TransAlta (TAC) 40-F 2015 FY Annual report (Canada)

Exhibit 13.2

TRANSALTA CORPORATION

Management’s Discussion and Analysis

Table of Contents

Forward-Looking Statements	M2
Additional IFRS Measure and Non-IFRS Measures	M3
Highlights	M4
Business Model and Competitive Forces	M15
TransAlta’s Capitals	M18
Discussion of Segmented Comparable Results	M36
Other Consolidated Analysis	M44
Earnings and Other Measures on a Comparable Basis	M51

Financial Instruments	M55
2016 Financial Outlook	M57
Governance and Risk Management	M61
Critical Accounting Policies and Estimates	M72
Accounting Changes	M78
Fourth Quarter	M80
Selected Quarterly Information	M87
Disclosure Controls and Procedures	M88

This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with our audited annual 2015 consolidated financial statements and our Annual Information Form for the year ended Dec. 31, 2015. Our consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) for Canadian publicly accountable enterprises as issued by the International Accounting Standards Board (“IASB”) and in effect at Dec. 31, 2015. All dollar amounts in the following discussion, including the tables, are in millions of Canadian dollars unless otherwise noted and except amounts per share which are in whole dollars to the nearest two decimals. This MD&A is dated Feb. 17, 2016. Additional information respecting TransAlta Corporation (“TransAlta”, “we”, “our”, “us”, or the “Corporation”), including our Annual Information Form, is available on SEDAR at www.sedar.com, on EDGAR at www.sec.gov, and on our website at www.transalta.com. Information on or connected to our website is not incorporated by reference herein.

TRANSALTA CORPORATION M1

Forward-Looking Statements

This MD&A, the documents incorporated herein by reference, and other reports and filings made with securities regulatory authorities include forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities legislation. Forward-looking statements, including the 2016 Financial Outlook section of this MD&A, are presented for general information purposes only and not as specific investment advice. All forward-looking statements are based on our beliefs as well as assumptions based on information available at the time the assumptions were made and on management’s experience and perception of historical trends, current conditions, and expected future developments, as well as other factors deemed appropriate in the circumstances. Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as “may”, “will”, “believe”, “expect”, “anticipate”, “intend”, “plan”, “project”, “forecast”, “foresee”, “potential”, “enable”, “continue”, or other comparable terminology. These statements are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance to be materially different from that projected.

In particular, this MD&A contains forward-looking statements pertaining to our business and anticipated future financial performance; our success in executing on our growth projects; the timing of the construction and commissioning of projects under development, including major projects such as the South Hedland power project and the Sundance 7 project, and their attendant costs; spending on growth and sustaining capital and productivity projects; expectations in terms of the cost of operations, capital spending, and maintenance, and the variability of those costs; expected decommissioning costs; the impact of certain hedges on future reported earnings and cash flows, including future reversals of unrealized gains or losses; expectations related to future earnings and cash flow from operating and contracting activities (including estimates of full-year 2016 comparable earnings before interest, taxes, depreciation, and amortization (“EBITDA”), comparable funds from operations (“FFO”), comparable free cash flow (“FCF”), and expected sustaining capital expenditures for 2016); expectations in respect of financial ratios and targets (including comparable FFO before interest to adjusted interest coverage, adjusted comparable FFO to adjusted net debt, and adjusted net debt to comparable EBITDA); the Corporation’s plans and strategies relating to repositioning its capital structure and strengthening its balance sheet and the debt reductions that are expected to occur in 2016 and beyond; expected governmental regulatory regimes and legislation (including the Government of Alberta’s Climate Leadership Plan) and their expected impact on TransAlta and the timing of the implementation of such regimes and regulations, as well as the cost of complying with resulting regulations and laws; the outcome of negotiations with the Government of Alberta in relation to coal-fired generation transition under the Climate Leadership Plan; and potential opportunities for investment in renewable and gas-fired generation; our comparative advantages over our competitors; estimates of fuel supply and demand conditions and the costs of procuring fuel; expectations for demand for electricity in both the short term and long term, and the resulting impact on electricity prices; the impact of load growth, increased capacity, and natural gas costs on power prices; expectations in respect of generation availability, capacity, and production; expectations regarding the role different energy sources will play in meeting future energy needs; expected financing of our capital expenditures; including the anticipated financial impact of increased Specified Gas Emitters Regulation (“SGER”) obligations in Alberta, and the value of offsets generated by our wind facilities in the province; our trading strategies and the risk involved in these strategies; estimates of future tax rates, future tax expense, and the adequacy of tax provisions; accounting estimates; anticipated growth rates in our markets; our expectations regarding the outcome of existing or potential legal and contractual claims, regulatory investigations, and disputes; expectations regarding the renewal of collective bargaining agreements; expectations for the ability to access capital markets at reasonable terms; the estimated impact of changes in interest rates and the value of the Canadian dollar relative to the US dollar, the Australian dollar, and other currencies in which we do business; the monitoring of our exposure to liquidity risk; expectations regarding the impact of the slowdown in the oil and gas sector; expectations in respect of the global economic environment and growing scrutiny by investors relating to sustainability performance; our credit practices; expected cost savings following the implementation of our efficiency and productivity initiatives; the estimated contribution of Energy Marketing activities to gross margin; expectations relating to the performance of TransAlta Renewables Inc.’s (“TransAlta Renewables”) assets; expectations regarding our continued ownership of common shares of TransAlta Renewables; expectations in respect of our community and environmental initiatives; and expectations in respect of the Keephills Unit 1 Force Majeure event, including the impact of the claim.

M2  TRANSALTA CORPORATION

Factors that may adversely impact our forward-looking statements include risks relating to: fluctuations in market prices and the availability of fuel supplies required to generate electricity; our ability to contract our generation for prices that will provide expected returns; the regulatory and political environments in the jurisdictions in which we operate; increasingly stringent environmental requirements and changes in, or liabilities under, these requirements; changes in general economic conditions, including interest rates; operational risks involving our facilities, including unplanned outages at such facilities; disruptions in the transmission and distribution of electricity; the effects of weather; disruptions in the source of fuels, water, or wind required to operate our facilities; natural or man-made disasters; the threat of terrorism and cyberattacks; equipment failure and our ability to carry out or have completed the repairs in a cost-effective or timely manner; commodity risk management; industry risk and competition; fluctuations in the value of foreign currencies and foreign political risks; the need for additional financing and the ability to access financing at a reasonable cost; our ability to fund our growth projects; our ability to maintain our investment grade credit ratings; structural subordination of securities; counterparty credit risk; our ability to recover our losses through our insurance coverage; our provision for income taxes; legal, regulatory, and contractual proceedings involving the Corporation; outcomes of investigations and disputes; reliance on key personnel; labour relations matters; development projects and acquisitions, including delays or changes in costs in the construction of the South Hedland power project; and the satisfactory receipt of applicable regulatory approvals for existing and proposed operations and growth initiatives.

The foregoing risk factors, among others, are described in further detail in the Governance and Risk Management section of this MD&A and under the heading “Risk Factors” in our 2016 Annual Information Form.

Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this document are made only as of the date hereof and we do not undertake to publicly update these forward-looking statements to reflect new information, future events, or otherwise, except as required by applicable laws. In light of these risks, uncertainties, and assumptions, the forward-looking events might occur to a different extent or at a different time than we have described, or might not occur. We cannot assure that projected results or events will be achieved.

Additional IFRS Measures and Non-IFRS Measures

An additional IFRS measure is a line item, heading, or subtotal that is relevant to an understanding of the financial statements but is not a minimum line item mandated under IFRS, or the presentation of a financial measure that is relevant to an understanding of the financial statements but is not presented elsewhere in the financial statements. We have included line items entitled gross margin and operating income (loss) in our Consolidated Statements of Earnings (Loss) for the years ended Dec. 31, 2015, 2014, and 2013. Presenting these line items provides management and investors with a measurement of ongoing operating performance that is readily comparable from period to period.

We evaluate our performance and the performance of our business segments using a variety of measures. Certain of the financial measures discussed in this MD&A are not defined under IFRS and, therefore, should not be considered in isolation or as an alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from operating activities, as determined in accordance with IFRS, when assessing our financial performance or liquidity. These measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. See the Comparable Funds from Operations and Comparable Free Cash Flow, Discussion of Segmented Comparable Results, and Earnings and Other Measures on a Comparable Basis sections of this MD&A for additional information.

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Highlights

Consolidated Financial Highlights

Year ended Dec. 31	2015		2014	2013
Revenues	2,267		2,623	2,292
Comparable EBITDA(1,2)	945		1,036	1,023
Net earnings (loss) attributable to common shareholders	(24	)	141	(71	)
Comparable net earnings (loss) attributable to common shareholders(1)	(48	)	68	81
Comparable funds from operations(1)	740		762	729
Cash flow from operating activities	432		796	765
Comparable free cash flow(1,2)	315		280	288
Net earnings (loss) per share attributable to common shareholders, basic and diluted	(0.09	)	0.52	(0.27	)
Comparable net earnings (loss) per share(1)	(0.17	)	0.25	0.31
Comparable funds from operations per share(1)	2.64		2.79	2.76
Comparable free cash flow per share(1,2)	1.13		1.03	1.09
Dividends declared per common share	0.72		0.72	1.16
As at Dec. 31	2015		2014	2013
Total assets	10,947		9,833	9,624
Total credit facilities, long-term debt, tax equity, and finance lease obligations(3), net of cash	4,441		4,013	4,305
Total long-term liabilities	5,704		4,504	5,337

§	Comparable EBITDA decreased by $91 million to $945 million compared to 2014. Excluding a $59 million adjustment to provisions relating mostly to prior years, comparable EBITDA would have been $1,004 million. A significant part of the year-over-year reduction in comparable EBITDA is due to Energy Marketing results during the second quarter of 2015, and lower prices in Alberta and the Pacific Northwest. Energy Marketing delivered strong performance in 2014 because of extraordinary conditions in the Northeast during the first quarter. Prices in Alberta averaged $33 per megawatt hour (“MWh”) in 2015 compared $49 per MWh in 2014. Our high level of contracts and hedges mostly mitigated the impact of low prices, but our wind and hydro businesses in Alberta were impacted. Continued improvement in our mining operations to reduce fuel costs mitigated the impacts of lower availability in Canadian Coal during the first half of the year.
§	Comparable FFO decreased by $22 million to $740 million. Lower interest expenses and cash taxes offset some of the impact from lower comparable EBITDA. The non-cash adjustment to provisions of $59 million does not impact FFO.
§	Comparable net loss attributable to common shareholders was $48 million ($0.17 net loss per share), down from comparable net earnings of $68 million ($0.25 net earnings per share) in 2014. The decrease was primarily due to lower comparable EBITDA and higher earnings attributable to non-controlling interest associated with the sale of additional non-controlling interests in TransAlta Renewables.

(1) These items are not defined under IFRS. Presenting these items from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Refer to the Comparable Funds from Operations and Comparable Free Cash Flow and Earnings and Other Measures on a Comparable Basis sections of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.

(2) 2014 and 2013 restated to deduct hydro life extension capital expenditures from comparable FCF. Refer to the Current Accounting Changes section of this MD&A.

(3) Includes current portion.

M4 TRANSALTA CORPORATION

§

Reported net loss attributable to common shareholders was $24 million ($0.09 net loss per share) compared to net earnings of $141 million ($0.52 net earnings per share) in 2014 and a net loss of $71 million ($0.27 net loss per share) in 2013. Reported net earnings includes the gain on the Poplar Creek contract restructuring ($192 million(1)) and the cost of the settlement with the Market Surveillance Administrator (the “MSA”) ($55 million(1)) in 2015. Changes in the fair value of de-designated and economic hedges at U.S. Coal also had a negative impact on our net earnings ($38 million(1,2)) (2014 - $35 million(1,2) positive, 2013 - $67 million(1,2) negative). Deferred income tax expense was also impacted by the increase in the Alberta corporate tax rate in June 2015 and by the sale of an economic interest in our Australian business to TransAlta Renewables, offsetting a reversal of a writedown of deferred tax assets associated with movements in financial instrument values. The loss in 2013 includes a $42 million(1) settlement of a prior year claim relating to power trading activities in California, a $22 million(1) assumption of pension obligations and $19 million(1) associated with the return to service of Sundance 1 and 2.

§

During 2015, credit facilities, long-term debt, and finance lease obligations increased by approximately $439 million primarily as a result of the stronger US dollar ($392 million) and the acquisition of operating wind and solar facilities ($211 million). Increases in value resulting from the stronger US dollar were offset by corresponding increases in value of U.S. assets as part of our hedging program. On Jan. 6, 2016, we completed a transaction with TransAlta Renewables to sell economic interests of certain assets located in Canada and received $173 million in cash proceeds as part of the transaction. All proceeds were used to reduce amounts borrowed under our credit facilities.

Highlights

During the year, we continued to work on strengthening our financial condition and flexibility, improve our operating performance, and grow our portfolio of highly contracted assets through the following initiatives:

§	We raised over $1.0 billion of capital in 2015, including cash proceeds from sale of an economic interest of certain assets located in Canada to TransAlta Renewables which closed on Jan. 6, 2016, to retire maturing debentures of US$500 million and $155 million. Of the amount raised, over $575 million represents equity raised through the sale of non-controlling interests:
	·	On May 7, 2015, TransAlta Renewables acquired an economic interest in our Australian assets (the “Transaction”) for total consideration of $1,278 million, comprised of net cash proceeds of $211 million as well as a combination of 58.3 million common shares and 26.1 million Class B shares of TransAlta Renewables.
	·	On Nov. 26, 2015, we sold 20.5 million common shares of TransAlta Renewables to the Alberta Investment Management Corporation (“AIMCo”), for net cash proceeds of $193 million.
	·	On Jan. 6, 2016, TransAlta Renewables acquired an economic interest based on the cash flows of the Sarnia cogeneration facility and of two renewable energy facilities for proceeds valued at $540 million. Net cash proceeds of this transaction were $173 million. We also received 15.6 million common shares of TransAlta Renewables and a $215 million convertible debenture.
	We raised $442 million in long-term non-recourse debt, which is secured by three wind projects in Ontario on Oct. 1, 2015. Project-level debt allows us to align the maturity profile of principal with the realization of value from our assets, which will be the central piece of our financing strategy to repay debentures maturing in 2017 and 2018.
§	Over the last three years, we have nearly doubled the weighted average remaining contractual life of our gas fleet from six years to 12 years. This year, we extended the contractual profile of three facilities:
	·	We restructured our contractual arrangements at the Poplar Creek facility, to extend the contracted cash flows attributable to Poplar Creek from 2023 to 2030, and we also acquired two wind facilities, representing 65 megawatts (“MW”) of capacity. As part of the restructuring, our customer acquired our steam generators and the rights to the output of the gas generators and will assume operational control of the site. As a result of the transaction, we recognized a finance lease of $372 million, and increased our long-term assets to reflect the acquisition of two wind farms for $138 million. The transaction closed on Sept. 1, 2015 and we have recognized a gain of $262 million on the transaction. The carrying amount of net assets we transferred to the counterparty was $250 million.
	·	We signed a new 15-year 72 MW power supply contract for our Windsor facility with Ontario’s Independent Electricity System Operator (“IESO”), taking effect in December 2016.

(1) Net of related income tax expense.

(2) Hedge accounting could not be applied to certain contracts, and accordingly, the mark-to-market on these contracts impacted reporting earnings. The impacts of these mark-to-market fluctuations have been removed from revenues to arrive at comparable results, which reflect the economic nature of these contracts.

TRANSALTA CORPORATION M5

·We extended the contract for our 55 MW Parkeston power station in Australia by a period of 10 years from November 2016.

§      We acquired 71 MW of fully contracted renewable generation assets for cash consideration of $106 million together with the assumption of $105 million of project financing obligations. The assets include our first solar facilities, representing 21 MW of capacity in Massachusetts, and one 50 MW wind farm in Minnesota. The acquisition of the solar facilities was completed on Sept. 1, 2015, while the acquisition of the wind farm closed on Oct. 1, 2015.

§      We reached an agreement with the MSA to settle all outstanding proceedings before the Alberta Utilities Commission (the “AUC”) for a total amount of $56 million. Of this amount, we paid $31 million in the fourth quarter and $25 million will be paid in the fourth quarter of 2016.

§      Overhead reductions and our efficiency and productivity initiatives in Canadian Coal will contribute in excess of $47 million in cost savings annually.

§      We received approval from the AUC to construct Sundance 7, an 856 MW high-efficiency natural gas-fired power plant in Alberta. Construction of Sundance 7 will not commence until we have contracted a significant portion of the plant capacity.

§      In March, we successfully completed construction of the natural gas pipeline to our Solomon power station. Since then, the pipeline has contributed $10 million to our EBITDA and FFO.

§      We continued to advance the construction of the South Hedland power project. Bulk earthworks and civil work were largely completed during the year, and major equipment has been arriving on schedule. We expect the project to be delivered on schedule and on budget in mid-2017.

On Nov. 22, 2015, the Government of Alberta announced the Alberta Climate Leadership Plan (the “Plan”). In respect of the power generation sector, the Plan targets the retirement of coal generation in the Province of Alberta by 2030; replacement of two-thirds of the retiring coal-fired generation with renewable generation (to achieve a 30 per cent share of generation by 2030) and one-third gas generation; and establishment of a new system of greenhouse gas (“GHG”) obligations and allowances benchmarked against highly efficient gas-fired generation beginning in 2018, at a price of $30 per tonne. The Government of Alberta has further stated intentions of providing compensation to coal-fired generators as part of its commitment to treat them fairly and not unnecessarily strand capital.

On Jan. 14, 2016, we announced key actions to support our transition from coal to gas-fired and renewable generation in the Province of Alberta and maximize our financial flexibility:

§      We have revised our dividend to $0.16 per common share on an annualized basis from $0.72 previously. The reduction will reduce cash required for the dividend to approximately $45 million from approximately $205 million annually. The revised dividend represents a 15 to 18 per cent payout of our estimated 2016 comparable FCF.

§      We have suspended our dividend reinvestment plan in order to stop shareholder dilution. We do not currently expect to raise additional equity in 2016 as the incremental cash from the dividend reduction will be used to strengthen our balance sheet and financial flexibility.

§      We will focus on raising non-recourse debt to fund upcoming corporate debt maturities. We expect to raise $400 million to $600 million of project-level debt in 2016 to fund the next material debt maturity of US$400 million in 2017, and we plan to execute a similar strategy for the 2018 maturities.

§      We will negotiate with the Government of Alberta, using a principles-based approach, to ensure the Corporation has the certainty and capacity needed to invest in clean power.

§      Over the next 15 years, we will focus on replacing coal-fired generation assets with gas-fired and renewable generation assets.

These actions, combined with initiatives completed in 2015, allow us to build the financial capacity and flexibility to address upcoming debt maturities and capitalize on opportunities in gas-fired and renewable generation that will arise as Alberta transitions from coal to clean power.

M6 TRANSALTA CORPORATION

Segmented Operational Results

Comparable EBITDA and operational performance for the business is as follows:

Year ended Dec. 31	2015		2014		2013
Availability (%)(1)	88.7		89.7		85.5
Adjusted availability (%)(2)	89.0		90.5		87.8
Production (GWh)(1,3)	40,673		45,002		42,482
Comparable EBITDA(4)
Canadian Coal	334		389		311
U.S. Coal	67		65		67
Gas	330		312		332
Wind and Solar	176		179		181
Hydro	73		87		148
Energy Marketing	37		75		58
Corporate	(72	)	(71	)	(74	)
Total comparable EBITDA	945		1,036		1,023

§      Canadian Coal: Comparable EBITDA decreased by $55 million to $334 million in 2015, compared to $389 million in 2014 and $311 million in 2013. The 2015 EBITDA includes a $59 million adjustment to provisions relating mostly to force majeure events for the periods between 2013 to 2015. Excluding this adjustment, 2015 comparable EBITDA would have been $393 million, in line with 2014. Incremental reductions in operating expenses at our Highvale mine offset the negative impact of lower availability on our comparable EBITDA. Our high level of contracts and hedges in Canadian Coal continues to mostly offset the impact of lower prices in Alberta compared to 2014 and 2013. In 2013, the Segment had experienced lower availability.

§      U.S. Coal: Comparable EBITDA was consistent with our 2014 and 2013 results as the stronger US dollar offset the impacts of lower pricing in the Pacific Northwest.

§      Gas: Comparable EBITDA increased by $18 million to $330 million in 2015 compared to $312 million in 2014 and $332 million in 2013. The increase was a result of additional revenues from the Australian natural gas pipeline and the positive impact of the strengthening of the US dollar on a US-dollar-denominated contract in Australia. The change in value in this contract offsets changes in value of our US-dollar-denominated debt. In 2013, the segment had benefitted from higher Alberta pricing at the Poplar Creek facility and from the last year under a higher-priced contract at the Ottawa plant.

§      Wind and Solar: Comparable EBITDA was $176 million in 2015 compared to $179 million in 2014 and $181 million in 2013. The decrease in 2015 is primarily due to lower power prices in Alberta. The acquisition of additional assets in the fourth quarter and the strengthening of the US dollar offset part of this shortfall. In 2014, incremental earnings from the addition of the Wyoming facility had offset the decline in Alberta prices, compared to 2013.

§      Hydro: Comparable EBITDA decreased $14 million to $73 million in 2015 compared to $87 million in 2014 and $148 million in 2013, due to the lower prices and a decrease in price volatility in Alberta, which limits our ability to take advantage of our flexibility to produce electricity in higher priced hours.

§      Energy Marketing: Comparable EBITDA decreased by $38 million in 2015 to $37 million, compared to $75 million in 2014 and $58 million in 2013. Comparable EBITDA in the first quarter of 2014 included effects of extraordinary market conditions caused by unusual weather in the Northeast. The decrease in 2015 is further due to volatile market conditions in the Alberta and Pacific Northwest regions in the second quarter that negatively affected results.

§      Corporate: Our Corporate overhead costs have remained comparable to 2014 and 2013.

(1) Availability and production includes all generating assets (generation operations and finance leases that we operate). 2014 and 2013 availability also includes equity investments, which were sold in May 2014.

(2) Adjusted for economic dispatching at U.S. Coal.

(3) Production includes 314 GWh in 2014 (2013 - 1,556 GWh) from CE Generation LLC and Wailuku Holding Company, LLC, both of which were sold in May 2014.

(4) 2014 and 2013 results restated to reflect the reassignment to the Corporate Segment of $12 million and $7 million, respectively, and to the Energy Marketing Segment of $1 million and $3 million, respectively, of costs associated with certain functions that were determined to benefit the broader organization, or the Energy Marketing Segment, respectively.

TRANSALTA CORPORATIONM7

Comparable Funds from Operations and Comparable Free Cash Flow

Comparable FFO and comparable FCF provide a proxy for the amount of cash generated from operating activities before changes in working capital, and provide the ability to evaluate cash flow trends more readily in comparison with results from prior periods. Comparable FFO per share and comparable FCF per share are calculated using the weighted average number of common shares outstanding during the period.

Year ended Dec. 31	2015		2014		2013
			Restated(1)		Restated(1)
Cash flow from operating activities	432		796		765
Change in non-cash operating working capital balances	242		(73	)	(74	)
Cash flow from operations before changes in working capital	674		723		691
Adjustments
MSA Settlement payment and impacts associated with California claim	31		33		27
Decrease in finance lease receivable	23		3		1
Payment of restructuring costs	19		-		5
Maintenance costs related to Alberta flood of 2013, net of insurance recoveries	(9	)	1		5
Other non-comparable items	2		2		-
Comparable FFO	740		762		729
Deduct:
Sustaining capital	(305	)	(361	)	(349	)
Insurance recoveries of sustaining capital expenditures	25		4		1
Dividends paid on preferred shares	(46	)	(41	)	(38	)
Distributions paid to subsidiaries’ non-controlling interests	(99	)	(84	)	(55	)
Comparable FCF	315		280		288
Weighted average number of common shares outstanding in the year	280		273		264
Comparable FFO per share	2.64		2.79		2.76
Comparable FCF per share	1.13		1.03		1.09

(1) Restated to include hydro life extension from growth capital expenditures to sustaining capital expenditures. Refer to the Current Accounting Changes section of this MD&A.

M8 TRANSALTA CORPORATION

A reconciliation of comparable EBITDA to comparable FFO is as follows:

Year ended Dec. 31	2015		2014		2013
Comparable EBITDA	945		1,036		1,023
Unrealized losses (gains) from risk management activities	1		4		(27	)
Interest expense	(230	)	(236	)	(238	)
Provisions	73		-		19
Current income tax expense	(19	)	(33	)	(39	)
Realized foreign exchange gain	17		11		-
Decommissioning and restoration costs settled	(24	)	(16	)	(24	)
Gain on curtailment and amendment of employee future benefit plans	(8	)	-		-
Capital insurance recoveries on Canadian Coal facility	(7	)	-		-
Flood-related maintenance costs	-		-		5
Other non-cash items	(8	)	(4	)	10
Comparable FFO	740		762		729

For the year ended Dec. 31, 2015, comparable FFO decreased by $22 million to $740 million compared to 2014 mainly due to the reduction in comparable EBITDA, partly offset by lower interest and cash taxes. Part of the reduction in EBITDA was due to adjustments to provisions, mostly relating to a prior year. The added provision is non-cash and has no impact to our comparable FFO in 2015. Comparable FFO was also positively impacted by the settlement of foreign exchange contracts relating to debt maturities in 2015.

For the year ended Dec. 31, 2014, comparable FFO increased $33 million to $762 million compared to 2013. The increase in FFO outpaced the increase in comparable EBITDA, as the prior year’s comparable EBITDA included $27 million of unrealized risk management gains.

Comparable FCF for the year ended Dec. 31, 2015 was $315 million, compared to $280 million in 2014. The increase in comparable FCF was mainly due to lower sustaining capital expenditures as a result of reductions in mining expenditures, deferral of major work in Centralia as a result of economic dispatching, reductions in our gas-fired capital expenditures caused by the Poplar Creek re-contracting and condition-based assessments, and higher insurance recoveries associated with the flood of 2013, partially offset by the reduction in comparable FFO as well as an increase in dividends paid on preferred shares and in distributions paid to non-controlling interests in subsidiaries.

Comparable FCF for the year ended 2014 was $280 million, down $8 million from 2013, as the increase in comparable FFO was offset by distributions paid to TransAlta Renewables’ public shareholders and improved performance at TransAlta Cogeneration L.P (“TA Cogen”).

TRANSALTA CORPORATIONM9

Key Financial Ratios

The methodologies and ratios used by rating agencies to assess our credit rating are not publicly disclosed. We have developed our own definitions of ratios and targets to help evaluate the strength of our financial position. These metrics and ratios are not defined under IFRS, and may not be comparable to those used by other entities or by rating agencies. As shown below, our key financial ratios are currently outside of our target ranges. We are focused on strengthening our financial position and flexibility and aim to meet all our target ranges by 2018.

Comparable Funds from Operations before Interest to Adjusted Interest Coverage

Year ended Dec. 31	2015	2014	2013
Comparable FFO	740	762	729
Add: Interest on debt net of capitalized interest	223	236	238
Comparable FFO before interest	963	998	967
Interest on debt	232	239	240
Add: 50 per cent of dividends paid on preferred shares	23	21	19
Adjusted interest	255	260	259
Comparable FFO before interest to adjusted interest coverage (times)	3.8	3.8	3.7

Our target for comparable FFO before interest to adjusted interest coverage is four to five times. The ratio is comparable to last year as the cost of funding the South Hedland project is included in our interest expense by adding back capitalized interest to the calculation.

Adjusted Comparable Funds from Operations to Adjusted Net Debt

Year ended Dec. 31	2015		2014		2013
Comparable FFO	740		762		729
Less: 50 per cent of dividends paid on preferred shares	(23	)	(21	)	(19	)
Adjusted comparable FFO	717		741		710
Period-end long-term debt(1)	4,495		4,056		4,347
Add: 50 per cent of issued preferred shares	471		471		391
Less: Cash and cash equivalents	(54	)	(43	)	(42	)
Fair value (asset) liability of hedging instruments on debt(2)	(190	)	(96	)	(16	)
Adjusted net debt	4,722		4,388		4,680
Adjusted comparable FFO to adjusted net debt (%)	15.2		16.9		15.2

Our target for adjusted comparable FFO to adjusted net debt is 20 to 25 per cent. The reduction in the ratio during 2015 is due to lower comparable FFO and the impacts of the strengthening of the US dollar on our US-dollar-denominated debt. Our US-dollar-denominated debt is fully hedged by US-dollar-denominated assets. Net debt includes the increase in value of financial instruments used to hedge approximately half of our US debt. The other half of our US debt is hedged with a US-dollar-denominated financial receivable contract and by our net investment in US operations. The change in value of these assets resulting from the strengthening of the US currency is not included in net debt; the year-over-year change in our US-dollar-denominated net asset amount is $201 million. As at Dec. 31, 2015, net debt is also impacted by the additionof debt resulting from the acquisition of the wind and solar facilities for $211 million. These assets were acquired in September and October and contributed limited FFO in 2015.

(1) Includes finance lease obligations and tax equity financing.

(2) Included in risk management assets and/or liabilities on the consolidated financial statements as at Dec. 31, 2015 and Dec. 31, 2014.

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Adjusted Net Debt to Comparable EBITDA

Year ended Dec. 31	2015		2014		2013
Period-end long-term debt(1)	4,495		4,056		4,347
Less: cash and cash equivalents	(54	)	(43	)	(42	)
Add: 50 per cent of issued preferred shares	471		471		391
Fair value (asset) liability of hedging instruments on debt(2)	(190	)	(96	)	(16	)
Adjusted net debt	4,722		4,388		4,680
Comparable EBITDA	945		1,036		1,023
Adjusted net debt to comparable EBITDA (times)	5.0		4.2		4.6

Our target for adjusted net debt to comparable EBITDA is 3.0 to 3.5 times. During 2015, our ratio deteriorated compared to Dec. 31, 2014, mainly as a result of lower comparable EBITDA during the period and the strengthening of the US dollar.

Sustainability Performance

Sustainability targets are strategic goals that support the long-term success of our business. Targets are set in line with business unit goals to manage key areas of concern for stakeholders and ultimately improve our environmental and social performance in these areas.

On a go-forward basis we are integrating our sustainability measures into this MD&A.

2015 Sustainability Targets
	Financial	Results	Comments
1. Maintain our investment grade rating	Continue to maintain our investment grade credit rating.	Partly achieved	TransAlta maintains investment grade ratings with stable outlooks from three rating agencies: S&P (BBB-), DBRS (BBB), and Fitch (BBB-). On Dec. 17, 2015, Moody’s reduced our rating to Ba1.
2. Increase focus on FFO and EBITDA	TransAlta Corporation targets comparable EBITDA and comparable FFO for 2015 in the range of $1,000 million to $1,040 million and $720 million to $770 million respectively.	Partly achieved	For the year ended December 31, 2015, comparable EBITDA was $945 million and comparable FFO was reported at $740 million. Comparable EBITDA includes an adjustment of provisions relating to prior year events in the amount of $59 million.
3. Customers	Grow our offering of products and services to Alberta electricity consumers as the Alberta PPAs expire to match customer power needs with TransAlta’s competitive generation.	Achieved	In 2015 we successfully launched a new product to a specific segment of our customer base that offers the customers flexibility and some price certainty without locking them in to a fixed-price, long term agreement.

(1) Includes finance lease obligations and tax equity financing.

(2) Included in risk management assets and/or liabilities on the consolidated financial statements as at Dec. 31, 2015 and Dec. 31, 2014.

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	Power Generating Portfolio	Results	Comments
4. Grow asset portfolio	Grow comparable EBITDA by $40 million to $60 million.	On track	In 2015, TransAlta purchased long-term contracted solar and wind assets expected to add approximately $20 to $25 million of incremental EBITDA in 2016 and commissioned the Fortescue River Gas Pipeline, which is expected to add approximately $10 million of EBITDA on an annualized basis. TransAlta also continues to advance the construction of the South Hedland power project, on budget and on-time. This project is expected to be commissioned in mid-2017 and add approximately $80 million of incremental annualized EBITDA.
5. Achieve top quartile performance within the industry	Continue to deliver 88-90 per cent availability.	Achieved	We achieved adjusted availability in 2015 of 89.0 per cent, compared to 90.5 per cent in 2014, and higher than our target of 88 to 90 per cent. Availability is adjusted for economic dispatching at Centralia.
	Human and Intellectual	Results	Comments
6. Minimize fleet-wide safety incidents	Strive for combined IFR(1) below 0.90 in 2015, which is a 10 per cent improvement over the 2014 target.	Achieved	IFR was 0.75, the best ever in our history.
7. Human Resources	a) Maintain a voluntary turnover percentage under 8 per cent in 2015.	Achieved	Turnover was 5 per cent in 2015.
	b) Achieve 100 per cent completion of development plans for all high-potential employees at the top three levels of the organization in 2015.	Partly achieved	88 per cent of our employees have development goals.
	c) Maintain a 100 per cent completion rate on new hire onboarding.	Partly achieved	94 per cent completion rate.
	d) The time to fill vacant position rate remains lower than 60 days for recruiting.	Achieved	54 days was the average to fill vacant positions.

(1) Injury Frequency Rate (“IFR”) is defined as the number of lost-time and medical injuries for every 200,000 hours worked.

M12  TRANSALTA CORPORATION

	Environmental	Results	Comments
8. Minimize fleet-wide environmental incidents	Keep recorded incidents (including spills and air infractions) below 18 in 2015, which is a 10 per cent improvement over the 2014 target.	Achieved	12 recorded incidents in 2015.
9. Mine reclamation	Maintain annual topsoil replacement rate at Highvale Mine of 74 acres/year.	Partly achieved	Replaced topsoil on 65 acres in 2015 due to warm conditions during winter.
10. Maximize by- product revenue opportunities	a) Recycle a minimum of two million tonnes of coal by-product materials during the period 2015 to 2017.	On track	Recycled approximately 700,000 tonnes of coal by- products (fly ash, cenosphere, bottom ash, and gypsum) in 2015.
	b) Recycle 2,000 tonnes of scrap metal materials in 2015.	Partly achieved	Recycled close to 1,000 tonnes.
11. Promoting biodiversity	Install bird and bat habitat improvements at Alberta wind facilities in 2015.	Achieved	· Ferruginous hawk nest platform was installed at Soderglen in March.
			· 16 bluebird nest boxes were  installed at Soderglen in April.
			· Bat houses were installed at the Pincher Creek and Fort Macleod yards in December.
12. Air emissions management	a) 95 per cent reduction from 2005 levels of TransAlta coal facility NOx and SO2 emissions by 2030.	On track	We are on track to achieve this target in 2030.
	b) 20 per cent reduction from 2005 levels by 2021, or the equivalent of 7,000,000 tonnes, of CO2e per year.	On track	We are on track to achieve this target in 2021.
	c) 55 per cent reduction from 2005 levels by 2030, or the equivalent of 19,700,000 tonnes, of CO2e per year.	On track	We are on track to achieve this target in 2030.
13. Water Management	a) Enter into a permanent agreement with the Government of Alberta to manage water on the Bow River to aid in potential flood mitigation in 2016.	On track	On track. The Alberta government is still modelling potential solutions and we are waiting for its information to proceed.
	b) Complete third party assurance of TransAlta water consumption and discharge in 2015.	Achieved	We completed a successful third party assurance of water consumption data and processes with Ernst&Young in 2015.
14. Environmental Management Systems (EMS)	Successfully self-audit each wind operations site against the Operations Environmental Management Plans created in 2014.	On track	All sites except for our Quebec and New Brunswick wind farms were audited. We have made good progress in this area. In 2015 a challenging economic climate forced us to implement a travel freeze, which stalled progress on our eastern Canadian sites as travel is required.

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	Local Communities	Results	Comments
15. Stakeholder Engagement	The TransAlta Stakeholder Engagement Framework (“SHEF”) implementation plan will be finalized in the first half of 2015, which will be followed by the completion of short- term SHEF actions such as internal stakeholder mapping. Full implementation of the SHEF will be completed in 2016.	Achieved	SHEF was finalized in 2015 and high level internal stakeholder mapping exercise was completed.
16. Community Involvement	Increase by 2 per cent the number of company-sponsored volunteering opportunities in 2015.	Not achieved	In 2014, employees volunteered approximately 3,400 hours; in 2015 the total was below 2,500 hours. Company restructuring in 2015 reduced the pool of potential volunteers and expectations were adjusted accordingly.
17. Aboriginal Relations	In 2015 TransAlta will increase the quantity and quality of engagement with First Nation communities by improving internal systems that will allow for feedback and tracking of engagement activities. By 2017, TransAlta is targeting to achieve gold-level designation in the Canadian Council for Aboriginal Bussiness’s Progressive Aboriginal Relations certification program.	Achieved	Created tracking forms for all engagement, which helped to ensure TransAlta meets both community and regulatory commitments.
	Comprehensive	Results	Comments
18. Reporting	Achieve year-over-year improvement in the Carbon Disclosure Project (“CDP”) by scoring a 90 or greater in 2015.	Achieved	TransAlta scored 100 in 2015 and was added to the CDP Climate Disclosure Leadership Index (representing the top 20 performing companies in Canada)
19. Supply Chain Management (SCM)	In 2015, make available sustainability clauses for optional inclusion into standard TransAlta request for proposal template and terms and conditions for supplier agreements.	Achieved	Increased focus on suppliers to meet sustainability standards

M14  TRANSALTA CORPORATION

Business Model and Competitive Forces

We are one of Canada’s largest publicly traded power generators with over 105 years of operating experience. We own, operate, and manage a highly contracted and geographically diversified portfolio of assets representing nearly 9,000 MW of gross generating capacity and use a broad range of generation fuels comprised of coal, natural gas, water, sun, and wind. Our energy marketing operations maximize margins by securing and optimizing high-value products and markets for ourselves and our customers in dynamic market conditions.

Vision and Values

Our vision is to be a leading clean energy company, utilizing our expertise, scale, and diversified fuel mix to capitalize on opportunities in our core markets and growing in areas where our competitive advantage can be employed.

Our values are grounded in accountability, integrity, sustainability, safety, and people which create a strong corporate culture and allow all of our people to work on a common ground and understanding; these values are at the heart of our success.

Strategy for Value Creation

Our goals are to deliver solid returns by developing and operating assets in our three regions and among four fuel types. By 2030, our fleet will be fully transitioned from coal to natural gas and renewables. We maximize value by contracting assets, achieving strong availability, and aiming for first-quartile costs. Our Energy Marketing group adds value to merchant assets through optimization. We develop new greenfield projects and undertake merger and acquisition activities to ensure growth of cash flows over the long term. The transition from coal to gas and renewables provides significant opportunity for growth in the future. In 2013, we launched TransAlta Renewables, our sponsored vehicle to own contracted gas and renewable assets.

Regional Competitive Environments

Demand and supply balances are the fundamental drivers of prices for electricity. Underlying economic growth is the main driver of longer-term changes in the demand for electricity, whereas system capacity, natural gas prices, GHG pricing, government subsidies, and renewable resource availability are key drivers to the supply. Growth in mining investment is key to developing our Australian business.

Renewable capacity addition has been strong for the past several years due to government incentives. New supply in the near term and intermediate term is expected to come primarily from investment in renewable energy as well as natural gas-fired generation. This expectation is driven by the low prices in the natural gas market combined with public policies that favour carbon emission reductions.

We have substantial merchant capacity in Alberta and the Pacific Northwest. In those regions, we enter into contracts and business relationships with commercial and industrial customers to sell power on a long-term basis, up to our available capacity in the markets. We further reduce the portion of production not sold in advance through short-term physical and financial contracts, and optimize production in real time against our position and market conditions.

We also compete for long-term contracted opportunities in renewable and gas power generation, including cogeneration, across Canada, the United States, and Australia. Our target customers in this area are incumbent utility providers and large industrial and mining operators.

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Alberta   Approximately 60 to 65 per cent of our capacity is located in Alberta and more than 65 per cent of it is subject to legislated Alberta PPAs, which were put in place in 2001 to facilitate the transition from regulated generation to the current energy market in the province. Alberta PPAs expire at the end of 2017 (Sundance 1 and 2) and the end of 2020 (Keephills 1 and 2, Sundance 3 to 6, Sheerness, and Hydro). Coal generation sold under Alberta PPAs retain some exposure to market prices as we pay penalties or receive payments for production below or above, respectively, targeted availability based upon a rolling 30-day average of spot prices. We can also retain proceeds from the sale of energy and ancillary services in excess of obligations on our Hydro Alberta PPAs (“hydro peaking”). We enter into financial contracts to reduce our exposure to variable power prices for the significant portion of our remaining generation.

Following the decrease in oil prices, Alberta’s annual average demand growth increased by less than one per cent in 2015 compared to 2014. Concurrently over 2014 and 2015, approximately 1,200 MW of gas generation capacity and approximately 350 MW of wind capacity were added to the market, resulting in a large decrease in power prices, impacting mostly merchant wind and hydro peaking, which are the portions of our portfolio we cannot effectively hedge.

Our current share of offer control in the province is approximately 11 per cent. After expiry of the PPAs in 2021, our share of offer control is forecast to increase to approximately 23 to 25 per cent depending on load growth in the province and excluding Sundance 7.

Alberta’s Climate Leadership Plan, recently announced by the provincial government, may alter Alberta’s competitive landscape. Currently, the marginal cost of generating power from coal is generally most competitive over alternate sources, excluding renewables and must-run cogeneration. If implemented as planned, after the carbon pricing and allowance rules enter into effect in 2018, we expect the incremental cost to coal generation could increase significantly and the production from coal plants could be dispatched after highly efficient combined-cycle gas sources, potentially resulting in lower coal production and reduced margins. Power demand growth could also decrease as a result of energy efficiency initiatives. We expect that the financial impact of the anticipated decrease in our coal production volumes and higher compliance costs could be partially offset by power price increases, as well as higher benefits from allowances generated by our renewable sources. Until 2020, the impact of carbon prices is limited due to the pass-through of compliance costs to buyers under the legislated Alberta PPAs at contracted plants.

The government is appointing a negotiator to ensure that the 14-year transition away from coal does not spike power prices, impact system reliability, or unnecessarily strand capital. We will be better able to assess the impact of legislation on the Alberta market after these negotiations are finalized in the 2016 and 2017 timeframe.

We expect that the elimination of current excess system capacity and future growth in Alberta will be primarily driven by the retirement of coal units over the next 15 years. Alberta’s Climate Leadership Plan projects the replacement of two-thirds of coal production through renewable sources and one-third through gas. We believe that our extensive portfolio of assets provides us with brownfield development opportunities in wind, solar, hydro, and gas that provides us a cost advantage over competitors for construction of new builds.

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U.S. Pacific Northwest

Our capacity in the U.S. Pacific Northwest is comprised of our 1,340 MW Centralia coal plant. Half of the plant capacity is set to retire at the end of 2020, and the other half at the end of 2025.

System capacity in the region is primarily comprised of hydro and gas generation, with some wind additions over the last few years in response to government programs favouring renewable generation. Demand growth in the region has been limited, and further constrained by emphasis on energy efficiency. Our coal plant can effectively compete against gas generation, although depressed gas prices following the expansion of shale gas production in North America has added to the downward pressure on power prices.

Our competitiveness is enhanced by our long-term contract with Puget Sound Energy for up to 380 MW over the remaining life of the facility. The contract and our hedges allow us to satisfy power requirements from the market when prices fall below our marginal costs of production.

We maintain an opportunity to redevelop Centralia as a gas plant after coal capacity retires, with permitting provided by our agreement for coal transition established with the State of Washington in 2011.

Contracted Gas and Renewables

The market for development or acquisition of gas and renewable generation facilities is highly competitive in all markets in which we operate. Our solid record as operator and developer supports our competitive position. We expect, where possible, to reduce our cost of capital and improve our competitive profile by using project financing and leveraging the lower cost of capital with TransAlta Renewables. In the United States, our substantial tax attributes further increase our competitiveness.

While depressed commodity prices have reduced sectoral growth in the oil, gas, and mining industries, the change is also creating opportunities for us as a service provider as some of our potential customers are more carefully evaluating non-core activities and driving for operational efficiencies. In renewables, we are primarily evaluating greenfield opportunities in Western Canada or acquisitions in other markets in which we have existing operations. We maintain highly qualified and experienced development teams to identify and develop these opportunities.

Some of our older gas plants are now reaching the end of their original contract life. The plants generally have a substantial cost advantage over new builds and we have been able to add value by re-contracting these plants with limited life-extending capital expenditures. We have recently extended the life of our Ottawa, Windsor, and Parkeston plants in this manner.

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TransAlta’s Capitals

The following discusses TransAlta’s main categories of capital, being Financial, Power Generating Portfolio, Human and Intellectual, and Environmental and Local Communities.

Financial Capital

Sources of Capital

Our goal over the last 18 months was to build financial flexibility by using multiple sources of funding to reposition our capital structure. Over the last few years, the rating of our unsecured debt was put under pressure by all the rating agencies1. We responded to this pressure by taking significant action starting in 2014 and through to today to reduce our indebtedness and work on strengthening our financial metrics. Since the end of 2013, senior unsecured debt has been reduced by over $800 million, including a reduction of over $500 million on our credit facility and a $300 million reduction in Canadian and US bonds. Over the next three years, we plan to continue on this path by replacing $1.2 billion of maturing recourse debt with non-recourse debt secured by certain projects.

On Dec. 17, 2015, Moody’s lowered the rating of our senior unsecured debt to Ba1 with a stable outlook. As expected, the direct financial impact of this downgrade has been limited. We have posted additional collateral of nearly $100 million to certain counterparties, and the cost of borrowing under our credit facilities and US$400 million of debt has been stepped-up in line with contractual provisions. These costs have been integrated into our 2016 financial outlook. We have investment grade ratings with stable outlooks from each of DBRS, S&P, and Fitch Ratings. We remain focused on maintaining these ratings, as strengthening our financial position allows our commercial team to contract our portfolio with a variety of counterparties on terms and prices that are favourable to our financial results, and provides us with better access to capital markets through commodity and credit cycles. Risks associated with further reductions in our credit ratings are discussed in the Liquidity Risk section of this MD&A.

(1) As at Dec. 31, 2015, our senior unsecured debt is rated as investment grade by three rating agencies: BBB (stable), BBB- (stable), and BBB- (stable) by DBRS, Standard and Poor’s (“S&P”), and Fitch Ratings (“Fitch”), respectively, and Ba1 (stable) by Moody’s Investors Services (“Moody’s”). Our preferred shares are rated P-3 and Pfd-3 by S&P and DBRS, respectively. Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities. The credit ratings accorded to our outstanding securities by DBRS, S&P, Moody’s, and Fitch, as applicable, are not recommendations to purchase, hold, or sell such securities inasmuch as such ratings do not comment as to market price or suitability for a particular investor. There is no assurance that the ratings will remain in effect for any given period or that a rating will not be revised or withdrawn entirely by DBRS, S&P, Moody’s, or Fitch in the future if, in its judgment, circumstances so warrant. See the Liquidity Risk section of this MD&A.

M18  TRANSALTA CORPORATION

Capital Structure

Our capital structure consisted of the following components as shown below:

	2015		2014		2013
As at Dec. 31	$	%	$	%	$	%
Net debt
Recourse debt - CAD debentures	1,044	12	1,043	13	1,269	17
Recourse debt - U.S. senior notes	2,221	26	2,444	31	1,797	23
Net credit facilities and other(1)	138	2	(24)	-	822	11
Total recourse debt	3,403	40	3,463	44	3,888	51
Non-recourse debt	766	9	380	5	376	5
Finance lease obligations	82	1	74	1	25	-
Total net debt	4,251	50	3,917	50	4,289	56
Non-controlling interests	1,029	12	594	8	517	6
Equity attributable to shareholders
Common shares	3,075	35	2,999	38	2,913	38
Preferred shares	942	11	942	12	781	10
Contributed surplus, deficit, and Accumulated Other Comprehensive Loss	(656)	(8)	(657)	(8)	(788)	(10)
Total capital	8,641	100	7,795	100	7,712	100

During 2014 and 2015, we have reduced our corporate senior debt and the amount drawn on our credit facility, primarily through the sale of non-controlling interests, issuance of project-level debt, divestiture of our equity investments, and the issuance of preferred shares. The strengthening US dollar added approximately $325 million to our recourse debt over the two-year period, net of the gain in fair value assets of the derivative hedging instruments on debt. Part of our US-dollar-denominated debt is also hedged using a US-dollar-denominated financial receivable contract and by our net investment in U.S. operations. During 2015, we also added $211 million of debt as part of the acquisition of the two renewable projects in the U.S.

The following graph shows the evolution of recourse debt, including credit facilities and tax equity obligations, versus non-recourse debt, including finance lease obligations, as well as the cumulative effect of foreign exchange:

(1) Includes cash, tax equity financing, and fair value assets of hedging instruments on debt.

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Over the last two years, the changes in our US-dollar-denominated debt were offset as follows:

For the year ended Dec. 31	2015	2014
Effects of foreign exchange on carrying amounts of U.S. operations (net investment hedge) and finance lease receivable	201	84
Foreign currency cash flow hedges on debt	183	79
Economic hedges and other	8	11
Total	392	174

On Jan. 15, 2015, our US$500 million 4.75 per cent senior notes matured. On Sept. 1, 2015, $120 million in 5.33 per cent non-recourse debentures matured. These amounts and were paid out using existing liquidity.

On Oct. 1, 2015, a subsidiary of TransAlta Renewables closed a $442 million bond offering, which is secured by a first-ranking charge over the subsidiary’s wind farms. The bonds are non-recourse to TransAlta, amortizing, and bear interest at a rate of 3.8 per cent, payable semi-annually and mature on Dec. 31, 2028. Net proceeds of the financing were used to reduce our balance on the credit facility. On Feb 11, 2015, we also refinanced our $35 million 5.28 per cent Pingston non-recourse debt with a $45 million 2.95 per cent non-recourse bond due in full in 2023. We also added $105 million of non-recourse debt relating to the acquisitions of two renewable facilities in the U.S.

The following graph shows our debt maturity schedule as at Dec. 31, 2015, excluding credit facilities, finance lease obligations, and other debt.

  Over the next three years, we have approximately $1.6 billion of recourse and non-recourse debt maturing. We will refinance some of these upcoming debt maturities by raising debt secured by some of our contracted assets in Canada and the U.S. We are also expecting to continue our de-leveraging strategy and most of our free cash flow over the next three years, after funding of the South Hedland project, will be allocated to debt reduction.

Our credit facilities provide us with significant liquidity. At Dec. 31, 2015, we had a total of $2.2 billion (2014 - $2.1 billion) of committed credit facilities, of which $1.3 billion (2014 - $1.6 billion) was not drawn. We are in compliance with the terms of the credit facility and all undrawn amounts are fully available.  At Dec. 31, 2015, the $0.9 billion (2014 - $0.5 billion) of credit utilized under these facilities was comprised of actual drawings of $0.3 billion (2014 - $0.1 billion) and letters of credit of $0.6 billion (2014 - $0.4 billion). These facilities are comprised of a $1.5 billion committed syndicated bank facility expiring in 2019, and four bilateral credit facilities expiring in 2017. We anticipate renewing these facilities, based on reasonable commercial terms, prior to their maturities.

M20  TRANSALTA CORPORATION

Working Capital

Including the current portion of long-term debt, the excess of current assets over current liabilities was $311 million as at Dec. 31, 2015 (2014 - $472 million - excess of current liabilities over current assets). The primary change relates to the timing of the classification of long-term debt as current. Excluding the current portion of long-term debt, the excess of current assets over current liabilities as at Dec. 31, 2015, was $383 million (2014 - $266 million). The increase is primarily due to the assumption of a new finance lease receivable resulting from the Poplar Creek restructuring ($48 million), and timing of payments and accruals.

Share Capital

On Feb. 17, 2016, we had 287.9 million common shares outstanding, and 12.0 million Series A, 11.0 million Series C, 9.0 million Series E, and 6.6 million Series G preferred shares outstanding. Preferred shares support our financial position as only half of their balance is generally considered as debt by credit rating agencies.

The following tables outline the common and preferred shares issued and outstanding:

As at Dec. 31	2015	2014
	Number of shares (millions)	Number of shares (millions)
Common shares issued and outstanding, end of year	284.0	275.0
Preferred shares
Series A	12.0	12.0
Series C	11.0	11.0
Series E	9.0	9.0
Series G	6.6	6.6
Preferred shares issued and outstanding, end of year	38.6	38.6

Non-Controlling Interests

As of Dec. 31, 2015, we own 66.6 per cent (2014 - 70.3 per cent) of TransAlta Renewables. TransAlta Renewables is a publicly traded company listed on the Toronto Stock Exchange under the symbol “RNW”. We also own 50.01 per cent of TA Cogen, which owns, operates, or has an interest in four natural gas-fired facilities and one coal-fired generating facility. Since we own a controlling interest in TA Cogen and TransAlta Renewables we consolidate the entire earnings, assets, and liabilities in relation to those assets.

TransAlta Renewables has been the cornerstone of our funding strategy over the last three years, starting with its formation with some of TransAlta’s wind and hydro assets in mid-2013. TransAlta Renewables forms a diversified, highly contracted portfolio of assets with comparatively lower carbon intensity. The stable and predictable cash flows generated by these assets has attracted favourable equity valuations from investors, allowing TransAlta to raise equity capital.

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In November 2015, we sold 20.5 million common shares of TransAlta Renewables in a private placement to AIMCo for net cash consideration of $193 million. During 2015, we initiated two transactions with TransAlta Renewables with concurrent public equity offerings by TransAlta Renewables:

■       On May 7, 2015, we completed the sale of an economic interest in our Australian assets to TransAlta Renewables. The Australian assets consist of six operating assets with an installed capacity of 425 MW, the 150 MW South Hedland project currently under construction, as well as the recently commissioned 270 kilometre gas pipeline, for total consideration of $1.78 billion. At the closing of the Transaction, TransAlta Renewables paid the Corporation $217 million in cash as well as approximately $1,067 million through a combination of common shares and Class B shares in TransAlta Renewables. TransAlta Renewables has also committed to funding the costs to construct the South Hedland project incurred after Jan. 1, 2015, representing an estimated amount of $491 million. TransAlta Renewables funded the cash proceeds through the public issuance of 17,858,423 common shares at a price of $12.65 per share.

■       On Jan. 6, 2016, we completed the sale of an economic interest of the 506 MW Sarnia cogeneration facility and of two renewable energy facilities with total capacity of 105 MW for $540 million. Consideration received from TransAlta Renewables consisted of gross proceeds from a public offering of 17,692,750 common shares at $9.75 per share for gross proceeds of $173 million, 15.6 million common shares of TransAlta Renewables with a value of $152 million, and a $215 million unsecured subordinated debenture convertible into common shares of TransAlta Renewables at a price of $13.16 per common share upon maturity on Dec 31, 2020. After completing this transaction, we own 64 per cent of TransAlta Renewables.

We remain committed to maintaining our position as the majority shareholder and sponsor of TransAlta Renewables with a stated goal of maintaining our interest between 60 to 80 per cent.

Returns to Providers of Capital

Net Interest Expense

The components of net interest expense are shown below:

Year ended Dec. 31	2015	2014	2013
Interest on debt	228	238	240
Capitalized interest	(9)	(3)	(2)
Interest on finance lease obligations	4	1	-
Other	7	-	-
Accretion of provisions	21	18	18
Net interest expense	251	254	256

For the year ended Dec. 31, 2015, net interest expense decreased compared to 2014, primarily due to the reduction in debt during the year and lower interest rates on debt that was refinanced, coupled with higher capitalized interest. Higher interest expense on foreign-denominated debt due to strengthening of the US dollar and other interest expense associated with the adjustment to provisions have partially offset these decreases.

In 2014, net interest expense decreased compared to 2013, primarily due to the approximate $500 million reduction in debt during the year and lower interest rates on debt that was refinanced. Higher interest expense due to strengthening of the US dollar had partially offset these decreases.

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Dividends to Shareholders

During the year ended Dec. 31, 2015, 9.0 million (2014 - 6.8 million) common shares were issued to shareholders that elected dividend reinvestment, for a total of $76 million (2014 - $85 million).

On Jan. 14, 2016, we announced the resizing of our common share dividend from $0.72 annually to $0.16 annually and the suspension of the Premium DividendTM, Dividend Reinvestment and Optional Common Share Purchase Plan effective immediately. These actions were taken as part of a plan to maximize our long-term financial flexibility. Declaration of dividends is at the discretion of the board of directors of TransAlta (the “Board”).

On Feb. 16, 2016, we declared a quarterly dividend of $0.04 per share on common shares, payable on April 1, 2016 and a quarterly dividend of $0.2875 per share on the Series A and Series C preferred shares, $0.3125 per share on the Series E preferred shares, and $0.33125 per share on the Series G preferred shares, all payable on March 31, 2016.

Non-Controlling Interests

Comparable earnings attributable to non-controlling interests for the year ended Dec. 31, 2015 increased $31 million to $80 million compared to 2014, primarily due to the additional common shares issued to the public in relation to the Australia portfolio dropdown in addition to higher earnings of TransAlta Renewables on a larger asset base.

In 2014, comparable earnings attributable to non-controlling interests increased $20 million compared to 2013, primarily due to the formation of TransAlta Renewables and increased public ownership.

Collectively, the two transactions effected in 2015 and early 2016 have allowed TransAlta Renewables to increase its dividend by approximately 14 per cent over 2015, with a further six to seven percent increase expected upon commissioning of the South Hedland project. This corresponds to an average annual increase of approximately six per cent between the 2013 Initial Public Offering to mid-2017. Through our majority ownership of TransAlta Renewables, we are the primary beneficiary of these increases.

Ability to Deliver Financial Results

The metrics we are using to track our performance are comparable EBITDA, comparable FFO and comparable FCF. The following table compares target to actual amounts for each of the three past fiscal years:

Year ended Dec. 31		2015	2014	2013
Comparable EBITDA	Target	1,000 to 1,040	1,015 to 1,065	Not applicable
	Actual	945	1,036	1,023
Comparable FFO	Target	720 to 770	743 to 793	800 to 900
	Actual	740	762	729
Comparable FCF(1)	Target	265 to 270	274 to 324	Not applicable
	Actual	315	280	288

The adjustment to the provision recognized at Dec. 31, 2015, mostly related to prior year events, caused the departure from the guidance. Before this adjustment was made, comparable EBITDA in 2015 was trending to the low end of the range, as a result of much lower prices in Alberta and the Pacific Northwest impacting our merchant generation. Our commodity risk management strategy is designed to protect us from short-term price variations. However, it is challenging to efficiently hedge our Alberta wind portfolio. Although our hydro portfolio is substantially all contracted, the Alberta hydro PPA allows us to benefit from price volatility in a low price and volatile price environment; however, we were not able to capture the value of this flexibility.

(1) 2014 and 2013 restated to deduct hydro life extension capital expenditures from comparable FCF. Refer to the Current Accounting Changes section of this MD&A. Target range boundaries for 2014 have been adjusted by an amount equal to the change in reported amount.

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Power Generating Portfolio

Our power generating portfolio is comprised of our fleet of power generating and related assets as well as our finance leases. We monitor availability closely as a key metric to delivering the required production to meet our contractual obligations and achieve financial targets. Over the short term and medium term, we adjust our maintenance and sustaining capital expenditures to optimize financial returns on our investments. We benchmark our performance against peers with the objective to rank within the first quartile. Over the long term, we adjust our growth capital expenditures to align with our strategic orientations.

Availability and Production Our adjusted availability target was 89 to 91 per cent for 2015.   Our availability in 2015, after adjusting for economic dispatching at U.S. Coal, was 89.0 per cent (2014 - 90.5 per cent; 2013 - 87.8 per cent). Lower availability for the year ended Dec. 31, 2015 compared to last year was due to higher unplanned outages and derates at Canadian Coal. On March 17, 2015, an unplanned outage began at our 395 MW Keephills Unit 1 facility due to a damaged superheater. The unit returned to service on May 17, 2015.

Following the establishment of the plan to return the unit to service and the review of the causes of the outage, we gave notice under the PPA to the PPA buyer and the Balancing Pool of a “High Impact Low Probability” force majeure event. In the event of a force majeure event, we are entitled to continue to receive our PPA capacity payment and are exempted, under the terms of the PPA, from having to pay availability penalties. We expect the counterparty to the PPA to disagree with our determination that the event qualifies as a force majeure and we recorded a provision to reflect a potential outcome. The costs incurred as a result of the event was mostly covered by insurance. Consequently, the outage did not have a material financial impact on our results in 2015.

Production for the year ended Dec. 31, 2015 decreased 4,329 gigawatt hours (“GWh”) compared to 2014, primarily due to lower availability at our Canadian Coal plants, and increased periods of lower prices in the Pacific Northwest where it was more economical to supply our contractual obligation by buying power in the market. Additionally, the Poplar Creek restructuring deal resulted in lower production, as the facility is now outside our operational scope.

Production for the year ended Dec. 31, 2014 increased 2,520 GWh compared to 2013, primarily due to a full year of contribution from Sundance Units 1 and 2, which returned to service in the second half of 2013, as well as the return to service of Keephills Unit 1, which was unavailable for seven months in 2013.

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Operational

We continuously drive for the cost-effective operation of our facilities. In 2015, we announced the elimination of positions to reduce our costs. This company-wide initiative is expected to result in annual cost savings in excess of $47 million annually.

In the generation segments, our operations, maintenance, and administration (“OM&A”) costs reflect the cost of operating our facilities. These costs can fluctuate due to the timing and nature of planned and unplanned maintenance activities. The remainder of OM&A costs reflects the cost of day-to-day operations. The following table outlines our generation comparable OM&A over the last three years:

	2015	2014	2013
Generation comparable OM&A	418	433	417

Our goal is to reduce our OM&A through cost control and targeted productivity initiatives. We have established long-term service agreements with third-party suppliers to reduce these costs, as well as maintenance-related sustaining capital costs. We regularly benchmark our performance against peers to measure our progress. OM&A costs decreased in 2015 due to changes in operational scope in the Gas segment, with the benefits of the cost-saving initiatives beginning to be realized. During 2013, OM&A costs were lower due to Sundance Units 1 and 2 returning to service late in the year.

In Canadian Coal, costs associated with our Highvale mine form part of our cost of fuel. In addition to the impact of the reduction in the number of positions, we have driven reductions in coal costs through improved mine design sequence, reduced equipment requirements, and optimized contractor usage. Since insourcing the activity in 2013, coal costs per tonne have decreased by 15 per cent, from approximately $27 to $23.

Sustaining Capital

We are in a long-cycle, capital-intensive business that requires significant capital expenditures. Our goal is to undertake sustaining capital that ensures our facilities operate reliably and safely over a long period of time. Sustaining capital also includes capital required following the 2013 flood in Alberta, most of which is recoverable from third parties.

Year ended Dec. 31	2015	2014	2013
		Restated (1)	Restated (1)
Routine capital	101	135	133
Mine capital	25	45	53
Planned major maintenance	162	162	153
Finance leases	13	10	9
	301	352	348
Flood-recovery capital	4	9	1
Total sustaining capital expenditures	305	361	349
Insurance recoveries of sustaining capital expenditures	(25)	(4)	(1)
Net amount	280	357	348

Lost production as a result of planned major maintenance is as follows:

Year ended Dec. 31	2015	2014	2013
GWh lost(2)	1,409	1,519	1,154

(1) Restated to include hydro life extension from growth capital expenditures to sustaining capital expenditures. Refer to the Current Accounting Changes section of this MD&A.

(2) Lost production excludes periods of planned major maintenance at U.S. Coal, which occur during periods of economic dispatching.

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In 2015, routine capital decreased due to the transfer of our Poplar creek facility and condition-based assessments at our Ontario gas-fired generating stations. Routine capital also included additional expenditures on capital spares and the Keephills ash solutions project in 2014. The mine capital expenditure was lower in 2015 as 2014 included significant expenditure on development activities of a new mining area. Finance lease costs increased primarily due to the strengthening of the US dollar in 2015. Planned major maintenance costs remained stable in 2015 compared to 2014 as scope changes offset the improvement in efficiency of our major turnaround costs in Canadian Coal. On Nov. 14, 2014, we entered into an agreement with Alstom to provide major maintenance for our Canadian Coal facilities. The agreement relates to 10 major maintenance projects over the subsequent three years at our Keephills and Sundance plants. It also expands Alstom’s current scope of work to service critical power assets, including boilers, steam turbines, generators, and other plant equipment. Alstom will be accountable for providing its services on budget and on time with a guarantee on performance. Excluding the effects of scope changes to our Sundance 3 outage this year, the new arrangement is on track to deliver an average 15 per cent cost reduction per turnaround and shorter turnaround times for major maintenance work, resulting in estimated direct cost savings of $34 million over the full term of the agreement. Other planned major outages in 2015 included Sundance 5, Keephills 3, and one outage at Sheerness.

The decrease in mine capital in 2014 compared to 2013 was primarily due to fewer mine support equipment purchases as mining intensity stabilized. Planned major maintenance costs in 2014 included five planned outages at Sundance Unit 5, Sundance Unit 6, Keephills Unit 2, U.S. Coal, and Genesee Unit 3 in 2014 compared to four in 2013 at Sundance 4, Keephills 3, U.S. Coal, and Sheerness.

Growth

We have set out to grow comparable EBITDA by $40 to $60 million annually. Our target investments are focused on highly contracted gas and renewable power generation.

During 2015 we have acquired the following renewable generation facilities:

■       On July 26, 2015, we agreed to acquire 71 MW of fully contracted renewable generation assets for cash consideration of US$76 million together with the assumption of certain tax equity obligations and US$42 million of non-recourse debt. The assets acquired include 21 MW of solar projects located in Massachusetts and the 50 MW Lakeswind wind project located in Minnesota. The assets are contracted under long-term power purchase agreements ranging from 20 to 30 years. The purchase of the solar projects in Massachusetts closed on Sept. 1, 2015 and the purchase of the Lakeswind wind project in Minnesota was completed on Oct. 1, 2015.

■       As part of the arrangement to restructure our Poplar Creek contract, on Sept. 1, 2015, we acquired the 20 MW Kent Breeze wind facility located in Ontario and a 51 per cent interest in the 88 MW Wintering Hills wind facility located in Alberta. The Kent Breeze facility has a 20-year contract with the Ontario IESO.

These assets further supplement our pipeline of potential assets for dropdown into TransAlta Renewables, as part of our financing strategy.

Previously announced growth projects have progressed in line with expectations:

■       On March 19, 2015, we completed the Fortescue River Gas Pipeline in Western Australia. The project, our first pipeline, was completed within a nine-month timeframe and for an estimated total cost of AUD$183 million. We hold a 43 per cent interest in the pipeline. The pipeline delivers gas to our Solomon power station, which services Fortescue Metals Group’s mining operations at the Solomon Hub.

■       Construction of the 150 MW gas-fired South Hedland project commenced in January 2015. The civil construction phase is progressing with all major foundation footings complete, with the exception of the steam turbine. Manufacturing and factory acceptance testing of primary electrical equipment was completed. Major equipment was received on site. Installation and testing of the main underground fuel gas pipeline was completed. Integration of the existing balance-of-plant control systems within the overall station control system and associated plant operation, monitoring, and communication requirements is progressing well.

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These initiatives will add approximately $35 million in EBITDA in 2016 and an additional $80 million annually when the South Hedland project will be in service during the second quarter of 2017.

Our target investments are focused on highly contracted gas and renewable power generation:

■       contracted assets support our financial position, as we transition to having increased merchant capacity in Alberta in the next decade; and

■       gas and renewable generation is our core orientation towards reducing our impact on the environment and utilizes our expertise in wind, hydro, and gas.

All investments are subject to due diligence procedures and ultimately reviewed by our investment committee (refer to the Governance and Risk Management section of this MD&A).

During 2015, we received approval from the AUC to construct and operate an 856 MW combined-cycle natural gas-fired power plant in Alberta. The Sundance 7 project has received all regulatory approvals after receiving the Environmental Protection and Enhancement Act approval from Alberta Environment and Parks on Oct. 1, 2015. Construction of Sundance 7 will not commence until we have contracted a significant portion of the plant capacity. Following changes to market conditions in Alberta during the past year, we do not anticipate that this condition will be met before the next decade. In December 2015, we repurchased our partner’s 50 per cent share in TAMA Power, the jointly controlled entity developing this project, for consideration of $10 million payable in five years, along with an option to buy back into this project or into other projects of TAMA Power during this period.

Contractual Profile

Approximately 65 per cent of our capacity is sold under long-term contract. Excluding Alberta PPAs for our coal and hydro facilities, the majority of these contracts have maturities in excess of 10 years. Amongst these groups of facilities, significant new contracts have been extended in respect of the Poplar Creek, Windsor, and Parkeston facilities, the details of which are provided below.

With most of our coal and hydro facilities in Alberta rolling off the Alberta PPA in 2021, our focus has been to develop a portfolio of commercial and industrial customers to sell our generation in the province post PPA. We are now serving a portfolio of 600 MW.

Poplar Creek

On Sept. 1, 2015, we closed the restructuring of our contractual arrangement for power generation services with Suncor Energy (“Suncor”) at Suncor’s oil sands base site near Fort McMurray and the acquisition of Suncor’s interest in two wind projects located in Alberta and Ontario.

The Poplar Creek cogeneration facility, which has a maximum capability of 376 MW, had been built and contracted to provide steam and electricity to Suncor until 2023. Under the terms of the new arrangement, Suncor acquired from TransAlta two steam turbines with an installed capacity of 132 MW and certain transmission interconnection assets. In addition, Suncor assumed full operational control of the cogeneration facility, including responsibility for all capital costs, and the right to use the full 244 MW capacity of TransAlta’s gas generators until Dec. 31, 2030. We will provide Suncor with centralized monitoring, diagnostics, and technical support to maximize performance and reliability of plant equipment. Ownership of the entire Poplar Creek cogeneration facility will transfer to Suncor in 2030.

As part of the arrangement, we acquired Suncor’s 20 MW Kent Breeze wind facility located in Ontario and Suncor’s 51 per cent interest in the 88 MW Wintering Hills wind facility located in Alberta. The Kent Breeze facility has a 20-year contract with the Ontario IESO.

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The transaction creates value by increasing the duration of the contract to 2030 from the prior 2023 expiry, reduces our exposure to Alberta’s merchant power market, and adds two high quality wind facilities representing 65 MW of capacity. The addition of a fully contracted gas generating asset and two wind farms supplements our pipeline of assets that we could sell to TransAlta Renewables in the future. As a result of the transaction, we recognized a finance lease of $372 million and increased our long-term assets to reflect the acquisition of two wind farms for $138 million. The transaction closed on Sept. 1, 2015 and we have recognized a gain of $262 million on the transaction. The carrying amount of net assets we transferred to the counterparty in the transaction was $250 million.

Windsor

During the first quarter of 2015, we executed a new 15-year power supply contract with Ontario’s IESO for our Windsor facility, which will be effective Dec. 1, 2016. The contract is similar to the contract signed in 2013 for our Ottawa facility. Under the new contract, the plant will become dispatchable for up to 72 MW of capacity. The new contract provides long-term stable earnings for this facility.

Parkeston

During the last quarter of 2015, we executed an extension to our power purchase agreement to supply power to the Kalgoorlie Consolidated Gold Mine from our 55 MW Parkeston power station. The agreement extends the previous contract to October 2026 with options for early termination available to either party beginning in 2021. The risks associated with the extended agreement remain consistent with the original contract. The contract extension will continue to provide stable cash flow for the business.

Over the last three years, we have nearly doubled the weighted average remaining contractual life of our gas fleet from six years to 12 years.

Human and Intellectual Capital

As at Dec. 31, 2015, we had 2,380 active employees. This number has decreased by 17 per cent since the previous year, following various restructuring initiatives to reduce costs and increase efficiency. A number of unfilled positions have also been eliminated.

With approximately 54 per cent of our employees being unionized, we strive to maintain open and positive relationships with union representatives and regularly meet to exchange information, listen to concerns, and share ideas that further our mutual objectives. Collective bargaining is conducted in good faith, and we respect the rights of all employees to participate in collective bargaining.

Safety

Safety is our top priority with all of our staff, contractors, and visitors. Injury Frequency Rate (“IFR”) is defined as the number of lost-time and medical injuries for every 200,000 hours worked. Our ultimate goal is to achieve zero injury incidents. We achieved our best results ever for safety performance in 2015, exceeding our IFR target of 0.90. We have experienced no fatalities during the last three years.

Year ended Dec. 31	2015	2014	2013
IFR	0.75	0.86	0.93

During 2015, we designed a new total safety management policy as a two-pronged approach. The policy builds upon our  occupational safety program, Target Zero, which is focused on protecting our workers on site, through means of personal protection equipment, inspections, safety controls, job safety analyses, field-level hazard assessments, and safety communications. The policy is supplemented by our newly launched operational integrity program, which is focused on keeping all hazards inside our equipment, through definition and measurement of safety-critical performance measures and operating limits.

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Employee Benefits

We provide compensation to our employees at levels that are competitive in relation to their respective location. We strive to be an employer of choice through our total rewards program, which include various incentive plans designed to align performance with our annual and mid-term targets, as determined annually by the Board.

Also included in compensation are various future benefit plans. We have registered pension plans in Canada and the U.S. covering substantially all employees of the Corporation, its domestic subsidiaries, and specific named employees working internationally. These plans have defined benefit and defined contribution options, and in Canada there is an additional supplemental defined benefit plan for members whose annual earnings exceed the Canadian income tax limit. Except for the Highvale pension plans acquired in 2013, the Canadian and U.S. defined benefit pension plans are closed to new entrants. The U.S. defined benefit pension plan was frozen effective Dec. 31, 2010, resulting in no future benefits being earned. The defined benefit plans are funded by the Corporation in accordance with governing regulations. We provide other health and dental benefits for disabled members and retired members, typically up to the age of 65. The supplemental pension plan is an obligation of the Corporation. We are not obligated to fund the supplemental plan but are obligated to pay benefits under the terms of the plan as they come due. We have posted a letter of credit in the amount of $65 million to secure the obligations under the supplemental plan.

Organizational Culture and Structure

During 2015 we initiated the Powering Performance organizational design program, with the primary objective of accelerating decision-making within our organization. The program has had us transition more fully to a decentralized, business-centric model, with Coal & Mining, Gas & Renewables, Australia, and Energy Marketing defined as our four primary businesses. As part of the design work, we have transferred accountability for shared services to the businesses and removed a layer of management. As part of this process, employees also have clearer accountabilities and authority. We are currently focused on training employees to adapt to these changes.

Fleet Management

TransAlta has maintained its Operations Diagnostic Centre (ODC) since 2008. The ODC monitors coal-fired, gas-fired and wind-generating assets across Canada, the United States, and Australia. A centralized team of engineers and operations specialists remotely monitors our power plants for emerging equipment reliability and performance issues. ODC staff are trained in the development and use of specialized equipment monitoring software and can apply their experience in power plant operations. If an equipment issue is detected, the ODC notifies plant operations to investigate and remedy the issue before there is an impact to operations. The monitoring, analysis, and diagnostics completed by the ODC are focused on early identification of equipment issues based on longer-term trend analysis and complements day-to-day plant operations.

Our energy trading and marketing operations optimize the financial returns of our facilities in real time. The group purchases fuels to feed plants, bids into energy markets the electricity we generate at our facilities, and mitigates the associated risks associated with those purchases and sales. In addition, they buy, sell, schedule, and negotiate all of the electricity transmission for each facility. They do so while applying an overlay of complex, real-time information — about weather, facility capacity, transmission congestion, and market pricing. Quantitative analysis, forecasting, mathematical models, and forward curves are key tools used to execute this responsibility. In addition, the application of these skills for proprietary trading allows us to generate margins ranging from approximately $60 million to $80 million annually and EBITDA of $40 million to $60 million annually. Effective Jan. 1, 2016, a new Energy Trading and Risk Management System (“ETRMS”) became operational, to further support optimization and trading capabilities, allowing for streamlined data flows, state-of-the-art linkages, and enhanced scalability for key optimization tools. The ETRMS had no impact on our internal control over financial reporting at Dec. 31, 2015. As a result of the implementation of the ETRMS, certain processes supporting our internal control over financial reporting are expected to change in 2016. Management will continue to monitor these processes going forward.

We seek to optimize cost and reliability of our assets and maintain or increase their capacity. Our decentralized organization allows the sharing and deployment of technology-specific innovative practices within the respective businesses. A key resolution achieved during 2015 was the confirmation by the Alberta Electric System Operator that Sundance Units 3 to 6 comply with reactive power standards. Additionally, we set aside annually $10 million to $15 million to invest in productivity projects and further the innovation from our employees. Productivity projects are evaluated against criteria that include a two- to three- year financial payback. During 2015, we completed some boiler erosion mitigation projects on Sundance 5. These improvements to the shielding and support attachments in the boiler are designed to reduce boiler tube leaks and reliability.

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During 2015, we set the foundation for our operational integrity program. The program is designed to achieve process and equipment safety through understanding and monitoring of key risks and implementation of mitigation measures. In 2015, we completed our risk assessment at all facilities except Australia and Mining. We have also developed operator checks, maintenance tasks, and proof tests for various safety critical elements at coal plants. Key performance indicators have been identified and are being integrated in a dashboard for ongoing monitoring. During 2016, we plan to finalize developing the balance of safety-critical maintenance strategies and related engineering standards. We have observed positive increases in self-reporting and addressing process safety hazards as awareness and new tools are being introduced.

New or Emerging Technologies

We seek to maintain TransAlta in pace with power technologies that have the potential to re-define power markets today and in the future. In certain markets, renewables penetration is rapidly changing the economic position of incumbent generators. As demonstrated by our investments in wind in the past decade, we are intent on adapting our business model to these changing realities. During 2015, we made our first investment in solar technology with the purchase of the Massachusetts solar facilities. We are also beginning to experiment with battery storage technology.

Environmental and Local Communities Capital

All energy sources used to generate electricity have some impact on the environment. While we are pursuing a business strategy that includes investing in low-impact renewable energy resources such as wind, hydro, and solar, we also believe that coal and natural gas will continue to play an important role in meeting energy needs as part of this transition. Regardless of the fuel type, we place significant importance on environmental compliance and continued environmental impact mitigation, while seeking to deliver low-cost electricity.

In the jurisdictions in which we operate, legislators have proposed and enacted regulations to discontinue over time the use of the technologies that our coal-fuelled plants currently utilize. Our gas and coal facilities can also incur costs in relation to their carbon emissions, depending on the jurisdiction in which the facility is located. Our contracted facilities can generally recover those costs from the customer. Conversely, our renewable generation facilities are generally able to realize value from their environmental attributes. We continue to closely monitor the progress and risks associated with environmental legislation changes on our future operations.

Reducing the environmental impact of our activities has a benefit not only to our operations and financial results, but also to the communities in which we operate. We expect that increased scrutiny will be placed on environmental emissions and compliance, and we therefore have a proactive approach to minimizing risks to our results. Our Board provides oversight to our environmental management programs and emission reduction initiatives to ensure continued compliance with environmental regulations. Our environmental initiatives include:

■       Renewable power growth and offsets portfolio: Over the last three years, we have added approximately 350 MW in renewable energy capacity. Of these additions, 45 MW of capacity generates offsets that can be used against GHG emissions in Alberta.

■       Environmental controls and efficiency: We continue to make operational improvements and investments to our existing generating facilities to reduce the environmental impact of generating electricity. We installed mercury control equipment at our Canadian Coal operations in 2010 in order to meet Alberta’s 70 per cent reduction objectives, and voluntarily at our U.S. coal-fired plant in 2012. Our Keephills 3 and Genesee 3 plants use supercritical combustion technology to maximize thermal efficiency, as well as sulphur dioxide (“SO2”) capture and low oxides of nitrogen (“NOx”) combustion technology. Uprate projects completed at our Keephills and Sundance plants, including a 15 MW uprate finalized in 2015 at Sundance 3, have improved the energy and emissions efficiency of those units.

■       Planning: With respect to announced environmental rules that have not yet entered into effect, such as Clean Air Strategic Alliance (“CASA”) rules in Alberta (as detailed in the following Regional Regulation and Compliance sub-section), we investigate the cost effectiveness of multiple technological solutions and various operating models in order to prepare appropriate work scopes.

■       Policy participation: We are active in policy discussions at a variety of levels of government and with industry participants. Where capacity retirements are being mandated, we advocate minimizing the capital requirements of incremental regulation, to allow reinvestment in lower-intensity sources during the transition phase. In Washington State, the retirement of our Centralia coal plant was established through a multi-stakeholder agreement.

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In addition to these initiatives, we maintain similar procedures for environmental incidents as we do for safety, with tracking, analyzing, and active management to eliminate occurrence, and ongoing support from our operational integrity program. With respect to biodiversity management, we seek to establish robust environmental research and data collection to establish scientifically sound baselines of the natural environment around our facilities and closely monitor the air, land, and water in these areas to identify and curtail potential impacts.

Environmental Performance

All of our 69 facilities have Environmental Management Systems (“EMS”) in place. As at Dec. 31, 2015, 67 of the facilities that we own and our mines have EMS based on the globally recognized ISO 14001 EMS Standard.

We recorded 12 environmental incidents in 2015 (2014 - 15 incidents), which is lower than our target of 18 (2014 - 20). One of these incidents led to an environmental enforcement action, for which fines were nominal.

Similarly, the volume of spills has been limited, with 19 m3 spilled, of which 99 per cent was recovered (2014 - 463 m3, 96 per cent recovered). This year marked a record year for the low volume of spills and is a testament to our increased focus and scrutiny placed on reporting all spills in order to understand their causes and take action to mitigate further incidents.

Air Emissions

In 2015, we estimate that 32.2 million tonnes of GHGs with an intensity of 0.87 tonnes per MWh (2014 - 35.1 million tonnes of GHGs with an intensity of 0.89 tonnes per MWh) were emitted as a result of normal operating activities(1). Our GHG emissions decreased in 2015, primarily as a result of lower production from coal plants. Variations in other air emissions (NOx, SO2, particulate matter, and mercury) trended similarly to GHG emissions.

Other decreases in emissions of the Gas segment are attributable to the transfer of operational control of the Poplar Creek facility to our customer in September 2015, conversion of the Ottawa plant to a peaking facility in 2013, and conversion of the Solomon plant in Australia to burn natural gas instead of diesel. Our continued investment in growth from renewable power generation further supports the decrease in emissions intensity observed in 2015.

We believe in proactive measurement and disclosure of air emissions. In 2015, TransAlta was the only power generation company recognized as part of the Top 20 in Canada in the Climate Leadership Index.

Resource utilization

Water

Our principal water uses are for cooling and steam generation in coal and gas plants, and for hydro power production. Typically, TransAlta withdraws in the ranges of 220-240 m3 of water across our fleet. Water is withdrawn primarily from rivers where we hold permits to withdraw water and adhere to regulations on water quality. We return or discharge approximately 70 per cent of water back to the source, meeting the regulatory quality levels that exist in the various locations we operate. The difference between withdraw and discharge, representing consumption, is largely due to evaporative loss.

Our areas of higher water risk are situated east of Perth in our single-cycle gas plants in Western Australia and in our Southern Alberta hydro operations. We continue to maintain ample water at all sites that require water for operation.

In Southern Alberta, following the flood of 2013, our hydro facilities are being solicited for an increased water management role than they have played in the past. During 2015, we established an interim agreement with the Government of Alberta to use our Ghost hydro reservoir for potential flood mitigation purposes. As part of the agreement, we lowered the reservoir level below typical operating levels for a longer period, and received compensation for commercial opportunity costs. We continue to engage with the government and partners towards a comprehensive water management framework that involves flood and drought mitigation.

(1) 2015 data are estimates based on best available data at the time of report production. GHGs include water vapour, carbon dioxide (“CO2”), methane, nitrous oxide, sulphur hexafluoride, hydrofluorocarbons, and perfluorocarbons. The majority of our estimated GHG emissions are comprised of CO2 emissions from stationary combustion.

Emissions intensity data has been aligned with the ‘Setting Organizational Boundaries: Operational Control’ methodology set out in The Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard. As per the methodology TransAlta reports emissions on an operation control basis, hence we report 100 per cent of emissions at facilities in which we are the operator. Emissions intensity is calculated by dividing total operational emissions by 100 per cent of production (MWh) from operated facilities, regardless of financial ownership.

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Land

The largest land use associated with our operations is for surface mining of coal. Of the three mines we have operated, Whitewood is completely reclaimed and the land certification process is ongoing. Centralia is in the reclamation phase, and Highvale is actively mined with ongoing reclamation. Our reclamation plans are set out on a lifecycle basis and include contouring disturbed areas, re-establishment of drainage, replacement of topsoil and subsoil, re-vegetation, and land management. Our mining practice incorporates progressive reclamation where the final end use of the land is considered at all stages of planning and development. In 2015, we reclaimed 65 acres (26 hectares) at our Higvale mine, slightly below our target of 74 acres (30 hectares) due to the impact of warm weather on soils in the winter as cold temperatures facilitate reclamation work and the spreading of topsoil. The variance has been accounted for and incorporated into the mine’s go-forward reclamation plans.

During 2015, we obtained approvals for our Highvale mine to develop a new area, which we anticipate will be the final area required to support our Sundance and Keephills facilities through to the end of their operation in 2030.

Also in 2015, we donated 64 acres of land to the Alberta Wildlife Trust Fund. The land includes an area that was once a mine settling pond and is a site of ecological significance. The donation aligns with our objectives for community participation and stakeholder engagement.

Waste

Our operating teams work to minimize waste and maximize recoverable value from waste. Over the years, we have invested in equipment to capture of byproducts from the combustion of coal, such as fly ash, bottom ash, gypsum, and cenospheres, for subsequent sale. These non-hazardous materials add value to products like cement and asphalt, wallboard, paints, and plastics. During 2015, our revenue from by-product sales amounted to $28 million (2014 — $31 million). The decrease is primarily attributable to the lower production.

Regional Regulation and Compliance

Environmental issues and related legislation have, and will continue to have, an impact upon our business. We are committed to complying with legislative and regulatory requirements and to minimizing the environmental impact of our operations. We work with governments and the public to develop appropriate frameworks to protect the environment and to promote sustainable development.

Recent changes to environmental regulations may materially adversely affect us. As indicated under “Risk Factors” in our Annual Information Form and within the Governance and Risk Management section of this MD&A, many of our activities and properties are subject to environmental requirements, as well as changes in our liabilities under these requirements, which may have a material adverse effect upon our consolidated financial results.

Alberta

On Nov. 22, 2015, the Government of Alberta announced its Climate Leadership Plan. That Plan established several environmental and energy targets for Alberta, including:

■the phase-out of emissions from coal-fired generation by 2030;

■the replacement of two-thirds of the retiring coal-fired generation with renewable generation and one-third with gas generation;

■the objective of achieving up to 30 per cent of Alberta’s electricity production from renewables by 2030; and

■maintaining reliability, reasonable prices to customers and businesses, and ensuring capital is not unnecessarily stranded.

The Province of Alberta will develop its associated regulations as well as a compensation plan for coal units in 2016. We will negotiate with the Government of Alberta, using a principles-based approach, to ensure the Corporation has the certainty and capacity needed to invest in clean power.

On Sept. 11, 2012, the Canadian federal government published the final regulations governing GHG emissions from coal-fired power plants. The regulations provide for up to 50 years of life for coal units, at which point units must meet an emissions performance standard of approximately 420 tonnes per GWh. There are some exceptions that require older units commissioned before 1975 to reach end of life by Dec. 31, 2019, and units commissioned between 1975 and 1986 to reach end of life by Dec. 31, 2029.

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We believe the regulations provide additional operating time and increased flexibility for our Canadian Coal units, allowing those units to comply in a more cost-effective manner. Our Keephills 3, Genesee 3, and Sheerness facilities, however, would be subject to the shorter 2030 limit proposed by the Alberta government.

Since 2007, we have incurred costs as a result of GHG legislation in Alberta. On June 29, 2015, the Alberta government announced an increase to its provincial SGER:

■       On Jan. 1, 2016, an increase in the GHG reduction obligation for large emitters from 12 per cent to 15 per cent of emissions, with the compliance price of the technology fund rising from $15 per tonne to $20 per tonne.

■       On Jan. 1, 2017, a further increase to a 20 per cent reduction requirement and a $30 per tonne compliance price.

Our exposure to increased costs as a result of environmental legislation in Alberta is mitigated to some extent through change-in-law provisions in our PPAs that allow us the opportunity to recover capital and operating compliance costs from our PPA customers. The GHG offsets created by our Alberta wind facilities are expected to increase in value through 2017, as GHG emitters can use them as compliance instruments in place of contributing to the technology fund. As part of the Climate Leadership Plan, the government has stated its intention to establish a new system of obligations and allowances, benchmarked against highly efficient gas generation, beginning in 2018. The initial compliance price would be set at $30 per tonne, escalating annually.

In Alberta there are additional requirements for coal-fired generation units to implement additional air emission controls for oxides of NOx and SO2 once they reach the end of their respective PPAs, in most cases in 2020. These regulatory requirements were developed by the province in 2004 as a result of multi-stakeholder discussions under Alberta’s CASA. The release of the federal regulations creates a potential misalignment between the CASA air pollutant requirements and schedules, and the GHG retirement schedules for older coal plants, which in themselves will result in significant reductions of NOx, SO2, and particulates.

We are in discussions with the provincial government in an effort to ensure coordination between GHG and air pollutant regulations, such that emission reduction objectives are achieved in the most effective manner while taking into consideration the reliability and cost of Alberta’s generation supply.

Pacific Northwest

On Aug. 3, 2015, President Obama announced the Clean Power Plan. The plan sets GHG emission standards for new fossil-fuel-based power plants and emission limits for individual states. States will have the option of interpreting their limits in mass-based (tons) or rate-based (pounds per megawatt hour) terms. The plan is intended to achieve an overall reduction in GHG emissions of 32 per cent from 2005 levels by 2030. It will be implemented in two stages: 2022 to 2029, and 2030 and beyond.

On Dec. 17, 2014, Washington State Governor Jay Inslee released a carbon-emissions reduction program for the State, where our U.S. Coal plant is located. Included in this program are a cap-and-trade plan and a low-carbon fuels standard. The proposed emissions cap will become more stringent over time, providing emitters time to transition their operations.

These additional regulations for existing power plants are not expected to significantly affect our U.S. operations. TransAlta has agreed with Washington State to retire units in 2020 and 2025. This agreement is formally part of the State’s climate change program. We believe that there will be no additional GHG regulatory burden on U.S. Coal given these commitments. The related TransAlta Energy Bill was signed into law in 2011 and provides a framework to transition from coal to other forms of generation.

Ontario

On April 13, 2015, the Ontario government announced that Ontario will be implementing a GHG cap-and-trade system in an effort to reduce emissions and fight climate change. The cap-and-trade system will impose a hard ceiling on the GHG emissions allowed in each sector of the economy. The details of the cap-and-trade system (such as specifics on a potential cap, covered sectors, or anticipated launch date) have not been determined but are to be developed through stakeholder consultations. Our contracts at Gas facilities in the province generally include provisions protecting us from adverse changes in laws.

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Australia

In Australia, the Senate recently passed amendments to the country’s Renewable Energy Target Scheme. The scheme was initially introduced in 2001 with three objectives: to establish a mandatory renewable energy target to be achieved in 2020; to provide incentives for large-scale renewable energy generators in the form of one large-scale generation certificate earned for each MWh of generation; and to require retailers and wholesale industrial customers to purchase a specified volume of their electricity from large-scale renewable-sourced electricity or incur a penalty of AUD$65/MWh on any shortfall. The amendments reduced the annual targets for large-scale renewable sourced electricity down from 41,000 GWh in 2020 to 33,000 GWh in 2020, held constant at this level until 2030. It is estimated that this will require an additional 5,000-6,000 MW of new capacity to be installed to add to the slightly more than 4,000 MW already operating. Since the Australian assets are fully contracted it is not expected that these amendments will have a significant impact.

Climate Change

Abnormal weather events that are sometimes associated with climate change can impact our operations and give rise to risks. Among other events, variations in wind, solar, water, and temperatures give rise to various levels of volume risk depending on the input fuel of each facility; events outside the design parameters of our facilities give rise to equipment risk; and fluctuations in temperatures can cause commodity price risk through impact on customer demand for heating or cooling. Refer to the Governance and Risk Management section of this MD&A for further discussion of each risk and our related management strategy.

During the past three years, some deviations from expected weather patterns have negatively impacted our annual financial results:

■       the Southern Alberta flood of 2013 disrupted our hydro operations and caused us to invest into substantial repair work. Our losses have been largely covered through insurance; and

■       warm weather in Alberta in 2015 increased derates at our coal facilities due to its impact on the Sundance cooling ponds. These cooling ponds are susceptible to warm weather; however, we anticipate that decreased coal production and the retirement of Sundance Units 1 and 2 in the medium term will reduce the stress from such occurrence.

Over the same period, other deviations have positively impacted our financial results such as the cold temperatures in Eastern North America in the winter of 2014 that caused market volatility which benefitted our energy marketing group.

Local Communities

We provide public benefit through reliable, cost-efficient power and related outputs or services. In the face of declining social acceptability of coal and with its phase-out on the horizon, we seek to secure favourable outcomes for our workers and the communities surrounding our plants. The approach is summarized in CEO Dawn Farrell’s editorial on TransAlta’s Dial Down - Dial Up submission to the Government of Alberta. “We are prepared to invest hundreds of millions of dollars to dial up the transition to new renewables, including hydro, wind, and solar. Dial Down - Dial Up starts with an agreement with the province, environmental groups, the communities in which we operate, and our employees, because jobs matter. Not jobs that will be created in the future, but thousands of jobs held today by our employees and contractors. That’s almost 3,000 people, not including jobs in the communities where they work. And electricity prices matter, because there is a real risk to consumers, including Alberta businesses, of price spikes and volatility.” TransAlta advocated for a sufficiently long timelines for transition, support for facility redevelopment, funds for retraining, and economic diversification. Our successful agreement with the State of Washington, in 2011, and our proposal in Alberta leading up to the Climate Leadership Plan illustrate this approach.

Competitive Behaviour

On July 27, 2015, the AUC issued a ruling that found, among other things, that our actions in relation to four outage events at our coal-fired generating units, spanning 11 days in 2010 and 2011, restricted or prevented a competitive response from the associated PPA buyers and manipulated market prices away from a competitive market outcome.

On Sept. 30, 2015, TransAlta and the MSA reached an agreement to settle all outstanding proceedings before the AUC. The settlement, which is in the form of a consent order, was approved by the AUC on Oct. 29, 2015. Under the terms of the agreement, we will pay a total amount of $56 million that includes approximately $27 million as a repayment of economic benefit, approximately $4 million to cover the MSA’s legal and related costs, and a $25 million administrative penalty. Of this amount, $31 million has been paid in the fourth quarter, and the $25 million administrative penalty will be paid in the fourth quarter of 2016. As a result of the approval, we have discontinued our appeal of the AUC’s decision.

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When we became aware that the market rules governing forced outages were in dispute, we changed our compliance procedures, and the actions that led to this case have not been repeated. In order to rebuild trust, we have undertaken two independent, third-party reviews of our current compliance procedures around forced outages, and of our trading compliance program, the results of which will be made public. We have received findings from these independent reports, including some recommendations for improvement, and are finalizing our response to the reports and recommendations.

Public Health

We seek to maintain public health and safety by restricting physical access to our operating sites and ongoing monitoring of air emissions from our coal and gas plants.

During the year, public assertions have been made concerning the impact of coal plants on air quality in the Edmonton area. In order to verify the veracity of this information, we funded an independent analysis of the sources of air quality issues in and around the Edmonton area by University of Alberta scientist Dr. Warren Kindzierski, using provincial government monitoring data from the past nine years.

Dr. Kindzierski’s work has determined that emissions from coal-fired generation are in fact a minor contributor to Edmonton’s air pollution. Chemical “signatures” for emissions pointed to several sources, including local industries, vehicles, and wood-burning fireplaces in relation to air quality concerns in Edmonton. Only about 10 per cent or less of all particulate matter in the airshed can be attributed to coal combustion emissions.

The study also looked at 17 years of wind patterns and confirmed that, in most seasons, the local winds around Edmonton predominantly blow into the city from the south and southeast, not from the west where coal-fired generation is concentrated.

Stakeholder Engagement

TransAlta is implementing a corporate stakeholder engagement framework, a streamlined corporate-wide approach to ensure that engagement and relationship-building practices are consistent across TransAlta’s locations and types of work. Our aboriginal relations group continues to develop and enhance aboriginal relations programming in areas of employment, economic development, community engagement, and investment to position TransAlta for achieving top standing in 2017. Since 2014, we have achieved the Canadian Council for Aboriginal Business’ silver-level Progressive Aboriginal Relations certification, and we are targeting to achieve gold-level by 2017.

Community

During 2015, TransAlta contributed $3.5 million in donations and sponsorships (2014 - $3.6 million).

On July 30, 2015 we announced that we are moving ahead with plans to invest US$55 million over 10 years to support energy efficiency, economic and community development, and education and retraining initiatives in Washington state. The US$55 million community investment is part of the TransAlta Energy Transition Bill, passed in 2011. This bill was a historic agreement between policymakers, environmentalists, labour leaders, and TransAlta to transition away from coal in Washington State, closing the Centralia facility’s two units, one in 2020 and the other in 2025. Although we did not secure additional long-term contracts totalling 500 MW as planned in the original agreement as a condition of the investment, we are following through on our funding pledge and securing mutual benefits agreed with the State for orderly transition.

Stakeholder Communication and Value Creation

The information contained herein seeks to highlight our ability to create value for investors, stakeholders, and society in the short, medium, and long term. The selection of key information and key metrics disclosed in this integrated report and our full sustainability disclosures follow a materiality assessment process, which identifies key impact areas to our stakeholders. We subsequently are guided by and place focus on reporting on these key areas. More information on key areas of materiality can be found on the sustainability section of our website.

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Discussion of Segmented Comparable Results

During the first quarter of 2015 we began reporting Canadian Coal, U.S. Coal, Gas, Wind, and Hydro as separate business segments. Previously, these were collectively reported as the Generation Segment and were further differentiated by fuel type within our MD&A to provide additional information to our readers. The change in segmentation under IFRS has minimal impact on our MD&A. No changes arose in respect of our Energy Marketing and Corporate segments. See the Current Accounting Changes section of this MD&A for additional information.

Solar facilities acquired in September 2015 have been included in our Wind and Solar Segment as it is integrated to this business from a management perspective.

Comparable figures are not defined under IFRS. Refer to the Earnings and Other Measures on a Comparable Basis section of this MD&A for further discussion of these items, including, where applicable, reconciliations to net earnings attributable to common shareholders.

Canadian Coal

Year ended Dec. 31	2015	2014	2013
Availability (%)	84.3	88.6	80.9
Contract production (GWh)	20,256	21,748	17,789
Merchant production (GWh)	3,827	3,806	3,779
Total production (GWh)	24,083	25,554	21,568
Gross installed capacity (MW)	3,786	3,771	3,771
Revenues	912	1,023	916
Fuel and purchased power	379	436	393
Comparable gross margin	533	587	523
Operations, maintenance, and administration	194	196	203
Taxes, other than income taxes	12	12	11
Gain on sale of assets	-	(1)	(2)
Net other operating income	(7)	(9)	-
Comparable EBITDA	334	389	311
Depreciation and amortization	299	292	292
Comparable operating income	35	97	19
Sustaining capital:
Routine capital	48	56	69
Mine capital	25	45	65
Finance leases	10	10	9
Planned major maintenance	107	100	94
Total sustaining capital expenditures	190	211	237
Insurance recoveries of sustaining capital expenditures	(7)	-	-
Net amount	183	211	237

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2015

Production for the year ended Dec. 31, 2015 decreased 1,471 GWh compared to 2014, primarily due to unplanned outages in the first half of the year (Sundance 4, and Keephills 1 Force Majeure outage) and derates due to high temperatures impacting cooling ponds in the spring and summer months. The planned outage at Sundance 3 was extended as a result of the level of turbine work found. Generation was also reduced due to economic dispatch resulting from the current low price environment.

Comparable EBITDA in 2015 was $334 million compared to $389 million in 2014. In 2015 comparable EBITDA included a $59 million adjustment to provisions primarily in relation to prior year events. Excluding the adjustment to provisions, comparable EBITDA would have been $393 million in 2015, in line with last year. Reductions in operating expenses at our Highvale mine and mark-to-market gains on certain forward financial contracts that do not qualify for hedge accounting fully offset the negative impact of year-over-year lower availability on our comparable EBITDA. Our high level of contracts and hedges in Canadian Coal mostly offset the impact of lower prices in Alberta compared to 2014. Other operating income in 2015 represents insurance recoveries received in connection to the Keephills 1 Force Majeure outage and additional work at Sundance 3.

Depreciation and amortization for the year ended Dec. 31, 2015 increased by $7 million compared to 2014 due to the addition of assets at our Highvale mine.

For the year ended Dec. 31, 2015, sustaining capital expenditures decreased by $21 million compared to 2014. In 2014, we incurred additional cost for the development of a new mining area, and the acquisition and refurbishment of vehicles as part of our mining operations.

2014

Production for the year ended Dec. 31, 2014 increased 3,986 GWh compared to 2013. Production for 2013 was impacted by a seven-month outage at our Keephills 1 facility and the return to service of Sundance 1 and 2 in September and October, respectively.

For the year ended Dec. 31, 2014, comparable gross margin increased by $64 million compared to 2013, primarily as a result of lower unplanned outages, lower unit coal costs, and contract price escalations. Lower prices in Alberta in 2014 compared to 2013 decreased incentive payments received for generation in excess of PPA targets, offsetting some of the gain in reliability. We were able to achieve the reduction in coal costs after we took over operations at the Highvale mine in 2013.

OM&A for the year ended Dec. 31, 2014 decreased despite much higher operating capacity with Sundance Units 1 and 2 returning to service. We achieved a reduction in OM&A as a result of reduced maintenance costs associated with lower unplanned outages and the implementation of initiatives to reduce costs.

Other operating income resulted from the settlement of a dispute with a supplier in relation to an equipment failure in prior years.

Depreciation and amortization for the year ended Dec. 31, 2014 was consistent compared to 2013. The increase in depreciation and amortization relative to 2013 resulted from an increased asset base, primarily related to Sundance Units 1 and 2 returning to service, was offset by fewer asset retirements during the year and the life extension of certain components.

For the year ended Dec. 31, 2014, sustaining capital decreased $26 million compared to 2013 as a result of the Keephills 1 Force Majeure outage in 2013 and investments required to increase mining intensity.

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U.S. Coal

Year ended Dec. 31	2015	2014	2013
Availability (%)	87.4	82.8	78.3
Adjusted availability (%)(1)	89.5	87.7	91.9
Contract sales volume (GWh)	2,868	1,131	996
Merchant sales volume (GWh)	5,484	6,102	6,459
Purchased power (GWh)	(3,329)	(549)	(744)
Total production (GWh)	5,023	6,684	6,711
Gross installed capacity (MW)	1,340	1,340	1,340
Revenues	431	368	346
Fuel and purchased power	311	251	227
Comparable gross margin	120	117	119
Operations, maintenance, and administration	50	49	48
Taxes, other than income taxes	3	3	4
Comparable EBITDA	67	65	67
Depreciation and amortization	63	54	56
Comparable operating income	4	11	11
Sustaining capital:
Routine capital	2	2	6
Finance leases	3	-	-
Planned major maintenance	10	10	10
Total	15	12	16

2015

Production decreased 1,661 GWh in 2015 compared to 2014, as a result of a reduction in our generation to supply our contractual obligation by buying cheaper power in the market.

In December 2014, we commenced supplying power to Puget Sound Energy under a 10-year contract. Initial contracted capacity was 180 MW. Contract volumes escalated to 280 MW in December 2015, and will escalate again by 100 MW in December 2016. We can also re-supply the contract by buying power from the market when economical to do so and further improve our margin. Because of this option for financial settlement, it is accounted as a financial contract. Hedge accounting was applied to this contract, with changes in value recorded in other comprehensive income (“OCI”).

EBITDA for the year ended Dec. 31, 2015 was comparable to 2014. The appreciation of the US dollar was offset by the impacts of lower prices on our merchant sales.

Depreciation and amortization for 2015 increased by $9 million compared to 2014 due to the strengthening of the US dollar.

For the year ended Dec. 31, 2015, sustaining capital expenditures increased by $3 million compared to last year as a result of the coal fines recovery finance lease. This operation allows us to recover fuel as part of mine decommissioning activities.

(1) Adjusted for economic dispatching.

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2014

Production was stable in 2014 compared to 2013, as higher unplanned outages at U.S. Coal were offset by lower economic dispatching as certain months during the period had higher prices that made production more economic.

Comparable EBITDA decreased $4 million in 2014, as 2013 comparable EBITDA included the favourable effects of adjustments to commercial arrangements recognized in prior periods. The effect of prior year adjustments was partially offset by increased optimization margins earned, as we were able to capitalize on high market volatility early in the year.

For the year ended Dec. 31, 2014, sustaining capital decreased by $4 million compared to 2013 primarily due to reduced general equipment repair and replacement.

Gas

Year ended Dec. 31	2015	2014	2013
Availability (%)	94.7	94.0	94.5
Contract production (GWh)	5,078	5,363	5,892
Merchant production (GWh)	1,535	2,027	1,962
Total Production (GWh)	6,613	7,390	7,854
Gross installed capacity (MW)(1)	1,405	1,531	1,779
Revenues	650	744	683
Fuel and purchased power	229	326	252
Comparable gross margin	421	418	431
Operations, maintenance, and administration	88	102	97
Taxes, other than income taxes	3	4	3
Net other operating income	-	-	(1	)
Comparable EBITDA	330	312	332
Depreciation and amortization	118	114	108
Comparable operating income	212	198	224
Sustaining capital:
Routine capital	8	24	17
Planned major maintenance	23	39	41
Total	31	63	58

(1) Includes production capacity for Fort Saskatchewan and Solomon power stations, which have been accounted for as finance leases. During the quarter, operational control of our Poplar Creek facility was transferred to Suncor. We continue to own a portion of the facility and have included our portion as a part of gross capacity measures. Poplar Creek has been removed from our availability and production metrics from Sept. 1, 2015, the date of transfer of operational accountability. Refer to TransAlta’s Capitals section of this MD&A for further information. Assets of the Centralia gas plant were sold in the fourth quarter of 2014 and the production capacity was removed from our gross capacity measures at that time.

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2015

Production for the year ended Dec. 31, 2015 decreased 777 GWh compared to 2014, predominantly due to the transfer of operational control of the Poplar Creek facility to our customer, effective Sept. 1, 2015.

Most of our contracts provide for pass-through of fuel cost to the counterparty limiting our exposure to fuel price. In the case where we have no provision for pass-through, we generally match our obligation to deliver energy and our fuel supply to minimize our exposure to volatile commodity prices. Revenue and costs of fuel decreased by similar amounts during the first half of 2015 compared to last year, following the decrease in gas input costs. Also, certain operating costs that are transferred to customers are now billed directly to the customer, resulting in revenue and OM&A decreasing in 2015 compared to last year. The Poplar Creek restructuring transaction had a minimal impact on EBITDA compared to last year as a lower gross margin was offset by lower operating costs. The increase in comparable EBITDA is primarily attributable to revenue from the Australian natural gas pipeline, which was commissioned in March 2015. Revenue from our Solomon facility was also positively impacted by the appreciation of the US dollar. The Australian dollar remained at similar levels in relation to the Canadian dollar during the year.

Depreciation and amortization for 2015 increased by $4 million compared to 2014 due to the increased asset base associated with the Fortescue River Gas Pipeline completed in the first quarter of 2015, as well as impacts from the Poplar Creek restructuring deal, and higher asset retirements. These were partially offset through the extension of certain asset lives.

Sustaining capital decreased by $32 million for the year ended Dec. 31, 2015 compared to 2014, due to the transfer of the Poplar Creek facility at the end of August, and lower planned maintenance activities resulting from condition-based assessments.

2014

Production for the year ended Dec. 31, 2014 decreased 464 GWh compared to 2013 due to the reduced requirement to run our Ottawa facility under the terms of its new capacity-based contract. The new contract is consistent with our contracting strategy and its 20-year duration supports continued investment in the facility.

Comparable EBITDA for the year ended Dec. 31, 2014 decreased by $18 million compared to 2013, primarily due to the impact of lower Alberta prices on our merchant capacity in Poplar Creek and the reduced contribution from our Ottawa facility under the terms of the new contract. These decreases in comparable EBITDA were partially offset by the benefits achieved through resale of higher priced excess gas during unplanned outages in 2014. The 2014 results include an $8 million unrealized loss on forward purchase and physical gas volumes in Ontario, which is offset by unrealized gains of the same amount in the Energy Marketing Segment.

For the year ended Dec. 31, 2014, sustaining capital increased by $5 million compared to 2013 mainly due to compressor repairs at Mississauga.

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Wind and Solar

Year ended Dec. 31	2015	2014	2013
Availability (%)	95.8	94.6	93.8
Contract production (GWh)	2,146	2,228	1,700
Merchant production (GWh)	1,060	947	1,009
Total production (GWh)	3,206	3,175	2,709
Gross installed capacity (MW)(1)	1,424	1,291	1,289
Revenues	250	247	237
Fuel and purchased power	19	14	13
Comparable gross margin	231	233	224
Operations, maintenance, and administration	48	48	38
Taxes, other than income taxes	7	6	5
Comparable EBITDA	176	179	181
Depreciation and amortization	99	88	79
Comparable operating income	77	91	102
Sustaining capital:
Routine capital	1	2	3
Planned major maintenance	12	10	6
Total	13	12	9

2015

Production for 2015 increased slightly by 31 GWh compared to 2014, primarily due to better wind resources and availability in Western Canada, and contribution from three additional wind farms and our first solar facility acquired during the second half of the year (111 GWh). This was partially offset by lower wind resources at Wyoming after high wind volumes in 2014.

Comparable EBITDA for 2015 was lower by $3 million compared to 2014 as lower generation from our Wyoming wind facility and lower merchant prices in Alberta were not fully offset by additional EBITDA from the acquired assets and the stronger US dollar positively impacting our U.S. assets.

Depreciation and amortization for 2015 increased by $11 million compared to 2014 primarily due to the additions of new projects during the year.

Sustaining capital for the year ended Dec. 31, 2015 was comparable to 2014.

2014

Production for the year ended Dec. 31, 2014 increased 466 GWh compared to 2013, primarily due to the contribution from a full year of operations at Wyoming and New Richmond and higher wind volumes in Eastern Canada.

For the year ended Dec. 31, 2014, comparable EBITDA decreased by $3 million compared to 2013. Lower prices in Alberta in 2014 compared to 2013 more than offset the contribution of new wind projects commissioned or acquired in 2013.

Depreciation and amortization for the year ended Dec. 31, 2014 increased by $9 million compared to 2013, primarily due to the higher asset base associated with recently added facilities.

For the year ended Dec. 31, 2014, sustaining capital increased by $3 million compared to 2013 mainly due to an increase in planned major maintenance activities as a result of an outage at Le Nordais.

(1) Includes production capacity for the recent Solar and Wind acquisitions.

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Hydro

Year ended Dec. 31	2015		2014		2013
Contract Production (GWh)	1,662		1,810		2,022
Merchant production (GWh)	86		75		72
Total production (GWh)	1,748		1,885		2,094
Gross installed capacity (MW)	926		913		913
Revenues	116		131		181
Fuel and purchased power	8		9		5
Comparable gross margin	108		122		176
Operations, maintenance, and administration	38		38		31
Taxes, other than income taxes	3		3		3
Net other operating income	(6	)	(6	)	(6	)
Comparable EBITDA	73		87		148
Depreciation and amortization	25		24		25
Comparable operating income	48		63		123
Sustaining capital(1):
Routine capital, excluding hydro life extension	3		9		8
Hydro life extension	18		19		8
Planned major maintenance	10		3		5
Total before flood-recovery capital	31		31		21
Flood-recovery capital	4		9		1
Total sustaining capital expenditures	35		40		22
Insurance recoveries of sustaining capital expenditures	(18	)	(4	)	(1	)
Net amount	17		36		21

2015

Production for 2015 decreased by 137 GWh compared to 2014 as a result of lower water resource.

Comparable EBITDA decreased by $14 million for 2015 compared to 2014, primarily as a result of lower prices and a decrease in price volatility in Alberta, which limited our ability to take advantage of our flexibility to produce electricity in higher priced hours.

Net other operating income includes business interruption insurance recoveries relating to the 2013 Alberta floods.

Sustaining capital expenditures decreased by $5 million for the year ended Dec. 31, 2015 compared to 2014 mainly due to flood-recovery capital related to the Alberta flood of 2013. We expect to spend $15 to $20 million to complete the flood recovery.

2014

Production for the year ended Dec. 31, 2014 decreased 200 GWh compared to 2013 due to lower water resource in Western Canada and optimization of storage capacity to capture highest prices.

Comparable EBITDA decreased by $61 million in 2014 compared to 2013, primarily as a result of lower prices and low price volatility in Alberta, which limited our ability to take advantage of our flexibility to produce electricity during higher priced hours.

(1) 2014 and 2013 restated to include hydro life extension from growth capital expenditures to sustaining capital expenditures. Refer to the Current Accounting Changes section of this MD&A.

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Net other operating income relates to business interruption insurance proceeds received in respect of prior period events.

For the year ended Dec. 31, 2014, total sustaining capital increased by $18 million compared to 2013, mainly due to higher spending on hydro life extension projects and flood-recovery capital related to the Alberta flood of 2013. The flood-related expenditures were mostly recovered through insurance proceeds recognized in net earnings in 2014, as non-comparable items.

Equity Investments

We completed the sale of our interests in CE Generation LLC (“CE Gen”) and CalEnergy, LLC (“CalEnergy”) in June 2014 and Wailuku River Hydroelectric, L.P. (“Wailuku”) in November 2014.

The equity method was used to account for the results of the CE Gen, CalEnergy, and Wailuku joint ventures for the months of January and February 2014, but ceased effective March 1, 2014. There were no earnings from Equity Investments during the two-month period in 2014 (2013 annual - loss of $10 million).

Energy Marketing

Year ended Dec. 31	2015	2014	2013
Revenues and comparable gross margin	49	108	79
Operations, maintenance, and administration	12	33	21
Comparable EBITDA	37	75	58
Depreciation and amortization	1	-	1
Comparable operating income	36	75	57

Comparable EBITDA from Energy Marketing totalled $37 million, approximately half of last year’s contribution, due to a return to normal performance from trading activities in the Northeast after extraordinary market conditions in the first quarter of 2014 and the negative impact from unexpected volatile markets in Alberta and the Pacific Northwest during the second quarter of 2015. Performance during the second half of the year was largely in line with last year. Lower OM&A costs partially offset the shortfall in revenue as a significant portion of our costs is incentive compensation that is impacted by lower margins generated by the business.

Corporate

The expenses incurred by the Corporate Segment are as follows:

Year ended Dec. 31	2015	2014	2013
Operations, maintenance, and administration and taxes other than income taxes	72	71	74
Depreciation and amortization	25	26	23
Comparable operating loss	97	97	97
Sustaining capital:
Routine capital	21	23	22

Our Corporate overhead costs have remained comparable to 2014 and 2013, and we anticipate to begin realizing benefits of our overhead reductions during 2016.

Routine capital expenditures for the year ended Dec. 31, 2015 decreased compared to 2014, mainly as a result of a reduction in corporate information technology costs.

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Other Consolidated Analysis

Asset Impairment Charges and Reversals

Alberta Merchant Cash Generating Unit

As part of the annual impairment review and assessment process in 2013, the Corporation’s Alberta plants with significant merchant capacity were considered one cash-generating unit (the “Alberta Merchant CGU”). While no impairment losses were recognized in 2013 for the Alberta Merchant CGU, total pre-tax impairment losses of $23 million that were recognized previously in the Wind Segment plants that became part of the Alberta Merchant CGU were reversed. Please refer to Note 6 of our audited consolidated financial statements within our Annual Report for additional information.

The Alberta Merchant CGU’s recoverable amount was based on an estimate of fair value less costs of disposal using a discounted cash flow methodology based on our long-range forecasts and prices evidenced in the marketplace. Due to a substantial excess of fair value over net book value at other plants included within the Alberta Merchant CGU, valuation assumptions and methodologies were not a significant driver of the impairment reversals.

We consider the relationship between our market capitalization and our book value, among other factors, when reviewing for indicators of impairment. The slowdown in the oil and gas sector has put Alberta into a recession, and put downward pressure on demand as well as power prices. Further, on Nov 20, 2015, the Government of Alberta announced its Climate Leadership Plan which broadly calls for the phase-out of coal-generated electricity by 2030 and proposes the imposition of additional compliance obligations for GHG emissions in the province. As at Dec. 31, 2015, our market capitalization was below our book value of equity. The government has stated intentions of providing compensation to coal-fired generators as part of its commitment to treat them fairly and not unnecessarily strand capital. We intend to negotiate an arrangement with the government.

As part of our monitoring controls, we estimate a recoverable amount for each Cash Generating Unit (“CGU”) by calculating an approximate fair value less costs of disposal using discounted cash flow projections based on our long-range forecasts. The valuations used are subject to measurement uncertainty based on assumptions and inputs to our long-range forecast, including changes to fuel costs, operating costs, capital expenditures, external power prices, and useful lives of the assets extending to the last planned asset retirement in 2073. These estimates are used to assess the significance of potential indicators of impairment and provide a criterion to evaluate adverse changes in operations.

During the fourth quarter, we completed a sensitivity analysis on these estimates to assess potential impacts of the proposed Alberta government policy on reducing GHG emissions, as well as the mandatory retirement of coal facilities by 2030. The sensitivity analysis demonstrated an approximate fair value substantially in excess of the carrying amount of the Alberta Merchant CGU, and accordingly, no further test was performed. The excess is attributable to our large renewable fleet in the province.

M44TRANSALTA CORPORATION

U.S. Coal

As at Nov. 30, 2014, we identified the decrease in projected growth in Mid-Columbia power prices as an indicator that the U.S. Coal CGU could be impaired. The U.S. Coal CGU’s carrying amount at that date, net of associated long-term liabilities, was $372 million. We estimated the fair value less costs of disposal of the CGU, utilizing our long-range forecast, and the following key assumptions:

Mid-Columbia annual average power prices	US$31.00 to 52.00 per MWh
On-highway diesel fuel on coal shipments	US$3.06 to 3.37 per gallon
Discount rates	5.1 to 6.2 per cent

The valuation is subject to measurement uncertainty based on those assumptions, and on inputs to our long-range forecast, including changes to fuel costs, operating costs, capital expenses, and the level of contractedness under the Memorandum of Agreement (“MoA”) for coal transition established with the State of Washington. The valuation period extended to the assumed decommissioning of the asset, after its projected cessation of operation in its current form in 2025.

Fair value less costs of disposal of the CGU was estimated to approximate its carrying amount, and accordingly, no impairment charge was recorded. Any adverse change in assumptions, in isolation, would have resulted in an impairment charge being recorded. We continue to manage risks associated with the CGU through optimization of our operating activities and capital plan.

We also considered possible impairment at the U.S. Coal CGU in 2015 utilizing a similar process and again found that the fair value less costs to sell approximates the current carrying amount. Accordingly, there were no impairment charges made during the year ended Dec. 31, 2015.

Centralia Gas

During 2014 we sold a portion of the assets of the Centralia gas facility to external counterparties and transferred other assets to other TransAlta facilities. The plant had been fully impaired and idled since 2010. As a result of the transaction, we recognized impairment reversals of $5 million and the plant’s generating capacity has been removed from TransAlta’s total owned capacity. In 2015, we reversed $2 million of previously impaired change as a result of additional recoveries.

TRANSALTA CORPORATION M45

Income Taxes

A reconciliation of income taxes and effective tax rates on earnings, excluding non-comparable items, is presented below:

Year ended Dec. 31	2015		2014	2013
Earnings (loss) before income taxes	221		239	(12)
Comparable adjustments:
Equity loss	-		-	10
Impacts associated with certain de-designated and economic hedges	60		(54)	103
Asset impairment charges (reversals)	(2)		(6)	(18)
Restructuring expense (recovery)	22		-	(3)
Gain on sale of assets	(262)		(2)	(12)
Economic hedges of non-controlling interest in intercompany foreign exchange contracts	8		-	-
Foreign exchange loss on California claim	-		4	-
Flood-related maintenance costs, net of insurance recovery	(9)		1	7
TAMA Transmission bid costs	-		5	-
Net other operating losses	38		1	109
Comparable earnings before tax	76		188	184
Comparable (earnings) attributable to non-controlling interests before tax	(85)		(53)	(31)
Comparable earnings attributable to TransAlta shareholders subject to tax	(9)		135	153
Comparable income tax expense adjustments:
Income tax (expense) recovery related to impacts associated with certain de-designated and economic hedges	22		(19)	36
Income tax expense related to asset impairment charges and reversals	(1)		(1)	(5)
Income tax (expense) recovery related to restructuring provision	5		-	(1)
Income tax (expense) recovery related to gain on sale of assets	(70	)	1	(2)
Income tax recovery related to divestiture of investment	-		35	-
Income tax (expense) recovery related to writedown of deferred income tax assets	56		5	(28)
Income tax expense related to investment in subsidiary	(95)		-	-
Income tax (expense) recovery related to changes in corporate income tax rates	(20)		-	5
Income tax recovery related to non-comparable items attributable to economic hedges of non-controlling interest in intercompany foreign exchange contracts	2		1	-
Income tax recovery related to flood-related maintenance costs, net of insurance recovery	(2)		-	2
Income tax recovery related to TAMA Transmission bid costs	-		1	-
Income tax recovery related to net other operating losses	(4)		-	27
Total comparable income tax expense adjustments	(107)		23	34
Income tax expense (recovery)	105		7	(8)
Comparable income tax expense (recovery)	(2)		30	26
Comparable income tax expense attributable to non-controlling interest	(5)		(4)	(2)
Comparable income tax expense (recovery) attributable to TransAlta shareholders	(7)		26	24
Comparable effective tax rate on earnings attributable to TransAlta shareholders (%)	78		19	16

M46TRANSALTA CORPORATION

The comparable income tax expense attributable to TransAlta shareholders decreased for the year ended Dec. 31, 2015 compared to 2014 due to lower comparable earnings.

In 2014, the comparable income tax expense increased compared to 2013 due to changes in the amount of earnings between the jurisdictions in which pre-tax income is earned, offset by lower comparable earnings.

The comparable effective tax rate on earnings attributable to TransAlta shareholders increased for the year ended Dec. 31, 2015 compared to 2014 due to certain amounts that do not fluctuate with earnings, and changes in the amount of earnings between the jurisdictions in which pre-tax income is earned.

In 2014, the comparable effective tax rate on earnings attributable to TransAlta shareholders increased compared to 2013 due to changes in the amount of earnings between the jurisdictions in which pre-tax income is earned and the effect of certain deductions that do not fluctuate with earnings.

During the year ended Dec. 31, 2015, we reversed a previous writedown of deferred income tax assets of $56 million. The deferred income tax assets relate mainly to the tax benefits of losses associated with our directly owned U.S. operations. We had written these assets off as it was no longer considered probable that sufficient future taxable income would be available from our directly owned U.S. operations to utilize the underlying tax losses, due to reduced price growth expectations. Recognized other comprehensive income during the year ended Dec. 31, 2015 has given rise to a taxable temporary difference that forms the primary basis for utilization of some of the tax losses and the reversal of the writedown.

In order to give effect to the Transaction with TransAlta Renewables, a reorganization of certain TransAlta companies was completed. The reorganization resulted in the recognition in 2015 of $95 million deferred tax liability on TransAlta’s investment in a subsidiary. The deferred tax liability had not been recognized previously, since prior to the reorganization, the taxable temporary difference was not expected to reverse in the foreseeable future.

During the second quarter of 2015, the Government of Alberta enacted legislation to increase its provincial corporate income tax rate to 12 per cent from 10 per cent, effective July 1, 2015. This resulted in a net increase in our deferred income tax liability of $18 million, of which $20 million is recorded in the Consolidated Statement of Earnings with an offsetting $2 million deferred tax recovery recorded in the Statement of Other Comprehensive Income.

TRANSALTA CORPORATION M47

Financial Position

The following chart highlights significant changes in the Consolidated Statements of Financial Position from Dec. 31, 2015 to Dec. 31, 2014:

	Increase/
	(decrease	)	Primary factors explaining change
Trade and other receivables	117		Timing of customer receipts and increases in collateral paid and short term portion of finance lease receivables following the Poplar Creek contract restructuring
Inventory	23		Increase in coal inventory following lower production, Mass Solar SREC inventory, and purchase of emission credits
Finance lease receivables (long-term)	372		Poplar Creek contract restructuring
Property, plant, and equipment, net	60		Acquisition of wind and solar assets ($217 million), sustaining capital and construction of the South Hedland project ($493 million) and favourable changes in foreign exchange rates ($139 million), partially offset by the net effect of the Poplar Creek contract restructuring ($130 million), depreciation for the period ($545 million), and revisions to decommissioning and restoration costs ($86 million)
Intangible assets	38		Acquisition of Kent Breeze wind farm
Deferred income tax assets	26		Effect of the internal reorganization associated with the Transaction and an increase in deductible temporary differences
Risk management assets (current and long-term)	420		Gains on commodity and foreign currency cash flow hedges
Other assets	35		Reclassification of Washington State community investment contribution funded but not yet disbursed
Other	23
Total increase in assets	1,114
Accounts payable and accrued liabilities	(147	)	Timing of payments and accruals
Credit facilities, long-term debt, and finance lease obligations (including current portion)	439		Unfavourable effects of changes in foreign exchange rates ($392 million) and increase in non-recourse obligations associated with acquisition of solar and wind facilities ($105 million) and financing of equity to acquire project ($106 million), partially offset by debt repayments ($758 million)
Decommissioning and other provisions (current and long-term)	42		Final installment of MSA settlement ($25 million) and adjustment to provisions ($66 million)
Deferred income tax liabilities	213		Effect of the internal reorganization associated with the Transaction, an increase in the Alberta corporate tax rate, and an increase in taxable temporary differences
Risk management liabilities (current and long-term)	47		Price movements and changes in underlying positions and settlements
Equity attributable to shareholders	77		Gains on cash flow hedges and gains on translating net assets of foreign operations recognized in other comprehensive income, and issuance of common shares, partially offset by the net loss, dividends declared in the period and sale of investment in subsidiaries to TransAlta Renewables
Non-controlling interests	435		Sale of investment in subsidiaries to TransAlta Renewables and net earnings for the period, partially offset by distributions paid and payable to non-controlling interests
Other	8
Total increase in liabilities and equity	1,114

M48TRANSALTA CORPORATION

Cash Flows

The following chart highlights significant changes in the Consolidated Statements of Cash Flows for year ended Dec. 31, 2015 compared to the year ended Dec. 31, 2014:

Year ended Dec. 31	2015	2014	Primary factors explaining change
Cash and cash equivalents, beginning of year	43	42
Provided by (used in):
Operating activities	432	796	Decrease in cash earnings of $49 million and an adverse change in non-cash working capital of $315 million
Investing activities	(573)	(292)	A decrease in proceeds on the sale of investment of $224 million and the acquisition of solar and wind assets for $101 million
Financing activities	149	(503)	Reduction in the net decrease in borrowings of $500 million, an increase in proceeds on the sale of non-controlling interest in a subsidiary of $275 million, and an increase in realized gains on financial instruments of $52 million, partially offset by a decrease in net proceeds on the issuance of preferred shares of $161 million
Translation of foreign currency cash	3	-
Cash and cash equivalents, end of year	54	43

Year ended Dec. 31	2014	2013	Explanation of change
Cash and cash equivalents, beginning of year	42	27
Provided by (used in):
Operating activities	796	765	Increase in cash earnings of $32 million. Refer to our discussion of funds from operations
Investing activities	(292)	(703)	Increase in proceeds on sale of investments of $224 million, a decrease in cash paid on the acquisition of Wyoming Wind of $109 million, a decrease in additions to property, plant, and equipment (“PP&E”) and intangibles of $72 million, and a decrease in investing non-cash working capital balances of $31 million, partially offset by a decrease in realized gains on financial instruments of $16 million and a decrease in proceeds on disposal of PP&E of $8 million
Financing activities	(503)	(47)	An increase in repayments of borrowings under credit facilities and in repayments (net of issuances) of long-term debt of $504 million, a decrease in proceeds on sale of non-controlling interest in a subsidiary of $78 million, an increase in distributions paid to subsidiaries’ non-controlling interests of $29 million, and an increase in common share cash dividends of $24 million, partially offset by an increase in proceeds on issuance of preferred shares of $161 million and an increase in realized gains on financial instruments of $20 million
Cash and cash equivalents, end of year	43	42

TRANSALTA CORPORATION M49

Unconsolidated Structured Entities or Arrangements

Disclosure is required of all unconsolidated structured entities or arrangements such as transactions, agreements, or contractual arrangements with unconsolidated entities, structured finance entities, special purpose entities, or variable interest entities that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources. We currently have no such unconsolidated structured entities or arrangements.

Guarantee Contracts

We have obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, commodity risk management and hedging activities, construction projects, and purchase obligations. At Dec. 31, 2015, we provided letters of credit totalling $575 million (2014 - $396 million) and cash collateral of $74 million (2014 - $25 million). These letters of credit and cash collateral secure certain amounts included on our Consolidated Statements of Financial Position under risk management liabilities and decommissioning and other provisions.

Commitments

Contractual commitments are as follows:

	2016	2017	2018	2019	2020	2021 and thereafter	Total
Natural gas, transportation, and other purchase contracts	52	17	15	6	6	105	201
Transmission	14	8	9	7	7	6	51
Coal supply and mining agreements	151	46	50	50	52	542	891
Long-term service agreements	103	110	23	19	36	70	361
Non-cancellable operating leases	9	8	7	7	7	50	88
Long-term debt(1)	72	604	947	761	447	1,596	4,427
Finance lease obligations	15	14	12	8	7	26	82
Interest on long-term debt and finance lease obligations(2)	225	216	171	138	106	796	1,652
Growth	85	186	6	1	-	-	278
TransAlta Energy Bill	6	6	6	6	6	19	49
Total	732	1,215	1,246	1,003	674	3,210	8,080

As part of the TransAlta Energy Bill signed into law in the State of Washington and the subsequent MoA, we have committed to fund US$55 million over the remaining life of the U.S. Coal plant to support economic and community development, promote energy efficiency, and develop energy technologies related to the improvement of the environment. The MoA contains certain provisions for termination and in the event of the termination and certain circumstances, this funding or part thereof would no longer be required.

(1) Repayments of long-term debt include amounts related to our credit facilities that are currently scheduled to mature in 2019.

(2) Interest on long-term debt is based on debt currently in place with no assumption as to re-financing an instrument on maturity.

M50TRANSALTA CORPORATION

Earnings and Other Measures on a Comparable Basis

We evaluate our performance and the performance of our business segments using a variety of measures. Those discussed below, and elsewhere in this MD&A, are not defined under IFRS and, therefore, should not be considered in isolation or as an alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from operating activities, as determined in accordance with IFRS, when assessing our financial performance or liquidity. These measures are not necessarily comparable to a similarly titled measure of another company.

Each business segment assumes responsibility for its operating results measured to gross margin and operating income. Operating income and gross margin provides management and investors with a measurement of operating performance that is readily comparable from period to period.

In calculating these items, we exclude certain items as management believes these transactions are not representative of our business operations. Earnings on a comparable basis per share are calculated using the weighted average common shares outstanding during the period.

During 2015, prior period restatements were made to 2014 and 2013. Refer to the Current Accounting Changes section of this MD&A for a description of these items.

The adjustments made to calculate comparable EBITDA and comparable earnings for the year ended Dec. 31, 2015 and 2014 are as follows. References are to the reconciliation presented on the following pages.

TRANSALTA CORPORATIONM51

Year ended Dec. 31			2015	2014	2013
Reference number	Adjustment	Segment
Reclassifications:
1	Finance lease income used as a proxy for operating revenue	Gas	58	49	46
2	Decrease in finance lease receivable used as a proxy for operating revenue and depreciation	Gas	23	3	1
3	Reclassification of mine depreciation from fuel and purchased power	Canadian Coal	62	56	58
4	Reclassification of comparable gain on sale of property, plant, and equipment that is included in depreciation	Canadian Coal	-	1	2
Adjustments (increasing (decreasing) earnings to arrive at comparable results):
5	Impacts to revenue associated with certain de-designated and economic hedges	U.S. Coal	60	(54)	103
6	Restructuring expense (recovery)	Canadian Coal	11	-	(2)
		U.S. Coal	1	-	-
		Gas	1	-	-
		Energy Marketing	3	-	-
		Corporate	6	-	(1)
7	MSA settlement	Energy Marketing	56	-	-
8	Economic hedges of non-controlling interest in intercompany foreign exchange contracts	Unassigned	8	-	-
9	Gain on Poplar Creek contract restructuring	Gas	(262)	-	-
10	Net tax effect on comparable adjustments subject to tax	Unassigned	48	18	(62)
11	(Reversal) accrual of writedown of deferred income tax assets	Unassigned	(56)	(5)	28
12	Income tax expense related to the Transaction	Unassigned	95	-	-
13	Deferred income tax rate adjustment	Unassigned	20	-	-
14	Maintenance costs related to the Alberta flood of 2013, net of insurance recoveries	Hydro	(9)	1	7
15	Costs related to TAMA Transmission bid	Corporate	-	5	-
16	Asset impairment charges (reversals)	Gas	(2)	(6)	1
		Wind	-	-	(23)
		Hydro	-	-	4
17	California claim	Energy Marketing	-	5	56
18	Non-comparable portion of insurance recovery received	Hydro	(18)	(4)	(1)
19	Sundance Units 1 and 2 return to service	Canadian Coal	-	-	25
20	Loss on assumption of pension obligation	Canadian Coal	-	-	29
21	Foreign exchange on California claim	Unassigned	-	4	-
22	Non-comparable gain on sale of assets	Equity Investments	-	(2)	-
		Corporate	-	-	(12)
23	Income tax recovery related to sale of investment	Unassigned	-	(36)	-
24	Non-comparable items attributable to non-controlling interest	Unassigned	14	1	-

M52  TRANSALTA CORPORATION

A reconciliation of comparable results to reported results for the year ended Dec. 31, 2015 and 2014 is as follows:

Year ended Dec. 31	2015						2014
	Reported	Comparable reclassifications		Comparable adjustments		Comparable total	Reported	Comparable reclassifications		Comparable adjustments		Comparable total
Revenues	2,267	81	(1, 2)	60	(5)	2,408	2,623	52	(1, 2)	(54)	(5)	2,621
Fuel and purchased power	1,008	(62)	(3)	-		946	1,092	(56)	(3)	-		1,036
Gross margin	1,259	143		60		1,462	1,531	108		(54)		1,585
Operations, maintenance, and administration	492	-		9	(14)	501	542	-		(6)	(14, 15)	536
Asset impairment reversals	(2)	-		2	(16)	-	(6)	-		6	(16)	-
Restructuring provision	22	-		(22)	(6)	-	-	-		-		-
Taxes, other than income taxes	29	-		-		29	29	-		-		29
Gain on sale of assets	-	-		-		-	-	(1)	(4)	-		(1)
Net other operating (income) losses	25	-	-	(38)	(7, 18)	(13)	(14)	-		(1)	(17, 18)	(15)
EBITDA	693	143		109		945	980	109		(53)		1,036
Depreciation and amortization	545	85	(2, 3)	-		630	538	60	(2, 3, 4)	-		598
Operating income	148	58		109		315	442	49		(53)		438
Finance lease income	58	(58)	(1)	-		-	49	(49)	(1)	-		-
Foreign exchange gain (loss)	4	-		8	(8)	12	-	-		4	(21)	4
Gain on sale of assets	262	-		(262)	(9)	-	2	-		(2)	(22)	-
Earnings (loss) before interest and taxes	472	-		(145)		327	493	-		(51)		442
Net interest expense	251	-		-		251	254	-		-		254
Income tax expense (recovery)	105	-		(107)	(10, 11, 12, 13)	(2)	7	-		23	(10, 11)	30
Net earnings	116	-		(38)		78	232	-		(74)		158
Non-controlling interests	94	-		(14)	(24)	80	50	-		(1)	(23)	49
Net earnings (loss) attributable to TransAlta shareholders	22	-		(24)		(2)	182	-		(73)		109
Preferred share dividends	46	-		-		46	41	-		-		41
Net earnings (loss) attributable to common shareholders	(24)	-		(24)		(48)	141	-		(73)		68
Weighted average number of common shares outstanding in the year	280					280	273					273
Net earnings (loss) per share attributable to common shareholders	(0.09)					(0.17)	0.52					0.25

TRANSALTA CORPORATIONM53

A reconciliation of comparable results to reported results for the year ended Dec. 31, 2013 is as follows:

Year ended Dec. 31	2013
	Reported	Comparable reclassifications		Comparable adjustments		Comparable total
Revenues	2,292	47	(1, 2)	103	(5)	2,442
Fuel and purchased power	948	(58)	(3)	-		890
Gross margin	1,344	105		103		1,552
Operations, maintenance, and administration	516	-		(5)	(14)	511
Asset impairment reversal	(18)	-		18	(16)	-
Restructuring provision	(3)	-		3	(6)	-
Taxes, other than income taxes	27	-		-		27
Gain on sale of assets	-	(2)	(4)	-		(2)
Net other operating (income) losses	102	-		(109)	(17, 18, 19, 20)	(7)
EBITDA	720	107		196		1,023
Depreciation and amortization	525	61	(2, 3, 4)	(2)	(14)	584
Operating income	195	46		198		439
Finance lease income	46	(46)	(1)	-		-
Equity loss	(10)	-		-		(10)
Foreign exchange gain	1	-		-		1
Gain on sale of assets	12	-		(12)	(22)	-
Earnings before interest and taxes	244	-		186		430
Net interest expense	256	-		-		256
Income tax recovery	(8)	-		34	(10, 11)	26
Net earnings (loss)	(4)	-		152		148
Non-controlling interests	29	-		-		29
Net earnings (loss) attributable to TransAlta shareholders	(33)	-		152		119
Preferred share dividends	38	-		-		38
Net earnings (loss) attributable to common shareholders	(71)	-		152		81
Weighted average number of common shares outstanding in the year	264					264
Net earnings per share attributable to common shareholders	(0.27)					0.31

M54  TRANSALTA CORPORATION

Financial Instruments

Financial instruments are used for proprietary trading purposes and to manage our exposure to interest rates, commodity prices, and currency fluctuations, as well as other market risks. We currently use physical and financial swaps, forward sale and purchase contracts, futures contracts, foreign exchange contracts, interest rate swaps, and options to achieve our risk management objectives. Some of our physical commodity contracts have been entered into and are held for the purposes of meeting our expected purchase, sale or usage requirements (“own use”) and as such, are not considered financial instruments, and are not recognized as a financial asset or financial liability. Other physical commodity contracts that are not held for normal purchase or sale requirements and derivative financial instruments are recognized on the Consolidated Statements of Financial Position and are accounted for using the fair value method of accounting. The initial recognition of fair value and subsequent changes in fair value can affect reported earnings in the period the change occurs if hedge accounting is not elected. Otherwise, changes in fair value will generally not affect earnings until the financial instrument is settled.

Some of our financial instruments and physical commodity contracts qualify for, and are recorded under, hedge accounting rules. The accounting for those contracts for which we have elected to apply hedge accounting depends on the type of hedge. Our financial instruments are categorized as fair value hedges, cash flow hedges, net investment hedges, or non-hedges. These categories and their associated accounting treatments are explained in further detail below.

For all types of hedges, we test for effectiveness at the end of each reporting period to determine if the instruments are performing as intended and hedge accounting can still be applied. The financial instruments we enter into are designed to ensure that future cash inflows and outflows are predictable. In a hedging relationship, the effective portion of the change in the fair value of the hedging derivative does not impact net earnings, while any ineffective portion is recognized in net earnings.

We have certain contracts in our portfolio that, at their inception, do not qualify for, or we have chosen not to elect to apply, hedge accounting. For these contracts, we recognize in net earnings mark-to-market gains and losses resulting from changes in forward prices compared to the price at which these contracts were transacted. These changes in price alter the timing of earnings recognition, but do not necessarily determine the final settlement amount received. The fair value of future contracts will continue to fluctuate as market prices change.

The fair value of derivatives traded by the Corporation that are not traded on an active exchange, or extend beyond the time period for which exchange-based quotes are available, are determined using valuation techniques or models.

Fair Value Hedges

Fair value hedges are used to offset the impact of changes in the fair value of fixed rate long-term debt caused by variations in market interest rates. We use interest rate swaps in our fair value hedges.

In a fair value hedge, changes in the fair value of the hedging instrument (an interest rate swap, for example) are recognized in risk management assets or liabilities, and the related gains or losses are recognized in net earnings. The carrying amount of long-term debt subject to the hedge is adjusted for losses or gains associated with the hedged risk, with the corresponding amounts recognized in net earnings. As a result, only the net ineffectiveness is recognized in net earnings.

TRANSALTA CORPORATIONM55

Cash Flow Hedges

Cash flow hedges are categorized as project, foreign exchange, interest rate, or commodity hedges and are used to offset foreign exchange, interest rate, and commodity price exposures resulting from market fluctuations.

Foreign currency forward contracts are used to hedge foreign exchange exposures resulting from anticipated contracts and firm commitments denominated in foreign currencies, primarily related to capital expenditures.

Physical and financial swaps, forward sale and purchase contracts, futures contracts, and options are used primarily to offset the variability in future cash flows caused by fluctuations in electricity and natural gas prices. Foreign exchange forward contracts and cross-currency swaps are used to offset the exposures resulting from foreign-denominated long-term debt. Interest rate swaps are used to convert the fixed interest cash flows related to interest expense at debt to floating rates and vice versa.

In a cash flow hedge, changes in the fair value of the hedging instrument (a forward contract or financial swap, for example) are recognized in risk management assets or liabilities, and the related gains or losses are recognized in OCI. These gains or losses are subsequently reclassified from OCI to net earnings in the same period as the hedged forecast cash flows impact net earnings, and offset the losses or gains arising from the forecast transactions. For project hedges, the gains and losses reclassified from OCI are included in the carrying amount of the related PP&E.

When we do not elect hedge accounting, or when the hedge is no longer effective and does not qualify for hedge accounting, the gains or losses as a result of changes in prices, interest, or exchange rates related to these financial instruments are recorded in net earnings in the period in which they arise.

Net Investment Hedges

Foreign currency forward contracts and foreign-denominated long-term debt are used to hedge exposure to changes in the carrying values of our net investments in foreign operations that have a functional currency other than the Canadian dollar. Gains or losses on these instruments are recognized and deferred in OCI and reclassified to net earnings on the disposal of the foreign operation. We attempt to manage foreign exchange risk by matching foreign-denominated expenses with revenues, such as offsetting revenues from our U.S. operations with interest payments on our US dollar debt.

Non-Hedges

Financial instruments not designated as hedges are used for proprietary trading and to reduce commodity price, foreign exchange, and interest rate risks. Changes in the fair value of financial instruments not designated as hedges are recognized in risk management assets or liabilities, and the related gains or losses are recognized in net earnings in the period in which the change occurs.

Fair Values

The majority of fair values for our project, foreign exchange, interest rate, commodity hedges, and non-hedge derivatives are calculated using adjusted quoted prices from an active market or inputs validated by broker quotes. We may enter into commodity transactions involving non-standard features for which market-observable data is not available. These transactions are defined under IFRS as Level III instruments. Level III instruments incorporate inputs that are not observable from the market, and fair value is therefore determined using valuation techniques. Fair values are validated by using reasonably possible alternative assumptions as inputs to valuation techniques, and any material differences are disclosed in the notes to the financial statements. At Dec. 31, 2015, Level III instruments had a net asset carrying value of $542 million. Refer to the Critical Accounting Policies and Estimates section of this MD&A for further details regarding valuation techniques. Our risk management profile and practices have not changed materially from Dec. 31, 2014.

M56  TRANSALTA CORPORATION

2016 Financial Outlook

In consideration of low power prices in Alberta and the Pacific Northwest, anticipated lower cash interest, and higher distributions to non-controlling interest payments, the following table outlines our expectation on key financial targets for 2016:

Measure	Target
Comparable EBITDA	$990 million to $1,100 million
Comparable FFO	$755 million to $835 million
Comparable FCF	$250 million to $300 million
Dividend	$0.16 per share, 15 to 18 per cent payout of Comparable FCF

Market

For 2016, power prices in Alberta are expected to be comparable to 2015 as a result of persistent low natural gas prices, low demand growth, and the current level of supply. However, prices can vary based on supply and weather conditions. In the Pacific Northwest we expect power prices to be lower as well due to low natural gas prices. We do not have significant uncontracted positions in other jurisdictions.

Operations

Availability

Availability of our coal fleet in Canada is expected to be in the range of 87 to 89 per cent in 2016. Availability of our other generating assets (gas, renewables) generally exceeds 95 per cent.

Contracted Cash Flows

As a result of Alberta PPAs and long-term contracts, approximately 75 per cent of our capacity is contracted over the next two years. This is reduced to 65 per cent when our Alberta PPAs expire in 2017. More than half of our non-contracted generation is sold forward 12 to 18 months ahead of time using short-term physical or financial contracts, such that on an aggregated portfolio basis, depending on market conditions, we target being up to 90 per cent contracted for the upcoming calendar year. As at the end of 2015, approximately 87 per cent of our 2016 capacity was contracted. The average prices of our short-term physical and financial contracts for 2016 are approximately $50 per MWh in Alberta and approximately US$45 per MWh in the Pacific Northwest.

Fuel Costs

Mining costs at our Alberta coal mine are expected to decrease in 2016 due to effective cost control, and production improvements. Seasonal variations in coal costs at our Alberta mine are minimized through the application of standard costing. Coal costs for 2016, on a standard cost per tonne basis, are expected to be one to two per cent lower than 2015 unit costs.

In the Pacific Northwest, our U.S. Coal mine, adjacent to our power plant, is in the reclamation stage. Fuel at U.S. Coal is purchased primarily from external suppliers in the Powder River Basin and delivered by rail. The delivered cost of fuel per MWh for 2016 is expected to decrease by approximately three per cent due to lower diesel surcharge costs on coal deliveries.

The value of coal inventories is assessed for impairment at the end of each reporting period. If the inventory is impaired, further charges are recognized in net earnings.

Most of our generation from gas is sold under contract with pass-through provisions for fuel. For gas generation with no pass-through provision, we purchase natural gas from outside companies coincident with production, thereby minimizing our risk to changes in prices.

We closely monitor the risks associated with changes in electricity and input fuel prices on our future operations and, where we consider it appropriate, use various physical and financial instruments to hedge our assets and operations from such price risks.

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Energy Marketing

EBITDA from our Energy Marketing Segment is affected by prices and volatility in the market, overall strategies adopted, and changes in regulation and legislation. We continuously monitor both the market and our exposure to maximize earnings while still maintaining an acceptable risk profile. Energy Marketing historically contributes between $60 million to $80 million in gross margin.

Exposure to Fluctuations in Foreign Currencies

Our strategy is to minimize the impact of fluctuations in the Canadian dollar against the US dollar and Australian dollar by offsetting foreign-denominated assets with foreign-denominated liabilities and by entering into foreign exchange contracts. We also have foreign-denominated expenses, including interest charges, which partly offset our net foreign-denominated revenues.

Net Interest Expense

Net interest expense for 2016 is expected to be lower than in 2015, primarily due to higher capitalized interest and lower debt balance. However, changes in interest rates and in the value of the Canadian dollar relative to the US dollar can affect the amount of net interest expense incurred. Most of our debt is at fixed interest rates.

Liquidity and Capital Resources

We expect to maintain adequate available liquidity under our committed credit facilities. Free cash flows generated by the business should be sufficient to support the construction of the South Hedland project station in 2016.

Income Taxes

The effective tax rate on earnings, excluding non-comparable items for 2016, is expected to be approximately 10 to 15
 per cent, which is lower than the statutory tax rate of 26 per cent, due to changes in the amount of earnings between the jurisdictions in which pre-tax income is earned and the effect of certain deductions that do not fluctuate with earnings.

Capital Expenditures

Our major projects are focused on sustaining our current operations and supporting our growth strategy.

Growth and Major Project Expenditures

A summary of the significant growth and major projects that are in progress is outlined below:

	Total Project		2016	Target
	Estimated spend	Spent to date(1)	Estimated spend	completion date	Details
Project
South Hedland power station(2)	589	242	113	Q2 2017	150 MW combined cycle power plant
Solomon load bank facility(3)	5	2	3	Q2 2016	Installation of 20 MW load bank facility required to complete the Solomon power station
Transmission	Not applicable(4)		13	Ongoing	Regulated transmission that receives a return on investment
Total	594	244	129

(1) Represents amounts spent as of Dec. 31, 2015.

(2) Estimated project spend is AUD$570 million. Total estimated project spend is stated in CAD$ and includes estimated capital interest costs. The total estimated project spend may change due to fluctuation in foreign exchange rates.

(3) Includes certain natural gas conversion costs at the Solomon power station that will be recognized as a finance lease receivable. The total estimated project spend may change due to fluctuations in foreign exchange rates.

(4) Transmission projects are aggregated and develop on an ongoing basis. Consequently, discrete project spend is not available.

M58  TRANSALTA CORPORATION

Sustaining and Productivity Expenditures

A significant portion of our sustaining and productivity capital is planned major maintenance, which includes inspection, repair and maintenance of existing components, and the replacement of existing components. Planned major maintenance costs are capitalized as part of PP&E and are amortized on a straight-line basis over the term until the next major maintenance event. It excludes amounts for day-to-day routine maintenance, unplanned maintenance activities, and minor inspections and overhauls, which are expensed as incurred.

Our estimate for total sustaining and productivity capital is allocated among the following:

Category	Description	Spent in 2014	Spent in 2015	Expected spend in 2016
		Restated (1)
Routine capital	Capital required to maintain our existing generating capacity	135	101	100 - 105
Planned major maintenance	Regularly scheduled major maintenance	162	162	170 - 175
Mine capital	Capital related to mining equipment and land purchases	45	25	30 - 35
Finance leases	Payments on finance leases	10	13	15
Total sustaining capital excluding flood-recovery capital		352	301	315 - 330
Flood-recovery capital	Capital arising from the 2013 Alberta flood	9	4	15 - 20
Total sustaining capital		361	305	330 - 350
Productivity capital	Projects to improve power production efficiency and   corporate improvement initiatives	14	6	10 - 20
Total sustaining and productivity capital		375	311	340 - 370

The planned major maintenance for 2015 included $9 million associated with major maintenance at Poplar Creek, which was incurred prior to the close of the contractual restructuring. Our customer has assumed capital obligations of the facility arising after closing, and on an ongoing basis thereafter. Planned major outage for 2016 includes major turnaround of three units that we operate, and two that our partners operate. Our planned outage also includes significant work at our hydro facilities, including the Ghost river diversion and a stator/generator replacement.

Lost production as a result of planned major maintenance, excluding planned major maintenance for U.S. Coal, which is scheduled during a period of economic dispatching, is estimated as follows for 2016:

	Coal	Gas and Renewables	Total
GWh lost	945 - 955	135 - 145	1,080 - 1,100

Financing

Financing for these capital expenditures is expected to be provided by cash flow from operating activities. We have access to approximately $1.4 billion in liquidity, if required. The funds required for committed growth, sustaining capital, and productivity projects are not expected to be significantly impacted by the current economic environment.

Sustainable Development Targets

Our 2016 and longer-term sustainability targets support the long-term success of our business. Targets are set in line with business unit goals to manage key areas of concern for stakeholders and ultimately improve our environmental and social performance in these areas. We continue to evolve and adapt targets to focus on anticipated key areas of materiality to stakeholders. Targets are outlined below:

(1) Restated to include hydro life extension from growth capital expenditures to sustaining capital expenditures. Refer to the Current Accounting Changes section of this MD&A.

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	Financial	Annual Performance Status
1. Maintain our investment grade rating	Achieve and maintain investment grade credit metrics.	Consistent with 2015 target
2. Increase focus on FFO and EBITDA	Deliver comparable EBITDA and comparable FFO for 2016 in the range of $990 million to $1,100 million and $755 million to $835 million respectively	6-8 per cent improvement from 2015
	Power Generating Portfolio	Annual Performance Status
3. Grow asset portfolio	Deliver an average of $40 million to $60 million of additional EBITDA from growth projects	Consistent with 2015 target
4. Achieve top quartile performance in Canadian Coal	Continue to deliver 87 to 89 per cent availability in the segment	Consistent with 2015 target in respect of the segment
	Human and Intellectual	Annual Performance Status
5. Reduce safety incidents	Achieve an Injury Frequency Rate (IFR) below 0.70	22 per cent improvement over 2015 target of 0.75
6. Manage employee turnover	Maintain voluntary turnover percentage under eight percent	Consistent with 2015 target
7. Support employee development	Achieve 100 per cent completion of development plans for all high-potential employees at the top three levels of the organization	Consistent with 2015 target
8. Enhance the capability of TransAlta leaders	Complete the final three stages of our globally recognized leadership development project to ensure TransAlta’s top three tiers of leaders have the tools to successfully reposition and grow our business	New target
	Environmental	Annual Performance Status
9. Minimize fleet-wide environmental incidents	Keep recorded incidents (including spills and air infractions) below 13	28 per cent improvement over 2015 target (18)
10. Increase mine reclaimed acreage	Replace annual topsoil at Highvale Mine of 74 acres/year	Consistent with 2015 target (74 acres)
11. Utilize coal by-product	Sell a minimum of two million tonnes of coal by-product materials during the period 2015 to 2017	33 per cent achieved (long-term target)
12. Reduce air emissions	95 per cent reduction from 2005 levels of TransAlta coal facility NOx and SO2 emissions by 2030	Consistent with 2015 (long-term target)
13. Reduce GHG emissions	20 per cent reduction from 2005 levels of TransAlta coal facility GHG by 2021, or the equivalent of 7,000,000 tonnes, of CO2e per year	Consistent with 2015 target (long-term target)
	55 per cent reduction from 2005 levels of TransAlta coal facility GHG by 2030, or the equivalent of 19,700,000 tonnes, of CO2e per year	Consistent with 2015 target (long-term target)
	Local Communities	Annual Performance Status
14. Combine stakeholder engagement	Implement final Stakeholder Engagement Framework. In 2016 every business unit will use a single framework for stakeholder guidance	New target
15. Support youth education with community investment	50 per cent of total communitiy investment spending will be directed to supporting youth education	New target
16. Increase internal best practice Aboriginal engagement awareness	Work with our aboriginal communities to develop an online best practice guide for employees on working with and engaging with aboriginal communities	New target

M60 TRANSALTA CORPORATION

Governance and Risk Management

Our business activities expose us to a variety of risks and opportunities including, but not limited to, regulatory changes, rapidly changing market dynamics, and increased volatility in our key commodity markets. Our goal is to manage these risks and opportunities so that we are in position to develop our business and achieve our goals while remaining reasonably protected from an unacceptable level of risk or financial exposure. We use a multilevel risk management oversight structure to manage the risks and opportunities arising from our business activities, the markets in which we operate, and the political environments and structures with which we interface.

Governance

The key elements of our governance practices are:

§employees, management and the Board are committed to ethical business conduct, integrity and honesty;

§we have established key policies and standards to provide a framework for how we conduct our business;

§the Chair of our Board and all directors, other than our Chief Executive Officer (“CEO”) are independent;

§the Board is comprised of individuals with a mix of skills, knowledge, and experience that are critical for our business and our strategy;

§the effectiveness of the Board is achieved through annual evaluations and continuing education of our directors; and

§our management and Board facilitate and foster an open dialogue with shareholders and community stakeholders.

Commitment to ethical conduct is the foundation of our corporate governance model. We have adopted the following codes of conduct to guide our business decisions and everyday business activities:

§Corporate Code of Conduct, which applies to all employees and officers of TransAlta and its subsidiaries;

§Directors’ Code of Conduct;

§Finance Code of Ethics, which applies to all financial employees of the Corporation; and

§Energy Trading Code of Conduct, which applies to all of our employees engaged in energy marketing.

Our codes of conduct outline the standards and expectations we have for our employees, officers, and directors with respect to the protection and proper use of our assets. The codes also provide guidelines with respect to securing our assets, conflicts of interest, respect in the workplace, social responsibility, privacy, compliance with laws, insider trading, environment, health and safety, and our commitment to ethical and honest conduct. Our Corporate Code of Conduct goes beyond the laws, rules, and regulations that govern our business in the jurisdictions in which we operate; it outlines the principal business practices with which all employees must comply.

Our employees, officers, and directors are reminded annually about the importance of ethics and professionalism in their daily work, and must certify annually that they have reviewed and understand their responsibilities as set forth in the respective codes of conduct. This certification also requires our employees, officers, and directors to acknowledge that they have complied with the standards set out in the respective code during the last calendar year.

The Board provides stewardship of the Corporation and ensures that the Corporation establishes key policies and procedures for the identification, assessment, and management of principal risks and strategic plans. The Board monitors and assesses the performance and progress of the Corporation’s goals through candid and timely reports from the CEO and the senior management team. We have also established an annual evaluation process whereby our directors are provided with an opportunity to evaluate the Board, Board committees, individual directors, and the chair’s performance.

In order to allow the Board to establish and manage the financial, environmental, and social elements of our governance practices, the Board has established the Audit and Risk Committee (“ARC”), the Governance and Environment Committee (the “GEC”), and the Human Resources Committee (the “HRC”).

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The ARC, consisting of independent members of the Board, provides assistance to the Board in fulfilling its oversight responsibility relating to the integrity of our financial statements and the financial reporting process; the systems of internal accounting and financial controls; the internal audit function; the external auditors’ qualifications and terms and conditions of appointment, including remuneration; independence; performance and reports; and the legal and risk compliance programs as established by management and the Board. The ARC approves our Commodity and Financial Exposure Management policies and reviews quarterly Enterprise Risk Management (“ERM”) reporting.

The GEC is responsible for developing and recommending to the Board a set of corporate governance principles applicable to the Corporation and for monitoring the compliance with these principles. The GEC is also responsible for Board recruitment and for the nomination of directors to the Board and its committees. In addition, the GEC assists the Board in fulfilling its oversight responsibilities with respect to the Corporation’s monitoring of environmental, health and safety regulations and public policy changes and the establishment and adherence to environmental, health and safety practices, procedures and policies. The GEC also receives an annual report on the annual Corporate Code of Conduct certification process.

In regards to overseeing and seeking to ensure that the Corporation consistently achieves strong environment, health and safety (“EH&S”) performance, the GEC undertakes a number of actions that include: (i) receiving regular reports from management regarding environmental compliance, trends, and TransAlta’s responses; (ii) receiving reports and briefings on management’s initiatives with respect to changes in climate change legislation, policy developments as well as other draft initiatives and the potential impact such initiatives may have on our operations; (iii)  assessing the impact of the GHG policies implementation and other legislative initiatives on the Corporation’s business; (iv) reviewing with management the EH&S policies of the Corporation; (v) reviewing with management the health and safety practices implemented within the Corporation, as well as the evaluation and training processes put in place to address problem areas; (vi) receiving reports from management on the near-miss reporting program and discussing with management ways to improve the EH&S processes and practices; and (vi) reviewing the effectiveness of our response to EH&S issues and any new initiatives put in place to further improve the Corporation’s EH&S culture.

The HRC is empowered by the Board to review and approve key compensation and human resources policies of the Corporation that are intended to attract, recruit, retain, and motivate employees of the Corporation. The HRC also makes recommendations to the Board regarding the compensation of the Corporation’s executive officers, including the review and adoption of equity-based incentive compensation plans, the adoption of human resources policies which support human rights and ethical conduct, and the review and approval of executive management succession and development plans.

The responsibilities of other stakeholders within our risk management oversight structure are described below:

The CEO and senior management review key risks quarterly. Specific Trading Risk Management reviews are held monthly by the Commodity and Compliance Risk Committee, and weekly by the Managing Director Commodity Risk, the commercial Managing Directors in Trading and Marketing, and the Senior Vice-President Trading and Marketing.

The Investment Committee is chaired by our Chief Financial Officer and is comprised of the Chief Executive Officer, Chief Financial Officer, Chief Legal and Compliance Officer, and Chief Investment Officer. It reviews and approves all major capital expenditures including growth, productivity, life extensions, and major coal outages. Projects that are approved by the committee will then be put forward for approval by the Board, if required.

TransAlta is listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange and is subject to the governance regulations, rules, and standards applicable under both exchanges. Our corporate governance practices meet the following governance rules of the TSX and Canadian Securities Administrators: (i) Multilateral Instrument 52-109 - Certification of Disclosure in Issuers’ Annual and Interim Filings; (ii) Multilateral Instrument 52-110 - Audit Committees; (iii) National Policy 58-201 - Corporate Governance Guidelines; and (iv) National Instrument 58-101 - Disclosure of Corporate Governance Practices. As a “foreign private issuer” under U.S. securities laws, we are generally permitted to comply with Canadian corporate governance requirements. Additional information in regards to our governance practices can be found in our management proxy circular.

M62  TRANSALTA CORPORATION

Risk Controls

Our risk controls have several key components:

Enterprise Tone

We strive to foster beliefs and actions that are true to and respectful of our many stakeholders. We do this by investing in communities where we live and work, operating and growing sustainably, putting safety first, and being responsible to the many groups and individuals with whom we work.

Policies

We maintain a comprehensive set of enterprise-wide policies. These policies establish delegated authorities and limits for business transactions, as well as allow for an exception approval process. Periodic reviews and audits are performed to ensure compliance with these policies. All employees and directors are required to sign a corporate code of conduct on an annual basis.

Reporting

On a regular basis, residual risk exposures are reported to key decision makers including the Board, senior management, and the Risk Management Committee (“RMC”). Reporting to the RMC includes analysis of new risks, monitoring of status to risk limits, review of events that can affect these risks, and discussion and status of actions to minimize risks. This quarterly reporting provides for effective and timely risk management and oversight.

Whistleblower System

We have a process in place where employees, shareholders, or other stakeholders may anonymously report any potential ethical concerns. These concerns can be submitted confidentially and anonymously, either directly to the ARC or to TransAlta’s Ethics Helpline. All complaints are investigated and the ARC receives a report at every scheduled committee meeting on all findings. If the findings are urgent, they will be reported to the Chair of the Board immediately.

Value at Risk and Trading Positions

Value at risk (“VaR”) is one of the primary measures used to manage our exposure to market risk resulting from commodity risk management activities. VaR is calculated and reported on a daily basis. This metric describes the potential change in the value of our trading portfolio over a three-day period within a 95 per cent confidence level, resulting from normal market fluctuations.

VaR is a commonly used metric that is employed by industry to track the risk in commodity risk management positions and portfolios. Two common methodologies for estimating VaR are the historical variance/covariance and Monte Carlo approaches. We estimate VaR using the historical variance/covariance approach. An inherent limitation of historical variance/covariance VaR is that historical information used in the estimate may not be indicative of future market risk. Stress tests are performed periodically to measure the financial impact to the trading portfolio resulting from potential market events, including fluctuations in market prices, volatilities of those prices, and the relationships between those prices. We also employ additional risk mitigation measures. VaR at Dec. 31, 2015 associated with our proprietary commodity risk management activities was $5 million (2014 - $5 million). Refer to the Commodity Price Risk section of this MD&A for further discussion.

Risk Factors

Risk is an inherent factor of doing business. The following section addresses some, but not all, risk factors that could affect our future results and our activities in mitigating those risks. These risks do not occur in isolation, but must be considered in conjunction with each other.

For some risk factors we show the after-tax effect on net earnings of changes in certain key variables. The analysis is based on business conditions and production volumes in 2015. Each item in the sensitivity analysis assumes all other potential variables are held constant. While these sensitivities are applicable to the period and the magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances, or for a greater magnitude of changes. The changes in rates should also not be assumed to be proportionate to earnings in all instances.

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Volume Risk

Volume risk relates to the variances from our expected production. For example, the financial performance of our Hydro, Wind, and Solar operations are partially dependent upon the availability of their input resources in a given year. Where we are unable to produce sufficient quantities of output in relation to contractually specified volumes, we may be required to pay penalties or purchase replacement power in the market.

We manage volume risk by:

§     actively managing our assets and their condition through the generation segments in order to be proactive in plant maintenance so that our plants are available to produce when required;

§     monitoring water resources throughout Alberta to the best of our ability and optimizing this resource against real-time electricity market opportunities;

§     placing our facilities in locations that we believe to have adequate resources to generate electricity to meet the requirements of our contracts. However, we cannot guarantee that these resources will be available when we need them or in the quantities that we require; and

§     diversifying our fuels and geography as one way of mitigating regional or fuel-specific events.

The sensitivities of volumes to our net earnings are shown below:

Factor	Increase or decrease (%)	Approximate impact on net earnings
Availability/production	1	19

Generation Equipment and Technology Risk

There is a risk of equipment failure due to wear and tear, latent defect, design error or operator error, among other things, which could have a material adverse effect on the Corporation. Although our generation facilities have generally operated in accordance with expectations, there can be no assurance that they will continue to do so. Our plants are exposed to operational risks such as failures due to cyclic, thermal, and corrosion damage in boilers, generators, and turbines, and other issues that can lead to outages and increased volume risk. If plants do not meet availability or production targets specified in their PPA or other long-term contracts, we may be required to compensate the purchaser for the loss in the availability of production or record reduced energy or capacity payments. For merchant facilities, an outage can result in lost merchant opportunities. Therefore, an extended outage could have a material adverse effect on our business, financial condition, results of operations, or our cash flows.

As well, we are exposed to procurement risk for specialized parts that may have long lead times. If we are unable to procure these parts when they are needed for maintenance activities, we could face an extended period where our equipment is unavailable to produce electricity.

We manage our generation equipment and technology risk by:

§     operating our generating facilities within defined and proven operating standards that are designed to maximize the availability of our generating facilities for the longest period of time;

§     performing preventative maintenance on a regular basis;

§     adhering to a comprehensive plant maintenance program and regular turnaround schedules;

§     adjusting maintenance plans by facility to reflect the equipment type and age;

§     having sufficient business interruption coverage in place in the event of an extended outage;

§     having force majeure clauses in our thermal and other PPAs and other long-term contracts;

§     using proven technology in our generating facilities;

§     monitoring technological advances and evaluating their impact upon our existing generating fleet and related maintenance programs;,

§     negotiating strategic supply agreements with selected vendors to ensure key components are available in the event of a significant outage;

§     entering into long-term arrangements with our strategic supply partners to ensure availability of critical spare parts; and

§     developing a long-term asset management strategy with the objective of maximizing the life cycles of our existing facilities and/or replacement of selected generating assets.

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Commodity Price Risk

We have exposure to movements in certain commodity prices, including the market price of electricity and fuels used to produce electricity in both our electricity generation and proprietary trading businesses.

We manage the financial exposure associated with fluctuations in electricity price risk by:

§entering into long-term contracts that specify the price at which electricity, steam, and other services are provided;

§maintaining a portfolio of short-, medium-, and long-term contracts to mitigate our exposure to short-term fluctuations in commodity prices;

§purchasing natural gas coincident with production for merchant plants so spot market spark spreads are adequate to produce and sell electricity at a profit; and

§ensuring limits and controls are in place for our proprietary trading activities.

In 2015, we had approximately 90 per cent (2014 - 90 per cent) of production under short-term and long-term contracts and hedges. In the event of a planned or unplanned plant outage or other similar event, however, we are exposed to changes in electricity prices on purchases of electricity from the market to fulfill our supply obligations under these short- and long-term contracts.

We manage the financial exposure to fluctuations in the costs of fuels used in production by:

§entering into long-term contracts that specify the price at which fuel is to be supplied to our plants;

§hedging emissions costs by entering into various emission trading arrangements; and

§selectively using hedges, where available, to set prices for fuel.

In 2015, 66 per cent (2014 - 68 per cent) of our cost of gas used in generating electricity was contractually fixed or passed through to our customers and 100 per cent (2014 - 100 per cent) of our purchased coal costs were contractually fixed.

The sensitivities of price changes to our net earnings, assuming production consistent with 2015 and applying the contractual profile in place at Dec. 31, 2015 for 2016, are shown below:

Factor	Increase or decrease	Approximate impact on net earnings and cash flow
Electricity price - Canada	$ 1.00/MWh	2
Electricity price - U.S.	US$ 1.00/MWh	2
Natural gas price	$ 0.10/GJ	1

Actual variations in net earnings can vary from calculated sensitivities and may not be linear due to optimization opportunities, co-dependencies and cost mitigations, production, availability, and other factors.

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Coal Supply Risk

Having sufficient fuel available when required for generation is essential to maintaining our ability to produce electricity under contracts and for merchant sale opportunities. At our coal-fired plants, input costs, such as diesel, tires, the price and availability of mining equipment, the volume of overburden removed to access coal reserves, rail rates, and the location of mining operations relative to the power plants are some of the exposures in our mining operations. Additionally, the ability of the mines to deliver coal to the power plants can be impacted by weather conditions and labour relations. At U.S. Coal, interruptions at our suppliers’ mine, the availability of trains to deliver coal, and the financial viability of our coal suppliers could affect our ability to generate electricity.

We manage coal supply risk by:

§ensuring that the majority of the coal used in electrical generation in Alberta is from reserves permitted through coal rights we have purchased or for which we have long-term supply contracts, thereby limiting our exposure to fluctuations in the supply of coal from third parties. The coal used in generating activities in U.S. Coal is secured through long-term supply contracts;

§using longer-term mining plans to ensure the optimal supply of coal from our mines;

§sourcing the majority of the coal used at U.S. Coal under a mix of short-, medium-, and long-term contracts and from multiple mine sources to ensure sufficient coal is available at a competitive cost;

§contracting sufficient trains to deliver the coal requirements at U.S. Coal;

§ensuring coal inventories on hand at Canadian Coal and U.S. Coal are at appropriate levels for usage requirements;

§ensuring efficient coal handling and storage facilities are in place so that the coal being delivered can be processed in a timely and efficient manner;

§monitoring and maintaining coal specifications, carefully matching the specifications mined with the requirements of our plants;

§monitoring the financial viability of U.S. coal suppliers; and

§hedging diesel exposure in mining and transportation costs.

Environmental Compliance Risk

Environmental compliance risks are risks to our business associated with existing and/or changes in environmental regulations. New emission reduction objectives for the power sector are being established by governments in Canada and the U.S. We anticipate continued and growing scrutiny by investors relating to sustainability performance. These changes to regulations may affect our earnings by imposing additional costs on the generation of electricity, such as emission caps or tax, requiring additional capital investments in emission capture technology, or requiring us to invest in offset credits. It is anticipated that these compliance costs will increase due to increased political and public attention to environmental concerns.

We manage environmental compliance risk by:

§     seeking continuous improvement in numerous performance metrics such as emissions, safety, land and water impacts, and environmental incidents;

§     having an International Organization for Standardization and Occupational Health and Safety Assessment Series-based environmental health and safety management system in place that is designed to continuously improve performance;

§     committing significant experienced resources to work with regulators in Canada and the U.S. to advocate that regulatory changes are well designed and cost effective;

§     developing compliance plans that address how to meet or exceed emission standards for GHGs, mercury, SO2, and NOx, which will be adjusted as regulations are finalized;

§     purchasing emission reduction offsets;

§     investing in renewable energy projects, such as wind, solar and hydro generation;

§     investing in clean coal technology development, which potentially provides long-term promise for large emission reductions from fossil-fuel-fired generation; and

§     incorporating change-in-law provisions in contracts that allow recovery of certain compliance costs from our customers.

We strive to be in compliance with all environmental regulations relating to operations and facilities. Compliance with both regulatory requirements and management system standards is regularly audited through our performance assurance policy and results are reported quarterly to the Governance and Environment Committee.

M66  TRANSALTA CORPORATION

Credit Risk

Credit risk is the risk to our business associated with changes in the creditworthiness of entities with which we have commercial exposures. This risk results from the ability of a counterparty to either fulfill its financial or performance obligations to us or where we have made a payment in advance of the delivery of a product or service. The inability to collect cash due to us or to receive products or services may have an adverse impact upon our net earnings and cash flows.

As at Dec. 31, 2015, we have liquidity of $1.4 billion comprised of amounts not drawn under our committed credit facility and cash on hand, and have no current need to draw in 2016.

We manage our exposure to credit risk by:

§     establishing and adhering to policies that define credit limits based on the creditworthiness of counterparties, contract term limits, and the credit concentration with any specific counterparty;

§     requiring formal sign-off on contracts that include commercial, financial, legal, and operational reviews;

§     requiring security instruments, such as parental guarantees, letters of credit, and cash collateral that can be collected if a counterparty fails to fulfill its obligation or goes over its limits; and

§     reporting our exposure using a variety of methods that allow key decision-makers to assess credit exposure by counterparty. This reporting allows us to assess credit limits for counterparties and the mix of counterparties based on their credit ratings.

If established credit exposure limits are exceeded, we take steps to reduce this exposure, such as by requesting collateral, if applicable, or by halting commercial activities with the affected counterparty. However, there can be no assurances that we will be successful in avoiding losses as a result of a contract counterparty not meeting its obligations.

Our credit risk management profile and practices have not changed materially from Dec. 31, 2014. We had no material counterparty losses in 2015, and we are exposed to minimal credit risk for Alberta PPAs because under the terms of these arrangements, receivables are substantially all secured by letters of credit. We continue to keep a close watch on changes and trends in the market and the impact these changes could have on our energy trading business and hedging activities, and will take appropriate actions as required, although no assurance can be given that we will always be successful.

The following table outlines our maximum exposure to credit risk without taking into account collateral held or right of set-off, including the distribution of credit ratings, as at Dec. 31, 2015:

	Investment grade (Per cent)	Non-investment grade (Per cent)	Total (Per cent)	Total Amount
Trade and other receivables(1)	90	10	100	567
Long-term finance lease receivables(2)	39	61	100	775
Risk management assets(1)	100	-	100	1,095
Total				2,437
(1) Letters of credit and cash are the primary types of collateral held as security related to these amounts.
(2) Includes balance of $446 million attributable to one non-investment-grade customer. Risk of significant loss arising from this counterparty has been assessed as low in the near term but could increase to moderate in an environment of sustained low commodity prices over the mid-to-long term. The assessment takes into consideration the counterparty’s financial position, external rating asessments, and how services are provided in an area of the counterparty’s lower-cost operations, and TransAlta’s other credit risk management practices.

The maximum credit exposure to any one customer for commodity trading operations, including the fair value of open trading positions, is $44 million (2014 - $29 million).

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Currency Rate Risk

We have exposure to various currencies as a result of our investments and operations in foreign jurisdictions, the earnings from those operations, the acquisition of equipment and services and foreign-denominated commodities from foreign suppliers, and our US-dollar-denominated debt. Our exposures are primarily to the U.S. and Australian currencies. Changes in the values of these currencies in relation to the Canadian dollar may affect our earnings or the value of our foreign investments to the extent that these positions or cash flows are not hedged or the hedges are ineffective.

We manage our currency rate risk by establishing and adhering to policies that include:

§     hedging our net investments in foreign operations using a combination of foreign-denominated debt and financial instruments. Our strategy is to offset 90 to 100 per cent of all such foreign currency exposures. At Dec. 31, 2015, we have hedged approximately 93 per cent (2014 - 95 per cent) of our foreign currency net investment exposure, which we define to exclude net U.S. risk management assets;

§     offsetting earnings from our foreign operations as much as possible by using expenditures denominated in the same foreign currencies and financial instruments to hedge the balance of this exposure; and

§     entering into forward foreign exchange contracts to hedge future foreign-denominated receipts and expenditures, and all US-dollar-denominated debt outside of our net investment portfolio.

The sensitivity of our net earnings to changes in foreign exchange rates has been prepared using management’s assessment that an average four cent increase or decrease in the U.S. or Australian currencies relative to the Canadian dollar is a reasonable potential change over the next quarter, and is shown below:

Factor	Increase or decrease		Approximate impact on net earnings
Exchange rate		$0.04		2

Liquidity Risk

Liquidity risk relates to our ability to access capital to be used to engage in trading and hedging activities, capital projects, debt refinancing and payment of liabilities, capital structure, and general corporate purposes. Investment grade credit ratings support these activities and provide a more reliable and cost-effective means to access capital markets through commodity and credit cycles. Changes in credit ratings may also affect our ability and/or the cost of establishing normal course derivative or hedging transactions, including those undertaken by our Energy Marketing Segment. Counterparties enter into certain electricity and natural gas purchase and sale contracts for the purposes of asset-backed sales and proprietary trading. The terms and conditions of these contracts require the counterparties to provide collateral when the fair value of the obligation pursuant to these contracts is in excess of any credit limits granted. Downgrades in creditworthiness by certain credit rating agencies may challenge our ability to enter into these contracts or any ordinary course contract, decrease the credit limits granted, and increase the amount of collateral that may have to be provided. Certain existing contracts contain credit rating contingent clauses, that, when triggered, automatically increase costs under the contract or require additional collateral to be posted. Where the contingency is based on the lowest single rating, a one-level downgrade from a credit rating agency with an originally higher rating may not, however, trigger additional direct adverse impact.

We are focused on strengthening our financial position and flexibility and maintaining stable investment grade credit ratings with three rating agencies. Credit ratings issued for TransAlta, as well as the corresponding rating agency outlook, are set out in the Financial Capital section of this MD&A. Credit ratings are subject to revision or withdrawal at any time by the rating organization, and there can be no assurance that TransAlta’s credit ratings and the corresponding outlook will not be changed, resulting in adverse possible impacts identified above.

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We manage liquidity risk by:

§monitoring liquidity on trading positions;

§preparing and revising longer-term financing plans to reflect changes in business plans and the market availability of capital;

§reporting liquidity risk exposure for commodity risk management activities on a regular basis to the RMC, senior management, and the ARC;

§maintaining investment grade credit ratings; and

§maintaining sufficient undrawn committed credit lines to support potential liquidity requirements.

Interest Rate Risk

Changes in interest rates can impact our borrowing costs while the opposite impact will be seen on the capacity revenues we receive from our Alberta PPA plants. Changes in our cost of capital may also affect the feasibility of new growth initiatives.

We manage interest rate risk by establishing and adhering to policies that include:

·employing a combination of fixed and floating rate debt instruments; and

·     monitoring the mixture of floating and fixed rate debt and adjusting where necessary to ensure a continued efficient mixture of these types of debt.

At Dec. 31, 2015, approximately nine per cent (2014 - four per cent) of our total debt portfolio was subject to changes in floating interest rates through a combination of floating rate debt and interest rate swaps.

The sensitivity of changes in interest rates upon our net earnings is shown below:

Factor	Increase or decrease (%)		Approximate impact on net earnings
Interest rate		0.15		1

Project Management Risk

On capital projects, we face risks associated with cost overruns, delays, and performance.

We manage project risks by:

·     ensuring all projects are reviewed to see that established processes and policies are followed, risks have been properly identified and quantified, input assumptions are reasonable, and returns are realistically forecasted prior to senior management and Board of Directors approvals;

·     using consistent and disciplined project management methodology and processes;

·     performing detailed analysis of project economics prior to construction or acquisition and by determining our asset contracting strategy to ensure the right mix of contracted and merchant capacity prior to commencement of construction;

·     partnering with those who have previously been able to deliver projects economically and on budget,

·     developing and following through with comprehensive plans that include critical paths identified, key delivery points, and backup plans;

·     managing project closeouts so that any learnings from the project are incorporated into the next significant project,

·     fixing the price and availability of the equipment, foreign currency rates, warranties, and source agreements as much as is economically feasible prior to proceeding with the project; and

·     entering into labour agreements to provide security around cost and productivity.

Human Resource Risk

Human resource risk relates to the potential impact upon our business as a result of changes in the workplace. Human resource risk can occur in several ways:

·potential disruption as a result of labour action at our generating facilities,

·reduced productivity due to turnover in positions,

·inability to complete critical work due to vacant positions,

·failure to maintain fair compensation with respect to market rate changes, and

·reduced competencies due to insufficient training, failure to transfer knowledge from existing employees, or insufficient expertise within current employees.

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We manage this risk by:

§monitoring industry compensation and aligning salaries with those benchmarks,

§using incentive pay to align employee goals with corporate goals;

§monitoring and managing target levels of employee turnover; and

§ensuring new employees have the appropriate training and qualifications to perform their jobs.

In 2015, 54 per cent (2014 - 53 per cent) of our labour force was covered by 11 (2014 - 12) collective bargaining agreements. In 2015, two (2014 - four) agreements were renegotiated. We anticipate the successful negotiation of six collective agreements in 2016.

Regulatory and Political Risk

Regulatory and political risk describes the risk to our business associated with potential changes to the existing regulatory structures and the political influence upon those structures. This risk can come from market re-regulation, increased oversight and control, structural or design changes in markets, or other unforeseen influences. Market rules are often dynamic and we are not able to predict whether there will be any material changes in the regulatory environment or the ultimate effect of changes in the regulatory environment on our business. This risk includes the qualification of our renewable facilities in Alberta to the generation of tradable GHG allowances as part of the transition from the SGER to new regulation to be formulated to give effect to the Climate Leadership Plan, in 2018, as well as the influence of regulation on the value of allowances or credits generated.

We manage these risks systematically through our Legal and Regulatory groups and our Compliance program, which is reviewed periodically to ensure its effectiveness. We work with governments, regulators, electric system operators, and other stakeholders to resolve issues as they arise. We are actively monitoring changes to market rules and market design, and we engage in market-sponsored stakeholder engagement processes. Through these and other avenues, we engage in advocacy and policy discussions at a variety of levels. These stakeholder negotiations have allowed us to engage in proactive discussions with governments over the longer term.

International investments are subject to unique risks and uncertainties relating to the political, social, and economic structures of the respective country and such country’s regulatory regime. We mitigate this risk through the use of non-recourse financing and insurance.

Transmission Risk

Access to transmission lines and transmission capacity for existing and new generation are key in our ability to deliver energy produced at our power plants to our customers. The risks associated with the aging existing transmission infrastructure in markets in which we operate continue to increase because new connections to the power system are consuming transmission capacity quicker than it is being added by new transmission developments.

Reputation Risk

Our reputation is one of our most valued assets. Reputation risk relates to the risk associated with our business because of changes in opinion from the general public, private stakeholders, governments, and other entities.

We manage reputation risk by:

·     striving as a neighbour and business partner in the regions where we operate to build viable relationships based on mutual understanding leading to workable solutions with our neighbours and other community stakeholders,

·clearly communicating our business objectives and priorities to a variety of stakeholders on a routine basis,

·maintaining positive relationships with various levels of government,

·pursuing sustainable development as a longer-term corporate strategy,

·ensuring that each business decision is made with integrity and in line with our corporate values,

·communicating the impact and rationale of business decisions to stakeholders in a timely manner, and

·maintaining strong corporate values that support reputation risk management initiatives.

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Corporate Structure Risk

We conduct a significant amount of business through subsidiaries and partnerships. Our ability to meet and service debt obligations is dependent upon the results of operations of our subsidiaries and the payment of funds by our subsidiaries in the form of distributions, loans, dividends, or otherwise. In addition, our subsidiaries may be subject to statutory or contractual restrictions that limit their ability to distribute cash to us.

General Economic Conditions

Changes in general economic conditions impact product demand, revenue, operating costs, the timing and extent of capital expenditures, the net recoverable value of PP&E, financing costs, credit and liquidity risk, and counterparty risk.

Income Taxes

Our operations are complex and located in several countries. The computation of the provision for income taxes involves tax interpretations, regulations, and legislation that are continually changing. Our tax filings are subject to audit by taxation authorities. Management believes that it has adequately provided for income taxes as required by IFRS, based on all information currently available.

The Corporation is subject to changing laws, treaties, and regulations in and between countries. Various tax proposals in the countries we operate in could result in changes to the basis on which deferred taxes are calculated or could result in changes to income or non-income tax expense. There has recently been an increased focus on issues related to the taxation of multinational corporations. A change in tax laws, treaties, or regulations, or in the interpretation thereof, could result in a materially higher income or non-income tax expense that could have a material adverse impact on the Corporation.

The sensitivity of changes in income tax rates upon our net earnings is shown below:

Factor	Increase or decrease (%)	Approximate impact on net earnings
Tax rate	1		1

The effective tax rate on comparable earnings before income taxes, equity income, and other items for 2015 was 78 per cent
 (2014 — 19 per cent). The effective income tax rate can change depending on the mix of earnings from various countries and certain deductions that do not fluctuate with earnings.

Legal Contingencies

We are occasionally named as a party in various claims and legal proceedings that arise during the normal course of our business. We review each of these claims, including the nature of the claim, the amount in dispute or claimed, and the availability of insurance coverage. There can be no assurance that any particular claim will be resolved in our favour or that such claims may not have a material adverse effect on us.

Other Contingencies

We maintain a level of insurance coverage deemed appropriate by management. There were no significant changes to our insurance coverage during renewal of the insurance policies on December 31. Our insurance coverage may not be available in the future on commercially reasonable terms. There can be no assurance that our insurance coverage will be fully adequate to compensate for potential losses incurred. In the event of a significant economic event, the insurers may not be capable of fully paying all claims.

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Critical Accounting Policies and Estimates

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as accounting rules and guidance have changed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment relative to the circumstances existing in the business. Every effort is made to comply with all applicable rules on or before the effective date, and we believe the proper implementation and consistent application of accounting rules is critical.

However, not all situations are specifically addressed in the accounting literature. In these cases, our best judgment is used to adopt a policy for accounting for these situations. We draw analogies to similar situations and the accounting guidelines governing them, consider foreign accounting standards, and consult with our independent auditors about the appropriate interpretation and application of these policies. Each of the critical accounting policies involves complex situations and a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our consolidated financial statements.

Our significant accounting policies are described in Note 2 to our audited consolidated financial statements within this Annual Report. The most critical of these policies are those related to revenue recognition, financial instruments, valuation of PP&E and associated contracts, project development costs, useful life of PP&E, valuation of goodwill, leases, income taxes, employee future benefits, decommissioning and restoration provisions, and other provisions. Each policy involves a number of estimates and assumptions to be made about matters that are uncertain at the time the estimate is made. Different estimates, with respect to key variables used for the calculations, or changes to estimates, could potentially have a material impact on our financial position or results of operations.

We have discussed the development and selection of these critical accounting estimates with our ARC and our independent auditors. The ARC has reviewed and approved our disclosure relating to critical accounting estimates in this MD&A.

These critical accounting estimates are described as follows:

Revenue Recognition

The majority of our revenues are derived from the sale of physical power, leasing of power facilities, and from commodity risk management activities.

Revenues under long-term electricity and thermal sales contracts generally include one or more of the following components: fixed capacity payments for availability, energy payments for generation of electricity, incentives or penalties for exceeding or not meeting availability targets, excess energy payments for power generation above committed capacity, and ancillary services. Each of these components is recognized upon output, delivery, or satisfaction of contractually specific targets. Revenues from non-contracted capacity are comprised of energy payments, at market prices, for each MWh produced and are recognized upon delivery.

In certain situations, a long-term electricity or thermal sales contract may contain, or be considered, a lease. Where the terms and conditions of the contract result in the customer assuming the principal risks and rewards of ownership of the underlying asset, the contractual arrangement is considered a finance lease, which results in the recognition of finance lease income. Where we retain the principal risks and rewards, the contractual arrangement is an operating lease. Rental income, including contingent rents where applicable, is recognized over the term of the contract. Revenues associated with non-lease elements are recognized as goods or services revenues as outlined above.

Commodity risk management activities involve the use of derivatives such as physical and financial swaps, forward sales contracts, and futures contracts and options, to earn trading revenues and to gain market information. These derivatives are accounted for using fair value accounting when hedge accounting is not applied. The initial recognition of fair value and subsequent changes in fair value affect reported earnings in the period the change occurs. The fair values of instruments that remain open at the end of a reporting period represent unrealized gains or losses and are presented on the Consolidated Statements of Financial Position as risk management assets or liabilities.

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The determination of the fair value of commodity risk management contracts and derivative instruments is complex and relies on judgments concerning future prices, volatility, and liquidity, among other factors. Some of our derivatives are not traded on an active exchange or extend beyond the time period for which exchange-based quotes are available, requiring us to use internal valuation techniques or models.

Financial Instruments

The fair value of a financial instrument is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair values can be determined by reference to prices for instruments in active markets to which we have access. In the absence of an active market, we determine fair values based on valuation models or by reference to other similar products in active markets.

Fair values determined using valuation models require the use of assumptions. In determining those assumptions, we look primarily to external readily observable market inputs. However, if not available, we use inputs that are not based on observable market data.

Level Determinations and Classifications

The Level I, II, and III classifications in the fair value hierarchy utilized by the Corporation are defined below. The fair value measurement of a financial instrument is included in only one of the three levels, the determination of which is based on the lowest level input that is significant to the derivation of the fair value.

Level I

Fair values are determined using inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access. In determining Level I fair values, we use quoted prices for identically traded commodities obtained from active exchanges such as the New York Mercantile Exchange.

Level II

Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability.

Fair values falling within the Level II category are determined through the use of quoted prices in active markets, which in some cases are adjusted for factors specific to the asset or liability, such as basis, credit valuation, and location differentials. Our commodity risk management Level II financial instruments include over-the-counter derivatives with values based on observable commodity futures curves and derivatives with inputs validated by broker quotes or other publicly available market data providers. Level II fair values are also determined using valuation techniques, such as option pricing models and regression or extrapolation formulas, where the inputs are readily observable, including commodity prices for similar assets or liabilities in active markets, and implied volatilities for options.

In determining Level II fair values of other risk management assets and liabilities, we use observable inputs other than unadjusted quoted prices that are observable for the asset or liability, such as interest rate yield curves and currency rates. For certain financial instruments where insufficient trading volume or lack of recent trades exists, we rely on similar interest or currency rate inputs and other third-party information such as credit spreads.

Level III

Fair values are determined using inputs for the asset or liability that are not readily observable.

We may enter into commodity transactions for which market-observable data is not available. In these cases, Level III fair values are determined using valuation techniques such as the Black-Scholes, mark-to-forecast, and historical bootstrap models with inputs that are based on historical data such as unit availability, transmission congestion, demand profiles for individual non-standard deals and structured products, and/or volatilities and correlations between products derived from historical prices. We also have various contracts with terms that extend beyond a liquid trading period. As forward market prices are not available for the full period of these contracts, the value of these contracts is derived by reference to a forecast that is based on a combination of external and internal fundamental modelling, including discounting. As a result, these contracts are classified in Level III.

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We have a Commodity Exposure Management Policy (the “Policy”), which governs both the commodity transactions undertaken in our proprietary trading business and those undertaken to manage commodity price exposures in our generation business. The Policy defines and specifies the controls and management responsibilities associated with commodity trading activities, as well as the nature and frequency of required reporting of such activities.

Methodologies and procedures regarding commodity risk management Level III fair value measurements are determined by our risk management department. Level III fair values are calculated within our energy trading risk management system based on underlying contractual data as well as observable and non-observable inputs. Development of non-observable inputs requires the use of judgment. To ensure reasonability, system-generated Level III fair value measurements are reviewed and validated by the risk management and finance departments. Review occurs formally on a quarterly basis or more frequently if daily review and monitoring procedures identify unexpected changes to fair value or changes to key parameters.

The effect of using reasonably possible alternative assumptions as inputs to valuation techniques from which the Level III commodity risk management fair values are determined at Dec. 31, 2015 is an estimated upside of $156 million (2014 - $101 million upside) and downside of $211 million (2014 - $113 million) impact to the carrying value of the financial instruments. Fair values are stressed for volumes and prices. The amount of $125 million upside (2014 - $76 million upside) and $186 million downside (2014 - $92 million downside) in the stress values stems from a long-dated power sale contract in the Pacific Northwest that is designated as a cash flow hedge utilizing assumed power prices ranging from US$28 to US$45 for the period from 2018 to 2025, while the remaining amounts account for the rest of the portfolio. The variable volumes are stressed up and down one standard deviation from historically available production data. Prices are stressed for longer-term deals where there are no liquid market quotes using various internal and external forecasting sources to establish a high and a low price range.

Valuation of PP&E and Associated Contracts

At the end of each reporting period, we assess whether there is any indication that a PP&E or intangible asset is impaired. Impairment exists when the carrying amount of the asset or CGU to which it belongs exceeds its recoverable amount, which is the higher of fair value less costs of disposal and value in use.

Factors that could indicate that an impairment exists include: significant underperformance relative to historical or projected operating results; significant changes in the manner in which an asset is used or in our overall business strategy; or significant negative industry or economic trends. In some cases, these events are clear. However, in many cases, a clearly identifiable event indicating possible impairment does not occur. Instead, a series of individually insignificant events occur over a period of time leading to an indication that an asset may be impaired. This can be further complicated in situations where we are not the operator of the facility. Events can occur in these situations that may not be known until a date subsequent to their occurrence.

Our operations, the market, and business environment are routinely monitored, and judgments and assessments are made to determine whether an event has occurred that indicates a possible impairment. If such an event has occurred, an estimate is made of the recoverable amount of the PP&E or CGU to which it belongs. Recoverable amount is the higher of an asset’s fair value less costs of disposal and its value in use. Fair value is the price that would be received to sell an asset in an orderly transaction between market participants at the measurement date. In determining fair value less costs of disposal, information about third-party transactions for similar assets is used and if none is available, other valuation techniques, such as discounted cash flows, are used. Value in use is computed using the present value of management’s best estimates of future cash flows based on the current use and present condition of the asset. In estimating either fair value less costs of disposal or value in use using discounted cash flow methods, estimates and assumptions must be made about sales prices, cost of sales, production, fuel consumed, retirement costs, and other related cash inflows and outflows over the life of the facilities, which can range from 30 to 60 years. In developing these assumptions, management uses estimates of contracted and future market prices based on expected market supply and demand in the region in which the plant operates, anticipated production levels, planned and unplanned outages, and transmission capacity or constraints for the remaining life of the facilities. Appropriate discount rates reflecting the risks specific to the asset under review are used in the assessments. These estimates and assumptions are susceptible to change from period to period and actual results can, and often do, differ from the estimates, and can have either a positive or negative impact on the estimate of the impairment charge, and may be material.

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The impairment outcome can also be impacted by the determination of CGUs or groups of CGUs for asset and goodwill impairment testing. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets, and goodwill is allocated to each CGU or group of CGUs that is expected to benefit from the synergies of the acquisition from which the goodwill arose. The allocation of goodwill is reassessed upon changes in the composition of segments, CGUs, or groups of CGUs. In respect of determining CGUs, significant judgment is required to determine what constitutes independent cash flows between power plants that are connected to the same system. We evaluate the market design, transmission constraints, and the contractual profile of each facility, as well as our commodity price risk management plans and practices, in order to inform this determination. With regard to the allocation or re-allocation of goodwill, significant judgment is required to evaluate synergies and their impacts. Minimum thresholds also exist with respect to segmentation and internal monitoring activities. We evaluate synergies with regards to opportunities from combined talent and technology, functional organization and future growth potential, and we consider own performance measurement processes in making this determination.

As a result of our review in 2015 and other specific events, various analyses were run to assess the significance of possible impairment indicators. Refer to the Asset Impairment Charges and Reversals section of this MD&A for further details.

Impairment charges can be reversed in future periods if circumstances improve. No assurances can be given if any reversal will occur or the amount or timing of any such reversal.

Project Development Costs

Deferred project development costs include external, direct, and incremental costs that are necessary for completing an acquisition or construction project. These costs are recognized in operating expenses until construction of a plant or acquisition of an investment is likely to occur, there is reason to believe that future costs are recoverable, and that efforts will result in future value to us, at which time the costs incurred subsequently are included in PP&E or investments. The appropriateness of capitalization of these costs is evaluated each reporting period, and amounts capitalized for projects no longer probable of occurring are charged to net earnings.

Useful Life of PP&E

Each significant component of an item of PP&E is depreciated over its estimated useful life. A component is a tangible asset that can be separately identified as an asset and is expected to provide a benefit of greater than one year. Estimated useful lives are determined based on current facts and past experience, and take into consideration the anticipated physical life of the asset, existing long-term sales agreements and contracts, current and forecasted demand, the potential for technological obsolescence, and regulations. The useful lives of PP&E and depreciation rates used are reviewed at least annually to ensure they continue to be appropriate.

In 2015, depreciation and amortization expense per the Consolidated Statements of Cash Flows was $605 million (2014 - $595 million), of which $59 million (2014 - $56 million) relates to mining equipment and is included in fuel and purchased power.

As a result of the announcement of Alberta’s Climate Leadership Plan on Nov. 20, 2015, some of our coal plants may no longer operate as long as originally planned. We have not adjusted the useful life of these plants for depreciation, pending final ruling, and negotiations with the government in respect of compensation.

Valuation of Goodwill

We evaluate goodwill for impairment at least annually, or more frequently if indicators of impairment exist. If the carrying amount of a CGU or group of CGUs, including goodwill, exceeds the unit’s fair value, the excess represents a goodwill impairment loss. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets.

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As a result of the re-segmentation described in the Accounting Changes section of this MD&A, we re-allocated goodwill on a relative fair value basis. The Corporation allocated goodwill of the previous Canadian Renewables and Alberta Merchant group of CGUs to the Hydro and Wind and Solar segments and the previous U.S. operations goodwill to the Wind and Solar Segment on the basis of management’s allocations for monitoring and performance measurement purposes. There were no changes made to the Energy Marketing goodwill.

For purposes of the 2015 and 2014 annual goodwill impairment review, the Corporation determined the recoverable amounts of the test units by calculating the fair value less costs of disposal using discounted cash flow projections based on the Corporation’s long-range forecasts for the period extending to the last planned asset retirement in 2073. The resulting fair value measurement is categorized within Level III of the fair value hierarchy.

We reviewed the carrying amount of goodwill prior to year-end and determined that the fair values of the related CGUs or groups of CGUs to which goodwill relates, based on estimates of future cash flows, exceeded their carrying amounts, and no goodwill impairments existed.

Determining the fair value of the CGUs or group of CGUs is susceptible to changes from period to period as management is required to make assumptions about future cash flows, production and trading volumes, margins, and fuel and operating costs. Had assumptions been made that resulted in fair values of the CGUs or groups of CGUs declining by five per cent from current levels, there would not have been any impairment of goodwill.

Leases

In determining whether the Corporation’s PPAs and other long-term electricity and thermal sales contracts contain, or are, leases, management must use judgment in assessing whether the fulfillment of the arrangement is dependent on the use of a specific asset and the arrangement conveys the right to use the asset. For those agreements considered to contain, or be, leases, further judgment is required to determine whether substantially all of the significant risks and rewards of ownership are transferred to the customer or remain with TransAlta, to appropriately account for the agreement as either a finance or operating lease. These judgments can be significant to how we classify amounts related to the arrangement as either PP&E or as a finance lease receivable on the Consolidated Statements of Financial Position, and therefore the value of certain items of revenue and expense is dependent upon such classifications.

Income Taxes

In accordance with IFRS, we use the liability method of accounting for income taxes. Under the liability method, deferred income tax assets and liabilities are recognized on the differences between the carrying amounts of assets and liabilities and their respective income tax basis.

Preparation of the consolidated financial statements involves determining an estimate of, or provision for, income taxes in each of the jurisdictions in which we operate. The process also involves making an estimate of taxes currently payable and taxes expected to be payable or recoverable in future periods, referred to as deferred income taxes. Deferred income taxes result from the effects of temporary differences due to items that are treated differently for tax and accounting purposes. The tax effects of these differences are reflected in the Consolidated Statements of Financial Position as deferred income tax assets and liabilities. An assessment must also be made to determine the likelihood that our future taxable income will be sufficient to permit the recovery of deferred income tax assets. To the extent that such recovery is not probable, deferred income tax assets must be reduced. The reduction of the deferred income tax asset can be reversed if the estimated future taxable income improves. No assurances can be given if any reversal will occur or the amount or timing of any such reversal. Management must exercise judgment in its assessment of continually changing tax interpretations, regulations, and legislation to ensure deferred income tax assets and liabilities are complete and fairly presented. Differing assessments and applications than our estimates could materially impact the amount recognized for deferred income tax assets and liabilities. Our tax filings are subject to audit by taxation authorities. The outcome of some audits may change our tax liability, although we believe that we have adequately provided for income taxes in accordance with IFRS based on all information currently available. The outcome of pending audits is not known nor is the potential impact on the consolidated financial statements determinable.

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Deferred income tax assets of $71 million (2014 - $45 million) have been recorded on the Consolidated Statements of Financial Position as at Dec. 31, 2015. These assets primarily relate to net operating loss carryforwards. We believe there will be sufficient taxable income that will permit the use of these loss carryforwards in the tax jurisdictions where they exist.

Deferred income tax liabilities of $647 million (2014 - $434 million) have been recorded on the Consolidated Statements of Financial Position as at Dec. 31, 2015. These liabilities are comprised primarily of taxes on unrealized gains from risk management transactions and income tax deductions in excess of related depreciation of PP&E.

Employee Future Benefits

We provide selected pension and post-employment benefits to employees. The cost of providing these benefits is dependent upon many factors that result from actual plan experience and assumptions of future experience.

The liabilities for future benefits and associated pension costs included in annual compensation expenses are impacted by employee demographics, including age, compensation levels, employment periods, the level of contributions made to the plans, and earnings on plan assets.

Changes to the provisions of the plans may also affect current and future pension costs. Pension costs may also be significantly impacted by changes in key actuarial assumptions, including, for example, the discount rates used in determining the defined benefit obligation and the net interest cost on the net defined benefit liability. The discount rate used to estimate our obligation reflects high-quality corporate fixed income securities currently available and expected to be available during the period to maturity of the pension benefits.

The plan assets are comprised primarily of equity and fixed income investments. Fluctuations in the return on plan assets as a result of actual equity market returns and changes in interest rates may result in increased or decreased pension costs in future periods.

Decommissioning and Restoration Provisions

We recognize decommissioning and restoration provisions for PP&E in the period in which they are incurred if there is a legal or constructive obligation to reclaim the plant or site. The amount recognized as a provision is the best estimate of the expenditures required to settle the provision. Expected values are probability weighted to deal with the risks and uncertainties inherent in the timing and amount of settlement of many decommissioning and restoration provisions. Expected values are discounted at the risk-free interest rate adjusted to reflect the market’s evaluation of our credit standing.

As at Dec. 31, 2015, the decommissioning and restoration provisions recorded on the Consolidated Statements of Financial Position were $233 million (2014 - $305 million). We estimate the undiscounted amount of cash flow required to settle the decommissioning and restoration provisions is approximately $1.0 billion, which will be incurred between 2016 and 2073. The majority of these costs will be incurred between 2020 and 2050. Some of the facilities that are co-located with mining operations do not currently have any decommissioning obligations recorded as the obligations associated with the facilities are indeterminate at this time.

Sensitivities for the major assumptions are as follows:

Factor	Increase or decrease (%)	Approximate impact on net earnings
Discount rate	1		2
Undiscounted decommissioning and restoration provision	10		2

Other Provisions

Where necessary, we recognize provisions arising from ongoing business activities, such as interpretation and application of contract terms and force majeure claims. These provisions, and subsequent changes thereto, are determined using our best estimate of the outcome of the underlying event and can also be impacted by determinations made by third parties, in compliance with contractual requirements. The actual amount of the provisions that may be required could differ materially from the amount recognized.

TRANSALTA CORPORATION M77

Accounting Changes

A. Current Accounting Changes

I. Operating and Reportable Segments

In January 2015, we completed changes to our internal reporting to systematize allocations of certain costs to each fuel type within our Generation Segment. This permitted internal reports regularly provided to the chief operating decision maker to be presented at the disaggregated fuel type level. Accordingly, commencing with first quarter 2015 reporting, we consider the following distinct fuel types as reportable segments: Canadian Coal, U.S. Coal, Gas, Wind, and Hydro. Previously, these were collectively reported as the Generation Segment. Comparative results for 2014 have been restated to align with the re-segmentation: general expenditures of the Generation Segment were allocated to each fuel type segment based on estimated relative benefit derived from those expenditures. For the years ended Dec. 31, 2014 and 2013, $12 million and $7 million, respectively, in expenditures associated with certain functions were determined to benefit the broader organization and were reassigned to the Corporate Segment. For the years ended Dec. 31, 2014 and 2013, $1 million and $3 million, respectively, in expenditures were determined to benefit the Energy Marketing Segment and were reassigned to that segment.

We have exercised judgment in aggregating the Corporation’s Canadian gas and Australian gas operating segments together into a single reportable segment, Gas. The operating segments were determined to share the following similar economic characteristics: nature of revenue sources, level of contractedness, and customer assumption of fuel and regulatory compliance costs. In addition, the Canadian gas and Australian gas operating segments share substantial similarity in products (energy), processes (gas turbines), customers (industrial and regional utilities), and distribution methods (connection to grid or behind-the-fence generation). Commencing Sept. 1, 2015, the solar facilities acquired are included in the Wind and Solar Segment.

II. Change in Estimates - Useful Lives

During the first quarter, our subsidiary TA Cogen executed a new 15-year power supply contract with Ontario’s IESO for the Windsor facility, which is effective Dec. 1, 2016. Accordingly, the useful life of the Windsor facility was extended prospectively to Nov. 30, 2031. As a result, depreciation expense for the year ended Dec. 31, 2015 decreased by $8 million.

III. Inventory Reclassification

During the fourth quarter of 2015, we finalized changes to our accounting system to improve tracking and management of parts, materials, and supplies that are expected to be consumed in the production process. Previously, these items were comprised in other capital spare parts. As a result, approximately $116 million was reclassified to inventory in current assets from PP&E. We restated the Consolidated Statement of Financial Position as at Dec. 31, 2014 to similarly reclassify parts, materials, and supplies to inventory in the amount of $125 million.

IV. Restatement of a Prior Quarter

During the fourth quarter of 2015, we restated the statement of earnings of the first quarter of 2015, to increase non-comparable deferred tax expense by $47 million. As a result, net earnings attributable to common shareholders of the first quarter of 2015 has decreased from $7 million to a net loss of $40 million. The adjustment is due to the correction of the tax basis of an internally transferred asset as part of the reorganization of companies giving effect to the Transaction with TransAlta Renewables. Comparative information of the first quarter of 2015 presented in this document has been adjusted accordingly.

V. Restatement of Prior Year Sustaining Capital

During 2015, we restated the hydro life extension capital spend, previously classified as growth capital, to sustaining capital, in order to align with the presentation of expenditures associated with projects of a similar nature made in 2015. As a result of the change, routine capital of the Hydro Segment increased by $19 million, $8 million, and $10 million, respectively, for 2014, 2013, and the fourth quarter of 2014. In consequence, comparable FCF was also reduced by these amounts for each period. Comparable FCF per share was adjusted accordingly.

M78  TRANSALTA CORPORATION

B. Future Accounting Changes

Accounting standards that have been previously issued by the IASB, but are not yet effective and have not been applied by the Corporation, include:

I. IFRS 9 Financial Instruments

In July 2014, on completion of the impairment phase of the project to reform accounting for financial instruments and replace IAS 39 Financial Instruments: Recognition and Measurement, the IASB issued the final version of IFRS 9 Financial Instruments. IFRS 9 includes guidance on the classification and measurement of financial assets and financial liabilities, impairment of financial assets (i.e., recognition of credit losses), and a new hedge accounting model.

Under the classification and measurement requirements for financial assets, financial assets must be classified and measured at either amortized cost or at fair value through profit or loss or through OCI, depending on the basis of the entity’s business model for managing the financial asset and the contractual cash flow characteristics of the financial asset.

The classification requirements for financial liabilities are unchanged from IAS 39. IFRS 9 requirements address the problem of volatility in net earnings arising from an issuer choosing to measure certain liabilities at fair value and require that the portion of the change in fair value due to changes in the entity’s own credit risk be presented in OCI, rather than within net earnings.

The new general hedge accounting model is intended to be simpler and more closely focus on how an entity manages its risks, replaces the IAS 39 effectiveness testing requirements with the principle of an economic relationship, and eliminates the requirement for retrospective assessment of hedge effectiveness.

The new requirements for impairment of financial assets introduce an expected loss impairment model that requires more timely recognition of expected credit losses. IAS 39 impairment requirements are based on an incurred loss model where credit losses are not recognized until there is evidence of a trigger event.

IFRS 9 is effective for annual periods beginning on or after Jan. 1, 2018, with early application permitted. We are assessing the impact of adopting this standard on our consolidated financial statements.

II. IFRS 15 Revenue from Contracts with Customers

In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers, which replaces existing revenue recognition guidance with a single comprehensive accounting model. The model specifies that an entity recognizes revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. In 2015, the effective date of IFRS 15 was delayed by one year. IFRS 15 is now effective for annual reporting periods beginning on or after Jan. 1, 2018 with early application permitted. We are assessing the impact of adopting this standard on our consolidated financial statements.

III. IFRS 16 Leases

In January 2016, the IASB issued IFRS 16 Leases, which replaces the current IFRS guidance on leases. Under current guidance, lessees are required to determine if the lease is a finance or operating lease, based on specified criteria. Finance leases are recognized on the statement of financial position, while operating leases are not. Under IFRS 16, lessees must recognize a lease liability and a right-of-use asset for virtually all lease contracts. An optional exemption to not recognize certain short-term leases and leases of low value can be applied by lessees. For lessors, the accounting remains essentially unchanged.

IFRS 16 is effective for annual periods beginning on or after Jan. 1, 2019, with early application permitted if IFRS 15 is also applied at the same time.

We are assessing the impact of adopting this standard on our consolidated financial statements.

TRANSALTA CORPORATION M79

Fourth Quarter

Consolidated Financial Highlights

Three months ended Dec. 31	2015	2014
		Restated(1)
Revenues	595	718
Comparable EBITDA(2)	268	301
Net earnings (loss) attributable to common shareholders	(7)	148
Comparable net earnings attributable to common shareholders(2)	3	46
Comparable funds from operations(2)	243	225
Cash flow from operating activities	118	250
Comparable FCF(2)	174	97
Net earnings (loss) per share attributable to common shareholders, basic and diluted	(0.02)	0.54
Comparable net earnings per share(2)	0.01	0.17
Comparable FFO per share(2)	0.86	0.82
Comparable FCF per share(2)	0.61	0.35
Dividends declared per common share	0.18	0.18

Financial Highlights

■    Comparable EBITDA for the fourth quarter of 2015 decreased by $33 million to $268 million compared to the same period in 2014, including an adjustment of $59 million to provisions. Excluding this non-cash adjustment relating mostly to prior year events, EBITDA would have been $327 million in the fourth quarter. This strong performance resulted from reductions to our operating expenses at our Highvale mine, solid availability in Canadian Coal, and the addition of wind, solar, and gas pipeline assets over the last year. Prices in Alberta averaged $21 per MWh during the fourth quarter of 2015, compared to $30 per MWh in the same period in 2014. Our strategy of being highly contracted generally limited the impacts of lower prices in Alberta, except for the wind and hydro facilities.

■    Comparable FFO increased by $18 million for the three months ended Dec. 31, 2015 compared to the same period in 2014, as it excluded the effects of the provision adjustment discussed above.

■Fourth quarter comparable net earnings attributable to common shareholders was $3 million ($0.01 per share), down from comparable net earnings of $46 million ($0.17 per share) in the same quarter last year, due to lower comparable EBITDA described above, higher depreciation expense associated with the increased asset base, and an increase in non-controlling interest due to the Transaction with TransAlta Renewables.

■Reported net loss attributable to common shareholders was $7 million for the fourth quarter ($0.02 net loss per share) compared to net earnings of $148 million ($0.54 per share) for the same period in 2014. The differences between comparable and reported net earnings are mainly due to decreases (2014 - increases) in the fair value of de-designated and economic hedges at U.S. Coal. Reported net earnings of the fourth quarter of 2014 also included a large reversal of a writedown of deferred tax assets.

(1) Restated to deduct hydro life extension capital expenditures from comparable FCF. Refer to the Current Accounting Changes section of this document.

(2) These items are not defined under IFRS.  Presenting these items from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results.  Refer to the Comparable Funds from Operations and Comparable Free Cash Flow and Earnings and Other Measures on a Comparable Basis sections of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.

M80TRANSALTA CORPORATION

Segmented Operational Results

Comparable EBITDA and operational performance for the business is as follows:

Three months ended Dec. 31	2015		2014
Availability (%)(1)	92.9		93.2
Adjusted availability (%)(2)	88.4		93.2
Production (GWh)(1)	11,107		12,207
Comparable EBITDA
Canadian Coal	67		119
U.S. Coal	23		19
Gas	90		80
Wind and Solar	65		56
Hydro	19		20
Energy Marketing	26		26
Corporate	(22	)	(19	)
Total comparable EBITDA	268		301

■Canadian Coal:  Comparable EBITDA decreased $52 million to $67 million in the fourth quarter of 2015 compared to the same period in 2014. Fourth quarter EBITDA included a $59 million adjustment to provisions relating mostly to force majeure events from the periods between 2013 to 2015. Excluding this adjustment, 2015 EBITDA would have been $126 million for the quarter, slightly better than last year.

■U.S. Coal:  Comparable EBITDA was $23 million in the fourth quarter compared to $19 million for the same period in 2014. The current quarter benefited from a full quarter of contract with Puget Sound Energy and of the appreciation of the US dollar in 2015.

■Gas:  Comparable EBITDA was $90 million in the fourth quarter of 2015, an increase of $10 million, compared to the same period in 2014, primarily due to additional revenues from the Australian natural gas pipeline and the positive impact of the strengthening of the US dollar on a certain contract in Australia.

■Wind and Solar:  Comparable EBITDA increased in the fourth quarter to $65 million compared to $56 million for the same period in 2014, primarily due to the contribution from assets acquired in 2015 and the impact of strengthening of the U.S. dollar on U.S. facilities.

■Hydro:   Comparable EBITDA was consistent in the fourth quarter with the same period in 2014.

■Energy Marketing: Comparable EBITDA was consistent with the same period in 2014; with gross margin in both periods exceeded our quarterly expectations of $15 to $20 million per quarter.

■Corporate:  Higher costs in our Corporate Segment is due to a provision associated with vacant leased office space following the corporate restructuring.

(1) Availability and production includes all generating assets under generation operations that we operate and finance leases and excludes hydro assets and equity investments.  Production includes all generating assets, irrespective of investment vehicle and fuel type.

(2) Adjusted for economic dispatching at U.S. Coal.

TRANSALTA CORPORATION  M81

Availability and Production

Availability for the three months ended Dec. 31, 2015 was consistent with the same period in 2014. Lower production for the three months ended Dec. 31, 2015 compared to the same period in 2014 is primarily due to market curtailments at Canadian Coal.

Comparable Funds from Operations and Comparable Free Cash Flow

Comparable FFO per share and comparable FCF per share are calculated as follows using the weighted average number of common shares outstanding during the period.

Three months ended Dec. 31	2015	2014
		Restated(1)
Cash flow from operating activities	118	250
Change in non-cash operating working capital balances	76	(23)
Cash flow from operations before changes in working capital	194	227
Adjustments
MSA settlement payment	31	-
Decrease in finance lease receivable	15	1
Payment of restructuring costs	11	-
Maintenance costs related to Alberta flood of 2013, net of insurance recoveries	(10)	(5)
Other non-comparable items	2	2
Comparable FFO	243	225
Deduct:
Sustaining capital	(52)	(97)
Insurance recoveries of sustaining capital expenditures	23	3
Dividends paid on preferred shares	(11)	(13)
Distributions paid to subsidiaries’ non-controlling interests	(29)	(21)
Comparable FCF	174	97
Weighted average number of common shares outstanding in the period	284	275
Comparable FFO per share	0.86	0.82
Comparable FCF per share	0.61	0.35

(1) Restated to include hydro life extension from Growth capital expenditures to sustaining capital expenditures. Refer to the Current Accounting Changes section of this document.

M82TRANSALTA CORPORATION

A reconciliation of comparable EBITDA to comparable FFO is as follows:

Three months ended Dec. 31	2015	2014
Comparable EBITDA	268	301
Unrealized gains from risk management activities	(6)	(12)
Interest expense	(63)	(58)
Provisions	76	-
Current income tax expense	(7)	(9)
Realized foreign exchange gain	1	14
Decommissioning and restoration costs settled	(4)	(5)
Non-cash gain on curtailment and amendment gain on empoyee future benefits	(8)	-
Capital insurance recoveries on Canadian Coal facility	(5)	-
Other non-cash items	(9)	(6)
Comparable FFO	243	225

Comparable FFO increased by $18 million in the fourth quarter of 2015 compared to the same period in 2014 as lower EBITDA in the quarter includes the non-cash impact of our adjustment to provisions.

Comparable FCF for the three months ended Dec. 31, 2015 increased $77 million to $174 million compared to the same period in 2014, primarily due to the increase in comparable FFO and a decrease in sustaining capital, partially offset by higher distributions paid to our subsidiaries’ non-controlling interests as a result of the reduction of our interest in TransAlta Renewables.

TRANSALTA CORPORATION M83

Earnings on a Comparable Basis

During the fourth quarter of 2015, a restatement was made to tax expense impacting earnings reported in the first quarter of 2015. Refer to the Current Accounting Changes section of this MD&A for a description of this change.

The adjustments made to calculate comparable earnings for the three months ended Dec. 31, 2015 and 2014 are as follows. References are to the subsequent reconciliation table.

Three months ended Dec. 31			2015		2014
Reference number	Adjustment	Segment and fuel type
Reclassifications:
1	Finance lease income used as a proxy for operating revenue	Gas	17		13
2	Decrease in finance lease receivable used as a proxy for operating revenue and depreciation	Gas	15		1
3	Reclassification of mine depreciation from fuel and purchased power	Canadian Coal	16		15
4	Reclassification of comparable gain on sale of property, plant, and equipment that is included in depreciation	Canadian Coal	-		1
Adjustments (increasing (decreasing) earnings to arrive at comparable results):
5	Impacts to revenue associated with certain de-designated and economic hedges	U.S. Coal	13		(47	)
6	Restructuring expense (recovery)	Canadian Coal	2		-
		Corporate	2		-
7	Economic hedges of non-controlling interest in intercompany foreign exchange contracts	Unassigned	8		-
8	Net tax effect on comparable adjustments subject to tax	Unassigned	-		20
9	(Reversal) accrual of writedown of deferred income tax assets	Unassigned	6		(68	)
10	Maintenance costs related to the Alberta flood of 2013, net of insurance recoveries	Hydro	(10	)	(5	)
11	Costs related to TAMA Transmission bid	Corporate	-		5
12	Asset impairment charges (reversals)	Gas	(1	)	(5	)
13	Non-comparable portion of insurance recovery received	Hydro	(18	)	(3	)
14	Foreign exchange on California claim	Unassigned	-		2
15	Non-comparable gain on sale of assets	Equity Investments	-		(1	)
16	Non-comparable item attributable to non-controlling interest	Unassigned	7		-
17	Gain on Poplar Creek contract restructuring	Gas	1		-

M84TRANSALTA CORPORATION

A reconciliation of comparable results to reported results for the three months ended Dec. 31, 2015 and 2014 is as follows:

	Three months ended Dec. 31, 2015						Three months ended Dec. 31, 2014
	Reported	Comparable reclassifications		Comparable adjustments		Comparable total	Reported	Comparable reclassifications		Comparable adjustments		Comparable total
Revenues	595	32	(1, 2)	13	(5)	640	718	14	(1, 2)	(47)	(5)	685
Fuel and purchased power	272	(16)	(3)	-		256	268	(15)	(3)	-		253
Gross margin	323	48		13		384	450	29		(47)		432
Operations, maintenance, and administration	109	-		10	(10)	119	138	-		-	(10, 11)	138
Asset impairment charges (reversals)	(1)	-		1	(12)	-	(5)	-		5	(12)	-
Restructuring provision	4	-		(4)	(6)	-	-	-		-		-
Taxes, other than income taxes	8	-		-		8	8	-		-		8
Gain on sale of assets	-	-		-		-	-	(1)	(4)	-		(1)
Net other operating (income) losses	(29)	-		18	(13)	(11)	(17)	-		3	(13)	(14)
EBITDA	232	48		(12)		268	326	30		(55)		301
Depreciation and amortization	136	31	(2, 3)	-		167	136	17	(2, 3, 4)	-		153
Operating income	96	17		(12)		101	190	13		(55)		148
Finance lease income	17	(17)	(1)	-		-	13	(13)	(1)	-		-
Foreign exchange gain (loss)	3	-		8	(7)	11	7	-		2	(14)	9
Gain (loss) on sale of assets	(1)	-		1	(17)	-	1	-		(1)	(15)	-
Earnings before interest and taxes	115	-		(3)		112	211	-		(54)		157
Net interest expense	69	-		-		69	62	-		-		62
Income tax expense (recovery)	(4)	-		(6)	(8,9)	(10)	(26)	-		48	(8, 9)	22
Net earnings (loss)	50	-		3		53	175	-		(102)		73
Non-controlling interests	46	-		(7)	(16)	39	14	-		-		14
Net earnings (loss) attributable to TransAlta shareholders	4	-		10		14	161	-		(102)		59
Preferred share dividends	11	-		-		11	13	-		-		13
Net earnings (loss) attributable to common shareholders	(7)	-		10		3	148	-		(102)		46
Weighted average number of common shares outstanding in the period	284					284	275					275
Net earnings (loss) per share attributable to common shareholders	(0.02)					0.01	0.54					0.17

TRANSALTA CORPORATION M85

Selected Quarterly Information

Our results are seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are usually incurred in the spring and fall when electricity prices are expected to be lower, as electricity prices generally increase in the peak winter and summer months in our main markets due to increased heating and cooling loads. Margins are also typically impacted in the second quarter due to the volume of hydro production resulting from spring runoff and rainfall in the Pacific Northwest, which impacts production at U.S. Coal. Typically, hydro facilities generate most of their electricity and revenues during the spring months when melting snow starts feeding watersheds and rivers. Inversely, wind speeds are historically greater during the cold winter months and lower in the warm summer months.

	Q1 2015	Q2 2015	Q3 2015	Q4 2015
	*Restated
Revenue	593	438	641	595
Comparable EBITDA	275	183	219	268
Comparable FFO	211	160	126	243
Net earnings (loss) attributable to common shareholders	(40)	(131)	154	(7)
Comparable net earnings (loss) attributable to common shareholders	26	(44)	(33)	3
Net earnings (loss) per share attributable to common shareholders, basic and diluted	(0.14)	(0.47)	0.55	(0.02)
Comparable net earnings (loss) per share, basic and diluted	0.09	(0.16)	(0.12)	0.01
	Q1 2014	Q2 2014	Q3 2014	Q4 2014
Revenue	775	491	639	718
Comparable EBITDA	310	213	212	301
Comparable FFO	238	154	145	225
Net earnings (loss) attributable to common shareholders	49	(50)	(6)	148
Comparable net earnings (loss) attributable to common shareholders	47	(12)	(13)	46
Net earnings (loss) per share attributable to common shareholders, basic and diluted	0.18	(0.18)	(0.03)	0.54
Comparable net earnings (loss) per share, basic and diluted	0.17	(0.04)	(0.05)	0.17
* See Accounting Changes note for restatement.

M86TRANSALTA CORPORATION

Basic and diluted earnings per share attributable to common shareholders and comparable earnings per share are calculated each period using the weighted average common shares outstanding during the period. As a result, the sum of the earnings per share for the four quarters making up the calendar year may sometimes differ from the annual earnings per share.

Comparable net earnings, comparable EBITDA, and comparable FFO are generally higher in the first and fourth quarters due to higher demand associated with winter cold in the markets in which we operate and lower planned outages. Market volatility can also impact quarterly contributions from our Energy Marketing Segment, as the first quarter of 2014 benefitted from exceptional weather conditions in northeastern North America. Following sales of non-controlling interest in TransAlta Renewables in the second quarter of 2014 and 2015 and the fourth quarter of 2015, an increasing portion of earnings is attributable to non-controlling interests.

Revenue is impacted by market and operational factors listed above, and by changes in future power prices in the Pacific Northwest, which cause de-designated and economic hedges in the region to fluctuate in value. These hedges significantly depreciated in the fourth quarter of 2013, in the second quarter of 2014, and in the first half of 2015, and significantly increased in value over the second half of 2014 and in the third quarter of 2015. Revenue of the fourth quarter of 2015 was also impacted by a significant increase to a provision related to Force Majeure events associated mostly to prior years.

Net earnings attributable to common shareholders have also been impacted by the following events:

■gain on disposal of assets, following the Poplar Creek contract restructuring in the third quarter of 2015;

■MSA provision in the third quarter of 2015;

■writedown of deferred tax assets in the first quarter of 2015 and a recovery in the third quarter of 2015;

■change in income tax rates in Alberta in the second quarter of 2015; and

■deferred income tax impacts of the Transaction in the first and second quarters of 2015.

TRANSALTA CORPORATION M87

Disclosure Controls and Procedures

Management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Disclosure controls and procedures refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934, as amended (“Exchange Act”) are recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the U.S. Securities and Exchange Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding our required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating and implementing possible controls and procedures.

There has been no change in the internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of Dec. 31, 2015, the end of the period covered by this report, our disclosure controls and procedures were effective at a reasonable assurance level.

M88TRANSALTA CORPORATION