PAINTED PONY PETROLEUM LTD. Year Ended December 31, 2014 ANNUAL INFORMATION FORM

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1 PAINTED PONY PETROLEUM LTD. Year Ended December 31, 2014 ANNUAL INFORMATION FORM March 26, 2015

2 TABLE OF CONTENTS CORPORATE STRUCTURE... 1 GENERAL DEVELOPMENT OF THE BUSINESS... 1 Three Year History and Recent Developments... 1 Recent Developments... 4 Significant Acquisitions in DESCRIPTION OF THE BUSINESS... 4 General... 4 Principal Property... 4 Land... 5 Drilling and Completions Operations... 5 Facilities and Infrastructure... 5 Production... 6 Natural Gas Marketing... 6 Specialized Skills and Knowledge... 6 Competitive Conditions... 7 Seasonal Factors... 7 Environmental Protection... 7 Employees... 7 Social and Environment Policies... 7 RISK FACTORS... 7 Exploration, Development and Production Risks... 7 Commodity Prices... 9 Markets and Marketing... 9 Risks Related to the Strategic Alliance... 9 Risks related to the Construction of the AltaGas Townsend Facility Evaluation of Acquisitions Conflicting Interests with Partners Global Financial Crisis Project Risks Share Price Volatility Capital Markets Variations in Foreign Exchange Rates and Interest Rates Hydraulic Fracturing i

3 Reserve Replacement Reserve Estimates Substantial Capital Requirements Availability of and Access to Drilling and Related Equipment Assessments of Value Reliance on Key Personnel Reliance on Industry Partners Operational Dependence Title to Properties Management of Growth Insurance Issuance of Debt Competition Environmental Risks and Regulations Climate Change Seasonality Aboriginal Claims Governmental Regulation Absence of Cash Dividends Additional Financing Requirements Dilution Hedging Borrowing Third Party Credit Risk Expiration of Licences and Leases Delays in Business Operations Income Taxes Changes in Legislation Changes to Accounting Policies Changes to Royalty Regime Litigation Matters DIVIDENDS AND DISTRIBUTIONS DESCRIPTION OF CAPITAL STRUCTURE Common Shares Preferred Shares ii

4 MARKET FOR SECURITIES DIRECTORS AND OFFICERS Directors Officers Ownership of Shares Cease Trade Orders, Bankruptcies, Penalties and Sanctions Conflicts of Interest AUDIT COMMITTEE Audit Committee Charter Audit Committee Members Audit Pre-Approval Policies and Procedures External Auditor Service Fees LEGAL PROCEEDINGS AND REGULATORY ACTIONS INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS TRANSFER AGENT AND REGISTRAR MATERIAL CONTRACTS INTERESTS OF EXPERTS ADDITIONAL INFORMATION ADVISORIES DEFINITIONS ABBREVIATIONS, CONVERSIONS AND CONVENTIONS SCHEDULE A - AUDIT COMMITTEE CHARTER... A-1 iii

5 CORPORATE STRUCTURE The registered and head office of Painted Pony Petroleum Ltd. ( Painted Pony or the Corporation ) is 1800, 736 6th Avenue S.W., Calgary, Alberta, T2P 3T7. The Corporation s Common Shares are listed for trading on the TSX under the trading symbol PPY and are included in the S&P/TSX Composite Index. The Corporation is the successor, by continuance and reorganization, to Alberta Ltd. ( ), which was incorporated as Ontario Inc. ( ) on August 12, 1999 in the Province of Ontario pursuant to the provisions of the Business Corporations Act (Ontario). On April 3, 2007, filed articles of amendment to change its name to Painted Pony Petroleum Ltd ; to create Class A Shares, Class B Shares, common voting shares, common non-voting shares and Preferred Shares; to convert each issued and outstanding common voting share of to 150 Class A Shares and Class B Shares of the Corporation. On May 17, 2007, the Corporation raised gross proceeds of $12,000,000 in an initial public offering and on May 23, 2007, its Class A Shares and Class B Shares commenced trading on the TSX Venture Exchange ( TSXV ) under the symbols PPY.A and PPY.B, respectively. On July 17, 2008, the Corporation amended its articles to cancel its authorized common voting shares and common non-voting shares. On December 1, 2011, the Corporation s outstanding Class B Shares were converted to Class A Shares and the Class B Shares were delisted from the TSXV. On January 1, 2012, the Corporation amalgamated with Painted Pony Petroleum Corp., a wholly-owned subsidiary, as part of an internal corporate reorganization. On June 7, 2012, pursuant to articles of amendment, the Corporation re-designated the Class A Shares as Common Shares and cancelled the Class B Shares (the Share Structure Amendment ). On June 11, 2012, the trading symbol on the TSXV changed from PPY.A to PPY. On October 17, 2013 the Corporation s Common Shares were delisted from the TSXV and were listed and began trading on the Toronto Stock Exchange (the TSX ) under the symbol PPY. The Corporation has one wholly-owned subsidiary, Painted Rock Resources Ltd., which is incorporated in the Province of Alberta. GENERAL DEVELOPMENT OF THE BUSINESS The Corporation is a publically-traded natural gas company based in Western Canada. The Corporation is focused on the production of natural gas and natural gas liquids from the Montney formation in northeast British Columbia. Three Year History and Recent Developments 2012 In September 2012, the Corporation increased its firm processing capacity at the AltaGas Ltd. ( AltaGas ) gas plant in the Blair area (the AltaGas Blair Facility ) to 32 MMcf/d, with additional processing available on an interruptible basis. 1

6 On December 21, 2012, the Corporation completed a bought deal financing of 16,997,000 Common Shares at a price of $10.15 per Common Share by way of short form prospectus, for total gross proceeds of $172.5 million. Also on December 21, 2012, the Corporation completed a $108 million acquisition of Montney natural gas assets in the Townsend area of northeast British Columbia, consisting of approximately 15,800 net acres of highly contiguous lands with an average working interest of 97%. In the year ended December 31, 2012, the Corporation drilled 10 (8.4 net) wells, of which 4 (3.2 net) wells were in British Columbia, 4 (3.2 net) wells were in Saskatchewan and 2 (2.0 net) wells were in Alberta. With respect to directors and officers of the Corporation, effective January 2, 2012 Mr. Bruce Hall was appointed Vice-President, Corporate Development. On June 6, 2012, Mr. Kelly Drader was appointed to the Corporation s Board of Directors (the Board ). On September 24, 2012, Mr. James Thompson, Vice- President, Land retired and Mr. Bruce Hall transitioned from his position as Vice-President, Corporate Development to Vice-President, Land. Also effective September 24, 2012, Mr. Barry McNamara was appointed Vice-President, Corporate Development. On December 31, 2012, Mr. James H. French, Vice- President, Production Operations, retired. Effective December 31, 2012, Mr. Ronald Talbot, Chairman of the Board, retired and Mr. Glenn Carley was appointed as Chairman of the Board In August 2013, the Corporation replaced its demand credit facility of $100 million with syndicated credit facilities of $125 million with three chartered banks, consisting of the National Bank of Canada (as administrative agent), the Alberta Treasury Branch and the Canadian Imperial Bank of Commerce. On October 17, 2013, the Common Shares were delisted from the TSXV and were listed and began trading on the TSX under the symbol PPY. In November 2013, the Corporation acquired 7,765 net acres of Montney natural gas assets that were directly contiguous to the Corporation s core area. At December 31, 2013, the Corporation had approximately 130,200 net acres of Montney assets. In December 2013, construction on the Corporation s 100% working interest 25 MMcf/d gas dehydration and condensate stabilization facility in the Townsend area (the Townsend Facility ) was initiated. During 2013 the Corporation also commissioned an engineering study through AltaGas, for a refrigeration and gas plant facility with capacity of up to 198 MMcf/d in the Townsend area (the AltaGas Townsend Facility ). At the AltaGas Blair Facility, the Corporation secured additional firm processing capacity, bringing the Corporation s total firm capacity at that facility to approximately 40 MMcf/d. In December 2013, the Corporation initiated a natural gas hedging program on a portion of its natural gas production volumes, using forward price swaps to manage some of the exposure to commodity price risk and provide a level of stability to operating cash flows. In the year ended December 31, 2013, the Corporation conducted an active drilling program, drilling 18 (13.0 net) wells, of which 13 (9.6 net) wells targeted Montney natural gas in British Columbia and 5 (3.4 net) wells targeted crude oil in Saskatchewan. 2

7 With respect to directors and officers, effective January 1, 2013 the Corporation appointed Mr. Edwin (Ted) Hanbury as Vice-President, Engineering. On June 5, 2013, Dr. Nereus Joubert was appointed to the Board. On September 1, 2013, Ms. Joan E. Dunne, Vice-President, Finance and Chief Financial Officer retired and Mr. John H. Van de Pol was appointed Vice-President, Finance and Chief Financial Officer In April 2014, the Corporation completed the commissioning of its Townsend Facility, a 25 MMcf/d natural gas dehydration and condensate stabilization facility. On May 7, 2014, the Corporation increased its syndicated credit facilities from $125 million to $175 million and added a fourth Canadian chartered bank, the Bank of Nova Scotia, to the syndication group. Effective July 30, 2014, the Corporation disposed of its crude oil assets in southeast Saskatchewan for gross proceeds of approximately $100 million. The assets represented approximately 2% of the Corporation s proved plus probable reserves at December 31, Following the closing of the transaction the Corporation s syndicated credit facilities were reduced to $150 million. On August 18, 2014 the Corporation entered into a 15-year strategic alliance with AltaGas for the development of processing and transportation infrastructure and marketing services for natural gas and natural gas liquids (the Strategic Alliance ). The Strategic Alliance was entered into to provide for the development of essential liquids-rich natural gas processing infrastructure in northeast British Columbia and to provide preferred access to international energy marketing oportunities for the Corporation s Montney production. In the first phase of the Strategic Alliance, AltaGas agreed to construct and operate the AltaGas Townsend Facility, a 198 MMcf/d shallow-cut natural gas processing facility on the Corporation s Montney resource play, of which the Corporation would have 150 MMcf/d of firm capacity. Concurrent with the Strategic Alliance, the Corporation completed a private placement to AltaGas of 4,166,666 Common Shares at a price of $12.00 per Common Share for total gross proceeds of approximately $50 million. In November 2014, the Corporation acquired 9,275 acres of 100% working interest land at a Crown land sale for $66.8 million. The land acquired was immediately adjacent to the Corporation s liquids-rich Montney natural gas project in the Townsend area of northeast British Columbia. On December 2, 2014, the Corporation completed a bought deal financing of 5,275,050 Common Shares at a price of $12.00 per Common Share for total gross proceeds of $63.3 million. On December 8, 2014 the Corporation s syndicated credit facilities were increased from $150 million to $175 million as part of the syndicate s semi-annual borrowing base review. In the year ended December 31, 2014, the Corporation conducted an active drilling program with the drilling of 25 (21.4 net) wells, of which 21 (19.5 net) wells targeted Montney natural gas in British Columbia and 4 (1.9 net) wells targeted crude oil in Saskatchewan. With respect to directors and officers, on February 22, 2014 Mr. Kelly Drader, a valued member of the Board, passed away. Effective May 16, 2014, Mr. Peter Williams was appointed to the Board. On September 29, 2014, the Corporation appointed Ms. Tonya Fleming as Vice-President and General Counsel. Effective October 6, 2014, Ms. Mary Kay Axford, Controller retired and Mr. Stuart W. Jaggard was appointed as Vice-President and Controller. 3

8 Recent Developments In early 2015 the Corporation completed the commissioning of a 100% working interest 25 MMcf/d natural gas compression and dehydration facility in the West Blair area (the West Blair Facility ), as well as doubling the processing capacity of its 50% working interest dry gas facility in the Daiber area (the Daiber Facility ), to 50 MMcf/d. In March 2015 the Corporation and AltaGas announced that the Corporation s firm capacity in the AltaGas Townsend Facility would be increased to 198 MMcf/d in the facility s second year of operation, allowing the Corporation to use its full capacity. In light of the current commodity pricing environment, the Corporation revised its 2015 capital budget from $295 million to $104 million. The Corporation and AltaGas agreed to revise the construction schedule for expected completion of the AltaGas Townsend Facility from the first quarter of 2016 to mid With respect to officers, on January 1, 2015, the following officers had title changes, being Mr. John Van de Pol, Senior Vice-President and Chief Financial Officer; Mr. Edwin (Ted) Hanbury, Senior Vice- President, Engineering; and Mr. James Reimer, Vice-President, Geoscience and Technology. Significant Acquisitions in 2014 The Corporation did not make any significant acquisitions in 2014 for which a Business Acquisition Report was required to be filed pursuant to NI General DESCRIPTION OF THE BUSINESS The Corporation is in the business of exploring for, developing and producing natural gas and natural gas liquids from the Western Canadian Sedimentary Basin. The Corporation s operations target the production of natural gas and natural gas liquids from the Montney formation in northeast British Columbia. Principal Property The Corporation s principal property is located in the northeast quadrant of the Province of British Columbia, Canada, northwest of the city of Fort St. John, near mile post 132 on the Alaska Highway. The Corporation has operations in one main consolidated geographic area, which is prospective for natural gas and liquids from multiple zones, including the Montney, Doig, Halfway, Gething, Bluesky, Cadomin and Buckinghorse formations. The Corporation s operations are all on the Montney resource play, in the areas called Blair, West Blair, Daiber, Gundy and Townsend. The Corporation s primary focus is on the Montney formation, which is a thick, over-pressured and gas charged tight dolomitic siltstone. The formation is prospective for natural gas and natural gas liquids development and production. Successful wells on the Corporation s lands and wells drilled by others in the Montney fairway, have shown this formation to hold natural gas and liquids reserves, which are recovered by applying advanced horizontal multi-stage fracture stimulations when completing the wells. 4

9 Land Petroleum and natural gas located in the Province of British Columbia are owned predominantly by the provincial government, generally termed the Crown. The British Columbia Provincial Government grants rights to explore for and produce petroleum and natural gas under leases, drilling licenses and permits, with terms generally varying from one year to ten years and on conditions contained in Provincial legislation. Leases may be continued indefinitely by producing under a lease form of tenure. A drilling license or permit must have either work commitments fulfilled or be validated by drilling with subsequent conversion of the licenses or permit to a lease in order to allow for production and qualify for indefinite continuation. The Corporation s land base is primarily one nearly contiguous block of high working interest acreage in British Columbia. At December 31, 2014, the Corporation had 291,783 (204,206 net) acres of land in British Columbia and 36,583 (36,583 net) acres in Alberta for a total of 328,366 (240,789 net) acres overall. All of the Corporation s operations are on the British Columbia lands and there are no current development plans for the Alberta lands. The Corporation s undeveloped land base at December 31, 2014 was 254,796 (193,369 net) acres. During 2014, the Corporation added 9,275 (9,275 net) acres of undeveloped land at a November 2014 British Columbia Crown land sale. Drilling and Completions Operations During 2014, the Corporation drilled 25 (21.4 net) wells, or which 21 (19.5 net) wells targeted Montney natural gas in British Columbia and 4 (1.9 net) wells targeted crude oil in Saskatchewan. During 2014, the Corporation completed 19 (17.5 net) Montney natural gas wells and all utilized an open-hole, multistage hydraulic fracture system. Facilities and Infrastructure In the Townsend area, during 2014 the Corporation constructed the Townsend Facility, a 100% owned and operated 25 MMcf/d dehydration and condensate stabilization facility. The sales gas from the Townsend Facility is transported and processed by Spectra Energy Inc. ( Spectra ) at their McMahon gas plant (the Spectra McMahon Facility ) and then delivered to markets in Alberta and British Columbia. In the Blair area, the Corporation has 40 MMcf/d of firm capacity for processing natural gas at the AltaGas Blair Facility and on March 1, 2015 contracted an additional 4 MMcf/d of firm capacity on a month to month basis from another producer. The sales gas from the AltaGas Blair Facility is delivered directly into the Spectra British Columbia gas sales pipeline system. Also in the Blair area, a small volume of non-montney natural gas production is transported by Spectra and processed at the Spectra McMahon Facility. In the West Blair area, during 2014 the Corporation built the West Blair Facility, a 100% owned and operated 25 MMcf/d natural gas compression and dehydration facility, which began operating in early The sales gas from the West Blair Facility is delivered directly into the Spectra British Columbia gas sales pipeline system. In the Daiber area, the Corporation operates the Daiber Facility, a 50% working interest dry gas separation and dehydration natural gas processing facility which, during 2014, was expanded from 25 5

10 MMcf/d to 50 MMcf/d and began operating in early Sales gas from the Daiber Facility is delivered into the Spectra British Columbia gas sales pipeline system. In the Gundy area, the Corporation owns a non-operated 35% working interest in the Gundy natural gas processing facility, with sales gas from the Gundy gas plant being delivered to the Spectra raw gas transmission system, for delivery to the Spectra McMahon Facility. The Corporation also produces small volumes of natural gas from the Daiber and Gundy areas via two other operator s facilities, with sale gas delivered directly into the Spectra British Columbia gas sales pipeline system. Production The Corporation s annual average production rate for 2014 was 13,192 boe per day. Natural Gas Marketing Supply and demand determine the price of natural gas and price is calculated at the sales point, being the wellhead, the outlet of a gas processing plant, on a gas transmission system such as the Alberta Nova Inventory Transfer ( NIT ), at a storage facility, at the inlet to a utility system or at the point of receipt by the consumer. Accordingly, the price for natural gas is dependent upon such producer s own arrangements (whether long or short term contracts and the specific point of sale). As natural gas is also traded on highly liquid trading platforms such as the Natural Gas Exchange ( NGX ), Intercontinental Exchange ( ICE ) or the New York Mercantile Exchange ( NYMEX ) in the United States, spot and future prices can also be influenced by supply and demand fundamentals on these platforms. Natural gas exported from Canada is subject to regulation by the National Energy Board ( NEB ) and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m 3 /day) must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or for a larger quantity requires an exporter to obtain an export licence from the NEB. The governments of Alberta and British Columbia also regulate the volume of natural gas that may be removed from the Province for consumption elsewhere, based on such factors as reserve availability, transportation arrangements and market considerations. Specialized Skills and Knowledge The Corporation s business requires the application of high levels of technical skill in the areas of geology, geophysics, engineering, drilling and completions and well production operations. The Corporation has assembled a team of highly skilled experts, both employees and consultants, who provide the technical skills required to successfully carry out its operations. See Risk Factors - Reliance on Key Personnel. 6

11 Competitive Conditions The natural gas industry is highly competitive particularly as it pertains to the search for and development of new sources of natural gas reserves, the construction and operation of natural gas pipelines and facilities and the transportation and marketing of natural gas and other petroleum products. The Corporation s competitors include major integrated oil and gas companies and numerous other independent oil and gas companies, some of which have greater financial, technical and other resources than the Corporation. See Risk Factors Competition. Seasonal Factors The exploration for, and the development of, natural gas reserves is dependent on access to areas where exploration and production activities are to be conducted. Seasonal weather variations affect access. See Risk Factors Seasonality. Environmental Protection The Corporation has an active program to monitor and comply with environmental protection requirements. As a result of its ownership interests in natural gas properties and equipment, including well sites, processing facilities and gathering systems, the Corporation incurs decommissioning obligations for the estimated costs to reclaim and abandon this property and equipment. At December 31, 2014, using a 2.5% discount value and an assumed inflation rate of 2%, the Corporation estimated the net present value of its decommissioning obligations to be $14.3 million, based on an undiscounted total future liability of $33.7 million. Employees At December 31, 2014, the Corporation had 47 full-time employees. Social and Environment Policies The Corporation has an active program to monitor and comply with the health, safety and environmental laws applicable to its operations. The Corporation s policies require operational activities to be conducted in a manner that meets or exceeds regulatory requirements and industry standards, to safeguard the environment and protect employees, contractors and the general public. All employees receive pertinent health, safety and environmental training applicable to their role. The Corporation regularly conducts operational audits and assessment to identify risks and takes steps to reduce and prevent accidents. See Risk Factors Health, Safety and Environment. RISK FACTORS Investors should carefully consider the risk factors set out below and consider all other information contained herein and in the Corporation s other public filings before making an investment decision. The risks below are not an exhaustive description of all the risks associated with natural gas exploration. Exploration, Development and Production Risks Natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long-term commercial success of the Corporation 7

12 depends on its ability to find, acquire, develop and commercially produce natural gas reserves. Without the continual addition of new reserves, any existing reserves that the Corporation may have at any particular time and the production therefrom will decline over time as such existing reserves are exploited. A future increase in the Corporation s reserves will depend not only on its ability to explore and develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects. No assurance can be given that the Corporation will be able to continue to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, the Corporation may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic. There is no assurance that commercial quantities of natural gas will be discovered or acquired by the Corporation. It is difficult to project the costs of implementing an exploratory or development drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions such as over-pressurized geological zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof. Future natural gas exploration or development may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, completion, operating royalty, taxes and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion, operating royalty, taxes and other costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While close well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue, cash flow and financial condition levels to varying degrees. Natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including but not limited to hazards such as fire, explosion, blowouts, cratering, sour gas releases and spills, each of which could result in substantial damage to natural gas wells, production facilities, other property and the environment or personal injury. In particular, the Corporation may encounter, explore for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to governments and third parties and may require the Corporation to incur costs to remedy such leak. In accordance with industry practice, the Corporation is not fully insured against all of these risks, nor are all such risks generally insurable. Although the Corporation will maintain liability insurance in an amount that it considers consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event the Corporation could incur significant costs that could have a material adverse effect upon its financial condition. Natural gas production operations are also subject to all the risks typically associated with such operations, including but not limited to encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these risks could have a material adverse effect on the Corporation s business, financial condition, results of operations and prospects. 8

13 Commodity Prices Natural gas prices are determined based on world demand, supply and other factors, all of which are beyond the control of the Corporation. World prices for natural gas have fluctuated widely in recent years. Prices for natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors beyond the control of the Corporation. These factors include economic conditions in the United States and Canada, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of natural gas, the price of foreign imports and the availability of alternative fuel sources. Any substantial and extended decline in the price of natural gas would have an adverse effect on the Corporation s carrying value of its proved reserves, borrowing capacity, revenues, profitability and cash flows from operations. The economics of producing from some wells may change as a result of lower commodity prices, which could result in reduced production of natural gas and a reduction in the volumes of our reserves. The Corporation might also elect not to produce from certain wells at lower prices. Volatile natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects. In addition, bank borrowings available to the Corporation may in part be determined by the Corporation s borrowing base. A sustained material decline in prices from historical average prices could reduce the Corporation s borrowing base, therefore reducing the bank credit available to the Corporation which could require that a portion, or all, of any potential bank debt of the Corporation be repaid. Markets and Marketing The marketability and price of natural gas that may be acquired or discovered by the Corporation is and will continue to be affected by numerous factors beyond its control. The Corporation s ability to market its natural gas and NGL may depend upon its ability to acquire space on pipelines that deliver natural gas to commercial markets. The Corporation may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and processing facilities, and related operational problems with such pipelines and facilities as well as extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of natural gas and many other aspects of the natural gas business. Natural gas prices are unstable and are subject to fluctuation. Any material decline in prices could result in a reduction of the Corporation s net production revenue. The economics of producing from some wells may change as a result of lower prices, which could result in reduced production or a reduction in the volumes of the Corporation s reserves. The Corporation might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in the Corporation s net production revenue causing a reduction in its acquisition, development and exploration activities. Risks Related to the Strategic Alliance There can be no assurance that the Strategic Alliance will provide the benefits expected by the Corporation. The Strategic Alliance is subject to the risks normally associated with the conduct of 9

14 strategic business arrangements. These risks include disagreement with a strategic partner on how to develop, operate and finance a project, as well as project timing, and the risk of litigation between the Corporation and a partner regarding operational matters if a disagreement cannot be resolved. The success of the Strategic Alliance will depend upon the financial strength and views of the Corporation and AltaGas at the time decisions are made. The Corporation or AltaGas may be unable or unwilling to commit funding to a particular phase of the Strategic Alliance. These matters may adversely affect the continuation of the Strategic Alliance, which may have a material adverse effect on the Corporation s ability to market its production and which may have a material adverse effect on the Corporation s business and prospects. Risks related to the Construction of the AltaGas Townsend Facility The successful design, construction, commissioning and operation of the AltaGas Townsend Facility is a key part of the Corporation s business plan. The timing of the commissioning of the AltaGas Townsend Facility is a key milestone in the Corporation s business model and failure to meet the targeted deadlines may have a material adverse effect on the Corporation s business and prospects. There is the risk that the AltaGas Townsend Facility may not be constructed in a timely manner, or at all, due to numerous factors, some of which are beyond the control of AltaGas or the Corporation. Factors that could adversely affect planned construction include, but are not limited to, the following: failure to obtain all required governmental and third-party permits, licenses and approvals for construction and operation; failure to enter into satisfactory agreements with contractors for construction of the AltaGas Townsend Facility; failure by contractors to fulfill their obligations under construction contracts, or disagreements with them over contractual obligations; shortages of materials or delays in delivery of materials; cost overruns and difficulty in obtaining sufficient financing to pay for such additional costs; difficulties or delays in obtaining gas for commissioning activities necessary to achieve commercial operability of the AltaGas Townsend Facility; weather conditions and other catastrophes; difficulties in obtaining a proper workforce for construction purposes, increased labor costs and potential labor disputes; resistance in the first nations, local and global communities to the developments due to safety, environmental or security concerns; and local economic and infrastructure conditions. If the AltaGas Townsend Facility is built and operated, there is also a risk it will not meet desired performance specifications. For the reasons described above, the Corporation may fail to realize some or all of the anticipated benefits of the AltaGas Townsend Facility and future development opportunities, which could have a material adverse effect on the Corporation s business and prospects. Evaluation of Acquisitions Acquisitions of natural gas properties or companies are based in large part on engineering, environmental and economic assessments made by the Corporation, independent engineers and consultants. These assessments include a series of assumptions regarding such factors as recoverability 10

15 and marketability of natural gas, environmental restrictions and prohibitions regarding releases and emissions of various substances, future prices of natural gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond the control of the Corporation. All such assessments involve a measure of geologic, engineering, environmental and regulatory uncertainty that could result in lower production and reserves or higher operating or capital expenditures than anticipated. Although title and environmental reviews are conducted prior to any purchase of resource assets, such reviews cannot guarantee that any unforeseen defects in the chain of title will not arise to defeat the Corporation s title to certain assets or that environmental defects or deficiencies do not exist. Conflicting Interests with Partners Joint venture, acquisition, financing and other agreements and arrangements must be negotiated with independent third parties and, in some cases, must be approved by governmental agencies. These third parties generally have objectives and interests that may not coincide with the Corporation s interests and may conflict with the Corporation s interests. Unless the parties are able to compromise these conflicting objectives and interests in a mutually acceptable manner, agreements and arrangements with these third parties will not be consummated. In certain circumstances, the concurrence of co-venturers may be required for various actions. Other parties influencing the timing of events may have priorities that differ from the Corporation s, even if they generally share the Corporation s objectives. Demands by or expectations of governments, coventurers, customers and others may affect the Corporation s strategy regarding its various projects. Failure to meet such demands or expectations could adversely affect the Corporation s participation in such projects or its ability to obtain or maintain necessary licenses and other approvals. Global Financial Crisis Recent market events and conditions, including disruptions in the international credit markets and other financial systems and the American and European sovereign debt levels have caused significant volatility in commodity prices. These conditions have caused a decrease in confidence in the global credit and financial markets and have created a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions by governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially. This volatility may in the future affect the Corporation s ability to obtain equity or debt financing on acceptable terms. Project Risks The Corporation will manage a variety of small and large projects in the conduct of its business. Project delays may delay expected revenues from operations. Significant project cost over-runs could make a project uneconomic. The Corporation s ability to execute projects and market natural gas will depend upon numerous factors beyond the Corporation s control, including: the availability and proximity of processing and pipeline capacity; the availability of storage capacity; the supply of and demand for natural gas; the availability of alternative fuel services; the effects of inclement weather; the availability 11

16 of drilling, completions and related equipment; unexpected cost increases; accidental events; currency fluctuations; changes in regulations; the availability and productivity of skilled labour; and the regulation of the natural gas industry by various levels of government and governmental agencies. Because of these factors, the Corporation could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the natural gas that it produces. Share Price Volatility The market price of the Common Shares could be subject to wide fluctuations in response to the Corporation s results of operations, changes in earnings estimates by analysts, changing conditions in the natural gas industry, or changes in general market, economic or political conditions. Capital Markets As a result of the uncertain global economic situation, the Corporation, along with all other natural gas entities, may have restricted access to capital and increased borrowing costs. Although the Corporation s business and asset base have not changed, the lending capacity of all financial institutions has diminished and risk premiums have increased. As future capital expenditures will be financed out of funds generated from operations, borrowings and possible future equity sales, the Corporation s ability to do so is dependent on, among other factors, the overall state of capital markets and investor appetite for investments in the energy industry and the Corporation s securities in particular. To the extent that external sources of capital become limited or unavailable or available on onerous terms, the Corporation s ability to make capital investments and maintain existing assets may be impaired, and its assets, liabilities, business, financial condition and results of operations may be materially and adversely affected as a result. Based on current funds available and expected funds generated from operations, the Corporation believes it has sufficient funds available to fund its projected capital expenditures. However, if funds generated from operations are lower than expected or capital costs for these projects exceed current estimates, or if the Corporation incurs major unanticipated expenses related to development or maintenance of its existing properties, it may be required to seek additional capital to maintain its capital expenditures at planned levels. Failure to obtain any financing necessary for the Corporation s capital expenditure plans may result in a delay in development or production on the Corporation s properties. Variations in Foreign Exchange Rates and Interest Rates World natural gas prices may be quoted in United States dollars and the price received by Canadian producers is therefore affected by the Canadian/United States dollar exchange rate, which will fluctuate over time. Material increases in the value of the Canadian dollar negatively impact the Corporation s production revenues. Future variations in the Canadian/United States dollar exchange rate could accordingly impact the future value of the Corporation s reserves as determined by independent evaluators. To the extent that the Corporation engages in risk management activities related to foreign exchange rates, there is a credit risk associated with counterparties with which the Corporation may contract. 12

17 An increase in interest rates could result in a significant increase in the amount the Corporation pays to service debt, which could negatively impact the market price of the Common Shares. Hydraulic Fracturing Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock formations to stimulate natural gas production. The use of hydraulic fracturing is being used to produce commercial quantities of natural gas from reservoirs that were previously unproductive. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs or third party or governmental claims, and could increase the Corporation s costs of compliance and doing business as well as delay the development of natural gas resources from shale formations which are not commercial without the use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of natural gas and NGL that the Corporation is ultimately able to produce from its reserves. Reserve Replacement The Corporation s natural gas and NGL reserves, production and cash flows therefrom are highly dependent on the Corporation successfully acquiring or discovering and developing new reserves. Without the continual addition of new reserves, any existing reserves the Corporation may have at any particular time and the production therefrom will decline over time as such existing reserves are exploited. A future increase in the Corporation s reserves will depend not only on the Corporation s ability to develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects. There can be no assurance that the Corporation s future exploration and development efforts will result in the discovery and development of additional commercial accumulations of natural gas and NGL. Reserve Estimates There are numerous uncertainties inherent in estimating quantities of natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserve and associated future net revenue information set forth in the Corporation s Statement of Reserves are estimates only. In general, estimates of economically recoverable natural gas reserves and the future net revenue therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of natural gas and NGL, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. For those reasons, estimates of the economically recoverable natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Corporation s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas were estimated by experience and analogy to similar producing pools. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history 13

18 and production practices will result in variations in the estimated reserves and such variations could be material. In accordance with applicable securities laws, the Corporation s independent reserves evaluators have used forecast prices and costs in estimating the reserves and future net cash flows as summarized herein. Actual future net cash flows will be affected by other factors, such as actual production levels, supply and demand for natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs. Actual production and cash flows derived from the Corporation s natural gas and NGL reserves will vary from the estimates contained in the reserve evaluations, and such variations could be material. The reserve evaluations are based in part on the assumed success of activities the Corporation intends to undertake in future years. The reserves and estimated cash flows to be derived therefrom contained in the reserve evaluations will be reduced to the extent that such activities do not achieve the level of success assumed in the reserve evaluations. The reserve evaluations are effective as of a specific effective date and have not been updated and thus do not reflect changes in the Corporation s reserves since that date. Substantial Capital Requirements The Corporation anticipates making substantial capital expenditures for the exploration, development, production and acquisition of natural gas reserves in the future. If the Corporation s future revenues or reserves decline, it may have limited ability to expend the capital necessary to undertake or complete future drilling development programs. There can be no assurance that debt or equity financing or cash generated by future operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Corporation. Moreover, future activities may require the Corporation to alter its capitalization significantly. The inability of the Corporation to access sufficient capital for its operations could have a material adverse effect on the Corporation s financial condition and its results of operations. Availability of and Access to Drilling and Related Equipment Natural gas exploration and development activities are dependent on the availability of drilling, completions and related equipment in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to the Corporation and may delay exploration and development activities. Assessments of Value Natural gas asset values are typically based on engineering and economic assessments made by independent engineers and the Corporation s own assessments. These assessments will include a series of assumptions regarding factors such as recoverability and marketability of natural gas and NGL, future prices of natural gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond the Corporation s control. In particular, the prices of, and markets for, natural gas and NGL products may change from those anticipated at the time of making such assessment. In addition, all such assessments involve a measure of geologic and engineering uncertainty which could result in lower production and reserves than anticipated. 14