TransCanada Reports Third Quarter 2015 Financial Results

CALGARY, ALBERTA--(Marketwired - Nov. 3, 2015) - TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada) today announced net income attributable to common shares for third quarter 2015 of $402 million or $0.57 per share compared to $457 million or $0.64 per share for the same period in 2014 and $1.2 billion or $1.72 per share compared to $1.3 billion or $1.81 per share on a year-to-date basis. Comparable earnings for third quarter 2015 were $440 million or $0.62 per share compared to $450 million or $0.63 per share for the same period last year. For the nine months ended September 30, 2015, comparable earnings were $1.3 billion or $1.84 per share compared to $1.2 billion or $1.70 per share in 2014. TransCanada's Board of Directors also declared a quarterly dividend of $0.52 per common share for the quarter ending December 31, 2015, equivalent to $2.08 per common share on an annualized basis.

"Over the past nine months, our diverse suite of high-quality long-life assets has performed well in a challenging environment with comparable earnings and funds generated from operations up eight and nine per cent, respectively, compared to the same period last year," said Russ Girling, TransCanada's president and chief executive officer. "The resiliency of our base business through various market conditions, combined with $12 billion of visible near-term growth projects, gives us the ability to continue growing the dividend at an annual rate of eight to ten per cent through 2017."

We are also focused on enhancing shareholder value by maximizing the effectiveness and efficiency of our existing operations. As part of those efforts, we recently commenced a business restructuring initiative that is expected to reduce overall costs. The changes will be undertaken in fourth quarter 2015 and continue into 2016.

Over the longer term, our portfolio of low-risk energy infrastructure assets and our financial strength leaves us well positioned to advance a number of other growth initiatives. They include $35 billion of commercially secured projects which would extend and augment future growth in earnings, cash flow and dividends.

Highlights

(All financial figures are unaudited and in Canadian dollars unless noted otherwise)

• Third quarter financial results
  • Net income attributable to common shares of $402 million or $0.57 per share
  • Comparable earnings of $440 million or $0.62 per share
  • Comparable earnings before interest, taxes, depreciation and amortization (EBITDA) of $1.5 billion 
  • Funds generated from operations of $1.1 billion
• Declared a quarterly dividend of $0.52 per common share for the quarter ending December 31, 2015
• Received final pipeline and facilities permits for the Prince Rupert Gas Transmission (PRGT) project in September
• Announced the acquisition of Ironwood, a strategically situated natural gas-fired power plant for US$654 million in October
• Reached an agreement with eastern Local Distribution Companies (LDCs) on the Energy East and Eastern Mainline Pipeline projects

Net income attributable to common shares decreased by $55 million to $402 million or $0.57 per share for the three months ended September 30, 2015 compared to the same period last year. Third quarter 2015 included a $6 million after-tax restructuring charge related to changes to our organizational structure while both periods included unrealized gains and losses from changes in risk management activities. All of these specific items are excluded from comparable earnings.

Comparable earnings for third quarter 2015 were $440 million or $0.62 per share compared to $450 million or $0.63 per share for the same period in 2014. Lower contributions from Bruce Power and Western Power were partially offset by higher earnings from the Keystone System, U.S. Power, ANR and Eastern Power.

Notable recent developments in Natural Gas Pipelines, Liquids Pipelines, Energy and Corporate include:

Natural Gas Pipelines:

• NGTL System Expansions: The NGTL System has approximately $6.8 billion of new supply and demand facilities under development. Approximately $2.8 billion of these facilities have received regulatory approval with $800 million currently under construction. In third quarter 2015, we continued to advance several of these capital expansion projects with an additional approximately $500 million of applied for facilities that now await regulatory review for approval. We have also received additional requests for firm receipt service that we anticipate will increase the overall capital spend on the NGTL System beyond the previously announced program and continue to work with our customers to best match their requirements for 2016, 2017 and 2018 in-service dates.
  
  
• LDC Agreement on Eastern Mainline Project and Energy East: On August 24, 2015, we announced an agreement 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 Eastern Mainline Project will provide gas consumers in Eastern Canada with sufficient natural gas transmission capacity and reduced natural gas transmission costs. As part of the agreement, we will size the Eastern Mainline Project to meet all firm requirements including gas transmission contracts resulting from both 2016 and 2017 new capacity open seasons plus approximately 50 million cubic feet per day of additional capacity.
  
  The Eastern Mainline Project capital cost is now estimated to be $2.0 billion with an expected in-service date of 2019. This increase resulted from the revised project scope resulting from the LDC agreement and updated cost estimates.
  
  
• PRGT: On June 11, 2015, Pacific North West (PNW) LNG announced a positive Final Investment Decision (FID) for its proposed liquefaction and export facility, subject to two conditions. The first condition, approval by the Legislative Assembly of B.C. of a Project Development Agreement between PNW LNG and the Province of B.C., was satisfied in mid-July 2015. The second condition is a positive regulatory decision on PNW LNG's environmental assessment by the Government of Canada. 
  
  In third quarter 2015, we received the remaining permits from the B.C. Oil and Gas Commission (BC OGC) which completes the 11 permits required to build and operate PRGT. Environmental permits for the project were also received in November 2014 from the B.C. Environmental Assessment Office.
  
  We also announced in third quarter 2015, the signing of project agreements with Metlakatla First Nation and Blueberry River First Nations. We are continuing our engagement with Aboriginal groups and have now signed project agreements with nine First Nation groups along the pipeline route.
  
  We remain ready to begin construction following confirmation of a FID by PNW LNG. The in-service date for PRGT is estimated to be 2020 but will be aligned with PNW LNG's liquefaction facility timeline.
  
  PRGT is a 900 kilometre (km) (559 mile) natural gas pipeline that will deliver gas from the Montney producing region at an expected interconnect on the NGTL System near Fort St. John, B.C. to PNW LNG's proposed LNG facility near Prince Rupert, B.C.
  
  
• Coastal GasLink: We have received eight of ten pipeline and facilities permits from the BC OGC and anticipate receiving the remaining two permits in fourth quarter 2015. We are continuing our engagement with Aboriginal groups and have signed project agreements with eight First Nation groups along the pipeline route.
  
  Coastal GasLink is a 670 km (416 mile) natural gas pipeline that will deliver gas from the Montney producing region at an expected interconnect on the NGTL System near Dawson Creek, B.C. to LNG Canada's proposed LNG facility near Kitimat, B.C. The project is subject to regulatory approvals and a positive FID.

Liquids Pipelines:

• Energy East Pipeline: In April 2015, we announced that the marine and associated tank terminal in Cacouna, Québec will not be built as a result of the recommended reclassification of beluga whales as an endangered species. Amendments to the project are expected to be submitted to the National Energy Board (NEB) in fourth quarter 2015. The NEB has continued to process the application in the interim.
  
  The alteration to the project scope and further refinement of the project schedule is expected to result in an in-service date of 2020. The original $12 billion cost estimate is expected to increase due to further scope refinement as we consult with stakeholders and escalation of construction costs as the project schedule is refined.
  
  
• Keystone XL: In January 2015, the Department of State re-initiated the national interest review and requested the eight federal agencies with a role in the review to complete their consideration of whether Keystone XL serves the national interest. All of the agency comments were submitted. The timing and ultimate resolution of Keystone XL's pending application for a Presidential Permit remains uncertain.
  
  Also in January 2015, Keystone XL initiated eminent domain actions against landowners in Nebraska who had not agreed to grant voluntary easements. These actions were taken under the eminent domain authority provided by the Governor's 2013 approval of the re-route in Nebraska. Several landowners then challenged those actions in Nebraska district court on the grounds that the law authorizing the Governor's approval violated the Nebraska constitution.
  
  In October 2015, we withdrew the eminent domain actions and moved to dismiss the constitutional court proceedings. The plaintiffs are resisting dismissal of this case; a hearing on that issue was held on October 19. A decision is expected in fourth quarter 2015.
  
  On October 5, 2015, we filed an application with the Nebraska Public Service Commission (PSC) for route approval through the state of Nebraska. The route we are seeking approval for is the same route previously approved by the Nebraska Department of Environmental Quality in January 2013. After careful review, we believe this would be the most expedient path to approval and expect the PSC to make a decision by third quarter 2016. On November 2, 2015, we sent a letter to U.S. Secretary of State John Kerry asking the Department of State to pause its review of the Presidential Permit application for Keystone XL while we seek Nebraska PSC approval of the route.
  
  On August 5, 2015, the South Dakota Public Utility Commission (PUC) concluded their hearing on Keystone XL's request to re-certify its existing permit authority in that state. The PUC is expected to make a decision by first quarter 2016.
  
  As of September 30, 2015, we have invested US$2.4 billion in the project and have also capitalized interest in the amount of US$0.4 billion.
  
  
• Grand Rapids Pipeline: On August 6, 2015, Grand Rapids Pipeline Limited Partnership (Grand Rapids) entered into an agreement to contribute the southernmost portion of the 20-inch diluent Grand Rapids Pipeline into a 50/50 joint venture with Keyera Corp (Keyera). The 45 km (28 mile) pipeline will be constructed by us and will extend from Keyera's Edmonton Terminal to our Heartland Terminal near Fort Saskatchewan. Keyera will also contribute a new pump station at its Edmonton terminal. We expect Grand Rapids' total contribution to the joint venture will be approximately $140 million. Keyera will operate the pipeline once construction is complete and the facilities are in-service. The expected in-service date is the second half of 2017 subject to regulatory approvals.
  
  

Energy:

• Ironwood Acquisition: On October 8, 2015, we reached an agreement to acquire the Ironwood natural gas-fired, combined cycle power plant in Lebanon, Pennsylvania, with a nameplate capacity of 778 megawatts (MW), from Talen Energy Corporation for US$654 million.
  
  The Ironwood power plant delivers energy into the PJM power market, North America's largest and most liquid energy region which includes a three-year forward capacity market. The facility provides us with a solid platform from which to continue to grow our wholesale, commercial and industrial customer base in this market area. Strategically located in proximity to the Marcellus shale gas play, the facility is well positioned to access competitively priced natural gas in a market that is in the midst of transitioning away from coal-fired power generation to gas.
  
  The acquisition is expected to be immediately accretive to earnings and cash flow and generate approximately US$90-$110 million in EBITDA annually through a combination of capacity payments and energy sales. The acquisition will be financed with a combination of cash on hand and available debt capacity and is expected to close early in first quarter 2016, subject to certain conditions being satisfied.
  
• Becancour: In August 2015, we executed an agreement with Hydro Quebec (HQ) to amend Becancour's electricity supply contract. The amendment allows HQ to dispatch up to 570 MW of firm peak winter capacity from the Becancour facility for a term of 20 years commencing in December 2016. Annual payments received for this new service will be incremental to existing capacity payments earned under the new agreement. In October 2015, the Regie de l'energie approved the amended contract.
  

Corporate:

• Our Board of Directors declared a quarterly dividend of $0.52 per share for the quarter ending December 31, 2015 on TransCanada's outstanding common shares. The quarterly amount is equivalent to $2.08 per common share on an annualized basis.
  
  
• Financing Activities: In July 2015, we issued $750 million of medium-term notes maturing on July 17, 2025 bearing interest at 3.30 per cent and in October 2015, we issued $400 million of medium-term notes maturing on November 15, 2041 bearing interest at 4.55 per cent.
  
  The net proceeds of these offerings will be used for general corporate purposes and to reduce short-term indebtedness which was used to fund a portion of our capital program and for general corporate purposes.
  
  
• Management Changes and Corporate Restructuring: Effective October 1, 2015, Alex Pourbaix was appointed as Chief Operating Officer. Don Marchand was appointed Executive Vice-President, Corporate Development and Chief Financial Officer and Kristine Delkus was appointed Executive Vice-President, Stakeholder Relations and General Counsel. Jim Baggs, Executive Vice-President, Operations and Engineering, has announced his intention to retire in early 2016.
  
  In mid-2015, we commenced a business restructuring initiative. While there is no change to our corporate strategy, we have undertaken this initiative to reduce overall costs and maximize the effectiveness and efficiency of our existing operations. We expect the changes to be undertaken in fourth quarter 2015 and continue into 2016.

Teleconference and Webcast:

We will hold a teleconference and webcast on Tuesday, November 3, 2015 to discuss our third quarter 2015 financial results. Russ Girling, TransCanada President and Chief Executive Officer, and Don Marchand, Executive Vice-President, Corporate Development and Chief Financial Officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and Company developments at 9 a.m. (MT) / 11 a.m. (ET).

Analysts, members of the media and other interested parties are invited to participate by calling 866.225.6564 or 416.340.2218 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available at www.transcanada.com.

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (ET) on November 10, 2015. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 9292695.

The unaudited interim Consolidated Financial Statements and Management's Discussion and Analysis (MD&A) are available under TransCanada's profile on SEDAR at www.sedar.com, with the U.S. Securities and Exchange Commission on EDGAR at www.sec.gov/info/edgar.shtml and on the TransCanada website at www.transcanada.com.

With more than 65 years' experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and liquids pipelines, power generation and gas storage facilities. TransCanada operates a network of natural gas pipelines that extends more than 68,000 kilometres (42,100 miles), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent's largest providers of gas storage and related services with 368 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns or has interests in over 10,900 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America's largest liquids delivery systems. TransCanada's common shares trade on the Toronto and New York stock exchanges under the symbol TRP. Visit TransCanada.com and our blog to learn more, or connect with us on social media and 3BL Media.

Forward Looking Information

This news release contains certain information that is forward-looking and is subject to important risks and uncertainties (such statements are usually accompanied by words such as "anticipate", "expect", "believe", "may", "will", "should", "estimate", "intend" or other similar words). Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future plans and financial outlook. All forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update or revise any forward-looking information except as required by law. For additional information on the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, refer to TransCanada's Quarterly Report to Shareholders dated November 2, 2015 and 2014 Annual Report on our website at www.transcanada.com or filed under TransCanada's profile on SEDAR at www.sedar.com and with the U.S. Securities and Exchange Commission at www.sec.gov.

Non-GAAP Measures

This news release contains references to non-GAAP measures, including comparable earnings, comparable EBITDA, funds generated from operations and comparable earnings per share, that do not have any standardized meaning as prescribed by U.S. GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. These non-GAAP measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable. For more information on non-GAAP measures, refer to TransCanada's Quarterly Report to Shareholders dated November 2, 2015.

Quarterly report to shareholders
Third quarter 2015
Financial highlights
		three months ended September 30			nine months ended September 30
(unaudited - millions of $, except per share amounts)		2015	2014		2015		2014
Income
Revenue		2,944	2,451		8,449		7,569
Net income attributable to common shares		402	457		1,218		1,285
	per common share - basic and diluted	$0.57	$0.64		$1.72		$1.81
Comparable EBITDA1		1,483	1,387		4,381		4,000
Comparable earnings1		440	450		1,302		1,204
	per common share1	$0.62	$0.63		$1.84		$1.70
Operating cash flow
Funds generated from operations1		1,140	1,071		3,354		3,090
Decrease/(increase) in operating working capital		107	171		(378	)	250
Net cash provided by operations		1,247	1,242		2,976		3,340
Investing activities
Capital expenditures		976	744		2,748		2,381
Capital projects under development		130	207		465		504
Equity investments		105	66		303		195
Acquisitions		-	181		-		181
Proceeds from sale of assets, net of transaction costs		-	-		-		187
Dividends declared
Per common share		$0.52	$0.48		$1.56		$1.44
Basic common shares outstanding (millions)
Average for the period		709	708		709		708
End of period		709	709		709		709

(1)	Comparable EBITDA, comparable earnings, comparable earnings per common share and funds generated from operations are all non-GAAP measures. See the non-GAAP measures section for more information.

Management's discussion and analysis

November 2, 2015

This management's discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the three and nine months ended September 30, 2015, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2015 which have been prepared in accordance with U.S. GAAP.

This MD&A should also be read in conjunction with our December 31, 2014 audited consolidated financial statements and notes and the MD&A in our 2014 Annual Report. 

About this document

Throughout this MD&A, the terms, we, us, our and TransCanada mean TransCanada Corporation and its subsidiaries.

Abbreviations and acronyms that are not defined in this MD&A are defined in the glossary in our 2014 Annual Report.

All information is as of November 2, 2015 and all amounts are in Canadian dollars, unless noted otherwise.

FORWARD-LOOKING INFORMATION

We disclose forward-looking information to help current and potential investors understand management's assessment of our future plans and financial outlook, and our future prospects overall.

Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.

Forward-looking statements in this MD&A may include information about the following, among other things:

• 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 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.

Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this MD&A.

Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties:

Assumptions

• 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.

Risks and uncertainties

• 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 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.

You can read more about these factors and others in reports we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2014 Annual Report.

You should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, except as required by law.

FOR MORE INFORMATION

You can find more information about TransCanada in our annual information form and other disclosure documents, which are available on SEDAR (www.sedar.com).

NON-GAAP MEASURES

We use the following non-GAAP measures:

• EBITDA
• EBIT
• funds generated from operations
• comparable earnings
• comparable earnings per common share
• comparable EBITDA
• comparable EBIT
• comparable depreciation and amortization
• comparable interest expense
• comparable interest income and other expense
• comparable income tax expense.

These measures do not have any standardized meaning as prescribed by U.S. GAAP and therefore may not be comparable to similar measures presented by other entities. Please see the Reconciliation of non-GAAP measures section in this MD&A for a reconciliation of the GAAP measures to the non-GAAP measures.

EBITDA and EBIT

We use EBITDA as an approximate measure of our pre-tax operating cash flow. It measures our earnings before deducting financial charges, income tax, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends, and includes income from equity investments. EBIT measures our earnings from ongoing operations and is a useful measure of our performance and an effective tool for evaluating trends in each segment as it is equivalent to our segmented earnings. It is calculated in the same way as EBITDA, less depreciation and amortization.

Funds generated from operations

Funds generated from operations includes net cash provided by operations before changes in operating working capital. We believe it is a useful measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period, and is used to provide a consistent measure of the cash generating performance of our assets. See the Financial condition section for a reconciliation to net cash provided by operations.

Comparable measures

We calculate the comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.

Comparable measure	Original measure
comparable earnings	net income attributable to common shares
comparable earnings per common share	net income per common share
comparable EBITDA	EBITDA
comparable EBIT	segmented earnings
comparable depreciation and amortization	depreciation and amortization
comparable interest expense	interest expense
comparable interest income and other expense	interest income and other expense
comparable income tax expense	income tax expense

Our decision not to include a specific item is subjective and made after careful consideration. Specific items may include:

• certain fair value adjustments relating to risk management activities
• income tax refunds and adjustments and changes to enacted rates
• 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
• write-downs of assets and investments.

We calculate comparable earnings by excluding the unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges, but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them reflective of our underlying operations.

Consolidated results - third quarter 2015
	three months ended September 30					nine months ended September 30
(unaudited - millions of $, except per share amounts)	2015		2014			2015		2014
Natural Gas Pipelines	528		484			1,648		1,566
Liquids Pipelines	287		226			783		613
Energy	249		359			730		832
Corporate	(45	)	(37	)		(140	)	(107	)
Total segmented earnings	1,019		1,032			3,021		2,904
Interest expense	(341	)	(304	)		(990	)	(875	)
Interest income and other expense	16		17			83		63
Income before income taxes	694		745			2,114		2,092
Income tax expense	(223	)	(239	)		(680	)	(625	)
Net income	471		506			1,434		1,467
Net income attributable to non-controlling interests	(46	)	(25	)		(145	)	(110	)
Net income attributable to controlling interests	425		481			1,289		1,357
Preferred share dividends	(23	)	(24	)		(71	)	(72	)
Net income attributable to common shares	402		457			1,218		1,285
Net income per common share - basic and diluted	$0.57		$0.64			$1.72		$1.81

Net income attributable to common shares decreased by $55 million and $67 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014. The 2015 results included:

• a charge of $6 million after tax in third quarter and $14 million after tax year-to-date for severance costs as part of a restructuring initiative to maximize the effectiveness and efficiency of our existing operations along with the restructuring of our major projects group in response to delayed timelines on certain of our major projects in second quarter 2015
• a $34 million adjustment in second quarter 2015 to income tax expense due to the enactment of a two per cent increase in the Alberta corporate income tax rate in June 2015.

The nine-month 2014 results included:

• a gain on sale of Cancarb Limited and its related power generation business of $99 million after tax
• a net loss resulting from the termination of a contract with Niska Gas Storage of $32 million after tax.

Net income in all periods included unrealized gains and losses from changes in risk management activities which we exclude, along with the above-noted items, to arrive at comparable earnings.

Comparable earnings decreased by $10 million for the three months ended September 30, 2015 and increased $98 million for the nine months ended September 30, 2015 compared to the same periods in 2014 as discussed below in the reconciliation of net income to comparable earnings.

RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS
		three months ended September 30				nine months ended September 30
(unaudited - millions of $, except per share amounts)		2015	2014			2015	2014
Net income attributable to common shares		402	457			1,218	1,285
Specific items (net of tax):
	Alberta corporate income tax rate increase	-	-			34	-
	Restructuring costs	6	-			14	-
	Cancarb gain on sale	-	-			-	(99	)
	Niska contract termination	-	1			-	32
	Risk management activities1	32	(8	)		36	(14	)
Comparable earnings		440	450			1,302	1,204
Net income per common share		$0.57	$0.64			$1.72	$1.81
Specific items (net of tax):
	Alberta corporate income tax rate increase	-	-			0.05	-
	Restructuring costs	0.01	-			0.02	-
	Cancarb gain on sale	-	-			-	(0.14	)
	Niska contract termination	-	-			-	0.04
	Risk management activities1	0.04	(0.01	)		0.05	(0.01	)
Comparable earnings per share		$0.62	$0.63			$1.84	$1.70

	(1)	Risk management activities	three months ended September 30					nine months ended September 30
		(unaudited - millions of $)	2015		2014			2015		2014
		Canadian Power	(14	)	2			(7	)	-
		U.S. Power	(5	)	41			(22	)	30
		Natural Gas Storage	2		7			2		4
		Foreign exchange	(26	)	(32	)		(25	)	(9	)
		Income tax attributable to risk management activities	11		(10	)		16		(11	)
		Total (losses)/gains from risk management activities	(32	)	8			(36	)	14

Comparable earnings decreased by $10 million for the three months ended September 30, 2015 compared to the same period in 2014. This was primarily the net effect of:

• lower earnings from Bruce Power due to lower volumes resulting from higher planned outage days and higher operating expenses at Bruce A, as well as losses from contracting activities and higher operating expenses, partially offset by lower lease expense at Bruce B
• lower earnings from Western Power as a result of lower realized power prices
• higher interest expense from new debt issuances
• higher earnings from Liquids Pipelines due to higher uncontracted volumes on the Keystone Pipeline System
• higher earnings from U.S. Power due to increased margins and sales volumes to wholesale, commercial and industrial customers, partially offset by lower realized capacity prices in New York
• higher ANR Southeast mainline transportation revenue, partially offset by increased spending on ANR pipeline integrity work
• higher earnings from Eastern Power due to incremental earnings from Ontario solar facilities acquired in the second half of 2014.

Comparable earnings increased by $98 million for the nine months ended September 30, 2015 compared to the same period in 2014. This was primarily the net effect of:

• higher earnings from Liquids Pipelines due to higher uncontracted volumes on the Keystone Pipeline System
• higher earnings from Eastern Power due to incremental earnings from Ontario solar facilities acquired in 2014, higher contractual earnings at Bécancour and the sale of unused natural gas transportation
• higher earnings from U.S. Power mainly due to increased margins and higher sales volumes to wholesale, commercial and industrial customers, partially offset by lower realized capacity prices in New York and lower earnings on U.S. generating assets as a result of lower realized power prices and reduced generation
• higher earnings from U.S. and International Pipelines due to higher ANR Southeast transportation revenue 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, plus increased earnings from the Tamazunchale Extension which was placed in service in 2014
• lower earnings from Western Power as a result of lower realized power prices
• higher interest expense from debt issuances.

The stronger U.S. dollar this quarter compared to the same period in 2014 positively impacted the translated results in our U.S. businesses, however, this impact was partially offset by a corresponding increase in interest expense on U.S. dollar-denominated debt as well as realized losses on foreign exchange hedges used to manage our exposure.

CAPITAL PROGRAM

We are developing quality projects under our long-term capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties or regulated business models and are expected to generate significant growth in earnings and cash flow.

Our capital program is comprised of $11 billion of small to medium-sized, shorter-term projects, $35 billion of commercially secured large-scale, medium and longer-term projects and $1 billion of acquisitions. Amounts presented exclude the impact of foreign exchange, AFUDC and capitalized interest.

Estimated project costs are generally based on the last announced project estimates and are subject to adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits.

at September 30, 2015
(unaudited - billions of $)			Segment	Expected in-service date	Estimated project cost	Amount spent
Small to medium sized, shorter-term
Houston Lateral and Terminal			Liquids Pipelines	2016	US 0.6	US 0.5
Topolobampo			Natural Gas Pipelines	2016	US 1.0	US 0.8
Mazatlan			Natural Gas Pipelines	2016	US 0.4	US 0.3
Grand Rapids1			Liquids Pipelines	2016-2017	1.5	0.4
Northern Courier			Liquids Pipelines	2017	1.0	0.5
Canadian Mainline			Natural Gas Pipelines	2015-2016	0.4	-
NGTL System
	- North Montney		Natural Gas Pipelines	2017	1.7	0.3
	- 2016/17 Facilities		Natural Gas Pipelines	2016-2018	2.7	0.2
	- Other		Natural Gas Pipelines	2015-2017	0.5	0.2
Napanee			Energy	2017 or 2018	1.0	0.3
					10.8	3.5
Large-scale, medium and longer-term
Heartland and TC Terminals			Liquids Pipelines	2	0.9	0.1
Upland			Liquids Pipelines	2020	US 0.6	-
Keystone projects
	Keystone XL3		Liquids Pipelines	4	US 8.0	US 2.4
	Keystone Hardisty Terminal		Liquids Pipelines	4	0.3	0.2
Energy East projects
	Energy East5		Liquids Pipelines	2020	12.0	0.7
	Eastern Mainline		Natural Gas Pipelines	2019	2.0	0.1
BC west coast LNG-related projects
	Coastal GasLink		Natural Gas Pipelines	2019+	4.8	0.3
	Prince Rupert Gas Transmission		Natural Gas Pipelines	2020	5.0	0.4
	NGTL System - Merrick		Natural Gas Pipelines	2020	1.9	-
					35.5	4.2
Acquisition
Ironwood				2016	US 0.7	-
					47.0	7.7

(1)	Represents our 50 per cent share.
(2)	In-service date to be aligned with industry requirements.
(3)	Estimated project cost dependent on the timing of the Presidential permit.
(4)	Approximately two years from the date the Keystone XL permit is received.
(5)	Excludes transfer of Canadian Mainline natural gas assets.

Outlook

The earnings outlook for 2015 is expected to be consistent with what was previously included in the 2014 Annual Report. See the MD&A in our 2014 Annual Report for further information about our outlook.

We expect our capital expenditures to be approximately $5 billion for 2015, a decrease of $1 billion from the outlook previously provided in our 2014 Annual Report due to project timing delays.

Natural Gas Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure).

	three months ended September 30					nine months ended September 30
(unaudited - millions of $)	2015		2014			2015		2014
Comparable EBITDA	812		750			2,493		2,357
Comparable depreciation and amortization1	(284	)	(266	)		(845	)	(791	)
Comparable EBIT	528		484			1,648		1,566
Specific items2	-		-			-		-
Segmented earnings	528		484			1,648		1,566

(1)	Comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization.
(2)	There were no specific items in any of these periods.

Natural Gas Pipelines segmented earnings increased by $44 million and $82 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 and are equivalent to comparable EBIT which, along with comparable EBITDA, are discussed below.

	three months ended September 30					nine months ended September 30
(unaudited - millions of $)	2015		2014			2015		2014
Canadian Pipelines
Canadian Mainline	289		311			876		938
NGTL System	226		213			675		637
Foothills	26		26			81		80
Other Canadian pipelines1	7		7			21		17
Canadian Pipelines - comparable EBITDA	548		557			1,653		1,672
Comparable depreciation and amortization	(212	)	(206	)		(632	)	(613	)
Canadian Pipelines - comparable EBIT	336		351			1,021		1,059
U.S. and International Pipelines (US$)
ANR	54		31			177		142
TC PipeLines, LP1,2	25		18			76		65
Great Lakes3	8		8			35		36
Other U.S. pipelines (Bison4, Iroquois1, GTN5, Portland6)	13		26			66		100
Mexico (Guadalajara, Tamazunchale)	44		43			138		117
International and other1,7	(2	)	(3	)		2		(5	)
Non-controlling interests8	68		49			208		176
U.S. and International Pipelines - comparable EBITDA	210		172			702		631
Comparable depreciation and amortization	(55	)	(54	)		(169	)	(162	)
U.S. and International Pipelines - comparable EBIT	155		118			533		469
Foreign exchange impact	49		10			138		44
U.S. and International Pipelines - comparable EBIT (Cdn$)	204		128			671		513
Business Development comparable EBITDA and EBIT	(12	)	5			(44	)	(6	)
Natural Gas Pipelines - comparable EBIT	528		484			1,648		1,566

(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. 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.

			Ownership percentage as of
			September 30, 2015	April 1, 2015	October 1, 2014	January 1, 2014
	TC PipeLines, LP		28.2	28.3	28.3	28.9
	Effective ownership through TC PipeLines, LP:
		Bison	28.2	28.3	28.3	20.2
		GTN	28.2	28.3	19.8	20.2
		Great Lakes	13.1	13.1	13.1	13.4

(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 interest 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 Gas Pacifico/INNERGY and TransGas as well as general and administration costs relating to our U.S. and International Pipelines. In November 2014, we sold our interest in Gas Pacifico/INNERGY.
(8)	Comparable EBITDA for the portions of TC PipeLines, LP and Portland we do not own.

CANADIAN PIPELINES

Net income and comparable EBITDA for our rate-regulated Canadian pipelines are generally affected by the approved ROE, investment base, level of deemed common equity, incentive earnings or losses and certain carrying charges. Changes in depreciation, financial charges and taxes also impact comparable EBITDA and comparable EBIT but do not impact net income as they are recovered in revenue on a flow-through basis.

NET INCOME - WHOLLY OWNED CANADIAN PIPELINES
	three months ended September 30					nine months ended September 30
(unaudited - millions of $)	2015		2014			2015		2014
Canadian Mainline	47		61			161		185
NGTL System	70		61			200		182
Foothills	3		5			11		13

Net income for the Canadian Mainline decreased by $14 million and $24 million for the three months and nine months ended September 30, 2015 compared to the same periods in 2014. The decrease in net income is primarily due to a lower ROE of 10.10 per cent on deemed equity of 40 per cent in 2015 compared to 11.5 per cent in 2014 and a lower average investment base in 2015, partially offset by higher incentive earnings recorded in 2015 primarily in second quarter.

Net income for the NGTL System increased by $9 million and $18 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 mainly due to a higher average investment base and OM&A incentive losses realized in 2014 under the terms of the 2013-2014 NGTL Settlement.

U.S. AND INTERNATIONAL PIPELINES

Earnings for our U.S. natural gas pipelines operations are generally affected by contracted volume levels, volumes delivered and the rates charged as well as by the cost of providing services, including OM&A and property taxes. ANR is also affected by the contracting and pricing of its storage capacity and incidental commodity sales.

Comparable EBITDA for U.S. and International Pipelines increased by US$38 million for the three months ended September 30, 2015 compared to the same period in 2014. This increase was the net effect of higher ANR Southeast mainline transportation revenue, partially offset by increased spending on ANR pipeline integrity work.

Comparable EBITDA for U.S. and International Pipelines increased by US$71 million for the nine months ended September 30, 2015 compared to the same period in 2014. This increase was the net effect of:

• higher ANR Southeast mainline transportation revenue 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.

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

COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization increased by $18 million and $54 million for three and nine months ended September 30, 2015 compared to the same periods in 2014 mainly because of a higher investment base on the NGTL System, depreciation for the completed Tamazunchale Extension, and the effect of a stronger U.S. dollar.

BUSINESS DEVELOPMENT

Business development expenses were higher by $17 million and $38 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 mainly due to increased business development activity as well as the third quarter 2014 recovery of amounts from partners for 2013 Alaska Gasline Inducement Act costs.

OPERATING STATISTICS - WHOLLY OWNED PIPELINES
nine months ended September 30		Canadian Mainline1			NGTL System2			ANR3
(unaudited)		2015	2014		2015	2014		2015	2014
Average investment base (millions of $)		4,840	5,632		6,599	6,205		n/a	n/a
Delivery volumes (Bcf)
	Total	1,204	1,264		2,871	2,857		1,212	1,202
	Average per day	4.4	4.6		10.5	10.5		4.4	4.4

(1)	Canadian Mainline's throughput volumes represent physical deliveries to domestic and export markets. Physical receipts originating at the Alberta border and in Saskatchewan for the nine months ended September 30, 2015 were 833 Bcf (2014 - 940 Bcf). Average per day was 3.1 Bcf (2014 - 3.5 Bcf).
(2)	Field receipt volumes for the NGTL System for the nine months ended September 30, 2015 were 2,994 Bcf (2014 - 2,857 Bcf). Average per day was 11.0 Bcf (2014 - 10.5 Bcf).
(3)	Under its current rates, which are approved by the FERC, changes in average investment base do not affect results.

Liquids Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure).

	three months ended September 30					nine months ended September 30
(unaudited - millions of $)	2015		2014			2015		2014
Comparable EBITDA	355		281			980		771
Comparable depreciation and amortization1	(68	)	(55	)		(197	)	(158	)
Comparable EBIT	287		226			783		613
Specific items2	-		-			-		-
Segmented earnings	287		226			783		613

(1)	Comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization.
(2)	There were no specific items in any of these periods.

Liquids Pipelines segmented earnings increased by $61 million and $170 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 and are equivalent to comparable EBIT which, along with comparable EBITDA, are discussed below.

	three months ended September 30					nine months ended September 30
(unaudited - millions of $)	2015		2014			2015		2014
Keystone Pipeline System	363		275			997		779
Liquids Pipelines Business Development	(8	)	6			(17	)	(8	)
Liquids Pipelines - comparable EBITDA	355		281			980		771
Comparable depreciation and amortization	(68	)	(55	)		(197	)	(158	)
Liquids Pipelines - comparable EBIT	287		226			783		613
Comparable EBIT denominated as follows:
Canadian dollars	58		58			175		157
U.S. dollars	173		155			480		417
Foreign exchange impact	56		13			128		39
	287		226			783		613

Comparable EBITDA for the Keystone Pipeline System is generated primarily by providing pipeline capacity to shippers for fixed monthly payments that are not linked to actual throughput volumes. Uncontracted capacity is offered to the market on a spot basis and provides opportunities to generate incremental earnings.

Comparable EBITDA for the Keystone Pipeline System increased by $88 million and $218 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014. These increases were primarily due to:

• higher uncontracted volumes
• a stronger U.S. dollar and its positive effect on the foreign exchange impact
• incremental earnings from the Gulf Coast extension which was placed in service in late January 2014.

BUSINESS DEVELOPMENT

Business development expenses increased by $14 million and $9 million for the three and nine months ended September 30, 2015, as a result of increased business development activities. 

COMPARABLE DEPRECIATION AND AMORTIZATION

Comparable depreciation and amortization increased by $13 million and $39 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 due to the Gulf Coast extension being placed in service and the effect of a stronger U.S. dollar.

Energy

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure).

		three months ended September 30					nine months ended September 30
(unaudited - millions of $)		2015		2014			2015		2014
Comparable EBITDA		345		387			1,005		963
Comparable depreciation and amortization1		(79	)	(76	)		(248	)	(230	)
Comparable EBIT		266		311			757		733
Specific items (pre-tax):
	Cancarb gain on sale	-		-			-		108
	Niska contract termination	-		(2	)		-		(43	)
	Risk management activities	(17	)	50			(27	)	34
Segmented earnings		249		359			730		832

(1)	Comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization.

Energy segmented earnings decreased by $110 million and $102 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 and included the following unrealized gains and losses from risk management activities:

(1)	Risk management activities	three months ended  September 30				nine months ended September 30
	(unaudited - millions of $, pre-tax)	2015		2014		2015		2014
	Canadian Power	(14	)	2		(7	)	-
	U.S. Power	(5	)	41		(22	)	30
	Natural Gas Storage	2		7		2		4
	Total (losses)/gains from risk management activities	(17	)	50		(27	)	34

The period-over-period variances in these unrealized gains and losses reflect the impact of changes in forward natural gas and power prices and the volume of our positions for these derivatives over a certain period of time; however, they do not accurately reflect the gains and losses that will be realized on settlement, or the offsetting impact of other derivative and non-derivative transactions that make up our business as a whole. As a result, we do not consider them reflective of our underlying operations.

The remainder of the Energy segmented earnings are equivalent to comparable EBIT which, along with EBITDA, are discussed below.

	three months ended September 30					nine months ended September 30
(unaudited - millions of $)	2015		2014			2015		2014
Canadian Power
Western Power	24		75			73		193
Eastern Power	87		76			309		239
Bruce Power	57		111			202		199
Canadian Power- comparable EBITDA1	168		262			584		631
Comparable depreciation and amortization	(47	)	(44	)		(141	)	(133	)
Canadian Power-comparable EBIT1	121		218			443		498
U.S. Power (US$)
U.S. Power - comparable EBITDA	141		117			338		291
Comparable depreciation and amortization	(23	)	(26	)		(78	)	(80	)
U.S. Power - comparable EBIT	118		91			260		211
Foreign exchange impact	36		8			68		19
U.S. Power-comparable EBIT (Cdn$)	154		99			328		230
Natural Gas Storage and other - comparable EBITDA	(1	)	3			8		32
Comparable depreciation and amortization	(3	)	(3	)		(9	)	(9	)
Natural Gas Storage and other - comparable EBIT	(4	)	-			(1	)	23
Business Development comparable EBITDA and EBIT	(5	)	(6	)		(13	)	(18	)
Energy-comparable EBIT1	266		311			757		733

(1)	Includes our share of equity income from our investments in ASTC Power Partnership, Portlands Energy and Bruce Power.

Comparable EBITDA for Energy decreased by $42 million for the three months ended September 30, 2015 compared to the same period in 2014 due to the net effect of:

• lower earnings from Bruce Power due to lower volumes resulting from higher planned outage days and higher operating expenses at Bruce A, as well as losses from contracting activities and higher operating expenses, partially offset by lower lease expense at Bruce B
• lower earnings from Western Power as a result of lower realized power prices
• higher earnings from U.S. Power due to increased margins and sales volumes to wholesale, commercial and industrial customers, partially offset by lower realized capacity prices in New York
• higher earnings from Eastern Power due to incremental earnings from Ontario solar facilities acquired in 2014
• a stronger U.S. dollar and its positive effect on the foreign exchange impact.

Comparable EBITDA for Energy increased by $42 million for the nine months ended September 30, 2015 compared to the same period in 2014 due to the net effect of:

• higher earnings from Eastern Power due to incremental earnings from Ontario solar facilities acquired in 2014, higher contractual earnings at Bécancour and the sale of unused natural gas transportation 
• higher earnings from U.S. Power mainly due to increased margins and higher sales volumes to wholesale, commercial and industrial customers, partially offset by lower realized capacity prices in New York and lower earnings on U.S. generating assets as a result of lower realized power prices and generation
• lower earnings from Western Power as a result of lower realized power prices
• lower earnings from Natural Gas Storage due to lower realized natural gas price spreads
• a stronger U.S. dollar and its positive effect on the foreign exchange impact.

CANADIAN POWER
Western and Eastern Power
	three months ended September 30					nine months ended September 30
(unaudited - millions of $)	2015		2014			2015		2014
Revenue1
Western Power	126		206			412		547
Eastern Power	119		92			358		322
Other2	1		-			49		57
	246		298			819		926
(Loss)/income from equity investments3	(2	)	14			13		42
Commodity purchases resold	(83	)	(105	)		(266	)	(296	)
Plant operating costs and other	(64	)	(54	)		(191	)	(240	)
Exclude risk management activities1	14		(2	)		7		-
Comparable EBITDA	111		151			382		432
Comparable depreciation and amortization	(47	)	(44	)		(141	)	(133	)
Comparable EBIT	64		107			241		299
Breakdown of comparable EBITDA
Western Power	24		75			73		193
Eastern Power	87		76			309		239
Comparable EBITDA	111		151			382		432

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

Sales volumes and plant availability

Includes our share of volumes from our equity investments.

			three months ended September 30					nine months ended September 30
(unaudited)			2015		2014			2015		2014
Sales volumes (GWh)
Supply
	Generation
		Western Power	589		637			1,876		1,857
		Eastern Power	1,083		563			3,145		2,436
	Purchased
		Sundance A & B and Sheerness PPAs1	2,948		2,791			7,808		8,189
		Other purchases	67		2			95		9
			4,687		3,993			12,924		12,491
Sales
	Contracted
		Western Power	2,188		2,585			5,627		7,480
		Eastern Power	1,083		563			3,145		2,436
	Spot
		Western Power	1,416		845			4,152		2,575
			4,687		3,993			12,924		12,491
Plant availability2
Western Power3			96	%	96	%		97	%	95	%
Eastern Power4,5			96	%	99	%		97	%	90	%

(1)	Includes our 50 per cent ownership interest of Sundance B volumes through the ASTC Power Partnership.
(2)	The percentage of time the plant was available to generate power, regardless of whether it was running.
(3)	Does not include facilities that provide power to us under PPAs.
(4)	Does not include Bécancour because power generation has been suspended since 2008.
(5)	Lower plant availability for the nine months ended September 30, 2014 in Eastern Power was due to a maintenance outage in second quarter 2014.

Western Power

Comparable EBITDA for Western Power decreased by $51 million and $120 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014. The decreases were due to lower realized power prices.

Average spot market power prices in Alberta decreased by 59 per cent from $64/MWh to $26/MWh for the three months ended September 30, 2015 and decreased 34 per cent from $56/MWh to $37/MWh for the nine months ended September 30, 2015, compared to the same periods in 2014. The addition of new natural gas-fired and wind plants over the last 12 months have contributed to a well supplied market and very few higher priced hours were observed in spite of seasonally higher summer energy consumption levels. Realized power prices on power sales can be higher or lower than spot market power prices in any given period as a result of contracting activities.

The decrease in equity earnings for the three and nine months ended September 30, 2015 of $16 million and $29 million compared to the same periods in 2014 is primarily due to the impact of lower Alberta spot market prices on earnings from the ASTC Power Partnership which holds our 50 per cent ownership interest in the Sundance B PPA. Equity earnings does not include the impact of related contracting activities.

Lower Alberta spot power prices are expected to continue in the near term and 2015 Western Power earnings are anticipated to be significantly lower compared to 2014 and lower than our original Outlook in the MD&A in our 2014 Annual Report due to a longer than expected period of over-supply in the Alberta power market.

Sixty-one per cent of Western Power sales volumes were sold under contract in third quarter 2015 compared to 75 per cent in third quarter 2014.

Eastern Power

Comparable EBITDA for Eastern Power increased by $11 million for the three months ended September 30, 2015 compared to the same period in 2014 mainly due to incremental earnings from solar facilities acquired in 2014.

Comparable EBITDA for Eastern Power increased by $70 million for the nine months ended September 30, 2015 compared to the same period in 2014 mainly due to incremental earnings from solar facilities acquired in 2014, higher contractual earnings at Bécancour, the sale of unused natural gas transportation and higher earnings at Halton Hills. 

BRUCE POWER

Our proportionate share

		three months ended September 30					nine months ended September 30
(unaudited - millions of $, unless noted otherwise)		2015		2014			2015		2014
Income from equity investments1
Bruce A		16		62			163		109
Bruce B		41		49			39		90
		57		111			202		199
Comprised of:
	Revenues	298		330			945		895
	Operating expenses	(159	)	(140	)		(498	)	(461	)
	Depreciation and other	(82	)	(79	)		(245	)	(235	)
		57		111			202		199
Bruce Power - Other information
Plant availability2
	Bruce A	73	%	83	%		87	%	76	%
	Bruce B	98	%	99	%		83	%	92	%
	Combined Bruce Power	86	%	91	%		85	%	84	%
Planned outage days
	Bruce A	87		34			126		118
	Bruce B	1		-			161		74
Unplanned outage days
	Bruce A	8		25			19		130
	Bruce B	-		-			11		-
Sales volumes (GWh)1
	Bruce A	2,374		2,653			8,339		7,227
	Bruce B	2,247		2,262			5,631		6,282
		4,621		4,915			13,970		13,509
Realized sales price per MWh3
	Bruce A	$73		$72			$73		$72
	Bruce B	$54		$55			$54		$55
	Combined Bruce Power	$62		$62			$63		$62

(1)	Represents our 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. Sales volumes include deemed generation.
(2)	The percentage of time the plant was available to generate power, regardless of whether it was running.
(3)	Calculation based on actual and deemed generation. Bruce B realized sales prices per MWh includes revenues under the floor price mechanism and revenues from contract settlements.

Equity income from Bruce A decreased by $46 million for the three months ended September 30, 2015 compared to the same period in 2014, mainly due to lower volumes resulting from higher planned outage days and higher operating expenses.

Equity income from Bruce A increased by $54 million for the nine months ended September 30, 2015 compared to the same period in 2014, mainly due to higher volumes resulting from fewer unplanned outage days partially offset by higher operating expenses.

Equity income from Bruce B decreased by $8 million for the three months ended September 30, 2015 compared to the same period in 2014, mainly due to losses from contracting activities and higher operating expenses partially offset by lower lease expense based on the terms of the lease agreement with Ontario Power Generation (OPG).

Equity income from Bruce B decreased by $51 million for the nine months ended September 30, 2015 compared to the same period in 2014, mainly due to lower volumes resulting from higher planned outage days, losses from contracting activities and higher operating expenses, partially offset by lower lease expense based on the terms of the lease agreement with OPG. All Bruce B units were removed from service in April 2015 to allow for inspection of the Bruce B vacuum building as mandated by the Canadian Nuclear Safety Commission to occur approximately once every decade. The outage, along with additional planned maintenance on Unit 6, was completed successfully during second quarter 2015.

Under a contract with the IESO, all of the output from Bruce A is sold at a fixed price per MWh which is adjusted annually on April 1 for inflation.

Bruce A fixed price	per MWh
April 1, 2015 - March 31, 2016	$73.42
April 1, 2014 - March 31, 2015	$71.70
April 1, 2013 - March 31, 2014	$70.99

Under the same contract, all output from Bruce B is subject to a floor price adjusted annually for inflation on April 1.

Bruce B floor price	per MWh
April 1, 2015 - March 31, 2016	$54.13
April 1, 2014 - March 31, 2015	$52.86
April 1, 2013 - March 31, 2014	$52.34

Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the average spot price in a month exceeds the floor price. We expect 2015 spot power prices to be less than the floor price throughout 2015 and therefore no amounts received under the floor price mechanism in 2015 are expected to be repaid. Amounts received above the floor price in first quarter 2014 were repaid to the IESO in January 2015.

The contract with the IESO also provides for payment if the IESO reduces Bruce Power's generation to balance the supply of and demand for electricity and/or manage other operating conditions of the Ontario power grid. The amount of the reduction is considered "deemed generation" for which Bruce Power is paid the fixed price, floor price or spot price as applicable under the contract.

Bruce B also enters into fixed-price contracting activities under which it receives or pays the difference between the contract price and the spot price.

Overall plant availability percentages in 2015 are expected to be in the mid 80s for Bruce A and Bruce B. In July 2015, planned outage work commenced on Bruce A Unit 4 and is expected to be completed in early November 2015.

U.S. POWER
	three months ended September 30					nine months ended September 30
(unaudited - millions of US$)	2015		2014			2015		2014
Revenue
Power1	568		439			1,552		1,493
Capacity	99		112			254		278
	667		551			1,806		1,771
Commodity purchases resold	(412	)	(260	)		(1,159	)	(1,027	)
Plant operating costs and other2	(118	)	(137	)		(326	)	(426	)
Exclude risk management activities1	4		(37	)		17		(27	)
Comparable EBITDA	141		117			338		291
Comparable depreciation and amortization	(23	)	(26	)		(78	)	(80	)
Comparable EBIT	118		91			260		211

(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 cost of fuel consumed in generation.

Sales volumes and plant availability
		three months ended September 30					nine months ended September 30
(unaudited)		2015		2014			2015		2014
Physical sales volumes (GWh)
Supply
	Generation	2,707		2,918			5,756		6,162
	Purchased	6,919		3,970			15,800		9,931
		9,626		6,888			21,556		16,093
Plant availability1,2		93	%	94	%		77	%	89	%

(1)	The percentage of time the plant was available to generate power, regardless of whether it was running.
(2)	Plant availability for the nine months ended September 30 was lower in 2015 than the same period in 2014 due to an unplanned outage at the Ravenswood facility. The unit returned to service in May 2015.

U.S. Power - other information
	three months ended September 30			nine months ended September 30
(unaudited)	2015	2014		2015	2014
Average Spot Power Prices (US$ per MWh)
New England1	29	34		47	73
New York²	31	35		44	70
Average New York² Spot Capacity Prices (US$ per KW-M)	15.27	18.47		12.18	14.64

(1)	New England ISO all hours Mass Hub price.
(2)	Zone J market in New York City where the Ravenswood plant operates.

Comparable EBITDA for U.S. Power increased US$24 million for the three months ended September 30, 2015 compared to the same period in 2014 primarily due to the net effect of:

• higher margins and higher sales to wholesale, commercial and industrial customers in both the PJM and New England markets
• lower realized capacity prices in New York.

Comparable EBITDA for U.S. Power increased US$47 million for the nine months ended September 30, 2015 compared to the same period in 2014 primarily due to the net effect of:

• higher margins and higher sales volumes to wholesale, commercial and industrial customers in both the New England and PJM markets
• lower realized capacity prices in New York
• lower realized power prices and generation at our facilities in New York and New England, partially offset by lower fuel costs.

Wholesale electricity prices in New York and New England were lower for the three and nine months ended September 30, 2015 compared to the same periods in 2014. In New England, spot power prices for the three and nine months ended September 30, 2015 were 15 per cent and 36 per cent lower compared to the same periods in 2014. In New York City, spot power prices were 11 per cent and 37 per cent lower for the three and nine months ended September 30, 2015 compared to the same periods in 2014. Both markets have experienced lower natural gas commodity prices throughout 2015 compared to 2014. Reductions in fuel oil prices and increased availability of liquefied natural gas in winter 2015 helped to mitigate the impact of pipeline constraints and keep peak price excursions limited compared to winter 2014.

Spot capacity prices in New York City were, on average, 17 per cent lower for both the three and nine months ended September 30, 2015 compared to the same periods in 2014, primarily due to increased available operational supply in New York City's Zone J market.

Physical sales volumes and purchased volumes sold to wholesale, commercial and industrial customers were higher than the same periods in 2014 as we have expanded our customer base in both the PJM and New England markets. Lower commodity prices and reduced price volatility contributed to higher margins on sales to wholesale, commercial and industrial customers by reducing the costs on volumes purchased to fulfill power sales commitments to these customers.

As at September 30, 2015, approximately 1,500 GWh or 72 per cent of U.S. Power's planned generation was contracted for the remainder of 2015 and 4,800 GWh or 52 per cent for 2016. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage.

NATURAL GAS STORAGE AND OTHER

Comparable EBITDA decreased by $4 million and $24 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 and were primarily due to decreased proprietary and third party storage revenues as a result of lower realized natural gas price spreads as well as extreme natural gas price volatility experienced in first quarter 2014.

Recent developments

NATURAL GAS PIPELINES

Canadian Regulated Pipelines

NGTL System

The NGTL System has approximately $6.8 billion of new supply and demand facilities under development. Approximately $2.8 billion of these facilities have received regulatory approval with $800 million currently under construction. In third quarter 2015, we continued to advance several of these capital expansion projects with an additional approximately $500 million of applied for facilities that now await regulatory review for approval. We have also received additional requests for firm receipt service that we anticipate will increase the overall capital spend on the NGTL System beyond the previously announced program and continue to work with our customers to best match their requirements for 2016, 2017 and 2018 in-service dates.

North Montney Mainline

In April 2015, the NEB issued its report recommending the federal government approve the $1.7 billion North Montney Mainline project which will provide substantial new capacity on the NGTL System to meet the transportation requirements associated with rapidly increasing development of natural gas resources in the Montney supply basin in northeastern B.C. The project will connect Montney and other Western Canada Sedimentary Basin supply to both existing and new natural gas markets, including LNG markets.

The North Montney Mainline project will consist of two large diameter 42-inch pipeline sections, Aitken Creek and Kahta, totaling approximately 301 km (187 miles) in length, and associated metering facilities, valve sites and compression facilities. The project will also include an interconnection with our proposed Prince Rupert Gas Transmission Project (PRGT) to provide natural gas supply to the proposed Pacific NorthWest (PNW) LNG liquefaction and export facility near Prince Rupert, B.C. We expect to have the Aitken Creek section and the Kahta section in service in 2017.

The NEB also approved the applied-for rolled-in tolling design for the North Montney Mainline project costs during a transition period, subject to certain conditions which we are reviewing. Following the transition period, we will have the option of applying to the NEB for a revised tolling methodology or the ability to implement stand-alone tolling on the project. We are engaging with shippers to determine an appropriate approach that best meets market requirements.

The Federal Government approved the recommendations of the report from the NEB and, in June 2015, the NEB issued a Certificate of Public Convenience and Necessity to proceed with the project, subject to certain terms and conditions. Under one of these conditions, construction on the North Montney Mainline project can only begin after a confirmation of a Final Investment Decision (FID) has been made on the proposed PNW LNG project and we are proceeding with construction on PRGT.

Canadian Mainline

Agreement Reached with Eastern LDCs on Energy East and Eastern Mainline Project

On August 24, 2015, we announced an agreement with eastern local distribution companies (LDCs) that resolves the LDCs' issues with Energy East and the Eastern Mainline Project. The agreement honours our previously stated commitment to ensure that Energy East and the Eastern Mainline Project will provide gas consumers in eastern Canada with sufficient natural gas transmission capacity and reduced natural gas transmission costs. As part of the agreement, we will size the Eastern Mainline Project to meet all firm requirements including gas transmission contracts resulting from both 2016 and 2017 new capacity open seasons plus approximately 50 million cubic feet per day additional capacity.

Eastern Mainline Project

The Eastern Mainline Project capital cost is now estimated to be $2.0 billion with an expected in-service date of 2019. This increase is due to the revised project scope resulting from the LDC agreement and updated cost estimates.

Canadian Mainline 2015-2020 Mainline Transportation Tolls Compliance Filing

In March 2015, we submitted a compliance toll filing in response to direction from the NEB's RH-001-2014 Decision issued in November 2014. In June 2015, the NEB approved the applied-for compliance tolls, as filed, which allowed, among other things, the recording of incentive earnings as approved by the NEB. These final tolls became effective on July 1, 2015.

Kings North Connection Project

In June 2015, the NEB approved construction of the King's North Connection project to expand gas transmission capacity in the greater Toronto area and provide shippers with the flexibility to source growing supplies of Marcellus gas from the U.S. Northeast. The project is expected to cost approximately $220 million and is anticipated to be in service by fourth quarter 2016.

U.S. Pipelines

Sale of GTN Pipeline to TC PipeLines, LP

In April 2015, we closed the sale of our remaining 30 per cent interest in GTN to our master limited partnership, TC PipeLines, LP, for an aggregate purchase price of US$446 million plus a purchase price adjustment of US$11 million. Proceeds for the US$457 million sale were comprised of US$264 million in cash, the assumption of US$98 million in proportional GTN debt and US$95 million of new Class B units of TC PipeLines, LP. The Class B units entitle us to a cash distribution based on 30 per cent of GTN's annual cash distribution after certain thresholds are achieved, namely 100 per cent of distributions above US$20 million in the first five years and 25 per cent of distributions above US$20 million in subsequent years.

LNG Pipeline Projects

Prince Rupert Gas Transmission

In June 2015, PNW LNG announced a positive FID for its proposed liquefaction and export facility, subject to two conditions. The first condition, approval by the Legislative Assembly of B.C. of a Project Development Agreement between PNW LNG and the Province of B.C., was satisfied in July 2015. The second condition is a positive regulatory decision on PNW LNG's environmental assessment by the Government of Canada.

In third quarter 2015, we received the remaining permits from the B.C. Oil and Gas Commission (BC OGC) which completes the 11 permits required to build and operate PRGT. Environmental permits for the project were received in November 2014 from the B.C. Environmental Assessment Office.

We also announced in third quarter 2015, the signing of project agreements with Metlakatla First Nation and Blueberry River First Nations. We are continuing our engagement with Aboriginal groups and have now signed project agreements with nine First Nation groups along the pipeline route.

We remain on target to begin construction following confirmation of a FID by PNW LNG. The in-service date for PRGT is estimated to be 2020 but will be aligned with PNW LNG's liquefaction facility timeline.

Coastal GasLink

We have received eight of ten pipeline and facilities permits from the BC OGC and anticipate receiving the remaining two permits in fourth quarter 2015. We are continuing our engagement with Aboriginal groups and have signed project agreements with eight First Nation groups along the pipeline route.

LIQUIDS PIPELINES

Houston Lateral and Terminal

Construction continues on the 77 km (48 mile) Houston Lateral pipeline and tank terminal which will extend the Keystone Pipeline System to Houston, Texas refineries. The terminal is expected to have initial storage capacity for 700,000 barrels of crude oil. The pipeline and terminal are now expected to be completed in second quarter 2016.

On April 14, 2015, we, along with Magellan Midstream Partners L.P. (Magellan), announced a joint development agreement to connect our Houston Terminal to Magellan's East Houston Terminal. We will own 50 per cent of this US$50 million pipeline project which will enhance connections to the Houston market for our Keystone Pipeline System. Subject to definitive agreements and receipt of necessary permits and approvals, the pipeline is expected to be operational in early 2017.

Keystone XL

In January 2015, the DOS re-initiated the national interest review and requested the eight federal agencies with a role in the review to complete their consideration of whether Keystone XL serves the national interest. All of the agency comments were submitted.

On February 2, 2015, the U.S. Environmental Protection Agency (EPA) posted a comment letter to its website suggesting that, among other things, the FSEIS issued by the DOS had not fully and completely assessed the environmental impacts of Keystone XL and that, at lower crude oil prices, Keystone XL may increase the rates of oil sands production and greenhouse gas emissions. On February 10, 2015, we sent a letter to the DOS refuting these and other comments in the EPA letter and offered to work with the DOS to ensure it has all the relevant information to allow it to reach a decision to approve Keystone XL.

On February 24, 2015, U.S. President Obama vetoed Congressional legislation that would have granted us authority to construct Keystone XL across the international border. The U.S. President stated that the legislation circumvented the process established for making a final decision on the permit application. The timing and ultimate resolution of Keystone XL's pending application for a Presidential Permit remains uncertain.

On June 29, 2015, we sent a letter to the DOS updating relevant developments since the 2014 FSEIS, including additional evidence demonstrating that Canada is taking strong steps toward managing carbon emissions.

On August 5, 2015, the South Dakota Public Utility Commission (PUC) concluded its hearing on Keystone XL's request to re-certify its existing permit authority in that state. The PUC is expected to make a decision by first quarter 2016.

In January 2015, Keystone XL initiated eminent domain actions against landowners in Nebraska who had not agreed to grant voluntary easements. These actions were taken under the eminent domain authority provided by the Governor's 2013 approval of the reroute in Nebraska. Several landowners then challenged those actions in Nebraska district court on the grounds that the law authorizing the Governor's approval violated the Nebraska constitution. In October 2015, we withdrew the eminent domain actions and moved to dismiss the constitutional court proceedings. The plaintiffs are resisting dismissal of this case. A hearing on that issue was held on October 19, 2015 and a decision is expected in fourth quarter 2015.

On October 5, 2015, we filed an application with the Nebraska Public Service Commission (PSC) for route approval through the state of Nebraska. The route we are seeking approval for is the same route previously approved by the Nebraska Department of Environmental Quality in January 2013. After careful review, we believe this would be the most expedient path to approval and expect the PSC to make a decision by third quarter 2016. On November 2, 2015, we sent a letter to U.S. Secretary of State John Kerry asking the Department of State to pause its review of the Presidential Permit application for Keystone XL while we seek Nebraska PSC approval of the route.

As of September 30, 2015, we have invested US$2.4 billion in the project and have also capitalized interest in the amount of US$0.4 billion.

Energy East Pipeline

In April 2015, we announced that the marine and associated tank terminal in Cacouna, Quebec will not be built as a result of the recommended reclassification of beluga whales as an endangered species. Amendments to the project are expected to be submitted to the NEB in fourth quarter 2015. The NEB has continued to process the application in the interim.    

The alteration to the project scope and further refinement of the project schedule is expected to result in an in-service date of 2020. The original $12 billion cost estimate is expected to increase due to further scope refinement as we consult with stakeholders and escalation of construction costs as the project schedule is refined.

Heartland Pipeline and TC Terminals

In May 2015, the Alberta Energy Regulator issued a permit for construction of the Heartland Pipeline. The in-service date of the project will be aligned to meet market requirements for incremental capacity between the Heartland region near Edmonton, Alberta and Hardisty, Alberta.

Crude oil prices continue to remain low, prompting many producers to cut capital spending and delay oil sands projects in western Canada. In its 2015 Crude Oil Forecast, Markets and Transportation report, the Canadian Association of Petroleum Producers estimated WCSB crude oil production will continue to grow but at a slower pace than previously anticipated. Our liquids pipelines projects are supported by long-term contracts. However, with the slowing in growth of crude oil production, our intra-Alberta projects may experience a similar slowing pace of growth to align with the market.

Grand Rapids Pipeline

On August 6, 2015, Grand Rapids Pipeline Limited Partnership (Grand Rapids) entered into an agreement to contribute the southernmost portion of the 20-inch diluent Grand Rapids Pipeline into a 50/50 joint venture with Keyera Corp. (Keyera). The 45-kilometre (28-mile) pipeline will be constructed by us and will extend from Keyera's Edmonton Terminal to our Heartland Terminal near Fort Saskatchewan. Keyera will also contribute a new pump station at its Edmonton terminal. We expect Grand Rapid's total contribution to the joint venture will be approximately $140 million. Keyera will operate the pipeline once construction is complete and the facilities are in service. The expected in-service date is the second half of 2017 subject to regulatory approvals.

Upland Pipeline

In April 2015, we filed an application to obtain a U.S. Presidential Permit for the Upland Pipeline. The US$600 million Upland Pipeline is a 400 km (240 mile) crude oil pipeline which will provide transportation from, and between, multiple points in North Dakota and interconnect with the Energy East Pipeline at Moosomin, Saskatchewan. Subject to regulatory approvals, we anticipate the Upland Pipeline to be in service in 2020. The commercial contracts we have executed for Upland Pipeline are conditioned on the Energy East pipeline project proceeding.

ENERGY

Ironwood Power Plant

On October 8, 2015, we reached an agreement to acquire the 778 MW Ironwood natural gas fired, combined cycle power plant located in Lebanon, Pennsylvania from Talen Energy Corporation for US$654 million. At closing, US$42 million in debt will be assumed and repaid within 45 days of closing using funds placed into escrow by the seller.

The Ironwood power plant delivers energy into the PJM power market and will provide us with a solid platform from which to continue to grow our wholesale, commercial and industrial customer base in this market area. The acquisition will be financed with a combination of cash on hand and available debt capacity. The transaction is expected to close early in first quarter 2016, subject to certain conditions being satisfied.

Becancour Power Plant

In August 2015, we executed an agreement with Hydro Quebec (HQ) to amend Becancour's electricity supply contract. The amendment allows HQ to dispatch up to 570 MW of firm peak winter capacity from the Becancour facility for a term of 20 years commencing in December 2016. Annual payments for this new service will be incremental to existing capacity payments earned under the agreement. In October 2015, the Regie de l'energie approved the amended contract.

Ravenswood

In late May 2015, the 972 MW Unit 30 at the Ravenswood Generating Station returned to service after a September 2014 unplanned outage which resulted from a problem with the generator associated with the high pressure turbine.

Alberta Greenhouse Gas Emissions

In June 2015, the Alberta government announced a renewal and change to the Specified Gas Emitters Regulations (SGER) in Alberta. Since 2007, under the SGER, established industrial facilities with GHG emissions above a certain threshold are required to reduce their emissions by 12 per cent below an average intensity baseline and a carbon levy of $15 per tonne is placed on emissions above this target. The changed regulations include an increase in the emissions reductions target to 15 per cent in 2016 and 20 per cent in 2017, along with an increase in the carbon levy to $20 per tonne in 2016 and $30 per tonne in 2017. While our Sundance and Sheerness PPAs are subject to this regulation, our significant inventory of carbon offset credits is expected to mitigate the majority of these increased costs. The remaining compliance costs are expected to be recovered through increased market pricing and contract flow through provisions.

CORPORATE

Restructuring

In mid-2015, we commenced a business restructuring and transformation initiative. While there is no change to our corporate strategy, we have undertaken this initiative to reduce overall costs and maximize the effectiveness and efficiency of our existing operations. At September 30, 2015, we had incurred $36 million before tax, mainly related to severance costs, of which $20 million before tax was included in plant operating costs and other on the income statement, $8 million was capitalized to projects impacted by the restructuring and $8 million is recoverable through regulatory and tolling structures. The total restructuring charges will be determined once the scope of the expected changes is known, which is anticipated to occur in fourth quarter 2015. We expect further restructuring initiatives to be undertaken in fourth quarter 2015 and to continue into 2016.

Other income statement items

The following are reconciliations and related analyses of our non-GAAP measures to the equivalent GAAP measures for other income statement items.

	three months ended September 30					nine months ended September 30
(unaudited - millions of $)	2015		2014			2015		2014
Comparable interest on long-term debt (including interest on junior subordinated notes)
Canadian-dollar denominated	(109	)	(108	)		(324	)	(335	)
U.S. dollar-denominated (US$)	(231	)	(215	)		(677	)	(638	)
Foreign exchange impact	(72	)	(19	)		(177	)	(60	)
	(412	)	(342	)		(1,178	)	(1,033	)
Other interest and amortization expense	(11	)	(19	)		(35	)	(41	)
Capitalized interest	82		57			223		199
Comparable interest expense	(341	)	(304	)		(990	)	(875	)
Specific items1	-		-			-		-
Interest expense	(341	)	(304	)		(990	)	(875	)

(1)	There were no specific items in any of these periods.

Comparable interest expense increased by $37 million and $115 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 due to the net effect of:

• higher interest expense reflecting debt issues of: 
  • $750 million in July 2015
  • US$750 million in May 2015
  • US$750 million in March 2015
  • US$350 million in March 2015 by TC PipeLines, LP
  • US$750 million in January 2015
  • US$1.25 billion in February 2014
  • 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 capitalized interest primarily due to Liquids Pipeline and LNG projects and the Napanee power generating facility. 

		three months ended September 30					nine months ended September 30
(unaudited - millions of $)		2015		2014			2015		2014
Comparable interest income and other expense		42		49			108		72
Specific items (pre-tax):
	Risk management activities	(26	)	(32	)		(25	)	(9	)
Interest income and other expense		16		17			83		63

Comparable interest income and other expense decreased by $7 million for the three months ended September 30, 2015 and increased by $36 million for the nine months ended September 30, 2015 compared to the same periods in 2014. The increase for the nine months ended is the net result of:

• increased AFUDC related to our rate-regulated projects, primarily Energy East Pipeline and our Mexico pipelines
• higher realized losses in 2015 compared to 2014 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar denominated income
• the impact of a strengthening U.S. dollar on the translation of foreign currency denominated working capital.

		three months ended September 30					nine months ended September 30
(unaudited - millions of $)		2015		2014			2015		2014
Comparable income tax expense		(236	)	(230	)		(668	)	(616	)
Specific items:
	Alberta corporate income tax rate increase	-		-			(34	)	-
	Restructuring costs	2		-			6		-
	Cancarb gain on sale	-		-			-		(9	)
	Niska contract termination	-		1			-		11
	Risk management activities	11		(10	)		16		(11	)
Income tax expense		(223	)	(239	)		(680	)	(625	)

Comparable income tax expense increased by $6 million and $52 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014. The increases were mainly the result of higher pre-tax earnings in 2015 compared to 2014 and changes in the proportion of income earned between Canadian and foreign jurisdictions, partially offset by lower flow-through taxes in 2015 on Canadian regulated pipelines.

	three months ended September 30					nine months ended September 30
(unaudited - millions of $)	2015		2014			2015		2014
Net income attributable to non-controlling interests	(46	)	(25	)		(145	)	(110	)
Preferred share dividends	(23	)	(24	)		(71	)	(72	)

Net income attributable to non-controlling interests increased by $21 million and $35 million for the three and nine months ended September 30, 2015 compared to the same periods in 2014 primarily due to the sale of our remaining 30 per cent direct interests in GTN in April 2015 and Bison in October 2014 to TC PipeLines, LP and the impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from TC PipeLines, LP.

Financial condition

We strive to maintain strong financial capacity and flexibility in all parts of the economic cycle. We rely on our operating cash flow to sustain our business, pay dividends and fund a portion of our growth. In addition, we access capital markets to meet our financing needs, manage our capital structure and to preserve our credit ratings.

We believe we have the financial capacity to fund our existing capital program through our predictable cash flow from our operations, access to capital markets, proceeds from the sale of U.S. natural gas pipeline assets to TC PipeLines, LP, cash on hand and substantial committed credit facilities.

CASH PROVIDED BY OPERATING ACTIVITIES
	three months ended September 30			nine months ended September 30
(unaudited - millions of $)	2015	2014		2015		2014
Funds generated from operations1	1,140	1,071		3,354		3,090
Decrease/(increase) in operating working capital	107	171		(378	)	250
Net cash provided by operations	1,247	1,242		2,976		3,340

(1)	See the non-GAAP measures section in this MD&A for further discussion of funds generated from operations.

At September 30, 2015, our current assets were $3.8 billion and current liabilities were $6.9 billion, leaving us with a working capital deficit of $3.1 billion compared to $4.0 billion at December 31, 2014. This working capital deficiency is considered to be in the normal course of business and is managed through:

• our ability to generate cash flow from operations
• our access to capital markets
• approximately $6.0 billion of unutilized, unsecured credit facilities.

CASH USED IN INVESTING ACTIVITIES
	three months ended September 30					nine months ended September 30
(unaudited - millions of $)	2015		2014			2015		2014
Capital expenditures	(976	)	(744	)		(2,748	)	(2,381	)
Capital projects under development	(130	)	(207	)		(465	)	(504	)
Equity investments	(105	)	(66	)		(303	)	(195	)
Acquisitions	-		(181	)		-		(181	)
Proceeds from sale of assets, net of transaction costs	-		-			-		187
Deferred amounts and other	147		67			461		139
Net cash used in investing activities	(1,064	)	(1,131	)		(3,055	)	(2,935	)

Capital expenditures in 2015 were primarily related to:

• the expansion of the NGTL System
• construction of Mexico pipelines
• expansion of the ANR pipeline
• construction of the Northern Courier pipeline
• construction of the Napanee power generating facility
• expansion of the Canadian Mainline.

Costs incurred on capital projects under development primarily relate to the Energy East Pipeline and LNG pipeline projects.

Equity investments have increased in 2015 compared to 2014 primarily due to our investment in Grand Rapids.

Deferred amounts and other has increased in 2015 compared to 2014 primarily due to the change in our long-term regulatory assets and liabilities.

CASH (USED IN)/PROVIDED BY FINANCING ACTIVITIES
	three months ended September 30					nine months ended September 30
(unaudited - millions of $)	2015		2014			2015		2014
Junior subordinated debt issued, net of issue costs	-		-			917		-
Long-term debt issued, net of issue costs	962		-			3,323		1,380
Repayment of long-term debt	(183	)	(38	)		(2,066	)	(1,020	)
Notes payable (repaid)/issued, net	(358	)	377			(828	)	(145	)
Dividends and distributions paid	(452	)	(406	)		(1,315	)	(1,208	)
Common shares issued, net of issue costs	1		27			12		43
Partnership units of subsidiary issued, net of issue costs	-		79			31		79
Preferred shares issued, net of issue costs	-		-			243		440
Preferred shares of subsidiary redeemed	-		-			-		(200	)
Net cash (used in)/provided by financing activities	(30	)	39			317		(631	)

LONG-TERM DEBT ISSUED
(unaudited - millions of $) Company	Issue date		Type	Maturity date	Amount	Interest rate
TRANSCANADA PIPELINES LIMITED
	October 2015		Medium-Term Notes	November 2041	400	4.55	%
	July 2015		Medium-Term Notes	July 2025	750	3.30	%
	March 2015		Senior Unsecured Notes	March 2045	US 750	4.60	%
	January 2015		Senior Unsecured Notes	January 2018	US 500	1.875	%
	January 2015		Senior Unsecured Notes	January 2018	US 250	Floating
TC PIPELINES, LP
	September 2015		Unsecured Term Loan	October 2018	US 170	Floating
	March 2015		Senior Unsecured Notes	March 2025	US 350	4.375	%
GAS TRANSMISSION NORTHWEST LLC
	June 2015		Unsecured Term Loan	June 2019	US 75	Floating

JUNIOR SUBORDINATED DEBT ISSUED
(unaudited - millions of $) Company	Issue date		Type	Maturity date	Amount	Interest rate
TRANSCANADA PIPELINES LIMITED
	May 2015		Junior subordinated unsecured notes1	May 2075	US 750	5.875%2

(1)	The Junior subordinated unsecured 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 unsecured 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.

TransCanada Trust (the Trust), our 100 per cent owned financing trust subsidiary of TCPL, issued US$750 million Trust Notes - Series 2015-A (Trust Notes) to third party investors with a fixed interest rate of 5.625 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to us in US$750 million junior subordinated notes of TCPL at a rate of 5.875 per cent which includes a 0.25 per cent administration charge. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in our financial statements as TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are receivables from TCPL.

Pursuant to the terms of the Trust Notes and related agreements, in certain circumstances, (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TransCanada and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with other outstanding first preferred shares of TCPL. Further details regarding the terms of the Trust Notes and the related agreements entered into by TransCanada and TCPL can be found in the prospectus in respect of the Trust Notes and other documents filed under the Trust's profile on SEDAR at www.sedar.com.

LONG-TERM DEBT RETIRED
(unaudited - millions of $) Company	Retirement date		Type	Amount	Interest rate
TRANSCANADA PIPELINES LIMITED
	August 2015		Debentures	150	11.90	%
	June 2015		Senior Unsecured Notes	US 500	3.40	%
	March 2015		Senior Unsecured Notes	US 500	0.875	%
	January 2015		Senior Unsecured Notes	US 300	4.875	%
GAS TRANSMISSION NORTHWEST LLC
	June 2015		Senior Unsecured Notes	US 75	5.09	%

PREFERRED SHARE ISSUANCE AND CONVERSION

In June 2015, holders of 5.5 million Series 3 cumulative redeemable first preferred shares exercised their option to convert to Series 4 cumulative redeemable first preferred shares and receive quarterly floating rate cumulative, dividends at an annual rate equal to the applicable 90-day Government of Canada treasury bill rate plus 1.28 per cent which will reset every quarter going forward. The fixed dividend rate on the remaining Series 3 preferred shares was reset for five years at 2.152 per cent per annum.

In March 2015, we completed a public offering of 10 million Series 11 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $250 million. The Series 11 preferred shareholders will have the right to convert their Series 11 preferred shares into Series 12 cumulative redeemable first preferred shares on November 30, 2020 and on November 30 of every fifth year thereafter. The holders of Series 12 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at an annual rate equal to the applicable 90-day Government of Canada treasury bill rate plus 2.96 per cent.

The following table summarizes the impact of the 2015 issuance and conversion of preferred shares discussed above:

(unaudited - millions of Canadian $, unless noted otherwise)	Number of shares issued and outstanding (thousands)	Current yield 1		Annual  dividend per share 1	Redemption  price per share 2		Redemption and conversion option date		Right to convert  into
Cumulative first preferred shares
Series 3	8,533	2.152	%	0.5375	$25.00		June 30, 2020		Series 4
Series 4	5,467	Floating	3	Floating	$25.50		June 30, 2020		Series 3
Series 11	10,000	3.80	%	0.95	$25.00		November 30, 2020		Series 12

(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 preferred shares. The holders of Series 4 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.
(3)	Commencing September 30, 2015, the floating quarterly dividend rate for the Series 4 preferred shares is 1.656 per cent and will reset every quarter going forward.

The net proceeds of the above debt and Series 11 preferred share offerings were used for general corporate purposes and to reduce short-term indebtedness.

TC PIPELINES, LP AT-THE-MARKET (ATM) EQUITY ISSUANCE PROGRAM

From January 1 to September 30, 2015, 0.4 million common units were issued under the TC PipeLines, LP ATM program generating net proceeds of approximately US$25 million. Our ownership interest in TC PipeLines, LP will decrease as a result of issuances under the ATM program.

DIVIDENDS

On November 2, 2015, we declared quarterly dividends as follows:

Quarterly dividend on our common shares
$0.52 per share
Payable on January 29, 2016 to shareholders of record at the close of business on December 31, 2015

Quarterly dividends on our preferred shares
Series 1	$0.204125
Series 2	$0.14467945
Series 3	$0.1345
Series 4	$0.10435068
Payable on December 31 to shareholders of record at the close of business on November 30, 2015
Series 5	$0.275
Series 7	$0.25
Series 9	$0.265625
Payable on February 1, 2016 to shareholders of record at the close of business on December 31, 2015
Series 11	$0.2375
Payable on November 30, 2015 to shareholders of record at the close of business on November 13, 2015

SHARE INFORMATION
as at October 28, 2015
Common shares	Issued and outstanding
	709 million
Preferred shares	Issued and outstanding	Convertible to
Series 1	9.5 million	Series 2 preferred shares
Series 2	12.5 million	Series 1 preferred shares
Series 3	8.5 million	Series 4 preferred shares
Series 4	5.5 million	Series 3 preferred shares
Series 5	14 million	Series 6 preferred shares
Series 7	24 million	Series 8 preferred shares
Series 9	18 million	Series 10 preferred shares
Series 11	10 million	Series 12 preferred shares
Options to buy common shares	Outstanding	Exercisable
	10 million	6 million

CREDIT FACILITIES

We use committed revolving credit facilities to support our commercial paper programs and, along with demand facilities, for general corporate purposes including issuing letters of credit as well as providing additional liquidity.

At September 30, 2015, we had approximately $7 billion in unsecured credit facilities, including:

Amount	Unused capacity		Subsidiary	Description and use	Matures
$3.0 billion	$3.0 billion		TCPL	Committed, syndicated, revolving, extendible credit facility that supports TCPL's Canadian commercial paper program	December 2019
US$1.0 billion	US$1.0 billion		TCPL USA	Committed, syndicated, revolving, extendible credit facility that is used for TCPL USA general corporate purposes	November 2015
US$1.0 billion	US$1.0 billion		TransCanada American Investments Ltd. (TAIL)	Committed, syndicated, revolving, extendible credit facility that supports TAIL's U.S. commercial paper program in the U.S.	November 2015
$1.5 billion	$0.5 billion		TCPL, TCPL USA	Demand lines for issuing letters of credit and as a source of additional liquidity. At September 30, 2015, we had $1.0 billion outstanding in letters of credit under these lines	Demand

At September 30, 2015, our operated affiliates had an additional $0.6 billion of undrawn capacity on committed credit facilities.

We are currently in the process of renewing the committed, syndicated, revolving, extendible credit facilities.

See Financial risks and financial instruments for more information about liquidity, market and other risks.

CONTRACTUAL OBLIGATIONS

Our capital commitments are consistent with the amounts reported at December 31, 2014 as a result of the completion or advancement of capital projects partially offset by new commitments for the Napanee generating facility. Our other purchase obligations have increased by approximately $0.1 billion since December 31, 2014 primarily due to an increase in commodity purchase obligations and information technology and communication contracts. There were no other material changes to our contractual obligations in third quarter 2015 or to payments due in the next five years or after. See the MD&A in our 2014 Annual Report for more information about our contractual obligations.

Financial risks and financial instruments

We are exposed to liquidity risk, counterparty credit risk and market risk, and have strategies, policies and limits in place to mitigate their impact on our earnings, cash flow and, ultimately, shareholder value. These are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance.

See our 2014 Annual Report for more information about the risks we face in our business. Our risks have not changed substantially since December 31, 2014.

LIQUIDITY RISK

We manage our liquidity risk by continuously forecasting our cash requirements for a rolling twelve month period and making sure we have adequate cash balances, cash flow from operations, committed and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations under both normal and stressed economic conditions.

COUNTERPARTY CREDIT RISK

We have exposure to counterparty credit risk in the following areas:

• accounts receivable
• the fair value of derivative and available for sale assets
• cash, notes, loans and advances receivable.

We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At September 30, 2015, we had not incurred any significant credit losses and had no significant amounts past due or impaired. We had a credit risk concentration due from a counterparty of $248 million (US$185 million) and $258 million (US$222 million) at September 30, 2015 and December 31, 2014. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's investment grade parent company.

We have significant credit and performance exposure to financial institutions because they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.

FOREIGN EXCHANGE AND INTEREST RATE RISK

Certain of our businesses generate income in U.S. dollars, but since we report in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect our net income. As our U.S. dollar-denominated operations continue to grow, this exposure increases. The majority of this risk is offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives.

We have floating interest rate debt and floating rate preferred shares (Series 2 and Series 4) which subject us to interest rate cash flow risk. We use interest rate swaps to help manage this risk.

Average exchange rate - U.S. to Canadian dollars
three months ended September 30, 2015	1.31
three months ended September 30, 2014	1.09
nine months ended September 30, 2015	1.26
nine months ended September 30, 2014	1.09

The impact of changes in the value of the U.S. dollar on our U.S. dollar-denominated operations is significantly offset by other U.S. dollar-denominated items, as set out in the table below.

Significant U.S. dollar-denominated amounts
	three months ended September 30					nine months ended September 30
(unaudited - millions of US$)	2015		2014			2015		2014
U.S. and International Natural Gas Pipelines comparable EBIT	155		118			533		469
U.S. Liquids Pipelines comparable EBIT	173		155			480		417
U.S. Power comparable EBIT	118		91			260		211
Interest expense on U.S. dollar-denominated long-term debt	(231	)	(215	)		(677	)	(638	)
Capitalized interest on U.S. dollar-denominated capital expenditures	42		30			102		125
U.S. non-controlling interests and other	(48	)	(52	)		(181	)	(184	)
	209		127			517		400

Derivatives designated as a net investment hedge

We hedge our net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps and foreign exchange forward contracts. The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:

	September 30, 2015				December 31, 2014
(unaudited - millions of $)	Fair value1		Notional or principal amount		Fair value1		Notional or principal amount
Asset/(liability)
U.S. dollar cross-currency interest rate swaps
(maturing 2015 to 2019)2	(711	)	US 2,300		(431	)	US 2,900
U.S. dollar foreign exchange forward contracts
(maturing 2015 to 2016)	(18	)	US 800		(28	)	US 1,400
	(729	)	US 3,100		(459	)	US 4,300

(1)	Fair values equal carrying values.
(2)	Net income in the three and nine months ended September 30, 2015 included net realized gains of $2 million and $7 million (2014 - gains of $5 million and $16 million) related to the interest component of cross-currency swaps settlements.

U.S. dollar-denominated debt designated as a net investment hedge
(unaudited - millions of $)	September 30, 2015	December 31, 2014
Carrying value	21,000 (US 15,600)	17,000 (US 14,700)
Fair value	22,400 (US 16,700)	19,000 (US 16,400)

The balance sheet classification of the fair value of derivatives used to hedge our net investment in foreign operations is as follows:

(unaudited - millions of $)	September 30, 2015		December 31, 2014
Other current assets	42		5
Intangible and other assets	6		1
Accounts payable and other	(355	)	(155	)
Other long-term liabilities	(422	)	(310	)
	(729	)	(459	)

FINANCIAL INSTRUMENTS

All financial instruments, including both derivative and non-derivative instruments, are recorded on the balance sheet at fair value unless they were entered into and continue to be held for the purpose of receipt or delivery in accordance with our normal purchase and sales exemptions and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting exemptions.

Non-derivative financial instruments

Fair value of non-derivative financial instruments

The fair value of our notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of long-term debt and junior subordinated notes has been estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data providers.

Available for sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments including cash and cash equivalents, accounts receivable, intangible and other assets, notes payable, accounts payable and other, accrued interest and other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity and would also be classified in Level II of the fair value hierarchy.

Credit risk has been taken into consideration when calculating the fair value of non-derivative financial instruments.

Derivative instruments

We use derivative instruments to reduce volatility associated with fluctuations in commodity prices, interest rates and foreign exchange rates. We apply hedge accounting to derivative instruments that qualify and are designated for hedge accounting treatment. The effective portion of the change in the fair value of hedging derivatives for cash flow hedges and hedges of our net investment in foreign operations are recorded in OCI in the period of change. Any ineffective portion is recognized in net income in the same financial category as the underlying transaction. The change in the fair value of derivative instruments that have been designated as fair value hedges are recorded in net income in interest income and other expense and interest expense.

The majority of derivative instruments that are not designated or do not qualify for hedge accounting treatment have been entered into as economic hedges to manage our exposure to market risk (held for trading). Changes in the fair value of held for trading derivative instruments are recorded in net income in the period of change. This may expose us to increased variability in reported operating results since the fair value of the held for trading derivative instruments can fluctuate significantly from period to period.

The recognition of gains and losses on derivatives for Canadian natural gas regulated pipelines exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, can be recovered or refunded through the tolls charged by us. As a result, these gains and losses are deferred as regulatory assets or regulatory liabilities and are refunded to or collected from the ratepayers in subsequent years when the derivative settles.

Fair value of derivative instruments

The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses period-end market rates and applies a discounted cash flow valuation model. The fair value of power and natural gas derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.

Balance sheet presentation of derivative instruments

The balance sheet classification of the fair value of the derivative instruments is as follows:

(unaudited - millions of $)	September 30, 2015		December 31, 2014
Other current assets	314		409
Intangible and other assets	150		93
Accounts payable and other	(795	)	(749	)
Other long-term liabilities	(626	)	(411	)
	(957	)	(658	)

The effect of derivative instruments on the condensed consolidated statement of income
The following summary does not include hedges of our net investment in foreign operations.
		three months ended September 30					nine months ended September 30
(unaudited - millions of $, pre-tax)		2015		2014			2015		2014
Derivative instruments held for trading1
Amount of unrealized (losses)/gains in the period
	Power	(34	)	20			(33	)	35
	Natural gas	7		7			3		(14	)
	Foreign exchange	(26	)	(32	)		(25	)	(9	)
Amount of realized (losses)/gains in the period
	Power	(27	)	8			(60	)	(23	)
	Natural gas	(25	)	(27	)		(24	)	19
	Foreign exchange	(34	)	(1	)		(87	)	(19	)
Derivative instruments in hedging relationships2,3
Amount of realized (losses)/gains in the period
	Power	(35	)	(50	)		(132	)	138
	Interest	2		1			6		3
Gains on ineffective portion in the period
	Power	10		23			3		13

(1)	Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in energy 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 expense.
(2)	For the three and nine months ended September 30, 2015, net realized gains on fair value hedges were $4 million and $8 million (2014 - gains of $2 million and $5 million) and were included in interest expense. For the three and nine months ended September 30, 2015 and 2014, we did not record any amounts in net income related to ineffectiveness for fair value hedges.
(3)	The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to energy revenues, interest expense and interest income and other expense, as appropriate, as the original hedged item settles. For the three and nine months ended September 30, 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.

Derivatives in cash flow hedging relationships

The components of other comprehensive income related to derivatives in cash flow hedging relationships are as follows:

		three months ended September 30					nine months ended September 30
(unaudited - millions of $, pre-tax)		2015		2014			2015		2014
Change in fair value of derivative instruments recognized in OCI (effective portion)1
	Power	(48	)	62			(77	)	96
	Natural gas	-		(1	)		-		(2	)
	Foreign exchange	-		-			-		10
	Interest	(1	)	1			(1	)	-
		(49	)	62			(78	)	104
Reclassification of gains/(losses) on derivative instruments from AOCI to net income (effective portion)1
	Power2	76		-			124		(109	)
	Natural gas2	-		1			-		3
	Interest3	4		4			12		12
		80		5			136		(94	)
Gains on derivative instruments recognized in net income (ineffective portion)
	Power	10		23			3		13
		10		23			3		13

(1)	No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI.
(2)	Reported within energy revenues on the condensed consolidated statement of income.
(3)	Reported within interest expense on the condensed consolidated statement of income.

Credit risk related contingent features of derivative instruments

Derivative contracts often contain financial assurance provisions that may require us to provide collateral if a credit risk related contingent event occurs (for example, if our credit rating is downgraded to non-investment grade).

Based on contracts in place and market prices at September 30, 2015, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $15 million (December 31, 2014 - $15 million), with collateral provided in the normal course of business of nil (December 31, 2014 - nil). If the credit-risk-related contingent features in these agreements had been triggered on September 30, 2015, we would have been required to provide collateral of $15 million (December 31, 2014 - $15 million) to our counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.

We have sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.

Other information

CONTROLS AND PROCEDURES

Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at September 30, 2015, as required by the Canadian securities regulatory authorities and by the SEC, and concluded that our disclosure controls and procedures are effective at a reasonable assurance level.

There were no changes in third quarter 2015 that had or are likely to have a material impact on our internal control over financial reporting.

CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICY CHANGES

When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amount we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgement. We also regularly assess the assets and liabilities themselves. You can find a summary of our critical accounting estimates in our 2014 Annual Report.

Our significant accounting policies have remained unchanged since December 31, 2014 other than described below. You can find a summary of our significant accounting policies in our 2014 Annual Report.

Changes in accounting policies for 2015

Reporting discontinued operations

In April 2014, the FASB issued amended guidance on the reporting of discontinued operations. The criteria of what will qualify as a discontinued operation has changed and there are expanded disclosures required. This new guidance was applied prospectively from January 1, 2015 and there was no impact on our consolidated financial statements as a result of applying this new standard.

Future accounting changes

Revenue from contracts with customers

In 2014, the FASB issued new guidance on revenue from contracts with customers. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. This new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In July 2015, the FASB agreed to defer the effective date of this new standard to January 1, 2018, with early adoption not permitted before January 1, 2017. There are two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application.

We are currently evaluating the impact of the adoption of this ASU and have not yet determined the effect on our consolidated financial statements.

Extraordinary and unusual income statement items

In January 2015, the FASB issued new guidance on extraordinary and unusual income statement items. This update eliminates from GAAP the concept of extraordinary items. This new guidance is effective from January 1, 2016 and will be applied prospectively. We do not expect the adoption of this new standard to have a material impact on our consolidated financial statements.

Consolidation

In February 2015, the FASB issued new guidance on consolidation analysis. This update requires that entities reevaluate whether they should consolidate certain legal entities and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance is effective from January 1, 2016 and will be applied retrospectively. We are currently evaluating the impact of the adoption of this ASU and have not yet determined the effect on our consolidated financial statements.

Imputation of interest

In April 2015, the FASB issued new guidance on simplifying the accounting for debt issuance costs. The amendments in this update require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability consistent with debt discounts or premiums. This new guidance is effective January 1, 2016 and will be applied retrospectively. The application of this amendment will result in a reclassification of debt issuance costs currently recorded in intangible and other assets to an offset of their respective debt liabilities.

Inventory

In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The amendments in this update specify that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. Subsequent measurement is unchanged for inventory measured using Last In First Out or the retail inventory method. This new guidance is effective January 1, 2017 and will be applied prospectively. We do not expect the adoption of this new standard to have a material impact on our consolidated financial statements.

Derivatives and Hedging

In August 2015, the FASB issued new guidance on the application of the normal purchases and normal sales scope exception to certain electricity contracts within nodal energy markets. The amendments in this update apply to entities that enter into contracts for the purchase or sale of electricity on a forward basis and arrange for transmission through or delivery to a location within a nodal energy market whereby one of the contracting parties incurs charges (or credits) for the transmission of that electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. This new guidance was effective upon issuance, was applied prospectively and did not have a material impact on our consolidated financial statements.

Business Combinations

In September 2015, the FASB issued new guidance on simplifying the accounting for measurement-period adjustments in business combinations. The new guidance in this update eliminates the requirement for an acquirer in a business combination to account for measurement-period adjustments retrospectively. This new guidance is effective January 1, 2016 and will be applied prospectively on future business combinations.

Reconciliation of non-GAAP measures
		three months ended September 30					nine months ended September 30
(unaudited - millions of $, except per share amounts)		2015		2014			2015		2014
EBITDA		1,458		1,435			4,334		4,099
Restructuring costs		8		-			20		-
Cancarb gain on sale		-		-			-		(108	)
Niska contract termination		-		2			-		43
Non-comparable risk management activities affecting EBITDA		17		(50	)		27		(34	)
Comparable EBITDA		1,483		1,387			4,381		4,000
Comparable depreciation and amortization		(439	)	(403	)		(1,313	)	(1,195	)
Comparable EBIT		1,044		984			3,068		2,805
Other income statement items
Comparable interest expense		(341	)	(304	)		(990	)	(875	)
Comparable interest income and other expense		42		49			108		72
Comparable income tax expense		(236	)	(230	)		(668	)	(616	)
Net income attributable to non-controlling interests		(46	)	(25	)		(145	)	(110	)
Preferred share dividends		(23	)	(24	)		(71	)	(72	)
Comparable earnings		440		450			1,302		1,204
Specific items (net of tax):
	Alberta corporate income tax rate increase	-		-			(34	)	-
	Restructuring costs	(6	)	-			(14	)	-
	Cancarb gain on sale	-		-			-		99
	Niska contract termination	-		(1	)		-		(32	)
	Risk management activities1	(32	)	8			(36	)	14
Net income attributable to common shares		402		457			1,218		1,285
Comparable depreciation and amortization		(439	)	(403	)		(1,313	)	(1,195	)
	Specific items	-		-			-		-
Depreciation and amortization		(439	)	(403	)		(1,313	)	(1,195	)
Comparable interest expense		(341	)	(304	)		(990	)	(875	)
	Specific items	-		-			-		-
Interest expense		(341	)	(304	)		(990	)	(875	)
Comparable interest income and other expense		42		49			108		72
Specific items:
	Risk management activities1	(26	)	(32	)		(25	)	(9	)
Interest income and other expense		16		17			83		63
Comparable income tax expense		(236	)	(230	)		(668	)	(616	)
Specific items:
	Alberta corporate income tax rate increase	-		-			(34	)	-
	Restructuring costs	2		-			6		-
	Cancarb gain on sale	-		-			-		(9	)
	Niska contract termination	-		1			-		11
	Risk management activities1	11		(10	)		16		(11	)
Income tax expense		(223	)	(239	)		(680	)	(625	)

		three months ended September 30						nine months ended September 30
(unaudited - millions of $, except per share amounts)		2015			2014			2015			2014
Comparable earnings per common share		$	0.62		$	0.63		$	1.84		$	1.70
Specific items (net of tax):
	Alberta corporate income tax rate increase		-			-			(0.05	)		-
	Restructuring costs		(0.01	)		-			(0.02	)		-
	Cancarb gain on sale		-			-			-			0.14
	Niska contract termination		-			-			-			(0.04	)
	Risk management activities1		(0.04	)		0.01			(0.05	)		0.01
Net income per common share		$	0.57		$	0.64		$	1.72		$	1.81

1	Risk management activities	three months ended September 30					nine months ended September 30
	(unaudited - millions of $)	2015		2014			2015		2014
	Canadian Power	(14	)	2			(7	)	-
	U.S. Power	(5	)	41			(22	)	30
	Natural Gas Storage	2		7			2		4
	Foreign exchange	(26	)	(32	)		(25	)	(9	)
	Income tax attributable to risk management activities	11		(10	)		16		(11	)
	Total (losses)/gains from risk management activities	(32	)	8			(36	)	14

Comparable EBITDA and EBIT by business segment
three months ended September 30, 2015	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines		Energy		Corporate		Total
EBITDA	812		355		328		(37	)	1,458
Restructuring costs	-		-		-		8		8
Non-comparable risk management activities affecting EBITDA	-		-		17		-		17
Comparable EBITDA	812		355		345		(29	)	1,483
Comparable depreciation and amortization	(284	)	(68	)	(79	)	(8	)	(439	)
Comparable EBIT	528		287		266		(37	)	1,044

three months ended September 30, 2014	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines		Energy		Corporate		Total
EBITDA	750		281		435		(31	)	1,435
Niska contract termination	-		-		2		-		2
Non-comparable risk management activities affecting EBITDA	-		-		(50	)	-		(50	)
Comparable EBITDA	750		281		387		(31	)	1,387
Comparable depreciation and amortization	(266	)	(55	)	(76	)	(6	)	(403	)
Comparable EBIT	484		226		311		(37	)	984

nine months ended September 30, 2015	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines		Energy		Corporate		Total
EBITDA	2,493		980		978		(117	)	4,334
Restructuring costs	-		-		-		20		20
Non-comparable risk management activities affecting EBITDA	-		-		27		-		27
Comparable EBITDA	2,493		980		1,005		(97	)	4,381
Comparable depreciation and amortization	(845	)	(197	)	(248	)	(23	)	(1,313	)
Comparable EBIT	1,648		783		757		(120	)	3,068

nine months ended September 30, 2014	Natural Gas		Liquids
(unaudited - millions of $)	Pipelines		Pipelines		Energy		Corporate		Total
EBITDA	2,357		771		1,062		(91	)	4,099
Cancarb gain on sale	-		-		(108	)	-		(108	)
Niska contract termination	-		-		43		-		43
Non-comparable risk management activities affecting EBITDA	-		-		(34	)	-		(34	)
Comparable EBITDA	2,357		771		963		(91	)	4,000
Comparable depreciation and amortization	(791	)	(158	)	(230	)	(16	)	(1,195	)
Comparable EBIT	1,566		613		733		(107	)	2,805

Quarterly results
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA
		2015			2014				2013
(unaudited - millions of $, except per share amounts)		Third	Second	First	Fourth	Third	Second	First	Fourth
Revenues		2,944	2,631	2,874	2,616	2,451	2,234	2,884	2,332
Net income attributable to common shares		402	429	387	458	457	416	412	420
Comparable earnings		440	397	465	511	450	332	422	410
Share statistics
	Net income per common share - basic and diluted	$0.57	$0.60	$0.55	$0.65	$0.64	$0.59	$0.58	$0.59
	Comparable earnings per share	$0.62	$0.56	$0.66	$0.72	$0.63	$0.47	$0.60	$0.58
	Dividends declared per common share	$0.52	$0.52	$0.52	$0.48	$0.48	$0.48	$0.48	$0.46

FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT

Quarter-over-quarter revenues and net income sometimes fluctuate, the causes of which vary across our business segments.

In Natural Gas Pipelines, quarter-over-quarter revenues and net income from the Canadian regulated pipelines generally remain relatively stable during any fiscal year. Our U.S. natural gas pipelines are generally seasonal in nature with higher earnings in the winter months as a result of increased customer demands. Over the long term, however, results from both our Canadian and U.S. natural gas pipelines fluctuate because of:

• regulatory decisions
• negotiated settlements with shippers
• acquisitions and divestitures
• developments outside of the normal course of operations
• newly constructed assets being placed in service.

In Liquids Pipelines, annual revenues and net income are based on contracted crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues and net income are affected by:

• developments outside of the normal course of operations
• newly constructed assets being placed in service
• regulatory decisions.

In Energy, quarter-over-quarter revenues and net income are affected by:

• 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.

FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER

We calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period.

Comparable earnings exclude the unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges, but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them part of our underlying operations.

In third quarter 2015, comparable earnings excluded a charge of $6 million after-tax for severance costs as part of a restructuring initiative to maximize the effectiveness and efficiency of our existing operations.

In second quarter 2015, comparable earnings excluded a $34 million adjustment to income tax expense due to the enactment of an increase in the Alberta corporate income tax rate in June 2015 and a charge of $8 million after-tax for severance costs primarily as a result of the restructuring of our major projects group in response to delayed timelines on certain of our major projects along with a continued focus on enhancing the efficiency and effectiveness of our operations.

In fourth quarter 2014, comparable earnings excluded an $8 million after-tax gain on the sale of our interest in Gas Pacifico/INNERGY.

In second quarter 2014, comparable earnings excluded a $99 million after-tax gain on the sale of Cancarb Limited and a $31 million after-tax loss related to the termination of the Niska Gas Storage contract.

Condensed consolidated statement of income
	three months ended September 30					nine months ended September 30
(unaudited - millions of Canadian $, except per share amounts)	2015		2014			2015		2014
Revenues
Natural Gas Pipelines	1,305		1,145			3,896		3,514
Liquids Pipelines	507		387			1,410		1,112
Energy	1,132		919			3,143		2,943
	2,944		2,451			8,449		7,569
Income from Equity Investments	94		159			350		362
Operating and Other Expenses
Plant operating costs and other	823		674			2,344		2,163
Commodity purchases resold	624		388			1,731		1,422
Property taxes	133		113			390		355
Depreciation and amortization	439		403			1,313		1,195
Gain on sale of assets	-		-			-		(108	)
	2,019		1,578			5,778		5,027
Financial Charges
Interest expense	341		304			990		875
Interest income and other expense	(16	)	(17	)		(83	)	(63	)
	325		287			907		812
Income before Income Taxes	694		745			2,114		2,092
Income Tax Expense
Current	30		22			124		104
Deferred	193		217			556		521
	223		239			680		625
Net Income	471		506			1,434		1,467
Net income attributable to non-controlling interests	46		25			145		110
Net Income Attributable to Controlling Interests	425		481			1,289		1,357
Preferred share dividends	23		24			71		72
Net Income Attributable to Common Shares	402		457			1,218		1,285
Net Income per Common Share
Basic and diluted	$0.57		$0.64			$1.72		$1.81
Dividends Declared per Common Share	$0.52		$0.48			$1.56		$1.44
Weighted Average Number of Common Shares (millions)
Basic	709		708			709		708
Diluted	710		710			710		709

See accompanying notes to the condensed consolidated financial statements.

Condensed consolidated statement of comprehensive income
	three months ended September 30					nine months ended September 30
(unaudited - millions of Canadian $)	2015		2014			2015		2014
Net Income	471		506			1,434		1,467
Other Comprehensive Income, Net of Income Taxes
Foreign currency translation gains on net investment in foreign operations	356		287			688		337
Change in fair value of net investment hedges	(153	)	(121	)		(361	)	(169	)
Change in fair value of cash flow hedges	(29	)	37			(50	)	64
Reclassification to net income of gains and losses on cash flow hedges	50		5			83		(55	)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	7		5			24		14
Other comprehensive income on equity investments	3		-			10		2
Other comprehensive income (Note 9)	234		213			394		193
Comprehensive Income	705		719			1,828		1,660
Comprehensive income attributable to non-controlling interests	171		97			388		187
Comprehensive Income Attributable to Controlling Interests	534		622			1,440		1,473
Preferred share dividends	23		24			71		72
Comprehensive Income Attributable to Common Shares	511		598			1,369		1,401

See accompanying notes to the condensed consolidated financial statements.

Condensed consolidated statement of cash flows
	three months ended September 30				nine months ended September 30
(unaudited - millions of Canadian $)	2015		2014		2015		2014
Cash Generated from Operations
Net income	471		506		1,434		1,467
Depreciation and amortization	439		403		1,313		1,195
Deferred income taxes	193		217		556		521
Income from equity investments	(94	)	(159	)	(350	)	(362	)
Distributed earnings received from equity investments	117		161		397		415
Employee post-retirement benefits expense, net of funding	11		16		41		28
Gain on sale of assets	-		-		-		(108	)
Equity AFUDC	(45	)	(40	)	(115	)	(59	)
Unrealized losses/(gains) on financial instruments	43		(18	)	52		(25	)
Other	5		(15	)	26		18
Decrease/(increase) in operating working capital	107		171		(378	)	250
Net cash provided by operations	1,247		1,242		2,976		3,340
Investing Activities
Capital expenditures	(976	)	(744	)	(2,748	)	(2,381	)
Capital projects under development	(130	)	(207	)	(465	)	(504	)
Equity investments	(105	)	(66	)	(303	)	(195	)
Acquisitions, net of cash acquired	-		(181	)	-		(181	)
Proceeds from sale of assets, net of transaction costs	-		-		-		187
Deferred amounts and other	147		67		461		139
Net cash used in investing activities	(1,064	)	(1,131	)	(3,055	)	(2,935	)
Financing Activities
Dividends on common shares	(369	)	(340	)	(1,078	)	(1,005	)
Dividends on preferred shares	(23	)	(24	)	(69	)	(69	)
Distributions paid to non-controlling interests	(60	)	(42	)	(168	)	(134	)
Notes payable (repaid)/issued, net	(358	)	377		(828	)	(145	)
Junior subordinated debt issued, net of issue costs	-		-		917		-
Long-term debt issued, net of issue costs	962		-		3,323		1,380
Repayment of long-term debt	(183	)	(38	)	(2,066	)	(1,020	)
Common shares issued, net of issue costs	1		27		12		43
Preferred shares issued, net of issue costs	-		-		243		440
Partnership units of subsidiary issued, net of issue costs	-		79		31		79
Preferred shares of subsidiary redeemed	-		-		-		(200	)
Net cash (used in)/provided by financing activities	(30	)	39		317		(631	)
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	12		(19	)	28		(3	)
Increase/(Decrease) in Cash and Cash Equivalents	165		131		266		(229	)
Cash and Cash Equivalents
Beginning of period	590		567		489		927
Cash and Cash Equivalents
End of period	755		698		755		698

See accompanying notes to the condensed consolidated financial statements.

Condensed consolidated balance sheet
		September 30,		December 31,
(unaudited - millions of Canadian $)		2015		2014
ASSETS
Current Assets
Cash and cash equivalents		755		489
Accounts receivable		1,445		1,313
Inventories		309		292
Other		1,291		1,446
		3,800		3,540
Plant, Property and Equipment,	net of accumulated depreciation of $21,344 and $19,563, respectively	46,831		41,774
Equity Investments		5,782		5,598
Regulatory Assets		1,243		1,297
Goodwill		4,657		4,034
Intangible and Other Assets		3,415		2,704
		65,728		58,947
LIABILITIES
Current Liabilities
Notes payable		1,714		2,467
Accounts payable and other		2,635		2,896
Accrued interest		446		424
Current portion of long-term debt		2,085		1,797
		6,880		7,584
Regulatory Liabilities		966		263
Other Long-Term Liabilities		1,302		1,052
Deferred Income Tax Liabilities		6,032		5,275
Long-Term Debt		26,990		22,960
Junior Subordinated Notes		2,333		1,160
		44,503		38,294
EQUITY
Common shares, no par value		12,214		12,202
Issued and outstanding:	September 30, 2015 - 709 million shares
	December 31, 2014 - 709 million shares
Preferred shares		2,499		2,255
Additional paid-in capital		169		370
Retained earnings		5,592		5,478
Accumulated other comprehensive loss (Note 9)		(1,084	)	(1,235	)
Controlling Interests		19,390		19,070
Non-controlling interests		1,835		1,583
		21,225		20,653
		65,728		58,947
Contingencies and Guarantees (Note 13)
Subsequent Events (Note 15)

See accompanying notes to the condensed consolidated financial statements.

Condensed consolidated statement of equity
		nine months ended September 30
(unaudited - millions of Canadian $)		2015		2014
Common Shares
Balance at beginning of period		12,202		12,149
Shares issued on exercise of stock options		12		48
Balance at end of period		12,214		12,197
Preferred Shares
Balance at beginning of period		2,255		1,813
Shares issued under public offering, net of issue costs		244		442
Balance at end of period		2,499		2,255
Additional Paid-In Capital
Balance at beginning of period		370		401
Issuance of stock options, net of exercises		8		1
Dilution impact from TC PipeLines, LP units issued		4		9
Redemption of subsidiary's preferred shares		-		(6	)
Impact of asset drop downs to TC PipeLines, LP		(213	)	-
Balance at end of period		169		405
Retained Earnings
Balance at beginning of period		5,478		5,096
Net income attributable to controlling interests		1,289		1,357
Common share dividends		(1,106	)	(1,019	)
Preferred share dividends		(69	)	(74	)
Balance at end of period		5,592		5,360
Accumulated Other Comprehensive Loss
Balance at beginning of period		(1,235	)	(934	)
Other comprehensive income		151		116
Balance at end of period		(1,084	)	(818	)
Equity Attributable to Controlling Interests		19,390		19,399
Equity Attributable to Non-Controlling Interests
Balance at beginning of period		1,583		1,611
Net income attributable to non-controlling interests
	TC PipeLines, LP	132		98
	Preferred share dividends of TCPL	-		2
	Portland	13		10
Other comprehensive income attributable to non-controlling interests		243		77
Issuance of TC PipeLines, LP units
	Proceeds, net of issue costs	31		79
	Decrease in TransCanada's ownership of TC PipeLines, LP	(6	)	(14	)
Distributions declared to non-controlling interests		(161	)	(134	)
Redemption of subsidiary's preferred shares		-		(194	)
Balance at end of period		1,835		1,535
Total Equity		21,225		20,934

See accompanying notes to the condensed consolidated financial statements.

Notes to condensed consolidated financial statements

(unaudited)

1. Basis of presentation

These condensed consolidated financial statements of TransCanada Corporation (TransCanada or the Company) have been prepared by management in accordance with U.S. GAAP. The accounting policies applied are consistent with those outlined in TransCanada's annual audited consolidated financial statements for the year ended December 31, 2014, except as described in Note 2, Changes in accounting policies. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in TransCanada's 2014 Annual Report.

These condensed consolidated financial statements reflect adjustments, all of which are normal recurring adjustments that are, in the opinion of management, necessary to reflect fairly the financial position and results of operations for the respective periods. These condensed consolidated financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2014 audited consolidated financial statements included in TransCanada's 2014 Annual Report. Certain comparative figures have been reclassified to conform with the current period's presentation.

Earnings for interim periods may not be indicative of results for the fiscal year in the Company's Natural Gas Pipelines segment due to the timing of regulatory decisions and seasonal fluctuations in short-term throughput volumes on U.S. pipelines. Earnings for interim periods may also not be indicative of results for the fiscal year in the Company's Energy segment due to the impact of seasonal weather conditions on customer demand and market pricing in certain of the Company's investments in electrical power generation plants and non-regulated gas storage facilities.

USE OF ESTIMATES AND JUDGEMENTS

In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. In the opinion of management, these condensed consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company's significant accounting policies included in the consolidated financial statements for the year ended December 31, 2014, except as described in Note 2, Changes in accounting policies.

2. Changes in accounting policies

CHANGES IN ACCOUNTING POLICIES FOR 2015

Reporting discontinued operations

In April 2014, the FASB issued amended guidance on the reporting of discontinued operations. The criteria of what will qualify as a discontinued operation has changed and there are expanded disclosures required. This new guidance was applied prospectively from January 1, 2015 and there was no impact on the Company's consolidated financial statements as a result of applying this new standard.

FUTURE ACCOUNTING CHANGES

Revenue from contracts with customers

In May 2014, the FASB issued new guidance on revenue from contracts with customers. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. This new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In July 2015, the FASB agreed to defer the effective date of this new standard to January 1, 2018, with early adoption not permitted before January 1, 2017. There are two methods in which the amendment can be applied:

(1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application.

The Company is currently evaluating the impact of the adoption of this ASU and has not yet determined the effect on its consolidated financial statements.

Extraordinary and unusual income statement items

In January 2015, the FASB issued new guidance on extraordinary and unusual income statement items. This update eliminates from GAAP the concept of extraordinary items. This new guidance is effective from January 1, 2016 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

Consolidation

In February 2015, the FASB issued new guidance on consolidation analysis. This update requires that entities reevaluate whether they should consolidate certain legal entities and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance is effective from January 1, 2016 and will be applied retrospectively. The Company is currently evaluating the impact of the adoption of this ASU and has not yet determined the effect on its consolidated financial statements.

Imputation of interest

In April 2015, the FASB issued new guidance on simplifying the accounting for debt issuance costs. The amendments in this update require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability consistent with debt discounts or premiums. This new guidance is effective January 1, 2016 and will be applied retrospectively. The application of this amendment will result in a reclassification of debt issuance costs currently recorded in intangible and other assets to an offset of their respective debt liabilities.

Inventory

In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The amendments in this update specify that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. Subsequent measurement is unchanged for inventory measured using Last In First Out or the retail inventory method. This new guidance is effective January 1, 2017 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

Derivatives and Hedging

In August 2015, the FASB issued new guidance on the application of the normal purchases and normal sales scope exception to certain electricity contracts within nodal energy markets. The amendments in this update apply to entities that enter into contracts for the purchase or sale of electricity on a forward basis and arrange for transmission through or delivery to a location within a nodal energy market whereby one of the contracting parties incurs charges (or credits) for the transmission of that electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. This new guidance was effective upon issuance, was applied prospectively and did not have a material impact on the Company's consolidated financial statements.

Business Combinations

In September 2015, the FASB issued guidance on simplifying the accounting for measurement-period adjustments in business combinations. The new guidance in this update eliminates the requirement for an acquirer in a business combination to account for measurement-period adjustments retrospectively. This new guidance is effective January 1, 2016 and will be applied prospectively on future business combinations.

3. Segmented information

three months ended September 30	Natural Gas Pipelines					Liquids Pipelines					Energy					Corporate					Total
(unaudited - millions of Canadian $)	2015		2014			2015		2014			2015		2014			2015		2014			2015		2014
Revenues	1,305		1,145			507		387			1,132		919			-		-			2,944		2,451
Income from equity investments	41		35			-		-			53		124			-		-			94		159
Plant operating costs and other	(446	)	(349	)		(130	)	(92	)		(210	)	(202	)		(37	)	(31	)		(823	)	(674	)
Commodity purchases resold	-		-			-		-			(624	)	(388	)		-		-			(624	)	(388	)
Property taxes	(88	)	(81	)		(22	)	(14	)		(23	)	(18	)		-		-			(133	)	(113	)
Depreciation and amortization	(284	)	(266	)		(68	)	(55	)		(79	)	(76	)		(8	)	(6	)		(439	)	(403	)
Segmented earnings	528		484			287		226			249		359			(45	)	(37	)		1,019		1,032
Interest expense																					(341	)	(304	)
Interest income and other expense																					16		17
Income before income taxes																					694		745
Income tax expense																					(223	)	(239	)
Net income																					471		506
Net income attributable to non-controlling interests																					(46	)	(25	)
Net income attributable to controlling interests																					425		481
Preferred share dividends																					(23	)	(24	)
Net income attributable to common shares																					402		457

nine months ended September 30	Natural Gas Pipelines					Liquids Pipelines					Energy					Corporate					Total
(unaudited - millions of Canadian $)	2015		2014			2015		2014			2015		2014			2015		2014			2015		2014
Revenues	3,896		3,514			1,410		1,112			3,143		2,943			-		-			8,449		7,569
Income from equity investments	134		124			-		-			216		238			-		-			350		362
Plant operating costs and other	(1,273	)	(1,030	)		(369	)	(293	)		(585	)	(749	)		(117	)	(91	)		(2,344	)	(2,163	)
Commodity purchases resold	-		-			-		-			(1,731	)	(1,422	)		-		-			(1,731	)	(1,422	)
Property taxes	(264	)	(251	)		(61	)	(48	)		(65	)	(56	)		-		-			(390	)	(355	)
Depreciation and amortization	(845	)	(791	)		(197	)	(158	)		(248	)	(230	)		(23	)	(16	)		(1,313	)	(1,195	)
Gain on sale of assets	-		-			-		-			-		108			-		-			-		108
Segmented earnings	1,648		1,566			783		613			730		832			(140	)	(107	)		3,021		2,904
Interest expense																					(990	)	(875	)
Interest income and other expense																					83		63
Income before income taxes																					2,114		2,092
Income tax expense																					(680	)	(625	)
Net income																					1,434		1,467
Net income attributable to non-controlling interests																					(145	)	(110	)
Net income attributable to controlling interests																					1,289		1,357
Preferred share dividends																					(71	)	(72	)
Net income attributable to common shares																					1,218		1,285

TOTAL ASSETS

(unaudited - millions of Canadian $)	September 30, 2015	December 31, 2014
Natural Gas Pipelines	30,008	27,103
Liquids Pipelines	18,856	16,116
Energy	14,820	14,197
Corporate	2,044	1,531
	65,728	58,947

4. Pipeline abandonment costs

As a result of the NEB's Land Matters Consultation Initiative (LMCI), TransCanada is required to collect funds to cover estimated future pipeline abandonment costs for all NEB regulated Canadian pipelines. Amounts collected are included in regulatory liabilities on the condensed consolidated balance sheet. As at September 30, 2015, regulatory liabilities included $188 million (December 31, 2014 - nil) of estimated future abandonment costs on the condensed consolidated balance sheet. 

Collected funds are placed in trusts that hold and invest the funds and are accounted for as restricted investments. As at September 30, 2015, intangible and other assets included $188 million (December 31, 2014 - nil) of LMCI restricted investments on the condensed consolidated balance sheet. For more information on the fair values of these investments which are classified as available for sale refer to Note 11.

5. Income taxes

At September 30, 2015, the total unrecognized tax benefit of uncertain tax positions was approximately $18 million (December 31, 2014 - $18 million). TransCanada recognizes interest and penalties related to income tax uncertainties in income tax expense. Included in income tax expense for the three and nine months ended September 30, 2015 is nil and $1 million for the reversal of interest expense and nil for penalties (September 30, 2014 - nil of interest expense and nil for penalties). At September 30, 2015, the Company had $4 million accrued for interest expense and nil accrued for penalties (December 31, 2014 - $5 million accrued for interest expense and nil for penalties).

The effective tax rates for the nine-month periods ended September 30, 2015 and 2014 were 32 per cent and 30 per cent. The higher effective tax rate in 2015 was primarily the result of an increase in the Alberta statutory tax rate and changes in the proportion of income earned between Canadian and foreign jurisdictions.

6. Long-term debt

LONG-TERM DEBT ISSUED

The Company issued long-term debt in the nine months ended September 30, 2015 as follows:

(unaudited - millions of Canadian $, unless noted otherwise)	Issue date		Type		Maturity date		Amount		Interest rate
TRANSCANADA PIPELINES LIMITED
	July 2015		Medium-Term Notes		July 2025		750		3.30 %
	March 2015		Senior Unsecured Notes		March 2045		US 750		4.60 %
	January 2015		Senior Unsecured Notes		January 2018		US 500		1.875 %
	January 2015		Senior Unsecured Notes		January 2018		US 250		Floating
TC PIPELINES, LP
	September 2015		Unsecured Term Loan		October 2018		US 170		Floating
	March 2015		Senior Unsecured Notes		March 2025		US 350		4.375 %
GAS TRANSMISSION NORTHWEST LLC
	June 2015		Unsecured Term Loan		June 2019		US 75		Floating

LONG-TERM DEBT RETIRED

The Company retired long-term debt in the nine months ended September 30, 2015 as follows:

(unaudited - millions of Canadian $, unless noted otherwise)		Retirement date		Type		Amount		Interest rate
TRANSCANADA PIPELINES LIMITED
		August 2015		Debentures		150		11.90 %
		June 2015		Senior Unsecured Notes		US 500		3.40 %
		March 2015		Senior Unsecured Notes		US 500		0.875 %
		January 2015		Senior Unsecured Notes		US 300		4.875 %
GAS TRANSMISSION NORTHWEST LLC
		June 2015		Senior Unsecured Notes		US 75		5.09 %

In the three and nine months ended September 30, 2015, TransCanada capitalized interest related to capital projects of $82 million and $223 million (2014 - $57 million and $199 million).

7. Junior Subordinated Notes

JUNIOR SUBORDINATED DEBT ISSUED

(unaudited - millions of Canadian $, unless noted otherwise)		Issue date		Type		Maturity date		Amount		Interest rate
TRANSCANADA PIPELINES LIMITED		May 2015		Junior subordinated unsecured notes1		May 2075		US 750		5.875%2

(1)	The Junior subordinated unsecured 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.

TransCanada Trust (the Trust), a 100 per cent owned financing trust subsidiary of TCPL, issued US$750 million Trust Notes - Series 2015-A (Trust Notes) to third party investors with a fixed interest rate of 5.625 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL in US$750 million junior subordinated notes of TCPL at a rate of 5.875 per cent which includes a 0.25 per cent administration charge. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TransCanada's financial statements because TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are receivables from TCPL.

Pursuant to the terms of the Trust Notes and related agreements, in certain circumstances (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TransCanada and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with other outstanding first preferred shares of TCPL. Further details regarding the terms of the Trust Notes and the related agreements entered into by TransCanada and TCPL can be found in the prospectus in respect of the Trust Notes and other documents filed under the Trust's profile on SEDAR at www.sedar.com.

8. Equity and share capital

In June 2015, holders of 5.5 million Series 3 cumulative redeemable first preferred shares exercised their option to convert to Series 4 cumulative redeemable first preferred shares and receive quarterly floating rate cumulative dividends at an annual rate equal to the applicable 90-day Government of Canada treasury bill rate plus 1.28 per cent which will reset every quarter going forward. The fixed dividend rate on the remaining Series 3 preferred shares was reset for five years at 2.152 per cent per annum.

In March 2015, TransCanada completed a public offering of 10 million Series 11 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $250 million. The Series 11 preferred shareholders will have the right to convert their Series 11 preferred shares into Series 12 cumulative redeemable first preferred shares on November 30, 2020 and on November 30 of every fifth year thereafter. The holders of Series 12 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at an annual rate equal to the applicable 90-day Government of Canada treasury bill rate plus 2.96 per cent.

PREFERRED SHARE ISSUANCE AND CONVERSION

The following table summarizes the impact of the 2015 issuance and conversion of preferred shares discussed above:

(unaudited - millions of Canadian $, unless noted otherwise)

Number of shares issued and outstanding (thousands)

Current yield1

Annual dividend per share

Redemption price per share2

Redemption and conversion option date

Right to convert into

Cumulative first preferred shares

Series 3

8,533

2.152 %

0.5375

$25.00

June 30, 2020

Series 4

Series 4

5,467

Floating3

Floating

$25.50

June 30, 2020

Series 3

Series 11

10,000

3.80 %

0.95

$25.00

November 30, 2020

Series 12

(1)	Holders of the cumulative redeemable first preferred shares set out in this table are entitled to receive a quarterly fixed, cumulative, preferred dividend, as and when declared by the Board with the exception of Series 4 preferred shares. The holders of Series 4 preferred shares are entitled to receive a quarterly, floating rate, cumulative, preferred dividend as and when declared by the Board.
(2)	TransCanada may, at its 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.
(3)	Commencing September 30, 2015, the floating quarterly dividend rate for the Series 4 preferred shares is 1.656 per cent and will reset every quarter going forward.

9. Other comprehensive income and accumulated other comprehensive loss

Components of other comprehensive income including non-controlling interests and the related tax effects are as follows:

three months ended September 30, 2015 (unaudited - millions of Canadian $)	Before tax amount		Income tax recovery/ (expense)		Net of tax amount
Foreign currency translation gains on net investment in foreign operations	350		6		356
Change in fair value of net investment hedges	(207	)	54		(153	)
Change in fair value of cash flow hedges	(49	)	20		(29	)
Reclassification to net income of gains and losses on cash flow hedges	80		(30	)	50
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	10		(3	)	7
Other comprehensive income on equity investments	4		(1	)	3
Other comprehensive income	188		46		234
three months ended September 30, 2014 (unaudited - millions of Canadian $)	Before tax amount		Income tax recovery/ (expense)		Net of tax amount
Foreign currency translation gains on net investment in foreign operations	234		53		287
Change in fair value of net investment hedges	(164	)	43		(121	)
Change in fair value of cash flow hedges	62		(25	)	37
Reclassification to net income of gains and losses on cash flow hedges	5		-		5
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	6		(1	)	5
Other comprehensive income on equity investments	2		(2	)	-
Other comprehensive income	145		68		213
nine months ended September 30, 2015 (unaudited - millions of Canadian $)	Before tax amount		Income tax  recovery/ (expense)		Net of tax amount
Foreign currency translation gains on net investments in foreign operations	675		13		688
Change in fair value of net investment hedges	(490	)	129		(361	)
Change in fair value of cash flow hedges	(78	)	28		(50	)
Reclassification to net income of gains and losses on cash flow hedges	136		(53	)	83
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	30		(6	)	24
Other comprehensive income on equity investments	13		(3	)	10
Other comprehensive income	286		108		394
nine months ended September 30, 2014 (unaudited - millions of Canadian $)	Before tax amount		Income tax recovery/ (expense)		Net of tax amount
Foreign currency translation gains on net investments in foreign operations	285		52		337
Change in fair value of net investment hedges	(228	)	59		(169	)
Change in fair value of cash flow hedges	104		(40	)	64
Reclassification to net income of gains and losses on cash flow hedges	(94	)	39		(55	)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	19		(5	)	14
Other comprehensive gain on equity investments	3		(1	)	2
Other comprehensive income	89		104		193

The changes in accumulated other comprehensive loss by component are as follows:

three months ended September 30, 2015 (unaudited - millions of Canadian $)	Currency translation adjustments			Cash flow hedges			Pension and OPEB plan adjustments			Equity investments			Total1
AOCI balance at July 1, 2015	(512	)		(116	)		(264	)		(301	)		(1,193	)
Other comprehensive income/(loss) before reclassifications 2	76			(27	)		-			-			49
Amounts reclassified from accumulated other comprehensive loss	-			50			7			3			60
Net current period other comprehensive income	76			23			7			3			109
AOCI balance at September 30, 2015	(436	)		(93	)		(257	)		(298	)		(1,084	)

(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 and cash flow hedges is net of non-controlling interest gains of $127 million and losses of $2 million.

nine months ended September 30, 2015 (unaudited - millions of Canadian $)		Currency translation adjustments		Cash flow hedges		Pension and OPEB plan adjustments		Equity Investments		Total1
AOCI balance at January 1, 2015		(518	)	(128	)	(281	)	(308	)	(1,235	)
Other comprehensive income/(loss) before reclassifications2		82		(48	)	-		-		34
Amounts reclassified from accumulated other comprehensive loss3		-		83		24		10		117
Net current period other comprehensive income		82		35		24		10		151
AOCI balance at September 30, 2015		(436	)	(93	)	(257	)	(298	)	(1,084	)

(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 and cash flow hedges is net of non-controlling interest gains of $245 million and losses of $2 million.
(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 $64 million ($39 million, net of tax) at September 30, 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.

Details about reclassifications out of accumulated other comprehensive loss are as follows:

		Amounts reclassified from accumulated other comprehensive loss1									Affected line item in the condensed consolidated statement of income
		three months ended September 30				nine months ended September 30
(unaudited - millions of Canadian $)		2015		2014		2015		2014
Cash flow hedges
	Power and Natural Gas	(76	)	(1	)	(124	)	106			Revenue (Energy)
	Interest	(4	)	(4	)	(12	)	(12	)		Interest expense
		(80	)	(5	)	(136	)	94			Total before tax
		30		-		53		(39	)		Income tax expense
		(50	)	(5	)	(83	)	55			Net of tax
Pension and OPEB plan adjustments
	Amortization of actuarial loss and past service cost	(10	)	(6	)	(30	)	(19	)		2
		3		1		6		5			Income tax expense
		(7	)	(5	)	(24	)	(14	)		Net of tax
Equity Investments
	Equity income	(4	)	(2	)	(13	)	(3	)		Income from equity investments
		1		2		3		1			Income tax expense
		(3	)	-		(10	)	(2	)		Net of tax

(1)	All amounts in parentheses indicate expenses to the condensed consolidated statement of income.
(2)	These accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 10 for additional detail.

10. Employee post-retirement benefits

The net benefit cost recognized for the Company's defined benefit pension plans and other post-retirement benefit plans is as follows:

	three months ended September 30								nine months ended September 30
	Pension benefit plans				Other post-retirement benefit plans				Pension benefit plans				Other post-retirement benefit plans
(unaudited - millions of Canadian $)	2015		2014		2015		2014		2015		2014		2015		2014
Service cost	27		21		1		1		81		64		2		2
Interest cost	29		28		2		2		86		84		7		7
Expected return on plan assets	(39	)	(35	)	(1	)	-		(116	)	(104	)	(2	)	(1	)
Amortization of actuarial loss	9		5		1		-		26		16		3		1
Amortization of past service cost	-		1		-		-		1		2		-		-
Amortization of regulatory asset	6		4		-		1		18		13		-		1
Amortization of transitional obligation related to regulated business	-		-		1		-		-		-		2		1
Net benefit cost recognized	32		24		4		4		96		75		12		11

11. Risk management and financial instruments

RISK MANAGEMENT OVERVIEW

TransCanada has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings, cash flow and, ultimately, shareholder value.

COUNTERPARTY CREDIT RISK

TransCanada's maximum counterparty credit exposure with respect to financial instruments at September 30, 2015, without taking into account security held, consisted of accounts receivable, available for sale assets recorded at fair value, the fair value of derivative assets and notes, loans and advances receivable. At September 30, 2015, there were no significant amounts past due or impaired, and there were no significant credit losses during the period.

The Company had a credit risk concentration due from a counterparty of $248 million (US$185 million) and $258 million (US$222 million) at September 30, 2015 and December 31, 2014. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's investment grade parent company.

NET INVESTMENT IN FOREIGN OPERATIONS

The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps and foreign exchange forward contracts.

U.S. dollar-denominated debt designated as a net investment hedge

(unaudited - millions of Canadian $, unless noted otherwise)	September 30, 2015	December 31, 2014
Carrying value	21,000 (US 15,600)	17,000 (US 14,700)
Fair value	22,400 (US 16,700)	19,000 (US 16,400)

Derivatives designated as a net investment hedge

	September 30, 2015				December 31, 2014
(unaudited - millions of Canadian $, unless noted otherwise)	Fair value1		Notional or principal amount		Fair value1		Notional or principal amount
Asset/(liability)
U.S. dollar cross-currency interest rate swaps
(maturing 2015 to 2019)2	(711	)	US 2,300		(431	)	US 2,900
U.S. dollar foreign exchange forward contracts
(maturing 2015 to 2016)	(18	)	US 800		(28	)	US 1,400
	(729	)	US 3,100		(459	)	US 4,300

(1)	Fair values equal carrying values.
(2)	Net income in the three and nine months ended September 30, 2015 included net realized gains of $2 million and $7 million (2014 - gains of $5 million and $16 million) related to the interest component of cross-currency swaps which is offset in interest expense.

Balance sheet presentation of net investment hedges

The balance sheet classification of the fair value of derivatives used to hedge the Company's net investment in foreign operations is as follows:

(unaudited - millions of Canadian $)	September 30, 2015		December 31, 2014
Other current assets	42		5
Intangible and other assets	6		1
Accounts payable and other	(355	)	(155	)
Other long-term liabilities	(422	)	(310	)
	(729	)	(459	)

FINANCIAL INSTRUMENTS

Non-derivative financial instruments

Fair value of non-derivative financial instruments

The fair value of the Company's notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of long-term debt and junior subordinated notes is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers.

Available for sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments included in cash and cash equivalents, accounts receivable, intangible and other assets, notes payable, accounts payable and other, accrued interest and other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity and would also be classified in Level II of the fair value hierarchy.

Credit risk has been taken into consideration when calculating the fair value of non-derivative instruments.

Balance sheet presentation of non-derivative financial instruments

The following table details the fair value of the non-derivative financial instruments, excluding those with carrying amounts that approximate fair value, that would be classified in Level II of the fair value hierarchy:

	September 30, 2015					December 31, 2014
(unaudited - millions of Canadian $)	Carrying amount		Fair value			Carrying amount		Fair value
Notes receivable1	204		254			213		263
Current and long-term debt2,3	(29,075	)	(32,511	)		(24,757	)	(28,713	)
Junior subordinated notes	(2,333	)	(2,069	)		(1,160	)	(1,157	)
	(31,204	)	(34,326	)		(25,704	)	(29,607	)

(1)	Notes receivable are included in other current assets and intangible and other assets on the condensed consolidated balance sheet.
(2)	Long-term debt is recorded at amortized cost except for US$750 million (December 31, 2014 - US$400 million) that is attributed to hedged risk and recorded at fair value.
(3)	Consolidated net income for the three and nine months ended September 30, 2015 included unrealized losses of $9 million and $9 million (2014 - gains of $2 million and 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$750 million of long-term debt at September 30, 2015 (December 31, 2014 - US$400 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

Available for sale assets summary

The following tables summarize additional information about the Company's restricted investments that are classified as available for sale assets:

		September 30, 2015			December 31, 2014
(unaudited - millions of Canadian $)		LMCI restricted investments	Other restricted investments2		LMCI restricted investments	Other restricted investments2
Fair Values1
	Fixed income securities (maturing within 5 years)	-	110		-	75
	Fixed income securities (maturing after 10 years)	186	-		-	-
		186	110		-	75

(1)	Available for sale assets are recorded at fair value and included in intangible and other assets on the condensed consolidated balance sheet.
(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.

		September 30, 2015				September 30, 2014
(unaudited - millions of Canadian $)		LMCI restricted investments1		Other restricted investments2		LMCI restricted investments1	Other restricted investments2
Net unrealized gains/ (losses) in the period
	three months ended	1		-		-	-
	nine months ended	(2	)	-		-	-

(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 records these gains and losses as regulatory assets or liabilities.
(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.

Derivative instruments

Fair value of derivative instruments

The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses period end market rates and applies a discounted cash flow valuation model. The fair value of power and natural gas derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.

In some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment or are not designated as a hedge and are accounted for at fair value with changes in fair value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period.

Balance sheet presentation of derivative instruments

The balance sheet classification of the fair value of the derivative instruments is as follows:

(unaudited - millions of Canadian $)	September 30, 2015		December 31, 2014
Other current assets	314		409
Intangible and other assets	150		93
Accounts payable and other	(795	)	(749	)
Other long-term liabilities	(626	)	(411	)
	(957	)	(658	)

2015 derivative instruments summary

The following summary does not include hedges of the Company's net investment in foreign operations.

(unaudited - millions of Canadian $, unless noted otherwise)			Power		Natural gas		Foreign exchange		Interest
Derivative instruments held for trading1
Fair values2,3
	Assets		$295		$60		$-		$3
	Liabilities		($366	)	($99	)	($56	)	($3	)
Notional values3
	Volumes4
		Purchases	60,603		106		-		-
		Sales	48,801		58		-		-
	U.S. dollars		-		-		US 1,299		US 100
Net unrealized (losses)/gains in the period5
	three months ended September 30, 2015		($34	)	$7		($26	)	$-
	nine months ended September 30, 2015		($33	)	$3		($25	)	$-
Net realized losses in the period5
	three months ended September 30, 2015		($27	)	($25	)	($34	)	$-
	nine months ended September 30, 2015		($60	)	($24	)	($87	)	$-
Maturity dates3			2015-2020		2015-2020		2015-2016		2015-2016
Derivative instruments in hedging relationships6,7
Fair values2,3
	Assets		$46		$-		$-		$12
	Liabilities		($116	)	$-		$-		($4	)
Notional values3
	Volumes4
		Purchases	11,985		-		-		-
		Sales	5,006		-		-		-
	U.S. dollars		-		-		-		US 900
Net realized (losses)/gains in the period5
	three months ended September 30, 2015		($35	)	$-		$-		$2
	nine months ended September 30, 2015		($132	)	$-		$-		$6
Maturity dates3			2015-2020		-		-		2015-2019

(1)	The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.
(2)	Fair values equal carrying values.
(3)	As at September 30, 2015.
(4)	Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.
(5)	Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in energy 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 expense, respectively. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to energy revenues, interest expense and interest income and other expense, as appropriate, as the original hedged item settles.
(6)	All hedging relationships are designated as cash flow hedges except for interest rate derivative instruments designated as fair value hedges with a fair value of $12 million and a notional amount of US$750 million as at September 30, 2015. For the three and nine months ended September 30, 2015, net realized gains on fair value hedges were $4 million and $8 million and were included in interest expense. For the three and nine months ended September 30, 2015, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.
(7)	For the three and nine months ended September 30, 2015, there were no gains or losses included in net income for discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

2014 derivative instruments summary

The following summary does not include hedges of the Company's net investment in foreign operations.

(unaudited - millions of Canadian $, unless noted otherwise)			Power		Natural gas		Foreign exchange		Interest
Derivative instruments held for trading1
Fair values2,3
	Assets		$362		$69		$1		$4
	Liabilities		($391	)	($103	)	($32	)	($4	)
	Notional values3
	Volumes4
		Purchases	42,097		60		-		-
		Sales	35,452		38		-		-
	U.S. dollars		-		-		US 1,374		US 100
Net unrealized gains/(losses) in the period5
	three months ended September 30, 2014		$20		$7		($32	)	$-
	nine months ended September 30, 2014		$35		($14	)	($9	)	$-
Net realized gains/(losses) in the period5
	three months ended September 30, 2014		$8		($27	)	($1	)	$-
	nine months ended September 30, 2014		($23	)	$19		($19	)	$-
Maturity dates3			2015-2019		2015-2020		2015		2015-2016
Derivative instruments in hedging relationships6,7
Fair values2,3
	Assets		$57		$-		$-		$3
	Liabilities		($163	)	$-		$-		($2	)
Notional values3
	Volumes4
		Purchases	11,120		-		-		-
		Sales	3,977		-		-		-
	U.S. dollars		-		-		-		US 550
Net realized (losses)/gains in the period5
	three months ended September 30, 2014		($50	)	$-		$-		$1
	nine months ended September 30, 2014		$138		$-		$-		$3
Maturity dates3			2015-2019		-		-		2015-2018

(1)	The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.
(2)	Fair values equal carrying values.
(3)	As at December 31, 2014.
(4)	Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.
(5)	Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in energy 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 expense, respectively. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to energy revenues, interest expense and interest income and other expense, as appropriate, as the original hedged item settles.
(6)	All hedging relationships are designated as cash flow hedges except for interest rate derivative instruments designated as fair value hedges with a fair value of $3 million and a notional amount of US$400 million as at December 31, 2014. Net realized gains on fair value hedges for the three and nine months ended September 30, 2014 were $2 million and $5 million and were included in interest expense. For the three and nine months ended September 30, 2014, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.
(7)	For the three and nine months ended September 30, 2014, there were no gains or losses included in net income for discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

Derivatives in cash flow hedging relationships

The components of OCI (Note 9) related to derivatives in cash flow hedging relationships are as follows:

		three months ended September 30					nine months ended September 30
(unaudited - millions of Canadian $, pre-tax)		2015		2014			2015		2014
Change in fair value of derivative instruments recognized in OCI (effective portion)1
	Power	(48	)	62			(77	)	96
	Natural gas	-		(1	)		-		(2	)
	Foreign exchange	-		-			-		10
	Interest	(1	)	1			(1	)	-
		(49	)	62			(78	)	104
Reclassification of gains/(losses) on derivative instruments from AOCI to net income (effective portion)1
	Power2	76		-			124		(109	)
	Natural gas2	-		1			-		3
	Interest3	4		4			12		12
		80		5			136		(94	)
Gains on derivative instruments recognized in net income (ineffective portion)
	Power	10		23			3		13
		10		23			3		13

(1)	No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI.
(2)	Reported within energy revenues on the condensed consolidated statement of income.
(3)	Reported within interest expense on the condensed consolidated statement of income.

Offsetting of derivative instruments

The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TransCanada has no master netting agreements, however, similar contracts are entered into containing rights to offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis:

at September 30, 2015 (unaudited - millions of Canadian $)		Gross derivative instruments presented on the balance sheet		Amounts available for offset1		Net amounts
Derivative - Asset
	Power	341		(296	)	45
	Natural gas	60		(48	)	12
	Foreign exchange	48		(48	)	-
	Interest	15		(3	)	12
Total		464		(395	)	69
Derivative - Liability
	Power	(482	)	296		(186	)
	Natural gas	(99	)	48		(51	)
	Foreign exchange	(833	)	48		(785	)
	Interest	(7	)	3		(4	)
Total		(1,421	)	395		(1,026	)

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

The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2014:

at December 31, 2014(unaudited - millions of Canadian $)		Gross derivative instruments presented on the balance sheet		Amounts available for offset1		Net amounts
Derivative - Asset
	Power	419		(330	)	89
	Natural gas	69		(57	)	12
	Foreign exchange	7		(7	)	-
	Interest	7		(1	)	6
Total		502		(395	)	107
Derivative - Liability
	Power	(554	)	330		(224	)
	Natural gas	(103	)	57		(46	)
	Foreign exchange	(497	)	7		(490	)
	Interest	(6	)	1		(5	)
Total		(1,160	)	395		(765	)

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

With respect to all financial arrangements, including the derivative instruments presented above as at September 30, 2015, the Company had provided cash collateral of $468 million (December 31, 2014 - $459 million) and letters of credit of $28 million (December 31, 2014 - $26 million) to its counterparties. The Company held nil (December 31, 2014 - $1 million) in cash collateral and $2 million (December 31, 2014 - $1 million) in letters of credit from counterparties on asset exposures at September 30, 2015. 

Credit risk related contingent features of derivative instruments

Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade.

Based on contracts in place and market prices at September 30, 2015, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $15 million (December 31, 2014 - $15 million), for which the Company had provided collateral in the normal course of business of nil (December 31, 2014 - nil). If the credit-risk-related contingent features in these agreements were triggered on September 30, 2015, the Company would have been required to provide additional collateral of $15 million (December 31, 2014 - $15 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.

The Company has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.

FAIR VALUE HIERARCHY

The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy.

Levels	How fair value has been determined
Level I	Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.
Level II	Valuation based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and power and natural gas commodity derivatives where fair value is determined using the market approach. Transfers between Level I and Level II would occur when there is a change in market circumstances.
Level III	Valuation of assets and liabilities are measured using a market approach based on extrapolation of inputs that are unobservable or where observable data does not support a significant portion of the derivative's fair value. This category includes long-dated commodity transactions in certain markets where liquidity is low and inputs may include long-term broker quotes. Valuation of options is based on the Black-Scholes pricing model. Long-term electricity prices may also be estimated using a third-party modeling tool which takes into account physical operating characteristics of generation facilities in the markets in which the Company operates. Model inputs include market fundamentals such as fuel prices, power supply additions and retirements, power demand, seasonal hydro conditions and transmission constraints. Long-term North American natural gas prices might be estimated on a view of future natural gas supply and demand, as well as exploration and development costs. Significant decreases in fuel prices or demand for electricity or natural gas, increases in the supply of electricity or natural gas, or a small number of transactions in markets with lower liquidity are expected to or may result in a lower fair value measurement of contracts included in Level III. Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which significant inputs are considered to be observable. As contracts near maturity and observable market data becomes available, they are transferred out of Level III and into Level II.

The fair value of the Company's derivative instrument assets and liabilities measured on a recurring basis, including both current and non-current portions, are categorized as follows:

at September 30, 2015 (unaudited - millions of Canadian $, pre-tax)		Quoted prices in active markets (Level I)1		Significant other observable inputs (Level II)1		Significant unobservable inputs (Level III)1		Total
Derivative instrument assets:
	Power commodity contracts	-		337		4		341
	Natural gas commodity contracts	34		14		12		60
	Foreign exchange contracts	-		48		-		48
	Interest rate contracts	-		15		-		15
Derivative instrument liabilities:
	Power commodity contracts	-		(476	)	(6	)	(482	)
	Natural gas commodity contracts	(88	)	(10	)	(1	)	(99	)
	Foreign exchange contracts	-		(833	)	-		(833	)
	Interest rate contracts	-		(7	)	-		(7	)
		(54	)	(912	)	9		(957	)

(1)	There were no transfers from Level I to Level II or from Level II to Level III for the nine months ended September 30, 2015.

The fair value of the Company's assets and liabilities measured on a recurring basis, including both current and non-current portions for 2014, are categorized as follows:

at December 31, 2014 (unaudited - millions of Canadian $, pre-tax)		Quoted prices in active markets (Level I)1		Significant other observable inputs (Level II)1		Significant unobservable inputs (Level III)1		Total
Derivative instrument assets:
	Power commodity contracts	-		417		2		419
	Natural gas commodity contracts	40		24		5		69
	Foreign exchange contracts	-		7		-		7
	Interest rate contracts	-		7		-		7
Derivative instrument liabilities:
	Power commodity contracts	-		(551	)	(3	)	(554	)
	Natural gas commodity contracts	(86	)	(17	)	-		(103	)
	Foreign exchange contracts	-		(497	)	-		(497	)
	Interest rate contracts	-		(6	)	-		(6	)
		(46	)	(616	)	4		(658	)

(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.

The following table presents the net change in fair value of derivative assets and liabilities classified as Level III of the fair value hierarchy:

	three months ended September 30					nine months ended September 30
(unaudited - millions of Canadian $, pre-tax)	2015		2014			2015		2014
Balance at beginning of period	11		(1	)		4		1
Transfers out of Level III	-		(1	)		3		(1	)
Total (losses)/gains included in net income	(2	)	2			3		-
Sales	(1	)	-			(1	)	-
Total gains included in OCI	1		-			-		-
Balance at end of period1	9		-			9		-

(1)	For the three and nine months ended September 30, 2015, energy revenues include unrealized losses of $2 million and gains of $6 million attributed to derivatives in the Level III category that were still held at September 30, 2015 (2014 - gains of $2 million and nil).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $2 million increase or decrease in the fair value of outstanding derivative instruments included in Level III as at September 30, 2015. 

12. Sale of GTN Pipeline to TC PipeLines, LP

On April 1, 2015, TransCanada completed the sale of its remaining 30 per cent interest in Gas Transmission Northwest (GTN) to TC PipeLines, LP for an aggregate purchase price of US$446 million plus a purchase price adjustment of US$11 million. Proceeds for the US$457 million sale were comprised of US$264 million in cash, the assumption of US$98 million in proportional GTN debt and US$95 million of new Class B units of TC PipeLines, LP.

13. Contingencies and guarantees

TransCanada and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations.

GUARANTEES

TransCanada and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust (BPC), have each severally guaranteed certain contingent financial obligations of Bruce B related to a lease agreement and contractor and supplier services. In addition, TransCanada and BPC have each severally guaranteed one-half of certain contingent financial obligations of Bruce A related to a sublease agreement and certain other financial obligations. The Company's exposure under certain of these guarantees is unlimited.

In addition to the guarantees for Bruce Power, the Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities related primarily to delivery of natural gas, PPA payments and the payment of liabilities. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners.

The carrying value of these guarantees has been included in other long-term liabilities. Information regarding the Company's guarantees is as follows:

			at September 30, 2015			at December 31, 2014
(unaudited - millions of Canadian $)	Term		Potential exposure1	Carrying value		Potential exposure1	Carrying value
Bruce Power	ranging to 20192		529	5		634	6
Other jointly owned entities	ranging to 2040		140	20		104	14
			669	25		738	20

(1)	TransCanada's share of the potential estimated current or contingent exposure.
(2)	Except for one guarantee with no termination date.

14. Restructuring costs

During 2015, TransCanada commenced a business restructuring and transformation initiative to reduce overall costs and maximize the effectiveness and efficiency of its existing operations. At September 30, 2015, TransCanada had incurred $36 million before tax, mainly related to severance costs, of which $20 million before tax was included in plant operating costs and other on the income statement, $8 million was capitalized to projects impacted by the restructuring and $8 million is recoverable through regulatory and tolling structures. The total restructuring charges will be determined once the scope of the expected changes is known, which is anticipated to occur in fourth quarter 2015. The Company expects further restructuring initiatives to be undertaken in fourth quarter 2015 and to continue into 2016.

15. Subsequent events

On October 6, 2015, TCPL completed an offering of $400 million, 4.55 per cent Medium Term Notes due November 15, 2041.

On October 8, 2015, TransCanada entered into an agreement to acquire the Ironwood natural gas fired, combined cycle power plant in Pennsylvania for US$654 million. At closing, US$42 million in debt will be assumed and repaid within 45 days of closing out of funds placed into escrow by the seller. The transaction is expected to close in first quarter 2016, subject to certain conditions being satisfied.