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•	anticipated business prospects

•	our financial and operational performance, including the performance of our subsidiaries

•	expectations or projections about strategies and goals for growth and expansion

•	expected cash flows and future financing options available to us

•	expected costs for planned projects, including projects under construction and in development

•	expected schedules for planned projects (including anticipated construction and completion dates)

•	expected regulatory processes and outcomes

•	expected common share purchases under our normal course issuer bid

•	expected impact of regulatory outcomes

•	expected outcomes with respect to legal proceedings, including arbitration and insurance claims

•	expected capital expenditures and contractual obligations

•	expected operating and financial results

•	the expected impact of future accounting changes, commitments and contingent liabilities

•	expected industry, market and economic conditions.

•	inflation rates, commodity prices and capacity prices

•	timing of financings and hedging

•	regulatory decisions and outcomes

•	foreign exchange rates

•	interest rates

•	tax rates

•	planned and unplanned outages and the use of our pipeline and energy assets

•	integrity and reliability of our assets

•	access to capital markets

•	anticipated construction costs, schedules and completion dates

•	acquisitions and divestitures.

•	our ability to successfully implement our strategic initiatives

•	whether our strategic initiatives will yield the expected benefits

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•	the operating performance of our pipeline and energy assets

•	amount of capacity sold and rates achieved in our pipeline businesses

•	the availability and price of energy commodities

•	the amount of capacity payments and revenues we receive from our energy business

•	regulatory decisions and outcomes

•	outcomes of legal proceedings, including arbitration and insurance claims

•	performance and credit risk of our counterparties

•	changes in market commodity prices

•	changes in the political environment

•	changes in environmental and other laws and regulations

•	competitive factors in the pipeline and energy sectors

•	construction and completion of capital projects

•	costs for labour, equipment and materials

•	access to capital markets

•	interest, tax and foreign exchange rates

•	weather

•	cybersecurity

•	technological developments

•	economic conditions in North America as well as globally.

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•	anticipated business prospects

•	our financial and operational performance, including the performance of our subsidiaries

•	expectations or projections about strategies and goals for growth and expansion

•	expected cash flows and future financing options available to us

•	expected costs for planned projects, including projects under construction and in development

•	expected schedules for planned projects (including anticipated construction and completion dates)

•	expected regulatory processes and outcomes

•	expected common share purchases under our normal course issuer bid

•	expected impact of regulatory outcomes

•	expected outcomes with respect to legal proceedings, including arbitration and insurance claims

•	expected capital expenditures and contractual obligations

•	expected operating and financial results

•	the expected impact of future accounting changes, commitments and contingent liabilities

•	expected industry, market and economic conditions.

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•	inflation rates, commodity prices and capacity prices

•	timing of financing and hedging

•	regulatory decisions and outcomes

•	foreign exchange rates

•	interest rates

•	tax rates

•	planned and unplanned outages and the use of our pipeline and energy assets

•	integrity and reliability of our assets

•	access to capital markets

•	anticipated construction costs, schedules and completion dates

•	acquisitions and divestitures.

•	our ability to successfully implement our strategic initiatives

•	whether our strategic initiatives will yield the expected benefits

•	the operating performance of our pipeline and energy assets

•	amount of capacity sold and rates achieved in our pipelines businesses

•	the availability and price of energy commodities

•	the amount of capacity payments and revenues we receive from our energy business

•	regulatory decisions and outcomes

•	outcomes of legal proceedings, including arbitration and insurance claims

•	performance and credit risk of our counterparties

•	changes in the political environment

•	changes in environmental and other laws and regulations

•	competitive factors in the pipeline and energy sectors

•	construction and completion of capital projects

•	costs for labour, equipment and material

•	access to capital markets

•	interest, tax and foreign exchange rates

•	weather

•	cybersecurity

•	technological developments

•	economic conditions in North America as well as globally.

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1	Exports include pipeline revenues attributable to Canadian Pipeline and power deliveries to U.S. markets.

2	Revenues include sales of natural gas.

3	Revenues are attributed to countries based on country of origin of product or service.

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1	As at December 31, 2015, TC Offshore was classified as Assets held for sale. See the Natural Gas Pipelines – Significant events section of the MD&A for further information.

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1	We have a 50 per cent interest in ASTC Power Partnership, which has a PPA for production from the Sundance B power generating facilities.

2	Our share of power generation capacity.

3	Acquired February 1, 2016.

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1	Power generation has been suspended since 2008. We continue to receive capacity payments while generation is suspended.

2

In August 2015, we executed an agreement with Hydro-Québec to amend Bécancour's electricity supply contract. The amendment allows HQ to dispatch up to 570 MW of firm peak winter capacity from the Bécancour facility for a term of 20 years commencing in December 2016. Annual tolling payments received for this new service will be incremental to existing capacity payments earned under the agreement and will expire in 2036. The existing capacity payments terminate in 2026.

3	We acquired four facilities in 2013 and an additional four facilities in 2014.

1	Expected in-service date is between late 2017 and early 2018.

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•	Planning: risk and regulatory assessment, objectives and targets, and structure and responsibility

•	Implementing: development and implementation of programs, plans, procedures and practices aimed at operational risk management

•	Reporting: document and records management, communication and reporting, and

•	Action: ongoing audit and review of HSE performance.

•	overall HSE corporate governance and performance

•	operational performance and preventive maintenance metrics

•	asset integrity programs

•	security and emergency preparedness, incident response and evaluation

•	people and process safety performance metrics, and

•	developments in and compliance with applicable legislation and regulations.

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1	Issued December 31, 2014 following conversion of Series 1 preferred shares at the election of the holders.

2	Issued June 30, 2015 following conversion of Series 3 preferred shares at the election of the holders.

3	Issued March 4, 2013.

4	Issued January 20, 2014.

5	Issued March 2, 2015.

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1	Issued upon conversion of Series 1 preferred shares on December 31, 2014.

2	Issued upon conversion of Series 3 preferred shares on June 30, 2015.

3	Issued upon conversion of Series 5 preferred shares on February 1, 2016.

4	Issued January 20, 2014.

5	Issued March 2, 2015.

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1

Canwest Global Communications Corp. (Canwest) voluntarily entered into the Companies’ Creditors Arrangement Act (CCAA) and obtained an order from the Ontario Superior Court of Justice (Commercial Division) to start proceedings on October 6, 2009. Although no cease trade orders were issued, Canwest shares were de-listed by the TSX after the filing and started trading on the TSX Venture Exchange. Canwest emerged from CCAA protection and Postmedia Network acquired its newspaper business on July 13, 2010 while Shaw Communications Inc. acquired its broadcast media business on October 27, 2010. Mr. Burney ceased to be a director of Canwest on October 27, 2010.

2	As President and CEO of TransCanada, Mr. Girling is not a member of any Board Committees, but is invited to attend committee meetings as required.

3

Laricina Energy (Laricina) voluntarily entered into the CCAA and obtained an order from the Court of Queen's Bench of Alberta, Judicial Centre of Calgary for creditor protection and stay of proceedings effective March 26, 2015.  A final court order was granted on January 28, 2016, allowing the company to exit from protection under the CCAA and concluding the stay of proceedings against Laricina and its subsidiaries.

4

Ms. Salomone was a director of Crucible Materials Corp. (Crucible) from May 2008 to May 1, 2009. On May 6, 2009, Crucible and one of its affiliates filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware (the Bankruptcy Court). On August 26, 2010, the Bankruptcy Court entered an order confirming Crucible’s Second Amended Chapter 11 Plan of Liquidation.

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•	National Instrument 52-110, Audit Committees

•	National Policy 58-201, Corporate Governance Guidelines, and

•	National Instrument 58-101, Disclosure of Corporate Governance Practices.

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1.	Additional information in relation to TransCanada may be found under TransCanada's profile on SEDAR (www.sedar.com).

2.

Additional information including directors' and officers' remuneration and indebtedness, principal holders of TransCanada's securities and securities authorized for issuance under equity compensation plans (all where applicable), is contained in TransCanada's Management information circular for its most recent annual meeting of shareholders that involved the election of directors and can be obtained upon request from the Corporate Secretary of TransCanada.

3.	Additional financial information is provided in TransCanada's audited consolidated financial statements and MD&A for its most recently completed financial year.

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*	The conversion is based on natural gas at a base pressure of 101.325 kilopascals and at a base temperature of 15 degrees Celsius.

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•	Company’s financial accounting and reporting process;

•	integrity of the financial statements;

•	Company’s internal control over financial reporting;

•	external financial audit process;

•	compliance by the Company with legal and regulatory requirements; and

•	independence and performance of the Company’s internal and external auditors.

a)

review, discuss with management and the external auditor and recommend to the Board for approval, the Company’s audited annual consolidated financial statements, annual information form, management’s discussion and analysis, all financial information in prospectuses and other offering memoranda, financial statements required by regulatory authorities, all prospectuses and all documents which may be incorporated by reference into a prospectus, including, without limitation, the annual management information circular, but excluding any pricing or prospectus supplement relating to the issuance of debt securities of the Company;

b)	review, discuss with management and the external auditor and recommend to the Board for approval, the release to the public of the Company’s interim reports, including the consolidated financial statements, management’s discussion and analysis and press releases on quarterly financial results;

c)	review and discuss with management and the external auditor the use of non-GAAP information and the applicable reconciliation;

d)

review and discuss with management any financial outlook or future-oriented financial information disclosure in advance of its public release; provided, however, that such discussion may be done generally (consisting of discussing the types of information to be disclosed and the types of presentations to be made). The Audit Committee need not discuss in advance each instance in which the Company may provide financial projections or presentations to credit rating agencies;

e)

review with management and the external auditor major issues regarding accounting and auditing policies and practices, including any significant changes in the Company’s selection or application of accounting policies, as well as major issues as to the adequacy of the Company’s internal controls and any special audit steps adopted in light of material control deficiencies that could significantly affect the Company’s financial statements;

f)	review and discuss quarterly findings reports from the external auditor on:

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(i)	all critical accounting policies and practices to be used;

(ii)	all alternative treatments of financial information within generally accepted accounting principles that have been discussed with management, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor;

(iii)	other material written communications between the external auditor and management, such as any management letter or schedule of unadjusted differences;

g)	review with management and the external auditor the effect of regulatory and accounting developments as well as any off-balance sheet structures on the Company’s financial statements;

h)	review with management, the external auditor and, if necessary, legal counsel, any litigation, claim or contingency, including arbitration and tax assessments, that could have a material effect upon the financial position of the Company, and the manner in which these matters have been disclosed in the financial statements;

i)

review disclosures made to the Audit Committee by the Company’s CEO and CFO during their certification process for the periodic reports filed with securities regulators about any significant deficiencies in the design or operation of internal controls or material weaknesses therein and any fraud involving management or other employees who have a significant role in the Company’s internal controls;

j)	discuss with management the Company’s material financial risk exposures and the steps management has taken to monitor and control such exposures, including the Company’s risk assessment and risk management policies;

(a)	review with the Company’s General Counsel legal matters that may have a material impact on the financial statements, the Company’s compliance policies and any material reports or inquiries received from regulators or governmental agencies;

(a)	review and approve the audit plans of the internal auditor of the Company including the degree of coordination between such plans and that of the external auditor and the extent to which the planned audit scope can be relied upon to detect weaknesses in internal control, fraud or other illegal acts;

(b)	review the significant findings prepared by the internal audit department and recommendations issued by it or by any external party relating to internal audit issues, together with management’s response thereto;

(c)	review compliance with the Company’s policies and avoidance of conflicts of interest;

(d)	review the report prepared by the internal auditor on officers' expenses and aircraft usuage;

(e)	review the adequacy of the resources of the internal auditor to ensure the objectivity and independence of the internal audit function, including reports from the internal audit department on its audit process with subsidiaries and affiliates;

(f)	ensure the internal auditor has access to the Chair of the Audit Committee, the Board and the Chief Executive Officer and meet separately with the internal auditor to review with him or her any problems or difficulties he or she may have encountered and specifically:

(i)	any difficulties which were encountered in the course of the audit work, including restrictions on the scope of activities or access to required information, and any disagreements with management;

(ii)	any changes required in the planned scope of the internal audit;

(iii)	the internal audit department responsibilities, budget and staffing; and to report to the Board on such meetings;

(a)	review any letter, report or other communication from the external auditor in respect of any identified weakness or unadjusted difference and management’s response and follow-up, inquire regularly of management and the external auditor of any significant issues between them and how they have been resolved, and intervene in the resolution if required;

(b)	receive and review annually the external auditor’s formal written statement of independence delineating all relationships between itself and the Company;

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(c)	meet separately with the external auditor to review any problems or difficulties the external auditor may have encountered and specifically:

(i)	any difficulties which were encountered in the course of the audit work, including any restrictions on the scope of activities or access to required information, and any disagreements with management;

(ii)	any changes required in the planned scope of the audit; and to report to the Board on such meetings;

(d)	meet with the external auditor prior to the audit to review the planning and staffing of the audit;

(e)	receive and review annually the external auditor's written report on their own internal quality control procedures; any material issues raised by the most recent internal quality control review, or peer review, of the external auditor, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, and any steps taken to deal with such issues;

(f)	review and evaluate the external auditor, including the lead partner of the external auditor team;

(g)	ensure the rotation of the lead (or coordinating) audit partner having primary responsibility for the audit and the audit partner responsible for reviewing the audit as required by law, but at least every five years;

(a)	pre-approve all audit services (which may entail providing comfort letters in connection with securities underwritings) and all permitted non-audit services, other than non-audit services where:

(i)	the aggregate amount of all such non-audit services provided to the Company that were not pre-approved constitutes not more than 5 per cent of the total fees paid by the Company and its subsidiaries to the external auditor during the fiscal year in which the non-audit services are provided;

(ii)	such services were not recognized by the Company at the time of the engagement to be non-audit services;

(iii)	such services are promptly brought to the attention of the Audit Committee and approved prior to the completion of the audit by the Audit Committee or by one or more members of the Audit Committee to whom authority to grant such approvals has been delegated by the Audit Committee;

(b)	approval by the Audit Committee of a non-audit service to be performed by the external auditor shall be disclosed as required under securities laws and regulations;

(c)	the Audit Committee may delegate to one or more designated members of the Audit Committee the authority to grant pre-approvals required by this subsection. The decisions of any member to whom authority is delegated to pre-approve an activity shall be presented to the Audit Committee at its first scheduled meeting following such pre-approval;

(d)	if the Audit Committee approves an audit service within the scope of the engagement of the external auditor, such audit service shall be deemed to have been pre-approved for purposes of this subsection;

(a)	review and recommend to the Board for approval the implementation of, and significant amendments to, policies and program initiatives deemed advisable by management or the Audit Committee with respect to the Company’s code of business ethics (COBE) risk management and financial reporting policies;

(b)	obtain reports from management, the Company’s senior internal auditing executive and the external auditors and report to the Board on the status and adequacy of the Company’s efforts to ensure its businesses are conducted and its facilities are operated in an ethical, legally compliant and socially responsible manner, in accordance with the Company’s codes of business conduct and COBE;

(c)	establish a non-traceable, confidential and anonymous system by which callers may ask for advice or report any ethical or financial concern, ensure that procedures for the receipt, retention and treatment of complaints in respect of accounting, internal controls and auditing matters are in place, and receive reports on such matters as necessary;

(d)	annually review and assess the adequacy of the Company’s public disclosure policy;

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(e)

review and approve the Company’s hiring policies for partners, employees and former partners and employees of the present and former external auditor (recognizing the Sarbanes-Oxley Act of 2002 does not permit the CEO, controller, CFO or chief accounting officer to have participated in the Company’s audit as an employee of the external auditor during the preceding one-year period) and monitor the Company’s adherence to the policy;

(a)	review and approve annually the Statement of Investment Beliefs for the Company’s pension plans;

(b)

delegate the ongoing administration and management of the financial aspects of the Canadian pension plans to the Pension Committee comprised of members of the Company’s management team appointed by the Human Resources Committee, in accordance with the Pension Committee Charter, which terms shall be approved by both the Audit Committee and the Human Resources Committee, and the terms of the Statement of Investment Beliefs;

(c)	monitor the financial management activities of the Pension Committee and receive updates at least annually from the Pension Committee on the investment of the Plan assets to ensure compliance with the Statement of Investment Beliefs;

(d)	provide advice to the Human Resources Committee on any proposed changes in the Company’s pension plans in respect of any significant effect such changes may have on pension financial matters;

(e)	review and consider financial and investment reports and the funded status relating to the Company’s pension plans and recommend to the Board on pension contributions;

(f)	receive, review and report to the Board on the actuarial valuation and funding requirements for the Company’s pension plans;

(g)	approve the initial selection or change of actuary for the Company’s pension plans;

(h)	approve the appointment or termination of auditor;

(a)	review and approve the engagement and related fees of the auditor for any plan of a U.S. subsidiary that offers Company stock to employees as an investment option under the plan;

(a)	review annually the reports of the Company’s representatives on certain audit committees of subsidiaries and affiliates of the Company and any significant issues and auditor recommendations concerning such subsidiaries and affiliates;

(b)	oversee succession planning for the senior management in finance, treasury, tax, risk, internal audit and the controllers’ group; and

(a)	review, at least quarterly, the report of the Chief Information Officer (or such other appropriate Company representative) on information security controls, education and awareness.

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(a)	review and approve the agenda for each meeting of the Audit Committee and, as appropriate, consult with members of management;

(b)	preside over meetings of the Audit Committee;

(c)	make suggestions and provide feedback from the Audit Committee to management regarding information that is or should be provided to the Audit Committee;

(d)	report to the Board on the activities of the Audit Committee relative to its recommendations, resolutions, actions and concerns; and

(e)	meet as necessary with the internal and external auditor.

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•	anticipated business prospects

•	our financial and operational performance, including the performance of our subsidiaries

•	expectations or projections about strategies and goals for growth and expansion

•	expected cash flows and future financing options available to us

•	expected costs for planned projects, including projects under construction and in development

•	expected schedules for planned projects (including anticipated construction and completion dates)

•	expected regulatory processes and outcomes

•	expected common share purchases under our normal course issuer bid

•	expected impact of regulatory outcomes

•	expected outcomes with respect to legal proceedings, including arbitration and insurance claims

•	expected capital expenditures and contractual obligations

•	expected operating and financial results

•	the expected impact of future accounting changes, commitments and contingent liabilities

•	expected industry, market and economic conditions.

•	inflation rates, commodity prices and capacity prices

•	timing of financings and hedging

•	regulatory decisions and outcomes

•	foreign exchange rates

•	interest rates

•	tax rates

•	planned and unplanned outages and the use of our pipeline and energy assets

•	integrity and reliability of our assets

•	access to capital markets

•	anticipated construction costs, schedules and completion dates

•	acquisitions and divestitures.

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•	our ability to successfully implement our strategic initiatives

•	whether our strategic initiatives will yield the expected benefits

•	the operating performance of our pipeline and energy assets

•	amount of capacity sold and rates achieved in our pipeline businesses

•	the availability and price of energy commodities

•	the amount of capacity payments and revenues we receive from our energy business

•	regulatory decisions and outcomes

•	outcomes of legal proceedings, including arbitration and insurance claims

•	performance and credit risk of our counterparties

•	changes in market commodity prices

•	changes in the political environment

•	changes in environmental and other laws and regulations

•	competitive factors in the pipeline and energy sectors

•	construction and completion of capital projects

•	costs for labour, equipment and materials

•	access to capital markets

•	interest, tax and foreign exchange rates

•	weather

•	cyber security

•	technological developments

•	economic conditions in North America as well as globally.

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•	EBITDA

•	EBIT

•	funds generated from operations

•	distributable cash flow

•	distributable cash flow per common share

•	comparable earnings

•	comparable earnings per common share

•	comparable EBITDA

•	comparable EBIT

•	comparable distributable cash flow

•	comparable distributable cash flow per common share

•	comparable income from equity investments

•	comparable depreciation and amortization

•	comparable interest expense

•	comparable interest income and other

•	comparable income tax expense

•	comparable income attributable to non-controlling interests.

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•	certain fair value adjustments relating to risk management activities

•	income tax refunds and adjustments

•	gains or losses on sales of assets

•	legal, contractual and bankruptcy settlements

•	impact of regulatory or arbitration decisions relating to prior year earnings

•	restructuring costs

•	impairment of assets and investments.

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1	Reflects U.S. foreign exchange rate of $1.38 at December 31, 2015.

1	Our proportionate share.

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1	Our proportionate share.

2	Carrying value reflects amount remaining after impairment charge.

3	Excludes transfer of Canadian Mainline natural gas assets.

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1	Issued December 2014 upon conversion of Series 1 preferred shares.

2	Issued June 2015 upon conversion of Series 3 preferred shares.

3	Issued January 2014.

4	Issued March 2015.

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•	a $2,891 million after-tax impairment charge on the carrying value of our investment in Keystone XL and related projects

•	an $86 million after-tax loss provision related to the sale of TC Offshore expected to close in early 2016

•

a net charge of $74 million after tax for restructuring charges comprised of $42 million mainly related to 2015 severance costs and a provision of $32 million for 2016 planned severance costs and expected future losses under lease commitments. These charges form part of a restructuring initiative, which commenced in 2015 to maximize the effectiveness and efficiency of our existing operations and reduce overall costs

•	a $43 million after-tax charge relating to an impairment in value on turbine equipment held for future use in our Energy business

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•	a $34 million adjustment to income tax expense due to the enactment of a two per cent increase in the Alberta corporate income tax rate in June 2015

•	a charge of $27 million after tax related to Bruce Power's retirement of debt in conjunction with the merger of the Bruce A and Bruce B partnerships

•	a $199 million positive income adjustment related to the impact on our net income from non-controlling interests of TC PipeLines, LP's impairment of their equity investment in Great Lakes.

•	a gain of $99 million after tax on the sale of Cancarb Limited and its related power generation business

•	a net loss of $32 million after tax resulting from a termination payment to Niska Gas Storage for contract restructuring

•	a gain of $8 million after tax on the sale of our 30 per cent interest in Gas Pacifico/INNERGY.

•	net income of $84 million recorded in 2013 related to 2012 from the NEB 2013 decision on the Canadian Restructuring Proposal (NEB 2013 Decision)

•	a favourable tax adjustment of $25 million due to the enactment of Canadian Federal tax legislation relating to Part VI.I tax.

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•	higher earnings from Liquids Pipelines due to higher volumes on the Keystone Pipeline System

•	lower earnings from Western Power as a result of lower realized power prices and lower PPA volumes

•	higher interest expense as a result of long term debt issuances net of maturities

•	higher interest income and other as a result of increased AFUDC related to our rate-regulated pipeline projects including Energy East Pipeline and our Mexico pipelines

•	higher earnings from U.S. Power due to increased margins and sales volumes to wholesale, commercial and industrial customers, partially offset by lower capacity revenue in New York and lower realized prices at our northeastern U.S. Power facilities

•	higher earnings from U.S. Natural Gas Pipelines due to higher ANR, Great Lakes and GTN transportation revenues

•	higher earnings from Eastern Power primarily due to four solar facilities acquired in 2014

•	higher earnings from the Tamazunchale Extension which was placed in service in 2014.

•	incremental earnings from the Gulf Coast extension of the Keystone Pipeline System which was placed in service in January 2014

•	higher interest expense from debt issuances and lower capitalized interest due to projects placed in service

•	lower earnings from Western Power as a result of lower realized power prices

•	higher earnings from the Tamazunchale Extension which was placed in service in 2014

•	higher earnings from U.S. Natural Gas Pipelines due to higher transportation revenues at Great Lakes reflecting colder winter weather and increased demand, partially offset by lower contributions from GTN and Bison following the reductions in our effective ownership in July 2013 (GTN and Bison) and October 2014 (Bison)

•	higher earnings from U.S. Power mainly because of higher realized capacity prices in New York and higher realized power prices at our New York and New England facilities

•	higher earnings from the Canadian Mainline due to higher incentive earnings

•	incremental earnings from Eastern Power primarily due to solar facilities acquired in 2013 and 2014.

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1	Annual dividend based on applicable annual or quarterly floating rate as of February 10, 2016.

2	Dividend rate changed in December 2014.

3	Floating quarterly dividend rate resets each quarter. See the Financial condition section for more information.

4	Series 3 preferred shares dividend rate changed in June 2015.

5	Series 5 preferred shares dividend rate changed in February 2016.

6	Series 6 preferred shares were issued February 1, 2016.

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•	Expected earnings from Topolobampo and Mazatlan Pipeline projects coming into service

•	Positive impact of a stronger U.S. dollar on U.S. denominated earnings

•	Increase in the average investment base for the NGTL System

•	Higher earnings associated with incremental contracts from ANR

•	Cost savings achieved as a result of corporate restructuring

•	Consistent earnings in Energy with higher earnings in U.S. Power, relatively consistent earnings in Western Power and Bruce Power and slightly lower earnings in Eastern Power.

•	Reduced capitalized interest due to the Keystone XL Pipeline project Presidential permit denial

•	Lower anticipated earnings from the Keystone Pipeline System based on expiring short-term contracts for Cushing Marketlink.

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•	wholly-owned natural gas pipelines – 56,600 km (35,200 miles)

•	partially-owned natural gas pipelines – 10,700 km (6,700 miles).

•	We were awarded the contract to build, own and operate the 36-inch diameter Tuxpan-Tula pipeline in Mexico which is approximately 250 km (155 miles) long and has a contracted capacity of 866 MMcf/d. The pipeline is expected to begin construction in 2016 and be in-service in fourth quarter 2017.

•	The NEB approved the NGTL System’s $1.7 billion North Montney Mainline Project on June 11, 2015. Construction remains subject to a positive FID on the proposed Pacific Northwest LNG Project.

•	The NEB approved the Canadian Mainline's compliance filing on the NEB 2014 Decision as applied for. The approval was the last step in getting the NEB 2014 Decision implemented and allowing the Canadian Mainline to recognize incentive earnings.

•	The NEB approved the Kings North Connection project on the Canadian Mainline which will increase gas transmission capacity into the greater Toronto area and provide shippers with the flexibility to source growing supplies of Marcellus gas from the U.S. Northeast.

•	An agreement was reached with eastern LDCs that resolves their issues with Energy East and the Eastern Mainline Project. The agreement honours our previously stated commitment to ensure that Energy East and the Canadian Mainline's Eastern Mainline Project will provide gas consumers in Eastern Canada with sufficient natural gas transmission capacity and reduced natural gas transmission costs.

•	We continued the drop down of U.S. natural gas pipeline assets into TC PipeLines, LP, with the sale of the remaining 30% of GTN in April 2015 and 49.9% of PNGTS on January 1, 2016.

•	NGTL signed contracts for an additional 2.7 Bcf/d of new firm natural gas transportation service that will require a further $600 million expansion of the System for its 2018 Facilities program.

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1	As at December 31, 2015, TC Offshore was classified as Assets held for sale. See Significant Events for further information.

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1	Results from TQM, Northern Border, Iroquois, TransGas and Gas Pacifico/INNERGY reflect our share of equity income from these investments. In November 2014, we sold our interest in Gas Pacifico/INNERGY.

2

Beginning in August 2014, TC PipeLines, LP began its at-the-market equity issuance program which, when utilized, decreases our ownership interest in TC PipeLines, LP. On October 1, 2014, we sold our remaining 30 per cent direct interest in Bison to TC PipeLines, LP. On April 1, 2015, we sold our remaining 30 per cent direct interest in GTN to TC PipeLines, LP. Effective May 22, 2013 our ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent. On July 1, 2013, we sold 45 per cent of GTN and Bison to TC PipeLines, LP. The following shows our ownership interest in TC PipeLines, LP and our effective ownership interest of GTN, Bison and Great Lakes through our ownership interest in TC PipeLines, LP for the periods presented.

3	Represents our 53.6 per cent direct ownership interest. The remaining 46.4 per cent is held by TC PipeLines, LP.

4	Effective October 1, 2014 we have no direct ownership in Bison. Prior to that our direct ownership interest was 30 per cent effective July 1, 2013.

5	Effective April 1, 2015 we have no direct ownership in GTN. Prior to that our direct ownership was 30 per cent effective July 1, 2013.

6	Represents our 61.7 per cent ownership interest.

7	Includes our share of the equity income from TransGas and Gas Pacifico/INNERGY as well as general and administration costs relating to our U.S. and International

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8	Comparable EBITDA for the portions of TC PipeLines, LP and Portland we do not own.

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•	higher ANR Southeast Mainline transportation revenue, incidental commodity sales and ANR's first quarter 2015 settlement with an owner of adjacent facilities for commercial interruption of ANR's service, partially offset by increased spending on ANR pipeline integrity work

•	higher earnings from the Tamazunchale Extension which was placed in service in 2014

•	lower contributions from other U.S. Pipelines due to ownership interests in GTN and Bison sold to TC PipeLines, LP  in April 2015 and October 2014, respectively. These drop downs increased EBITDA from TC PipeLines, LP and also increased the partially offsetting non-controlling interests

•	a stronger U.S. dollar had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. and International operations.

•	higher earnings from the Tamazunchale Extension which was placed in service in 2014

•	higher transportation revenue at Great Lakes mainly due to colder winter weather and increased demand

•	lower contributions from GTN and Bison following the reductions in our effective ownership in each pipeline in July 2013 (GTN and Bison) and October 2014 (Bison)

•	a stronger U.S. dollar had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. and International operations.

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•	continued technological progress with horizontal drilling and multi-stage hydraulic fracturing or fracking. This is increasing the technically accessible resource base of existing basins and emerging regions, such as the Marcellus and Utica in the U.S. northeast and the Montney and Horn River areas in northeastern B.C.

•	these technologies are also being applied to existing oil fields where further recovery of the resource is now possible. There is often associated gas discovered in the exploration and production of liquids-rich hydrocarbon basins (for example, the Bakken oil fields) which also contributes to an increase in the overall gas supply for North America.

•	natural gas-fired power generation

•	petrochemical and industrial facilities

•	the production of Alberta oil sands, although new greenfield projects that have not begun construction may be delayed in the current low oil price environment

•	exports to Mexico to fuel new power generation facilities.

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•	Increased average throughput on Keystone Pipeline by 30,000 Bbl/d and increased long term contracts to 545,000 Bbl/d

•	Finalized definitive agreements with Magellan Midstream Partners L.P. (Magellan), to jointly develop a connection between our Houston Tank Terminal and the Magellan delivery system enhancing our crude oil infrastructure connectivity to Houston and Texas City area refineries and terminals

•	Finalized definitive agreements between Keyera Corp. and our Grand Rapids pipeline to enable Alberta oil sands producers to gain access to a reliable and cost effective source of diluent

•	Created a liquids marketing business to expand our service offerings to other areas of the liquids pipelines business value chain. Marketing transactions will commence in 2016

•	Throughout 2015, the Keystone XL cross border permit application experienced multiple delays from the DOS and was ultimately denied. We have launched legal and NAFTA challenges in response to the denial. We remain supportive of Keystone XL and are reviewing our options which include filing a new U.S. Presidential permit application

•	Achieved significant construction progress on our regional Alberta projects, the Grand Rapids and Northern Courier pipeline systems

•	Filed an amendment to Energy East’s existing application with the NEB that adjusts the proposed route, scope and capital cost of the Energy East pipeline project based on extensive landowner, environmental, community and customer input

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•	higher volumes

•	incremental earnings from the Keystone Gulf Coast extension which was placed in service in January 2014

•	a stronger U.S. dollar which had a positive impact on the Canadian dollar equivalent comparable earnings

•	incremental earnings from the Keystone Gulf Coast extension which was placed in service in January 2014

•	a stronger U.S. dollar which had a positive impact on the Canadian dollar equivalent comparable earnings

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•	Organic growth at Bruce Power: executed agreement with the IESO to extend the operating life of the Bruce Power facility to 2064 and acquired an additional ownership interest in this facility, a primary source of emission-less generation for Ontario underpinned by a long-term contract

•

Acquisition of Ironwood power plant: strategically located natural gas-fired investment in proximity to the Marcellus shale gas play with energy and capacity revenues in the PJM power market, North America’s largest and most liquid energy region. Facility is well positioned in a market that is transitioning away from coal-fired to natural gas generation and complements our existing wholesale marketing business

•	Amendment to Bécancour contract: executed agreement with Hydro Québec allowing for dispatch of up to 570 MW of firm peak winter capacity for a term of 20 years beginning December 2016. Annual payments are incremental to existing capacity payments

•	Began construction of the Napanee 900 MW natural gas-fired power plant

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1	We have a 50 per cent interest in ASTC Power Partnership, which has a PPA for production from the Sundance B power generating facilities.

2	Our share of power generation capacity.

3	Acquired February 1, 2016.

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•	a $59 million pre-tax charge relating to an impairment in value on turbine equipment previously purchased for a new power development project that did not proceed. Various other projects have recently been evaluated for possible use of this equipment and those evaluations support the impairment of the carrying value. See Critical accounting estimates on page 101 for further information

•	a $36 million pre-tax charge related to Bruce Power's retirement of debt in conjunction with the merger of the Bruce A and Bruce B partnerships

•	a gain in 2014 of $108 million on the sale of Cancarb Limited and its related power generation business, which closed in April 2014

•	a net loss in 2014 of $43 million resulting from the contract termination payment to Niska Gas Storage effective April 30, 2014

•	unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain commodity price risks as follows:

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1	Includes four solar facilities acquired between June and December 2013, three solar facilities acquired in September 2014 and one solar facility acquired in December 2014.

2	Includes our share of equity income from our investments in ASTC Power Partnership and Portlands Energy, and our share of comparable income from equity investments from Bruce Power.

•	lower earnings from Western Power as a result of lower realized prices and lower PPA volumes

•	higher earnings from U.S. Power due to increased margins and sales volumes to wholesale, commercial and industrial customers, partially offset by lower capacity revenue in New York and lower realized prices at our northeastern U.S. Power facilities

•	higher earnings from Eastern Power primarily due to four solar facilities acquired in 2014

•	lower earnings from Bruce Power due to higher operating expenses mostly offset by fewer unplanned outage days at Bruce A, as well as higher operating expenses and lower gains from contracting activities, partially offset by lower lease expense at Bruce B

•	lower earnings from Natural Gas Storage due to lower realized natural gas storage price spreads

•	a stronger U.S. dollar and its positive effect on the foreign exchange impact.

•	lower earnings from Western Power due to lower realized prices

•	higher earnings from U.S. Power mainly because of higher realized capacity prices in New York and higher realized power prices at our New York and New England facilities

•	incremental earnings from Eastern Power primarily due to four solar facilities acquired in each of 2013 and 2014

•	lower earnings from Natural Gas Storage due to lower realized natural gas storage price spreads.

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•	acquisition of the Ironwood power plant in Pennsylvania

•	increased ownership interest in Bruce Power

•	increased planned maintenance activity at Bruce Power

•	lower U.S. Power marketing contribution

•	lower realized capacity prices in New York

•	lower contributions from our power operations in Eastern Canada

•	lower North American energy commodity prices

•	higher GHG emissions costs in Alberta.

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•	Canadian Power

•	U.S. Power

•	Natural Gas Storage

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1	Power generation has been suspended since 2008. We continue to receive capacity payments while generation is suspended.

2

In August 2015, we executed an agreement with HQ to amend Bécancour's electricity supply contract. The amendment allows HQ to dispatch up to 570 MW of firm peak winter capacity from the Bécancour facility for a term of 20 years commencing in December 2016. Annual tolling payments received for this new service will be incremental to existing capacity payments earned under the agreement and will expire in 2036. The existing capacity payments terminate in 2026.

3	We acquired four facilities in 2013 and an additional four facilities in 2014.

1	Expected in-service date is between late 2017 and early 2018

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1	The realized and unrealized gains and losses from financial derivatives used to manage Canadian Power’s assets are presented on a net basis in Western and Eastern Power revenues. The unrealized gains and losses from financial derivatives included in Revenue are excluded to arrive at Comparable EBITDA.

2	Includes four solar facilities acquired between June and December 2013, three solar facilities acquired in September 2014 and one solar facility acquired in December 2014.

3	Includes Revenue from the sale of unused natural gas transportation, sale of excess natural gas purchased for generation and Cancarb sales of thermal carbon black up to April 15, 2014 when it was sold.

4	Includes our share of equity income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, and Portlands Energy. Equity income does not include any earnings related to our risk management activities.

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1	Includes four solar facilities acquired between June and December 2013, three solar facilities acquired in September 2014, and one solar facility acquired in December 2014.

2	Includes our 50 per cent ownership interest of Sundance B volumes through the ASTC Power Partnership. Sundance A Unit 1 returned to service in September 2013 and Unit 2 returned to service in October 2013 after extended outages.

3	The percentage of time the plant was available to generate power, regardless of whether it was running.

4	Does not include facilities that provide power to us under PPAs.

5	Does not include Bécancour because power generation has been suspended since 2008.

•	lower realized power prices

•	incremental earnings from the return to service of the Sundance A PPA Unit 1 in September 2013 and Unit 2 in October 2013 which also resulted in increased volume purchases

•	sale of Cancarb in April 2014.

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1	Represents our 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B up to December 3, 2015 when we increased our ownership percentage in Bruce B, and Bruce A and B were merged. Sales volumes include deemed generation.

2	The percentage of time in a year the plant is available to generate power, regardless of whether it is running.

3	Calculation based on actual and deemed generation. Bruce B realized sales price per MWh includes revenues under the floor price mechanism and revenues from contract settlements.

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•	New York, operated by the New York ISO

•	New England, operated by the New England ISO

•	PJM Interconnection area (PJM).

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1	The realized and unrealized gains and losses from financial derivatives used to manage U.S. Power's assets are presented on a net basis in power revenues. The unrealized gains and losses from financial derivatives included in Revenue are excluded to arrive at Comparable EBITDA.

2	Includes the costs of fuel consumed in generation.

1	The percentage of time the plant was available to generate power, regardless of whether it is running.

2	Plant availability was lower in 2015 due to an unplanned outage at the Ravenswood facility. The unit returned to service in May 2015.

1	New England ISO all hours Mass Hub price.

2	Zone J market in New York City where the Ravenswood plant operates.

•	higher margins and higher sales to wholesale, commercial and industrial customers in both the PJM and New England markets

•	lower realized power prices at our facilities in New York and New England, partially offset by lower fuel costs

•	lower capacity revenue at Ravenswood due to lower realized capacity prices in New York and the impact of lower availability at the facility.

•	higher realized capacity prices primarily in New York

•	higher realized power prices for the New England and New York facilities

•	higher generation volumes primarily at the Ravenswood facility

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•	higher prices and related costs on increased volumes purchased to fulfill power sales commitments to wholesale, commercial and industrial customers.

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•	higher interest expense as a result of long term debt issuances partially offset by Canadian and U.S. dollar-denominated debt maturities. See the Financial condition section on page 82 for details on long term debt

•	a stronger U.S dollar and its effect on the foreign exchange impact on interest expense related to U.S. dollar-denominated debt

•	lower carrying charges to shippers in 2015 on the net revenue variance for the Canadian Mainline

•	higher capitalized interest primarily due to capital spending on Liquids Pipelines projects, LNG projects and the Napanee power generating facility, partially offset by lower capitalized interest on the completion of the Gulf Coast extension of the Keystone Pipeline System in first quarter 2014.

•	higher interest expense as a result of long term debt issuances partially offset by Canadian and U.S. dollar-denominated debt maturities

•	a stronger U.S dollar and its effect on the foreign exchange impact on interest expense related to U.S. dollar-denominated debt

•	higher carrying charges to shippers in 2014 on the net revenue variance for Canadian Mainline

•	lower capitalized interest due to the completion of the Gulf Coast extension of the Keystone Pipeline System in first quarter 2014, partially offset by higher capitalized interest primarily for Keystone XL.

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•	increased AFUDC related to our rate-regulated projects, including Energy East Pipeline and our Mexico pipeline projects

•	higher realized losses in 2015 compared to 2014 and 2014 compared to 2013 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

•	the impact of a fluctuating U.S. dollar on the translation of foreign currency denominated working capital.

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•	investments in property, plant and equipment on the NGTL System, Mexico pipeline construction, ANR, Northern Courier and Napanee

•	equity investments in Bruce Power and Grand Rapids

•	capital investment in projects under development including Energy East.

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1	Includes non-controlling interests in TC PipeLines, LP and Portland

2	Net of cash and excluding junior subordinated notes

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•	our ability to generate predictable and growing cash flow from operations

•	our access to capital markets

•	approximately $7 billion of unutilized unsecured credit facilities.

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•	the expansion of the NGTL System

•	construction of Mexico pipelines

•	capital additions to our ANR pipeline

•	construction of the Northern Courier pipeline

•	expansion of the Canadian Mainline

•	construction of the Napanee power generating facility.

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1	The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL and are callable at TCPL's option at any time on or after May 20, 2025 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

2	The Junior subordinated notes were issued to TransCanada Trust. The interest rate is fixed at 5.875 per cent per annum and will reset starting May 2025 until May 2045 to the three month LIBOR plus 3.778 per cent per annum; from May 2045 to May 2075 the interest rate will reset to the three month LIBOR plus 4.528 per cent per annum.

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1

Holders of the cumulative redeemable first preferred shares set out in this table are entitled to receive a fixed cumulative quarterly preferred dividend, as and when declared by the Board with the exception of Series 4 and Series 6 preferred shares. The holders of Series 4 and Series 6 preferred shares are entitled to receive a quarterly floating rate cumulative preferred dividend as and when declared by the Board.

2

We may, at our option, redeem all or a portion of the outstanding preferred shares for the redemption price per share, plus all accrued and unpaid dividends on the redemption option date and on every fifth anniversary date thereafter. In addition, Series 2 and Series 4 preferred shares are redeemable by us at any time other than on a designated date for $25.50 per share plus all accrued and unpaid dividends on such redemption date, in which case they are redeemable at $25.00 per share plus all accrued and unpaid dividends.

3	Commencing December 31, 2015, the floating quarterly dividend rate for the Series 4 preferred shares is 1.778 per cent and will reset every quarter going forward.

4	Commencing February 1, 2016, the floating quarterly dividend rate for the Series 6 preferred shares is 2.037 per cent and will reset every quarter going forward.

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1	Includes repurchases of common shares pursuant to private agreements between us and third-parties.

2	Includes brokerage fees.

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1	The amounts in this table exclude funding contributions to our pension plans.

2	Demand rates are subject to change. The contractual obligations in the table are based on demand volumes only and exclude commodity charges incurred when volumes flow.

3	Amounts include capital expenditures and capital projects under development, are estimates and are subject to variability based on timing of construction and project enhancements.

4	Includes estimates of certain amounts which are subject to change depending on plant-fired hours, use of natural gas storage facilities, the consumer price index, actual plant maintenance costs, plant salaries as well as changes in regulated rates for transportation.

•	senior debt

•	project financing

•	preferred shares

•	hybrid securities

•	additional drop downs of our U.S. natural gas pipeline assets to TC PipeLines, LP

•	asset sales

•	potential involvement of strategic or financial partners

•	portfolio management

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•	interest rates

•	actual returns on plan assets

•	changes to actuarial assumptions and plan design

•	actual plan experience versus projections

•	amendments to pension plan regulations and legislation.

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•	overall HSE corporate governance and performance

•	operational performance and preventive maintenance metrics

•	asset integrity programs

•	security and emergency preparedness, incident response and evaluation

•	people and process safety performance metrics

•	developments in and compliance with applicable legislation and regulations.

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•	air and GHG emissions

•	product releases, including crude oil and natural gas, into the environment (land, water and air)

•	use, storage and disposal of chemicals and hazardous materials

•	compliance with corporate and regulatory policies and requirements and new regulations.

•	environmental laws and regulations (and interpretation and enforcement of them) change

•	new claims can be brought against our existing or discontinued assets

•	our pollution control and clean up cost estimates may change, especially when our current estimates are based on preliminary site investigation or agreements

•	we may find new contaminated sites, or what we know about existing sites could change

•	where there is potentially more than one responsible party involved in litigation, we cannot estimate our joint and several liability with certainty.

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•

under the SGER in Alberta, established industrial facilities with GHG emissions above a certain threshold have to reduce their emissions below an intensity baseline. Our Sundance and Sheerness PPA facilities and NGTL System facilities are subject to this regulation. We recover compliance costs on the NGTL System through the tolls our customers pay. A portion of the compliance costs for Sundance and Sheerness are recovered through market pricing and hedging activities. A new climate change policy, the Climate Leadership Plan (CLP), was announced by the Alberta government in the fall of 2015 that has the objective of positioning the provincial economy to be less carbon intensive. Our internal processes and procedures for managing changing regulations such as the CLP are mature. The potential new costs and business opportunities that come with the Alberta CLP are within the bounds of our previously expected changes to GHG regulation. We have been actively managing its exposure to the existing and newly-announced Alberta carbon pricing policies to minimize the impact.

•	B.C. has a tax on GHG emissions from fossil fuel combustion. We recover the compliance costs for our compressor and meter stations through the tolls our customers pay.

•	U.S. northeastern states that are members of the RGGI have implemented a CO2 cap-and-trade program for electricity generators. This program applies to both the Ravenswood and Ocean State Power generation facilities.

•

Québec’s Regulation Respecting a Cap-and-Trade System for Greenhouse Gas Emission Allowances came into force in 2011. Bécancour has been required to cover its GHG emissions since 2013. As per the regulations, the government allocates free emission units for the majority of Bécancour's compliance requirements. The remaining requirements were met with GHG instruments purchased at auctions or secondary markets. The costs of these emissions units were recovered through commercial contracts. The pipeline facilities in Québec are also covered under this regulation and have purchased compliance instruments.

•	in 2013, California implemented a cap-and-trade program for industrial emitters of GHGs, including electricity importers. We have costs associated with the program from our power marketing activities.

•	forwards and futures contracts – agreements to buy or sell a financial instrument or commodity at a specified price and date in the future. We use foreign exchange and commodity forwards and futures to manage the impact of changes in foreign exchange rates and commodity prices

•	swaps – agreements between two parties to exchange streams of payments over time according to specified terms. We use interest rate, cross-currency and commodity swaps to manage the impact of changes in interest rates, foreign exchange rates and commodity prices

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•	options – agreements that give the purchaser the right (but not the obligation) to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. We use option agreements to manage the impact of changes in interest rates, foreign exchange rates and commodity prices.

•	committing a portion of expected power supply to fixed price sales contracts of varying terms while reserving a portion of our unsold power supply to mitigate operational and price risk in our asset portfolio

•	purchasing a portion of the natural gas we need to fuel our natural gas-fired power plants in advance or entering into contracts that base the sale price of our electricity on the cost of the natural gas, effectively locking in a margin

•	meeting our power sales commitments using power we generate ourselves or with power we buy at fixed prices, reducing our exposure to changes in commodity prices

•	using derivative instruments to enter into offsetting or back-to-back positions to manage commodity price risk created by certain fixed and variable prices in arrangements for different pricing indices and delivery points.

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1	Fair values equal carrying values.

2	Consolidated net income in 2015 included net realized gains of $8 million (2014 – gains of $21 million) related to the interest component of cross-currency swap settlements.

•	accounts receivable

•	portfolio investments

•	the fair value of derivative assets

•	cash and notes receivable.

•	dealing with creditworthy counterparties – a significant amount of our credit exposure is with investment grade counterparties or, if not, is generally partially supported by financial assurances from investment grade parties

•	setting limits on the amount we can transact with any one counterparty – we monitor and manage the concentration of risk exposure with any one counterparty, and reduce our exposure when we feel we need to and when it is allowed under the terms of our contracts

•	using contract netting arrangements and obtaining financial assurances, such as guarantees and letters of credit or cash, when we believe it is necessary.

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•	a regulator must establish or approve the rates for the regulated services or activities

•	the regulated rates must be designed to recover the cost of providing the services or products

•	it is reasonable to assume that rates set at levels to recover the cost can be charged to (and collected from) customers because of the demand for services or products and the level of direct and indirect competition.

•	a $2,891 million after-tax charge on the carrying value of our investment in the Keystone XL project

•	a loss of $43 million after tax relating to certain Energy turbine equipment.

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1.	First, we compare the fair value of the reporting unit to its book value, including its goodwill. If fair value is less than book value, we consider our goodwill to be impaired.

2.	Next, we measure the amount of the impairment by calculating the implied fair value of the reporting unit's goodwill. We do this by deducting the fair value of the tangible and intangible net assets of the reporting unit from the fair value we calculated in the first step. If the goodwill's carrying value exceeds its implied fair value, we record an impairment charge.

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•	discount rates

•	commodity and capacity prices

•	market supply and demand assumptions

•	growth opportunities

•	output levels

•	competition from other companies

•	regulatory changes.

•	when we expect to retire the asset

•	the scope of abandonment and reclamation activities that are required

•	inflation and discount rates.

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1	Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included net in revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held for trading derivative instruments are included net in interest expense and interest income and other, respectively.

2	In 2015, net realized gains on fair value hedges were $11 million (2014 - $7 million) and were included in interest expense.

3	In 2015 and 2014, there were no gains or losses included in net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

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1	No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI.

2	Reported within revenues on the consolidated statement of income.

3	Reported within interest expense on the consolidated statement of income.

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•	regulators' decisions

•	negotiated settlements with shippers

•	acquisitions and divestitures

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service.

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service

•	regulatory decisions.

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•	weather

•	customer demand

•	market prices for natural gas and power

•	capacity prices and payments

•	planned and unplanned plant outages

•	acquisitions and divestitures

•	certain fair value adjustments

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service.

•	a $2,891 million after-tax impairment charge on the carrying value of our investment in Keystone XL and related projects

•	an $86 million after-tax loss provision related to the sale of TC Offshore expected to close in early 2016

•

a net charge of $60 million after tax for our business restructuring and transformation initiative comprised of $28 million mainly related to 2015 severance costs and a provision of $32 million for 2016 planned severance costs and expected future losses under lease commitments. These charges form part of a restructuring initiative, which commenced in 2015 to maximize the effectiveness and efficiency of our existing operations and reduce overall costs

•	a $43 million after-tax charge relating to an impairment in value of turbine equipment held for future use in our Energy business

•	a charge of $27 million after tax related to Bruce Power's retirement of debt in conjunction with the merger of the Bruce A and Bruce B partnerships

•	a $199 million positive income adjustment related to the impact on our net income from non-controlling interests of TC PipeLines, LP's impairment of their equity investment in Great Lakes.

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•	a $2,891 million after-tax impairment charge on the carrying value of our investment in Keystone XL and related projects

•	an $86 million after-tax loss provision related to the sale of TC Offshore expected to close in early 2016

•

a net charge of $60 million after tax for our business restructuring and transformation initiative comprised of $28 million mainly related to 2015 severance costs and a provision of $32 million for 2016 planned severance costs and expected future losses under lease commitments. These charges form part of a restructuring initiative, which commenced in 2015 to maximize the effectiveness and efficiency of our existing operations and reduce overall costs

•	a $43 million after-tax charge relating to an impairment in value on turbine equipment held for future use in our Energy business

•	a charge of $27 million after tax related to Bruce Power's retirement of debt in conjunction with the merger of the Bruce A and Bruce B partnerships

•	a $199 million positive income adjustment related to the impact on our net income from non-controlling interests of TC PipeLines, LP's impairment of their equity investment in Great Lakes.

•	an $8 million after-tax gain on sale of our 30 per cent interest in Gas Pacifico/INNERGY.

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•	lower Canadian Mainline incentive earnings

•	lower earnings from Canadian Power due to lower realized power prices and PPA volumes from Western Power, lower earnings from Bruce Power due to higher planned outage days and higher operating expenses at Bruce A, partially offset by fewer planned outage days and lower lease expense at Bruce B and lower earnings on sale of unused natural gas transportation from Eastern Power

•	higher earnings from Liquids Pipelines due to higher contracted volumes

•	higher interest expense due to long-term debt issuances and the ceasing of capitalized interest on Keystone XL and related projects following the November 6, 2015 denial of a U.S. Presidential permit.

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a $59 million pre-tax charge relating to an impairment in value on turbine equipment previously purchased for a new power development project that did not proceed. Various other projects have recently been evaluated for possible use of this equipment and those evaluations support the impairment of the carrying value. The evaluation included a comparison to similar assets available for sale on the market

•	a pre-tax charge of $36 million related to Bruce Power's retirement of debt in conjunction with the merger of the Bruce A and Bruce B partnerships

•	unrealized losses from changes in the fair value of certain derivatives used to reduce our exposure to certain commodity price risks as follows:

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•	lower earnings from Western Power as a result of lower realized power prices and PPA volumes

•	lower earnings from Bruce Power due to lower volumes resulting from higher planned outage days and higher operating expenses at Bruce A, partially offset by higher volumes resulting from fewer planned outage days and lower lease expense at Bruce B

•	lower earnings from Eastern Power primarily due to lower earnings on the sale of unused natural gas transportation

•	a stronger U.S. dollar and its positive effect on the foreign exchange impact.

•	lower capacity revenue at Ravenswood due to lower realized capacity prices in New York and the impact of lower availability at the facility

•	lower realized power prices at our New England facilities

•	higher generation at our Ravenswood facility

•	higher sales to wholesale, commercial and industrial customers in both the PJM and New England markets.

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•	fair value and depreciation rates of plant, property and equipment (Note 7);

•	carrying value of regulatory assets and liabilities (Note 9);

•	fair value of goodwill (Note 10);

•	amortization rates and fair value of intangible assets (Note 11);

•	carrying value of asset retirement obligations (Note 14);

•	provisions for income taxes (Note 15);

•	assumptions used to measure retirement and other post-retirement obligations (Note 22);

•	fair value of financial instruments (Note 23); and

•	provision for commitments, contingencies and guarantees (Note 26).

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1	TCO is excluded from the ANR net book value at December 31, 2015 as it has been classified as an asset held for sale. Refer to Note 6 for further information.

2	Includes Bison, Portland Natural Gas Transmission System (PNGTS), North Baja, Tuscarora and Ventures LP.

3

Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $813 million and $142 million, respectively, at December 31, 2015 (2014 – $695 million and $103 million, respectively). Revenues of $93 million were recognized in 2015 (2014 – $81 million; 2013 – $78 million) through the sale of electricity under the related PPAs.

4	Includes Halton Hills, Coolidge, Bécancour, Ocean State Power, Mackay River and other natural gas-fired facilities.

5	Includes the acquisitions of four solar power facilities in 2014.

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1

The results reflect a 50.0 per cent interest in Northern Border as a result of the Company fully consolidating TC PipeLines, LP. At December 31, 2015, TransCanada had an ownership interest in TC PipeLines, LP of 28.0 per cent (2014 – 28.3 and 2013 – 28.9 per cent) and its effective ownership of Northern Border, net of non-controlling interests, was 14.0 per cent (2014 – 14.2 and 2013 – 14.5 per cent).

2	At December 31, 2015, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company is US$117 million (2014 – US$117 million) due to the fair value assessment of assets at the time of acquisition.

3

As a result of TransCanada's increased ownership in Bruce Power L.P. (Bruce B) and the merger of Bruce Power A L.P. (Bruce A) and Bruce B (to form Bruce Power) in December 2015, TransCanada has an ownership interest in Bruce Power of 48.5 per cent. Prior to the acquisition and merger, TransCanada applied equity accounting to its 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. TransCanada continues to apply equity accounting to Bruce Power. Refer to Note 25 for further information.

4	At December 31, 2015, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power is $973 million (2014 – $776 million) due to the fair value assessment of assets at the time of acquisitions.

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1	These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period.

2

Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determining tolls for the following calendar year. Pre-tax operating results in 2015 would have been $32 million lower (2014 – $28 million higher; 2013 – $76 million lower) had these amounts not been recorded as Regulatory assets and liabilities.

3

These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from customers in future rates. The balances are excluded from the rate base and do not earn a return on investment. Pre-tax operating results in 2015 would have been $26 million higher (2014 – $46 million lower; 2013 – $171 million higher) had these amounts not been recorded as regulatory assets and liabilities.

4	Pre-tax operating results in 2015 would have been $35 million lower (2014 – $2 million higher; 2013 – $2 million higher) had these amounts not been recorded as regulatory assets and liabilities.

5

Foreign exchange on long-term debt of the NGTL System and Foothills represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. In the absence of RRA, GAAP would have required the inclusion of these unrealized gains or losses in Net income.

6

Under the terms of ANR’s last rate settlement, ANR will be required to make refunds to its customers, pursuant to a refund plan to be approved by FERC in a future rate proceeding, of those amounts in the post-retirement benefit trust fund that have not been used to pay benefits to its employees. This regulatory liability represents the difference between the amount collected in rates and the amount of post-retirement benefits expense. ANR anticipates that the resolution of this liability will be determined through the section 4 rate case ANR filed with the FERC on January 29, 2016.  Since the timing of the rate case conclusion is uncertain, a settlement period cannot be determined at this time. Pre-tax operating results in 2015 would have been $30 million higher (2014 – $13 million higher; 2013 – $16 million higher) had these amounts not been recorded as regulatory assets and liabilities.

7	Pre-tax operating results in 2015 would have been $167 million higher (2014 – $418 million higher; 2013 – $247 million lower) had these amounts not been recorded as regulatory liabilities.

8

Effective January 1, 2015, NEB regulated pipelines including the Mainline, NGTL System, Foothills, Keystone and TQM are required to collect and set-aside funds received from customers to be used for future pipeline abandonment activities. Funds are collected through a surcharge mechanism, set-aside in trust accounts, and the obligation to use these funds for future pipeline abandonment activities is recorded as a regulatory liability. Pre-tax operating results in 2015 would have been $285 million higher (2014 – nil; 2013 – nil) had these amounts not been recorded as regulatory liabilities.

9	Pre-tax operating results in 2015 would have been $456 million higher (2014 – nil; 2013 – nil) had these amounts not been recorded as regulatory liabilities.

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1

TransCanada held a note receivable from the seller of Ravenswood of $213 million (US$154 million) and $213 million (US$184 million) as at December 31, 2015 and at December 31, 2014, which bears interest at 6.75 per cent and matures in 2040. The current portion included in Other current assets was $55 million (US$40 million) at December 31, 2015 and $46 million (US$40 million) at December 31, 2014.

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1	The asset impairment impact is net of $311 million attributed to higher foreign tax rates.

1	In 2015, an increase to the valuation allowance of $935 million was recorded as the Company believes that it is more likely than not that the tax benefits related to the unrealized foreign exchange losses on long-term debt and unrealized losses on certain impaired assets will not be realized in the future.

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1	As a result of retrospectively applying guidance on the presentation of deferred taxes on the Consolidated balance sheet on January 1, 2015, the Company reclassified its December 31, 2014 current Deferred income tax assets of $427 million, and current Deferred income tax liabilities of $4 million to its non-current Deferred income tax assets and liabilities.

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1	Interest rates are the effective interest rates except for those pertaining to Long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. Weighted average and effective interest rates are stated as at the respective outstanding dates.

2	Debentures issued by NGTL in the amount of $225 million have retraction provisions that entitle the holders to periodically require redemption of up to eight per cent of the then outstanding principal plus accrued and unpaid interest on specified repayment dates. No redemptions were made in 2015 or 2014.

3	Secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements.

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1	Amortization and other financial charges includes amortization of transaction costs and debt discounts calculated using the effective interest method and changes in the fair value of derivatives used to manage the Company's exposure to changes in interest rates.

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1	The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL.

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1	Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares.

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1	The holder is entitled to receive a fixed cumulative quarterly preferential dividend as and when declared by the Board with the exception of Series 2 and Series 4 preferred shares. The holders of Series 2 and Series 4 preferred shares are entitled to receive quarterly floating rate cumulative preferential dividends as and when declared by the Board.

2

TransCanada may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter. In addition, Series 2 and Series 4 preferred shares are redeemable by TransCanada at any time other than on a designated date for $25.50 per share plus all accrued and unpaid dividends on such redemption date, in which case they are redeemable at $25.00 per share plus all accrued and unpaid dividends.

3	The holder will have the right, subject to certain conditions, to convert their first preferred shares of a specified series into first preferred shares of another specified series on the conversion option date and every fifth anniversary thereafter.

4

Each of the even numbered series of preferred shares, if in existence, will be entitled to receive floating rate cumulative quarterly preferential dividends per share at an annualized rate equal to the 90-day Government of Canada Treasury bill rate plus 1.92 per cent (Series 2), 1.28 per cent (Series 4), 1.54 per cent (Series 6), 2.38 per cent (Series 8), 2.35 per cent (Series 10) and 2.96 per cent (Series 12). These rates will reset each quarter going forward.

5

The odd numbered series of preferred shares, if in existence, will be entitled to receive fixed rate cumulative quarterly preferential dividends which will reset on the redemption and conversion option date and every fifth year thereafter, equal to an annualized rate equal to the then five-year Government of Canada bond yield plus 1.92 per cent (Series 1), 1.28 per cent (Series 3), 1.54 per cent (Series 5), 2.38 per cent (Series 7), 2.35 per cent (Series 9), and 2.96 per cent (Series 11).

6	Net of underwriting commissions and deferred income taxes.

7	Commencing December 31, 2015, the floating quarterly dividend rate for the Series 2 preferred shares is 2.418 per cent and the Series 4 preferred shares is 1.778 per cent for the period starting December 31, 2015 to, but excluding, March 31, 2016. These rates will reset each quarter going forward.

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1	All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.

2	Other comprehensive income before reclassifications on currency translation adjustments is net of non-controlling interest gains of $306 million in 2015 (2014 – $130 million gains; 2013 – $66 million gains).

3

Losses related to cash flow hedges reported in AOCI and expected to be reclassified to Net income in the next 12 months are estimated to be $83 million ($51 million, net of tax) at December 31, 2015. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

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1	All amounts in parentheses indicate expenses to the Consolidated statement of income.

2	These Accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 22 for further information.

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1	The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other post-retirement benefit plans represents the accumulated post-retirement benefit obligation

2	Excludes $214 million in letters of credit provided to the Canadian DB Plans for funding purposes (2014 – $181 million).

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1	The projected benefit obligation for the pension benefit plan differs from the accumulated benefit obligation in that it includes an assumption with respect to future compensation levels.

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•	Forwards and futures contracts – contractual agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future. TransCanada enters into foreign exchange and commodity forwards and futures to manage the impact of changes in foreign exchange rates and commodity prices.

•	Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to manage the impact of changes in interest rates, foreign exchange rates and commodity prices.

•	Options – contractual agreements that convey the right, but not the obligation of the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. The Company enters into option agreements to manage the impact of changes in interest rates, foreign exchange rates and commodity prices.

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•	Subject to its overall risk management strategy, the Company commits a portion of its expected power supply to fixed-price medium-term or long-term sales contracts, while reserving an amount of unsold supply to manage operational and price risks in its asset portfolio.

•	The Company purchases a portion of the natural gas required for its power plants or enters into contracts that base the sale price of electricity on the cost of natural gas, effectively locking in a margin.

•	The Company's power sales commitments are fulfilled through power generation or through purchased contracts, thereby reducing the Company's exposure to fluctuating commodity prices.

•	The Company enters into offsetting or back-to-back positions using derivative instruments to manage price risk exposure in power and natural gas commodities created by certain fixed and variable pricing arrangements for different pricing indices and delivery points.

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1	Fair values equal carrying values.

2	In 2015, net realized gains of $8 million (2014 – gains of $21 million) related to the interest component of cross-currency swap settlements are included in Interest expense.

•	Dealing with creditworthy counterparties – a significant amount of the Company’s credit exposure is with investment grade counterparties or, if not, is generally partially supported by financial assurances from investment grade parties

•	Setting limits on the amount TransCanada can transact with any one counterparty – the Company monitors and manages the concentration of risk exposure with any one counterparty, and reduces the exposure when necessary and when it is allowed under the terms of the contracts

•	Using contract netting arrangements and obtaining financial assurances such as guarantees, letters of credit or cash when deemed necessary.

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1	Notes receivable are included in Other current assets and Intangible and other assets on the Consolidated balance sheet.

2	Long-term debt is recorded at amortized cost, except for US$850 million (2014 – US$400 million) that is attributed to hedged risk and recorded at fair value.

3

Consolidated Net income in 2015 included gains of $2 million (2014 – losses of $3 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$850 million of Long-term debt at December 31, 2015 (2014 – US$400 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

1	Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company would record these gains and losses as regulatory assets or liabilities. In 2015 and 2014, there were no net realized or unrealized gains or losses on LMCI restricted investments.

2	Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. In 2015 and 2014, there were no net realized or unrealized gains or losses on other restricted investments.

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1	Fair value equals carrying value.

2	Includes purchases and sales of power and natural gas.

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1	Fair value equals carrying value.

2	Includes purchases and sales of power and natural gas.

1	Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.

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1	Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.

1	Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative instruments held for trading are included net in Interest expense and Interest income and other, respectively.

2	In 2015, net realized gains on fair value hedges were $11 million (2014 – gains of $7 million) and were included in Interest expense.

3	In 2015 and 2014, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

1	No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI.

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2	Reported within Revenues on the Consolidated statement of income.

3	Reported within Interest expense on the Consolidated statement of income.

1	Amounts available for offset do not include cash collateral pledged or received.

1	Amounts available for offset do not include cash collateral pledged or received.

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1	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2015.

1	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2014.

1	Revenues include unrealized gains attributed to derivatives in the Level III category that were still held at December 31, 2015 of $7 million (2014 – $3 million).

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1	TransCanada's share of the potential estimated current or contingent exposure.

2	Except for one guarantee with no termination date.

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1	As at December 31.

2	The price/book multiple is determined by dividing price per common share by book value per common share as calculated by dividing common shareholders' equity by the number of common shares outstanding as at December 31.

4	The dividend yield is determined by dividing dividends per common share declared during the year by price per common share as at December 31.

5	Price per common share refers to market price per share as reported on the Toronto Stock Exchange as at December 31.

6	The price/earnings multiple is determined by dividing price per common share by the basic net income per share.

7	Debt includes Junior Subordinated Notes, total long-term debt, including the current portion of long-term debt, plus preferred securities as at December 31 and excludes long-term debt of joint ventures. Shareholders' equity in this ratio is as at December 31.

8	Total shareholder return is the sum of the change in price per common share plus the dividends received plus the impact of dividend re-investment in a calendar year, expressed as a percentage of the value of shares at the end of the previous year.

9

The earnings to fixed charges ratio is determined by dividing earnings by fixed charges. Earnings is calculated as the sum of EBIT and interest income and other, less income attributable to non-controlling interests with interest expense and undistributed earnings of investments accounted for by the equity method. Fixed charges is calculated as the sum of interest expense, and capitalized interest.

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1	Member, Governance Committee

2	Member, Human Resources Committee

3	Chair, Audit Committee

4	Member, Audit Committee

5	Member, Health, Safety & Environment Committee

6	Chair, Health, Safety & Environment Committee

7	Chair, Governance Committee

8	Chair, Human Resources Committee

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1.	I have reviewed this annual report on Form 40-F of TransCanada Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.	The issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting.

5.	The issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

1.	I have reviewed this annual report on Form 40-F of TransCanada Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.	The issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting.

5.	The issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.