EX-13.2 3 a17-7040_1ex13d2.htm EX-13.2

Exhibit 13.2

TRANSALTA CORPORATION

Management’s Discussion and Analysis

Table of Contents

Forward-Looking Statements | M2 | Financial Instruments | M58
Additional IFRS Measure and Non-IFRS Measures | M3 | 2017 Financial Outlook | M60
Business Model | M4 | Governance and Risk Management | M64
Highlights | M5 | Critical Accounting Policies and Estimates | M75
Reconciliation of Non-IFRS Measures | M8 | Accounting Changes | M82
Comparable Results | M12 | Fourth Quarter | M84
Competitive Forces | M26 | Reconciliation of Non-IFRS Measures | M86
TransAlta’s Capitals | M28 | Selected Quarterly Information | M90
Other Consolidated Analysis | M50 | Disclosure Controls and Procedures | M91

This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with our audited annual 2016 consolidated financial statements and our Annual Information Form for the year ended Dec. 31, 2016. 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, 2016. 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 March 2, 2017. 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.

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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 2017 Financial Outlook section and Sustainable Development Targets 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 relating to the dispositions of assets and the completion of sale transactions including the disposition of our interest in the Wintering Hills wind facility; expectations related to future earnings and cash flow from operating and contracting activities (including estimates of full-year 2017 comparable earnings before interest, taxes, depreciation, and amortization (“EBITDA”), comparable funds from operations (“FFO”), comparable free cash flow (“FCF”), and expected sustaining capital expenditures); expectations in respect of financial ratios and targets and the timing associated with meeting such 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 2017 and beyond; expected governmental regulatory regimes and legislation (including the Government of Alberta’s Climate Leadership Plan) and proposed regulations to discontinue over time the use of technologies that our coal-fired plants currently utilize, 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 expected results and impact of the recently signed Off-Coal Agreement (“OCA”) and Memorandum of Understanding (“MOU”) with the Government of Alberta on our business and financial performance; the outcome of discussions with the Government of Alberta in relation to 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; our share of offer control in the Province of Alberta after the expiry of the Power Purchase Arrangements (“PPAs”) at the end of 2020; 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, including the impact of the anticipated elimination of current excess system capacity and future growth in Alberta driven by the retirement of coal units over the next 15 years; expected financing of our capital expenditures; the anticipated financial impact of increased carbon price (including under the existing Specified Gas Emitters Regulation) (“SGER”) in Alberta; expectations in respect of our environmental initiatives; 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;

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expectations relating to the performance of TransAlta Renewables Inc.’s (“TransAlta Renewables”) assets; expectations regarding our continued ownership of common shares of TransAlta Renewables; the refinancing our upcoming debt maturities over the next two years by raising $700 million to $900 million of debt secured by contracted cash flows; expectations regarding our de-leveraging strategy, including applying a portion of our free cash flow over the next four years to reduce debt expectations in respect of our community initiatives; impacts of future IFRS standards; and amendments or interpretations by accounting standard setters prior to initial adoption of those standards.

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 and our ability to manage such attacks; 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 2017 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, 2016, 2015, and 2014. 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 on a Comparable Basis sections of this MD&A for additional information.

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Business Model

Our Business

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(1) of net generating capacity and use a broad range of generation fuels that include coal, natural gas, water, sun, and wind. We are Canada’s largest generator of wind power and the largest generator of renewable energy in Alberta. 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, using our expertise, scale, and diversified fuel mix to capitalize on opportunities in our core markets and growing in areas where our competitive advantages can be employed. Our values are grounded in accountability, integrity, safety, respect for people, innovation and loyalty which together 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 five 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 strategic growth of cash flows over the long term. The transition from coal to natural gas and renewables provides significant opportunity for future growth. In 2013, we launched TransAlta Renewables, our sponsored vehicle to own contracted gas and renewable assets.

(1) We measure capacity as net maximum capacity (see Glossary of Key Terms for definition of this and other key terms), which is consistent with industry standards. Capacity figures represent capacity owned and in operation unless otherwise stated, and reflect the basis of consolidation of underlying assets.

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Highlights

Consolidated Financial Highlights

Year ended Dec. 31 |  | 2016 | 2015 |  | 2014
Revenues |  | 2,397 | 2,267 |  | 2,623
Comparable EBITDA(1) |  | 1,145 | 945 |  | 1,036
Net earnings (loss) attributable to common shareholders |  | 117 | (24 | ) | 141
Comparable net earnings (loss) attributable to common shareholders(1) |  | 34 | (48 | ) | 68
Comparable FFO(1) |  | 763 | 740 |  | 762
Cash flow from operating activities |  | 744 | 432 |  | 796
Comparable FCF(1) |  | 299 | 315 |  | 280
Net earnings (loss) per share attributable to common shareholders, basic and diluted |  | 0.41 | (0.09 | ) | 0.52
Comparable net earnings (loss) per share(1) |  | 0.12 | (0.17 | ) | 0.25
Comparable FFO per share(1) |  | 2.65 | 2.64 |  | 2.79
Comparable FCF per share(1) |  | 1.04 | 1.13 |  | 1.03
Dividends declared per common share |  | 0.20 | 0.72 |  | 0.72
As at Dec. 31 |  | 2016 | 2015 |  | 2014
Total assets |  | 10,996 | 10,947 |  | 9,833
Total debt(2) |  | 4,056 | 4,441 |  | 4,013
Total long-term liabilities |  | 5,116 | 5,704 |  | 4,504

In 2016, comparable EBITDA increased by $200 million to $1,145 million compared to 2015, with all segments other than U.S. Coal delivering improved results over last year. The improved results throughout the year are a result of positive contributions from renewable assets acquired in the second half of 2015, solid performance from our gas and renewables portfolios, cost reduction initiatives across the fleet implemented in 2015, and the reversal of the $80 million provision relating to our Keephills 1 outage in 2013. Our highly contracted profile and hedging strategy mitigated the impact of lower prices during the year. The decreased contribution from U.S. Coal is attributable to unfavourable market conditions in the Pacific Northwest. Last year’s comparable EBITDA was impacted by a $59 million increase in our provision relating to the Keephills 1 outage in 2013.

Comparable FFO increased by $23 million to $763 million. The increase was lower than the increase in comparable EBITDA, primarily due to the non-cash impact of the provision relating to our Keephills 1 outage, which was approximately $139 million of the change in comparable EBITDA.

Reported net earnings attributable to common shareholders was $117 million ($0.41 net earnings per share) compared to a net loss of $24 million ($0.09 net loss per share) in 2015. Comparable net earnings attributable to common shareholders was $34 million ($0.12) net earnings per share), up from a comparable net loss of $48 million ($0.17 net loss per share) in 2015. The improvements year-over-year primarily relate to contributions from assets we acquired in 2015, solid performance from the renewable asset portfolio, and cost reduction initiatives. The Keephills 1 outage provision reversal also favourably impacted 2016 net earnings. Our reported net earnings attributable to common shareholders in 2016 was impacted positively by the Mississauga cogeneration recontracting ($48 million(3)) and negatively by the Wintering Hills wind facility impairment ($21 million(3)). Changes in the fair value of de-designated and economic hedges at U.S. Coal also had a negative impact on our reported net earnings of $17 million(3,4) in 2016 (2015 – $38 million(3,4)).

(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 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) Total debt includes current portion, amounts due under credit facilities, long-term debt, tax equity, and finance lease obligations net of cash.

(3) Net of related income tax expense.

(4) Hedge accounting could not be applied to certain contracts, and accordingly, the mark-to-market on these contracts impacted reported 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.

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2015’s reported net loss also included the gain on the Poplar Creek restructuring ($192 million(1)), the cost of the settlement with the Market Surveillance Administrator (the “MSA”) ($55 million(1)), and a $95 million income tax expense related to an internal reorganization. These items are not included in our comparable net earnings.

The decrease of $385 million in total debt, net of cash, is primarily due to repayment of debt using the proceeds received from the sale to TransAlta Renewables of economic interests in the Canadian Assets (as defined below) completed in January 2016, free cash flows generated by the business, and the strengthening of the Canadian dollar.

Significant Events

At the beginning of the year we had three strategic objectives: first, work with the Government of Alberta to develop a plan that would facilitate our transition from coal to natural gas and renewables; second, continue to improve our financial condition and flexibility by reducing our total outstanding corporate debt and better aligning our debt maturities with the life of our assets; and third, commit ourselves to achieving our operational goals (health and safety, equipment availability, and environment). We made significant progress on our strategic objectives in 2016. Our results for the year demonstrate our financial and operating stability. Specifically, we:

§ | Entered into an OCA with the Government of Alberta (the “Government”) for the cessation of coal-fired emissions at our Alberta coal facilities. Under the terms of the OCA, we will receive transition payments of approximately $37.4 million (our net share) from 2017 to 2030 for a total amount of approximately $524 million.
§ | Entered into an MOU with the Government to collaborate and co-operate in the development of a policy framework to facilitate coal-to-gas conversions and renewable electricity development, and ensure existing generation is able to effectively participate in a future capacity market.
§ | Signed a new contract for our Mississauga cogeneration facility effective Jan. 1, 2017, with Ontario’s Independent Electricity System Operator (“IESO”) and terminated our existing contract early. The new contract, which expires in December 2018, provides us with monthly payments totalling approximately $209 million over the term of the contract with no delivery obligations. The new contract will allow us to reduce operational costs for this facility while retaining flexibility to operate the facility should economic conditions permit.
§ | Completed the sale to TransAlta Renewables of an economic interest in the Sarnia cogeneration facility and two renewable energy facilities (collectively, the “Canadian Assets”) for aggregate proceeds valued at $540 million. 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. Proceeds were used to reduce TransAlta’s indebtedness. In November 2016, the economic interest was converted to direct ownership of the Canadian Assets by TransAlta Renewables.
§ | Repositioned our capital structure through two non-recourse bond issuances in 2016, through our subsidiaries, New Richmond Wind L.P. and TAPC Holdings L.P., in the amounts of $159 million and $202.5 million, respectively. These financings have aligned debt maturities with the contracted cash flows of the underlying assets.
§ | Announced the sale of our 51 per cent interest in the 88 MW Wintering Hills merchant wind facility, located in Alberta, for approximately $61 million in early 2017. The sale provides us with near-term liquidity, increases our financial flexibility, and reduces our merchant exposure in Alberta.
§ | Continued to advance the construction of the South Hedland power project. We expect the project to be delivered on schedule and on budget in mid-2017.
§ | Announced a reduction of our dividend to $0.16 per common share on an annualized basis from $0.72 previously. As a result, our annual dividend is approximately $46 million, down from $205 million, thereby increasing our financial flexibility.

These actions, coupled with our solid financial performance in 2016, are expected to build the financial capacity and flexibility to address upcoming debt maturities and capitalize on growth opportunities in gas-fired and renewable generation that are expected to arise as Alberta transitions from its reliance on coal-fired generation to cleaner sources of power generation.

(1) Net of related income tax expense.

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Reconciliation of Non-IFRS Measures

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.

Comparable Funds from Operations and Comparable Free Cash Flow

Comparable FFO is an important metric as it provides a proxy for the amount of cash generated from operating activities before changes in working capital, and provides the ability to evaluate cash flow trends more readily in comparison with results from prior periods. Comparable FCF is an important metric as it represents the amount of cash generated by our business, before changes in working capital, that is available to invest in growth initiatives, make scheduled principal repayments on debt, repay maturing debt, pay common share dividends, or repurchase common shares. Changes in working capital are excluded so as to not distort comparable FFO and comparable FCF with changes that we consider temporary in nature, reflecting, among other things, the impact of seasonal factors and the timing of capital projects. Comparable FFO per share and comparable FCF per share are calculated using the weighted average number of common shares outstanding during the period.

The table below reconciles our cash flow from operating activities to our comparable FFO.

Year ended Dec. 31 |  | 2016 |  | 2015 |  | 2014
Cash flow from operating activities |  | 744 |  | 432 |  | 796
Change in non-cash operating working capital balances |  | (73) |  | 242 |  | (73)
Cash flow from operations before changes in working capital |  | 671 |  | 674 |  | 723
Adjustments |  |  |  |  |  |
MSA settlement payment and California claim |  | 25 |  | 31 |  | 33
Decrease in finance lease receivable |  | 57 |  | 23 |  | 3
Restructuring costs |  | 4 |  | 19 |  | -
Maintenance costs related to Alberta flood of 2013, net of insurance recoveries |  | - |  | (9) |  | 1
Other |  | 6 |  | 2 |  | 2
Comparable FFO |  | 763 |  | 740 |  | 762
Deduct: |  |  |  |  |  |
Sustaining capital |  | (272) |  | (305) |  | (361)
Insurance recoveries of sustaining capital expenditures |  | 1 |  | 25 |  | 4
Dividends paid on preferred shares |  | (42) |  | (46) |  | (41)
Distributions paid to subsidiaries’ non-controlling interests |  | (151) |  | (99) |  | (84)
Comparable FCF |  | 299 |  | 315 |  | 280
Weighted average number of common shares outstanding in the year |  | 288 |  | 280 |  | 273
Comparable FFO per share |  | 2.65 |  | 2.64 |  | 2.79
Comparable FCF per share |  | 1.04 |  | 1.13 |  | 1.03

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Reconciliation of Comparable EBITDA and Comparable Net Earnings

Comparable EBITDA is a widely adopted valuation metric and an important metric for management that represents our core business profitability. Interest, taxes, and depreciation and amortization are not included, as differences in accounting, treatments may distort our core business results. A reconciliation of reported results to comparable results for the year ended Dec. 31, 2016, is as follows:

Year ended Dec. 31 |  | 2016
|  | Reported |  | Comparable reclassifications |  | Comparable adjustments |  | Comparable total
Revenues |  | 2,397 |  | 123 | (1, 2) | 26 | (5) | 2,546
Fuel and purchased power |  | 963 |  | (65) | (3) | (14) | (9) | 884
Gross margin |  | 1,434 |  | 188 |  | 40 |  | 1,662
Operations, maintenance, and administration |  | 489 |  | - |  | - |  | 489
Asset impairment |  | 28 |  | - |  | (28) | (8) | -
Restructuring |  | 1 |  | - |  | (1) | (10) | -
Taxes, other than income taxes |  | 31 |  | - |  | - |  | 31
Net other operating (income) losses |  | (194) |  | - |  | 191 | (9) | (3)
EBITDA |  | 1,079 |  | 188 |  | (122) |  | 1,145
Depreciation and amortization |  | 601 |  | 122 | (2, 3, 4) | (46) | (9) | 677
Operating income |  | 478 |  | 66 |  | (76) |  | 468
Finance lease income |  | 66 |  | (66) | (1) | - |  | -
Foreign exchange loss |  | (5) |  | - |  | (3) | (17) | (8)
Gain on sale of assets |  | 4 |  | - |  | (4) | (15) | -
Earnings (loss) before interest and taxes |  | 543 |  | - |  | (83) |  | 460
Net interest expense |  | 229 |  | - |  | - |  | 229
Income tax expense |  | 38 |  | - |  | 4 | (18, 19, 20, 21) | 42
Net earnings |  | 276 |  | - |  | (87) |  | 189
Non-controlling interests |  | 107 |  | - |  | (4) | (23) | 103
Net earnings (loss) attributable to TransAlta shareholders |  | 169 |  | - |  | (83) |  | 86
Preferred share dividends |  | 52 |  | - |  | - |  | 52
Net earnings (loss) attributable to common shareholders |  | 117 |  | - |  | (83) |  | 34
Weighted average number of common shares outstanding in the year |  | 288 |  |  |  |  |  | 288
Net earnings (loss) per share attributable to common shareholders |  | 0.41 |  |  |  |  |  | 0.12

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

Year ended Dec. 31 |  | 2015
|  | Reported |  | Comparable reclassifications |  | Comparable adjustments |  | Comparable total
Revenues |  | 2,267 |  | 81 | (1, 2) | 60 | (5) | 2,408
Fuel and purchased power |  | 1,008 |  | (62) | (3) | - |  | 946
Gross margin |  | 1,259 |  | 143 |  | 60 |  | 1,462
Operations, maintenance, and administration |  | 492 |  | - |  | 9 | (6) | 501
Asset impairment reversals |  | (2) |  | - |  | 2 | (8) | -
Restructuring |  | 22 |  | - |  | (22) | (10) | -
Taxes, other than income taxes |  | 29 |  | - |  | - |  | 29
Net other operating (income) losses |  | 25 |  | - |  | (38) | (7, 11) | (13)
EBITDA |  | 693 |  | 143 |  | 109 |  | 945
Depreciation and amortization |  | 545 |  | 85 | (2, 3, 4) | - |  | 630
Operating income |  | 148 |  | 58 |  | 109 |  | 315
Finance lease income |  | 58 |  | (58) | (1) | - |  | -
Foreign exchange gain |  | 4 |  | - |  | 8 | (17) | 12
Gain on sale of assets |  | 262 |  | - |  | (262) | (12) | -
Earnings (loss) before interest and taxes |  | 472 |  | - |  | (145) |  | 327
Net interest expense |  | 251 |  | - |  | - |  | 251
Income tax expense |  | 105 |  | - |  | (107) | (18,19,20,21) | (2)
Net earnings |  | 116 |  | - |  | (38) |  | 78
Non-controlling interests |  | 94 |  | - |  | (14) | (23) | 80
Net earnings (loss) attributable to TransAlta shareholders |  | 22 |  | - |  | (24) |  | (2)
Preferred share dividends |  | 46 |  | - |  | - |  | 46
Net earnings (loss) attributable to common shareholders |  | (24) |  | - |  | (24) |  | (48)
Weighted average number of common shares outstanding in the year |  | 280 |  |  |  |  |  | 280
Net loss per share attributable to common shareholders |  | (0.09) |  |  |  |  |  | (0.17)

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

Year ended Dec. 31 |  | 2014
|  | Reported |  | Comparable reclassifications |  | Comparable adjustments |  | Comparable total
Revenues |  | 2,623 |  | 52 | (1, 2) | (54) | (5) | 2,621
Fuel and purchased power |  | 1,092 |  | (56) | (3) | - |  | 1,036
Gross margin |  | 1,531 |  | 108 |  | (54) |  | 1,585
Operations, maintenance, and administration |  | 542 |  | - |  | (6) | (6, 13) | 536
Asset impairment reversal |  | (6) |  | - |  | 6 | (8) | -
Taxes, other than income taxes |  | 29 |  | - |  | - |  | 29
Gain on sale of assets |  | - |  | (1) | (4) | - |  | (1)
Net other operating (income) losses |  | (14) |  | - |  | (1) | (7, 14) | (15)
EBITDA |  | 980 |  | 109 |  | (53) |  | 1,036
Depreciation and amortization |  | 538 |  | 60 | (2, 3, 4) | - |  | 598
Operating income |  | 442 |  | 49 |  | (53) |  | 438
Finance lease income |  | 49 |  | (49) | (1) | - |  | -
Foreign exchange gain |  | - |  | - |  | 4 | (16) | 4
Gain on sale of assets |  | 2 |  | - |  | (2) | (15) | -
Earnings before interest and taxes |  | 493 |  | - |  | (51) |  | 442
Net interest expense |  | 254 |  | - |  | - |  | 254
Income tax expense |  | 7 |  | - |  | 23 | (18, 20, 22) | 30
Net earnings |  | 232 |  | - |  | (74) |  | 158
Non-controlling interests |  | 50 |  | - |  | (1) | (23) | 49
Net earnings attributable to TransAlta shareholders |  | 182 |  | - |  | (73) |  | 109
Preferred share dividends |  | 41 |  | - |  | - |  | 41
Net earnings (loss) attributable to common shareholders |  | 141 |  | - |  | (73) |  | 68
Weighted average number of common shares outstanding in the year |  | 273 |  |  |  |  |  | 273
Net earnings per share attributable to common shareholders |  | 0.52 |  |  |  |  |  | 0.25

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The adjustments made to calculate comparable earnings for the years ended Dec. 31, 2016, 2015 and 2014 are as follows. References are to the previous reconciliation tables.

Year ended Dec. 31 |  |  | 2016 | 2015 | 2014
Reference number | Adjustment | Segment | Financial Statement line item |  |  |
Reclassifications: |  |  |  |  |
1 | Finance lease income used as a proxy for operating revenue | Australian Gas | Revenues | 52 | 49 | 42
|  | Canadian Gas | Revenues | 14 | 9 | 7
2 | Decrease in finance lease receivable used as a proxy for operating revenue and depreciation | Canadian Gas | Revenues | 54 | 23 | 4
|  | Australian Gas | Revenues | 3 | - | (1)
3 | Reclassification of mine depreciation from fuel and purchased power | Canadian Coal | Fuel and purchased power | 65 | 62 | 56
4 | Reclassification of comparable gain on sale of property, plant, and equipment that is included in depreciation | Canadian Coal | Gain on sale of assets | - | - | 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 | Revenues | 26 | 60 | (54)
6 | Maintenance costs related to the Alberta flood of 2013, net of insurance recoveries | Hydro | OM&A | - | (9) | 1
7 | Non-comparable portion of insurance recovery received | Hydro | Net other operating (income) losses | - | (18) | (4)
8 | Asset impairment charges (reversals) | U.S. Coal | Asset impairment (reversals) | - | (2) | (5)
|  | Canadian Gas | Asset impairment (reversals) | - | - | (1)
|  | Wind and Solar | Asset impairment (reversals) | 28 | - | -
9 | Mississauga recontracting(1) | Canadian Gas | Net other operating (income) losses | (131) | - | -
10 | Restructuring expense | Canadian Coal | Restructuring | - | 11 | -
|  | U.S. Coal | Restructuring | - | 1 | -
|  | Canadian Gas | Restructuring | - | 1 | -
|  | Hydro | Restructuring | - | - | -
|  | Energy Marketing | Restructuring | - | 3 | -
|  | Corporate | Restructuring | 1 | 6 | -
11 | MSA settlement | Energy Marketing | Net other operating (income) losses | - | 56 | -
12 | Gain on Poplar Creek contract restructuring | Canadian Gas | Gain on sale of assets | - | (262) | -
13 | Costs related to TAMA Transmission bid | Corporate | OM&A | - | - | 5
14 | California claim | Energy Marketing | Net other operating (income) losses | - | - | 5
15 | Non-comparable gain on sale of assets | Equity Investments | Gain on sale of assets | - | - | (2)
|  | Corporate | Gain on sale of assets | (4) | - | -
16 | Foreign exchange on California claim | Unassigned | Foreign exchange gain (loss) | - | - | 4
17 | Economic hedges of non-controlling interest in intercompany foreign exchange contracts | Unassigned | Foreign exchange gain (loss) | (3) | 8 | -
18 | Net tax effect on comparable adjustments subject to tax | Unassigned | Income tax expense (recovery) | 2 | 48 | 18
19 | Deferred income tax rate adjustment | Unassigned | Income tax expense (recovery) | 1 | 20 | -
20 | Reversal of writedown of deferred income tax assets | Unassigned | Income tax expense (recovery) | (10) | (56) | (5)
21 | Income tax expense related to temporary difference on investment in subsidiary | Unassigned | Income tax expense (recovery) | 3 | 95 | -
22 | Income tax recovery related to sale of investment | Unassigned | Income tax expense (recovery) | - | - | (36)
23 | Non-comparable items attributable to non-controlling interest | Unassigned | Non-controlling interests | 4 | 14 | 1

(1) Reported in net other operating (income) loss of ($191 million), depreciation and amortization of ($46 million), and fuel and purchased power of ($14 million).

TRANSALTA CORPORATION M11

Comparable Results

Discussion of Comparable FFO and Comparable FCF

The table below provides a reconciliation of our comparable EBITDA to our comparable FFO and comparable FCF.

Year ended Dec. 31 | 2016 |  | 2015 |  | 2014 |
Comparable EBITDA | 1,145 |  | 945 |  | 1,036 |
Provisions | (85 | ) | 73 |  | - |
Unrealized losses from risk management activities | 3 |  | 1 |  | 4 |
Interest expense | (219 | ) | (230 | ) | (236 | )
Current income tax expense | (23 | ) | (19 | ) | (33 | )
Realized foreign exchange gain | 1 |  | 17 |  | 11 |
Decommissioning and restoration costs settled | (23 | ) | (24 | ) | (16 | )
Gain on curtailment and amendment of employee future benefit plans | - |  | (8 | ) | - |
Capital insurance recoveries | (1 | ) | (7 | ) | - |
Other non-cash items | (35 | ) | (8 | ) | (4 | )
Comparable FFO | 763 |  | 740 |  | 762 |
Deduct: |  |  |  |  |  |
Sustaining capital | (272 | ) | (305 | ) | (361 | )
Insurance recoveries of sustaining capital expenditures | 1 |  | 25 |  | 4 |
Dividends paid on preferred shares | (42 | ) | (46 | ) | (41 | )
Distributions paid to subsidiaries’ non-controlling interests | (151 | ) | (99 | ) | (84 | )
Comparable FCF | 299 |  | 315 |  | 280 |

Comparable FFO was $763 million for 2016 as compared to $740 million for 2015. The full year contribution from renewable assets we acquired in late 2015 added $25 million to our comparable EBITDA and comparable FFO. Operations, maintenance, and administration (“OM&A”) cost reduction initiatives across the fleet also increased comparable EBITDA and comparable FFO. Lower prices in Alberta and the Pacific Northwest negatively impacted our business, but the impact was mitigated by the high level of contracts and hedges in each market.

For the year ended Dec. 31, 2015, comparable FFO decreased by $22 million to $740 million compared to 2014, mainly due to the higher outages and derates in Alberta, and lower prices in Alberta and the Pacific Northwest.

Comparable FCF for 2016 was down by $16 million, largely related to higher distributions paid to subsidiaries’ non-controlling interests. Higher comparable FCF in 2015 compared to 2014 was mostly 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, and reductions in our gas-fired capital expenditures caused by the Poplar Creek recontracting.

Discussion of Segmented Comparable Results

In 2016, we disaggregated presentation of the previous Gas reportable segment into its two operating segments: Canadian Gas and Australian Gas. Previously included legacy costs of the non-operating U.S. Gas function have been reallocated to U.S. Coal to align with management’s internal monitoring practices. Comparative segmented results for 2015 and 2014 have been restated to align with separate reporting of the two segments and the reallocation of the non-operating costs.

We evaluate our performance and the performance of our business segments using a variety of measures. Comparable figures are not defined under IFRS. Refer to the Reconciliation of Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to net earnings attributable to common shareholders.

M12 TRANSALTA CORPORATION

Each business segment assumes responsibility for its operating results measured to comparable EBITDA. Operating income and gross margin are also useful measures as they provide management and investors with a measurement of operating performance that is readily comparable from period to period.

Canadian Coal

Year ended Dec. 31 | 2016 | 2015 | 2014
Availability (%) | 85.3 | 84.3 | 88.6
Contract production (GWh) | 19,823 | 20,256 | 21,748
Merchant production (GWh) | 3,787 | 3,827 | 3,806
Total production (GWh) | 23,610 | 24,083 | 25,554
Gross installed capacity (MW) | 3,791 | 3,786 | 3,771
Revenues | 1,048 | 912 | 1,023
Fuel and purchased power | 386 | 379 | 436
Comparable gross margin | 662 | 533 | 587
Operations, maintenance, and administration | 178 | 194 | 196
Taxes, other than income taxes | 13 | 12 | 12
Gain on sale of assets | - | - | (1)
Net other operating income | (2) | (7) | (9)
Comparable EBITDA | 473 | 334 | 389
Depreciation and amortization | 307 | 299 | 292
Comparable operating income | 166 | 35 | 97
Sustaining capital: |  |  |
Routine capital | 33 | 48 | 56
Mine capital | 23 | 25 | 45
Finance leases | 13 | 10 | 10
Planned major maintenance | 100 | 107 | 100
Total sustaining capital expenditures | 169 | 190 | 211
Insurance recoveries of sustaining capital expenditures | - | (7) | -
Net amount | 169 | 183 | 211

TRANSALTA CORPORATION M13

2016

Production for the year ended Dec. 31, 2016, decreased 473 gigawatt hours (“GWh”) compared to 2015, primarily due to higher paid curtailments in the first half of the year and higher levels of economic dispatching, in both cases caused by lower prices in Alberta. This was partially offset by lower planned outages and derates. Unplanned outages remained at a similar level compared to last year.

Comparable EBITDA for the year ended Dec. 31, 2016, increased $139 million compared to 2015, primarily due to the reversal of the $80 million provision relating to the Keephills 1 outage in 2013. The year-over-year impact to comparable EBITDA of this provision was $139 million, as last year’s comparable EBITDA was reduced by $59 million due to this provision. Our high level of contracted generation and hedging strategy largely mitigated the impact of low power prices in Alberta. Comparable EBITDA was also positively impacted by a reduction in our operations, maintenance, and administration costs.

For the year ended Dec. 31, 2016, sustaining capital expenditures decreased by $21 million compared to 2015, mainly due to lower expenditures on our turnaround outages executed on two of our operated units and deferral of discretionary projects into 2017.

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 2015 (Sundance 4 and the Keephills 1 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 required. Generation was also reduced due to economic dispatching resulting from the low price environment in 2015.

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 2014. 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 with the Keephills 1 force majeure outage and additional work at Sundance 3.

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

M14 TRANSALTA CORPORATION

U.S. Coal

Year ended Dec. 31 | 2016 | 2015(2) | 2014(2)
Availability (%) | 88.1 | 87.4 | 82.8
Adjusted availability (%)(1) | 88.9 | 89.5 | 87.7
Contract sales volume (GWh) | 3,535 | 2,868 | 1,131
Merchant sales volume (GWh) | 4,896 | 5,484 | 6,102
Purchased power (GWh) | (3,854) | (3,329) | (549)
Total production (GWh) | 4,577 | 5,023 | 6,684
Gross installed capacity (MW) | 1,340 | 1,340 | 1,340
Revenues | 380 | 432 | 369
Fuel and purchased power | 281 | 316 | 255
Comparable gross margin | 99 | 116 | 114
Operations, maintenance, and administration | 54 | 50 | 49
Taxes, other than income taxes | 4 | 3 | 3
Comparable EBITDA | 41 | 63 | 62
Depreciation and amortization | 61 | 63 | 54
Comparable operating income (loss) | (20) | - | 8
Sustaining capital: |  |  |
Routine capital | 3 | 2 | 2
Finance leases | 3 | 3 | -
Planned major maintenance | 11 | 10 | 10
Total | 17 | 15 | 12

2016

Production was down 446 GWh in 2016 compared to 2015, due mainly to increased economic dispatching in the first half of the year caused by lower prices. We supplied our contractual obligations by buying less expensive power in the market during such periods.

Comparable EBITDA decreased by $22 million compared to 2015 as a result of reduced margins due to lower prices and the unfavourable impact of mark-to-market on certain forward financial contracts that do not qualify for hedge accounting. This was partially offset by lower coal transportation costs and a reduction in our coal impairment charges.

Depreciation and amortization for 2016 decreased by $2 million compared to 2015 due to higher discount rates being applied to our decommissioning obligation for the Centralia mine. As the mine is in the reclamation stage, the adjustment flows directly to earnings.

Sustaining capital expenditures for 2016 were $2 million higher compared to 2015, primarily due to higher planned outages.

(1) Adjusted for economic dispatching.

(2) Restated to include non-operating legacy U.S. Gas costs. Refer to the Accounting Changes section of this MD&A.

TRANSALTA CORPORATION M15

2015

Production decreased 1,661 GWh in 2015 compared to 2014, as a result of a higher level of economic dispatching caused by lower prices.

In December 2014, we began 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 to 380 MW in 2016. We can supply the contract by buying power from the market when economical to do so and further improve our margin. The contract is accounted for 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 and lower pricing on uncontracted generation was offset by the increased contracted volumes with Puget Sound Energy.

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.

Canadian Gas

Year ended Dec. 31 |  | 2016 |  | 2015 |  | 2014 |
Availability (%) |  | 95.7 |  | 95.6 |  | 94.9 |
Contract production (GWh) |  | 2,784 |  | 3,697 |  | 4,096 |
Merchant production (GWh) |  | 288 |  | 1,535 |  | 2,027 |
Total production (GWh) |  | 3,072 |  | 5,232 |  | 6,123 |
Gross installed capacity (MW)(1) |  | 1,057 |  | 1,057 |  | 1,183 |
Revenues |  | 470 |  | 486 |  | 584 |
Fuel and purchased power |  | 171 |  | 204 |  | 299 |
Comparable gross margin |  | 299 |  | 282 |  | 285 |
Operations, maintenance, and administration |  | 54 |  | 67 |  | 69 |
Taxes, other than income taxes |  | 1 |  | 3 |  | 4 |
Comparable EBITDA |  | 244 |  | 212 |  | 212 |
Depreciation and amortization |  | 108 |  | 98 |  | 98 |
Comparable operating income |  | 136 |  | 114 |  | 114 |
Sustaining capital: |  |  |  |  |  |  |
Routine capital |  | 7 |  | 4 |  | 22 |
Planned major maintenance |  | 5 |  | 19 |  | 33 |
Total |  | 12 |  | 23 |  | 55 |

(1) Includes production capacity for the Fort Saskatchewan power station, which has been accounted for as a finance lease. During 2015, operational control of our Poplar Creek facility was transferred to Suncor Energy (“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, effective Sept. 1, 2015.

M16 TRANSALTA CORPORATION

2016

Production for the year decreased 2,160 GWh compared to 2015, primarily due to the restructuring of our contract with Suncor at the Poplar Creek facility in the third quarter of 2015 and higher economic dispatching in Ontario driven by lower prices.

Comparable EBITDA for 2016 increased by $32 million compared to 2015, as result of a year-over-year change in unrealized mark-to-market on our gas position, cost-efficiency initiatives, and favourable pricing in Ontario from our contracts for power and gas. The recontracting of the Poplar Creek facility reduced our OM&A by more than $9 million in 2016, compared to last year.

Sustaining capital totalled $12 million in 2016, a decrease of $11 million. In 2015, we refurbished two engines in Ontario. The change in our Poplar Creek operation also lowered our sustaining capital by approximately $7 million compared to 2015.

2015

Production for the year ended Dec. 31, 2015, decreased 891 GWh compared to 2014, also as a result of the restructuring of our contract with Suncor at Poplar Creek, effective Sept. 1, 2015.

The Poplar Creek transaction had a minimal impact on EBITDA in 2015 compared to 2014.

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.

Australian Gas

Year ended Dec. 31 |  | 2016 |  | 2015 |  | 2014 |
Availability (%) |  | 93.1 |  | 92.4 |  | 91.4 |
Contract production (GWh) |  | 1,529 |  | 1,381 |  | 1,267 |
Gross installed capacity (MW)(1) |  | 425 |  | 348 |  | 348 |
Revenues |  | 174 |  | 163 |  | 159 |
Fuel and purchased power |  | 20 |  | 20 |  | 23 |
Comparable gross margin |  | 154 |  | 143 |  | 136 |
Operations, maintenance, and administration |  | 25 |  | 21 |  | 33 |
Taxes, other than income taxes |  | 1 |  | - |  | - |
Comparable EBITDA |  | 128 |  | 122 |  | 103 |
Depreciation and amortization |  | 20 |  | 20 |  | 16 |
Comparable operating income |  | 108 |  | 102 |  | 87 |
Sustaining capital: |  |  |  |  |  |  |
Routine capital |  | 3 |  | 4 |  | 2 |
Planned major maintenance |  | 11 |  | 4 |  | 6 |
Total |  | 14 |  | 8 |  | 8 |

(1) Includes production capacity for the Solomon power station, which has been accounted for as a finance lease.

TRANSALTA CORPORATION M17

2016

Production for 2016 increased 148 GWh compared to 2015 mostly from an increase in customer load. Due to the nature of our contracts, the increase did not have a significant financial impact as our contracts are structured as capacity payments with a pass-through of fuel costs.

Comparable EBITDA for the year increased by $6 million compared to 2015, mainly due to the addition of capacity payments for the gas conversion project at our Solomon gas plant that was completed in May 2016, as well as the uplift from our natural gas pipeline that was commissioned in March 2015. The change in value of the Australian dollar had limited impact on our comparable EBITDA in 2016.

Sustaining capital increased by $6 million compared to 2015, mainly driven by maintenance projects on two engines in 2016 compared to maintenance projects on only one engine in 2015.

2015

Production for the year ended Dec. 31, 2015, increased 114 GWh compared to 2014 due to an increase in the power import regime at one of our customer’s locations. Due to the nature of our contracts, the change did not have a significant financial impact as our contracts are structured as capacity payments with a pass-through of fuel costs.

The increase in comparable EBITDA was 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 2015.

Most of our contracts provide for the pass-through of fuel costs to the counterparty, limiting our exposure to fluctuations in fuel prices. 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 2014, 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 2014.

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.

Sustaining capital remained at similar levels in 2015 compared to 2014.

M18 TRANSALTA CORPORATION

Wind and Solar

Year ended Dec. 31 |  | 2016 |  | 2015 |  | 2014 |
Availability (%) |  | 94.9 |  | 95.8 |  | 94.6 |
Contract production (GWh) |  | 2,301 |  | 2,146 |  | 2,228 |
Merchant production (GWh) |  | 1,212 |  | 1,060 |  | 947 |
Total production (GWh) |  | 3,513 |  | 3,206 |  | 3,175 |
Gross installed capacity (MW)(1) |  | 1,408 |  | 1,424 |  | 1,291 |
Revenues |  | 272 |  | 250 |  | 247 |
Fuel and purchased power |  | 18 |  | 19 |  | 14 |
Comparable gross margin |  | 254 |  | 231 |  | 233 |
Operations, maintenance, and administration |  | 52 |  | 48 |  | 48 |
Taxes, other than income taxes |  | 8 |  | 7 |  | 6 |
Net other operating income |  | (1 | ) | - |  | - |
Comparable EBITDA |  | 195 |  | 176 |  | 179 |
Depreciation and amortization |  | 119 |  | 99 |  | 88 |
Comparable operating income |  | 76 |  | 77 |  | 91 |
Sustaining capital: |  |  |  |  |  |  |
Routine capital |  | 2 |  | 1 |  | 2 |
Planned major maintenance |  | 11 |  | 12 |  | 10 |
Total sustaining capital expenditures |  | 13 |  | 13 |  | 12 |
Insurance recoveries of sustaining capital expenditures |  | (1 | ) | - |  | - |
Net amount |  | 12 |  | 13 |  | 12 |

2016

Production for 2016 increased by 307 GWh compared to 2015, mainly due to the full year contribution from assets acquired during the second half of 2015, partly offset by lower wind resources negatively impacting generation across Canada.

Comparable EBITDA for 2016 increased $19 million compared to 2015, as assets acquired in the second half of 2015 contributed approximately $23 million to the increase. Lower merchant prices in Alberta and lower generation in Canada negatively impacted our EBITDA.

Depreciation and amortization increased by $20 million compared to 2015, primarily due to the addition of assets acquired during the second half of 2015.

2015

Production for 2015 increased slightly by 31 GWh compared to 2014, due to contributions from three additional wind farms and our first solar facility acquired during the second half of 2015 (111 GWh). This was partially offset by lower wind resources at Wyoming in 2015 compared to relatively 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.

Depreciation and amortization for 2015 increased by $11 million compared to 2014, primarily due to the acquisition of new assets during the year and a stronger US dollar.

(1) Our 2015 capacity excludes acquisitions completed during the second half of 2015.

TRANSALTA CORPORATION M19

Hydro

Year ended Dec. 31 |  | 2016 |  | 2015 |  | 2014 |
Contract production (GWh) |  | 1,768 |  | 1,662 |  | 1,810 |
Merchant production (GWh) |  | 88 |  | 86 |  | 75 |
Total production (GWh) |  | 1,856 |  | 1,748 |  | 1,885 |
Gross installed capacity (MW) |  | 926 |  | 926 |  | 913 |
Revenues |  | 126 |  | 116 |  | 131 |
Fuel and purchased power |  | 8 |  | 8 |  | 9 |
Comparable gross margin |  | 118 |  | 108 |  | 122 |
Operations, maintenance, and administration |  | 33 |  | 38 |  | 38 |
Taxes, other than income taxes |  | 3 |  | 3 |  | 3 |
Net other operating income |  | - |  | (6 | ) | (6 | )
Comparable EBITDA |  | 82 |  | 73 |  | 87 |
Depreciation and amortization |  | 33 |  | 25 |  | 24 |
Comparable operating income |  | 49 |  | 48 |  | 63 |
Sustaining capital: |  |  |  |  |  |  |
Routine capital, excluding hydro life extension |  | 8 |  | 3 |  | 9 |
Hydro life extension |  | 9 |  | 18 |  | 19 |
Planned major maintenance |  | 10 |  | 10 |  | 3 |
Total before flood-recovery capital |  | 27 |  | 31 |  | 31 |
Flood-recovery capital |  | 2 |  | 4 |  | 9 |
Total sustaining capital expenditures |  | 29 |  | 35 |  | 40 |
Insurance recoveries of sustaining capital expenditures |  | - |  | (18 | ) | (4 | )
Net amount |  | 29 |  | 17 |  | 36 |

2016

Production for 2016 increased by 108 GWh over 2015, primarily due to better water resources.

Comparable EBITDA for 2016 increased $9 million compared to 2015. Higher generation contributed to higher revenues. Our financial contracts partially offset lower levels of revenues in the Alberta ancillary market, and we also benefited from cost-reduction initiatives implemented in late 2015.

Depreciation and amortization for 2016 increased by $8 million compared to 2015 due to the recognition of decommissioning obligations on certain transmission lines that were taken out of service. As these transmission lines are in the reclamation stage, the adjustment flows directly to earnings.

Sustaining capital (before insurance recoveries) for 2016 decreased $6 million compared to 2015 due to lower expenditures on hydro life extension projects, partially offset by higher expenditures on routine capital.

2015

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

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 flood.

Sustaining capital expenditures (before insurance recoveries) 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.

M20 TRANSALTA CORPORATION

Energy Marketing

Year ended Dec. 31 |  | 2016 |  | 2015 |  | 2014 |
Revenues and comparable gross margin |  | 76 |  | 49 |  | 108 |
Operations, maintenance, and administration |  | 24 |  | 12 |  | 33 |
Comparable EBITDA |  | 52 |  | 37 |  | 75 |
Depreciation and amortization |  | 3 |  | 1 |  | - |
Comparable operating income |  | 49 |  | 36 |  | 75 |

Comparable EBITDA from Energy Marketing increased $15 million compared to 2015, as a result of solid performances in all markets where we are active. During the second quarter of 2015, unexpectedly volatile markets in Alberta and the Pacific Northwest negatively impacted gross margin. Operating, maintenance, and administration costs increased $12 million to $24 million in 2016 compared to 2015, due to increases in share-based incentive compensation and lower charges to other business segments for energy hedging and optimization services.

Corporate

Our Corporate overhead costs of $70 million were lower in 2016 compared to 2015 and 2014 ($72 million and $71 million, respectively), as we realized benefits of cost-efficiency initiatives that were offset by reduced allocations to our business segments.

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. 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

As at Dec. 31 |  | 2016 |  | 2015 |  | 2014 |
Comparable FFO |  | 763 |  | 740 |  | 762 |
Add: Interest on debt net of capitalized interest |  | 223 |  | 223 |  | 236 |
Comparable FFO before interest |  | 986 |  | 963 |  | 998 |
Interest on debt |  | 239 |  | 232 |  | 239 |
Add: 50 per cent of dividends paid on preferred shares |  | 21 |  | 23 |  | 21 |
Adjusted interest |  | 260 |  | 255 |  | 260 |
Comparable FFO before interest to adjusted interest coverage (times) |  | 3.8 |  | 3.8 |  | 3.8 |

Our target for comparable FFO before interest to adjusted interest coverage is four to five times. This ratio is comparable to last year, as 2016’s higher comparable FFO was offset by higher interest on debt, which includes interest capitalized on our South Hedland power project. We expect this metric to improve towards our targeted level in the future, due the South Hedland power project, once commissioned.

TRANSALTA CORPORATION M21

Adjusted Comparable Funds from Operations to Adjusted Net Debt

As at Dec. 31 | 2016 | 2015 | 2014
Comparable FFO | 763 | 740 | 762
Less: 50 per cent of dividends paid on preferred shares | (21) | (23) | (21)
Adjusted comparable FFO | 742 | 717 | 740
Period-end long-term debt(1) | 4,361 | 4,495 | 4,056
Less: Cash and cash equivalents | (305) | (54) | (43)
Add: 50 per cent of issued preferred shares | 471 | 471 | 471
Fair value asset of hedging instruments on debt(2) | (163) | (190) | (96)
Adjusted net debt | 4,364 | 4,722 | 4,388
Adjusted comparable FFO to adjusted net debt (%) | 17.0 | 15.2 | 16.9

Our adjusted comparable FFO to adjusted net debt ratio improved to 17.0 per cent, mostly due to the increase in comparable FFO, and lower net debt due to repayments, and the strengthening of the Canadian dollar in 2016. We expect this metric to improve towards our targeted level of 20 to 25 in the future, due the South Hedland power project, once commissioned.

Adjusted Net Debt to Comparable EBITDA

As at Dec. 31 | 2016 | 2015 | 2014
Period-end long-term debt(1) | 4,361 | 4,495 | 4,056
Less: Cash and cash equivalents | (305) | (54) | (43)
Add: 50 per cent of issued preferred shares | 471 | 471 | 471
Fair value asset of hedging instruments on debt(2) | (163) | (190) | (96)
Adjusted net debt | 4,364 | 4,722 | 4,388
Comparable EBITDA(1) | 1,145 | 945 | 1,036
Adjusted net debt to comparable EBITDA (times) | 3.8 | 5.0 | 4.2

During the year, our adjusted net debt to comparable EBITDA ratio improved compared to 2015, mainly because of a lower debt balance due to repayments and the strengthening of the Canadian dollar, and higher comparable EBITDA. Our target for adjusted net debt to comparable EBITDA is 3.0 to 3.5 times. We expect this metric to improve towards our targeted level in the future due to the expected increase in comparable EBITDA of approximately $80 million annually from the South Hedland power project, once commissioned.

Sustainability Performance

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.

(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, 2016, Dec. 31, 2015, and Dec. 31, 2014.

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Sustainability Targets and Results

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.

2016 Sustainability Targets
|  | Financial |  | Results |  | Comments
1. Maintain our investment grade rating |  | Achieve and maintain investment grade credit metrics |  | Partly achieved |  | TransAlta maintains investment grade ratings from three rating agencies: S&P (BBB-) stable, DBRS (BBB) negative outlook, and Fitch (BBB-) negative outlook. On Dec. 17, 2015, Moody’s reduced our rating to Ba1
2. Increase focus on FFO and EBITDA |  | TransAlta targeted comparable EBITDA and comparable FFO for 2016 in the range of $990 million to $1,100 million and $755 million to $835 million respectively |  | Achieved |  | For the year ended Dec. 31, 2016, comparable EBITDA was $1,145 million and comparable FFO was reported at $763 million. Comparable EBITDA includes the reversal of provisions relating to the Keephills 1 force majeure event in the amount of $80 million

|  | Power Generating Portfolio |  | Results |  | Comments
3. Grow asset portfolio |  | Deliver an average of $40 million to $60 million of additional EBITDA from growth projects |  | On track |  | In 2016, we continued to exercise prudence and discipline in growing our cash flow. The wind and solar pojects acquired in late 2015 contributed approximately $25 million of comparable EBITDA in 2016. We continue to advance the construction of the South Hedland power project, on budget and on time. This project is expected to be commisioned by mid-2017 and add approximately $80 million of incremental annualized EBITDA
4. Achieve top-quartile performance in Canadian Coal |  | Continue to deliver 87 to 89 per cent availability in the segment |  | Not achieved |  | We achieved availability in 2016 of 85.3 per cent, compared to 84.3 per cent in 2015, lower than our targeted availability of at least 87 per cent. Our high level of contracted generation and hedging strategy mitgated lower power prices in Alberta. We continue to drive towards our targets

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|  | Human and Intellectual |  | Results |  | Comments
5. Reduce safety incidents |  | Achieve an Injury Frequency Rate below 0.70 |  | Not achieved |  | IFR was 0.85 in 2016, up from 0.75 in 2015. We will continue to seek improvement in this area through deployment of additional targeted initiatives in 2017
6. Human Resources |  | a) Maintain voluntary turnover percentage under eight per cent |  | Achieved |  | Voluntary turnover was 6.7 per cent in 2016
|  | b) Achieve 100 per cent completion of development plans for all high-potential employees at the top three levels of the organization |  | Achieved |  |
|  | c) Complete the final three stages of our globally recognized leadership development project to ensure TransAlta’s top three levels of leaders have the tools to successfully reposition and grow our business |  | Partly achieved |  | Final stages to be completed in Q1 2017

|  | Natural |  | Results |  | Comments
7. Minimize fleet-wide environmental incidents |  | Keep recorded incidents (including spills and air infractions) below 13 |  | Not achieved |  | We recorded 16 reportable environmental incidents in 2016, none of which had a material environmental impact
8. Increase mine reclaimed acreage |  | Replace annual topsoil rate at Highvale mine at a rate of 74 acres/year |  | Partly achieved |  | Replaced topsoil on 38 acres in 2016. A warmer winter and early spring limited our ability to transport topsoil for placement without adversely impacting the ground surface (the preference is to drive on frozen soil)
9. Utilize coal byproduct |  | Sell a minimum of two million tonnes of coal byproduct materials during the period 2015 to 2017 |  | On track |  | 70 per cent achieved (long-term target)
10. Reduce air emissions |  | 95 per cent reduction from 2005 levels of TransAlta coal facility NO x and SO 2 emissions by 2030 |  | On track |  | We reduced levels of NO x and SO 2 in 2016 and remain on track to realize these emission reductions by 2030
11. Reduce greenhouse gas emissions |  | a) 20 per cent reduction from 2005 levels of TransAlta coal facility GHG by 2021, or the equivalent of 7 million tonnes, of CO 2 e per year |  | On track |  | We reduced GHG emissions in 2016, primarily as a result of lower coal production, and we remain on track to realize emission reductions by 2021/2030
|  | b) 55 per cent reduction from 2005 levels by 2030, or the equivalent of 19.7 million tonnes, of CO 2 e per year. |  | On track |  |

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|  | Social and Relationship Capital |  | Results |  | Comments
12. Combine stakeholder engagement |  | Implement final Stakeholder Engagement Framework. In 2016, every business unit will use a single framework for stakeholder guidance |  | Achieved |  | A corporate-wide framework was implemented and we introduced our Stakeholder and Aboriginal Relations (“STAR”) tracking program. STAR is a communication record-keeping tool and fulfils our requirements for consultation with both stakeholders and aboriginal groups
13. Support youth education with community investment |  | 50 per cent of total communitiy investment spending will be directed to supporting youth education |  | Partly achieved |  | In 2016 we spent approximately $0.75 million out of $2.5 million (30 per cent) on youth education. Funds were directed to the University of Calgary, University of Alberta, Southern Alberta Institute of Technology, Mount Royal University, The Banff Centre (indigenous leadership scholarships), Mother Earth’s Children’s Charter School (indigenous kindergarten to grade 9), Calgary Stampede (the Young Canadians - ages 7 to 18) and national Canada and U.S. indigenous scholarships (post-secondary for trades and academic)
14. 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 |  | Achieved |  | With the help of the First Nations groups and voices of those communities, we produced an Indigenous Awareness Training handbook for all our employees. This achievement is in line with a commitment to support the United Nations Sustainable Development Goals, specifically, goal 10: reduced inequalities

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Competitive Forces

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 behind-the-fence generation for mining investments is key to developing our Australian gas segment.

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 we 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.

Alberta

Approximately 63 per cent of our gross capacity is located in Alberta and more than 65 per cent of this 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 retains 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 a significant portion of our remaining generation. |  |

Following the decrease in oil prices, Alberta’s annual demand for power decreased by approximately 1.1 per cent in 2016 compared to 2015. Since 2014, approximately 1,000 MW of gas and wind generation capacity were added to the market. As a result, power pool prices trended to their lowest levels in the last 10 years, dropping to an average of $18/MWh in 2016, due to an oversupply of energy as well as bidding behaviour in the market that kept prices low. The decline impacted 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 12 per cent. After the expiry of the PPAs at the end of 2020, our share of offer control is forecast to increase to approximately 28 per cent depending on load and supply growth in the province.

In late November 2016, we announced that we had entered into an OCA with the Government of Alberta that provides transition payments for the cessation of coal-fired emissions from the Keephills 3, Genesee 3 and Sheerness coal-fired plants on or before Dec. 31, 2030. The affected plants are not, however, precluded from generating electricity at any time by any method other than the combustion of coal. We also entered into the MOU with the Government of Alberta to collaborate and co-operate in the development of a capacity market in Alberta that ensures both current and new electricity generators will have a level economic playing field to build, buy, and sell electricity, and to develop a policy framework to facilitate the conversion of coal-fired generation to gas-fired generation. We expect additional compliance costs as a result of the federal government’s proposed framework in which each province is expected to implement a greenhouse gas (“GHG”) policy equivalent to a carbon price of $50 per tonne by 2022. We believe that our extensive portfolio of assets provides us with brownfield development opportunities in wind, solar, hydro, and gas that give us a cost advantage over competitors when constructing generation facilities that use these fuel types.

M26 TRANSALTA CORPORATION

In March and May 2016, the buyers under the legislated Sundance, Sheerness, and Keephills PPAs announced their intention to terminate the PPAs and transfer their respective obligations under the PPAs to the Balancing Pool because of a change in Alberta law. Accordingly, the Balancing Pool began its investigation to determine whether these transfers are permitted by the terms of the PPAs in the current circumstances and, if so, when the transfers would become effective. On July 25, 2016, the Attorney General for the Province of Alberta commenced legal proceedings seeking relief against: all buyers who purported to transfer their respective obligations under the PPAs, the owner of the Battle River #5 PPA, the Alberta Utilities Commission (“AUC”), and the Balancing Pool. In this claim, the Attorney General challenges, among other things, the basis on which the buyers purported to terminate the PPAs and transfer their PPA obligations to the Balancing Pool.

Recently, the Attorney General announced that it entered into settlement agreements with the buyers of the PPAs for Sheerness, Sundance A, Sundance B, and Sundance C, and therefore discontinued its claims against those buyers. As part of the settlement, the Balancing Pool confirmed the terminations of the PPAs for Sheerness and Sundance A, B, and C and, as a result, the Balancing Pool assumed the role of buyer and is carrying out the responsibilities of the buyer under each of those PPAs, including dispatching the generating units and making the capacity and energy payments to TransAlta until the end of the PPA terms. TransAlta does not presently expect the transfer of the role of PPA buyer to the Balancing Pool to have a material impact on its business.

Pursuant to the Electric Utilities Act (Alberta), the Balancing Pool may also choose to terminate the PPAs after following the legislative requirements, which would include paying TransAlta an amount essentially equal to the applicable closing net book value of the generating units.

The Attorney General has not entered into a settlement agreement with the buyer under the Keephills PPA and the Balancing Pool has not confirmed the termination of that PPA. The outcome of the Attorney General’s proceeding and any investigation by the Balancing Pool into the purported termination of the Keephills PPA is uncertain.

Notwithstanding all the above events, TransAlta continues to operate the PPA generating units in their ordinary course and receives the capacity and energy payments due to TransAlta under the PPAs.

U.S. Pacific Northwest

Our capacity in the U.S. Pacific Northwest is represented by our 1,340 MW Centralia coal plant. Half of the plant capacity is scheduled 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 cost of production.

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

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Contracted Gas and Renewables

The market for developing or acquiring 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 recontracting these plants with limited life-extending capital expenditures. We have recently extended the life of our Ottawa (2033 expiry), Windsor (2031 expiry), and Parkeston (2026 expiry) plants in this manner. During the fourth quarter of 2016, we entered into a new contract with the IESO for our Mississauga cogeneration facility. The new contract took effect on Jan. 1, 2017, and has resulted in the termination of the existing contract, which would have otherwise terminated in December 2018. See the Significant Events section for further details. The new contract provides us with additional financial flexibility to pay down upcoming debt maturities.

TransAlta’s Capital

The following discusses TransAlta’s main categories of capital, being Financial, Power Generating Portfolio, Human and Intellectual, Social and Relationship, and Natural.

Financial Capital

Sources of Capital

Our goal over the last two years 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 agencies.(1) 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 $1.1 billion, including a reduction of over $800 million on our credit facility and a $300 million reduction in Canadian and U.S. bonds. Over the next two years, we plan to continue on this path by replacing an additional $700 million to $900 million of maturing recourse debt with debt secured by contracted cash flows.

On Dec. 17, 2015, Moody’s lowered the rating of our senior unsecured debt to Ba1 with a stable outlook. The direct financial impact of this downgrade has been limited. We have posted additional collateral (including letters of credit) of nearly $130 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. During the first quarter of 2016, DBRS and Fitch Ratings (“Fitch”) changed their outlooks from stable to negative. Their negative outlooks are a reflection of low energy prices and concerns over coal generation transition in Alberta. We have investment grade ratings from each of DBRS, S&P, and Fitch. 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, 2016, our senior unsecured debt is rated as investment grade by three rating agencies: BBB (negative), BBB- (stable), and BBB- (negative) by DBRS, Standard and Poor’s (“S&P”), and Fitch Ratings (“Fitch”), respectively, and Ba1 (stable) by Moody’s Investors Service (“Moody’s”). Our preferred shares are rated P-3 (stable) and Pfd-3 (negative) 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 their judgment, circumstances so warrant. See the Liquidity Risk section of this MD&A.

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Capital Structure

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

|  | 2016 |  | 2015 |  | 2014 |
As at Dec. 31 |  | $ |  | % |  | $ |  | % |  | $ |  | % |
Recourse debt - CAD debentures |  | 1,045 |  | 12 |  | 1,044 |  | 12 |  | 1,043 |  | 13 |
Recourse debt - U.S. senior notes |  | 2,151 |  | 25 |  | 2,221 |  | 26 |  | 2,444 |  | 31 |
Credit facilities |  | - |  | - |  | 315 |  | 4 |  | 96 |  | 1 |
U.S. tax equity financing |  | 39 |  | 1 |  | 50 |  | 1 |  | - |  | - |
Other |  | 15 |  | - |  | 17 |  | - |  | 19 |  | - |
Less: cash and cash equivalents |  | (305 | ) | (4 | ) | (54 | ) | (1 | ) | (43 | ) | - |
Less: fair value asset of hedging instruments on debt |  | (163 | ) | (2 | ) | (190 | ) | (2 | ) | (96 | ) | (1 | )
Net recourse debt |  | 2,782 |  | 32 |  | 3,403 |  | 40 |  | 3,463 |  | 44 |
Non-recourse debt |  | 1,038 |  | 12 |  | 766 |  | 9 |  | 380 |  | 5 |
Finance lease obligations |  | 73 |  | 1 |  | 82 |  | 1 |  | 74 |  | 1 |
Total net debt |  | 3,893 |  | 45 |  | 4,251 |  | 50 |  | 3,917 |  | 50 |
Non-controlling interests |  | 1,152 |  | 14 |  | 1,029 |  | 12 |  | 594 |  | 8 |
Equity attributable to shareholders |  |  |  |  |  |  |  |  |  |  |  |  |
Common shares |  | 3,094 |  | 36 |  | 3,075 |  | 35 |  | 2,999 |  | 38 |
Preferred shares |  | 942 |  | 11 |  | 942 |  | 11 |  | 942 |  | 12 |
Contributed surplus, deficit, and accumulated other comprehensive income |  | (525 | ) | (6 | ) | (656 | ) | (8 | ) | (657 | ) | (8 | )
Total capital |  | 8,556 |  | 100 |  | 8,641 |  | 100 |  | 7,795 |  | 100 |

During 2016, we continued to work on strengthening our financial position and executing on our debt deleveraging strategy. Our total debt, net of cash on hand and the fair value of our financial instruments hedging our U.S. debt, was reduced by more than $350 million, from a combination of cash flows from operations and cash proceeds of $173 million received from the sale of the economic interest in the Canadian Assets. Furthermore, we extended $1.8 billion of our $2.0 billion credit facilities to 2020 and the remaining were extended to 2018. Since 2014, we acquired one wind and five solar projects for a total consideration of approximately $200 million, including the assumption of debt. These projects contributed approximately $25 million of comparable EBITDA in 2016. We also funded $336 million for the construction of the South Hedland project. In total, the South Hedland project is expected to cost approximately $576 million and add $80 million of EBITDA annually over the 25-year life of the long-term contract (including approximately $29 million of EBITDA relating to TransAlta Renewables’ non-controlling interest share). We expect the project to commence operations in mid-2017.

During the year, we continued implementing our strategy to raise debt secured by our contracted cash flows and completed the following debt offerings:

¡ a non-recourse bond in the amount of $202.5 million, with principal and interest payable quarterly, maturing on Dec. 31, 2030, secured by our Poplar Creek finance lease contract, and

¡ a non-recourse bond in the amount of $159 million, with principal and interest payable semi-annually, and maturing on June 30, 2032, secured by our New Richmond Wind project in Quebec.

In 2015, we completed a $442 million bond offering, secured by two wind projects located in Ontario. 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. 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.

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Non-recourse debt of $845 million in total (2015 - $536 million) is subject to customary financing restrictions that restrict our ability to access funds generated by certain facilities’ operations. Upon meeting certain distribution tests, typically performed once per quarter, the funds are able to be distributed by the subsidiary entities to their respective parent entity. At Dec. 31, 2016, $24 million of cash was subject to these financial restrictions. Non-recourse debts of $644 million are each secured by a first ranking charge over all of the respective assets of our subsidiaries that issued the bonds, which includes renewable generation facilities with total carrying amounts of $956 million at Dec. 31, 2016 (2015 - $798 million). A non-recourse bond of approximately $201 million is secured by a first ranking charge over the equity interests of the issuer that issued the non-recourse bond.

The weakening of the US dollar has decreased our long-term debt balances by $67 million in 2016. Almost all our U.S.-denominated debt is hedged either through financial contracts or net investments in our U.S. operations. During the period, these changes in our U.S.-denominated debt were offset as follows:

As at Dec. 31 |  | 2016 |  | 2015 |
Effects of foreign exchange on carrying amounts of U.S. operations (net investment hedge) and finance lease receivable |  | (35 | ) | 201 |
Foreign currency cash flow hedges on debt |  | (29 | ) | 183 |
Economic hedges and other |  | (3 | ) | 8 |
Total |  | (67 | ) | 392 |

Over the next four years, we have approximately $2.2 billion of recourse and non-recourse debt maturing. We expect to refinance some of these upcoming debt maturities by raising $700 million to $900 million of debt secured by our contracted cash flows. We also expect to continue our deleveraging strategy, as a significant part of our free cash flow over the next four years will be allocated to debt reduction. The reduction of our common share dividend in January 2016 is expected to provide additional funds which may be used for debt reduction.

Our credit facilities provide us with significant liquidity. At Dec. 31, 2016, we had a total of $2.0 billion (2015 - $2.2 billion) of committed credit facilities, of which $1.4 billion (2015 - $1.3 billion) was available for use. We are in compliance with the terms of the credit facilities. At Dec. 31, 2016, the $0.6 billion (2015 - $0.9 billion) of credit utilized under these facilities was comprised of actual drawings of nil (2015 - $0.3 billion) and letters of credit of $0.6 billion (2015 - $0.6 billion). These facilities are comprised of a $1.5 billion committed syndicated bank facility expiring in 2020, one bilateral credit facility of US$200 million, expiring in 2020, and three bilateral credit facilities, totalling $240 million, expiring in 2018.

Working Capital

Including the current portion of long-term debt, the excess of current assets over current liabilities was $337 million as at Dec. 31, 2016 (2015 - $311 million). Although our working capital has not changed significantly, the timing of the classification of long-term debt as current has negatively impacted our current period-end working capital. Excluding the current portion of long-term debt of $639 million, the excess of current assets over liabilities was $976 million as at Dec. 31, 2016 (2015 - $398 million). Working capital as at Dec. 31, 2016, also includes approximately $93 million of receivables related to the Mississauga recontracting and $61 million related to the Wintering Hills wind facility reclassified as assets held for sale. Last year, working capital included a $59 million provision relating to the Keephill 1 outage. We reversed a total of $94 million of this provision in the fourth quarter of 2016.

Share Capital

Our Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares reset in 2016 at a coupon rate of 2.709 per cent. As permitted under the terms of the Preferred Shares, some shareholders elected to convert to a floating rate and 1,824,620 of our 12 million Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares were tendered for conversion, on a one-for-one basis, into the Series B Cumulative Redeemable Floating Rate Preferred Shares.

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

As at | March 2, 2017 | Dec. 31, 2016 | Dec. 31, 2015
| Number of shares (millions)
Common shares issued and outstanding, end of period | 287.9 | 287.9 | 284.0
Preferred shares |  |  |
Series A | 10.2 | 10.2 | 12.0
Series B | 1.8 | 1.8 | -
Series C | 11.0 | 11.0 | 11.0
Series E | 9.0 | 9.0 | 9.0
Series G | 6.6 | 6.6 | 6.6
Preferred shares issued and outstanding, end of period | 38.6 | 38.6 | 38.6

The Series C and Series E preferred shares will also reset in 2017. The rate spread on the Series C and Series E over the then 5-year Government of Canada bond rate is 3.10 per cent and 3.65 per cent, respectively.

Non-Controlling Interests

As of Dec. 31, 2016, we own 64.0 per cent (2015 – 66.6 per cent) of TransAlta Renewables. On January 2016, we completed the sale to TransAlta Renewables of an economic interest in 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. In November 2016, the economic interest was converted to direct ownership of the Canadian Assets by TransAlta Renewables.

TransAlta Renewables is a publicly traded company whose common shares are listed on the Toronto Stock Exchange under the symbol “RNW”. TransAlta Renewables holds 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.

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.

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 a 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 $474 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.

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.

We also own 50.01 per cent of TransAlta Cogeneration L.P (“TA Cogen”), which owns, operates, or has an interest in three natural-gas-fired facilities and one coal-fired generating facility. We recently recontracted our Mississauga cogeneration facility, which resulted in a pre-tax gain of approximately $191 million, accelerated depreciation of $46 million, and a fuel charge for the de-designation of gas hedges of $14 million. 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.

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Returns to Providers of Capital

Net Interest Expense

The components of net interest expense are shown below:

Year ended Dec. 31 |  | 2016 |  | 2015 |  | 2014 |
Interest on debt |  | 236 |  | 228 |  | 238 |
Loss on redemption of bonds |  | 1 |  | - |  | - |
Capitalized interest |  | (16 | ) | (9 | ) | (3 | )
Interest on finance lease obligations |  | 3 |  | 4 |  | 1 |
Other |  | (5 | ) | (2 | ) | (1 | )
Keephills 1 outage interest accruals (reversals) |  | (10 | ) | 9 |  | 1 |
Accretion of provisions |  | 20 |  | 21 |  | 18 |
Net interest expense |  | 229 |  | 251 |  | 254 |

Net interest expense decreased in 2016 compared to 2015, primarily as a result of higher capitalized interest relating to the South Hedland power project and the reversal of the accrued interest component of the Keephills 1 provision. See the Other Consolidated Analysis section of this MD&A for further details. These decreases were partially offset by higher interest on debt, due partially to the downgrade to our credit rating from Moody’s and higher average interest rates in 2016 as compared to 2015.

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 the strengthening of the US dollar and other interest expense associated with the adjustment to provisions have partially offset these decreases.

Dividends to Shareholders

On Jan. 14, 2016, we announced a reduction of our common share dividend from $0.72 annually to $0.16 annually. This action was taken as part of a plan to improve our long-term financial flexibility. The declaration of dividends is at the discretion of the Board.

The following are the 2016 common and preferred shares dividends declared each quarter:

|  | Common |  | Preferred Series dividends per share |
|  | dividends |  |  |  |  |  |  |  |  |  |  |
Year ended Dec. 31, 2016 |  | per share |  | A |  | B |  | C |  | E |  | G |
First quarter |  | 0.04 |  | 0.2875 |  | - |  | 0.2875 |  | 0.3125 |  | 0.33125 |
Second quarter |  | 0.04 |  | 0.16931 |  | 0.15490 |  | 0.2875 |  | 0.3125 |  | 0.33125 |
Third quarter |  | 0.04 |  | 0.16931 |  | 0.16144 |  | 0.2875 |  | 0.3125 |  | 0.33125 |
Fourth quarter |  | 0.04 |  | 0.16931 |  | 0.15974 |  | 0.2875 |  | 0.3125 |  | 0.33125 |
Fourth quarter (1) |  | 0.04 |  | 0.16931 |  | 0.15651 |  | 0.2875 |  | 0.3125 |  | 0.33125 |

During the year ended Dec. 31, 2016, 3.9 million (2015 – 9.0 million) common shares were issued to shareholders that elected to reinvest their dividends, for a total of $18 million (2015 - $76 million). On Jan. 14, 2016, we suspended the Premium Dividend TM, Dividend Reinvestment and Optional Common Share Purchase Plan (the “DRIP”).

(1) On Dec. 19, 2016 the Board declared quarterly dividends per common share and preferred shares payable to shareholders of record at the close of business on March 1, 2017.

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Non-Controlling Interests

Comparable earnings attributable to non-controlling interests for the year ended Dec. 31, 2016 increased, $23 million to $103 million compared to 2015, primarily due to the public offering of additional common shares by TransAlta Renewables to finance its investments in the Australian and Canadian portfolios in May 2015 and January 2016, respectively.

In 2015, comparable earnings attributable to non-controlling interests increased $31 million to $80 million compared to 2014, primarily due to the additional common shares issued to the public by TransAlta Renewables to fund its investment in the Australian portfolio.

Ability to Deliver Financial Results

The metrics we use 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 |  |  |  | 2016 |  | 2015 |  | 2014
Comparable EBITDA |  | Target |  | 990 - 1,100 |  | 1,000 - 1,040 |  | 1,015 - 1,065
|  | Actual(1) |  | 1,145 |  | 945 |  | 1,036
Comparable FFO |  | Target |  | 755 - 835 |  | 720 - 770 |  | 743 - 793
|  | Actual |  | 763 |  | 740 |  | 762
Comparable FCF |  | Target |  | 250 - 300 |  | 265 - 270 |  | 274 - 324
|  | Actual |  | 299 |  | 315 |  | 280

Power Generating Portfolio Capital

We monitor availability closely as a key metric to achieving our financial targets. We adjust our maintenance and sustaining capital expenditures to optimize financial returns on our investments and to align with our strategic orientations.

Availability and Production

Our adjusted availability target was 89 to 91 per cent for 2016. Our availability in 2016, after adjusting for economic dispatching at U.S. Coal, was 89.2 per cent (2015 - 89.0 per cent, 2014 - 90.5 per cent) and was comparable to last year. Lower outages and derates at Canadian Coal were mostly offset by higher unplanned outages at our Eastern Wind facilities. Similar availability year-over-year did not impact our performance metrics. |  |

Production for the year ended Dec. 31, 2016, decreased 2,516 GWh compared to 2015, primarily due to the Poplar Creek restructuring that occurred in late 2015 and lower generation from our coal portfolio due to lower prices in the Pacific Northwest and Alberta. Under our new arrangement with Suncor, they now operate the facilities and pay us a fixed monthly fee. Production from renewable assets acquired in the second half of 2015 contributed to partially offset generation lost from Poplar Creek. The Pacific Northwest continues to be dampened by lower prices, where it was more economic to supply our contractual obligation by buying power in the market, rather than through our own generation. In Alberta, lower prices impacted both paid and unpaid curtailments in 2016. |  |

(1) Over the last three years we have had a track record of delivering financial results well within or above guidance. Comparable EBITDA in 2015 and 2016 was impacted by non-cash adjustments related to the Keephills 1 provision. Excluding these adjustments, our Comparable EBITDA would have been $1,065 million in 2016 and $1,004 million in 2015.

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Operational

In the generation segments, our 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 reflect the cost of day-to-day operations.

OM&A costs were $22 million lower in 2016 compared to 2015 as we realized benefits from our cost control and targeted productivity initiatives. Over the last two years we reduced our OM&A costs by almost $40 million. The Poplar Creek restructuring also reduced OM&A costs throughout the year as the facility falls outside our operational scope.

The following table outlines our generation comparable OM&A over the last three years:

|  | 2016 |  | 2015 |  | 2014 |
Generation comparable OM&A |  | 396 |  | 418 |  | 433 |

We continuously drive for the cost-effective operation of our facilities. In 2015, we introduced multiple initiatives to reduce our overhead and increase efficiency and productivity at Canadian Coal. Aside from the reduction in the number of positions in Canadian Coal, we have driven reductions in coal costs through improved mine planning and mining methodologies, reduced equipment requirements, and optimized contractor usage.

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 has been recovered from third parties.

Year ended Dec. 31 |  | 2016 |  | 2015 |  | 2014 |
Routine capital |  | 83 |  | 101 |  | 135 |
Mine capital |  | 23 |  | 25 |  | 45 |
Planned major maintenance |  | 148 |  | 162 |  | 162 |
Finance leases |  | 16 |  | 13 |  | 10 |
|  | 270 |  | 301 |  | 352 |
Flood-recovery capital |  | 2 |  | 4 |  | 9 |
Total sustaining capital expenditures |  | 272 |  | 305 |  | 361 |
Insurance recoveries of sustaining capital expenditures |  | (1 | ) | (25 | ) | (4 | )
Net amount |  | 271 |  | 280 |  | 357 |

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

Year ended Dec. 31 |  | 2016 |  | 2015 |  | 2014 |
GWh lost(1) |  | 938 |  | 1,409 |  | 1,519 |

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

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Total sustaining capital expenditures were $33 million lower compared to 2015. At Canadian Coal, sustaining capital expenditures decreased by $21 million compared to 2015, mainly due to a reduction in maintenance projects without impacting our availability. At our Canadian Gas segment, sustaining capital expenditures decreased by $11 million compared to 2015, as we have been able to reschedule a large inspection of our gas generation units at Sarnia due to a lower number of operating hours. At our Australian Gas segment, planned major maintenance was up by $7 million in 2016 compared to 2015, driven by maintenance projects on two engines at our Kambalda and Kalgoorlie plants.

Strategic Growth

In 2016 we continued to explore opportunities to grow our cash flow but remained prudent and disciplined before allocating capital. We are focused on highly contracted gas and renewable power generation to support our financial position as we transition to having increased merchant capacity in Alberta post-2021. All investments are subject to due diligence procedures and are ultimately reviewed by our investment committee (refer to the Governance and Risk Management section of this MD&A).

Our South Hedland power project continues to progress in line with expectations. At the end of 2016 construction work was largely complete and the project team is now focusing on commissioning activities. The combined-cycle gas turbines achieved first fire in the fourth quarter and commissioning activities continue on these units. We expect to invest $230 million to $250 million to complete the construction of South Hedland, for a total cost of $576 million. We continue to expect the project to be delivered on schedule and on budget in mid-2017. The project is expected to add an additional $80 million of EBITDA annually, when fully in service.

In 2015 we completed two transactions and acquired:

¡ 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.

¡ As part of the restructuring of our Poplar Creek contract, we acquired the 20 MW Kent Breeze wind facility located in Ontario, which has a 20-year contract with the Ontario IESO and a 51 per cent interest in an 88 MW non-contracted wind facility in Alberta. Our interest in the Alberta wind facility was sold in early 2017.

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 last few years, 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 over five years, along with an option permitting the partner to buy back into this project or into other projects of TAMA Power during this period.

Contractual Profile

Approximately 73 per cent of our capacity over the next two years is sold under long-term contracts. Excluding Alberta PPAs for our coal and hydro facilities, the majority of these contracts have maturities in excess of 10 years. In 2016, we entered into a long term contract for the Akolkolex hydro facility in B.C., expiring in 2045. Our South Hedland power project is expected to commence operations mid-2017, which will add stable contracted cash flows until the end of its 25-year contract life. Last year, significant contracts were extended at our Poplar Creek, Windsor, and Parkeston facilities, as discussed in more detail below. The average life of these contracts is approximately 12 years.

With most of our coal and hydro facilities in Alberta rolling off the Alberta PPAs at the end of 2020, we continue to develop a portfolio of commercial and industrial customers to sell our generation to the province. We are now serving a portfolio of approximately 450 MW.

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Poplar Creek

In late 2015, we closed the restructuring of our contractual arrangement for power generation services with 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 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 provide Suncor with 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 merchant wind facility located in Alberta. The Kent Breeze facility has a 20-year contract with the Ontario IESO. On Jan. 26, 2017, we announced the sale of our 51 per cent interest in the Wintering Hills merchant wind facility for approximately $61 million.

The Poplar Creek transaction creates value by increasing the duration of the contract to 2030 from the prior 2023 expiry, while the sale of Wintering Hills reduces our exposure to Alberta’s merchant power market, and allows us an injection of near-term liquidity and financial flexibility to pay down debt. Additionally, we were able to further leverage our interest in the Poplar Creek cogeneration facility by completing a private placement in late December, of $202.5 million bonds that mature in 2030 and are secured by a first ranking charge over the equity interests of the issuer that issued such bonds, further allowing us to deleverage our corporate debt.

Windsor

During the first quarter of 2015, we executed a new 15-year power supply contract with the Ontario IESO for our Windsor facility, which was 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 share of the 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 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.

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Human Capital

Engaging our workforce, developing our employees, and minimizing safety incidents are the keys to human capital value creation at TransAlta. The most material impacts an our human capital performance are an engaged workforce and keeping our employees safe.

As at Dec. 31, 2016, we had 2,341 active employees. This number has decreased by two 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 53 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.

Organizational Culture and Structure

Our employees are central to our value creation. Our corporate culture is one that has been cultivated throughout our more than 100-year heritage of pioneering innovative ways to safely and responsibly generate reliable and affordable electricity. In 2016 we formalized our core values to help provide strategic clarity for our employees. We want our people to align with and live our core values, which are: innovation, respect, loyalty, accountability, integrity, and safety. TransAlta has a stimulating work environment and we seek to challenge our employees to maximize their potential. We encourage alignment with our values and work ethic, while providing a foundation for leadership, collaboration, community support, growth, and work life balance.

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.

Employee Benefits

TransAlta is an attractive employer in all three countries in which we operate. 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 includes 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 pension 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 $73 million to secure the obligations under the supplemental pension plan.

Safety

At TransAlta we operate large and complex facilities. The environments in which we work – including Canadian winters and the Australian outback, often add an additional challenge to keep our employees safe. The safety of our staff, contractors, and visitors is one of the top priorities, if not the top priority, of our social performance. Our safety culture is further embedded into TransAlta culture each year. Every meeting of more than four people starts with a “safety moment,” which helps share key safety learnings across our company. Our Operational Integrity program is focused on reducing safety hazards. Our core values include the safety of our people.

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In 2016 our IFR was 0.85. 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, but annually we seek improvement over the prior year. We have experienced no fatalities during the last three years.

Year ended Dec. 31 |  | 2016 |  | 2015 |  | 2014 |
IFR |  | 0.85 |  | 0.75 |  | 0.86 |

During 2015, we designed a new total safety management policy as a two-pronged approach. The policy builds on 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 preventing all hazards from equipment, through definition and measurement of safety-critical performance measures and operating limits.

Intellectual Capital

Intellectual capital at TransAlta is another key to our value creation. We have developed innovative solutions to optimize and maximize value from our fleet. We are constantly exploring use of applied or new technologies to find solutions to expand or adapt our fleet in an ever-changing world, which helps protect our shareholder value and maintain delivery of reliable and affordable electricity.

Operations Diagnostic Centre

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.

Operational Integrity Program

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 implementing 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 finalized developing the balance of safety-critical maintenance strategies and related engineering standards. 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. Productivity projects are evaluated against criteria that include a two- to three- year financial payback. We also incurred $3 million in 2016 on a productivity improvement blade enhancement technology at our Wolfe Island wind project. This investment is expected to increase the annual energy production of the Wolfe Island wind project by approximately three per cent. In 2017 we are planning to put into place our Total Safety Management System where we integrate our work in Process Safety with our existing Occupational Safety programs. We continue to observe a positive increase in self-reporting and addressing process safety hazards as awareness and new tools are being introduced.

Energy Trading and Marketing

Our energy trading and marketing operations optimize the financial returns of our facilities in real time. The group purchases fuels to feed plants, bids the electricity we generate at our facilities into energy markets, 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 positive margins.

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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 was integrated into our internal control over financial reporting for the year ended Dec. 31, 2016.

Innovation: Applied Technologies

TransAlta has been at the forefront of innovation in the power generation sector since the early 1900s when we developed hydro assets. To add context, these assets were developed at the same time as the automobile. We have been an early adopter of wind technology in Canada and today are the largest wind generator in the country. Today we run a Wind Control Centre, the only one of its kind in Canada, that monitors, to the second, each and every wind turbine we operate across North America. In 2015 we made our first investment in solar technology with the purchase of the Massachusetts solar facilities.

As we move towards becoming the leading clean power company in Canada by 2030 we will continue to seek solutions to innovate. The announcement of our proposed Brazeau hydro expansion, a 600-900 MW pumped hydro expansion, which will double our hydro capacity in Alberta, demonstrates our ability to seek solutions to create value for both our shareholders and society. Hydro is a clean alternative to both coal and gas and has long-term life. We still operate some of our legacy hydro assets from the early 1900s today.

We strive to keep up to date with power technologies that have the potential to redefine power markets today and in the future. Innovation is constantly happening on a more micro scale at TransAlta. For further communication on innovation at TransAlta please visit www.transalta.com/about-us/innovation.

Social and Relationship Capital

Creating shared value for our stakeholders is the key to social and relationship value creation at TransAlta. The most material impacts to our social and relationship performance are public health and safety, anti-competitive behaviour and fostering better relationships and conditions with all stakeholders, but with a key focus on indigenous groups. Each year we strive to do better in each of these areas.

Public Health and Safety

We seek to ensure public health and safety through measures such as restricting physical access to our operating sites and by minimizing our environmental impact. It is our goal to both keep our employees safe and the peoples and the communities in which we operate.

We specifically look to protect against the following risks:

¡ harm to person(s),

¡ damage to property,

¡ increased liability due to negligence, and

¡ loss of organizational reputation and integrity.

When addressing concerns such as occupiers liability, our Corporate Security team liaises with stakeholders to facilitate appropriate security countermeasures and controls to prevent or reduce the identified risk. For example, in 2016 our Corporate Security term initiated a security/safety signage campaign across the Hydro fleet to elevate the awareness of the safety risks associated with dams. By implementing signage from a safety perspective, Corporate Security and TransAlta also benefited from a security perspective. Signage gave notice of potential physical dangers, but also allows as an organization and landowner to reduce liability and increase safety through notice, awareness, and mitigation of trespassing and vandalism.

We actively monitor air emissions from our coal and gas plants. Our large coal facilities have Continuous Emissions Monitoring Systems (“CEMS”) in place, which help us monitor our pollutant emission levels in line with acceptable limits. When we are in breach of regulatory limits we report this to Alberta Environment & Parks and conduct a root cause analysis to understand how we can eliminate future breaches from occurring. In 2016 we had two breaches at our Alberta coal facilities. Both breaches were minor and due to an instrumentation calibration failure at Keephills 3 and an opacity CEMS analyzer failure at the Sundance operations.

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Of note, our coal plants currently capture 80 per cent of mercury emissions and the majority of particulate matter emissions. Both have been deemed harmful to human health, which we recognize and work to minimize through capture. The health impact risk from emissions that do reach our environment is minimized due to the location of our plants, which are located away from urban environments. Independent studies conducted by University of Alberta scientist Dr. Warren Kindzierski, using provincial government monitoring data from the past nine years, also show that only approximately 10 per cent or less of all particulate matter in the airshed in the largest urban environment close to our facilities, Edmonton, can be attributed to coal combustion emissions. Chemical “signatures” for emissions pointed to several sources of air quality concern in Edmonton, including local industries, vehicles, and wood-burning fireplaces.

We are currently evaluating the option of converting some of our coal-fired units to natural gas units in 2022 and 2023, which will represent 90 per cent of our coal fleet at that point in time. This action will reduce our GHG emissions by close to 50 per cent. It will also eliminate the majority, if not all, of our mercury emissions and nitrogen oxide emissions from our Alberta coal facilities.

Stakeholder Relations

TransAlta implemented a corporate stakeholder engagement framework in 2016, a streamlined corporate-wide approach to ensure that engagement and relationship-building practices are consistent across TransAlta’s locations and types of work. This framework is modelled and closely tied to the stakeholder engagement aspect of ISO 14001, which is an internationally recognized environmental management standard.

In 2016 we introduced our Stakeholder and Aboriginal Relations (“STAR”) tracking program. STAR functions as a communication record-keeping tool, which is managed by our Stakeholder and Aboriginal Relations team. This capacity fulfils our requirements for consultation with stakeholders and aboriginal groups alike, and is capable of producing reports (notably, government reports) as proof of engagement and consultation efforts. Built as a SharePoint page, STAR has the capacity to centralize information and grant different levels of access to the information it stores.

Some features of the STAR program include:

¡ in-house application with no operating cost or fees,

¡ centralized for the entire company to use,

¡ different levels of accessibility (privileges),

¡ can store email conversations, documents, and voice-mail messages related to any project, event, or issue; and use them in reports, and

¡ produces an array of statistical reports showing frequencies and volumes of engagement based on project, stakeholder, stakeholder group, issue, or keywords.

The Board believes that it is important to have constructive engagement with its shareholders and other stakeholders and has established means for the shareholders of the Company and other stakeholders to communicate with the Board through the use of a confidential Ethics Helpline or by writing directly to the Board. The contact information for communicating with the Board is published in Whistleblower section of this MD&A. Shareholders and other stakeholders may, at their option, communicate with the Board on an anonymous basis. In addition, the Board has adopted an annual non-binding advisory vote on the Company’s approach to executive compensation. The Company is committed to ensuring continued good relations and communications with its shareholders and other stakeholders and will continue to evaluate its practices in light of any new governance initiatives or developments.

Aboriginal Relations

The focus of our efforts in this area is to establish solid relationships with indigenous and Métis communities, recognizing and respecting their rights and focusing on engaging them at the earliest stages of any project or development. Specifically, our aboriginal relations team continues to develop and enhance aboriginal relations in areas of employment, economic development, community engagement, and investment. Since 2014, we have achieved the Canadian Council for Aboriginal Business’s silver-level Progressive Aboriginal Relations certification. As noted above, in 2016 we introduced our STAR tracking program, which functions a communication record-keeping and engagement measurement tool.

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Local Communities

We provide public benefit through reliable, cost-efficient power and related outputs or services. With the phase-out of coal on the horizon, we seek to secure favourable outcomes for our workers and the communities surrounding our plants. Our proposed coal-to-gas conversions provide the opportunity to maintain some jobs during conversions, to support sector jobs, and to redeploy some of our workforce in the plants or toward renewables growth. Electricity and energy have always been at the heart of the economy in Alberta, and any changes in the industry must therefore support our communities. Conversion will also help keep municipal, provincial, and federal tax revenues supporting these communities. TransAlta advocates for sufficiently long timelines for transition, support for facility redevelopment, funds for retraining, and economic diversification.

Community

During 2016, TransAlta contributed $2.5 million in donations and sponsorships (2015 - $3.5 million).

On July 30, 2015, we announced that we were 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.

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 Alberta Market Surveillance Administrator (“MSA”) reached an agreement to settle all outstanding proceedings before the AUC. The settlement, which was in the form of a consent order, was approved by the AUC on Oct. 29, 2015. Under the terms of the agreement, we agreed to pay a total amount of $56 million that included approximately $27 million as a repayment of economic benefits, approximately $4 million to cover the MSA’s legal and related costs, and a $25 million administrative penalty. Of this amount, $31 million was paid in the fourth quarter of 2015, and $25 million was paid in the fourth quarter of 2016.

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 asked a national law firm with expertise in electricity markets, and a national accounting firm, to complete independent third-party reviews of our then current compliance procedures around forced outages. We also asked them to review our trading compliance program to ensure that our current practices met the company’s legal and ethical obligations and the high expectations of our customers and stakeholders, the results of which were made public during the first half of 2016.

The national law firm assessment concluded that:

¡ outage practices are consistent with the law in Alberta, and

¡ senior management has demonstrated a strong commitment to compliance.

Recommendations were provided to formalize the outage practices and procedures and related document management, and to incorporate the procedures into the existing TransAlta Compliance programs in terms of training, investigation procedures and annual reviews.

Using a 10-point compliance effectiveness review framework, the national accounting firm’s assessment of TransAlta’s Energy Trading Compliance Program concluded that:

¡ from a program design perspective, TransAlta’s program contains each of the 10 components of an effective compliance program, and includes the key elements required and normally seen at industry peers, and

¡ in terms of operational effectiveness, TransAlta’s program meets or exceeds current industry practice in each of the 10 components.

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Recommendations were provided in 5 of the 10 areas, for increasing cross functional communications, cross-training of compliance staff, scheduling of training components more frequently throughout a year, formalizing documentation of monitoring tools and performance review assessments for compliance.

TransAlta has accepted all of the recommendations in both reports.

Natural 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 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. Currently the most material natural or environmental capital impacts to our business are GHG emissions, air emissions (pollutants, metals), and energy use. Material impacts that we manage and track include our environmental management systems, environmental incidents and spills, land use, water usage, and waste management.

In the jurisdictions in which we operate, legislators have proposed and enacted regulations to discontinue, over time, the use of the technologies 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 therefore we 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 10 years, we have added approximately 1,300 MW in renewable energy capacity. From our Alberta wind fleet, 360 MW of capacity generates offsets that can be applied against GHG emissions in Alberta. Annual revenue generation from these offsets is in the range of $10 million to $15 million.

¡ 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. In 2016 we achieved an 80 per cent capture rate of mercury at all coal facilities. Our Keephills 3 and Genesee 3 plants use supercritical combustion technology to maximize thermal efficiency, as well as sulphur dioxide (“SO 2”) capture and low oxides of nitrogen (“NOx”) combustion technology. Uprate or energy- efficiency 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 environmental rules (as detailed in the following Regional Regulation and Compliance subsection), we investigate the cost effectiveness of multiple technological solutions and various operating models in order to prepare appropriate work scopes. In 2016 we announced our proposed coal to natural gas conversions and support for the Government of Alberta’s renewable electricity plans.

¡ 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. In 2016 we entered into the MOU with the Government of Alberta, which entails co-operation and collaboration to enable the conversion of coal-fired generation to gas-fired generation.

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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, the majority of which closely mimic the internationally recognized ISO 14001 EMS standard. We have operated our facilities in line with ISO 14001 for 17 years, and our systems and knowledge of management systems are therefore mature. In 2016 we moved to no longer certify our Alberta coal plants as ISO 14001, but the plants continue to run best practice EMS, as do 97 per cent of our facilities. Only two of our facilities do not closely track ISO 14001, which is due to commercial arrangements (we are not the primary operator), but these facilities still have EMS in place.

Environmental Incidents and Spills

We recorded 16 reportable environmental incidents in 2016 (2015 - 12 incidents), which was above our target of 13. None of these incidents resulted in a material environmental impact. Our Gas & Renewables fleet recorded only three incidents in 2016, a record year. The remainder of our 13 environmental incidents occurred at our Alberta Coal business unit. Incident types included spills, which were highly recoverable, air emission exceedances or instrument failures, wastewater sampling errors, effluent releases, water blowdown exceedances, and process safety incidents. We will continue to target improvement in 2017 with a specific focus on Alberta Coal. Our corporate-wide 2017 target is 11 or fewer incidents. We also continue to track and manage all non-reportable (minor) environmental incidents, which helps us identify what leads to an incident. Understanding the root cause of incidents helps with incident prevention planning and education.

Typical spills at TransAlta are hydrocarbon spills, which happen in low environmental impact areas and are almost always contained and recovered. It is extremely rare that we experience large spills with impact on the environment. Spills that do occur that we must report are typically just above acceptable regulatory spill limits and these are always addressed with a critical time factor. The volume of spills in 2016 was 61 m 3 (2015 - 19 m 3), of which 78 per cent was recovered (2015 - 99 per cent recovered). The increase is attributable to three large spills, two at our Sundance coal operations and one at Mt Keith in southwestern Australia. All three incidents were contained at our sites and were reported to the appropriate bodies.

Energy Use

TransAlta uses energy in a number of different ways. We burn coal, gas, and diesel to generate electricity. We harness the kinetic energy of water and wind to generate electricity. We also utilize the sunshine to generate electricity. In addition to combustion of fuel sources we also track combustion of fuel in the vehicles we use and energy use in the buildings we occupy. Knowledge of how much energy we use allows us to optimize and create energy efficiencies.

The following are our millions of gigajoules of energy use. On a comparable basis, our energy use has declined over the last three years as a result of lower generation from our coal-generating assets.

Year ended Dec. 31 |  | 2016 |  | 2015 | (1) | 2014 |
Coal |  | 469.1 |  | 483.4 |  | 529.7 |
Gas and Renewables |  | 59.2 |  | 58.7 |  | 54.3 |
Corporate |  | 0.1 |  | 0.1 |  | 0.1 |
Total energy use |  | 528.4 |  | 542.2 |  | 584.1 |

(1) Gas & Renewable 2015 volumes were restated due to a diesel volume reporting error at our Solomon facility.

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Greenhouse Gas Emissions

In 2016, we estimate that 30.7 million tonnes of GHGs with an intensity of 0.84 tonnes per MWh (2015 - 32.2 million tonnes of GHGs with an intensity of 0.87 tonnes per MWh) were emitted as a result of normal operating activities.(1) Our GHG emissions decreased slightly in 2016, primarily as a result of lower production from coal plants. Other decreases in emissions of the Canadian 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.

The following are our GHG emissions in million tonnes CO 2:

Year ended Dec. 31 | 2016 | 2015 | 2014
Coal | 27.7 | 29.2 | 32.3
Gas and renewables | 3.0 | 3.0 | 2.7
Total GHG emissions | 30.7 | 32.2 | 35.0

Our continued investment in growth from renewable power generation further supports the decrease in emissions intensity observed in 2016. We believe in proactive measurement and disclosure of air emissions.

In 2016, TransAlta improved its scoring on the Carbon Disclosure Project Climate Change report to a B, our highest integrated score yet. We were also highlighted by Chartered Professional Accountants of Canada as the only company in Canada, out of 75 companies, that reports on climate change across all levels of disclosure: the annual information form, this MD&A, and our information circular.

Refer to the Climate Change section of this MD&A for further information.

Air Emissions

In 2016 air emissions were down compared with 2015. Air emissions decreased slightly in line with reduction in coal power generation.

Year ended Dec. 31 | 2016 | 2015 | 2014
Sulphur dioxide (tonnes) | 39,600 | 41,800 | 47,600
Nitrogen oxide (tonnes) | 48,400 | 48,000 | 52,900
Particulate matter (tonnes) | 4,900 | 4,900 | 5,200
Mercury (kilograms) | 130 | 170 | 220

Our continued investment in growth from renewable power generation further supports the decrease in emissions intensity observed in 2016. We believe in proactive measurement and disclosure of air emissions.

(1) 2016 data are estimates based on best available data at the time of report production. GHGs include water vapour, carbon dioxide (“CO 2”), methane, nitrous oxide, sulphur hexafluoride, hydrofluorocarbons, and perfluorocarbons. The majority of our estimated GHG emissions are comprised of CO 2 emissions from stationary combustion.

Emissions intensity data has been aligned with the ‘Setting Organizational Boundaries: Operational Control’ methodology set out in The GHG 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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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 range of 220-240 million m 3 of water across our fleet. In 2016 we withdrew 247 million m 3 and returned approximately 188 million m 3 back to its source. 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 in which we operate. The difference between withdraw and discharge, representing consumption, is largely due to evaporation loss.

The following represents our total water consumption (million m 3 ) over the last three years:

Year ended Dec. 31 | 2016 | 2015 | 2014
Water from environment | 247 | 272 | 243
Water to environment | 188 | 198 | 172
Total water consumption | 59 | 74 | 71

Our areas of higher water risk are situated east of Perth in our simple-cycle gas plants in Western Australia and in our Southern Alberta hydro operations. We monitor and manage water risk in our operating areas east of Perth.

In Southern Alberta, following the flood of 2013, our hydro facilities are being used for an increased water management role than they have played in the past. During 2016, we signed a five-year agreement with the Government of Alberta to manage water on the Bow River at our Ghost reservoir facility to aid in potential flood mitigation efforts, as well as at our Kananaskis Lakes System (which includes Interlakes, Pocaterra and Barrier), for drought mitigation efforts.

Land Use

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-establishing of drainage, replacing 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 2016, we reclaimed 39 acres (16 hectares) at our Highvale mine, which was 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 Centralia mine is no longer actively used for coal operations, but reclamation activity is ongoing. In 2016 we reclaimed 38 hectares of land.

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 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. Byproduct sales and associated annual revenue generation typically ranges from $25 million to $35 million.

Coal Transition

Our coal transition, whether it is executing on our coal-to-gas conversion plans or completing a full phase-out by 2030, will vastly improve our environmental performance. Energy use, GHG, air emissions, waste generation, and water usage will all significantly decline. A conversion of coal-fired power generation to gas-fired generation is expected to eliminate all mercury emissions and the majority of nitrogen oxide emissions.

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Climate Change

Governance

TransAlta’s Governance and Environment Committee (“GEC”) is a Board-appointed committee that reports directly to the Board of Directors to help fulfil oversight responsibility with respect to environment, health, and safety. In conjunction, the GEC and Board hold the highest levels of oversight in regards to TransAlta’s climate change policy and sustainability initiatives.

Strategy

Climate change related risks are monitored through our company-wide risk management processes and actively managed. Identified climate change risks and opportunities are also reviewed by our management team through our Governance and Environment Committee. We attribute regionally specific carbon pricing, both current and anticipated, as a mechanism to manage future risks pertaining to uncertainty in the carbon market and as a safeguard to anticipate future impacts of regulatory changes on facilities. It is also a method of modelling for future electricity prices and to analyze the viability of acquisitions. Identified climate change risks or opportunities and carbon pricing are recognized in the annual TransAlta long-and-medium range forecasting processes. Regulatory risk/compliance (coal electricity generation), physical risks (hydro and drought/floods), and monetary opportunities (gas and renewable electricity generation) are the main drivers of integration into business strategy.

Aligned with our business strategy is our climate change strategy, which is implemented and managed on a corporate-wide business unit level, consisting of four main areas of focus:

§ Energy-efficiency improvements,

§ Development of emissions offsets portfolios to achieve emissions reductions at competitive costs,

§ Development of clean combustion technologies,

§ Growth of our renewables portfolio as an increasing component of our total generation portfolio.

We seek investment in climate change related mitigation solutions where we can maximize value creation for our shareholders, local communities, and the environment. Anticipated conversion of our large coal fleet to gas-fired generation highlights this approach, which will allow us to run our assets longer than the federally mandated coal retirement schedule. Our anticipated actions maximize value for our shareholders, ensure low-cost and reliable power for Albertans, and reduce the environmental impact from coal-fired generation.

Our investment and growth in renewable energy is highlighted by our diverse portfolio of renewable energy generating assets. We currently operate and are invested in over 2,200 MW of hydro, wind, and solar power. We are the largest producer of wind power in Canada and the largest producer of hydro in Alberta. Production from renewable energy in 2016 resulted in avoidance of over 3.1 million tonnes of CO2e, which is equivalent to removing over 730,000 vehicles from North American roads. For further details on governance and risk, see our Governance and Risk Management section of this MD&A.

Targets

We recognize climate change risk and the goal set out in the 2015 Paris Agreement to prevent two degrees Celsius of global warming above pre-industrial levels. Our GHG reduction targets have been established to align with the UN Sustainable Development Goals, specifically Goal 13, which calls for “urgent action to combat climate change and its impacts.” Our 2030 GHG reduction target is set based on climate-based science and the goal of preventing two degrees Celsius of global warming. This target is approved by the Science Based Targets initiative, which is a partnership between the Carbon Disclosure Project, UN Global Compact, World Resources Institute and World Wildlife Fund, which helps companies determine how much they must cut emissions to prevent the worst impacts of climate change.

Our GHG reduction targets are as follows:

1. Our goal, in line with a commitment to the UN Sustainable Development Goals (“SDGs”), is to reduce our total GHG emissions in 2021 to 30 per cent below 2015 levels.

2. Our goal, in line with a commitment to the UN SDGs and prevention of two degrees Celsius of global warming, is to reduce our total GHG emissions in 2030 to 60 per cent below 2015 levels.

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Regional Regulation and Compliance

Carbon issues and related legislation will continue to have an impact on 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 carbon 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 carbon requirements, as well as changes in our liabilities under these requirements, which may have a material adverse effect upon our consolidated financial results.

Canadian Federal Government

In November 2016, the Canadian federal government announced that coal-fired generation would be phased out by 2030, following a similar commitment by the Alberta provincial government in November 2015. These two decisions changed the coal plant closure requirements, which had previously been guided by the federal regulations that became effective on July 1, 2015 which provided for up to 50 years of life for coal units. According to the new shut-down requirements, the Corporation’s older coal units (which retire prior to 2030) will be guided by the 50-year life rule, while newer units (which were previously scheduled to retire post-2030) will face the new 2030 shutdown date. In November 2016, the Corporation signed an OCA with the Alberta Government that confirmed the 2030 shutdown commitment for the impacted units.

On Nov. 21, 2016, the Canadian federal government announced that the Department of Environment and Climate Change will be developing regulations for gas-fired generation. The announcement confirmed plans to include specific rules for coal-to-gas converted units, including a proposed 15-year life and a separate emissions intensity standard. The Canadian federal government will conduct consultations on the proposed regulation in the first two quarters of 2017. Finalized regulations are currently expected by the end of 2018.

On Oct. 3, 2016, the Canadian federal government announced its intention to implement a national price on GHG emissions. Under this proposal, beginning in 2018, there would be a price of $10 per tonne of carbon dioxide equivalent emitted, rising to $50 per tonne by 2022, or a comparable reduction in GHGs under a cap-and-trade program. The application of the price would be co-ordinated with provincial jurisdictions. We do not yet know how such a price mechanism will affect our operations.

Alberta

On Nov. 22, 2015, the Government of Alberta announced through the Climate Leadership Plan its intent, among other things, to phase out emissions from coal-fired generation by 2030, replace two-thirds of the retiring coal-fired generation with renewable generation, and impose a new carbon price of $30 per tonne of CO 2 emissions based on an industry-wide performance standard. On March 16, 2016, the Government of Alberta announced the appointment of a Coal Phase-out Facilitator to work with coal-fired electricity generators, the Alberta Electric System Operator (“AESO”), and the Government of Alberta to develop options to phase out emissions from coal-fired generation by 2030. The Coal Phase-out Facilitator was tasked with presenting options to the Government of Alberta that would strive to maintain the reliability of Alberta’s electricity grid, maintain stability of prices for consumers, and avoid unnecessarily stranding capital.

In March 2016, Alberta began development of its renewable energy procurement process design for the AESO to procure a first block of renewable generation projects to be in-service by mid-2019. On Sept. 14, 2016, the Government of Alberta reconfirmed its commitment to achieve 30 per cent renewables in Alberta’s electricity energy mix by 2030.

On May 24, 2016, the Government of Alberta passed the Climate Leadership Implementation Act which establishes the carbon tax framework for its application to fuels. It is expected that additional regulations will be developed governing the treatment of large industrial emitters. The Climate Leadership Plan will be implemented for the electricity sector on January 1, 2018.

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On Nov. 24, 2016, we announced that we had entered into the OCA, which provides for transition payments for the cessation of coal-fired emissions from the Keephills 3, Genesee 3 and Sheerness coal-fired plants on or before Dec. 31, 2030. The affected plants are not, however, precluded from generating electricity at any time by any method other than the combustion of coal. Under the terms of the OCA, the Corporation will receive annual cash payments of approximately $37.4 million, net to the Corporation, commencing in 2017 and terminating in 2030. For further details, refer to the Highlights section of this MD&A.

Additionally, we announced that we had reached an understanding set out in the MOU to collaborate and co-operate with the Government of Alberta in the development of a policy framework to facilitate the conversion of coal-fired generation to gas-fired generation, facilitate existing and new renewable electricity development through supportive and enabling policy, and ensure existing generation and new electricity generation are able to effectively participate in the recently announced capacity market to be developed for the Province of Alberta.

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 Specified Gas Emitters Regulation:

§ 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 SO 2 once the units 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 Clean Air Strategic Alliance (“CASA”). The release of the federal regulations in 2012 adopted by the Government of Canada and the Government of Alberta, and the accelerated coal-fired generation retirement schedule, creates a potential misalignment between the CASA air pollutant requirements and schedules, and the retirement schedules for the coal plants, which in themselves will result in significant reductions of NOx, SO 2, and particulate emissions, something which has been identified as a matter yet to be addressed in the MOU.

The Government of Alberta’s Renewable Electricity Program is intended to encourage the development of 5,000 MW of new renewable electricity capacity by 2030. The AESO is currently soliciting interest in the first competitive procurement for 400 MW under the program. Proponents must submit an expression of interest by late March 2017. The process will be followed by a request for qualification in late April 2017, request for proposal in mid-September 2017 and successful proponents announced in December 2017. Eligible projects must be 5 MW or larger and can be hydro, wind, solar, and certain biomass. The successful projects will be awarded a Renewable Electricity Supply Agreements that utilizes an indexed renewable energy credit or contract for difference mechanism that will fix the price to the proponent over 20 years. The contracts are expected to require the facility to be operational by 2019.

The Government of Alberta has tasked the AESO with transitioning Alberta’s energy-only market to a capacity market structure. The capacity market will help to ensure that there is sufficient supply adequacy as over 6,000 MW of coal generation retires by 2030. The new market structure is expected to reduce the reliance on scarcity pricing, which drives energy price volatility and the price signal for new investment, and compensate resource owners with monthly capacity payments for making their capacity available in the energy and ancillary services market. The AESO plans to engage stakeholders in determining the design and implementation of the capacity market over 2017 and 2018 and conduct the first auction in 2019 with a contract delivery year targeted for 2021. The AESO has suggested they will need new capacity in 2021.

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Pacific Northwest

On Dec. 17, 2014, Washington State Governor Jay Inslee released a carbon-emissions reduction program for the state, which is 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.

On Aug. 3, 2015, former U.S. 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 MWh) 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 Feb. 9, 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan pending consideration as to whether the regulations are lawful. It is not clear yet how this may affect the future of the Clean Power Plan. As a result of our 2011 agreement for coal transition with the State of Washington, we do not expect the proposed regulations to significantly affect our U.S. 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 currently 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 Feb. 25, 2016, Ontario released draft regulations for its GHG cap-and-trade program that were finalized on May 19, 2016. The regulations became effective Jan. 1, 2017, and will apply to all fossil fuels used for electricity generation. The majority of our gas-fired generation in Ontario will not be significantly impacted by virtue of change-in-law provisions within existing power purchase agreements.

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 renewables capacity to be installed to add to the slightly more than 4,000 MW already operating. Since our Australian assets are fully contracted it is not expected that these amendments will have a significant impact on our operations.

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Weather

Abnormal weather events can impact our operations and give rise to risks. In addition, normal year-over-year 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 in substantial repair work. Our losses have been largely covered through insurance,

§ 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, and

§ our Alberta mine was susceptible to significant rain starting in August of 2016, which resulted in several weeks of flooding and impacted our coal deliveries. We focused on improving drainage infrastructure and use of stockpiles to mitigate future risks.

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 and benefitted our Energy Marketing Group.

Other Consolidated Analysis

Asset Impairment Charges and Reversals

As part of our monitoring controls, long-range forecasts are prepared for each Cash Generating Unit (“CGU”). The long-range forecast estimates are used to assess the significance of potential indicators of impairment and provide a criteria to evaluate adverse changes in operations. When indicators of impairment are present, we estimate a recoverable amount for each CGU by calculating an approximate fair value less costs of disposal using discounted cash flow projections based on the Corporation’s 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.

In 2016, we concluded that an indicator of possible impairment existed with respect to our U.S. Coal facility as the plant has merchant exposure and price expectations in the Pacific Northwest region continued to decline. The results of the impairment analysis are outlined in section III below.

During 2016, uncertainty continued to exist within the province of Alberta regarding the government’s previously announced Climate Leadership Plan and the future design parameters of the electricity market. Additionally, economic conditions, while more stable than in 2014 and 2015, contributed to continued over-supply conditions and depressed market prices. We assessed whether these factors presented an indicator of impairment for our Alberta Merchant CGU, and in consideration of the composition of this CGU and events arising during the latter part of 2016, which are more fully discussed below in I, determined that no indicators of impairment were present with respect to the Alberta Merchant CGU. Due to this determination, we did not perform an in-depth impairment analysis, but sensitivities associated with these factors were performed to confirm the continued existence of an adequate excess of estimated recoverable amount over net book value.

There was one impairment charge of $28 million (2015 - $2 million reversal) made during the year ended Dec. 31, 2016 as a result of the sale of our 51 per cent interest in the Wintering Hills merchant wind facility as discussed below in II.

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I. Alberta Merchant CGU

In 2015, the Government of Alberta announced its Climate Leadership Plan (“CLP”), which broadly called for the phase-out of coal-generated electricity by 2030, and proposed the imposition of additional compliance obligations for GHG emissions in the province. In 2016, the Government of Alberta refined its approach to GHG by instituting a levy on carbon emissions in excess of defined limits, amounting to $20 per tonne in 2017 and $30 per tonne in 2018. At the federal level, the Canadian government announced its intention to implement a national price on GHG emissions. Under this proposal, beginning in 2018, there would be a price of $10 per tonne of carbon dioxide equivalent emitted, rising to $50 per tonne by 2022.

On November 24, 2016, we entered into the OCA with the Government of Alberta to receive annual cash payments of approximately $37.4 million, net to us in return for ceasing coal-fired generation by the end of 2030, among other conditions. Furthermore, we entered into an MOU on Nov. 24, 2016, with the purpose of collaborating and co-operating to advance objectives of the Alberta CLP. Specifically, the parties collaborated on initiatives that included:

§ a move toward a capacity market, commencing 2021, compared to the current energy-only market. Under a capacity market, generators are compensated for their available capacity;

§ development of a policy and to facilitate the economic conversion of some coal-fired generation to natural gas-fired generation in Alberta, including securing regulatory co-operation from the federal government; and

§ development of supportive and enabling policy, including policy that addresses the value of carbon reductions in the generation of electricity from existing wind and hydro generation, the development of effective supporting mechanisms to ensure that existing renewables generation is not adversely impacted by the implementation of a capacity market in Alberta, and the development of regulatory clarity and alignment so as to permit the economic and timely development of hydroelectric projects within Alberta.

The MOU does not create any legally binding obligations between the Government of Alberta and the Corporation and does not impose any obligations on, or constrain the discretion and authority of the Government of Alberta. The announcement of the intention to move to a capacity market is expected to impact the Alberta market mechanisms. The Government of Alberta has not provided further detail on the market rules or construct. The introduction of a capacity market to replace Alberta’s current market structure could impact our determination of the Alberta Merchant CGU; however, there is not currently sufficient information from the Government of Alberta to determine if a change is required. We have not modified its previous conclusions on the determination of the Alberta Merchant CGU.

During the year, we monitored the potential impacts of the CLP and other announcements on the Alberta CGU. A sensitivity analysis on these estimates to assess potential impacts of the Alberta and federal government policies on the carbon levy and GHG emissions, as well as the impacts of the OCA and MOU. The analysis of the Alberta Merchant CGU, with its large merchant renewable fleet, resulted in no impairment in 2016.

II. Wintering Hills

On Jan. 26, 2017, we announced the sale of our 51 per cent interest in the Wintering Hills merchant wind facility for approximately $61 million. In connection with this sale, the Wintering Hills assets were accounted for as held for sale at December 31, 2016. As required, we assessed the assets for impairment prior to classifying them as held for sale. Accordingly, we have recorded an impairment charge of $28 million using the purchase price in the sale agreement as the indicator of fair value less cost of disposal.

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III. U.S. Coal

We considered possible impairment at the U.S. Coal CGU, and again found that the fair value less costs to sell approximates the current carrying amount. We estimated the fair value less costs of disposal of the CGU, a Level III fair value measurement, utilizing our long-range forecast and the following key assumptions:

Mid-Columbia annual average power prices | US$22.68 to 45.65 per MWh
On-highway diesel fuel on coal shipments | US$1.69 to 2.09 per gallon
Discount rates | 5.4 to 5.7 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 its operating activities and capital plan.

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. No further reversals or impairments were recorded in 2016.

Other Significant and Subsequent Events

Alberta Off-Coal Agreement

On Nov. 24, 2016, we announced that we entered into the OCA with the Government of Alberta on transition payments in exchange for the cessation of coal-fired emissions from the Keephills 3, Genesee 3 and Sheerness coal-fired plants on or before Dec. 31, 2030.

Under the terms of the OCA, we will receive annual cash payments of approximately $37.4 million, net to the Corporation, commencing in 2017 and terminating in 2030. Receipt of the payments is subject to terms and conditions. The OCA’s main condition is the cessation of all coal-fired emissions in 2030. Other conditions include maintaining prescribed spending on investment and investment-related activities in Alberta, maintaining a significant business presence in Alberta (including through the maintenance of prescribed employment levels), and maintaining spending on programs and initiatives to support the communities surrounding the plants, and the employees of the Corporation negatively impacted by the phase-out of coal generation and fulfilling all obligations to affected employees. The affected plants are not, however, precluded from generating electricity at any time by any method, other than the combustion of coal.

Force Majeure Relief - Keephills 1

Keephills 1 tripped off-line on March 5, 2013, due to a suspected winding failure within the generator. After extensive testing and analysis, it was determined that a full rewind of the generator stator was required. After completing the repairs, the unit returned to service on Oct. 6, 2013. We claimed force majeure relief on March 26, 2013. The buyer, ENMAX, disputed the claim of force majeure, which triggered the need for an arbitration hearing that took place in May 2016. On Nov. 18, 2016, we announced that the independent arbitration panel confirmed our claim for force majeure relief. Accordingly, we reversed a provision of approximately $94 million. The buyer and the Balancing Pool are seeking to appeal or set the arbitration panel’s decision aside in the Court of Queen’s Bench of Alberta. We oppose these steps and believe they are without merit.

M52 TRANSALTA CORPORATION

Memorandum of Understanding with the Government

In November 2016, we additionally reached an understanding with the Government of Alberta pursuant to an MOU to collaborate and co-operate in the development of a policy framework to facilitate the conversion of coal-fired generation to gas-fired generation, facilitate existing and new renewable electricity development through supportive and enabling policy, and ensure existing generation and new electricity generation are able to effectively participate in the recently announced capacity market to be developed for the province of Alberta. Specifically, the parties undertook to collaborate on, among other things:

§ work to ensure existing incumbents and new electricity generation are able to effectively participate in capacity payment auctions to be established as part of the development of a capacity market,

§ development of a policy environment to facilitate the economic and environmentally responsible conversion of some coal-fired generation to natural gas-fired generation in Alberta, including securing regulatory cooperation from the federal government, and

§ development of supportive and enabling policy, including policy that addresses the value of carbon reductions in the generation of electricity from existing wind and hydro generation, the development of effective supporting mechanisms to ensure that existing renewables generation is not adversely impacted by the implementation of a capacity market in Alberta, and the development of regulatory clarity and alignment so as to permit the economic and timely development of hydroelectric projects within Alberta.

The MOU does not create any legally binding obligations between the Government of Alberta and the Corporation and does not impose any obligations on, or constrain the discretion and authority of, the Government of Alberta.

Mississauga Cogeneration Facility New Contract

On Dec. 22, 2016, we announced that we had signed a Non-Utility Generator (“NUG”) Enhanced Dispatch Contract (the “NUG Contract”) with the IESO for our Mississauga cogeneration facility (the “Mississauga Facility”). The NUG Contract is effective on Jan. 1, 2017, and in conjunction with the execution of the NUG Contract, we agreed to terminate effective Dec. 31, 2016, the Facility’s pre-existing contract with the Ontario Electricity Financial Corporation, which would have otherwise terminated in December 2018.

The NUG Contract provides us stable monthly payments until Dec. 31, 2018, totalling approximately $209 million, reduced operational costs, and the ability to maintain operational flexibility to pursue opportunities for the Mississauga Facility to meet power market needs in northeastern Ontario.

As a result of the NUG Contract, we recognized a pre-tax gain of approximately $191 million. The predominant components of the gain relate to recognition of a one-time discounted revenue amount of approximately $207 million, offset by onerous contract expenses and other termination charges totalling $15 million. We also recognized $46 million in accelerated depreciation resulting from the change in useful life of the asset. We released and recognized in earnings unrealized pre-tax losses of net $14 million from Accumulated Other Comprehensive Income (“AOCI”) due to cash flow hedges de-designated for accounting purposes. The cash flow hedges were in respect of future gas purchases denominated in US dollars expected to occur between 2017 and 2018. In the fourth quarter of 2016, the forecasted gas consumption was no longer expected to occur, which resulted in the cumulative loss on the hedging instruments being released from AOCI and recognized in earnings.

TRANSALTA CORPORATION M53

Investment and Acquisition by TransAlta Renewables of the Sarnia Cogeneration Plant, Le Nordais Wind Farm, and Ragged Chute Hydro Facility

On Jan. 6, 2016, TransAlta Renewables completed its investment in an economic interest based on the cash flows of the Corporation’s Canadian Assets for a combined aggregate value of approximately $540 million. The Canadian Assets consist of approximately 611 MW of highly contracted power generation assets located in Ontario and Québec. The transaction was originally announced on Nov. 23, 2015.

As consideration, TransAlta Renewables provided to the Corporation $173 million in cash, issued 15,640,583 common shares with an aggregate value of $152 million, and issued a $215 million convertible unsecured subordinated debenture. The debenture issued by TransAlta Renewables to the Corporation is on an interest-only basis at a coupon of 4.5 per cent per annum payable semi-annually in arrears on June 30 and December 31, and will mature on Dec. 31, 2020. On the maturity date, the Corporation will have the right, at its sole option, to convert the outstanding principal amount of the debenture, in whole or in part, into common shares of TransAlta Renewables at a conversion price of $13.16 per common share, being a 35 per cent premium to the offering price on the closing date of the investment in the Canadian Assets. If TransAlta does not exercise its conversion option, TransAlta Renewables may satisfy the principal obligation through issuance of common shares with a unit value corresponding to 95 per cent of its then-current common share value.

TransAlta Renewables funded the cash proceeds through the public issuance of 17,692,750 subscription receipts at a price of $9.75 per subscription receipt. Upon the closing of the transaction, each holder of subscription receipts received, for no additional consideration, one common share of TransAlta Renewables and a cash dividend equivalent payment of $0.07 for each subscription receipt held. As a result, TransAlta Renewables issued 17,692,750 common shares and paid a total dividend equivalent of $1 million. Share issuance costs amounted to $8 million, net of $2 million income tax recovery. On Jan. 6, 2016, TransAlta Renewables declared a dividend increase of 5 per cent.

On Nov. 30, 2016, TransAlta Renewables acquired direct ownership of the Canadian Assets from the Corporation for a purchase price of $520 million by issuing a promissory note. At the same time, the Corporation’s subsidiary redeemed the preferred shares that it had issued to TransAlta Renewables in January 2016 when TransAlta Renewables acquired an economic interest in the Canadian Assets as described above for $520 million. The two transactions were subject to a set-off arrangement and resulted in no cash payments. TransAlta Renewables also acquired working capital and certain capital spares totalling $19 million through the issuance of a non-interest bearing loan payable to the Corporation.

Wintering Hills Sale

On Jan. 26, 2017, we announced the sale of our 51 per cent interest in the Wintering Hills merchant wind facility for approximately $61 million. Proceeds from the sale will be used for general corporate purposes, including reducing our debt and funding future renewables growth. The sale closed March 1, 2017. We acquired the interest in Wintering Hills in 2015 in connection with the restructuring of the arrangements associated with our Poplar Creek cogeneration facility. As at Dec. 31, 2016, the assets are classified as held for sale, and were measured at the lower of carrying amount and fair value less costs to sell, resulting in an impairment charge of $28 million, included in the Wind and Solar segment. This arrangement provides us with near-term liquidity and increases our financial flexibility to pay down debt maturities.

Preferred Share Exchange

On Feb. 10, 2017, we announced that we would not proceed with the transaction previously announced Dec. 19, 2016 pursuant to which all currently outstanding first preferred shares in the capital of the Corporation would be exchanged for shares in a single new series of cumulative redeemable minimum rate reset first preferred shares.

M54 TRANSALTA CORPORATION

Financial Position

The following chart highlights significant changes in the Consolidated Statements of Financial Position from Dec. 31, 2016, to Dec. 31, 2015:

|  | Increase/ |  |
Assets |  | (decrease | ) | Primary factors explaining change
Cash and cash equivalents |  | 251 |  | Timing of receipts and payments, and non-recourse bond offerings
Trade and other receivables |  | 136 |  | Timing of customer receipts and seasonality of revenue, and current Mississauga facility recontracting receivable ($91 million)
Assets held for sale |  | 61 |  | Transfer of Wintering Hills wind facility from PP&E
Finance lease receivables (long term) |  | (56 | ) | Unfavourable changes in foreign exchange rates ($12 million) and scheduled receipts ($56 million), partially offset by an increase due to completion of gas conversion work at the Solomon gas plant ($14 million)
Property, plant, and equipment, net |  | (349 | ) | Depreciation for the period ($607 million), unfavourable changes in foreign exchange rates ($46 million), retirement of assets ($21 million), partially offset by additions ($358 million), revisions to decommissioning and restoration costs ($71 million), and transfer of Wintering Hills to assets held for sale ($61 million)
Intangible assets |  | (14 | ) | Amortization ($38 million), partially offset by additions ($24 million)
Deferred income tax assets |  | (18 | ) | Decreases in deductible temporary differences
Risk management assets (current and long term) |  | (61 | ) | Unfavourable changes in foreign exchange rates and contract settlements, partially offset by favourable market price movements
Other assets |  | 109 |  | Mississauga facility recontracting long term receivable ($116 million)
Other |  | (10 | ) |
Total decrease in assets |  | 49 |  |
|  | Increase/ |  |
Liabilities and equity |  | (decrease | ) | Primary factors explaining change
Accounts payable and accrued liabilities |  | 79 |  | Timing of payments and accruals
Credit facilities, long term debt, and finance lease obligations (including current portion) |  | (134 | ) | Credit facility repayment ($315 million), repayment of long term debt ($88 million), and favourable effects of changes in foreign exchange rates ($67 million), partially offset by bond issuances ($362 million)
Decommissioning and other provisions (current and long term) |  | (55 | ) | Keephills 1 provision reversal ($94 million) and liabilities settled ($59 million), partially offset by a decrease in risk-adjusted discount rates ($44 million)
Defined benefit obligation and other long term liabilities |  | (18 | ) | Amortization of deferred revenue ($7 million) and actuarial gains ($8 million)
Deferred income tax liabilities |  | 65 |  | Mississauga recontracting and increase in taxable temporary differences
Risk management liabilities (current and long term) |  | (155 | ) | Favourable market price movements and contract settlements
Equity attributable to shareholders |  | 150 |  | Net earnings ($169 million), issuance of common shares ($19 million), gains on cash flow hedges ($106 million), and changes in non-controlling interests in TransAlta Renewables ($26 million), partially offset by net losses on translating net assets of foreign operations ($53 million) and common and preferred share dividends ($110 million)
Non-controlling interests |  | 123 |  | Sale of economic interests to TransAlta Renewables, partially offset by distributions paid and payable to non-controlling interests
Other |  | (6 | ) |
Total decrease in liabilities and equity |  | 49 |  |

TRANSALTA CORPORATION M55

Cash Flows

The following chart highlights significant changes in the Consolidated Statements of Cash Flows for the year ended Dec. 31, 2016, compared to the years ended Dec. 31, 2015 and Dec. 31, 2014:

Year ended Dec. 31 |  | 2016 |  | 2015 |  | Primary factors explaining change
Cash and cash equivalents, beginning of year |  | 54 |  | 43 |  |
Provided by (used in): |  |  |  |  |  |
Operating activities |  | 744 |  | 432 |  | Favourable change in non-cash working capital of $315 million
Investing activities |  | (327) |  | (573) |  | Lower additions to property, plant, and equipment ($118 million), a higher decrease in finance lease receivables ($33 million), and a decrease in our renewable asset acquisitions ($101 million)
Financing activities |  | (163) |  | 149 |  | Increase in repayments of borrowings under credit facilities ($533 million), lower issuance of long-term debt ($126 million), lower proceeds on the sale of non-controlling interest in a subsidiary ($242 million), higher distributions paid to subsidiaries’ non-controlling interests ($52 million), and lower realized gains on financial instruments ($89 million), partially offset by lower dividends paid to common shareholders ($55 million) and lower repayment of long-term debt ($670 million).
Translation of foreign currency cash |  | (3) |  | 3 |  |
Cash and cash equivalents, end of year |  | 305 |  | 54 |  |
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 |  |

M56 TRANSALTA CORPORATION

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, 2016, we provided letters of credit totalling $566 million (2015 - $575 million) and cash collateral of $77 million (2015 - $74 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:

|  | 2017 |  | 2018 |  | 2019 |  | 2020 |  | 2021 |  | 2022 and thereafter |  | Total |
Natural gas, transportation, and other purchase contracts |  | 40 |  | 13 |  | 6 |  | 5 |  | 5 |  | 100 |  | 169 |
Transmission |  | 9 |  | 11 |  | 8 |  | 8 |  | 4 |  | 3 |  | 43 |
Coal supply and mining agreements(1) |  | 163 |  | 48 |  | 49 |  | 51 |  | 52 |  | 472 |  | 835 |
Long-term service agreements |  | 79 |  | 29 |  | 24 |  | 41 |  | 30 |  | 51 |  | 254 |
Non-cancellable operating leases(2) |  | 7 |  | 7 |  | 7 |  | 7 |  | 7 |  | 68 |  | 103 |
Long-term debt(3) |  | 623 |  | 959 |  | 461 |  | 460 |  | 63 |  | 1,745 |  | 4,311 |
Principal payments on finance lease obligations |  | 16 |  | 14 |  | 10 |  | 8 |  | 6 |  | 19 |  | 73 |
Interest on long-term debt and finance lease obligations(4) |  | 219 |  | 174 |  | 143 |  | 117 |  | 91 |  | 764 |  | 1,508 |
Growth |  | 181 |  | 5 |  | 1 |  | - |  | - |  | - |  | 187 |
TransAlta Energy Bill |  | 6 |  | 6 |  | 6 |  | 6 |  | 6 |  | 12 |  | 42 |
Total |  | 1,343 |  | 1,266 |  | 715 |  | 703 |  | 264 |  | 3,234 |  | 7,525 |

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.

I. Line Loss Rule Proceeding

TransAlta is participating in a line loss rule proceeding (the “LLRP”) which is currently before the AUC. The AUC determined that it had the ability to retroactively adjust line loss rates beginning in 2006 and has directed the Alberta Electric System Operator (the “AESO”), among other actions, to perform such calculations. The various decisions by the AUC are subject to appeal and challenge. TransAlta may incur additional transmission charges as a result of the LLRP. The outcome of the LLRP remains uncertain and the potential exposure, if any, cannot be calculated with any degree of certainty until the retroactive calculations are made available. The AESO expects retroactive calculations to be available mid-2017, at the earliest. As a result, no provision has been recorded. Certain PPAs for TransAlta’s Alberta facilities provide for the pass through of these types of transmission charges to TransAlta’s buyers.

(1) Commitments related to Sheerness and Genesee 3 may be impacted by the cessation of coal-fired emissions on or before Dec. 31, 2030.

(2) Includes amounts under certain evergreen contracts on the assumption of the Corporation’s continued operations.

(3) Excludes impact of derivatives.

(4) Interest on long-term debt is based on debt currently in place with no assumption as to refinancing on maturity.

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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.

M58 TRANSALTA CORPORATION

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 have historically been 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. In late 2016 we modified our net investment hedging practices and are no longer using foreign currency forward contracts in our hedges. Our net investment hedges using U.S.-denominated debt remain effective and in place. 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 also 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, 2016, Level III instruments had a net asset carrying value of $758 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, 2015, with the exception of the changes to our net investment hedge strategy, as discussed above and in the Governance and Risk Management section of this MD&A.

TRANSALTA CORPORATION M59

2017 Financial Outlook

For 2017, we expect our results to be slightly better than 2016 given the positive contribution from South Hedland, which is expected to be operational by mid-2017, and the receipt of the first coal transition payment from the Government of Alberta. The outlook also accounts for expected continuing weak power prices in Alberta, the Pacific Northwest, and the impact of lower priced power hedges in 2017. Approximately 85 per cent of our capacity in Alberta is contracted, either through power PPAs or financial contracts at an average price of $45 MWh to $50 MWh. Our performance next year will also be impacted by an increase in our fuel costs caused by a planned major outage to one of the large draglines at the Highvale Mine.

The following table outlines our expectation on key financial targets for 2017:

Measure |  | Target
Comparable EBITDA |  | $1,025 million to $1,135 million
Comparable FFO |  | $765 million to $855 million
Comparable FCF |  | $300 million to $365 million
Dividend |  | $0.16 per share annualized, 13 to 15 per cent payout of Comparable FCF

Operations

Availability

Availability of our coal fleet is expected to be in the range of 86 to 88 per cent in 2017. Availability of our other generating assets (gas, renewables) generally exceeds 95 per cent.

Fuel Costs

The cost to mine coal in Alberta is expected to increase due to a major outage of a dragline. Seasonal variations in coal costs at our Alberta mine are minimized through the application of standard costing. Coal costs for 2017, on a standard cost per tonne basis, are expected to be approximately 12 per cent higher than 2016 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 has been purchased primarily from external suppliers in the Powder River Basin and delivered by rail. The delivered fuel cost will increase slightly in 2017 primarily due to higher transportation costs.

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.

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. Our 2017 objective for Energy Marketing is for the segment to contribute between $70 million to $90 million in gross margin for the year.

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 largely offset our net foreign-denominated revenues.

M60 TRANSALTA CORPORATION

Net Interest Expense

Net interest expense for 2017 is expected to be higher than in 2016 largely due to lower capitalized interest. 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.

Net Debt, Liquidity, and Capital Resources

We expect to maintain adequate available liquidity under our committed credit facilities. We currently have access to $1.7 billion in liquidity including more than $300 million in cash. Our continued focus will be toward repositioning our capital structure and we expect to be well positioned to address the upcoming debt maturities in 2017 and 2018.

Capital Expenditures

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

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

|  | Total Project |  | 2017 |  | Target |  |
|  | Estimated spend |  | Spent to date(1) |  | Estimated spend |  | completion date |  | Details
Project |  |  |  |  |  |  |  |  |  |
South Hedland power project(2) |  | 576 |  | 336 |  | 230 - 250 |  | Q2 2017 |  | 150 MW combined-cycle power plant
Solomon load bank facility |  | 5 |  | 2 |  | 3 |  | Q1 2017 |  | Installation of 20MW load bank facility required to support the operation of the Solomon power station
Transmission |  | Not applicable(3) |  | 3 |  | Ongoing |  | Regulated transmission that receives a return on investment
Total |  | 581 |  | 338 |  | 256 - 276 |  |  |  |

Cash required to fund the construction of the South Hedland power project is expected to be partially funded by proceeds from project financing and cash generated by our business.

(1) Represents amounts spent as of Dec. 31, 2016.

(2) Estimated project expenditures are AUD$553 million. Total estimated project expenditures are stated in CAD$ and includes estimated capital interest costs. The total estimated project expenditures may change due to fluctuations in foreign exchange rates.

(3) Transmission projects are aggregated and develop on an ongoing basis. Consequently, discrete project expenditures are not available.

TRANSALTA CORPORATION M61

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 2015 | Spent in 2016 | Expected spend in 2017
Routine capital(1) | Capital required to maintain our existing generating capacity | 101 | 83 | 85 - 90
Planned major maintenance | Regularly scheduled major maintenance | 162 | 148 | 125 - 130
Mine capital | Capital related to mining equipment and land purchases | 25 | 23 | 30 - 35
Finance leases | Payments on finance leases | 13 | 16 | 20 - 25
Total sustaining capital excluding flood-recovery capital | 301 | 270 | 260 - 280
Flood-recovery capital | Capital arising from the 2013 Alberta flood | 4 | 2 | -
Total sustaining capital |  | 305 | 272 | 260 - 280
Productivity capital | Projects to improve power production efficiency and corporate improvement initiatives | 6 | 8 | 10 - 15
Total sustaining and productivity capital | 311 | 280 | 270 - 295

Significant planned major outages for 2017 include the following:

§ four major outages in which two relate to our partners, and a major outage to draglines at our Canadian Coal segment,

§ three major outages in our Canadian Gas segment related to our Sarnia and Windsor facilities,

§ one major outage in our Alberta Hydro segment and distributed planned maintenance expenditures across the entire fleet, and

§ distributed expenditures across our wind fleet, focusing on planned component replacements.

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 2017:

| Coal | Gas and Renewables | Total
GWh lost | 895 - 905 | 200 - 230 | 1,095 - 1,135

Funding of Capital Expenditures

Funding for these planned capital expenditures is expected to be provided by cash flow from operating activities, existing liquidity, and capital raised from our contracted cash flows. We have access to approximately $1.7 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.

(1) Includes hydro life extension expenditures.

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Sustainable Development Targets

Our 2017 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:

|  | Human and Intellectual |  | Annual Performance Status
1. Reduce safety incidents |  | Achieve an Injury Frequency Rate below 0.50 |  | 33 per cent improvement over 2016 target of 0.75
2. Manage employee turnover |  | Maintain voluntary turnover percentage under eight per cent |  | Consistent with 2016 target, we seek to maintain voluntary turnover under 8 per cent as this is considered a healthy amount of turnover
3. Support employee development |  | Continue development plans for all high-potential employees at the top three levels of the organization |  | Consistent with 2016 target, ongoing leadership development process
|  | Natural |  | Annual Performance Status
4. Minimize fleet-wide environmental incidents |  | Keep recorded incidents (including spills and air infractions) below 11 |  | 15 per cent improvement over 2016 target (13)
5. Increase mine reclaimed acreage |  | Replace annual topsoil at Highvale mine at a rate of 74 acres/year |  | Consistent with 2016 target (74 acres)
6. Utilize coal by-product |  | Sell a minimum of two million tonnes of coal byproduct materials during the period 2015 to 2017 |  | 70 per cent achieved (on a target to meet 2 million tonnes in 2017)
7. Reduce air emissions |  | 95 per cent reduction from 2005 levels of TransAlta coal facility NOx and SO 2 emissions by 2030 |  | Consistent with 2016 (long-term target)
8. Reduce GHG emissions |  | Our goal, in line with a commitment to the UN Sustainable Development Goals (SDGs), is to reduce our total GHG emissions in 2021 to 30 per cent below 2015 levels |  | Revised baseline to align with COP21 commitments and target aligned with UN Sustainable Development Goals
|  | Our goal, in line with a commitment to the UN SDGs and prevention of two degrees Celsius of global warming, is to reduce our total greenhouse gas emissions in 2030 to 60 per cent below 2015 levels |  | Revised baseline to align with COP21 commitments; target aligned with Science Based Targets Initiative and prevention of two degrees Celsius of global warming; and target aligned with UN SDGs
|  | Social and Relationship |  | Annual Performance Status
9. Support youth education with community investment |  | Approximately $0.75 million of community investment spending will be directed to supporting youth education |  | Revision from 2015, which was 50% of total community investment spending directed to youth education
10. Increase internal best practice Aboriginal engagement awareness |  | Develop an engagement and consultation best practices document for project planning and development as a guide for employees to work with indigenous communities and stakeholders |  | New target
|  | Comprehensive |  | Annual Performance Status
10. Transition from coal to gas-fired and renewable generation |  | Continue negotiations with the Government of Alberta, using a principles-based approach, to ensure we have regulation certainty and the capacity needed to invest in clean power |  | New target

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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 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 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 that 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 CEO, Chief Financial Officer, Chief Legal and Compliance Officer and Corporate Secretary, 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.

The Commodity Risk & Compliance Committee is chaired by our Chief Financial Officer and is comprised of the Chief Financial Officer, Chief Legal and Compliance Officer and Senior Vice President, Energy Marketing. It oversees the risk and compliance program in trading and ensures that this program is adequately resourced to monitor trading operations from a risk and compliance perspective. It also ensures the existence of appropriate controls, processes, systems and procedures to monitor adherence to policy.

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

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Practices. As a “foreign private issuer” under U.S. securities laws, we are generally permitted to comply with Canadian corporate governance requirements. Additional information regarding our governance practices can be found in our management proxy circular.

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 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 Commodity Risk & Compliance Committee. Reporting to this committee includes analysis of new risks, monitoring of status to risk limits, review of events that can affect these risks, and discussion and review of the 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, 2016, associated with our proprietary commodity risk management activities was $2 million (2015 - $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 2016. 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 is 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 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 sensitivity of volumes to our net earnings is shown below:

Factor | Increase or decrease (%) | Approximate impact on net earnings
Availability/production | 1 | 10

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 preventive 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 replacing 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 2016, we had approximately 88 per cent (2015 - 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 fulfil 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 2016, 79 per cent (2015 - 66 per cent) of our cost of gas used in generating electricity was contractually fixed or passed through to our customers and 100 per cent (2015 - 100 per cent) of our purchased coal costs were contractually fixed.

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

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 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 supplier’s mine, the availability of trains to deliver coal, and the financial viability of our coal suppliers could affect our ability to generate electricity.

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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,

§ 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 (including as set forth in the Alberta Climate Leadership Plan) 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 reducing the operating life of generating facilities, 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 surpass emission standards for GHGs, mercury, SO 2, 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, 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 GEC.

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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 fulfil 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.

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 fulfil 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, 2015. We had no material counterparty losses in 2016. 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, 2016:

|  | Investment grade (Per cent) |  | Non-investment grade (Per cent) |  | Total (Per cent) |  | Total amount
Trade and other receivables(1) |  | 92 |  | 8 |  | 100 |  | 703
Long-term finance lease receivables(2) |  | 36 |  | 64 |  | 100 |  | 719
Risk management assets(1) |  | 100 |  | - |  | 100 |  | 1,034
Total |  |  |  |  |  |  |  | 2,456

The maximum credit exposure to any one customer for commodity trading operations, including the fair value of open trading positions net of any collateral held, is $14 million (2015 - $44 million).

(1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts.

(2) We have one non-investment grade customer whose outstanding balance accounted for $445 million (Dec. 31, 2015 - $446 million). 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 Corporation’s assessment takes into consideration the counterparty’s financial position, external rating assessments, how the Corporation provides its services in an area of the counterparty’s lower-cost operations, and the Corporation’s other credit risk management practices.

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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 U.S. 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 allow for both designated hedges and economic hedges and include:

§ hedging our net investments in U.S. operations using U.S.-denominated debt,

§ entering into forward foreign exchange contracts to hedge future foreign denominated expenditures including our U.S.-denominated debt that is outside the net investment portfolio, and

§ hedging our expected foreign operating cash flows. Our target is to hedge a minimum of 60 per cent of our forecasted foreign operating cash flows over a four-year period, with a minimum of 90 per cent in the current year, 70 per cent in the next year, 50 per cent in the third year, and 30 per cent in the fourth year. The U.S. exposure will be managed with a combination of interest expense on our U.S.-denominated debt and forward foreign exchange contracts; the Australian exposure will be managed with forward foreign exchange contracts.

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 |  | 12

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 achieving stable investment grade credit ratings with rating agencies. Credit ratings issued for TransAlta, as well as the corresponding rating agency outlooks, 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 the adverse possible impacts identified above.

As at Dec. 31, 2016, we have liquidity of $1.7 billion comprised of amounts not drawn under our committed credit facilities and cash on hand, and foresee no current need to draw down on this liquidity in 2017.

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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 Commodity Risk & Compliance Committee, 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 and 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, 2016, approximately six per cent (2015 - nine 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 |  | -

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 methodologies 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.

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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.

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 2016, 53 per cent (2015 - 54 per cent) of our labour force was covered by 11 (2015 - 11) collective bargaining agreements. In 2016, five (2015 - two) agreements were renegotiated. We anticipate the successful negotiation of five collective agreements in 2017.

Regulatory and Political Risk

Regulatory and political risk is 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 regulation and 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, among other things, uncertainties associated with the development of capacity markets for electricity in the provinces of Alberta and Ontario, uncertainties associated with the development of carbon pricing policies, the qualification of our renewable facilities in Alberta to the generation of tradable GHG allowances as part of the transition from the Specified Gas Emitters Regulation to new regulation to be formulated to give effect to the Alberta 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, electricity 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.

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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.

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.

Cyber Security Risk

We rely on our information technology to process, transmit and store electronic information, including information we use to safely operate our assets. Cyber-attacks or other breaches of network or information technology systems security may cause disruptions to our operations. Cyber attackers may use a range of techniques, from manipulating people to using sophisticated malicious software and hardware on a single or distributed basis. Some cyber attackers use a combination of techniques in their attempt to evade safeguards such as firewalls, intrusion prevention systems, and antivirus software found in our systems and networks. A successful attack on our systems, networks, and infrastructure may allow for the unauthorized interception, destruction, use, or dissemination of our information and may cause disruptions to our operations.

We take measures to secure our infrastructure against potential cyber-attacks that may damage our infrastructure, systems and data. Our cyber security program aligns with industry best practices to ensure that a holistic approach to security is maintained. We have implemented security controls to help secure our data and business operations, including access control measures, intrusion detection and prevention systems, logging and monitoring of network activities, and implementing policies and procedures to ensure the secure operations of the business.

While we have systems, policies, hardware, practices, data backups, and procedures designed to prevent or limit the effect of the security breaches of our generation facility and infrastructure, there can be no assurance that these measures will be sufficient and that such security breaches will not occur or, if they do occur, that they will be adequately addressed in a timely manner. We closely monitor both preventive and detective measures to manage these risks.

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.

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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 |  | 3

Legal Contingencies

We are occasionally named as a party in various claims and legal regulatory 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 or proceedings 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.

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.

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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.

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.

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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.

We have a Commodity Exposure Management 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. This 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, 2016, is an estimated total upside of $93 million (2015 - $156 million upside) and total downside of $89 million (2015 - $211 million) impact to the carrying value of the financial instruments. Fair values are stressed for volumes and prices. The amount of $75 million upside (2015 - $125 million upside) and $69 million downside (2015 - $186 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$24 to US$40 for the period from 2019 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.

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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.

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 reallocation 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 regard to opportunities from combined talent and technology, functional organization, and future growth potential, and we consider our own performance measurement processes in making this determination.

As a result of our review in 2016 and other specific events, various analyses were completed 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.

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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 2016, total depreciation and amortization expense was $664 million (2015 - $605 million), of which $63 million (2014 - $59 million) relates to mining equipment and is included in fuel and purchased power.

As a result of the Alberta OCA, we will cease coal-fired emissions by the end of 2030. The useful lives of the PP&E and amortizable intangibles associated with the coal assets were reduced to 2030. We also entered a Non-Utility Generator Enhanced Dispatch Contract for the Mississauga plant in December 2016. As a result, the useful life of the plant was shortened to the end of 2016.

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.

For purposes of the 2016 and 2015 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.

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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.

Deferred income tax assets of $53 million (2015 - $71 million) have been recorded on the Consolidated Statements of Financial Position as at Dec. 31, 2016. 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 $712 million (2015 - $647 million) have been recorded on the Consolidated Statements of Financial Position as at Dec. 31, 2016. 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.

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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, 2016, the decommissioning and restoration provisions recorded on the Consolidated Statements of Financial Position were $293 million (2015 - $233 million). We estimate the undiscounted amount of cash flow required to settle the decommissioning and restoration provisions is approximately $1.1 billion, which will be incurred between 2017 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 |  | 1

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.

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Accounting Changes

A. Current Accounting Changes

I. Operating and Reportable Segments

During the first quarter, we disaggregated presentation of the previous Gas reportable segment into its two operating segments: Canadian Gas and Australian Gas. Previously included legacy costs of the non-operating U.S. Gas function have been reallocated to U.S. Coal to align with management’s internal monitoring practices. Comparative segmented results for 2015 and 2014 have been restated to align with separate reporting of the two segments and the reallocation of the non-operating costs.

II. Change in Estimates – Useful Lives

As a result of the Alberta OCA described above, we will cease coal-fired emissions by the end of 2030. The useful lives of the PP&E and amortizable intangibles associated with the Alberta coal assets were reduced to 2030 at the end of 2016. The useful lives may be revised or extended in compliance with our accounting policies, dependent upon future operating decisions and events.

We entered into a Non-Utility Generator Contract for the Mississauga plant in December 2016. As a result, the useful life of the plant was shortened to the end of 2016.

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 us, include:

I. 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 April 2016, the IASB issued an amendment to IFRS 15 to clarify the identification of performance obligations, principal versus agent considerations, licences of intellectual property, and transition practical expedients. IFRS 15, including the amendment, is required to be adopted either retrospectively or using a modified retrospective approach for annual periods beginning on or after Jan. 1, 2018, with earlier adoption permitted. IFRS 15 will be applied by us on Jan. 1, 2018.

We have created an implementation plan and are currently in the process of reviewing our various revenue streams and underlying contracts with customers to determine the impact, that the adoption of IFRS 15 will have on our financial statements. Our implementation plan includes an assessment of the impacts on processes and controls which may be significant. Based on our initial scoping assessment, we have identified sources of revenue that are accounted for as leases or financial instruments that are excluded from the scope of IFRS 15. Thus, we are currently focusing efforts on evaluating the effect of IFRS 15 on revenue contracts such as our long-term electricity and thermal contracts, contracts for the sale of renewable attributes, merchant power revenue, and contracts for the sale of generation byproducts. Once we have developed the necessary accounting policies, estimates, judgments, and processes with respect to our revenue streams, the incremental compilation of historical data to make reasonable quantitative estimates of the effects of the new standard will commence. We have made progress on the implementation plan for IFRS 15 during 2016; however, it is not yet possible to make a reliable estimate of the impact of IFRS 15 on our financial statements and disclosures.

Our current estimate of the time and effort necessary to complete our implementation plan for IFRS 15 extends into mid to late 2017.

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II. 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. IFRS 9 is effective for annual periods beginning on or after Jan. 1, 2018 with early application permitted. IFRS 9 will be applied by us on Jan. 1, 2018.

Under the classification and measurement requirements, financial assets must be classified and measured at either amortized cost, 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.

We have created an implementation plan and are currently in the process of reviewing our various types of financial instruments to determine the potential impact. Our implementation plan includes an assessment of the impacts on processes and controls that may be significant. Based on our initial assessments, we anticipate financial statement impacts resulting from the implementation of the expected loss impairment model. The assessment of the financial statement impacts of implementing the classification and measure of financial assets and liabilities and hedge accounting model under IFRS 9 are ongoing. We made progress on the implementation plan for IFRS 9 during 2016; however, it is not yet possible to make a reliable estimate of the impact of IFRS 9 on our financial statements and disclosures.

Our current estimate of the time and effort necessary to complete our implementation plan for IFRS 9 extends into mid to late 2017.

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. The standard is required to be adopted either retrospectively or using a modified retrospective approach. IFRS 16 will be applied by us on Jan. 1, 2019.

We are in the process of completing our initial scoping assessment and expect to have an implementation plan in place by mid-2017. We anticipate most the effort under the implementation plan will occur in late 2017 through mid-2018. It is not yet possible to make reliable estimates of the potential impact of IFRS 16 on our financial statements and disclosures.

TRANSALTA CORPORATION M83

Fourth Quarter

Consolidated Financial Highlights

Three months ended Dec. 31 |  | 2016 |  | 2015 |
Revenues |  | 717 |  | 595 |
Comparable EBITDA(1) |  | 374 |  | 268 |
Net earnings (loss) attributable to common shareholders |  | 61 |  | (7) |
Comparable net earnings attributable to common shareholders(1) |  | 51 |  | 3 |
Comparable FFO(1) |  | 228 |  | 243 |
Cash flow from operating activities |  | 122 |  | 118 |
Comparable FCF(1) |  | 93 |  | 174 |
Net earnings (loss) per share attributable to common shareholders, basic and diluted |  | 0.21 |  | (0.02) |
Comparable net earnings per share(1) |  | 0.18 |  | 0.01 |
Comparable FFO per share(1) |  | 0.79 |  | 0.86 |
Comparable FCF per share(1) |  | 0.32 |  | 0.61 |
Dividends declared per common share |  | 0.08 |  | 0.18 |

Financial Highlights

Comparable EBITDA for the fourth quarter of 2016 improved by $106 million compared to the same period in 2015, primarily as a result of the reversal of an $80 million provision relating to our Keephills 1 outage in 2013. Last year’s comparable EBITDA was impacted by an increase to our provision of $59 million relating to prior years’ Keephills 1 outage in 2013. Excluding the change to our provision, comparable EBITDA in the fourth quarter of 2016 was $33 million lower than the fourth quarter of 2015. Unrealized mark-to-market gains on our gas positions favourably affected our comparable EBITDA, but were offset by lower prices and lower availability in both our Canadian and U.S. Coal segments. Also impacting our results this quarter is lower margins from our Energy Marketing segment.

Comparable FFO decreased by $15 million to $228 million for the three months ended Dec. 31, 2016, compared to same period in 2015. The year-over-year non-cash change in our provisions totalled approximately $160 million and is excluded from comparable FFO. Comparable EBITDA also included $9 million of unrealized non-cash mark-to-market losses compared to a $6 million unrealized mark-to-market gain in 2015.

Fourth quarter comparable net earnings attributable to common shareholders was $51 million ($0.18 per share), up from the comparable net earnings of $3 million ($0.01 per share) in the same quarter last year. The Keephills 1 outage provision reversal as described above favourably impacted net earnings.

Reported net earnings attributable to common shareholders was $61 million ($0.21 per share) for the fourth quarter compared to a net loss of $7 million ($0.02 net loss per share) for the same period in 2015. The difference between comparable and reported net earnings includes the net gain on the Mississauga cogeneration facility recontracting, partially offsetting the Wintering Hills wind facility impairment charge during the quarter.

(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 on a Comparable Basis of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.

M84 TRANSALTA CORPORATION

Segmented Operational Results

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

Three months ended Dec. 31 |  | 2016 |  | 2015 |
Availability (%)(1) |  | 88.9 |  | 92.9 |
Adjusted availability (%)(2) |  | 88.9 |  | 88.4 |
Production (GWh)(1) |  | 10,624 |  | 11,107 |
Comparable EBITDA |  |  |  |  |
Canadian Coal |  | 178 |  | 67 |
U.S. Coal(3) |  | 14 |  | 22 |
Canadian Gas(3) |  | 70 |  | 57 |
Australian Gas(3) |  | 32 |  | 34 |
Wind and Solar |  | 66 |  | 65 |
Hydro |  | 20 |  | 19 |
Energy Marketing |  | 13 |  | 26 |
Corporate |  | (19 | ) | (22 | )
Total comparable EBITDA |  | 374 |  | 268 |

Availability and Production

Adjusted availability for the three months ended Dec. 31, 2016, was consistent with the same period in 2015. Lower production for the three months ended Dec. 31, 2016, compared to the same period in 2015 are primarily due to higher outages and derates, partially offset by paid curtailments at our Canadian Coal segment, and higher economic dispatching in Ontario as a result of lower prices at our Canadian Gas segment.

§ Canadian Coal: Comparable EBITDA totalled $178 million in the fourth quarter of 2016, including the reversal of the Keephills 1 outage provision of $80 million, partially offset by unrealized losses on hedging activities. The quarter-over-quarter change in our provisions was $139 million. Excluding the adjustment to our provision, comparable EBITDA was down $28 million compared to last year mainly due to lower realized prices and lower availability due to outages and derates.

§ U.S. Coal: Comparable EBITDA was down $8 million in the fourth quarter compared to the same period in 2015. The unfavourable impact of mark-to-market losses on certain forward financial contracts that do not qualify for hedge accounting was partially offset by coal inventory recoveries. In addition, lower revenue and pricing was offset by lower delivered coal costs.

§ Canadian Gas: Comparable EBITDA was $70 million in the fourth quarter of 2016, an increase of $13 million, compared to the same period in 2015, primarily due to favourable unrealized mark-to-market gains on our gas positon.

§ Australian Gas: Comparable EBITDA was down by $2 million during the fourth quarter of 2016, compared to the same period in 2015. The addition of capacity payments for the gas conversion project at our Solomon gas plant was offset by increased repair and maintenance expenses and unfavourable Canadian dollar foreign exchange translation.

§ Wind and Solar: Comparable EBITDA was consistent in the fourth quarter with the same period in 2015.

§ Hydro: Comparable EBITDA was consistent in the fourth quarter with the same period in 2015.

§ Energy Marketing: Comparable EBITDA was down $13 million in the fourth quarter compared to the same period in 2015 due to lower margins and increased OM&A costs associated with share-based payment expenses.

§ Corporate: Lower costs in our Corporate Segment mainly due to realized benefits of cost efficiency initiatives which were offset by reduced allocations to our business segments.

(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.

(3) See the Accounting Changes section of this MD&A for information on changes in the presentation of the Gas reportable segment.

TRANSALTA CORPORATION M85

Reconciliation of Non-IFRS Measures

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.

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.

| 3 months ended Dec. 31 |
|  | 2016 |  | 2015 |
Cash flow from operating activities |  | 122 |  | 118 |
Change in non-cash operating working capital balances |  | 61 |  | 76 |
Cash flow from operations before changes in working capital |  | 183 |  | 194 |
Adjustments |  |  |  |  |
Decrease in finance lease receivable |  | 15 |  | 15 |
Restructuring costs |  | 3 |  | 11 |
MSA settlement payment |  | 25 |  | 31 |
Maintenance costs related to Alberta flood of 2013, net of insurance recoveries |  | - |  | (10) |
Other |  | 2 |  | 2 |
Comparable FFO |  | 228 |  | 243 |
Deduct: |  |  |  |  |
Sustaining capital |  | (85) |  | (52) |
Insurance recoveries of sustaining capital expenditures |  | - |  | 23 |
Dividends paid on preferred shares |  | (10) |  | (11) |
Distributions paid to subsidiaries’ non-controlling interests |  | (40) |  | (29) |
Comparable FCF |  | 93 |  | 174 |
Weighted average number of common shares outstanding in the period |  | 288 |  | 284 |
Comparable FFO per share |  | 0.79 |  | 0.86 |
Comparable FCF per share |  | 0.32 |  | 0.61 |

M86 TRANSALTA CORPORATION

The table below provides a reconciliation of our comparable EBITDA to our comparable FFO and comparable FCF:

| 3 months ended Dec. 31 |
|  | 2016 |  | 2015 |
Comparable EBITDA |  | 374 |  | 268 |
Provisions |  | (79) |  | 76 |
Interest expense |  | (47) |  | (63) |
Unrealized (gains) losses from risk management activities |  | 9 |  | (6) |
Current income tax expense |  | (6) |  | (7) |
Decommissioning and restoration costs settled |  | (8) |  | (4) |
Realized foreign exchange gain (loss) |  | (1) |  | 1 |
Non-cash gain on curtailment and amendment gain on empoyee future benefits |  | - |  | (8) |
Capital insurance recoveries |  | - |  | (5) |
Other non-cash items |  | (14) |  | (9) |
Comparable FFO |  | 228 |  | 243 |
Deduct: |  |  |  |  |
Sustaining capital |  | (85) |  | (52) |
Insurance recoveries of sustaining capital expenditures |  | - |  | 23 |
Dividends paid on preferred shares |  | (10) |  | (11) |
Distributions paid to subsidiaries’ non-controlling interests |  | (40) |  | (29) |
Comparable FCF |  | 93 |  | 174 |
Weighted average number of common shares outstanding in the period |  | 288 |  | 284 |
Comparable FFO per share |  | 0.79 |  | 0.86 |
Comparable FCF per share |  | 0.32 |  | 0.61 |

TRANSALTA CORPORATION M87

Reconciliation of Comparable EBITDA and Comparable Net Earnings

A reconciliation of reported results to comparable results for the three months ended Dec. 31, 2016 and 2015 is as follows:

|  | 3 months ended Dec. 31, 2016 |  | 3 months ended Dec. 31, 2015
|  | Reported |  | Comparable reclassifications |  | Comparable adjustments |  | Comparable total |  | Reported |  | Comparable reclassifications |  | Comparable adjustments |  | Comparable total
Revenues |  | 717 |  | 32 | (1, 2) | 2 | (4) | 751 |  | 595 |  | 32 | (1, 2) | 13 | (4) | 640
Fuel and purchased power |  | 280 |  | (19) | (3) | (14) | (8) | 247 |  | 272 |  | (16) | (3) | - |  | 256
Gross margin |  | 437 |  | 51 |  | 16 |  | 504 |  | 323 |  | 48 |  | 13 |  | 384
Operations, maintenance, and administration |  | 125 |  | - |  | - |  | 125 |  | 109 |  | - |  | 10 | (5) | 119
Asset impairment reversals |  | 28 |  | - |  | (28) |  | - |  | (1) |  | - |  | 1 | (7) | -
Restructuring provision |  | - |  | - |  | - | (7) | - |  | 4 |  | - |  | (4) | (9) | -
Taxes, other than income taxes |  | 7 |  | - |  | - |  | 7 |  | 8 |  | - |  | - |  | 8
Net other operating (income) losses |  | (193) |  | - |  | 191 | (8) | (2) |  | (29) |  | - |  | 18 | (6) | (11)
EBITDA |  | 470 |  | 51 |  | (147) |  | 374 |  | 232 |  | 48 |  | (12) |  | 268
Depreciation and amortization |  | 187 |  | 34 | (2, 3) | (46) | (8) | 175 |  | 136 |  | 31 | (2, 3) | - |  | 167
Operating income |  | 283 |  | 17 |  | (101) |  | 199 |  | 96 |  | 17 |  | (12) |  | 101
Finance lease income |  | 17 |  | (17) | (1) | - |  | - |  | 17 |  | (17) | (1) | - |  | -
Foreign exchange gain (loss) |  | (3) |  | - |  | (3) | (11) | (6) |  | 3 |  | - |  | 8 | (11) | 11
Gain on sale of assets |  | 3 |  | - |  | (4) | (10) | (1) |  | (1) |  | - |  | 1 | (10) | -
Earnings before interest and taxes |  | 300 |  | - |  | (108) |  | 192 |  | 115 |  | - |  | (3) |  | 112
Net interest expense |  | 47 |  | - |  | - |  | 47 |  | 69 |  | - |  | - |  | 69
Income tax expense (recovery) |  | 82 |  | - |  | (40) | (12, 13) | 42 |  | (4) |  | - |  | (6) | (13) | (10)
Net earnings (loss) |  | 171 |  | - |  | (68) |  | 103 |  | 50 |  | - |  | 3 |  | 53
Non-controlling interests |  | 90 |  | - |  | (58) | (14) | 32 |  | 46 |  | - |  | (7) | (14) | 39
Net earnings (loss) attributable to TransAlta shareholders |  | 81 |  | - |  | (10) |  | 71 |  | 4 |  | - |  | 10 |  | 14
Preferred share dividends |  | 20 |  | - |  | - |  | 20 |  | 11 |  | - |  | - |  | 11
Net earnings (loss) attributable to common shareholders |  | 61 |  | - |  | (10) |  | 51 |  | (7) |  | - |  | 10 |  | 3
Weighted average number of common shares outstanding in the period |  | 288 |  |  |  |  |  | 288 |  | 284 |  |  |  |  |  | 284
Net earnings (loss) per share attributable to common shareholders |  | 0.21 |  |  |  |  |  | 0.18 |  | (0.02) |  |  |  |  |  | 0.01

M88 TRANSALTA CORPORATION

Earnings on a Comparable Basis

The adjustments made to calculate comparable earnings for the three months ended Dec. 31, 2016 and 2015 are as follows. References are to the previous reconciliation table.

|  |  |  |  |  |  |  | 3 months ended Dec. 31
|  |  |  |  |  |  |  | 2016 |  | 2015
Reference number |  | Adjustment |  | Segment |  | Financial statement line item |  |  |  |
Reclassifications: |  |  |  |  |  |  |  |
1 |  | Finance lease income used as a proxy for operating revenue |  | Australian Gas |  | Revenues |  | 13 |  | 13
|  |  |  | Canadian Gas |  | Revenues |  | 4 |  | 4
2 |  | Decrease in finance lease receivable used as a proxy for operating revenue and depreciation |  | Canadian Gas |  | Revenues |  | 14 |  | 15
|  |  |  | Australian Gas |  | Revenues |  | 1 |  | -
3 |  | Reclassification of mine depreciation from fuel and purchased power |  | Canadian Coal |  | Fuel and purchased power |  | 19 |  | 16
Adjustments (increasing (decreasing) earnings to arrive at comparable results): |  |  |  |  |  |
4 |  | Impacts to revenue associated with certain de-designated and economic hedges |  | U.S. Coal |  | Revenues |  | 2 |  | 13
5 |  | Maintenance costs related to the Alberta flood of 2013, net of insurance recoveries |  | Hydro |  | OM&A |  | - |  | (10)
6 |  | Non-comparable portion of insurance recovery received |  | Hydro |  | Net other operating (income) losses |  | - |  | (18)
7 |  | Asset impairment reversals |  | U.S. Coal |  | Asset impairment (reversals) |  | - |  | (1)
|  |  |  | Wind and Solar |  | Asset impairment (reversals) |  | 28 |  | -
8 |  | Mississauga recontracting(1) |  | Canadian Gas |  | Net other operating (income) losses |  | (131 | ) | -
9 |  | Restructuring expense |  | Canadian Coal |  | Restructuring provision |  | - |  | 2
|  |  |  | Corporate |  | Restructuring provision |  | - |  | 2
10 |  | Gain on Poplar Creek contract restructuring |  | Canadian Gas |  | Gain on sale of assets |  | - |  | 1
|  | Non-comparable gain on sale of assets |  | Corporate |  | Gain on sale of assets |  | (4 | ) | -
11 |  | Economic hedges of non-controlling interest in intercompany foreign exchange contracts |  | Unassigned |  | Foreign exchange loss |  | (3 | ) | 8
12 |  | Net tax effect on comparable adjustments subject to tax |  | Unassigned |  | Income tax expense (recovery) |  | 9 |  | -
13 |  | Reversal of a writedown of deferred income tax assets |  | Unassigned |  | Income tax expense (recovery) |  | 31 |  | 6
14 |  | Non-comparable items attributable to non-controlling interests |  | Unassigned |  | Non-controlling interests |  | 58 |  | 7

(1) Reported in net other operating (income) loss of ($191 million), depreciation and amortization of ($46 million) and fuel and purchased power of ($14 million).

TRANSALTA CORPORATION M89

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 2016 | Q2 2016 | Q3 2016 | Q4 2016
Revenues | 568 | 492 | 620 | 717
Comparable EBITDA | 279 | 248 | 244 | 374
Comparable FFO | 196 | 175 | 163 | 228
Net earnings (loss) attributable to common shareholders | 62 | 6 | (12) | 61
Comparable net earnings (loss) attributable to common shareholders | 14 | (20) | (11) | 51
Net earnings (loss) per share attributable to common shareholders, basic and diluted(1) | 0.22 | 0.02 | (0.04) | 0.21
Comparable net earnings (loss) per share, basic and diluted(1) | 0.05 | (0.07) | (0.04) | 0.18
| Q1 2015 | Q2 2015 | Q3 2015 | Q4 2015
Revenues | 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(1) | (0.14) | (0.47) | 0.55 | (0.02)
Comparable net earnings (loss) per share, basic and diluted(1) | 0.09 | (0.16) | (0.12) | 0.01

(1) 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.

M90 TRANSALTA CORPORATION

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.

Net earnings attributable to common shareholders has also been impacted by the following variations and events:

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

§ U.S. Solar and Wind acquisitions in the third quarter of 2015,

§ settlement with the Market Surveillance Administrator in the third quarter of 2015,

§ a recovery of a writedown of deferred tax assets in the fourth quarter of 2014, the third quarter of 2015, and the first and second quarters of 2016,

§ change in income tax rates in Alberta in the second quarter of 2015,

§ deferred income tax impacts of the sale of an economic interest in Australian Assets to TransAlta Renewables in the first and second quarters of 2015,

§ effects of non-comparable unrealized losses on intercompany financial instruments that are attributable only to the non-controlling interests in the first, second, and third quarters of 2016,

§ effects of the Mississauga facility recontracting during the fourth quarter of 2016, and

§ effects of the Wintering Hills impairment charge during the fourth quarter of 2016.

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.

During the first quarter of 2016, we completed the implementation of a new energy trading and risk management system. In connection with the implementation, we updated the processes that constitute our internal control over financial reporting, as necessary, to accommodate related changes to our business processes and accounting procedures.

Except as otherwise described above, there have been no other changes in our internal control over financial reporting during the year ended Dec. 31, 2016 that have materially affected, or are 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 at Dec. 31, 2016, the end of the period covered by this report, our disclosure controls and procedures were effective.

TRANSALTA CORPORATION M91