will be required to execute alock-up agreement and rollover his vested allocation award into our common equity. However, Mr. Dillabough will not be required to do so if he is no longer employed by us in the same or similar position immediately prior to this offering.

Eugene I. Davis

Mr. Davis serves pursuant to an executed offer letter which does not provide for cash severance benefits. Accordingly, if we terminate Mr. Davis’ employment without cause or for any other reason, Mr. Davis will receive his accrued salary, unreimbursed expenses and other entitlements to the date of termination, unless we decide at that time to provide additional severance compensation or benefits.

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Mr. Davis participates in certain compensation arrangements that provide for benefits in the case of certain termination events. If Mr. Davis’ service is terminated by us, any non-vested equity grants made by us to Mr. Davis will vest immediately, unless Mr. Davis has (i) breached his fiduciary duties or obligations to us or (ii) otherwise failed to perform his services under the offer letter or to conduct himself in accordance with applicable law.

In addition to the severance payments, in the case of the 1% allocation award granted to Mr. Davis under the sub-plan of the Executive Bonus Plan for the 2008 plan year, such allocation award will vest (to the extent not vested) and will be paid upon Mr. Davis’ involuntary termination of service, retirement, termination for cause, death, a change in control, or voluntary termination of service following a Liquidity Transaction. No value is included in the table above with respect to the vesting and payment of this award since it had not been granted as of December 31, 2007.

Upon the closing of this offering, we may allow Mr. Davis to elect to have his vested but unpaid allocation award deemed invested in our common equity.

John Anderson

Pursuant to the terms of his employment agreement, if Mr. Anderson’s employment had been terminated (i) by us without “Cause” (as defined in Mr. Anderson’s employment agreement, which definition was the same as is in Mr. Baker’s employment agreement. See Employment Agreements — Jonathan Baker) or (ii) by Mr. Anderson for “Good Reason” (as defined below) within theninety-day period following the occurrence of a “Change of Control” (as defined below), he would have become entitled to receive a lump sum severance payment equal to two times his total cash compensation, which would have consisted of (i) his annual base salary, (ii) all incentive bonuses paid or payable to Mr. Anderson in respect of our last completed fiscal year (but only if Mr. Baker was not President or Chief Executive Officer of TEC or TRC), and (iii) the cash value of premiums paid on Mr. Anderson’s behalf for medical, dental, life, and other insurance coverage during our last completed fiscal year immediately preceding termination.

For purposes of Mr. Anderson’s employment agreement, “Good Reason” meant (i) any action that would have constituted termination at law including any actions or combination of actions that would have resulted in a material reduction of seniority, duties, authorities, responsibility or remuneration of Mr. Anderson (a “constructive dismissal”), (ii) TEC’s failure to have obtained a satisfactory agreement from a successor to assume and agree to perform Mr. Anderson’s employment agreement or if the business or undertaking in connection with which Mr. Anderson’s services were principally performed were sold at any time after a Change of Control and Mr. Anderson’s employment had been transferred as a result, the purchaser of such business failed to agree to provide Mr. Anderson with the same or a comparable position, authority, responsibility, duties, compensation and benefits as provided under his employment agreement immediately prior to the Change of Control, or (iii) if during the period commencing ninety days from the event that would have constituted a Change of Control up until the six-month anniversary of that event, Mr. Anderson had delivered us notice of his intent to terminate his employment.

For purposes of Mr. Anderson’s employment agreement, a “Change of Control” would have occurred when (i) any person or persons acting jointly or in concert (a) beneficially held, directly or indirectly, a majority of the voting interests of TRC or (b) obtained the power (whether or not exercised) to elect a majority of the board of directors of TRC; provided that the McNeil Group and Aurora Energy Partners, LP would have been deemed to not be acting jointly or in concert; (ii) TEC ceased to be a subsidiary of TRC; (iii) any person or persons acting jointly or in concert beneficially acquired more than a 50% effective ownership of the economic or voting interests of TEC; or (iv) TEC sold all or substantially all of the assets of TEC other than to a wholly-owned subsidiary of TEC or to a partnership in which TEC is a partner.

The severance payments and benefits were conditioned upon Mr. Anderson’s execution and delivery of a release of claims, which was executed on March 13, 2008.

Gordon MacMahon

Pursuant to the terms of his employment agreement, if Mr. MacMahon’s employment had been terminated (i) by us without “Cause” (as defined in Mr. MacMahon’s employment agreement, which definition was the same as is in

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Mr. Baker’s employment agreement. See Employment Agreements — Jonathan Baker) or (ii) by Mr. MacMahon for “Good Reason” (as defined in Mr. MacMahon’s employment agreement, which definition was the same as in Mr. Anderson’s employment agreement) within theninety-day period following the occurrence of a “Change of Control” (as defined in Mr. MacMahon’s employment agreement, which definition was the same as in Mr. Anderson’s employment agreement), he would have become entitled to receive a lump sum severance payment equal to two times his total cash compensation, which would have consisted of his (i) annual base salary, (ii) all incentive bonuses paid to Mr. MacMahon in respect of our last completed fiscal year (but only if Mr. Baker was not President or Chief Executive Officer of TEC or TRC), and (iii) the cash value of premiums paid on Mr. MacMahon’s behalf for medical, dental, life, and other insurance plans coverage during our last completed fiscal year immediately preceding termination.

The severance payments and benefits were conditioned upon Mr. MacMahon’s execution and delivery of a release of claims, which was executed on March 13, 2008.

Director Compensation for Fiscal Year 2007

Our non-employee directors are entitled to annual retainers in addition to certain fees for attending meetings of our board of directors and committee meetings. None of our directors were granted any stock awards or option awards in fiscal year 2007 and none held any stock awards or option awards at the end of fiscal year 2007. Non- employee directors are reimbursed for out-of-pocket expenses in excess of $25.00 incurred in connection with attending meetings of our board of directors and committee meetings. Effective as of December 31, 2007, members of our board of directors participate in the Executive Bonus Plan and are therefore eligible to receive a specified percentage of our net asset value appreciation during 2008. In 2009, it is anticipated that our directors will be granted restricted stock units under our new equity-based compensation plan.

Director Compensation Table(1)


	Fees Earned or
	Paid in Cash
Name	(US$)(9)		Total (US$)

Timothy J. Bernlohr	$	107,195	$	107,195
Anthony Caluori	$	33,071	$	33,071
John H. Forsgren	$	36,606	$	36,606
Todd A. Overbergen	$	34,821	$	34,821
Marc MacAluso	$	33,353	$	33,353
Peter Dea(2)	$	13,856	$	13,856
Randall Kob(3)	$	2,853	$	2,853
Charlie MacNeil(4)	$	110,250	$	110,250
Tom Jung(5)	$	75,250	$	75,250
Bob Puchniak(6)	$	47,332	$	47,332
Jamie Heller(7)	$	41,250	$	41,250
Brian Humphrey(8)	$	40,000	$	40,000


(1)		Messrs. Davis and Baker served as named executive officers and directors in 2007. The director fees paid to each of these named executive officers are reported in column (b) of the Summary Compensation Table.

(2)		Mr. Dea resigned from our board of directors as of September 21, 2007.

(3)		Mr. Kob resigned from our board of directors as of September 10, 2007.

(4)		Mr. MacNeil resigned from our board of directors as of August 21, 2007.

(5)		Mr. Jung resigned from our board of directors as of August 21, 2007.

(6)		Mr. Puchniak resigned from our board of directors as of April 16, 2007.

(7)		Mr. Heller resigned from our board of directors as of March 26, 2007.

(8)		Mr. Humphrey resigned from our board of directors as of March 26, 2007.

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(9)		Fees earned are comprised of the following:


			Committee or
			Special
	Board		Committee(i)				Total
	Meeting Fee		Meeting Fee		Retainer Fee		Fees Earned
Name	(US$)		(US$)		(US$)		(US$)

Timothy J. Bernlohr		18,600		22,500		66,095		107,195
Anthony Caluori		7,500		7,500		18,071		33,071
John H. Forsgren		7,500		2,000		21,106		36,606
Todd A. Overbergen		7,500		9,250		18,071		34,821
Marc MacAluso		6,750		11,250		15,353		33,353
Peter Dea		2,250		3,250		8,356		13,856
Randall Kob		—		—		2,853		2,853
Charlie MacNeil		42,000		16,250		52,000		110,250
Tom Jung		42,000		6,250		27,000		75,250
Bob Puchniak		33,000		3,750		10,582		47,332
Jamie Heller		31,500		1,250		8,500		41,250
Brian Humphrey		31,500		—		8,500		40,000


(i)		The Special Committee was formed in April 2007 and dissolved in August 2007. Its purpose was to ensure that the TRC 2007 subordinated credit agreement closed.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information with respect to the beneficial ownership of our common stock as of , 2009 and after giving effect to this offering for the following persons:


	•	each person known to us to be the beneficial owner of more than five percent of our outstanding shares of common stock;

	•	each of our directors;

	•	each of our named executive officers; and

	•	all of our directors and executive officers as a group.

We have determined beneficial ownership in accordance with the rules of the SEC. Except as indicated by the footnotes below, we believe, based on the information furnished to us, that the persons and entities named in the table below have sole voting and investment power with respect to all shares of common stock that they beneficially own, subject to applicable community property laws.

For purposes of the table below, beneficial ownership prior to this offering is calculated based on 28,115,114 shares of our common stock and 5,607,559 shares of preferred stock that vote as a single class with our outstanding shares of common stock, in each case, outstanding as of , 2009. In computing the number of shares of common stock beneficially owned by a person and the percentage ownership of that person, we deemed to be outstanding all shares of common stock subject to options, other warrants or other convertible securities held by that person or entity that are currently exercisable or were exercisable within 60 days of , which is , however, we did not deem these shares outstanding for the purpose of computing the percentage of any other person. In calculating the number of shares issuable upon a redemption of each holder’s shares of preferred stock and exercise of the preferred warrants, we have assumed an initial public offering price of US$ per share, the midpoint of the estimated price range shown on the cover page of this prospectus.

For purposes of the table below, beneficial ownership upon completion of this offering is based on shares which will be outstanding, assuming the initial public offering price will be US$ per share, the midpoint of the estimated price range shown on the cover page of this prospectus. We have also included in our calculation of percentage ownership of each beneficial owner, where applicable, the additional shares to be held by the beneficial owners of our 2007 debt warrants assuming the exercise of their right of first refusal to purchase shares of our common stock offered by us in this offering pursuant to the right of first refusal agreement. Pursuant to this agreement our 2007 debt warrant holders may purchase up to a maximum of 28.8% of the shares offered by us in this offering. In addition, the number of shares issuable pursuant to our 2006 and 2007 debt warrants and deemed beneficially owned by each of the holders below will vary depending on the initial public offering price. As a result the beneficial ownership following completion of this offering will likely change.

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Unless otherwise indicated, the address of each beneficial owner listed in the table below isc/o Trident Resources Corp., 1000, 444 — 7th Avenue SW, Calgary, AB, T2P 0X8.

Shares Beneficially

Owned After Offering and the

Shares Beneficially

Owned After Offering and the

Recapitalization

Owned Prior to this

Recapitalization

(Assuming Exercise of

Offering and the

(Assuming No Exercise of

Over-Allotment

Recapitalization

Over-Allotment Option)(7)

Option in Full)(7)

Percent

(Upon

Exercise of

Name and Address of

First Refusal

Beneficial Owner

Number

Percent

Number

Percent

Right)

Number

Percent

Right)

Aurora Energy Partners, L.P.(1)

The McNeil Family Irrevocable GST Trust(2)

Jennison Associates LLC Funds(3)(4)

The Charles S. McNeil Family Trust(5)

Chilton Limited Partnerships(6)(4)

Clery SARL(7)

Todd A. Dillabough

—

Alan G. Withey

—

Eugene I. Davis

—

Kenneth L. Ancell

—

Timothy J. Bernlohr

—

Anthony Caluori

—

John H. Forsgren

—

Marc MacAluso

—

Todd A. Overbergen

—

Tracey Bell

—

Colin Michael Finn

—

Jacques G. St. Hilaire

—

All directors and executive officers as a group

—


(1)		Consists of 8,726,815 shares of common stock and shares of common stock to be issued upon the mandatory redemption of the Series A preferred stock and warrants. Aurora Energy Partners, L.P. is a limited partnership. White Hat Ventures, L.P. is the general partner of Aurora Energy Partners, L.P. and White Hat Management, Inc. is the general partner of White Hat Ventures, L.P. The address of Aurora Energy Partners, L.P. isc/o Argue Pearson Harbison & Myers, LLP, 10 W. Broadway, Suite 500, Salt Lake City, UT 84101.

(2)		Consists of 4,976,541 shares of common stock and shares of common stock to be issued upon the mandatory redemption of the Series A preferred stock and warrants. Wyoming Bank & Trust is the trustee of The McNeil Family Irrevocable GST Trust and holds sole voting and investment power over the shares, and the beneficiaries of that trust consist of Mr. McNeil’s children, grandchildren and other descendants. The shares of common stock held by The McNeil Family Irrevocable GST Trust are not beneficially owned by Mr. McNeil because neither Mr. McNeil nor his spouse is a trustee or beneficiary of The McNeil Family Irrevocable GST Trust, nor do they possess voting or investment power over those shares. The address of the McNeil Family Irrevocable GST Trust isc/o Wyoming Bank & Trust, 5827 Yellowstone Road, Cheyenne, WY 82009.

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(3)		Consists of (i) 551,694 shares of common stock, shares of common stock to be issued upon the mandatory redemption of the Series B preferred stock and warrants and 2,591,932 shares of common stock issuable upon the exercise of the 2007 debt warrants owned by Jennison Natural Resources Fund, Inc.; (ii) 2,345,594 shares of common stock, shares of common stock to be issued upon the mandatory redemption of the Series B preferred stock and warrant and 879,216 shares of common stock issuable upon the exercise of the 2007 debt warrants owned by Jennison Utility Fund of the Prudential Sectors Funds, Inc.; (iii) 236,629 shares of common stock and 720,366 shares of common stock issuable upon the exercise of the 2007 debt warrants owned by Jennison Value Fund; (iv) 7,060 shares of common stock owned by Samsung Life Investment (America), Ltd.; (v) 404,537 shares of our common stock owned by Value Portfolio of The Prudential Series Funds, Inc. and (vi) 412,657 shares of common stock owned by Natural Resources Portfolio of the Prudential Series Fund, Inc. In addition, the Jennison Funds, pursuant to the right of first refusal agreement, have a combined right to purchase 8.8479% of the shares of common stock offered by us in this offering. The address of the Jennison Funds isc/o Jennison Associates LLC, 466 Lexington Avenue, 18th Floor, New York, NY 10017.

(4)		Includes shares of common stock that may be acquired in this offering pursuant to a right to purchase shares of common stock offering by us in this offering pursuant to a right of first refusal agreement. For a description of the right of first refusal agreement, see “Certain Relationships and Related Party Transactions — Agreements Related to Our Securities — Right of First Refusal Agreement.”

(5)		Consists of 3,317,695 shares of common stock and shares of common stock to be issued upon the mandatory redemption of the Series A preferred stock and warrants held by Wyoming Bank & Trust as the investment trustee of The Charles S. McNeil Family Trust, a revocable trust of which Mr. McNeil, his spouse, his children and his other descendants are the beneficiaries. The address of the Charles S. McNeil Family Trust isc/o Alaska Trust Company, 1029 West Third Avenue, Suite 510, Anchorage, AK 99051.

(6)		Consists of (i) 60,000 shares of common stock owned by Chilton Global Natural Resources Partners, L.P.; (ii) 4,000 shares of common stock owned by Chilton New ERA Partners, L.P.; (iii) 80,000 shares of common stock held by Chilton Small Cap International, L.P.; (iv) 198,548 shares of common stock issuable upon the exercise of the 2007 debt warrants by Chilton Global Distressed Opportunities Master Fund, L.P.; (v) 2,330,951 shares of common stock issuable upon the exercise of the 2007 debt warrants by Chilton Natural Resource Partners, L.P.; (vi) 12,097 shares of common stock and 68,102 shares of common stock issuable upon the exercise of the 2007 debt warrants by Chilton Global Partners, L.P.; (vii) 184,184 shares of common stock and 470,459 shares of common stock issuable upon the exercise of the 2007 debt warrants by Chilton International L.P.; (viii) 110,540 shares of common stock and 483,961 shares of common stock issuable upon the exercise of the 2007 debt warrants by Chilton Investment Partners L.P.; (ix) 25,358 shares of common stock and 138,487 shares of common stock issuable upon the exercise of the 2007 debt warrants by Chilton Opportunity International L.P.; and (x) 25,821 shares of common stock and 129,552 shares of common stock issuable upon the exercise of the 2007 debt warrants by Chilton Opportunity Trust L.P. In addition, the Chilton Funds, pursuant to the right of first refusal agreement, have a combined right to purchase 8.0638% of the shares of common stock offered by us in this offering. The address of the Chilton Funds is 1266 East Main Street, Stamford, CT 06902.

(7)		Consists of 1,746,923 shares of common stock and shares of common stock to be issued upon the mandatory redemption of the Series A preferred stock and warrants. The address of Clery SARL isc/o The Ospraie Fund, 780 — Third Avenue, New York, New York, United States 10017.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Agreements Related to our Securities

Amended and Restated Exchange Rights Agreement

We are a party to an amended and restated exchange rights agreement with each of the shareholders of TEC common shares that are not one of our subsidiaries and certain holders of options to purchase TEC common shares. Two of these shareholders are Trident Exploration Limited Partnership and Trident Exploration (2003) Limited Partnership formed for third party investors. Pursuant to the agreement each such shareholder and optionholder is entitled to (i) exchange a TEC common share for a share of our common stock, or (ii) exchange a vested option to purchase a share of TEC common stock for a share of our common stock upon payment of the exercise price. The agreement terminates on the date there cease to be any outstanding TEC common shares that are not owned, or controlled directly or indirectly, by us, or any rights (including options) to acquire such shares.

Right of First Refusal Agreement

In connection with our recapitalization on August 20, 2007, we entered into a right of first refusal agreement, whereby we granted to investors party to the TRC 2007 subordinated credit agreement the right to purchase up to their “pro rata” share of certain additional equity securities that we issue, including the shares of common stock sold in this offering. Shares issued pursuant to any rights or agreements, options, warrants or convertible securities outstanding as of the date of the agreement are excluded from coverage. Each investor’s pro rata share is determined by multiplying the number of such issued additional equity securities by the ratio of (A) the number of warrants securities held by such investor to (B) the sum of all outstanding shares of our common stock and preferred stock and the total number of warrants securities held by all such investors, as of the date that notice of the issuance of the additional equity securities is given to the investors; provided, however, except for the warrant securities, shares of common stock or preferred stock issuable upon the exercise of options, warrants, securities convertible into such capital stock and other rights to acquire such capital stock shall not constitute outstanding shares of common stock or preferred stock for purposes of calculating the outstanding number of shares until they are issued. No later than 30 days prior to the contemplated date such proposed equity securities are to be sold, we must provide each of these investors with a written notice setting forth (i) the terms of the proposed sale including price and conditions and (ii) the contemplated sale date. Each investor has 20 days following receipt of our notice of the proposed issuance or sale, to exercise such right or it is waived with respect to such issuance or sale, so long as the proposed sale is completed within 90 days of the sale date specified in the offer notice. The right of first refusal granted under this agreement terminates upon certain events, including closing of this offering.

Based on the number of our outstanding common shares, preferred stock, and common stock issuable upon the conversion of the 2007 debt warrants, the investors collectively have the right to purchase 28.8% of any shares of common stock offered by us in this offering. To facilitate the offer of these shares to our investors under the right of first refusal agreement, the underwriters have reserved from the shares we are offering up to shares, representing up to 28.8% of the aggregate number of shares offered in this offering at the public offering price per share. We do not know if the investors will choose to purchase all or any portion of the reserved shares, but any purchases such investors do make will reduce the number of shares available to the general public. Investors who purchase reserved shares will agree not to offer, sell or contract to sell or otherwise dispose of those shares, without the prior written consent of the underwriters, for a period of 180 days from the date of this prospectus.

Registration Rights Agreements

Pursuant to two registration rights agreement, the current holders of our common stock, and holders of our common stock upon redemption of our preferred stock and exercise of the related preferred warrants and upon the exercise of our 2006 and 2007 debt warrants, have rights to request that we register their shares under the Securities Act in certain circumstances, which includes the right to include shares in this offering, to the extent not limited or cutback by the underwriters.

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Third Amended and Restated Registration Rights Agreement

Demand Registration Rights. At any time following 180 days after the effective date of the registration statement of which this prospectus forms a part or, the effective date, the holders of outstanding or issuable shares of our common stock, having demand registration rights under the third amended and restated registration rights agreement, have the right to require that we register their common stock with an aggregate market value of at least US$5.0 million. We are required to file a registration statement in respect of such shares within 90 days of the receipt of such request. We are not, however, obligated to file more than one registration statement for each stockholder, and its affiliates, in response to a demand registration right by such stockholder. We may postpone the filing of a registration statement for up to 90 days if we determine in good faith that the filing would have an adverse effect on any proposal by us to engage in any acquisition of assets, or any merger, consolidation, takeover bid or similar transaction. In addition, if the filing of a registration statement would require us to disclose material information that we have a bona fide business purpose for preserving as confidential, we are not required to effect the registration until the earlier of: (i) the date upon which such material information is disclosed to the public or ceases to be material or (ii) 90 days after we make such good faith determination. If we have been advised by an independent investment dealer that a registration in response to a demand registration would adversely affect any proposed financing by us, we are not required to effect the registration until the later of (i) 45 days after the completion or abandonment of such financing, and (ii) the termination of any blackout, orlock-up, required by the underwriters or agents in connection with such financing. In any case, we cannot postpone the filing or effectiveness of a registration statement in response to a demand registration for more than an aggregate of 90 days in any 365 day period. The underwriters of any underwritten offering have the right to limit the number of shares to be included in a demand registration statement. We have agreed to pay all expenses, except for underwriters’ discounts and commissions, incurred in connection with these demand registration rights.

Piggyback Registration Rights. In connection with any demand registration, we will give prompt notice to all other stockholders of our intention to file a registration statement in accordance with such request and use commercially reasonable efforts to include any registrable shares held by such stockholders who wish to participate. If we otherwise wish to register our common stock, including this offering, we are required to provide as much prior notice as is reasonably possible to all applicable stockholders and we must use commercially reasonable efforts to include any registrable shares held by such stockholders in this offering. In any underwritten offering, including this offering, the underwriters of any underwritten offering have the right to limit the number of shares registered due to marketing reasons, in which case (i) if the registration is a demand registration, the shares of stockholders requesting a general piggyback registration will be included on a pro rata basis, based upon each such holder’s relative holdings of shares subject to the third amended and restated registration rights agreement or (ii) if the registration is not a demand registration, we will include (a) the shares we propose to sell first, then (b) shares of the stockholders requesting registration pursuant to piggyback rights, on a pro rata basis, based upon each such stockholder’s relative holdings of shares subject to the third amended and restated registration rights agreement. We have agreed to pay all expenses, except for underwriters’ discounts and commissions, incurred in connection with these piggyback registration rights.

Expiration. The registration rights granted pursuant to the third amended and restated registration rights agreement will expire with respect to an individual stockholder when such stockholder is able to sell all of its shares without restriction as to volume under Rule 144(k) under the Securities Act, subject to certain exceptions.

Registration Rights Agreement

Upon the written request of a stockholder delivered to us on or prior to the 120th day following the Effective Date, we are required to use commercially reasonable efforts to file with the SEC no later than 150 days after the Effective Date a shelf registration statement registering for resale the shares of our common stock. The holders of an aggregate of outstanding or issuable shares of our common stock following this offering are entitled to include their shares in such a registration statement. We are required to use commercially reasonable efforts to cause the shelf registration statement to become effective as soon as reasonably practicable after the date that is 180 days after the Effective Date (in no event prior to the expiry of any lock up agreements relating to this offering) and to maintain its continuous effectiveness for two years following the closing of this offering, or such earlier time as the shares covered by such registration statement (i) have been or may be sold pursuant to a registration statement or

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pursuant to Rule 144 under the Securities Act, (ii) have become saleable and could all be sold but are still held on such date pursuant to Rule 144 in a 90 day period or (iii) have been sold to us or our subsidiaries. We may direct holders of shares registered under the shelf registration statement to suspend their sales of shares under the shelf registration under certain circumstances where such sales could negatively impact our activities and operations.

Fourth Amended and Restated Stockholder Agreement

In connection with debt financing provided to us by the members of certain lenders, we entered into the fourth amended and restated stockholder agreement, or the Stockholder Agreement, with our stockholders, lenders under the TRC 2007 subordinated credit agreement, TEC and the TEC shareholders. Under the Stockholder Agreement, as amended by the first amendment, each TRC stockholder agrees to vote all of his, her or its shares to cause the authorized number of directors on our board to be established at eleven directors, consisting of up to: (i) three representatives designated by certain lenders under the TRC 2007 subordinated credit agreement; (ii) two representatives designated by the majority preferred holders; (iii) one representative designated by Aurora Energy Partners, L.P.; (iv) one representative designated by the McNeil Group; (v) one representative designated by the previously described parties; (v) one representative designated by the Richardsons; and (vii) two individuals nominated by a majority of the members of the board or a committee thereof. The Stockholders Agreement contains certain tag along and drag along rights and provides several dates on which it will terminate, including upon completion of our initial public offering. See “Management — Board Structure and Compensation — Composition of our Board of Directors.”

Financing Transactions

Private Placement Offering to Senior Management

On January 1, 2005, our board of directors awarded Jon Baker, our former President and Chief Executive Officer, 397,879 shares of our common stock, Richard Meli, our former Executive Vice President and Chief Financial Officer, 100,000 shares of our common stock and Steven J. Buchanan, one of the former managers of Aurora Energy, LLC, 257,879 shares of our common stock at a price of C$16.50 per share. As consideration for these shares, we accepted 50% recourse promissory notes in the amount of US$5,435,027 from Mr. Baker, US$1,366,000 from Mr. Meli and US$3,522,627 from Mr. Buchanan. Each of these notes bore interest at 5% per annum. Interest and principal were due on December 31, 2012. On July 13, 2006, we entered into separate agreements with Jon Baker and Richard Meli pursuant to which Mr. Baker granted us a call option to purchase 397,879 shares of our common stock and Mr. Meli granted us a call option to purchase 100,000 shares of our common stock. In return for these call option grants, we cancelled the 50% recourse promissory notes in the amount of US $5,435,027 from Mr. Baker and US$1,366,000 from Mr. Meli, plus accrued interest thereon. The exercise price of the call options granted to us by Mr. Baker is equal to the fair market value of the shares of common stock covered by the option at the time of exercise minus US$14.71 per share. The exercise price of the call options granted to us by Mr. Meli is equal to the fair market value of the shares of common stock covered by the option at the time of exercise minus US$19.80 per share. The options are exercisable by us under certain circumstances, including a change of control or a sale of our common stock by Mr. Baker or Mr. Meli, and subject to certain conditions. The options expire on July 12, 2012. The note from Mr. Buchanan is still outstanding.

Bridge Financing Arrangements

During February 2005, Aurora Energy Opportunity, L.P., an affiliate of Jon Baker, provided us with bridge equity financing of US$3,100,000. The terms of such financing allowed the investment to be converted into shares of our common stock or our Series A preferred stock units at a discounted purchase price. On March 11, 2005, the bridge investment was converted into 77,010 shares of our common stock which resulted in a subscription price of C$47.50 per share of common stock, a discount of 5% to the C$50.00 per share price paid by investors on March 11, 2005 in our equity financing.

On March 3, 2005, NexGen Investments L.P., an affiliate of Charles S. McNeil, our former Chairman of the board, loaned US$3,000,000 to us, with interest payable at 9% per annum. The loan was repaid with part of the net proceeds from the March 11, 2005 equity financing.

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Reorganization of Certain U.S. Subsidiaries

Pursuant to a reorganization agreement dated as of March 11, 2005, among us, The McNeil Family Irrevocable GST Trust and The Charles S. McNeil Family Trust, or together, the McNeil Family Trusts, Aurora Energy Partners, L.P., and three of our U.S. subsidiaries, NexGen Energy Canada Inc., Aurora Energy, LLC and Trident CBM Corp., we exchanged our Series A preferred stock units for the preferred stock of the three U.S. subsidiaries that was held by the McNeil Family Trusts and Aurora Energy Partners, L.P.

In the exchange with Aurora Energy Partners, L.P. we issued an aggregate of 101,654 of our Series A preferred stock units and gave Aurora Energy Partners, L.P. a residual interest in Aurora Energy, LLC and we received all of the preferred equity interests in Aurora Energy, LLC, a promissory note to us in an aggregate principal amount of US$543,303 and all of the shares of preferred stock of Trident CBM Corp. On July 13, 2006, we redeemed the residual interest in Aurora Energy, LLC received by Aurora Energy Partners, L.P. for US$890,505.00 and Aurora Energy Partners, L.P. repaid the promissory note in full. In the exchange with the McNeil Family Trusts, we issued 107,594 of our Series A preferred stock units and received all of the shares of preferred stock of NexGen Energy Canada Inc.

Stock Awards to Certain Former Executive Officers

Stock Award Loans. Pursuant to a stock award loan program we established on June 23, 2005, we loaned Richard Meli US$500,000 on July 28, 2005; we loaned John E. Koch, TEC’s former Chief Operating Officer and one of our former Vice Presidents, C$500,000 on August 1, 2005; we loaned Robert Funnell, one of TEC’s former Vice Presidents, C$500,000 on August 17, 2005; we loaned Dave Cox, our former Chief Operating Officer and one of our former Vice Presidents, US$500,000 on August 24, 2005; we loaned Colin Michael Finn, one of our current Vice Presidents, C$256,500 on August 24, 2005; and we loaned Murray Rodgers, TEC’s former Executive Vice President, C$500,000 on September 26, 2005. These loans were secured by certain shares of our common stock in the case of Messrs. Cox and Meli, or certain vested options to purchase shares of our common stock in the case of Messrs. Koch, Finn, Funnell and Rodgers. These loans bore interest at 3%, with accrued interest payable in arrears annually on December 31. The loans would have matured, inter alia, on the date the shares of our common stock, or options to purchase shares of our common stock, as applicable, securing the loans ceased to be held by the applicable borrower. On July 14, 2006, Mr. Koch exercised options and subsequently sold 10,246 shares of our common stock to us for a net aggregate cash purchase price equal to C$500,000. He used the proceeds of that sale to repay the stock award loan made to him. Mr. Koch was thereafter granted options to purchase 10,246 TEC common shares at an exercise price of C$53.00 per share. On June 28, 2006, Mr. Rodgers exercised options and subsequently sold 10,246 shares of our common stock to us for a net aggregate cash purchase price equal to C$500,000. He used the proceeds of that sale to repay the stock award loan made to him. Mr. Rodgers was thereafter granted options to purchase 10,246 TEC common shares at an exercise price of C$53.00 per share. We cancelled the stock award loan granted to Mr. Meli in return for his option granted on July 13, 2006 described under “Private Placement Offering to Senior Management.” Messrs. Cox and Funnell repaid their stock award loans on June 28, 2006. Mr. Finn’s stock award loan is still outstanding.

Other Transactions

On January 1, 2006, TEC entered into a compressor package and generator supply agreement with Profile Compression Inc., or Profile Compression. John Koch was a member of the board of directors of Profile Compression. During 2007, Profile Compression charged TEC C$400,000 for certain equipment under that agreement. The agreement was terminated in February 2008.

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Policy on Related Party Transactions

We recognize that related party transactions present a heightened risk of conflicts of interest. Historically, when we have engaged in such transactions our board of directors has reviewed the transactions and provided approval. In connection with this offering, we intend to adopt a written policy to which the related party transactions shall be subject. All ongoing and future transactions between us and any of our directors, executive officers, principal stockholders or affiliates will be on terms believed by us at that time, based upon other similar arrangements known to us, to be no less favorable than are available from unaffiliated third parties. Such transactions will require prior approval in each instance by a majority of disinterested members of the board of directors. If a transaction with an affiliated third party were found to be on terms less favorable to us than with an unaffiliated third party, we will not engage in such transaction.

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DESCRIPTION OF CAPITAL STOCK

General

The following is a summary of the rights of our common stock and preferred stock and related provisions of our amended and restated certificate of incorporation and amended and restated bylaws, as they will be in effect upon the closing of this offering. For more detailed information, see the form of fifth amended and restated certificate of incorporation and form of amended and restated bylaws, which are filed as exhibits to the registration statement of which this prospectus forms a part.

Immediately following the closing of this offering, our authorized capital stock will consist of 2,500,000,000 shares, each with a par value of US$0.0001 per share, of which 2,490,000,000 shares will be designated as common stock, and 10,000,000 shares will be designated as preferred stock. At the closing of this offering, all of our outstanding preferred stock will be mandatorily redeemed for common stock.

Common Stock

The holders of our common stock are entitled to one vote per share on all matters to be voted upon by our stockholders. The election of directors shall be determined by a plurality of the votes cast by the stockholders present in person or represented by proxy at the meeting and entitled to vote thereon. All other matters shall be determined by the vote of a majority of the votes cast by the stockholders present in person or represented by proxy at the meeting and entitled to vote thereon, unless the matter is one upon which, by applicable law, the certificate of incorporation, the bylaws or applicable stock exchange rules, a different vote is required, in which case such provision shall govern and control the decision of such matter. Holders of common stock have no preemptive or conversion rights or other subscription rights other than as described elsewhere in this prospectus. There are no redemption or sinking fund provisions applicable to the common stock. All of the outstanding shares of common stock are, and the shares of common stock to be sold in this offering when issued and paid for will be, fully paid and nonassessable. The rights, preferences and privileges of holders of common stock are subject to the rights of the holders of shares of any series of preferred stock that may be issued in the future.

Preferred Stock

Our board of directors are authorized, without any action by our stockholders, to designate and issue up to 10,000,000 shares of preferred stock in one or more series and to fix the powers, rights, preferences, privileges, restrictions, qualifications and limitations of each series.

The authority possessed by our board of directors to issue preferred stock could potentially be used to discourage attempts by third parties to obtain control of us through a merger, tender offer, proxy contest or otherwise by making such attempts more difficult or more costly. Our board of directors may issue preferred stock with voting rights or conversion rights that, if exercised, could adversely affect the voting power of the holders of our common stock. There are no current agreements or understandings with respect to the issuance of preferred stock and the board of directors does not have a present intention to issue any shares of preferred stock.

Stockholder Meetings

Special meetings of stockholders may be called only by a majority of the entire board.

All notices of meetings with stockholders shall be in writing and shall be sent or otherwise given not less than 10 and not more than 60 days before the date of the meeting to each stockholder entitled to vote as such meeting. The notice shall specify the place (if any), date and hours of the meeting, and in the case of a special meeting, the purpose for which the meeting is called.

Stockholder Action

Any action required or permitted to be taken by our stockholders must be effected at a duly called annual or special meeting of the stockholders and may not be effected by written consent in lieu of a meeting.

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Election and Removal of Directors

Directors are elected by a plurality of the votes cast by stockholders present or represented by proxy at the annual meeting of the stockholders present or represented by proxy at the meeting and entitled to vote thereon to hold office for a three-year term. There are no cumulative voting rights in the election of directors. Each director, including a director elected to fill a vacancy, shall hold office until his or her successor is elected and qualified or until his or her earlier death, resignation, retirement, disqualification or removal. Any director may resign at any time upon written notice to the attention of the secretary. In accordance with the terms of our fifth amended and restated certificate of incorporation, our board of directors is divided into three classes, class I, class II and class III, with members of each class serving until the annual meeting for the year in which his or her successor has been elected subject to the exceptions above. At each succeeding annual meeting of stockholders beginning in 2010, successors to the class of directors whose term expires at that annual meeting shall be elected for a three-year term. Any additional directorships resulting from an increase in the number of directors will be distributed among the three classes so that, as nearly as possible, each class will consist of one-third of the directors. The term of office of the first class of directors, consisting of Messrs. Forsgren and Overbergen, will expire at our 2010 annual meeting of stockholders. The term of office of the second class of directors, consisting of Messrs. Ancell, Dillabough and MacAluso, will expire at the 2011 annual meeting of stockholders. The term of office of the third class of directors, consisting of Messrs. Bernlohr, Caluori and Davis, will expire at the 2012 annual meeting of stockholders.

Directors may be removed with cause, by the holders of a majority of shares then entitled to vote at an election of directors.

Except as otherwise provided by law, newly created directorships resulting from any increase in the authorized number of directors or any vacancies in the board of directors resulting from death, resignation, retirement, disqualification, removal from office or other cause may be filled solely by a majority vote of the directors then in office, even if less than a quorum, or by a sole remaining director and not by stockholders.

Requirements for Advance Notification of Stockholder Nominations and Proposals

Our amended and restated bylaws provide for advance notice procedures with respect to stockholder proposals and nomination of candidates for election as directors other than nominations made by or at the direction of the board of directors or a committee of the board of directors. In particular, stockholders must notify the corporate secretary in writing prior to the meeting at which the matters are to be acted upon or directors are to be elected. The notice must contain the information specified in our amended and restated bylaws. To be timely, the notice must be received at our principal executive office not later than 45 or more than 75 days prior to the first anniversary of the date on which we first mail our proxy materials for the preceding year’s annual meeting of stockholders. However, if the date of the annual meeting is advanced more than 30 days prior to or delayed by more than 30 days after the anniversary of the preceding year’s annual meeting, notice by the stockholder, to be timely, must be delivered no later than the close of business on the later of the 90th day prior to such annual meeting or the tenth day following the day on which public announcement of the date of such meeting is first made. Moreover, in the event that the number of directors to be elected to the board of directors is increased and there is no public announcement by us naming all of the nominees for director or specifying the size of the increased board of directors at least ten days prior to the first anniversary of the date on which we first mailed our proxy materials for the preceding year’s annual meeting of stockholders, the stockholder’s notice will be considered timely, but only with respect to nominees for any new positions created by such increase, if it is delivered to the corporate secretary at our principal executive offices not later than the close of business on the tenth day following the day on which such public announcement is first made by us.

Amendment of the Certificate of Incorporation and Bylaws

In addition to any other vote that may be required by law or any preferred stock designation, our amended and restated certificate of incorporation may be amended and restated by the affirmative vote of the holders of at least 66 2/3% of the voting power of all of the then outstanding shares of capital stock of the corporation entitled to vote generally in the election of directors. Our bylaws may be adopted, amended, altered or repealed by the affirmative vote of at least a majority of the entire board of directors or by the affirmative vote of the holders of at least 66 2/3%

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of the voting power of all of the then outstanding shares of capital stock of the corporation entitled to vote generally in the election of directors.

Directors’ Liability; Indemnification of Directors and Officers

Our amended and restated certificate of incorporation provides that a director will not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director to the fullest extent permitted by the General Corporation Law of the State of Delaware, or DGCL.

In addition, our amended and restated certificate of incorporation and bylaws provide for mandatory indemnification of directors, officers, and certain persons serving other enterprises at the request of the corporation against expenses, fines, judgments, and amounts paid in settlement actually and reasonably incurred in connection with any proceeding, to the fullest extent provided by the laws of the State of Delaware, except in connection with certain proceedings (or part of proceedings) initiated by such indemnitees.

Warrants

Following the closing of this offering, we will have outstanding the following warrants:


	•	warrants to purchase shares of our common stock issued in connection with the TRC 2006 credit agreement, with an exercise price of C$ per share;

	•	warrants to purchase shares of our common stock issued in connection with the TRC 2007 subordinated credit agreement, with an exercise price of C$0.0001 per share;

	•	30,000 warrants to purchase shares of our common stock held by a consultant, with an exercise price of C$50.00 per share; and

	•	20,000 warrants to purchase TEC common shares held by a former employee, with an exercise price of C$4.20 per share.

Anti-Takeover Effects of Our Certificate of Incorporation, Bylaws and Delaware Law

Certain provisions of Delaware law contain provisions that could have the effect of delaying, deferring or discouraging another party from acquiring control of us. These provisions are expected to discourage certain types of coercive takeover practices and inadequate takeover bids. These provisions are also designed, in part, to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of increased protection from our potential ability to negotiate with an unfriendly or unsolicited acquiror outweigh the disadvantages of discouraging such proposals, including proposals that are priced above the then-current market value of our common stock, because, among other things, the negotiation of such proposals could result in an improvement of their terms.

Opt-Out of Delaware Anti-Takeover Statute

Pursuant to our amended and restated certificate of incorporation, we have opted out of the provisions of Section 203 of the Delaware General Corporation Law regulating corporate takeovers. In general, Section 203 prohibits a publicly-held Delaware corporation from engaging, under certain circumstances, in a business combination with an interested stockholder (defined generally as a person owning 15% or more of the corporation’s voting stock) for a period of three years following the date the person became an interested stockholder unless:


	•	prior to the date the person became an interested person, the board of directors of the corporation approved either the business combination or the transaction which resulted in the stockholder becoming an interested stockholder;

	•	upon completion of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced; or

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	•	at or subsequent to the date of the transaction, the business combination is approved by the board of directors of the corporation and authorized at an annual or special meeting of stockholders, and not by written consent, by the affirmative vote of at least 66 2/3% of the outstanding voting stock which is not owned by the interested stockholder.

Generally, a business combination includes a merger, asset or stock sale, or other transaction resulting in a financial benefit to the interested stockholder. We have opted out of the provisions of Section 203 of the Delaware General Corporation Law because we believe this statute could prohibit or delay mergers or other change in control attempts, and thus may discourage attempts to acquire us.

Registration Rights

Upon the closing of this offering, the holders of outstanding or issuable shares of our common stock may demand that we register their shares under the Securities Act, or if we file another registration statement under the Securities Act, may elect to include their shares in such registration. If these shares are registered, they will be freely tradable without restriction under the Securities Act. For additional information, see “Certain Relationships and Related Party Transactions — Agreements Related to Our Securities — Registration Rights Agreements.”

Listing

We will apply to have our common stock listed on the New York Stock Exchange under the symbol “TZ.”

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is and is located at .

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has not been a public market for our stock. Sales of substantial amounts of our common stock in the public market after this offering, including shares issued upon the exercise of outstanding options or warrants or the possibility of these sales occurring, could cause the prevailing market price for our common stock to fall.

Assuming no exercise of options and warrants outstanding following this offering, a total of shares of our common stock will be outstanding after this offering. Of these shares, shares of common stock sold in this offering will be freely tradable in the public market without restriction or further registration under the Securities Act, unless these shares are held by persons who may be deemed to be our “affiliates,” as that term is defined in Rule 144 under the Securities Act, who will be subject to the restrictions described below.

An aggregate of shares of our common stock held by our existing stockholders upon the closing of this offering will be “restricted securities,” as that term is defined in Rule 144 under the Securities Act. These restricted securities are eligible for public sale only if their resale is registered under the Securities Act or qualifies for an exemption from registration under Rule 144 or 701 under the Securities Act, which are summarized below.

Subject to thelock-up agreements described below and the provisions of Rules 144 and 701 under the Securities Act, these restricted securities will be available for sale in the public market as follows:


		Number of
Date		Shares

On the date of this prospectus
Between 90 and 180 days after the date of this prospectus
At various times beginning more than 180 days after the date of this prospectus

In addition, as of June 30, 2008, a total of 19,534,099 shares of our common stock were subject to outstanding options and warrants that do not expire upon the closing of this offering. The shares underlying these options and warrants will become freely tradable in the public market from time to time, subject to the provisions of Rules 144 and 701.

Rule 144

Generally, the shares of our common stock sold in this offering will be freely transferable without restriction or further registration under the Securities Act, except that any shares of our common stock held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits common stock of an issuer that has been acquired by a person who is an affiliate of the issuer, or has been an affiliate of the issuer within the past three months, to be sold in an amount that does not exceed, during any three-month period, the greater of:


	•	1.0% of the total number of shares of our common stock outstanding; or

	•	the average weekly reported trading volume of our common stock for the four calendar weeks prior to the sale.

Such sales are also subject to specific manner of sale provisions, a six-month holding period, notice requirements and the availability of current public information about us.

Rule 144 also provides that a person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned shares of our common stock that are restricted securities for at least six months, will be entitled to freely sell such shares of stock subject only to the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned for at least one year shares of our common stock that are restricted securities, will be entitled to freely sell such shares under Rule 144 without regard to the current public information requirements of Rule 144.

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Lock-Up Agreements

Our officers and directors, and substantially all of our shareholders, have signedlock-up agreements pursuant to which, subject to certain exceptions, as described in “Underwriting”, they have agreed not to sell or otherwise dispose of their ordinary shares or any securities convertible into or exchangeable for ordinary shares for a period of 180 days after the date of this prospectus without the prior written consent of Deutsche Bank Securities Inc. Thelock-up agreements may be extended under certain circumstances described in “Underwriting.”

Registration Rights

Rule 701

Under Rule 701 under the Securities Act, each of our employees, officers, directors, and consultants who purchased or received shares pursuant to a written compensatory plan or contract is eligible to resell these shares 90 days after the effective date of this offering in reliance upon Rule 144, but without compliance with specific restrictions. Rule 701 provides that affiliates may sell their Rule 701 shares under Rule 144 without complying with the holding period requirement and that non-affiliates may sell their shares in reliance on Rule 144 without complying with the holding period, public information, volume limitation, or notice provisions of Rule 144.

Registration Statements onForm S-8

We intend to file one or more registration statements onForm S-8 under the Securities Act following this offering to register the resale of shares of our common stock that are issuable pursuant to our employee benefit plans. These registration statements are expected to become effective upon their filing. Shares covered by these registration statements will then be eligible for sale in the public markets, subject to any applicablelock-up agreements and to Rule 144 limitations applicable to affiliates.

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MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS

The following is a summary of the material U.S. federal income tax consequences of the acquisition, ownership and disposition of our common stock byNon-U.S. Holders (defined below), but does not purport to be a complete analysis of all the potential tax considerations. This summary is based upon the Internal Revenue Code of 1986, as amended or “Code,” the Treasury Regulations or the “Regulations” promulgated or proposed thereunder and administrative and judicial interpretations thereof, all as of the date hereof and all of which are subject to change, possibly on a retroactive basis. This summary is limited to the tax consequences of persons who hold shares of our common stock as capital assets within the meaning of Section 1221 of the Code.

This summary does not purport to deal with all aspects of U.S. federal income taxation that might be relevant to particularNon-U.S. Holders in light of their particular investment circumstances or status, nor does it address specific tax consequences that may be relevant to particular persons (including, for example, financial institutions, broker-dealers, insurance companies, partnerships or other pass-through entities, expatriates, banks, real estate investment trusts, regulated investment companies, tax-exempt organizations, or persons in special situations, such as those who have elected to mark securities to market or those who hold shares of our common stock as part of a straddle, hedge, conversion transaction or other integrated investment orNon-U.S. Holders that own (or owned during the relevant period) actually or constructively, more than 5% of our common stock). In addition, this summary does not address U.S. federal alternative minimum, estate and gift tax consequences or consequences under the tax laws of any state, local or foreign jurisdiction. We have not sought any ruling from the Internal Revenue Service, or the IRS, with respect to the statements made and the conclusions reached in this summary, and we cannot assure you that the IRS will agree with such statements and conclusions.

This summary is for general information only. Prospective purchasers of shares of our common stock are urged to consult their independent tax advisors concerning the U.S. federal income taxation and other tax consequences to them of acquiring, owning and disposing of shares of our common stock, as well as the application of state, local and foreign income and other tax laws.

For purposes of the following summary, a“Non-U.S. Holder” is a holder of our common stock that, for U.S. federal income tax purposes, is not (i) a citizen or individual resident of the U.S.; (ii) a corporation or other entity taxable as a corporation created or organized under the laws of the U.S., any state thereof, or the District of Columbia; (iii) an estate, the income of which is subject to U.S. federal income tax regardless of the source; or (iv) a trust, if a court within the U.S. is able to exercise primary supervision over the trust’s administration and one or more U.S. persons have the authority to control all its substantial decisions or if a valid election to be treated as a U.S. person is in effect with respect to such trust.

If you are a partner in a partnership, or an entity treated as a partnership for U.S. federal income tax purposes, that holds shares of our common stock, your tax treatment generally will depend upon your U.S. tax status and upon the activities of the partnership. If you are a partner of a partnership acquiring shares of our common stock, you are urged to consult your tax advisor about the U.S. tax consequences of holding and disposing of the shares of our common stock.

Dividends

We do not expect to declare or pay any dividends on shares of our common stock in the foreseeable future. However, if we do pay dividends on shares of our common stock, such distributions will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Distributions in excess of earnings and profits will constitute a return of capital that is applied against and reduces theNon-U.S. Holder’s adjusted tax basis in shares of our common stock. Any remaining excess will be treated as gain realized on the sale or other disposition of shares of our common stock and will be treated as described under“Non-U.S. Holders — Gain on Disposition of Common Stock” below. Any dividend paid to aNon-U.S. Holder of shares of our common stock ordinarily will, except as described in the following paragraph, be subject to withholding of U.S. federal income tax at a rate of 30%, or such lower rate as may be specified under an applicable income tax treaty. In order to receive a reduced treaty rate, aNon-U.S. Holder must provide an IRSForm W-8BEN or other appropriate version ofForm W-8 certifying eligibility for the reduced rate.

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If at least 80% of our gross income during the applicable testing period is “active foreign business income” as defined in the Code, then U.S. withholding tax would apply only to the percentage of dividends that we pay equal to the percentage which our gross income from U.S. sources for the testing period is of our total gross income for the testing period. The “testing period” means the three-year period ending with the close of our taxable year preceding the payment (or such part of such period as may be applicable). If these special rules apply at the time of payment, we will calculate the amount we withhold on dividends paid toNon-U.S. Holders based upon application of such rules. Although we expect that substantially all of our income will be derived from active foreign business income, there can be no assurances in this regard.

Dividends paid to aNon-U.S. Holder that are effectively connected with a trade or business conducted by theNon-U.S. Holder in the United States generally will be exempt from the withholding tax described above (if theNon-U.S. Holder complies with applicable certification and disclosure requirements) and instead generally will be subject to U.S. federal income tax on a net income basis at the regular graduated U.S. federal income tax rates in much the same manner as if theNon-U.S. Holder were a U.S. person (unless, where an income tax treaty applies, the dividend is not attributable to a permanent establishment maintained by theNon-U.S. Holder in the United States). In order to obtain this exemption from withholding tax, aNon-U.S. Holder must provide an IRSForm W-8ECI properly certifying eligibility for such exemption. Dividends received by a corporateNon-U.S. Holder that are effectively connected with a trade or business conducted by such corporateNon-U.S. Holder in the United States may also be subject to an additional branch profits tax at a rate of 30% or such lower rate as may be specified by an applicable income tax treaty.

Gain on Disposition of Common Stock

ANon-U.S. Holder generally will not be subject to U.S. federal income tax on any gain realized on a disposition of shares of our common stock, provided that (i) the gain is not otherwise effectively connected with a trade or business conducted by theNon-U.S. Holder in the U.S. (and, in the case of an applicable tax treaty, is not attributable to a permanent establishment maintained by theNon-U.S. Holder in the United States), and (ii) in the case of aNon-U.S. Holder who is an individual and who holds the shares of our common stock as a capital asset, such Holder is not present in the United States for 183 or more days in the taxable year of the sale or other disposition and certain other conditions are met. Additional special rules would apply if our stock were considered to be a U.S. real property interest, which is not expected to be the case.Non-U.S. Holders should consult their own tax advisors with respect to the application of the foregoing rules to their ownership and disposition of shares of our common stock.

Information Reporting and Backup Withholding

U.S. backup withholding tax will not apply to payments of dividends to aNon-U.S. Holder if the certification described above in“Non-U.S. Holders — Dividends” is duly provided by suchNon-U.S. Holder or theNon-U.S. Holder otherwise establishes an exemption, provided that the payor does not have actual knowledge or reason to know that the Holder is a U.S. person or that the conditions of any claimed exemption are not satisfied. Certain information reporting may still apply to payments even if an exemption from backup withholding is established. Copies of any information returns reporting dividend payments and any withholding may also be made available to the tax authorities in the country in which aNon-U.S. Holder resides under the provisions of an applicable income tax treaty.

Any amounts withheld under the backup withholding tax rules from a payment to aNon-U.S. Holder will be allowed as a refund, or a credit against suchNon-U.S. Holder’s U.S. federal income tax liability, provided that the requisite procedures are followed.

Non-U.S. Holders are urged to consult their own tax advisors regarding their particular circumstance and the availability of and procedure for obtaining an exemption from backup withholding.

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UNDERWRITING

Subject to the terms and conditions of the underwriting agreement, the underwriters named below, through their representatives Deutsche Bank Securities Inc. and Jefferies & Company, Inc. have severally agreed to purchase from us the following respective numbers of shares of common stock at a public offering price less the underwriting discounts and commissions set forth on the cover page of this prospectus:


		Number
Underwriters		of Shares

Deutsche Bank Securities Inc.
Jefferies & Company, Inc.
Total

The underwriting agreement provides that the obligations of the several underwriters to purchase the shares of common stock offered hereby are subject to certain conditions precedent and that the underwriters will purchase all of the shares of common stock offered by this prospectus, other than those covered by the over-allotment option described below, if any of these shares are purchased.

We have been advised by the representatives of the underwriters that the underwriters propose to offer the shares of common stock to the public at the public offering price set forth on the cover of this prospectus and to dealers at a price that represents a concession not in excess of $ per share under the public offering price. The underwriters may allow, and these dealers may re-allow, a concession of not more than $ per share to other dealers. After the initial public offering, representatives of the underwriters may change the offering price and other selling terms.

We have granted to the underwriters an option, exercisable not later than 30 days after the date of this prospectus, to purchase up to additional shares of common stock at the public offering price less the underwriting discounts and commissions set forth on the cover page of this prospectus. The underwriters may exercise this option only to cover over-allotments made in connection with the sale of the common stock offered by this prospectus. To the extent that the underwriters exercise this option, each of the underwriters will become obligated, subject to conditions, to purchase approximately the same percentage of these additional shares of common stock as the number of shares of common stock to be purchased by it in the above table bears to the total number of shares of common stock offered by this prospectus. We will be obligated, pursuant to the option, to sell these additional shares of common stock to the underwriters to the extent the option is exercised. If any additional shares of common stock are purchased, the underwriters will offer the additional shares on the same terms as those on which the shares are being offered.

The underwriting discounts and commissions per share are equal to the public offering price per share of common stock less the amount paid by the underwriters to us per share of common stock. The underwriting discounts and commissions are % of the initial public offering price. We have agreed to pay the underwriters the following discounts and commissions, assuming either no exercise or full exercise by the underwriters of the underwriters’ over-allotment option:

Total Fees

Without Exercise of

With Full Exercise of

Fee Per

Over-Allotment

Share

Option

Discounts and commissions paid by us

US$

The underwriters may also receive an additional performance fee at our sole discretion equal to % of the initial public offering price or US$ per share. This would result in an additional payment to the underwriters of an aggregate of US$ or US$ if the underwriters exercise their over-allotment option in full.

In addition, we estimate that our share of the total expenses of this offering, excluding underwriting discounts and commissions, will be approximately $ .

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We have agreed to indemnify the underwriters against some specified types of liabilities, including liabilities under the Securities Act, and to contribute to payments the underwriters may be required to make in respect of any of these liabilities.

Each of our officers and directors, and substantially all of our stockholders and holders of options and warrants to purchase our stock, have agreed not to offer, sell, contract to sell or otherwise dispose of, or enter into any transaction that is designed to, or could be expected to, result in the disposition of any shares of our common stock or other securities convertible into or exchangeable or exercisable for shares of our common stock or derivatives of our common stock owned by these persons prior to this offering or common stock issuable upon exercise of options or warrants held by these persons for a period of 180 days after the effective date of the registration statement of which this prospectus is a part without the prior written consent of Deutsche Bank Securities Inc. This consent may be given at any time without public notice. Transfers or dispositions can be made during thelock-up period in the case of gifts or for estate planning purposes where the donee signs alock-up agreement. We have entered into a similar agreement with the representatives of the underwriters. There are no agreements between the representatives and any of our stockholders or affiliates releasing them from theselock-up agreements prior to the expiration of the180-day period.

The representatives of the underwriters have advised us that the underwriters do not intend to confirm sales to any account over which they exercise discretionary authority.

In connection with the offering, the underwriters may purchase and sell shares of our common stock in the open market. These transactions may include short sales, purchases to cover positions created by short sales and stabilizing transactions.

Short sales involve the sale by the underwriters of a greater number of shares than they are required to purchase in the offering. Covered short sales are sales made in an amount not greater than the underwriters’ option to purchase additional shares of common stock from us in the offering. The underwriters may close out any covered short position by either exercising their option to purchase additional shares or purchasing shares in the open market. In determining the source of shares to close out the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option.

Naked short sales are any sales in excess of the over-allotment option. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if underwriters are concerned that there may be downward pressure on the price of the shares in the open market prior to the closing of the offering.

Stabilizing transactions consist of various bids for or purchases of our common stock made by the underwriters in the open market prior to the closing of the offering.

The underwriters may impose a penalty bid. This occurs when a particular underwriter repays to the other underwriters a portion of the underwriting discount received by it because the representatives of the underwriters have repurchased shares sold by or for the account of that underwriter in stabilizing or short covering transactions.

Purchases to cover a short position and stabilizing transactions may have the effect of preventing or slowing a decline in the market price of our common stock. Additionally, these purchases, along with the imposition of the penalty bid, may stabilize, maintain or otherwise affect the market price of our common stock. As a result, the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the New York Stock Exchange, in the over-the-counter market or otherwise.

At our request, the underwriters have reserved for sale at the initial public offering price up to shares, representing approximately 28.8% of the shares offered by us in this offering, for sale to certain existing holders of our securities pursuant to a right of first refusal agreement dated August 20, 2007 and up to shares, representing approximately % of the shares offered by us in this offering, for sale to certain of our directors and employees and their family members, and certain other persons having business relationships with us. The number of shares of our common stock available for the sale to the general public will be reduced to the

135

extent these reserved shares are purchased. Any reserved shares not purchased by these persons will be offered by the underwriters to the general public on the same basis as the other shares in this offering.

A prospectus in electronic format is being made available on Internet web sites maintained by one or more of the lead underwriters of this offering and may be made available on web sites maintained by other underwriters. Other than the prospectus in electronic format, the information on any underwriter’s web site and any information contained in any other web site maintained by an underwriter is not part of the prospectus or the registration statement of which the prospectus forms a part.

Pricing of this Offering

Prior to this offering, there has been no public market for our common stock. Consequently, the initial public offering price of our common stock will be determined by negotiation among us and the representatives of the underwriters. Among the primary factors that will be considered in determining the public offering price are:


	•	prevailing market conditions;

	•	our results of operations in recent periods;

	•	the present stage of our development;

	•	the market capitalizations and stages of development of other companies that we and the representatives of the underwriters believe to be comparable to our business; and

	•	estimates of our business potential.

Each underwriter intends to comply with all applicable laws and regulations in each jurisdiction in which it acquires, offers, sells or delivers shares of common stock or has in its possession or distributes the prospectus.

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:


	•	to any legal entity that is authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;

	•	to any legal entity that has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than € 50,000,000, as shown in its last annual or consolidated accounts;

	•	to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the representatives; or

	•	in any other circumstances that do not require the publication of a prospectus pursuant to Article 3 of the Prospectus Directive,

provided that no such offer of securities shall require us or any underwriters to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC and includes any relevant implementing measure in each relevant member state.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters. Each underwriter

136

has represented and agreed that (i) it has not offered or sold and, prior to the expiration of the period of six months from the closing date of this offering, will not offer or sell any shares of our common stock to persons in the United Kingdom except to persons whose ordinary activities involve them in acquiring, holding, managing or disposing of investments (as principal or agent) for the purposes of their businesses or otherwise in circumstances which have not resulted and will not result in an offer to the public in the United Kingdom within the meaning of the Public Offers of Securities Regulations 1995; (ii) it has complied with and will comply with all applicable provisions of the Financial Services Act 1986 with respect to anything done by it in relation to the shares of our common stock in, from or otherwise involving the United Kingdom; and (iii) it has only issued or passed on and will only issue or pass on in the United Kingdom, any document received by it in connection with the issue of the shares of our common stock to a person who is of a kind described in Article 11 (3) of the Financial Services Act 1986 (Investment Advertisements) (Exemptions) Order 1996 or is a person to whom such document may otherwise lawfully be issued or passed on.

Some of the underwriters or their affiliates may provide investment banking services to us in the future. They will receive customary fees and commissions for these services. Deutsche Bank Securities Inc. and Jefferies & Company, Inc. are acting as with respect to the offering of our senior notes due being conducted concurrently with this offering. Further, Deutsche Bank Securities Inc. and Jefferies & Company, Inc. are acting as joint lead arrangers under the new revolving credit facility that we intend to enter into concurrently with this offering, for which will act as administrative agent and will act as syndication agent.

137

LEGAL MATTERS

The validity of the common stock offered hereby will be passed upon by Akin Gump Strauss Hauer & Feld LLP, New York, New York. Certain legal matters in connection with the common stock offered hereby will be passed upon for the underwriters by White & Case LLP, New York, New York. Certain legal matters relating to the laws of Canada in connection with the common stock offered hereby will be passed upon for us by Blake, Cassels & Graydon LLP and for the underwriters by McCarthy Tétrault LLP.

EXPERTS

Our consolidated financial statements as of December 31, 2005, 2006 and 2007, and for each of the years in the three-year period ended December 31, 2007, have been included herein, and in the registration statement, in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

The estimates of our proved reserves as of June 30, 2008 included in this prospectus are based on a reserve report prepared by Netherland, Sewell and Associates, Inc., independent petroleum engineers. The estimates of our proved reserves as of December 31, 2004, 2005, 2006 and 2007 are based on reserve reports prepared by Sproule Associates Limited, independent petroleum engineers. The estimates of our proved reserves as of December 31, 2003 included in this prospectus are based on a reserve report prepared by Ryder Scott Company, independent petroleum engineers. These estimates are included in this prospectus in reliance upon the authority of the firm as experts in these matters.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement onForm S-1 under the Securities Act with respect to the shares of common stock that are being offered by this prospectus. This prospectus does not contain all of the information included in the registration statement. For further information pertaining to us and our common stock, you should refer to the registration statement and its exhibits. Whenever we make reference in this prospectus to any of our contracts, agreements or other documents, the references are not necessarily complete, and you should refer to the exhibits attached to the registration statement for copies of the actual contract, agreement or other document.

Upon the closing of this offering, we will be subject to the informational requirements of the Securities Exchange Act of 1934 and will file annual, quarterly and current reports, proxy statements and other information with the SEC. You can read our SEC filings, including the registration statement, over the Internet at the SEC’s website at www.sec.gov. You may also read and copy any document we file with the SEC at its public reference facility at 100 F Street, N.E., Room 1580, Washington, D.C. 20549.

You may also obtain copies of the documents at prescribed rates by writing to the public reference room of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at1-800-SEC-0330 for further information on the operation of the public reference facilities.

138

GLOSSARY OF NATURAL GAS AND COALBED METHANE TERMS

As used in this prospectus, the terms set forth below have the following meanings:

Bblmeans stock tank barrel, or 42 U.S. gallons liquid volume, used in this prospectus in reference to crude oil or other liquid hydrocarbons. One Bbl is equivalent to six Mcfe of natural gas.

Bcfemeans billion cubic feet equivalent.

GJ, or gigajoule,is a measure of heat equivalent to approximately 0.95 Mcfe.

MBblsmeans thousand barrels of oil.

Mcfemeans thousand cubic feet equivalent.

Mmcfemeans million cubic feet equivalent.

Mmcfe/dmeans million cubic feet per day.

Tcfmeans trillion cubic feet.

In addition, as used in this prospectus,

Commercialmeans, in relation to a gas project, once gas is produced in commercial quantities, which means that the project produces gas in quantities sufficient for operation at a profit (even though the operations as a whole, including expenditures for development and equipment, result in a loss).

Doig formationmeans, in relation to the Montney Shale gas play, interbedded sandstone, siltstone and shale deposits of the Middle Triassic aged Doig Formation which overlie the Montney Shale formation in the Lower Triassic strata. The Doig Formation contains commercial quantities of oil and gas as demonstrated by competitors in British Columbia and other locations in Canada.

Greenhouse GasesorGHGsmeans any or all of carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulphur hexafluoride (SF6).

Grossmeans:


	•	in relation to wells, the total number of wells in which a company has an interest; and

	•	in relation to leasehold acreage, the total area of properties in which a company has an interest.

Horizontal lateralmeans, in relation to the Mannville CBM and Montney Shale plays, drilling a near horizontal wellbore that is initiated from a near vertical wellbore drilled from the surface to the target geologic horizon. The horizontal lateral is programmed to drill within the targeted formation such as the Mannville coals or Montney shales.

Horseshoe Canyonmeans widespread Upper Cretaceous aged interbedded coal, sandstone, siltstone, carbonaceous shale and shale deposits of the Horseshoe Canyon Formation which overlies the Belly River formation of the lower-most Upper Cretaceous aged strata in the Plains area of Alberta.

Mannvillemeans widespread Lower Cretaceous aged interbedded coal, sandstone, siltstone, carbonaceous shale and shale deposits of the Mannville formation which overlies the Jurassic aged formations in the Plains area of Central Alberta. This formation is historically known for significant quantities of conventional oil and gas production in the Western Canadian Sedimentary Basin.

Montneymeans widespread Lower Triassic aged interbedded sandstone, siltstone, and shale deposits of the Montney formation which overlies the Permian aged Belloy formation in the Deep Basin area of British Columbia and Alberta. This formation is historically known for significant quantities of conventional oil and gas production in Northwest Alberta and Northeast British Columbia.

A-1

Netmeans:


	•	in relation to a company’s production, its working interest (operating or non-operating) share after deduction of royalty obligations;

	•	in relation to a company’s interest in reserves, its working interest (operating or non-operating) share after deduction of royalty obligations;

	•	in relation to a company’s interest in wells, the number of wells obtained by aggregating the company’s working interest in each of its gross wells; and

	•	in relation to a company’s interest in leasehold acreage, the total acreage in which the company has an interest multiplied by the working interest owned by the company.

Productionis calculated based on a company’s working interest (operating or non-operating) share before the deduction of royalty obligations.

Proved reservesare those reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.

Sectionmeans one square mile (or 640 acres).

A-2

NSAI RESERVE REPORT AS OF JUNE 30, 2008

B-1

August 26, 2008

Mr. Todd Dillabough

Mr. Ken Ancell

Trident Exploration Corporation

1000,444-7^th Avenue S.W.

Calgary, Alberta

Canada T2P 0X8

Dear Mr. Dillabough and Mr. Ancell:

In accordance with your request, we have estimated the proved reserves and future revenue, as of June 30, 2008, to the Trident Exploration Corporation (Trident) interest in certain gas properties located in Alberta, Canada, as listed in the accompanying tabulations. This report has been prepared using constant prices and costs, as discussed in subsequent paragraphs of this letter. The estimates of reserves and future revenue in this report have been prepared in accordance with the definitions and guidelines of the U.S. Securities and Exchange Commission and, with the exception of the exclusion of future income taxes, conform to the Statement of Financial Accounting Standards No. 69. Definitions are presented immediately following this letter.

As presented in the accompanying summary projections, Tables I through IV, we estimate the gas reserves and future net revenue to the Trident interest in these properties, as of June 30, 2008, to be:


	Gas Reserves (MMCF)						Future Net Revenue (M$)
	Gross		Company		Company				Present Worth
Category	(100 Percent)		Gross		Net		Total		at 10%

Proved Developed
Producing		557,093.7		282,797.1		221,789.0		1,859,421.4		1,010,859.7
Non-Producing		22,953.7		12,250.8		10,455.9		89,426.0		38,652.1
Proved Undeveloped		414,282.3		184,233.4		162,695.7		1,126,888.4		379,114.3
Total Proved		994,329.8		479,281.3		394,940.6		3,075,735.8		1,428,626.1

Totals may not add because of rounding.

Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. These properties no longer produce commercial volumes of condensate. Company Gross reserves are defined as the working interest share of reserves prior to the deduction of interests owned by others (burdens) and do not include reserves for wells in which Trident owns only royalty interest. Company Net reserves are defined as the working, net carried, and royalty interest reserves after deduction of all applicable burdens. Revenue includes the gas cost allowances (GCA) for the estimated future costs of gathering, compressing, and processing natural gas; additional corporate GCA are not included. Revenue estimates are expressed in thousands of United States dollars (M$) using a June 30, 2008, Bank of Canada currency exchange rate of $1.000 United States equals $1.0197 Canadian.

The estimates shown in this report are for proved developed producing, proved developed non-producing, and proved undeveloped reserves. Our estimates do not include any probable or possible reserves that may exist for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk. As shown in the Table of Contents, for each reserves category


4500 Thanksgiving Tower • 1601 Elm Street • Dallas, Texas75201-4754 • Ph:214-969-5401 • Fax:214-969-5411	nsai@nsai-petro.com


1221 Lamar Street, Suite 1200 • Houston, Texas77010-3072 • Ph:713-654-4950 • Fax: 713-654-4951	netherlandswewell.com

B-2

this report includes a summary projection of reserves and revenue along with one-line summaries of reserves and revenue by lease.

Future gross revenue to the Trident gross interest is prior to deducting royalty burdens, Crown royalty, freehold taxes, and GCA. Future net revenue is after deductions for these taxes, royalties, future capital costs, abandonment costs, and operating expenses but before consideration of Canadian federal and provincial income taxes. For 2008, Crown royalty and freehold tax calculations are based on current regulatory guidelines outlined inOil and Gas Fiscal Regimes of the Western Canadian Provinces and Territories located on the Alberta Department of Energy website.¹ Crown royalty and freehold tax calculations for 2009 forward are based on Alberta’s new royalty framework, outlined inThe New Royalty Framework, dated October 25, 2007, located on the Alberta Department of Energy website.² The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and their related facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. Our estimates of future revenue do not include any salvage value for the lease and well equipment but do include Trident’s estimates of the costs to abandon the wells and production facilities. Abandonment costs are excluded for inactive wells.

Gas prices used in this report are based on a June 30, 2008, Natural Gas Exchange AB-NIT price of $11.477 per MMBTU and are adjusted by field for energy content, transportation fees, and regional price differentials. As requested, an economic projection is included in the proved developed producing category to account for the cost incurred as a result of certain gas price hedge contracts in place through February 28, 2009. Gas prices are held constant throughout the lives of the properties.

Lease and well operating costs used in this report are based on operating expense records of Trident. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Headquarters general and administrative overhead expenses of Trident are not included. Lease and well operating costs are held constant throughout the lives of the properties. Capital costs are included as required for workovers, new development wells, and production equipment. The future capital costs and abandonment costs are held constant to the date of expenditure.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Trident interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Trident receiving its net revenue interest share of estimated future gross gas production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. The reserves may or may not be recovered; if they are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report. Also, estimates of reserves may increase or decrease as a result of future operations.

In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geologic. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of

¹ http://www.energy.gov.ab.ca/tenure/pdfs/FISREG.pdf

² http://www.energy.gob.ab.ca/Org/pdfs/royalty_Oct25.pdf

B-3

engineering and geologic data; therefore, our conclusions necessarily represent only informed professional judgment.

The contractual rights to the properties have not been examined by Netherland, Sewell & Associates, Inc., nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were obtained from Trident Exploration Corporation, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting geologic, field performance, and work data are on file in our office. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties and are not employed on a contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.


	By:	/s/ C.H. (Scott) Rees III, P.E.

C.H. (Scott) Rees III, P.E.

Chairman and Chief Executive Officer


By: /s/ Danny D. Simmons, P.E. Danny D. Simmons, P.E. President and Chief Operating Officer	By:	/s/ David E. Nice, P.G. David E. Nice, P.G. Vice President

Date Signed: August 26, 2008		Date Signed: August 26, 2008

B-4


		INDEX TO FINANCIAL STATEMENTS


Trident Resources Corp. and Subsidiaries
Unaudited Interim Financial Statements for the six months ended June 30, 2007 and 2008
Consolidated Balance Sheets as of June 30, 2008 and December 31, 2007			F-2
Consolidated Statements of Operations and Comprehensive Loss for the six months ended June 30, 2007 and 2008			F-3
Consolidated Statements of Stockholders’ Deficit for the six months ended June 30, 2007 and 2008			F-4
Consolidated Statements of Cash Flows for the six months ended June 30, 2007 and 2008			F-5
Notes to the Interim Consolidated Financial Statements			F-6
Audited Financial Statements as of December 31, 2007 and 2006 and for each of the years in the three-year period ended December 31, 2007
Report of Independent Registered Public Accounting Firm			F-18
Consolidated Balance Sheets as of December 31, 2006 and 2007			F-19
Consolidated Statements of Operations and Comprehensive Loss for the years ended December 31, 2005, 2006 and 2007			F-20
Consolidated Statements of Stockholders’ Deficit for the years ended December 31, 2005, 2006 and 2007			F-21
Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2006 and 2007			F-22
Notes to the Consolidated Financial Statements for the years ended December 31, 2005, 2006 and 2007			F-23
Supplemental Financial Information — Oil and Gas Producing Activities — Unaudited			F-50

F-1

Trident Resources Corp.
Consolidated Balance Sheets
(In thousands of Canadian dollars, except for share data)

(Unaudited)


	June 30,			December 31,
	2008			2007

ASSETS
Current
Cash	$	99,919		$	134,963
Accounts receivable (note 4)		98,389			69,469
Fair value of risk management contracts (note 5)		—			5,508
Prepaid expenses and deposits		4,486			2,419

Total current assets		202,794			212,359

Property, plant and equipment, full cost method — net (note 6)		663,433			633,889
Other assets (note 7)		34,034			37,496

	$	900,261		$	883,744


LIABILITIES
Current
Accounts payable	$	17,582		$	25,377
Accrued interest		9,468			11,788
Accrued other liabilities		40,036			34,100
Fair value of risk management contracts (note 5)		5,779			—

Total current liabilities		72,865			71,265

Long-term debt (note 8)		978,923			918,620
Series A preferred stock embedded derivative		375,377			374,525
Series B preferred stock, 2,000,000 authorized with US$0.0001 par value and 614,000 issued and outstanding at June 30, 2008 and December 31, 2007 (note 15)		39,108			38,018
Other long-term liabilities (note 10)		99,647			9,185
Asset retirement obligation		21,188			19,246
Minority interests in subsidiary (note 14)		—			2,558

		1,587,108			1,433,417
Series A redeemable preferred stock, 8,000,000 authorized with US$0.0001 par value and 4,993,559 issued and outstanding at June 30, 2008 and December 31, 2007 (note 15)		408,574			380,828

STOCKHOLDERS’ DEFICIT
Common Stock, $0.0001 par value, 2,490,000,000 authorized with 27,359,357 issued as of June 30, 2008 and 27,330,727 as of December 31, 2007		3			3
Paid-in capital		306,346			303,492
Deficit		(1,401,770	)		(1,233,996	)

		(1,095,421	)		(930,501	)

	$	900,261		$	883,744

Commitments (note 17)
Contingencies (note 18)
Subsequent events (note 20)

The accompanying notes are an integral part of these interim consolidated financial statements.

F-2

Trident Resources Corp.
Consolidated Statements of Operations and Comprehensive Loss
For the six months ended June 30
(In thousands of Canadian dollars, except for share data)

(Unaudited)


	2008			2007

Revenue
Production revenue	$	110,554		$	107,692

Expenses
Operating — exclusive of depletion and depreciation shown below		29,068			28,606
General and administrative		22,398			9,336
Depletion, depreciation and accretion		32,034			104,144

		83,500			142,086

Income (loss) from operations		27,054			(34,394	)
Other income and expenses
Financing charges (note 12)		126,800			87,424
Restructuring charges (note 13)		2,410			17,198
Loss on disposition		423			—
Foreign exchange (gain) loss		35,409			(115,299	)

		165,042			(10,677	)

Loss before undernoted items		(137,988	)		(23,717	)

Taxes
Capital taxes		98			172

Net loss before undernoted items		(138,086	)		(23,889	)
Minority interests		(1,942	)		—

Net loss and comprehensive loss	$	(140,028	)	$	(23,889	)

Net loss per share (note 16)
Basic and diluted	$	(6.13	)	$	(0.22	)

Weighted average number of shares of common stock outstanding
(thousands)
Basic and diluted		27,349			27,330

The accompanying notes are an integral part of these interim consolidated financial statements.

F-3

Trident Resources Corp.
Consolidated Statements of Stockholders’ Deficit
For the six months ended June 30
(In thousands of Canadian dollars, except for share data)

(Unaudited)


	2008			2007

Common stock, $0.0001 par value, 2,490,000 authorized with 27,359,357 issued as of June 30, 2008 and 27,330,727 as of December 31, 2007

Balance at beginning and end of period		3			3

Paid-in capital
Balance at beginning of period		303,492			301,133
Issuance of common stock		74			—
Elimination of minority interest stock		4,500			—
Stock-based compensation (recovery)		(1,720	)		1,693

Balance at end of period		306,346			302,826

Deficit
Balance at beginning of period		(1,233,996	)		(1,177,132	)
Net loss and comprehensive loss		(140,028	)		(23,889	)
Accrued dividends on Series A preferred stock		(16,187	)		(19,766	)
Foreign exchange gain (loss) on Series A preferred stock		(11,559	)		37,539

Balance at end of period		(1,401,770	)		(1,183,248	)

Total stockholders’ deficit at end of period	$	(1,095,421	)	$	(880,419	)

The accompanying notes are an integral part of these interim consolidated financial statements.

F-4

Trident Resources Corp.
Consolidated Statements of Cash Flows
For the six months ended June 30
(In thousands of Canadian dollars)
(Unaudited)


	2008			2007

Operating activities
Net loss and comprehensive loss	$	(140,028	)	$	(23,889	)
Minority interests		1,942			—
Depletion, depreciation and accretion		32,034			104,144
Non-cash financing charges		109,740			65,432
Stock-based compensation (recovery)		(1,240	)		(1,084	)
Long-term portion of long-term incentive plan		10,524			—
Loss on disposition		423			—
Unrealized foreign exchange (gain) loss		35,409			(115,299	)
Change in fair value of risk management contracts		11,287			—
Change in non-cash working capital		(1,326	)		(14,185	)

Net cash provided by operating activities		58,765			15,119

Financing activities
Settlement of lenders’ warrants		—			(8,941	)
Debt issue costs		(33	)		(1,500	)
Change in non-cash working capital		—			1,346

Net cash used for financing activities		(33	)		(9,095	)

Investing activities
Additions to property, plant and equipment		(61,863	)		(37,633	)
Change in restricted cash		—			(1,536	)
Proceeds from sale of property, plant and equipment		1,400			9,745
Investments		—			(43	)
Change in non-cash working capital		(33,803	)		(47,359	)

Net cash used for investing activities		(94,266	)		(76,826	)

Effect of translation on foreign currency denominated cash		490			(721	)

Decrease in cash		(35,044	)		(71,523	)
Cash, beginning of period		134,963			117,536

Cash, end of period	$	99,919		$	46,013

The accompanying notes are an integral part of these interim consolidated financial statements.

F-5

Trident Resources Corp.
Notes to the Interim Consolidated Financial Statements
For the six months ended June 30, 2008 and 2007
Tabular amounts in thousands of Canadian dollars
(Unaudited)

1. Basis of Presentation

These interim consolidated financial statements of Trident Resources Corp. (“Trident”, “TRC” or “the Company”) have been prepared by management in conformity with U.S. generally accepted accounting principles (“GAAP”).

Trident’s functional currency is the Canadian dollar as the majority of the Company’s assets and operations are located in Canada and substantially all of the Company’s operations are conducted using the Canadian dollar. Accordingly, the Company’s reporting currency is also the Canadian dollar.

These financial statements reflect all adjustments (consisting of normal recurring adjustments and accruals) that are, in management’s opinion, necessary for a fair presentation of the results of the interim period. The results for interim periods are not necessarily indicative of annual results. The timely preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual amounts could differ from estimated amounts due to factors such as fluctuations in commodity prices, changes in the fair value of the Company’s common stock, interest rates and legislative changes.

These interim consolidated financial statements do not include all of the disclosures included in the Company’s annual audited consolidated financial statements for the year ended December 31, 2007. Accordingly, these interim consolidated financial statements should be read in conjunction with the Company’s December 31, 2007 annual audited consolidated financial statements. With the exception of fair value measurements (note 2), the accounting policies used in the preparation of these interim consolidated financial statements conform to those used in the Company’s most recent annual audited consolidated financial statements.

At June 30, 2008, management’s estimated fair value of Trident common stock was $5 per share (December 31, 2007 – $nil). Changes in the estimated fair value of the Company’s common stock price have a material impact on the financial statements including financing charges, subordinated facility warrants included in other long term liabilities, the Series A preferred stock embedded derivative, stock-based compensation expense/(recovery), paid-in capital, net loss, and deficit. It is reasonably possible that the estimate of the fair value of the Company’s common stock will change in the near term. The magnitude of this change cannot be reasonably estimated.


2.	New Accounting Policies

Two new accounting statements of the Financial Accounting Standards Board (“FASB”) were adopted by Trident in the first quarter of 2008: FASB Statement No. 157 –Fair Value Measurements (“FAS 157”) and FASB Statement No. 159 –The Fair Value Option for Financial Assets and Financial Liabilities (“FAS 159”). FAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. This statement applies to other accounting pronouncements that require or permit fair value measurements, and is effective for financial statements issued for fiscal years beginning after November 15, 2007. In addition to required disclosures, FAS 157 also requires companies to evaluate current measurement techniques. The adoption of FAS 157 had no impact on Trident’s consolidated results of operations or financial position. FAS 159 allows an entity to choose to measure many financial instruments and certain other items at fair value for fiscal years beginning on or after November 15, 2007. Trident’s financial statements were not materially impacted by FAS 159.

The Company’s assets and liabilities that are recorded at fair value have been categorized into one of three categories based on the fair value hierarchy established by FAS 157. Fair values of assets or liabilities in Level I are

F-6

Trident Resources Corp.
Notes to the Interim Consolidated Financial Statements
For the six months ended June 30, 2008 and 2007
Tabular amounts in thousands of Canadian dollars
(Unaudited) — (Continued)

assigned according to published or quoted prices in active markets for identical assets or liabilities. The technique used to measure fair value for Level I is the market approach. Level II includes assets and liabilities that were fair valued either by reference to published or quoted prices in markets that were not active or that had outputs that were observable directly or indirectly. Valuations in Level II include values determined using comparisons of similar assets or liabilities that have established market values, models that estimate fair values and other valuation techniques that are commonly used to assign values by market participants. This valuation technique is called the income approach. Level II valuations may rely on the use of estimates of future cash flows, the timing of those cash flows and future discount rates and their effect on the Company’s common stock price per share. In making these assumptions, the Company relies on publicly published interest rate yield data, foreign exchange rates and the share price volatility of the Company’s peers. Level III valuations are based on inputs that are unobservable yet significant to the measurement of fair value. The Company does not have any assets or liabilities that have fair values that are based on unobservable inputs.

The following assets and liabilities are measured on a recurring basis in the Company’s financial statements as at June 30, 2008 at fair value as defined and categorized by FAS 157:


	Level
Liabilities Recorded at Fair Value	I		II		III

Costless collars	$	5,779	$	—	$	—
Series A preferred stock embedded derivative		—		375,377		—
Subordinated facility and unsecured lender’s warrants		—		75,719		—
Stock option loan program and contractor vested options		—		534		—

	$	5,779	$	451,630	$	—

The Company’s management estimates the fair value of shares of its common stock. This valuation has a material impact on the liabilities that are listed as level II liabilities in the table above.


3.	New Accounting Pronouncements

In December 2007, FASB issued SFAS No. 160Non-controlling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin No. 51 which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the non-controlling interest, changes in a parent’s ownership interest and the valuation of retained non-controlling equity instruments when a subsidiary is deconsolidated. The statement also establishes disclosure requirements to clearly identify and distinguish between the interests of the parent and the interest of the non-controlling owners. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. The Company plans to implement this standard on January 1, 2009. The Company does not expect a material affect on its financial results as a result of adopting this standard on January 1, 2009. When adopted, our minority interest positions on the balance sheet will be presented as a component of equity.

In December 2007, FASB issued Statement SFAS 141(R),Business Combinations (“SFAS 141R”). SFAS 141R provides greater consistency in the accounting and financial reporting of business combinations. It requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed, and requires the acquirer to disclose the nature and financial effect of business combination. SFAS 141R is effective on a prospective basis for fiscal years beginning after December 15, 2008.

In March 2008, FASB issued Statement 161,Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133, which is effective for fiscal years beginning after

F-7

November 15, 2008. Statement 161 expands the disclosure requirements for derivative instruments and hedging activities with respect to how and why entities use derivative instruments, how they are accounted for under SFAS No. 133 and the related impact on financial position, financial performance and cash flows. Trident does not expect a material affect on its financial results as a result of adopting this standard on January 1, 2009.

In May 2008, FASB issued Statement 162,The Hierarchy of Generally Accepted Accounting Principles which codifies the sources of accounting principles and the related framework to be utilized in preparing financial statements in conformity with GAAP. Trident’s financial statements are not expected to be impacted by this standard.


4.	Accounts Receivable


	June 30,		December 31,
	2008		2007

Joint interest billings	$	67,438	$	46,661
Production revenue		30,000		20,746
Goods and services tax receivable		—		266
Other		951		1,796

	$	98,389	$	69,469

Trident has a material receivable outstanding with one of its joint venture partners in the amount of $33.0 million at June 30, 2008. In July 2008, the outstanding amount was paid in full along with interest of approximately $1.0 million, which will be recognized in July 2008.


5.	Risk Management Contracts

Trident has entered into costless collar derivative contracts and fixed price commodity sales contracts. The costless collar contracts establish floor and ceiling prices on anticipated future natural gas production. The fair value of the costless collar contracts at June 30, 2008 was $5.8 million liability (December 31, 2007 – $5.5 million asset) on the balance sheet and the change in fair value has been recorded in production revenue in the statement of operations. Fixed price contracts represent physical delivery contracts and are recorded as production revenue upon delivery. At June 30, 2008, the Company had the following risk management contracts outstanding:

Volume

Weighted Average

Contract Type

(GJ/day)

Pricing Point

Price ($/GJ)

Term

Costless Collar(1)

10,000

AECO

7.00 - $8.83

Jul ’08 to Oct ’08

Costless Collar(1)

10,000

AECO

7.00 - $7.75

Jul ’08 to Sep ’08

Fixed price(2)

12,000 - 30,500

AECO

6.21 - $8.15

Jul ’08 to Feb ’09


(1)		Costless collar strike prices indicate minimum floor and maximum ceiling

(2)		Physical delivery

F-8


6.	Property, Plant and Equipment


	June 30,			December 31,
	2008			2007

Properties subject to depletion	$	1,430,401		$	1,324,828
Properties not subject to depletion		274,950			320,373
Accumulated depletion		(1,044,554	)		(1,013,778	)

		660,797			631,423

Office equipment, furniture and fixtures		5,532			5,776
Accumulated depreciation		(2,896	)		(3,310	)

		2,636			2,466

	$	663,433		$	633,889

In the first six months of 2007, the net carrying amount of properties subject to depletion exceeded the discounted future net revenues from the proved reserves by $43.3 million and was recognized as additional depletion expense.

For the six month period ended June 30, 2008, depletion, depreciation and accretion per mcf was $2.25 (2007 – $6.31), respectively. Excluding the impairment charges in 2007, depletion, depreciation and accretion per mcf was $3.24.

During the six month period ended June 30, 2008, the Company capitalized general and administrative expenses of $3.6 million (2007 – $7.9 million) and interest charges of $9.5 million (2007 – $13.5 million).

At June 30, 2008, the carrying value of Trident’s property, plant and equipment consisted of $642.7 million of net assets located in Canada and $20.7 million of net assets located in the U.S.


7.	Other Assets


	June 30,		December 31,
	2008		2007

Deferred financing charges, net	$	33,784	$	37,246
Investments		250		250

	$	34,034	$	37,496


8.	Credit Facilities

The credit facilities restrict Trident Exploration Corp. (“TEC”), a Trident subsidiary, from paying any dividends or distributions to Trident for anything other than general corporate expenses incurred in the normal course of business. Due to these restrictions, dividends on the preferred shares are being accrued instead of being paid out in cash. No cash dividends were paid to Trident by any subsidiaries in 2007 or up to June 30, 2008.


(a)	Revolving facility

At June 30, 2008 and December 31, 2007, TEC held a364-day secured revolving facility (“Revolving Facility”) with a maximum availability of $10 million. The Revolving Facility bears interest at a rate of bank prime plus 1% for Canadian or U.S. prime rate loans and 2% for LIBOR loans, bankers’ acceptances and letters of credit.

F-9

The Revolving Facility is secured by all of the present and future assets of TEC. At June 30, 2008 and December 31, 2007 the Company had $nil drawn and letters of credit of $5.6 million (December 31, 2007 – $9.6 million) issued under the Revolving Facility. The Revolving Facility expired on July 3, 2008, but was renewed for a period of 60 days, with maturity on September 3, 2008, and again for a period of 30 days, with a maturity of October 3, 2008 and finally renewed until October 2, 2009.


(b)	Long-term debt


	June 30,			December 31,
	2008			2007

Second lien secured syndicated term loan facility (US$500 million)	$	509,850		$	495,650
Discounts on second lien facility		(1,562	)		(1,766	)

Second lien secured syndicated term loan facility, net of discount		508,288			493,884

Subordinated facility (US$270 million plus accrued interest)		359,989			323,805
Discounts and warrants on subordinated facility		(22,079	)		(24,839	)

Subordinated facility, net of discounts and warrants		337,910			298,966

2007 unsecured facility ($120 million plus accrued interest)		132,725			125,770

	$	978,923		$	918,620


9.	Warrants and Options

In conjunction with the $120 million unsecured facility (note 8(b)), Trident issued 13.7 million detachable warrants to purchase shares of Trident common stock at $0.0001 per share (“Unsecured Lender’s Warrants”). At June 30, 2008, the estimated fair value of the Unsecured Lender’s Warrants is $68.2 million (December 31, 2007 – $nil), and is recorded in Other Long-Term Liabilities.

In conjunction with the US$270 million subordinated facility (note 8(b)), Trident issued 4.5 million detachable warrants to purchase shares of Trident’s common stock at the lower of $25 per share or 20% below either an Initial Public Offering (“IPO”) price or a price used in the event of a change in control (“Subordinated Facility Warrants”). At June 30, 2008, the estimated fair value of the Subordinated Facility Warrants is $7.5 million (December 31, 2007 – $nil), and is recorded in Other Long-Term Liabilities.

In addition, the estimated fair value of the employee stock option loan program at June 30, 2008 is $0.5 million (December 31, 2007 – $nil).

During the six months ended June 30, 2007, Trident cash settled $8.9 million related to outstanding lenders’ warrants associated with a 2004 subordinated facility.

F-10


10.	Other Long-Term Liabilities


	June 30,		December 31,
	2008		2007

Accrued interest on Series B preferred stock	$	12,870	$	9,185
Warrants and options (note 9)		76,202		—
Long-term portion of long-term incentive plan		10,524		—
Contractor vested options		51		—

	$	99,647	$	9,185


11.	Stock-Based Compensation


(a)	TEC stock options

Trident has a stock option plan under which the Board of Directors may grant stock options to directors, officers, employees, and consultants for the purchase of shares of TEC common stock. The options are granted at the estimated fair value of the TEC common stock at the grant date. The maximum number of options to be granted under the plan is 3.1 million. Trident issues new shares of common stock to settle options exercised. Upon exercise, holders of TEC options have the option of receiving Trident shares.

Option activity for the periods ended June 30, 2008 and December 31, 2007, was as follows:


	Number of			Weighted		Exercisable at		Weighted
	Options			Average		Period-End		Average
	(Thousands)			Exercise Price		(Thousands)		Exercise Price

Balance, December 31, 2006		3,036		$	23.21		1,395	$	11.82
Forfeited		(940	)		26.75

Balance, December 31, 2007		2,096			21.61		1,376		14.15
Forfeited		(762	)		23.47

Balance, June 30, 2008		1,334		$	20.55		808	$	13.00

At June 30, 2008, there were 1,095,312 (December 31, 2007 – 1,695,071) options outstanding to employees and 238,625 (December 31, 2007 – 401,125) options outstanding to consultants. At June 30, 2008, the intrinsic value of all outstanding options was $0.2 million (December 31, 2007 – $nil). There were no options granted in 2008 or 2007.

F-11

Details on options outstanding at June 30, 2008 are as follows:


				Weighted
		Number of		Average		Exercisable at
Exercise Price		Options		Remaining Term		Period-End		Exercise Price
($ per share)		(Thousands)		(Years)		(Thousands)		($ per share)

$	4.20		208		4.1		208	$	4.20
	5.30		90		4.1		90		5.30
	8.40		184		4.1		184		8.40
	13.00		94		5.1		55		13.00
	14.00		206		5.8		105		14.00
	16.50		216		6.3		84		16.50
	18.70		3		6.8		2		18.70
	50.00		285		7.5		80		50.00
	53.00		48		8.3		—		53.00

$	20.55		1,334		5.7		808	$	13.00


(b)	Trident in-substance options

In 2005, two then-current members, and a former member, of senior management purchased 755,758 Trident shares of common stock at a price of $16.50 per share in exchange for share purchase promissory notes in the aggregate amount of US$10.3 million. The shares are pledged as collateral for the promissory notes and had to be held for 366 days before they could be sold. The promissory notes bear interest at 5% per annum and are due at the earlier of the sale of the shares or December 31, 2012. This arrangement is considered, in substance, to be the issuance of stock options and is accounted for in accordance with the Company’s policy on stock-based compensation.

On July 13, 2006, Trident entered into an agreement with two members of senior management (“the individuals”) to eliminate their share purchase promissory notes. The individuals granted the Company call options to purchase 497,879 shares of Trident common stock owned by the individuals. In return, the Company cancelled the US$6.8 million share purchase promissory notes plus all accrued interest thereupon and a US$0.5 million stock option loan. The exercise price of the option is equal to the greater of $nil and the fair value of the shares of common stock covered by the option at the time of exercise, less a weighted average purchase discount of US$15.67 per share. The options are exercisable by the Company at the earliest of: (a) a change of control (as defined in the agreement), (b) December 31, 2012, (c) after an IPO, the date upon which the individuals intend to sell one or more of the underlying shares of common stock, or (d) after an IPO, the date at which the exercise price falls below $0.50 per share. The combination of the common stock and purchased call option has substantially the same characteristics as the grant of stock options. Accordingly, this arrangement is accounted for as a modification of an existing award in accordance with the Company’s policy on stock-based compensation. Consistent with the accounting for the promissory notes, because the shares sold subject to the call options are considered stock options, neither the shares outstanding nor the purchased call options are recorded on the balance sheet. As this arrangement does not have a service period, costs related to the issuance were recognized in the third quarter of 2006.

At June 30, 2008, the intrinsic value of the Trident in-substance options was $nil (December 31, 2007 – $nil). The two individuals are no longer employed by the Company.

F-12


(c)	Stock option loan program

On June 23, 2005, the Board of Directors approved a program (the “stock option loan program”) whereby employees are permitted to borrow from Trident an amount up to 50% of the July 1, 2005 intrinsic value of their vested TEC stock options or Trident in-substance stock options up to a maximum of $2.0 million per employee (US$2.0 million per U.S. based employee). Up to 25% of the intrinsic value of vested stock options as of July 1, 2005 may be borrowed immediately (up to a maximum of $0.5 million per employee, or US$0.5 million per U.S. based employee) and the remaining 25% of the intrinsic value of vested options on the date at which Trident achieves a weekly average production rate of 125 mmcf per day. The loans bear interest at the Canada Revenue Agency’s prescribed rate and are secured by the employees’ stock options in an amount equal to double the loan amount.

The stock option loan program represents a cash-settled liability indexed to the Company’s own common stock and the loan is effectively a put option with an exercise price equal to that required for the employee to breakeven. Accordingly, compensation cost is measured as the fair value of the put option. Changes in the fair value of the liability are recognized in the period they occur.

On March 29, 2006, in anticipation of Trident filing an initial registration statement with the SEC, the Board of Directors approved a program under which senior management would repay their stock option loans. On April 21, 2006 a member of senior management repaid his $0.3 million loan in cash. On June 29, 2006 and July 14, 2006, the remaining members of senior management repaid all amounts borrowed under the employee stock option loan program. These members of senior management exercised a number of TEC stock options with an intrinsic value equivalent to the principal amount owing on the stock option loans. The TEC stock options were exercised for shares of Trident common stock under the exchange rights agreement between Trident and TEC. The Company repurchased the Trident common stock and the funds received by senior management were used to settle the loans.

Due to the decrease in the estimated fair value of the Company’s common stock, holders of the stock option loans are incented to forfeit the options given as collateral rather than repay the loan. Accordingly, in 2007, Trident recorded a $0.3 million charge to general and administrative expense to recognize an impairment of the outstanding loans to employees, reducing the carrying value for these loans as of December 31, 2007 and June 30, 2008 to $nil. These loans have not been forgiven.


*(d)*	*Contractor warrants*

In 2006, the Company granted 30,000 warrants to a contractor that have an exercise price of $50.00 per common share and expire in 2012.

In 2003, TEC issued 25,000 warrants to a former contractor that have an exercise price of $4.20 per share and expire in 2012, of which 5,000 were settled subsequent to June 30, 2008 (see note 20). These warrants may be settled for cash at the Company’s option. As of June 30, 2008 the intrinsic value of the warrants was a liability of $0.1 million (December 31, 2007 – $nil).

F-13


12.	Financing Charges

For the six months ended June 30, 2008 and 2007, financing charges consisted of the following:


	2008			2007

Change in fair value of Series A preferred stock embedded derivative	$	(9,878	)	$	43,093
Interest expense on credit facilities		61,592			64,506
Amortization of deferred financing charges		6,459			4,051
Accrued interest on Series B preferred stock		3,377			3,263
Change in fair value of warrants and options		76,253			(12,687	)
Interest income		(1,540	)		(1,302	)
Interest capitalized		(9,463	)		(13,500	)

	$	126,800		$	87,424


13.	Restructuring Charges

In the first quarter of 2008, Trident underwent a reorganization by consolidating five departments and eliminating 15 employment positions and three contract positions within the Company. The cost of the reorganization was $2.4 million for the six month period ended June 30, 2008. Similar restructuring costs were incurred during the first six months of 2007, which included severance costs, retention costs, and third party advisor costs. A total of $17.2 million was expensed during the six month period ended June 30, 2007.


14.	Minority Interests

The components of minority interests are presented below:


	June 30,			December 31,
	2008			2007

Exchangeable shares of subsidiary	$	—		$	4,500
TEC common stock		823			823
Cumulative minority interest recorded in the statement of operations		(823	)		(2,765	)

	$	—		$	2,558

In the six months ended June 30, 2008, Trident cancelled 90,000 shares of a subsidiary as part of a sale transaction of the subsidiary (see note 16). The shares were originally issued in 2006 for gross proceeds of $4.5 million.


15.	Preferred Stock


(a)	Series A Preferred Stock


	June 30,		December 31,
	2008		2007

Balance, beginning of period	$	380,828	$	408,166
Accrued dividends		16,187		38,908
Foreign exchange (gain) loss		11,559		(66,246	)

Balance, end of period	$	408,574	$	380,828

F-14

The number of common stock or amount of cash due upon redemption of the Series A preferred stock and concurrent exercise of the warrant is dependent on the Company’s common stock price on the redemption date. There is no maximum number of shares of common stock that may be issued in the event that the fair value of the Company’s common stock declines.

If the redemption and concurrent exercise of the warrants occurred at June 30, 2008, at which time the estimated fair value of the Company’s common stock was $5.00 per share, the Company would be required to issue 97,951,552 shares of common stock to provide the holders with a return of the face amount of the Series A preferred stock plus a compounded minimum return of 15%.


(b)	Series B Preferred Stock

The number of common stock or amount of cash due upon redemption of the Series B preferred stock and concurrent exercise of the warrant is also dependent on the Company’s common stock price on the redemption date. There is no maximum number of shares of common stock that may be issued in the event that the fair value of the Company’s common stock declines.

The Series B preferred stock are recorded on the balance sheet at their redemption value. If the redemption and concurrent exercise of the warrants occurred at June 30, 2008, at which time the estimated fair value of the Company’s common stock was $5.00 per share, the Company would be required to issue 10,392,716 shares of common stock to provide the holders with a return of the face amount of the Series B preferred stock plus a compounded return of 15%.


16.	Common Stock


(a)	Issued


	Shares
	(Thousands)

Balance, December 31, 2006		27,330
Issued during the year		—

Balance, December 31, 2007		27,330
Issued during the period		29

Balance, June 30, 2008		27,359

In the six months ended June 30, 2008, as part of a transaction that involved the sale of a subsidiary, Trident issued 28,630 shares of common stock and cancelled 90,000 common shares of the subsidiary that were exchangeable into shares of common stock of Trident.

F-15


(b)	Loss per share

For the six months ended June 30, 2008 and 2007:


	2008			2007

Net loss and comprehensive loss	$	(140,028	)	$	(23,889	)
Accrued dividends on Series A preferred stock		(16,187	)		(19,766	)
Foreign exchange gain (loss) on Series A preferred stock		(11,559	)		37,539

Loss attributable to common stockholders	$	(167,774	)	$	(6,116	)

Weighted average number of common stock, basic and diluted (thousands)		27,349			27,330

Basic and diluted loss per share	$	(6.13	)	$	(0.22	)

The following securities have been deemed anti-dilutive and were excluded from Trident’s calculation of net loss per share:


	2008		2007
	(in thousands)

Series A preferred stock		4,994		4,994
Stock options		1,334		2,357
Trident in-substance options		756		756
Warrants		18,205		4,555
Series B preferred stock		614		614
Convertible minority interest stock		180		180

		26,083		13,456


17.	Commitments

Trident has entered into operating leases for office space, office equipment, drilling rigs and vehicles. Future minimum lease payments for these agreements as at June 30, 2008 are as follows:


2008	$	3,494
2009		6,762
2010		3,151
2011		1,768
2012		1,763
Thereafter		1,324

Total lease commitments	$	18,262


18.	Contingencies

The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favor, Trident does not currently believe that the outcome of adverse decisions in any pending proceedings related to these matters or any foreseeable amount which it may be required to pay would have a material adverse impact on its financial position, results of operations or liquidity.

F-16


19.	Supplemental Cash Flow information

During the six month period ended June 30, 2008, Trident paid interest of $29.7 million (2007 – $37.2 million) and income taxes of $nil (2007 – $nil).


20.	Subsequent Events


(a)	Revolving Facility amendment

Subsequent to June 30, 2008, the Revolving Facility was amended to extend its maturity date to October 2, 2009.


(b)	Retirement savings plan

Effective July 1, 2008, the Company established a Retirement Savings Plan (“the Plan”) which includes a Defined Contribution Pension Plan and a Registered Retirement Savings Plan. The expenses for this Plan will be recorded when incurred in general and administrative expenses.


(c)	Risk management contracts

Subsequent to June 30, 2008, the Company entered into fixed price physical delivery commodity sales contracts as follows:

Volume

Weighted Average

Contract Type

(GJ/day)

Pricing Point

Price ($/GJ)

Term

Fixed price

6,200 - 7,000

AECO

6.30 - $7.27

Sep ’08 to Dec ’08

Fixed price

28,600

AECO

7.02 - $7.30

Mar ’09 to Jun ’09


(d)	Subsequent collection of outstanding receivable

Subsequent to June 30, 2008, the Company collected a $35.1 million receivable from a joint venture partner representing twelve months of outstanding receivables to June 30, 2008.


(e)	Warrant cancellation

On September 18, 2008, a former contractor and TEC agreed to decrease the amount of warrants held by the former contractor from 25,000 to 20,000.

F-17

Report of Independent Registered Public Accounting Firm

To The Board of Directors of

Trident Resources Corp.:

We have audited the accompanying consolidated balance sheets of Trident Resources Corp. (“the Company”) and subsidiaries as at December 31, 2007 and 2006, and the related consolidated statements of operations and comprehensive loss, stockholders’ deficit and cash flows for each of the years in the three-year period ended December 31, 2007. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, these consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007 in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Chartered Accountants

Calgary, Canada

March 25, 2008 (except as to Note 27, which is as of November 10, 2008)

F-18

Trident Resources Corp.
Consolidated Balance Sheets
(In thousands of Canadian dollars, except for share data)


	December 31,			December 31,
	2007			2006

ASSETS
Current
Cash	$	134,963		$	117,536
Accounts receivable (note 4)		69,469			75,987
Fair value of risk management contracts (note 5)		5,508			5,772
Prepaid expenses and deposits		2,419			984

Total current assets		212,359			200,279

Property, plant and equipment, full cost method — net (note 6)		633,889			765,449
Intangible assets, net (note 7)		—			5,153
Other assets (note 8)		37,496			24,617

	$	883,744		$	995,498


LIABILITIES
Current
Accounts payable (note 9)	$	25,377		$	70,945
Accrued interest		11,788			13,902
Accrued other liabilities		34,100			63,068

Total current liabilities		71,265			147,915

Long-term debt (note 10)		918,620			870,757
Series A preferred stock embedded derivative		374,525			368,432
Series B preferred stock, 2,000,000 authorized with US$0.0001 par value and 614,000 issued and outstanding at December 31, 2007 and 2006 (note 11)		38,018			44,699
Other long-term liabilities (note 12)		9,185			19,909
Asset retirement obligation (note 13)		19,246			7,298
Minority interests in subsidiary (note 14)		2,558			4,318

	$	1,433,417			1,463,328


SERIES A PREFERRED STOCK
Series A redeemable preferred stock, 8,000,000 authorized with US$0.0001 par value and 4,993,559 issued and outstanding at December 31, 2007 and 2006 (note 15)		380,828			408,166

STOCKHOLDERS’ DEFICIT
Common Stock, $0.0001 par value, 2,490,000,000 authorized with 27,330,727 issued as of December 31, 2007 and 2006		3			3
Paid-in capital		303,492			301,133
Deficit		(1,233,996	)		(1,177,132	)

		(930,501	)		(875,996	)

	$	883,744		$	995,498

Commitments (note 22)
Contingencies (note 24)
Subsequent events (note 27)

The accompanying notes are an integral part of these consolidated financial statements.

F-19

Trident Resources Corp.
Consolidated Statements of Operations and Comprehensive Loss
For the years ended December 31
(In thousands of Canadian dollars, except for share data)


	2007			2006			2005

Revenue
Production revenue	$	201,993		$	139,631		$	40,258

Expenses
Operating — exclusive of depletion and depreciation shown below		59,450			43,086			13,571
General and administrative		20,198			25,378			20,177
Depletion, depreciation and accretion		219,243			766,228			38,800

		298,891			834,692			72,548

Loss from operations		(96,898	)		(695,061	)		(32,290	)

Other income and expenses
Financing charges (note 18)		170,271			292,941			41,845
Restructuring charges (note 19)		20,746			—			—
Gain on disposition of equity investment (note 8)		—			(21,242	)		—
Foreign exchange (gain) loss		(202,109	)		18,631			(11,757	)

		(11,092	)		290,330			30,088

Loss before undernoted items		(85,806	)		(985,391	)		(62,378	)

Taxes
Capital taxes		156			165			1,188
Deferred income taxes (note 20)		—			(64,633	)		(13,366	)

		156			(64,468	)		(12,178	)

Net loss before undernoted items		(85,962	)		(920,923	)		(50,200	)
Earnings (loss) from equity method investment		—			1,663			(400	)
Minority interests		1,760			786			2,363

Net loss and comprehensive loss	$	(84,202	)	$	(918,474	)	$	(48,237	)

Net loss per share (note 16)
Basic and diluted	$	(2.08	)	$	(35.18	)	$	(8.23	)

Weighted average number of shares of common stock outstanding
(thousands)
Basic and diluted		27,330			27,221			24,043

The accompanying notes are an integral part of these consolidated financial statements.

F-20

Trident Resources Corp.
Consolidated Statements of Stockholders’ Deficit
For the years ended December 31
(In thousands of Canadian dollars, except for share data)


	2007			2006			2005

Common stock, $0.0001 par value, 2,490,000 authorized with 27,330,727 issued as of December 31, 2007 and 2006 and 24,470,256 issued as of December 31, 2005
Balance at beginning of year	$	3		$	2		$	2
Issuance of common stock		—			1			—

Balance at end of year		3			3			2

Paid-in capital
Balance at beginning of year		301,133			168,142			103,867
Issuance of common stock		—			142,668			58,254
Common stock issue costs		—			(8,439	)		(2,776	)
Adoption of FAS 123R		—			(13,859	)		—
Fair value of stock-based compensation		2,359			10,123			13,144
Stock option loans		—			4,347			(4,347	)
Repurchase of common stock		—			(1,849	)		—

Balance at end of year		303,492			301,133			168,142

Deficit
Balance at beginning of year		(1,177,132	)		(219,473	)		(21,669	)
Net loss		(84,202	)		(918,474	)		(48,237	)
Accrued dividends on Series A preferred stock		(38,908	)		(37,370	)		(21,223	)
Foreign exchange gain (loss) on Series A preferred stock		66,246			(1,815	)		16,138
Accretion of Series A preferred stock		—			—			(144,482	)

Balance at end of year		(1,233,996	)		(1,177,132	)		(219,473	)

Total stockholders’ deficit at end of year	$	(930,501	)	$	(875,996	)	$	(51,329	)

The accompanying notes are an integral part of these consolidated financial statements.

F-21

Trident Resources Corp.
Consolidated Statements of Cash Flows
For the years ended December 31

(In thousands of Canadian dollars)


	2007			2006			2005

Operating activities
Net loss	$	(84,202	)	$	(918,474	)	$	(48,237	)
Minority interests		(1,760	)		(786	)		(2,363	)
Depletion, depreciation and accretion		219,243			766,228			38,800
Financing charges		125,698			231,371			32,429
Deferred income tax reduction		—			(64,633	)		(13,366	)
Stock-based compensation (recovery)		(599	)		3,137			6,631
Foreign exchange (gain) loss		(202,109	)		18,631			(11,757	)
Gain on disposal of equity investment		—			(21,242	)		—
Unrealized loss (gain) on derivative contracts		264			(5,772	)		—
Earnings from equity method investment		—			(1,663	)		400
Change in non-cash working capital (note 21)		(1,278	)		9,330			(6,116	)

Net cash provided by (used for) operating activities		55,257			16,127			(3,579	)

Financing activities
Long-term debt advances		120,000			689,573			391,393
Long-term debt repayments		—			(141,825	)		(80,957	)
Debt issue costs		(16,700	)		(23,847	)		(16,976	)
Issuance of common stock, net of costs		—			133,540			55,478
Repurchase of common stock		—			(2,058	)		—
Issuance of Series A preferred stock, net of costs		—			—			371,016
Repurchase of Series A preferred stock		—			—			(23,407	)
Issuance of Series B preferred stock		—			42,663			—
Repurchase of preferred stock of subsidiaries		—			—			(20,083	)
Stock and stock option loan repayments (issuances)		—			2,072			(4,347	)
Repurchase of TEC stock options		—			—			(62	)
Issuance of subsidiaries common stock		—			265			—
Change in non-cash working capital (note 21)		(12,043	)		1,027			(619	)

Net cash provided by financing activities		91,257			701,410			671,436

Investing activities
Additions to property, plant and equipment		(89,734	)		(650,693	)		(445,021	)
Purchase of minority interests		—			—			(147,400	)
Acquisitions		—			(2,691	)		(58,043	)
Proceeds from sale of property, plant and equipment		18,605			—			—
Proceeds from sale of equity investment		—			26,207			—
Investments		(41	)		(50	)		(1,967	)
Change in non-cash working capital (note 21)		(57,232	)		(37,150	)		47,452

Net cash used for investing activities		(128,402	)		(664,377	)		(604,979	)

Effect of translation on foreign currency denominated cash		(685	)		(702	)		(8,091	)

Increase in cash		17,427			52,458			54,787
Cash, beginning of year		117,536			65,078			10,291

Cash, end of year	$	134,963		$	117,536		$	65,078

The accompanying notes are an integral part of these consolidated financial statements.

F-22

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005
(Tabular amounts in thousands of Canadian dollars)


1.	Basis of Presentation

Trident Resources Corp. (“Trident”, “TRC” or “the Company”) was incorporated in the State of Delaware on November 7, 2003 for the purpose of investing in Trident Exploration Corp. (“TEC”) and its subsidiaries, a private Canadian company founded in 2000. Trident participates in the acquisition, exploration, development and production of petroleum and natural gas with a principal focus on natural gas from coals. Substantially all of the Company’s operations and production are in Western Canada with certain unproved landholdings in the United States. All of Trident’s proved reserves are located in the Province of Alberta, Canada.


2.	Significant Accounting Policies

These consolidated financial statements have been prepared in conformity with United States generally accepted accounting principles (“GAAP”) within the framework of the accounting policies summarized below.


(a)	Principles of consolidation

These consolidated financial statements reflect the activities of Trident and its subsidiaries. Inter-company transactions and balances are eliminated upon consolidation. Substantially all of Trident’s activities are conducted jointly with others, and accordingly, Trident reflects its proportionate interest in such activities.


(b)	Use of estimates

The timely preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual amounts could differ from the estimated amounts due to factors such as fluctuations in commodity prices, changes in the fair value of the Company’s common stock, interest rates and legislative changes. Significant items subject to such estimates and assumptions include the following:


	•	estimates of proved reserves and related estimates of the present value of future net revenues

	•	carrying value of petroleum and natural gas properties

	•	asset retirement obligations

	•	estimates of common share value and assumptions implicit for calculation of preferred stock embedded derivatives

	•	valuation of derivative financial instruments

	•	obligations related to legal and environmental risks and exposures


(c)	Accounts receivable

Trident’s accounts receivable are with customers and joint venture partners in the petroleum and natural gas business. Receivables are generally due within 60 days. If, after consideration of relevant existing economic conditions, management concludes that the collection of any specific amount due is no longer reasonably assured, an allowance for doubtful accounts is established. During 2007, four purchasers accounted for approximately 31%, 28%, 24%, and 16% of Trident’s total consolidated sales, respectively.

F-23

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)


(d)	Property, plant and equipment

Trident follows the full cost method of accounting for petroleum and natural gas operations. Accordingly, all costs relating to the acquisition, exploration and development of petroleum and natural gas properties, including leasehold costs, geological and geophysical costs, carrying charges of non-producing interests, costs of drilling both productive and non-productive wells, tangible production equipment costs, and general and administrative costs directly related to, and necessary to, exploration and development activities, are capitalized. Proceeds from the disposal of petroleum and natural gas interests are applied against capitalized costs, with no gain or loss recognized in the statement of operations, unless such disposal would alter the rate of depletion by 20% or more.

Costs of unproved properties are not depleted pending determination of the existence of proved reserves. All costs of unproved properties are reviewed quarterly to determine if impairment has occurred. Any amount of impairment assessed is transferred to the costs subject to depletion.

The sum of net capitalized costs and estimated future development and asset retirement costs is depleted on the unit-of-production method, based on proved petroleum and natural gas reserves as determined by independent reservoir engineers. Proved reserve and production volumes are converted to equivalent units on the basis of relative energy content using a ratio of six thousand cubic feet of natural gas to one barrel of crude oil.

The Company performs a ceiling test each quarter. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of: (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated period-end prices excluding asset retirement obligations that have been accrued on the balance sheet; (b) the cost of unproved properties not subject to depletion; (c) the lower of cost or estimated fair value of unproved properties included in the cost being depleted; less (d) income tax effects related to differences in the book and tax basis of petroleum and natural gas properties. If capitalized costs exceed this limit, the excess is charged to depletion expense and reflected as additional accumulated depletion and depreciation.

Other equipment, which consists of furniture, fixtures and office equipment, is recorded at cost and depreciated over their useful lives on a declining basis at 20% per annum.


(e)	Deferred financing charges

Financing charges relating to long-term debt are deferred and amortized over the term of the related debt using the effective interest rate method.


(f)	Asset retirement obligations

Trident records the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, developmentand/or normal use of the assets. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Subsequent to the initial measurement of the asset retirement obligations, the obligations are adjusted at the end of each period to reflect accretion for the passage of time and changes in the estimated future cash flows underlying the obligation.


(g)	Revenue recognition

Natural gas revenue is recognized when title passes to the customer. Revenue from properties in which Trident has an interest with other joint venture partners is recognized on the basis of Trident’s net working interest. Trident’s joint venture operating agreements do not permit the Company to take more than its working interest gas production. Accordingly, Trident uses the entitlement method of accounting for gas-balancing arrangements

F-24

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)

where each owner recognizes revenue based on its ownership share of total gas actually produced during the period, regardless of which owner actually sells and receives payment for the gas.


(h)	Income taxes

Trident uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between financial accounting bases and tax bases of assets and liabilities. The tax benefits of tax loss carry-forwards and other potential future income tax deductions are recorded as an asset to the extent that management assesses the utilization of such assets to be “more likely than not”. If the future utilization of some portion of a deferred tax asset is not determined to be more likely than not, a valuation allowance is provided to reduce the recorded deferred tax asset.


(i)	Stock-based compensation plans

Prior to January 1, 2006, Trident accounted for stock-based compensation using the fair value method as described in the Financial Accounting Standards Board (“FASB”) Statement 123,Accounting for Stock-Based Compensation(“FAS 123”).

Effective January 1, 2006, Trident adopted Statement 123(R),Share Based Payments(“FAS No. 123(R)”), using the modified prospective transition method. Compensation costs continue to be recognized using the accelerated recognition method for options subject to graded vesting. FAS 123(R) requires equity-classified, share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant and to be expensed over the applicable vesting period. Under the modified prospective transition method, share-based awards granted or modified on or after January 1, 2006, are recognized in compensation expense over the applicable vesting period. Also, any previously granted awards that were not fully vested as of January 1, 2006 are recognized as compensation expense over the remaining vesting period. Compensation costs recognized are based on awards ultimately expected to vest and are reduced by estimated forfeitures.

Under FAS 123(R), the liability awards are recognized at fair value rather than intrinsic value as required by FAS 123. At January 1, 2006, the difference between the intrinsic value and the fair value of Trident’s previously classified liability awards was not material.

Compensation costs that are directly related to, and necessary to, exploration and development activities are recorded as property, plant and equipment on the balance sheet with a corresponding increase to either paid-in capital or liabilities. To the extent that compensation costs do not relate to exploration and development activities, they are recorded in the statement of operations. If a stock option is exercised, the consideration received, together with the amount recognized in paid-in capital or liabilities are recorded as an increase to equity.

Stock-based awards granted to contractors that are no longer subject to service requirements are not subject to FAS 123(R) and become subject to other accounting standards. As the maximum number of shares that could be required to be delivered to the holders of the Series A preferred stock exceeds the current number of authorized but unissued shares, there may be insufficient authorized but unissued shares to allow settlement of contractor warrants and vested options by delivering shares. Accordingly, contractor warrants and vested options must be presented as liabilities and are remeasured at their vesting date and at each balance sheet date thereafter. The change in fair value at the vesting date is recognized in equity with subsequent changes in fair value recognized as a change to the amount of recorded liabilities. All shares of common stock that are issued upon the receipt of consideration for the exercise of stock-based awards are issued from treasury.

Temporary differences from stock-based awards classified as both equity and as liabilities that would result in a future tax deduction under existing tax law, will result in the recognition of deferred tax benefits in the income

F-25

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)

statement with a corresponding increase to a deferred tax asset. Tax benefits resulting from tax deductions in excess of the compensation cost recognized for exercised options (“excess tax benefits”) are classified as both an operating cash outflow and a financing cash inflow. As a result of the Company’s net operating losses, the excess tax benefits that would otherwise be available to reduce income taxes payable have the effect of increasing Trident’s net operating loss carry-forwards. Accordingly, because the Company is not currently able to realize these excess tax benefits, such benefits have not been recognized in the statement of cash flows for the years ended December 31, 2007 and 2006.


(j)	Foreign currency translation

Monetary assets and liabilities in foreign currencies are translated to Canadian dollars at exchange rates in effect at the balance sheet date. Non-monetary items, revenues and expenses are translated at rates of exchange in effect at the respective transaction dates. Foreign exchange gains and losses are included in the statement of operations.


(k)	Earnings per share

Basic net loss per share is calculated by dividing the net loss attributable to common shareholders by the weighted average number of common shares outstanding during the period. Diluted per share amounts are calculated using the treasury stock and “if-converted” methods. The treasury stock method recognizes the use of proceeds that could be obtained upon exercise of options and warrants and the associated unamortized stock-based compensation costs in computing diluted earnings per share. It assumes that any proceeds would be used to purchase common shares at the average market price during the period. The if-converted method assumes conversion of convertible securities at the beginning of the reporting period.


(l)	Risk management contracts

Trident periodically enters into derivative financial instrument commodity contracts to mitigate the potential adverse impact of changing commodity prices. The Company does not enter into derivative financial instruments for trading or speculative purposes. The derivative contracts are initiated within the guidelines of the Company’s risk management policy. The Company considers these contracts to be effective hedges on an economic basis but has decided not to designate these contracts as hedges for accounting purposes and, accordingly, an unrealized gain or loss is recorded in production revenue in the statement of operations based on the fair value of the contracts at the balance sheet date. The Company has also entered into fixed price physical commodity sales contracts. Trident has elected to account for fixed price physical delivery natural gas sales contracts as normal sales expected in the normal course of business and accordingly, these contracts are not recorded on the balance sheet.


(m)	Capitalization of interest

Trident capitalizes interest as part of the historical cost of acquiring assets. Petroleum and natural gas investments in unproved properties on which depletion and depreciation expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. As excluded petroleum and natural gas costs are transferred to costs subject to depletion and depreciation, the associated capitalized interest is also transferred to costs subject to depletion and depreciation.


(n)	Recently issued accounting standards

In September 2006, FASB issued Statement 157,Fair Value Measurements (“FAS 157”). FAS 157 defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. FAS 157 is effective for fiscal years beginning after November 15, 2007 (November 15, 2008 for the

F-26

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)

measurement of non-financial assets and liabilities). The Company does not anticipate that the implementation of FAS 157 will have a material impact on consolidated results of operations or financial position.

In February 2007, FASB issued Statement 159,Fair Value Option for Financial Assets and Financial Liabilities(“FAS 159”). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value and applies to other accounting pronouncements that require or permit fair value measurements. FAS 159 is effective for fiscal years beginning after November 15, 2007. The Company does not anticipate that the implementation of FAS 159 will have a material impact on the Company’s results of operations or financial position.

In December 2007, FASB issued Statement 160,Non-controlling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin No. 51(“FAS 160”) which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the non-controlling interest, changes in a parent’s ownership interest and the valuation of retained non-controlling equity instruments when a subsidiary is deconsolidated. The statement also establishes disclosure requirements to clearly identify and distinguish between the interests of the parent and the interest of the non-controlling owners. FAS 160 is effective for fiscal years beginning after December 15, 2008. The Company plans to implement this standard on January 1, 2009. The Company does not expect a material affect on its financial results as a result of adopting this standard on January 1, 2009. When adopted, our minority interest positions on the balance sheet will be presented as a component of equity.

In December 2007, FASB issued Statement 141(R),Business Combinations (“FAS 141R”). FAS 141R provides greater consistency in the accounting and financial reporting of business combinations. It requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed, and requires the acquirer to disclose the nature and financial effect of business combination. FAS 141R is effective on a prospective basis for fiscal years beginning after December 15, 2008.

In March 2008, FASB issued Statement 161Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133, which is effective for fiscal years beginning after November 15, 2008. Statement 161 expands the disclosure requirements for derivative instruments and hedging activities with respect to how and why entities use derivative instruments, how they are accounted for under SFAS No. 133 and the related impact on financial position, financial performance and cash flows. Trident does not expect a material affect on its financial results as a result of adopting this standard on January 1, 2009.

In May 2008, FASB issued Statement 162The Hierarchy of Generally Accepted Accounting Principles which codifies the sources of accounting principles and the related framework to be utilized in preparing financial statements in conformity with GAAP. Trident’s financial statements are not expected to be impacted by this standard.


3.	Change in Accounting Policies

In July 2006, FASB issued Interpretation 48,Accounting for Uncertainty in Income Taxeswith respect to FAS 109Accounting for Income Taxesregarding accounting for and disclosure of uncertain tax positions. This guidance seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. This interpretation is effective for fiscal years beginning after December 15, 2006. Effective January 1, 2007, Trident adopted this Interpretation, which did not have an impact on the Company’s results of operations or financial position.

F-27

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)


4.	Accounts Receivable


	2007		2006

Joint interest billings	$	46,661	$	43,223
Accrued production revenue		20,746		22,428
Goods and services tax		266		8,703
Due from officers, employees and related parties		—		245
Other		1,796		1,388

	$	69,469	$	75,987

At December 31, 2007 and 2006, Trident did not have a provision for doubtful accounts.


5.	Risk Management Contracts

During the year ended December 31, 2007, Trident entered into costless collar derivative contracts and fixed price commodity sales contracts. The costless collar contracts establish floor and ceiling prices on anticipated future natural gas production. The fair value of the costless collar contracts at December 31, 2007 was $5.5 million (2006 – $5.8 million) and has been recorded as an asset on the balance sheet, with changes in fair value recorded in production revenue in the statement of operations. Fixed price contracts represent physical delivery contracts and are recorded as production revenue upon delivery. At December 31, 2007, the Company had the following risk management contracts:

Volume

Weighted Average

Contract Type

(GJ/day)

Pricing Point

Price ($/GJ)

Term

Costless Collar(1)

36,000

AECO

$7.15 - $10.14

Jan ’08 to Mar ’08

Costless Collar(1)

10,000

AECO

$7.00 - $ 8.83

April 2008

Costless Collar(1)

20,000

AECO

$7.00 - $ 8.29

May ’08 to Sep ’08

Costless Collar(1)

10,000

AECO

$7.00 - $ 8.83

October 2008

Fixed price(2)

1,000 - 33,500

AECO

$6.21 - $ 8.15

Jan ’08 to Feb ’09


(1)		Costless collar strike prices indicate minimum floor and maximum ceiling

(2)		Physical delivery


6.	Property, Plant and Equipment


	2007			2006

Properties subject to depletion	$	1,324,828		$	1,179,320
Properties not subject to depletion		320,373			396,291
Accumulated depletion		(1,013,778	)		(813,405	)

		631,423			762,206

Office equipment, furniture and fixtures		5,776			5,650
Accumulated depreciation		(3,310	)		(2,407	)

		2,466			3,243

	$	633,889		$	765,449

In 2007, the net carrying amount of properties subject to depletion exceeded the discounted future net revenues from proved reserves by $112.8 million in aggregate from quarterly ceiling tests and was recognized as additional

F-28

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)

depletion expense. For the year ended December 31, 2007, depletion, depreciation and accretion per BOE was $19.09 (2006 – $24.73; 2005 – $25.86) excluding the effects of the ceiling test write-downs and asset impairments. The carrying value of Trident’s property, plant and equipment consists of $613.5 million of net assets located in Canada and $20.4 million of net assets located in the United States (2006 – $745.0 million in Canada and $20.4 million in the United States). During the year, the Company capitalized $10.5 million of general and administrative costs (2006 – $16.7 million; 2005 – $19.9 million) and interest costs of $23.4 million (2006 – $18.1 million; 2005 – $6.6 million).


7.	Acquisitions


(a)	Rakhit Petroleum Consulting Ltd.

Effective January 1, 2006, a wholly-owned subsidiary of Trident purchased certain assets of Rakhit Petroleum Consulting Ltd. (“Rakhit”) for an aggregate amount of $6.0 million. The purchase price was paid with 90,000 exchangeable shares of common stock of the subsidiary and $1.5 million in cash. At the purchase date, the estimated fair value of the subsidiary’s common stock was $50.00 per share. The stock was exchangeable into Trident common stock on a one-for-one basis. Rakhit provided petroleum consulting services specializing in the application of hydrodynamics, geology and hydrogeology for petroleum exploration and development, including coalbed methane. The net assets acquired consisted of $7.7 million of intangible assets, $0.6 million of property, plant and equipment and a $2.3 million deferred income tax liability. During 2007, Trident wrote off the remaining unamortized value of the intangible assets and subsequent to year-end, Rakhit was sold back to its original owner. As part of the sale, Trident maintains a license to Rakhit studies that were part of the original purchase and 28,630 of the exchangeable shares were converted to common shares. Any remaining outstanding exchangeable shares were eliminated upon closing of the transaction.


(b)	Former shareholders

On December 30, 2005, Trident completed the purchase of a significant shareholder’s interest in TEC common and preferred stock, held directly and indirectly, along with its entire working interest in the Mannville CBM operations for an aggregate amount of US$175.0 million (C$202.6 million). The transaction reduced the minority interests in Trident. Prior to the transaction, the significant shareholder held, directly and indirectly, 2,948,120 shares of TEC common stock and 2,006,951 shares of TEC preferred stock.

The purchase of these interests included multiple components with the aggregate proceeds allocated to each component based on their respective fair values. The $20.1 million fair value of the 2,006,951 TEC preferred stock repurchased equaled their carrying amount and the fair value of the Mannville CBM assets was $35.1 million. The purchase of the 2,948,120 TEC common stock was considered a repurchase of minority interests which was accounted for using the purchase method. The estimated fair values of the assets acquired and liabilities assumed at the date of acquisition are as follows:


Property, plant and equipment	$	207,537
Other assets		347
Net deferred income tax liability		(69,245	)
Minority interest		8,761

	$	147,400

Results of operations from the Mannville CBM area working interest are included in Trident’s statement of operations commencing December 30, 2005.

F-29

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)


8.	Other Assets


	2007		2006

Deferred financing charges, net of accumulated amortization	$	37,246	$	24,267
Investments		250		350

	$	37,496	$	24,617

On August 11, 2006, Trident disposed of its equity investment in Ammonite Drilling Ltd. for cash consideration of $26.2 million which resulted in a $21.2 million gain.

Costs amounting to $27.5 million related to financing raised in August 2007 were charged to deferred financing charges during the year.


9.	Accounts Payable


	2007		2006

Trade	$	25,377	$	55,724
Due to lenders		—		12,500
Due to related party		—		2,315
Other		—		406

	$	25,377	$	70,945


10.	Credit Facilities

The credit facilities restrict TEC from paying any dividends or distributions to Trident for anything other than general corporate expenses incurred in the normal course of business. In each of 2007 and 2006, no cash dividends were paid to Trident by any subsidiaries.


(a)	Revolving facility

At December 31, 2007, TEC held a364-day secured revolving facility (“Revolving Facility”) with a maximum availability of $10 million. The Revolving Facility bears interest at a rate of bank prime plus 1% for Canadian or U.S. prime rate loans and bank prime plus 2% for LIBOR loans, bankers’ acceptances and letters of credit. The Revolving Facility has a commitment fee of 0.5% per annum on undrawn amounts and is also used to issue letters of credit. The Revolving Facility’s borrowing base is based on the lender’s assessment of the fair value of the proved reserves of TEC.

The Revolving Facility is secured by all of the present and future assets of TEC and contained a financial covenant that required the maintenance of a minimum tangible net worth (as defined in the agreement). Prior to December 31, 2007, the lender waived compliance of this covenant for measurement at December 31, 2007. In March 2008, the covenant was deleted and on October 3, 2008 the Revolving Facility was extended to October 2, 2009 (see note 27). At December 31, 2007, the Company had $nil drawn and letters of credit of $9.6 million issued under the Revolving Facility.

F-30

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)


(b)	Long-term debt


	2007			2006

Second lien secured syndicated term loan facility (US$500 million)	$	495,650		$	582,700
Discounts on second lien facility		(1,766	)		(2,175	)

Second lien secured syndicated term facility, net of discount		493,884			580,525

Subordinated facility (US$270 million plus accrued interest)		323,805			320,350
Discounts and warrants on subordinated facility		(24,839	)		(30,118	)

Subordinated facility, net of discount and warrants		298,966			290,232

2007 unsecured facility (C$120 million plus accrued interest)		125,770			—

	$	918,620		$	870,757

On April 26, 2005, TEC entered into a second lien secured syndicated term loan facility (“Secured Facility”) for US$175.0 million and drew the entire amount of the Secured Facility. On December 16, 2005, Trident amended the Secured Facility for an additional US$150 million and drew US$100.0 million prior to December 31, 2005. In April 2006, the remaining US$50.0 million was drawn. On April 25, 2006, Trident amended its Secured Facility to increase the maximum available to draw to US$450.0 million and drew the incremental US$125.0 million on that date. The amended Secured Facility matures April 26, 2011 and principal is due at maturity. On October 25, 2006, Trident further amended the Secured Facility to increase the maximum available to US$500.0 million and drew the incremental US$50.0 million (US$42.1 million after fees, expenses and a US$2.0 million discount). The incremental US$50.0 million matures April 26, 2012. In association with the October 25, 2006 amendment, Trident was required to raise US$75 million of additional capital. In addition, Trident was required to enter into, and maintain, derivative commodity contracts for minimum production levels between 33,000 gigajoules (“GJ”) and 49,500 GJ per day from November 2006 through April 2008. In August 2007, these levels were amended to minimum production levels between 28,500 GJ and 52,500 GJ per day from September 2007 to February 2009. Interest on the entire US$500 million accrues at LIBOR plus 7.5% per annum. The effective rate for this facility is LIBOR plus 7.6% as a result of the discount. The effective interest rate on this facility at December 31, 2007 was 12.5% per annum.

The Secured Facility has a cross covenant which requires Trident to comply with the Revolving Facility covenants. The Secured Facility has certain financial covenants including a maximum total debt to earnings before interest, taxes, depletion, depreciation, amortization, extraordinary losses and other non-cash expenses as defined in the agreement and an interest coverage ratio. The Secured Facility also requires a minimum present value of proved reserves to total debt ratio. Concurrent with the $120.0 million subordinated Unsecured Credit Facility (“2007 Unsecured Facility”) that was completed on August 20, 2007, all financial covenants have been waived until the quarter ending June 30, 2008, on all existing debt facilities, with the exception of the Revolving Facility covenant. During December 2007, Trident received a waiver on the Revolving Facility covenant for the period ending December 31, 2007. In March of 2008, the covenant was deleted (see note 27).

On November 24, 2006, Trident entered into a US$270.0 million subordinated credit facility (“Subordinated Facility”). Draws of US$75 million on November 27, 2006 from the Subordinated Facility satisfied the additional capital requirement of the Secured Facility. The Subordinated Facility matures on November 24, 2011 and accrues interest at LIBOR plus 12.0% per annum. The effective interest rate is LIBOR plus 13.1% per annum as a result of discounts applied. Interest is payable in kind for the first two years to be extended for a third year at Trident’s option. If the third year option is exercised, the interest rate increases by 2% per annum to LIBOR plus 14.0% per annum. Principal is due at maturity. The Subordinated Facility has substantially the same covenants as the Secured Facility. If the Secured Facility is paid off or refinanced without covenants, the Subordinated Facility’s covenants are eliminated. The effective interest rate on this facility at December 31, 2007 was 18.0% per annum.

F-31

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)

In conjunction with the Subordinated Facility, Trident issued warrants (“Subordinated Facility Warrants”) to the lenders to purchase 4,500,000 shares of Trident common stock at the lower of $25.00 per share or 20.0% below either an initial public offering (“IPO”) price or a price used in the event of a change of control. The warrants are exercisable at the earlier of (a) the date that is one year and one day after the consummation of an IPO, (b) November 25, 2013, or (c) the date that is immediately prior to a change of control. The warrants terminate on the earliest date of (a) seven years after the effective date of an IPO, (b) seven years after a partial change of control (as defined in the agreement), or (c) the consummation of a change of control.

The Subordinated Facility Warrants are recorded as long-term liabilities as the maximum number of shares that could be required to be delivered to the holders of the Series A preferred stock exceeds the current number of authorized but unissued shares. As a result, there may be insufficient authorized but unissued shares to allow settlement of the Subordinated Facility Warrants by delivering common stock. Accordingly, the estimated fair value of the Subordinated Facility Warrants is presented as a liability on the consolidated balance sheets with changes in the fair value recorded in the statement of operations in the period they occur (see notes 12 and 18). The fair value of the Subordinated Facility warrants is calculated each balance sheet date using the Black-Scholes option-pricing model.

At the date of issuance, the estimated fair value of the warrants was $18.5 million and was recorded as a discount to long-term debt with an offset to long-term liabilities. The discount is amortized through financing charges over the term of the Subordinated Facility.

On August 20, 2007, Trident drew $120.0 million under the 2007 Unsecured Facility. The 2007 Unsecured Facility matures August 31, 2012 and bears interest at LIBOR plus 7.5% per annum. Interest is payable in kind and the principal is due at maturity. The 2007 Unsecured Facility does not have any financial covenants. In conjunction with the issuance of the 2007 Unsecured Facility, covenants in both the Secured Facility and the Subordinated Facility have been eliminated until June 30, 2008.

Principal repayments for the Company’s long-term debt are scheduled as follows:


2008	$	—
2009		—
2010		—
2011		769,890
2012		175,335
Thereafter		—

Total principal repayments	$	945,225


(c)	Lenders’ warrants

In connection with an initial draw on a subordinated facility in 2004, Trident issued 735,124 warrants to the lenders (“2004 Lenders’ Warrants”). Each 2004 Lenders’ Warrant entitles the holder to purchase one share of Trident common stock for $18.93. As part of the settlement of that facility and an anti-dilution clause, an additional 92,366 2004 Lenders’ Warrants were issued in 2005. Each of the 2004 Lenders’ Warrants was subject to a call right of Trident and a put right of the holder. The 2004 Lenders’ Warrants may be settled in cash or common stock at the holder’s discretion. The fair value of the warrants was recognized as a long-term liability with an offset to the subordinated facility balance. As a result of subsequent common share issuances at $50.00 per share, the 2004 Lenders’ Warrant holders have the right to put all of the outstanding warrants for a maximum cash payment of $12.5 million or 356,231 shares of common stock. The $12.5 million potential payment was recognized as a

F-32

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)

financing charge in 2005. In 2006, the holders of the 2004 Lenders’ Warrants exercised their cash put rights on all of the warrants and in 2007, Trident paid the $12.5 million to the lenders.

In conjunction with the Unsecured Facility issued on August 20, 2007, Trident issued 13.7 million detachable warrants to purchase shares of Trident common stock (“Unsecured Lender’s Warrants”). The warrants have an exercise price of $0.0001 per share and are exercisable for a period of 7 years after January 1, 2008. As the maximum number of shares that could be required to be delivered to the holders of the Series A preferred stock exceeds the current number of authorized but unissued shares, there may be insufficient authorized but unissued shares to allow settlement of the Unsecured Lender’s Warrants. Accordingly, the estimated fair value of the Unsecured Lender’s Warrants is presented as a liability on the consolidated balance sheets with changes in the fair value recorded in the statements of operations in the period they occur. The fair value of the Unsecured Lender’s Warrants is calculated at each balance sheet date using the Black-Scholes option pricing model. At the date of issuance and at December 31, 2007, the estimated fair value of the Unsecured Lender’s Warrants is $nil.


11.	Series B Preferred Stock

At December 31, 2007, there were 2,000,000 Series B preferred stock authorized with US$0.0001 par value. In 2006, Trident issued 614,000 units for gross proceeds of US$38.4 million. Each unit consists of one share of Series B preferred stock with a face amount of US$62.50 per share and one warrant exercisable for the purchase of, initially, one share of common stock. In conjunction with the closing of the Unsecured Facility in August 2007, the conversion rate of a Series B preferred stock unit and associated warrant into a share of common stock was revised to a ratio of one unit exercisable for 1.4814 shares of common stock. All other terms associated with exercise of the warrant have remaining unchanged from the original issuance. The warrant can only be exercised at the time of redemption of the associated shares of Series B preferred stock. A share of Series B preferred stock can only be redeemed if the associated warrant is simultaneously exercised.

The Series B preferred stock are mandatorily redeemable on the earlier of March 10, 2013 or the consummation of a public offering of common stock with gross proceeds exceeding US$50.0 million. The Series B preferred stock are redeemable at the option of the holder at any time after March 10, 2008 or in connection with a change in control. Trident may also elect to redeem the Series B preferred stock after March 10, 2008, subject to the condition that no debt restrictions exist that would otherwise prevent the Company from doing so, or in connection with a change of control. The holder of a unit may elect to put the common stock received on redemption for cash upon maturity of the Series B preferred stock or if Trident elects to redeem the Series B preferred stock at any time after March 10, 2008 or upon a change in control. Upon consummation of a public offering or redemption at the holder’s election, the holder will receive common stock.

The Series B preferred stock earn dividends at 7% per annum. In the event that the value of Trident’s common stock at the time of redemption of a share of preferred stock and exercise of its corresponding warrant is such that, upon such redemption and exercise, the holder would receive less than a 15% annually compounded return, the Company will issue additional shares of common stock as necessary to bring the holder’s compounded return up to 15%. In the event that the value of Trident’s common stock at the time of redemption of a share of preferred stock and exercise of its corresponding warrant is such that, upon such redemption and exercise, the holder would receive more than a 15% annually compounded return, the holder will pay to the Company such amount necessary to reduce the holder’s compounded return to 15%. The holder has the option to either pay this amount to the Company in cash or to forego an equivalent value in common stock by accepting less than one share of common stock for each warrant. The number of common stock due upon redemption of the Series B preferred stock and concurrent exercise of the warrant is dependent on the Company’s common stock price on the redemption date. There is no maximum number of shares of common stock that may be issued in the event that the fair value of the Company’s common stock declines. As the fair value of the Company’s common stock is estimated as $nil, the number of shares to issue would be infinite if the redemption were to occur at December 31, 2007.

F-33

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)

The Series B preferred stock are considered liabilities as they will be settled by issuing a variable number of shares of common stock or cash. Interest is accrued at 15% per annum.


12.	Other Long-Term Liabilities


	2007		2006

Subordinated Facility Warrants (note 10(b))	$	—	$	12,686
Accrued interest on Series B preferred stock (note 11)		9,185		3,575
Contractors vested options		—		1,875
Other stock-based compensation awards		—		1,773

	$	9,185	$	19,909


13.	Asset Retirement Obligation

Trident’s asset retirement obligation results from net ownership interests in petroleum and natural gas interests including well sites, gathering systems and processing facilities. Trident estimates that the total undiscounted inflation-adjusted amount of cash flows required to settle its asset retirement obligation is approximately $42 million, which will be incurred between 2008 and 2025. A credit-adjusted risk-free rate of 15.4% was used to calculate the asset retirement obligation.


	2007		2006		2005

Balance, beginning of year	$	7,298	$	5,552	$	3,112
Accretion expense		1,943		524		256
Revision in estimated cash flow		—		—		(274	)
Liabilities incurred		10,005		1,222		2,458

	$	19,246	$	7,298	$	5,552


14.	Minority Interests

The components of minority interests are presented below:


	2007			2006

Exchangeable shares of subsidiary (note 7(a))	$	4,500		$	4,500
TEC common stock (180,000 shares)		823			823
Cumulative minority interest recorded in the statement of operations		(2,765	)		(1,005	)

Balance, end of year	$	2,558		$	4,318

Holders of TEC common shares are able to exchange one TEC common share for one Trident common share.


15.	Series A Preferred Stock

At December 31, 2007, there were 8,000,000 Series A preferred stock authorized with US$0.0001 par value. In 2005, Trident issued 5,104,311 units for gross proceeds of US$319.1 million before share issue costs of $16.4 million. In addition, holders of preferred stock of subsidiaries exchanged 1,667,714 preferred stock of subsidiaries for 209,248 units in the amount of US$13.1 million. At December 31, 2006 and 2007, there were 4,993,559 units issued and outstanding.

F-34

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)

Each unit consists of one share of Series A preferred stock with a face amount of US$62.50 per share and one warrant exercisable for the purchase of, initially, one share of common stock. In conjunction with the closing of the Unsecured Facility in August 2007, the conversion rate of a Series A preferred stock unit and associated warrant into a share of common stock was revised to a ratio of one unit exercisable for 1.4814 shares of common stock. All other terms associated with exercise of the warrant have remaining unchanged from the original issuance. The warrant can only be exercised at the time of redemption of the associated shares of Series A preferred stock. A share of Series A preferred stock can only be redeemed if the associated warrant is simultaneously exercised.

The shares of Series A preferred stock are mandatorily redeemable on the earlier of March 10, 2013 or the consummation of a public offering of common stock with gross proceeds exceeding US$50.0 million. The shares of Series A preferred stock are redeemable at the option of the holder at any time after March 10, 2008, or in connection with a change of control. Trident may also elect to redeem the Series A preferred stock after March 10, 2008, or in connection with a change of control, subject to the condition that no debt restrictions exist that would otherwise prevent the Company from doing so. The holder of a unit may elect to put the common stock received on redemption for cash upon maturity of the Series A preferred stock or if Trident elects to redeem the Series A preferred stock at any time after March 10, 2008 or upon a change of control. Upon consummation of a public offering or redemption at the holder’s election, the holder will receive common stock.

The Series A preferred stock earn dividends at 9% per annum for the first 24 months after issuance and 11% per annum thereafter.

Upon redemption of a share of Series A preferred stock and exercise of the warrant, the number of shares of common stock issued will be adjusted if necessary, (a) either upward for the holder to receive a minimum annual compounded return, or downward for the holder to receive a maximum annual compounded return; and (b) to return the Series A preferred stock’s face amount of US$62.50 per share. The downward adjustment may be paid in cash rather than common stock at the option of the holder. The minimum and maximum annual compounded return is determined based on the date the Series A preferred stock are redeemed and the warrants are concurrently exercised, as follows:


Redemption Date		Minimum Return

Before March 10, 2006		19%
March 10, 2006 to March 9, 2007		17%
March 10, 2007 to March 9, 2013		15%
After March 10, 2013		an additional 1% per year


Redemption Date	Maximum Return

Before March 10, 2006		30	%
March 10, 2006 to March 9, 2007		25	%
March 10, 2007 to March 9, 2008		22	%
March 10, 2008 to March 9, 2009		20	%
March 10, 2009 to March 9, 2010		19	%
After March 10, 2010		18	%

The above noted minimum and maximum return feature on redemption comprising (a) the minimum and maximum compounded annual return; and (b) the return of the difference between the face amount and the fair value of the common stock was determined to be an embedded derivative. Accordingly, a portion of the gross proceeds received on issuance of the units was attributed to this embedded derivative and recorded as a liability at its fair value. The carrying amount of the Series A preferred stock was calculated as the gross proceeds received on issuance of the units less the value attributed to the embedded derivative at issuance. The Series A preferred stock

F-35

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)

are classified as temporary equity as the holder has a contingent right to put for cash the common stock received on redemption of the Series A preferred stock and concurrent exercise of the warrant. The difference between the original carrying amount recorded on issuance of the Series A preferred stock and their face amount was recognized as an additional charge to deficit on the issuance date. Dividends on the Series A preferred stock are recognized in the statement of stockholders’ equity (deficit).


Series A Preferred Stock	2007			2006		2005

Balance, beginning of year	$	408,166		$	368,981	$	—
New issues, net of costs		—			—		242,290
Accretion		—			—		144,482
Repurchases		—			—		(22,876	)
Accrued dividends		38,908			37,370		21,223
Foreign exchange (gain) loss		(66,246	)		1,815		(16,138	)

Balance, end of year	$	380,828		$	408,166	$	368,981

In July 2005, Trident repurchased 320,000 units at a 3% discount from the issuance price without deemed dividends or interest for a total purchase price of US$19.4 million (C$23.4 million).

The number of common stock or amount of cash due upon redemption of the Series A preferred stock and concurrent exercise of the warrant is also dependent on the Company’s common stock price on the redemption date. There is no maximum number of shares of common stock that may be issued in the event that the fair value of the Company’s common stock declines.

As the fair value of the Company’s common stock was estimated as $nil for December 31, 2007, the number of shares to issue would be infinite if the redemption were to occur on that date.

The Series A preferred stockholders vote together with the common stockholders as a single class. The Series A preferred stockholders also have certain separate voting rights. The Series A preferred stock rank senior to the Company’s common stock as to dividends and distributions of assets. Trident cannot pay any cash dividends or cash distributions or make any other cash payment in respect of the common stock unless all accrued dividends on the Series A preferred stock have been paid in full in cash.

The estimated fair value of the Series A preferred stock embedded derivative is presented as a liability on the consolidated balance sheet with changes in the fair value recorded in the statement of operations in the period they occur. The fair value of the embedded derivative is calculated each balance sheet date using the Black-Scholes option-pricing model incorporating management’s estimates, including the expected method and timing for settling the Series A preferred stock. The Series A preferred stock are denominated in U.S. dollars, and accordingly, foreign exchange gains and losses on the embedded derivative recorded on the balance sheet are recognized in the statement of operations in the period they occur.


16.	Common Stock


(a)	Issued and outstanding

At December 31, 2007, there were 2,490,000,000 (December 31, 2006 – 50,000,000; December 31, 2005 – 50,000,000) voting common stock authorized with US$0.0001 par value.

F-36

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)


Number of Outstanding Common Shares (000s)	2007		2006		2005

Balance, beginning of year		27,330		24,470		23,271
Issued during the year		—		2,860		1,199

Balance, end of year		27,330		27,330		24,470

In 2006, Trident issued 2,860,471 shares of common stock for gross proceeds of $142.2 million before share issue costs of $8.4 million. In 2005, the Company issued 1,198,985 shares of common stock for gross proceeds of $58.2 million before share issue costs of $2.7 million.

At December 31, 2007, management’s estimated fair value of Trident common stock was $nil (December 31, 2006 – $10.00; December 31, 2005 – $50.00). Changes in the estimated fair value of the Company’s common stock price have a material impact on the financial statements. It is reasonably possible that the estimate of the fair value of the Company’s common stock will change in the near term. The magnitude of this change cannot be reasonably estimated.


(b)	Loss per share

For the years ended December 31, 2007, 2006 and 2005:


	2007			2006			2005

Net loss and comprehensive loss	$	(84,202	)	$	(918,474	)	$	(48,237	)
Accretion of Series A preferred stock		—			—			(144,482	)
Accrued dividends on Series A preferred stock		(38,908	)		(37,370	)		(21,223	)
Foreign exchange gain (loss) on Series A preferred stock		66,246			(1,815	)		16,138

Loss attributable to common stockholders	$	(56,864	)	$	(957,659	)	$	(197,804	)

Weighted average number of common stock, basic and diluted (thousands)		27,330			27,221			24,043

Basic and diluted loss per share	$	(2.08	)	$	(35.18	)	$	(8.23	)

The following securities have been deemed anti-dilutive and were excluded from Trident’s calculation of net loss per share:


	2007		2006		2005
	(In thousands)

Series A preferred stock		4,994		4,994		4,994
Stock options		2,096		3,036		2,495
Warrants		18,205		4,555		853
Trident in-substance options		756		756		756
Series B preferred stock		614		614		—
Convertible minority interest stock		180		180		180

		26,845		14,135		9,278


17.	Stock-Based Compensation

For the year ended December 31, 2007, a stock-based compensation recovery of $0.6 million reduced expenses (2006 – $3.1 million expense; 2007 – $7.0 million expense) and a $0.7 million stock-based compensation recovery

F-37

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)

was capitalized (2006 – $4.7 million recovery; 2005 – $10.3 million charge). In 2007 and 2006, no amount was recognized as a tax benefit in the statement of operations.


(a)	TEC stock options

Trident has a stock option plan under which the Board of Directors may grant stock options to directors, officers, employees, and consultants for the purchase of shares of TEC common stock. The options are granted at the estimated fair value of the TEC common stock at the grant date. The maximum number of options to be granted under the plan is 3.1 million. Trident issues new shares of common stock to settle options exercised. On March 29, 2006, the Board of Directors approved a modification of the stock option plan. Upon exercise, holders of TEC options will have the option of receiving Trident shares.

The fair value of stock options are estimated on the date of the grant, using a Black-Scholes option pricing model that incorporates the assumptions as noted in the table below. The contractual term of stock options granted is 10 years and the options typically vest over four years. Commencing January 1, 2006, the expected term was calculated based on the simplified method due to the limited history of actual employee exercise behaviour and post-vesting termination behaviour. For purposes of the calculation, the employees were divided into two groups (executives and non-executives) based on expected employee exercise behaviour and post-vesting termination behaviour. Expected volatility is based on the historical volatility of a peer group of similar companies, comparable in industry and size, for a period equivalent to the expected term as it was not practicable to estimate Trident’s expected volatility due to the limited market data available for share transactions. Expected forfeitures are based on actual historical experience and an analysis of the same peer group. The risk free rate is based on the zero-coupon yield curve for Bank of Canada bonds with a term equivalent to the expected term.


	2006			2005

Risk-free interest rate (%)		4.2	%		4.2	%
Expected life (years)		6.3			6.3
Expected dividends ($)		nil			nil
Expected volatility (%)		45.0	%		40.0	%

Option activity for years ended December 31, 2007, 2006 and 2005 was as follows:


	Number of			Weighted		Exercisable at		Weighted
	Options			Average Exercise		Year-End		Average Exercise
	(Thousands)			Price		(Thousands)		Price

Balance, December 31, 2004		2,145			11.88		548		7.62
Granted		415			38.49
Forfeited		(63	)		23.91
Exercised		(2	)		8.40

Balance, December 31, 2005		2,495			16.01		1,003		9.08
Granted		645			50.59
Forfeited		(38	)		39.57
Exercised		(66	)		9.11

Balance, December 31, 2006		3,036			23.21		1,395		11.82
Forfeited		(940	)		26.75

Balance, December 31, 2007		2,096			21.61		1,376		14.15

F-38

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)

Details on options outstanding at December 31, 2007 are as follows:


		Options Outstanding				Exercisable Options
		Number of		Weighted		Exercisable at
		Options		Average		Year-End
Exercise Price		(Thousands)		Remaining Term		(Thousands)		Exercise Price

$	4.20		248		4.6		248	$	4.20
	5.30		90		4.6		90		5.30
	8.40		279		4.6		279		8.40
	13.00		130		5.6		130		13.00
	14.00		313		6.3		276		14.00
	16.50		497		6.8		189		16.50
	18.70		3		7.3		2		18.70
	50.00		439		8.0		138		50.00
	53.00		97		8.8		24		—

$	21.60		2,096		6.3		1,376		14.15

At December 31, 2007, there were 1,695,071 (2006 – 2,558,671; 2005 – 1,950,500) options outstanding to employees and 401,125 (2006 – 477,525; 2005 – 544,375) options outstanding to consultants. At December 31, 2007, the intrinsic value of all outstanding options was $nil.

There were no options issued in 2007 and, consequently, there was not a weighted average fair value of options granted (2006 – $23.80; 2005 – $16.36). The stock options vested and exercisable at December 31, 2007 had an aggregate intrinsic value of $nil and a weighted average remaining term of 5.7 years.

At December 31, 2007, approximately $2.4 million of compensation cost relating to unvested stock options has not yet been recognized. The weighted average period over which these costs are expected to be recognized is 1.5 years. No cash has been received from options exercised in 2007 (2006 – $0.3 million; 2005 – $nil). The total intrinsic value of options exercised was $2.8 million in 2006 (2005 – $nil).


(b)	Trident in-substance options

F-39

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)

exercise price falls below $0.50 per share. The combination of the common stock and purchased call option has substantially the same characteristics as the grant of stock options. Accordingly, this arrangement is accounted for as a modification of an existing award in accordance with the Company’s policy on stock-based compensation. Consistent with the accounting for the promissory notes, because the shares sold subject to the call options are considered stock options, neither the shares outstanding nor the purchased call options are recorded on the balance sheet. As this new arrangement does not have a service period, $1.5 million of previously deferred costs plus $1.4 million of incremental costs were recognized in the third quarter of 2006.

At December 31, 2007, the intrinsic value of the Trident in-substance options was $nil (2006 – $nil). The two individuals are no longer employed by the Company.


(c)	Stock option loan program

On June 23, 2005, the Board of Directors approved a program (the “stock option loan program”) whereby employees are permitted to borrow from Trident, an amount up to 50% of the July 1, 2005 intrinsic value of their vested TEC stock options or Trident in-substance stock options up to a maximum of $2.0 million per employee (US$2.0 million per U.S. based employee). Up to 25% of the intrinsic value of vested stock options as of July 1, 2005 may be borrowed immediately (up to a maximum of $0.5 million per employee, or US$0.5 million per U.S. based employee) and the remaining 25% of the intrinsic value of vested options on the date at which Trident achieves a weekly average production rate of 125 mmcf per day. The loans bear interest at the Canada Revenue Agency’s prescribed rate and are secured by the employees’ stock options in an amount equal to double the loan amount.

Due to the decrease in the estimated fair value of the Company’s common stock, holders of the stock option loans are incented to forfeit the options given as collateral rather than repay the loan. Accordingly, in 2007, Trident recorded a $0.3 million (2006 – $1.6 million) charge to general and administrative expense to recognize an impairment of the outstanding loans to employees, reducing the carrying value for these loans to $nil (2006 – $0.3 million). These loans have not been forgiven.


(d)	TEC deferred stock units

On December 17, 2004, the Board of Directors granted 245,000 deferred stock units to members of senior management. Members of senior management will receive a cash payment equal to the number of deferred stock units multiplied by the fair value of one Trident common share on the vesting date. The deferred stock units vest at the earlier of four years after the grant date, the date of a change of control, or two years after Trident becomes a public corporation. During 2007, Trident wrote off the value of the deferred stock units to $nil based on the current value of the common stock of the Company (see note 27).

F-40

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)


(e)	Contractors warrants

In 2006, the Company granted 30,000 warrants to a contractor that have an exercise price of $50.00 per common share and expire in 2012.

In 2004, Trident issued 1,000 warrants to a former contractor that had an exercise price of $10.75 and expired in 2012. In 2005, 500 warrants were exercised and cancelled via a settlement of cash. In 2006, the remaining warrants were exercised and cancelled via a settlement of cash.

In 2003, Trident issued 25,000 warrants to a former contractor that have an exercise price of $4.20 per share and expire in 2012 (see note 27). These warrants may be settled for cash at the Company’s option.


18.	Financing Charges


	2007			2006			2005

Change in fair value of Series A preferred stock embedded derivative	$	61,134		$	219,802		$	10,424
Interest expense on credit facilities		131,064			79,502			19,004
Amortization of deferred financing charges		9,540			19,588			8,293
Accrued interest on Series B preferred stock		6,657			3,461			—
Change in fair value of Subordinated Facility Warrants		(12,687	)		(5,809	)		—
2004 subordinated facility financing charges		—			—			14,840
Interest income		(2,030	)		(5,493	)		(4,142	)
Interest capitalized		(23,407	)		(18,110	)		(6,574	)

	$	170,271		$	292,941		$	41,845


19.	Restructuring Charges

In the first quarter of 2007, Trident began a significant organizational restructuring. As a result, $20.7 million of severance charges, retention costs and third party advisor charges were recognized during the year.


20.	Income Taxes

The provision for income taxes is comprised of:


	2007		2006			2005

Current state	$	156	$	165		$	150
Current federal		—		—			1,038
Deferred		—		(64,633	)		(13,366	)

	$	156	$	(64,468	)	$	(12,178	)

F-41

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)

The provision for taxes reflects an effective tax rate which differs from the statutory federal tax rate. Differences were attributable to the following:


	2007			2006			2005

Loss before taxes	$	(85,806	)	$	(985,391	)	$	(62,378	)
Statutory federal income tax rate		35.0	%		35.0	%		35.0	%

Expected income taxes (reduction)		(30,032	)		(344,887	)		(21,832	)
Increase (decrease) in income taxes resulting from:
Unrealized foreign exchange (gain) loss		—			868			(2,136	)
Non-deductible costs		(2,683	)		77,090			8,026
Capital taxes		156			165			1,188
Valuation allowance changes affecting provision		32,715			202,026			1,470
Other		—			270			1,106

	$	156		$	(64,468	)	$	(12,178	)

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2007 and 2006 are as follows:


	2007			2006

Deferred tax assets
Net operating loss carry-forwards	$	95,674		$	51,856
Asset retirement obligations		6,736			2,554
Debt issuance costs		3,344			3,213
Deferred tax benefit on stock based compensation		—			1,794
Property, plant and equipment		181,437			153,026

		287,191			212,443

Valuation allowance		(236,805	)		(204,090	)

		50,386			8,353

Deferred tax liabilities
Properties, plant and equipment		1,928			2,020
Long term debt		48,458			6,333

		50,386			8,353

Net deferred tax liabilities	$	—		$	—

At December 31, 2007, Trident had approximately $1,400 million (2006 - $1,152 million) of deductions available for income tax purposes.

Included in deferred tax assets are net operating losses of approximately $273 million (2006 – $148 million) that are available for carryover to reduce future U.S. taxable income. The net operating losses will expire in 2023 through 2026.

Tax returns by Trident and its subsidiaries for taxation years from 2003 to 2007 are subject to examination and re-assessment by the Canadian and United States tax authorities.

F-42

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)


21.	Changes in Non-Cash Working Capital


	2007			2006			2005

Cash provided by (used for) changes to:
Accounts receivable	$	6,518		$	(39,624	)	$	(26,139	)
Prepaid expenses and deposits		(1,435	)		695			(6,083	)
Accounts payable		(45,568	)		2,969			27,249
Accrued liabilities		(31,082	)		21,667			45,690
Lenders’ warrants		—			(12,500	)		—
Foreign exchange on interest accrued and other		1,014			—			—

		(70,553	)		(26,793	)		40,717

Less changes in non-cash working capital for financing activities		12,043			(1,027	)		619
Less changes in non-cash working capital for investing activities		57,232			37,150			(47,452	)

Changes in non-cash working capital for operating activities	$	(1,278	)	$	9,330		$	(6,116	)


22.	Commitments

Trident has entered into operating leases for office space, office equipment, drilling rigs and vehicles. Future minimum lease payments for these agreements are as follows:


2008	$	6,435
2009		7,593
2010		3,141
2011		1,765
2012		1,760
Thereafter		1,320

Total lease commitments	$	22,014


23.	Related Party Transactions


(a)	Stock transactions

In 2006, Trident employees purchased 9,064 common stock for proceeds of $0.5 million.

In 2005, Trident issued 117,010 common stock and 301,405 Series A preferred stock to shareholders that have representation on the Board of Directors for proceeds of $5.9 million and US$18.8 million (C$22.9 million), respectively. In January 2005, members of senior management purchased 10,573 common stock and employees purchased 40,441 common stock for gross proceeds of $0.2 million and $0.7 million, respectively.

On July 21, 2005, holders of the preferred stock of certain subsidiaries exchanged 1,667,714 preferred stock of the subsidiaries for 209,248 Series A preferred stock units at US$62.50 per unit.

F-43

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)


(b)	Stock award loans

Under the stock option loan program, Trident loaned $1.5 million and US$0.5 million (C$0.6 million) to members of senior management which were subsequently repaid in 2006. Trident also entered into an agreement with a member of senior management to eliminate a US$0.5 million (C$0.6 million) stock option loan. The individual granted the Company call options to purchase shares of Trident common stock owned by the individual.

In April 2005, Trident loaned $0.4 million to a member of senior management. The loan was secured by vested stock options with an equivalent intrinsic value. Upon approval of the stock option loan program by the Board of Directors, the $0.4 million was converted to a loan under the program and additional security was obtained. The loan was repaid in 2006.

See note 17.


(c)	Financing activities

On March 3, 2005, Trident entered into a US$3.0 million (C$3.7 million) subordinated loan agreement with a stockholder with representation on the Board of Directors. On March 31, 2005, the loan was repaid.

In January 2005, all Trident stockholders were offered the opportunity to invest bridge equity into Trident on or before February 1, 2005. Certain stockholders funded a US$3.1 million bridge investment which was convertible into common stock or the units being offered in the March 2005 equity issuance. In March 2005, the stockholders purchased 77,010 common shares at a 5% discount in exchange for the bridge investment.


(d)	Other

During 2007, a company that had a member of Trident senior management on its Board of Directors charged Trident $0.4 million for certain equipment (2006 – $34.7 million; 2005 – $10.6 million). In 2007, 2006 and 2005, the costs were capitalized to property, plant and equipment. At December 31, 2007, this person was no longer an employee of the Company.

In 2006, Trident purchased drilling services from Ammonite Drilling Ltd., an equity method investment. In that year, prior to disposing of its interest in Ammonite, Trident incurred $6.6 million (2005 – $9.4 million) of drilling services at market rates. Trident had entered into a four year drilling contract with Ammonite at market rates.

In 2006, a company owned by an officer of Trident charged the Company $0.3 million in consulting fees (2005 – $0.6 million). In each year, the costs were primarily capitalized to property, plant and equipment.


24.	Contingencies

The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favour, Trident does not currently believe that the outcome of adverse decisions in any pending proceedings related to these matters or any amount which it may be required to pay would have a material adverse impact on its financial position, results of operations or liquidity.

F-44

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)


25.	Financial Instruments


(a)	Fair value of financial instruments

Trident’s financial instruments consist of cash, accounts receivable, derivative contracts, accounts payable, accrued liabilities, long-term debt, share purchase loan receivable, the embedded derivative within the Series A preferred stock, the Series B preferred stock and the subordinated facility warrants.

Cash, accounts receivable, accounts payable and accrued liabilities approximate their carrying amount due to their short terms to maturity. The fair value of the long-term debt approximates its carrying amount due to the at market floating interest rate.

The fair value of the remaining share purchase loan receivable is approximately $2.1 million compared to the face value of $4.3 million. As discussed in note 17(b), this loan is deemed to be non-recourse and, accordingly, neither the loan nor the shares purchased with the loan are recorded on the balance sheet.

Trident recognizes the estimated fair value of the embedded derivative within the Series A preferred stock on the balance sheets with changes in fair value recorded as financing charges in the period they occur.

The Series B preferred stock are recorded on the balance sheet at their redemption value which approximates fair value.

The subordinated facility warrants are recognized on the balance sheet at their estimated fair value with changes in fair value recorded as financing charges in the period they occur.

The derivative contracts are recognized on the balance sheet at their fair value with changes in the fair value recorded in the period they occur.


(b)	Credit risk

Trident is exposed to normal credit risk on accounts receivable from customers and counter-parties in the natural gas industry, including counter-parties related to derivative contract activities. Trident actively monitors the Company’s credit risks throughout the year.


(c)	Commodity price risk

Trident is exposed to commodity price risk to the extent that changes in commodity prices will impact the sale price of the Company’s production. Trident has entered into fixed-price commodity sales contracts and derivative contracts to mitigate the potential adverse impact of changing commodity prices.


(d)	Foreign currency risk

The Company has exposure to foreign exchange rate fluctuations due to U.S. dollar denominated cash balances, long-term debt, Series A and B preferred stock and the Series A preferred stock embedded derivative. Trident does not currently hedge foreign exchange rate fluctuations.


(e)	Interest rate risk

Trident is exposed to interest rate risk to the extent that changes in market interest rates will impact the Company’s floating interest rate debt. Trident does not hedge its interest rate exposure.

F-45

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)


26.	Supplemental Cash Flow Information

In 2007, Trident paid $65.2 million in interest (2006 – $37.8 million; 2005 – $18.2 million) and $nil in income taxes (2006 – $nil; 2005 – $0.4 million).


27.	Subsequent Events


(a)	Revolving Facility amendments

In March 2008, the minimum tangible net worth covenant on the Revolving Facility was deleted. In addition, subsequent to December 31, 2007, the Revolving Facility has been amended to extend its maturity date to October 2, 2009.


(b)	Restructuring

Subsequent to the year ended December 31, 2007, Trident underwent a reorganization consolidating five departments and eliminating 15 employment positions and three contract positions within the Company. The costs of restructuring subsequent to the year ended December 31, 2007 is $2.4 million and is recorded as a restructuring charge in the six months ended June 30, 2008.


(c)	Retirement savings plan


(d)	Warrant and deferred stock unit cancellation

On September 18, 2008, a former contractor and TEC agreed to decrease the amount of warrants held by the former contractor from 25,000 to 20,000 (see notes 12 and 17). Also subsequent to the year-end, the Company cancelled all outstanding TEC deferred stock units as no recipients remained employed and no vesting events had occurred.


(e)	Risk Management Contracts

Subsequent to December 31, 2007, the Company entered into fixed price physical delivery commodity sales contracts as follows:

Volume

Weighted Average

Contract Type

(GJ/day)

Pricing Point

Price ($/GJ)

Term

Fixed price

6,200 - 7,000

AECO

6.30 - $7.27

Sep ’08 to Dec ’08

Fixed price

28,600

AECO

7.02 - $7.30

Mar ’09 to Jun ’09

F-46

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)


28.	Non-Consolidated Financial Information of Trident Resources Corp.

The non-consolidated financial information of TRC is included below. Investments in subsidiaries are recorded under the equity method of accounting.

Non-consolidated Balance Sheets


	As at December 31
	2007			2006

ASSETS
Current
Cash	$	1,527		$	54,248
Accounts receivable		197			193
Prepaid expenses		488			—

Total current assets		2,212			54,441
Other assets		26,455			12,011
Investment in subsidiaries		250			350
Amounts due from subsidiaries		254,258			174,945

	$	283,175		$	241,747


LIABILITIES
Current
Accounts payable and accrued liabilities	$	1,227		$	200
Long-term debt		424,736			290,231
Series B preferred stock		38,018			44,699
Series A preferred stock embedded derivative		374,525			368,432
Other long-term liabilities		9,185			16,261

		847,691			719,823
Series A preferred stock		380,828			408,166

STOCKHOLDERS’ EQUITY (DEFICIT)
Common stock		3			3
Paid-in capital		288,649			290,887
Deficit		(1,233,996	)		(1,177,132	)

		(945,344	)		(886,242	)

	$	283,175		$	241,747

F-47

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)

Non-consolidated Statements of Operations


	For the Years Ended December 31
	2007			2006			2005

Revenue	$	—		$	—		$	—

Expenses
General and administrative		17,566			9,316			2,841
Foreign exchange (gain) loss		(114,287	)		10,922			1,057
Financing charges		99,226			222,214			10,336

		2,505			242,452			14,234

Loss before undernoted items		(2,505	)		(242,452	)		(14,234	)


Taxes
Capital taxes		156			165			158

		156			165			158

Net loss before undernoted item		(2,661	)		(242,617	)		(14,392	)
Loss from equity method investments		(81,541	)		(675,857	)		(33,845	)

Net loss	$	(84,202	)	$	(918,474	)	$	(48,237	)

F-48

Trident Resources Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2007, 2006 and 2005 — (Continued)
(Tabular amounts in thousands of Canadian dollars)

Non-consolidated Statements of Cash Flows


	For the Years Ended December 31
	2007			2006			2005

Operating activities
Net loss	$	(84,202	)	$	(918,474	)	$	(48,237	)
Loss from equity method investments		81,541			675,857			33,845
Financing charges		122,903			228,639			10,424
Foreign exchange (gain) loss		(114,287	)		10,922			1,057
Stock-based compensation		(349	)		5,377			319
Change in non-cash working capital		—			—			—

Net cash provided by (used for) operating activities		5,606			2,321			(2,592	)

Financing activities
Long-term debt advances, net of repayments		120,000			293,713			—
Debt issue costs		(16,700	)		(17,749	)		—
Loan to subsidiaries		(138,350	)		(421,531	)		(329,297	)
Issuance of Series A preferred stock		—			—			387,431
Repurchase of Series A preferred stock		—			—			(23,407	)
Series A preferred stock issue costs		—			—			(16,415	)
Issue share capital		—			141,979			58,254
Share issue costs		—			(8,439	)		(2,776	)
Issuance of Series B preferred stock		—			42,663			—
Repurchase of common stock		—			(2,058	)		—
Investment in subsidiaries		(23,364	)		(18,015	)		(20,383	)
Stock and stock option loan receipts (issuances)		—			2,072			(4,347	)
Change in non-cash working capital		535			1,286			(1,677	)

Net cash provided by (used for) financing activities		(57,879	)		13,921			47,383
Net cash provided by investing activities		—			—			—

Effect of translation on foreign currency denominated cash		(448	)		292			(7,077	)

Increase (decrease) in cash		(52,721	)		16,534			37,714
Cash, beginning of year		54,248			37,714			—

Cash, end of year	$	1,527		$	54,248		$	37,714

F-49

TRIDENT RESOURCES CORP.

SUPPLEMENTAL FINANCIAL INFORMATION — OIL AND GAS PRODUCING ACTIVITIES

(UNAUDITED)

Note — All of Trident’s production activity occurs entirely within Canada, with the exception of unproven landholdings in the United States. As such, no geographic distinctions are made in the tables below.

Proved Reserve Reconciliation

Proved oil and gas reserves estimates were prepared by the independent oil and gas engineering firm of Sproule Associates Limited in accordance with Securities and Exchange Commission guidelines for the years ended December 31, 2005, 2006 and 2007, and by the independent oil and gas engineering firm Netherland Sewell & Associates Inc. for the six months ended June 30, 2008. Proved oil and gas reserves are quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable from reserves in future years based on prices and costs as of the date of estimate.

Our estimated proved reserves and the changes in proved reserves for the six months ended June 30, 2008, and the years ended December 31, 2007, 2006 and 2005 were as follows:


	Natural Gas			Crude Oil
	(MMcf)			(MBbl)

December 31, 2005		81,916			6
Extensions and discoveries		80,483			—
Revisions		22,108			29
Production		(20,303	)		(20	)

December 31, 2006		164,204			15

Extensions and discoveries		24,480			—
Revisions		9,838			17
Dispositions		(3,709	)		—
Production		(28,793	)		(17	)

December 31, 2007		166,020			15

Extensions and discoveries		70,534			—
Revisions		172,500			1
Production		(14,113	)		(16	)

June 30, 2008		394,941			—

Proved developed reserves
December 31, 2005		47,124			6
December 31, 2006		103,896			15
December 31, 2007		107,605			15
June 30, 2008		232,245			—

F-50

Standardized Measure of Discounted Future Net Cash Flows

Future natural gas sales, and operating and development costs have been estimated using prices and costs in effect as of the periods indicated below. All cash flow amounts have been discounted at 10%.


	(In thousands)

June 30, 2008

Future petroleum and natural gas sales, net of royalties	$	4,728,977
Future operating expenses		(1,296,624	)
Future development costs		(297,205	)
Future income taxes		(560,497	)

Future net cash flows		2,574,651
10% annual discount for estimated timing of cash flows		(1,287,307	)

Standardized measure of discounted future net cash flows	$	1,287,344

December 31, 2007

Future petroleum and natural gas sales, net of royalties	$	1,083,720
Future operating expenses		(331,910	)
Future development costs		(189,236	)
Future income taxes		—

Future net cash flows		562,574
10% annual discount for estimated timing of cash flows		(160,025	)

Standardized measure of discounted future net cash flows	$	402,549

December 31, 2006

Future petroleum and natural gas sales, net of royalties	$	1,024,149
Future operating expenses		(338,686	)
Future development costs		(178,971	)
Future income taxes		—

Future net cash flows		506,492
10% annual discount for estimated timing of cash flows		(139,575	)

Standardized measure of discounted future net cash flows	$	366,917

December 31, 2005

Future petroleum and natural gas sales, net of royalties	$	813,776
Future operating expenses		(257,281	)
Future development costs		(94,249	)
Future income taxes		—

Future net cash flows		462,246
10% annual discount for estimated timing of cash flows		(152,252	)

Standardized measure of discounted future net cash flows	$	309,994

F-51

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

An analysis of the changes in the standardized measure of discounted future net cash flows during each of the last three years is as follows:


	(In thousands)

December 31, 2005 — Standardized measure of discounted future net cash flows	$	309,994
Net changes in prices, operating expenses and royalties on future production		(149,761	)
Net changes in future development costs		(145,098	)
Sales of oil and gas, net of royalties and operating costs		(96,545	)
Extensions, discoveries and improved recoveries		253,917
Revisions of previous quantity estimates		70,291
Previously estimated development costs incurred during the period		92,012
Accretion of discount		30,999
Other		1,108

December 31, 2006 — Standardized measure of discounted future net cash flows		366,917
Net changes in prices, operating expenses and royalties on future production		31,792
Net changes in future development costs		(66,055	)
Sales of oil and gas, net of royalties and operating costs		(142,543	)
Extensions, discoveries and improved recoveries		81,970
Dispositions of reserves		(11,703	)
Revisions of previous quantity estimates		33,279
Previously estimated development costs incurred during the period		63,818
Accretion of discount		36,692
Other		8,382

December 31, 2007 — Standardized measure of discounted future net cash flows		402,549
Net changes in prices, operating expenses and royalties on future production		154,593
Net changes in future development costs		(112,548	)
Sales of oil and gas, net of royalties and operating costs		(81,486	)
Extensions, discoveries and improved recoveries		301,824
Revisions of previous quantity estimates		738,182
Previously estimated development costs incurred during the period		32,490
Accretion of discount		40,255
Revisions of future income taxes		(168,944	)
Other		(19,571	)

June 30, 2008 — Standardized measure of discounted future net cash flows	$	1,287,344

F-52

Results of Operations

Results of operations from producing activities for each of the periods indicated are as follows:


										Six Months Ended
	Years Ended December 31,									June 30,
	2005			2006			2007			2007			2008
	(In thousands)

Production revenue, net of royalties	$	40,258		$	139,631		$	201,993		$	107,692		$	110,554
Operating expenses		(13,571	)		(43,086	)		(59,450	)		(28,606	)		(29,068	)
Depletion, depreciation and accretion		(38,800	)		(766,228	)		(219,243	)		(104,144	)		(32,034	)
Income tax expenses		—			—			—			—			—

Results of operations	$	(12,113	)	$	(669,683	)	$	(76,700	)	$	(25,058	)	$	49,452

Capitalized costs

The aggregate capitalized costs at the end of each period indicated were as follows:


	As at December 31,						As at June 30,
	2006			2007			2008
	(In thousands)

Costs related to proved properties	$	1,179,320		$	1,324,828		$	1,430,401
Costs related to unproved properties		396,291			320,373			274,950

		1,575,611			1,645,201			1,705,351
Less accumulated depletion		(813,405	)		(1,013,778	)		(1,044,554	)

	$	762,206		$	631,423		$	660,797

Costs related to unproved properties includes costs incurred in the United States of $20.4 million and $20.7 million as at December 31, 2007 and June 30, 2008, respectively.

Costs incurred for property acquisition, exploration and development activities


	Years Ended				Six Months Ended
	December 31,				June 30,
	2006		2007		2008
	(In thousands)

Proved property acquisition	$	—	$	—	$	—
Unproved property acquisition		39,009		326		895
Exploration		9,245		503		3,257
Development		380,567		62,412		34,556
Gathering pipelines, well site facilities and gas plants		192,967		3,752		11,730
Capitalized interest		18,110		23,407		9,819

Costs expended	$	639,898	$	90,400	$	60,257

F-53

Costs not being depleted


	2004 and
	Prior		2005		2006		2007		Total
	(In thousands)

December 31, 2007 costs incurred during:
Acquisition costs	$	—	$	143,316	$	36,318	$	—	$	179,634
Exploration costs		1,264		5,663		13,408		2,321		22,656
Development costs		2,524		12,006		16,437		12,027		42,994
Gathering pipelines, well site facilities and gas plants		—		42,626		—		—		42,626
Capitalized interest		—		—		9,056		23,407		32,463

	$	3,788	$	203,611	$	75,219	$	37,755	$	320,373

Acquisition costs includes costs incurred in the United States of $19.7 million.

F-54

Shares

TRIDENT RESOURCES CORP.

Common Stock


Deutsche Bank Securities	Jefferies & Company

DEALER PROSPECTUS DELIVERY OBLIGATION

Until , 2009 (the 25th day after the date of this prospectus), all dealers that effect transactions in our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

, 2009

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS


Item 13.	*Other Expenses of Issuance and Distribution.*

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission, or SEC, registration fee, the FINRA filing fee and the New York Stock Exchange listing fee, the amounts set forth below are estimates.


SEC registration fee	US$	18,078
FINRA filing fee	US$	46,500
New York Stock Exchange listing fee		*
Printing expenses		*
Legal fees and expenses		*
Accounting fees and expenses		*
Engineering fees and expenses		*
Transfer agent fees		*
Blue sky fees and expenses		*
Miscellaneous		*

Total	US$	*


*		To be completed by amendment.


Item 14.	*Indemnification of Directors and Officers.*

Article VI of our amended and restated certificate of incorporation and bylaws generally provide that we will indemnify our directors and officers and certain other persons to the fullest extent permitted by the General Corporation Law of the State of Delaware, or DGCL.

Section 145 of the DGCL authorizes a corporation to indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, other than an action by or in the right of the corporation, because such person is or was a director, officer, employee or agent of the corporation or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation or other enterprise, against expenses, including attorneys’ fees, judgments, fines and amounts paid in settlement actually and reasonably incurred by the person in connection with such suit or proceeding if the person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe the person’s conduct was unlawful. Similar indemnity is authorized for such persons against expenses, including attorneys’ fees, actually and reasonably incurred in defense or settlement of any such action or suit by or in the right of the corporation if such person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interests of the corporation, and provided further that, unless a court of competent jurisdiction otherwise provides, no indemnification shall be made if the person is adjudged liable to the corporation. Any such indemnification may be made only as authorized in each specific case upon a determination by the stockholders or a majority of disinterested directors that indemnification is proper because the indemnitee has met the applicable standard of conduct. Section 145 of the DGCL also authorizes a corporation to purchase and maintain insurance on behalf of any person who is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation or enterprise, against any liability asserted against him and incurred by him in any such capacity, or arising out of his status as such whether or not the corporation would otherwise have the power to indemnify him. We maintain policies insuring our and our subsidiaries’ officers and directors against certain liabilities for actions taken in such capacities, including liabilities under the Securities Act.

II-1

Since 2004, we have entered into indemnity agreements with each of our directors and two of our officers. Pursuant to these indemnity agreements, which are governed by the laws of Delaware, we will, subject to the DGCL, indemnify and hold harmless the director or officer:


	•	from and against any and all claims that may be made against such director or officer by any person or other entity (including governmental entities) arising out of or in any way in connection with such individual having been a directorand/or officer of us or any subsidiary, limited liability company, partnership, joint venture, trust or other enterprise of ours (each such entity, a “Related Entity”);

	•	from and against any and all liability (except where such liability relates to a failure of the director or officer to act honestly and in good faith with a view to the best interests of us), losses, damages, costs, charges, expenses, fines and penalties, including an amount paid to settle an action or satisfy a judgment, and the fees, charges and disbursements of legal counsel, which the director or officer may reasonably sustain, incur or be liable for in consequence of acting as a directorand/or officer of us or Related Entity; and

	•	without limiting the generality of the foregoing, from and against all liabilities and penalties at any time imposed upon the director or officer or any claims at any time made against the director or officer to the fullest extent permitted by law, which in any way involves the affairs of the business of us or Related Entity.

The above indemnities will continue in effect after the director or officer resigns his position or his position is terminated for any reason.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling us under the indemnification arrangements described above, the SEC is of the opinion that this indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.


Item 15.	*Recent Sales of Unregistered Securities.*

Since September 2005, the Registrant has sold the following securities without registration under the Securities Act:

On September 1, 2005, we issued 606,061 Series A preferred stock units and 100,000 shares of common stock for an aggregate value of C$50,000,000 to 2079517 Ontario Limited in a private placement. TD Securities Inc. and Credit Suisse First Boston LLC acted as agents for this private placement and received a commission in the amount of C$568,858 and US$481,321, respectively. The issuance of the shares of common stock and Series A preferred stock units was exempt from registration pursuant to Rule 903 of Regulation S under, the Securities Act.

On September 26, 2005, we issued 465,600 Series A preferred stock units with an aggregate value of US$29,100,000 to D.E. Shaw Laminar Portfolios, LLC in a private placement. Buchanan Investment Inc. acted as agent for this private placement and received a commission in the amount of US$900,000. The issuance of the Series A preferred stock units was exempt from registration pursuant to Section 4(2) of the Securities Act.

On November 4, 2005, we issued 30,617 shares of common stock with an aggregate value of C$1,530,850 to Trident Exploration (2005) Limited Partnership II. The issuance of the shares of common stock was exempt from registration pursuant to Rule 903 of Regulation S under the Securities Act.

On November 4, 2005, we issued 11,200 shares of common stock with an aggregate value of C$560,000 to Value Portfolio of the Prudential Series Fund, Inc. and Jennison Natural Resources Fund, Inc. The issuance of the shares of common stock was exempt from registration pursuant to Section 4(2) of the Securities Act.

From September 1, 2005 to December 31, 2005, TEC issued options to purchase 122,500 shares of TEC common stock of with an exercise price of C$50.00 per share were granted to directors, officers and consultants under the Stock Option Plan. The issuance of the options was exempt from registration under Rule 701 under the Securities Act because the options were issued pursuant to a written compensation plan.

On January 5, 2006, we issued 2,380,000 shares of common stock and 2,380,000 liquidity entitlements, of which 358,010 were cancelled due to re-registration and newly issued on February 8, 2006. Each whole entitlement entitles the holder to acquire 1/10 of one share of our common stock, provided a liquidity event does not occur before January 4, 2007. The aggregate offering price was C$119,000,000. The shares of common stock and liquidity

II-2

entitlements were issued to a group of accredited investors. TD Securities Inc. and Credit Suisse First Boston LLC acted as agents for this private placement and received a commission in the amount of C$3,570,000 and US$3,113,281.59, respectively. On July 28, 2006, all liquidity entitlements and all associated rights were cancelled due to the occurrence of a liquidity event. The issuance of the shares of common stock was exempt from registration pursuant to Rule 506 of Regulation D and Rule 903 of Regulation S under the Securities Act.

In connection with the completion of our January 5, 2006 and February 2, 2006 offerings on January 5, 2006, we issued 3,300 shares of common stock with an aggregate value of C$165,000 to Jennison Value Fund pursuant to pre-emptive rights under the expiring stockholders agreement. The issuance of the shares of common stock was exempt from registration pursuant to Section 4(2) of the Securities Act.

On January 30, 2006, we issued 8,764 shares of common stock with an aggregate value of C$438,200 to Trident Exploration (2005) Limited Partnership II. The issuance of the shares of common stock was exempt from registration pursuant to Section 4(2) of, and Rule 903 of Regulation S under, the Securities Act.

On February 2, 2006, we issued 100,000 shares of common stock and 100,000 liquidity entitlements with an aggregate value of C$5,000,000 to Viking Global Equities LP and VGE III Portfolio Ltd. TD Securities Inc. and Credit Suisse First Boston LLC acted as agents for this transaction and each received a commission in the amount of C$150,000. On July 28, 2006, all liquidity entitlements and all associated rights were cancelled. The issuance of the shares of common stock was exempt from registration pursuant to Section 4(2) of the Securities Act.

In connection with the completion of our January 5, 2006 and February 2, 2006 offerings on February 10, 2006, we issued 57,165 shares of common stock and 57,165 liquidity entitlements with an aggregate value of C$2,858,250 to Ensis S.á.r.l. pursuant to pre-emptive rights under the expiring stockholders agreement. Hunter Capital LLC received a commission in the amount of C$114,330 in relation to this issuance. On July 28, 2006, all liquidity entitlements and all associated rights were cancelled. The issuance of the shares of common stock was exempt from registration pursuant to Section 4(2) of the Securities Act.

In connection with the completion of our January 5, 2006 and February 2, 2006 offerings on March 9, 2006, we issued 286,800 shares of common stock and 286,800 liquidity entitlements with an aggregate value of C$14,340,000 to Jennison Utility Fund of the Prudential Sectors Fund Inc. pursuant to pre-emptive rights under the expiring stockholders agreement. On July 28, 2006, all liquidity entitlements and all associated rights were cancelled. The issuance of the shares of common stock was exempt from registration pursuant to Section 4(2) of the Securities Act.

On March 15, 2006, we purchased substantially all of the assets of Rakhit Petroleum Consulting Ltd., through our former wholly owned subsidiary, 981463 Alberta Ltd. A portion of the purchase price was paid by the issuance of 90,000 exchangeable shares in the capital of 981463 Alberta Ltd. to Rakhit. The exchangeable shares have a deemed aggregate value of C$4,500,000 and entitle Rakhit to have the exchangeable shares exchanged for shares of our common stock on a one for one basis. On March 19, 2008, 28,630 of the exchangeable shares were exchanged for 28,630 shares of our common stock. 981463 Alberta Ltd. purchased and cancelled the remaining 61,370 exchangeable shares. In addition, Rakhit purchased all of the issued common shares of 981463 Alberta Ltd. The issuance of the shares of common stock was exempt from registration pursuant to Rule 903 of Regulation S under the Securities Act.

In connection with the completion of our January 5, 2006 and February 2, 2006 offerings on April 18, 2006, we issued 2,769.10 shares of common stock and 2,769.10 liquidity entitlements with an aggregate value of US$121,250 to Trident Energy Opportunity, L.P. pursuant to pre-emptive rights under the expiring stockholders agreement. On July 28, 2006, all liquidity entitlements and all associated rights were cancelled. The issuance of the shares of common stock was exempt from registration pursuant to Section 4(2) of the Securities Act.

On April 18, 2006, we issued 8,573 shares of common stock with an aggregate value of C$428,650 to Randy Neely and Trident Exploration (2005) Limited Partnership II. The issuance of the shares of common stock was exempt from registration pursuant to Rule 903 of Regulation S under the Securities Act.

II-3

On April 25, 2006, we issued 11,250 shares of common stock with an aggregate value of C$562,500 to Sandy Murphy. The issuance of the shares of common stock was exempt from registration pursuant to Rule 903 of Regulation S under the Securities Act.

On May 25, 2006 we issued 100 shares of common stock with an aggregate value of C$5,000 to Rhonda Gathers. The issuance of the shares of common stock was exempt from registration pursuant to Section 4(2) of the Securities Act.

From January 1, 2006 to June 21, 2006, TEC issued options to purchase 509,444 shares of TEC common stock with an exercise price of C$50.00 per share were granted to directors, officers and consultants under the Stock Option Plan. From June 21, 2006 to December 30, 2006, TEC issued options to purchase 217,706 shares of TEC common stock with an exercise price of C$53.00. The issuances of the options were exempt from registration under Rule 701 under the Securities Act because the options were issued pursuant to a written compensation plan.

On February 23, 2006, we granted warrants to Gustav Eriksson, our former General Counsel, pursuant to a contractual obligation to purchase 30,000 shares of our common stock upon the payment of the exercise price of C$50.00 per share. The issuances of the warrants were exempt from registration pursuant to Section 4(2) of the Securities Act.

From June 8 to July 7, 2006, we issued 614,000 shares of Series B Preferred Stock for an aggregate value of US$38,375,000 to Arbiter Partners, L.P., Paul J. Isaac, Lucas Energy Ventures II, L.P., Lucas Energy Total Return Master Fund, L.P., Lucas Energy Total Return Partners, L.P., Ashton R. Lee, U.S. Global Investors — Global Resources Fund, Jennison Utility Fund and Jennison Natural Resources Fund, Inc. The issuances of the warrants were exempt from registration pursuant to Section 4(2) of the Securities Act.

On November 24, 2006, in connection with the TRC 2006 credit agreement, we granted warrants to purchase shares of our common stock to certain of the lenders under that agreement, for the exercise price (subject to adjustment) of the lower of C$25.00, 80% of the price per share upon a change of control that occurs prior to the consummation of a qualifying IPO, or 80% of the price per share offering price in the qualifying IPO. The issuances of the warrants were exempt from registration pursuant to Rule 144A under the Securities Act.

On August 20, 2007, in connection with the TRC 2007 subordinated credit agreement, we granted warrants to purchase shares of our common stock to all lenders under that agreement in the aggregate amount of 11,912,869. We simultaneously issued warrants to all lenders under the TRC 2006 credit agreement in the aggregate amount of 1,737,293. The issuances of the warrants were exempt from registration pursuant to Rule 506 of Regulation D under the Securities Act.

On July 24, 2008, in connection with a syndication of a portion of our 2007 TRC subordinated credit agreement, we granted warrants to purchase shares of our common stock, for an exercise price of C$0.0001 per share, to DVW Energy Partnership, LP (98,536 warrants) and Scott Setrakian (5,912 warrants). As a result, the warrants of certain of the lenders were adjusted downward to the following amounts, for a total of 104,448 warrants: Jennison Natural Resources Fund, Inc.: 2,591,932; Jennison Utility Fund of the Jennison Sector Funds, Inc.: 879.216; Jennison Value Fund of the JennisonDryden Portfolios (formerly Jennison Value Fund): 720,366; The Prudential Variable Contract Account-10: 309,661; The Prudential Variable Contract Account-2: 499,039; Value Portfolio of the Prudential Series Fund: 1,043,852; Natural Resources Portfolio of the Prudential Series Fund: 1,455,868. The issuances of the warrants were exempt from registration pursuant to Rule 506 of Regulation D under the Securities Act and no underwriting commission was paid.

With respect to the sales made in reliance on Section 4(2) of the Securities Act, the Registrant believes that each of the purchasers listed above: (i) was a sophisticated investor having enough knowledge and experience in finance and business matters to evaluate the risks and merits of the investment; (ii) was able to bear the investment’s economic risk; (iii) had access to the type of information normally provided in a prospectus through each individual’s relationship with the Registrant; and (iv) understood and agreed that the shares could not be resold or distributed to the public. In addition, the Registrant did not use any form of public solicitation or advertisement in connection with the offerings.

II-4

With respect to sales made in reliance on Rule 144A under the Securities Act, the Registrant (i) believes that each of the purchasers listed above was a qualified institutional buyer; (ii) informed each purchaser that the securities are not registered under the Securities Act in reliance on Rule 144A; and (iii) provided the information required under Rule 144A to the purchasers. In addition, the securities are not traded publicly in the United States.

With respect to sales made in reliance on Rule 506 of Regulation D under the Securities Act, the Registrant believes that each of the purchasers listed above: (i) was an accredited investor and (ii) received restricted securities. In addition, the Registrant did not use any form of public solicitation or advertisement in connection with the offerings.

With respect to sales made in reliance on Rule 903 of Regulation S under the Securities Act, the Registrant believes that each of the sales made was an offshore transaction, on the basis that: (i) each investor was outside of the United States at the time the offer to purchase the securities was made and (ii) at the time the subscription agreement of the securities was executed, the investor was outside the United States or the Registrant had a reasonable belief that the investor was outside of the United States. In addition, the Registrant did not engage in direct selling efforts in the United States. Each investor represented to the Registrant that the investor was not a U.S. Person and was not acquiring the securities for the account or benefit of a U.S. person.


Item 16.	*Exhibits and Financial Statement Schedules*


(a)	Exhibits

A list of exhibits filed herewith is contained in the exhibit index that immediately precedes such exhibits and is incorporated herein by reference.


(b)	Financial Statement Schedules

Schedules have been omitted because the information required to be shown in the schedules is not applicable or is included elsewhere in our financial statements or accompanying notes.


Item 17.	*Undertakings*

The undersigned Registrant hereby undertakes to provide to the underwriter at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriter to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

The undersigned Registrant hereby undertakes that:

(a) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(b) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-5

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Calgary, Alberta on November 10, 2008.

TRIDENT RESOURCES CORP.


	By:	/s/ Todd A. Dillabough

Name: Todd A. Dillabough


	Title:	President, Chief Executive Officer

and Chief Operating Officer

POWER OF ATTORNEY

Each individual whose signature appears below constitutes and appoints each of Todd A. Dillabough, Alan G. Withey and Eugene I. Davis as such person’s true and lawful attorney-in-fact and agent with full power of substitution and reconstitution, for such person and in such person’s name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement (or to any other registration statement for the same offering that is to be effective upon filing pursuant to Rule 462(b) under the U.S. Securities Act of 1933), and to file the same, with all exhibits thereto, and all documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as such person might or could do in person, hereby ratifying and confirming all that any said attorney-in-fact and agent, or any substitute or substitutes of any of them, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates indicated below.


Signature	Title	Date


/s/ Todd A. Dillabough Todd A. Dillabough	President, Chief Executive Officer, Chief Operating Officer and Director (Principal Executive Officer)	November 10, 2008

/s/ Alan G. Withey Alan G. Withey	Chief Financial Officer (Principal Financial and Accounting Officer)	November 10, 2008

/s/ Eugene I. Davis Eugene I. Davis	Executive Chairman of the board of directors	November 10, 2008

/s/ Kenneth L. Ancell Kenneth L. Ancell	Director	November 10, 2008

/s/ Timothy J. Bernlohr Timothy J. Bernlohr	Director	November 10, 2008

/s/ Anthony Caluori Anthony Caluori	Director	November 10, 2008

II-6


Signature	Title	Date


/s/ John H. Forsgren John H. Forsgren	Director	November 10, 2008

/s/ Marc MacAluso Marc MacAluso	Director	November 10, 2008

/s/ Todd A. Overbergen Todd A. Overbergen	Director	November 10, 2008

II-7

EXHIBIT INDEX


Exhibit
Number			Description

	1	.1*	Form of Underwriting Agreement.
	3	.1	Fourth Amended and Restated Certificate of Incorporation of Trident Resources Corp.
	3	.2	Bylaws of Trident Resources Corp.
	3	.3*	Form of Fifth Amended and Restated Certificate of Incorporation of Trident Resources Corp. to be effective upon the closing of this offering.
	3	.4*	Form of Amended and Restated Bylaws of Trident Resources Corp. to be effective upon the closing of this offering.
	4	.1	Amended and Restated Certificate of Designation of Series A Cumulative Preferred Stock.
	4	.2	Amended and Restated Certificate of Designation of Series B Cumulative Preferred Stock.
	4	.3*	Specimen stock certificate.
	4	.4*	Fourth Amended and Restated Stockholder Agreement, dated as of August 1, 2007, among Trident Resources Corp. and its stockholders, Trident Exploration Corp. and its shareholders and the members of the Backstop Parties Group.
	4	.4.1*	First Amendment to Fourth Amended and Restated Stockholder Agreement, dated as of February 16, 2008, among Trident Resources Corp. and certain of its stockholders, Trident Exploration Corp. and certain of its shareholders and the members of the Backstop Parties Group.
	4	.5	Registration Rights Agreement, dated as of January 5, 2006, among Trident Resources Corp. and certain of its stockholders.
	4	.6	Third Amendment & Restated Registration Rights Agreement, dated as of January 5, 2006, among Trident Resources Corp. and certain of its stockholders, and Trident Exploration Corp. and certain of its shareholders.
	4	.7	Right of First Refusal Agreement, dated as of August 20, 2007, among Trident Resources Corp., Trident Exploration Corp. and the investors named therein.
	4	.8	Amended & Restated Exchange Rights Agreement, dated as of June 1, 2006, among Trident Resources Corp., Trident Exploration Corp. and certain shareholders and optionholders of Trident Exploration Corp.
	4	.9	Form of Series A preferred stock warrant between preferred stock holder and Trident Resources Corp.
	4	.10	Form of Series B preferred stock warrant between preferred stock holder and Trident Resources Corp.
	4	.11	Form of 2006 lender warrant between warrant holder and Trident Resources Corp.
	4	.12	Form of 2007 lender warrant between warrant holder and Trident Resources Corp.
	4	.13	Form of 2007 lender syndication warrant.
	4	.14	Common stock purchase warrant, dated as of February 23, 2006, among Trident Resources Corp. and Gustav Eriksson.
	4	.15	Common stock purchase warrant, dated as of September 18, 2008, among Trident Exploration Corp. and Kaduna Energy Ltd.
	5	.1*	Opinion re U.S. legality by Akin Gump Strauss Hauer & Feld LLP.
	10	.1*	Amended and Restated Credit Agreement, among Trident Exploration Corp. and the Toronto-Dominion Bank, originally dated July 8, 2004 and amended and restated as of December 16, 2005.
	10	.1.1*	Amending Agreement, dated as of April 13, 2006, by and between Trident Exploration Corp. and The Toronto-Dominion Bank.
	10	.1.2*	Second Amending Agreement, dated as of April 25, 2006, by and between Trident Exploration Corp., and The Toronto-Dominion Bank.
	10	.1.3*	Third Amending Agreement, dated as of October 12, 2006, by and between Trident Exploration Corp., and The Toronto-Dominion Bank.
	10	.1.4*	Fourth Amending Agreement, dated as of November 6, 2006, by and between Trident Exploration Corp., and The Toronto-Dominion Bank.
	10	.1.5*	Fifth Amending Agreement, dated as of November 24, 2006, by and between Trident Exploration Corp., and The Toronto-Dominion Bank.


Exhibit
Number			Description

	10	.1.6*	Sixth Amending Agreement, dated as of April 20, 2007, by and between Trident Exploration Corp., and The Toronto-Dominion Bank.
	10	.1.7*	Seventh Amending Agreement, dated as of August 20, 2007, by and between Trident Exploration Corp., and The Toronto-Dominion Bank.
	10	.1.8*	Eighth Amending Agreement, dated as of March 18, 2008, by and between Trident Exploration Corp., and The Toronto-Dominion Bank.
	10	.1.9*	Ninth Amending Agreement, dated as of July 4, 2008, by and between Trident Exploration Corp., and The Toronto-Dominion Bank.
	10	.1.10*	Tenth Amending Agreement, dated as of September 3, 2008, by and between Trident Exploration Corp., and The Toronto-Dominion Bank.
	10	.1.11*	Eleventh Amending Agreement, dated as of October 3, 2008, by and between Trident Exploration Corp., and The Toronto-Dominion Bank.
	10	.2*	Amended and Restated Credit Agreement, dated as of April 25, 2006, among Trident Exploration Corp., the Subsidiaries named therein, the Lenders named therein, Credit Suisse, Toronto Branch, and Credit Suisse Securities (USA) LLC.
	10	.2.1*	Amendment No. 1 to the Credit Agreement, dated as of October 12, 2006, by and between Trident Exploration Corp., the Subsidiaries named therein, the Lenders named therein, Credit Suisse, Toronto Branch, and Credit Suisse Securities (USA) LLC.
	10	.2.3*	Amendment No. 2 to the Credit Agreement, dated as of April 12, 2007, by and between Trident Exploration Corp., the Subsidiaries named therein, the Lenders named therein, Credit Suisse, Toronto Branch, and Credit Suisse Securities (USA) LLC.
	10	.2.4*	Amendment and Waiver No. 3 to the Credit Agreement, dated as of August 20, 2007, by and between Trident Exploration Corp., the Subsidiaries named therein, the Lenders named therein, Credit Suisse, Toronto Branch, and Credit Suisse Securities (USA) LLC.
	10	.2.5*	Amendment No. 4 to the Credit Agreement, dated as of February 29, 2008, by and between Trident Exploration Corp., the Subsidiaries named therein, the Lenders named therein, Credit Suisse, Toronto Branch, and Credit Suisse Securities (USA) LLC.
	10	.3*	Credit Agreement, dated as of November 24, 2006, among Trident Resources Corp., the Subsidiaries named therein, the Lenders named therein, Credit Suisse, Toronto Branch, and Credit Suisse Securities (USA) LLC.
	10	.3.1*	Amendment and Waiver No. 1 to the Credit Agreement, dated as of August 20, 2007, by and between Trident Resources Corp., the Subsidiaries named therein, the Lenders named therein, Credit Suisse, Toronto Branch, and Credit Suisse Securities (USA) LLC.
	10	.3.2*	Amendment No. 2 to the Credit Agreement, dated as of August 30, 2007, by and between Trident Resources Corp., the Subsidiaries named therein, the Lenders named therein, Credit Suisse, Toronto Branch, and Credit Suisse Securities (USA) LLC.
	10	.3.3*	Amendment No. 3 to the Credit Agreement, dated as of December 20, 2007, by and between Trident Resources Corp., the Subsidiaries named therein, the Lenders named therein, Credit Suisse, Toronto Branch, and Credit Suisse Securities (USA) LLC.
	10	.3.4*	Amendment No. 4 to the Credit Agreement, dated as of February 29, 2008, by and between Trident Resources Corp., the Subsidiaries named therein, the Lenders named therein, Credit Suisse, Toronto Branch, and Credit Suisse Securities (USA) LLC.
	10	.3.5*	Amendment No. 5 to the Credit Agreement, dated as of February 29, 2008, by and between Trident Resources Corp., the Subsidiaries named therein, the Lenders named therein, Credit Suisse, Toronto Branch, and Credit Suisse Securities (USA) LLC.
	10	.4*	TRC Subordinated Loan Agreement, dated as August 20, 2007, among Trident Resources Corp., the Subsidiaries named therein, the Lenders named therein and Wells Fargo Bank N.A.
	10	.4.1*	Amendment No. 1 to the TRC Subordinated Loan Agreement, dated as of December 20, 2007, among Trident Resources Corp., the Subsidiaries named therein and Wells Fargo Bank N.A.
	10	.4.2*	Amendment No. 2 to the TRC Subordinated Loan Agreement, dated as of February 29, 2008, by and between Trident Resources Corp., the Subsidiaries named therein and Wells Fargo Bank N.A.


Exhibit
Number			Description

	10	.4.3*	Amendment and Waiver No. 3 to the TRC Subordinated Loan Agreement, dated as of July 24, 2008, among Trident Resources Corp., the Subsidiaries named therein and Wells Fargo Bank N.A.
	10	.5*	Subordination and Postponement Agreement, dated as of August 20, 2007, among Trident Resources Corp., Trident Exploration Corp., the Subsidiary Guarantors, Credit Suisse, Toronto Branch and Wells Fargo Bank N.A.
	10	.6*	Subordination and Postponement Agreement, dated as of August 20, 2007, among Trident Exploration Corp., the Subsidiary Guarantors, Credit Suisse, Toronto Branch and Wells Fargo Bank N.A.
	10	.7*	Amended and Restated Subordination and Postponement Agreement, dated as of August 20, 2007, among Trident Resources Corp., Trident Exploration Corp., the Subsidiary Guarantors, Credit Suisse, Toronto Branch and Wells Fargo Bank N.A.
	10	.8*	Intercreditor Agreement, dated as of April 26, 2005, among Trident Exploration Corp., The Toronto-Dominion Bank and Credit Suisse First Boston Toronto Branch.
	10	.8.1*	First Amendment to Intercreditor Agreement, dated as of December 16, 2005, among Trident Exploration Corp., The Toronto-Dominion Bank and Credit Suisse First Boston Toronto Branch.
	10	.8.2*	Second Amendment to Intercreditor Agreement, dated as of April 25, 2006, among Trident Exploration Corp., The Toronto-Dominion Bank and Credit Suisse First Boston Toronto Branch.
	10	.8.3*	Third Amendment to Intercreditor Agreement, dated as of October 12, 2006, among Trident Exploration Corp., The Toronto-Dominion Bank and Credit Suisse First Boston Toronto Branch.
	10	.8.4*	Fourth Amendment to Intercreditor Agreement, dated as of August 20, 2007, among Trident Exploration Corp., The Toronto-Dominion Bank and Credit Suisse First Boston Toronto Branch.
	10	.10*	Participation and Farmout Agreement, by and between Husky Oil Operations Limited and TEC dated as of July 22, 2004.
	10	.11*	Earning and Joint Operation Agreement, and AMI between Nexen Inc. and Trinity Energy Corp., dated as of November 9, 2001, as amended (governing substantially all of Corbett AMI acreage).
	10	.12*	Joint Operating Agreement by and between Trident Exploration Corp. and Kerogen Resources Canada, ULC, dated as of March 1, 2008.
	10	.13*	Executive Employment Agreement, by and between Trident Resources Corp. and Eugene I. Davis.
	10	.14*	Executive Employment Agreement, by and between Trident Resources Corp. and Todd A. Dillabough.
	10	.15*	Executive Employment Agreement, by and between Trident Resources Corp. and Alan G. Withey.
	10	.16*	Form of Indemnification Agreement.
	10	.17*	Trident Exploration Corp. Stock Option Plan.
	10	.18*	Trident Exploration Corp. Executive Bonus Plan dated as of December 31, 2007.
	14	*	Form of Code of Business Conduct and Ethics.
	21	.1	List of TRC subsidiaries.
	23	.1	Consent of KPMG LLP.
	23	.2	Consent of Ryder Scott Company.
	23	.3	Consent of Sproule Associates Limited.
	23	.4	Consent of Netherland, Sewell & Associates, Inc.
	23	.5*	Consent of Akin Gump Strauss Hauer & Feld LLP (included in Exhibit 5.1).
	24	.1	Power of Attorney (included on signature pages hereto).


*		To be filed by amendment.

Number of Shares

Percentage

Date of Availability for Resale into the Public Market

Upon the effectiveness of this prospectus

180 days after the date of this prospectus, of which approximately are subject to holding period, volume and other restrictions under Rule 144 of the Securities Act