Exhibit 13.2

	TransAlta Corporation
	Second Quarter Report for 2017

Management’s Discussion and Analysis

This Management’s Discussion and Analysis (“MD&A”) contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. See the Forward-Looking Statements section of this MD&A for additional information.

This MD&A should be read in conjunction with the unaudited interim condensed consolidated financial statements of TransAlta Corporation as at and for the three and six months ended June 30, 2017 and 2016, and should also be read in conjunction with the audited annual consolidated financial statements and MD&A contained within our 2016 Annual Integrated Report. In this MD&A, unless the context otherwise requires, “we”, “our”, “us”, the “Corporation”, and “TransAlta” refers to TransAlta Corporation and its subsidiaries. Our condensed consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) International Accounting Standards (“IAS”) 34 Interim Financial Reporting for Canadian publically accountable enterprises as issued by the International Accounting Standards Board (“IASB”) and in effect at June 30, 2017. All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted. This MD&A is dated Aug. 9, 2017. Additional information respecting TransAlta, including its 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.

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 Condensed Consolidated Statements of Earnings (Loss) for the three and six months ended June 30, 2017, and 2016. 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. Earnings before interest, taxes, depreciation, and amortization (“EBITDA”), comparable EBITDA, Funds from Operations (“FFO”), and “Free Cash Flow” (“FCF”) are non-IFRS measures. See the Reconciliation of Non-IFRS Measures and, Discussion of Segmented Comparable Results sections of this MD&A for additional information.

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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 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, the Brazeau Pumped Storage Project, Kent Hills 3 Wind Project, and the conversion of our Sundance Units 3 to 6 and Keephills Units 1 and 2 from coal-fired generation to gas-fired generation, and their attendant costs and sources of funding; the retirement of Sundance Unit 1 and mothballing of Sundance Unit 2; the changes to capacity and emissions following the conversion to gas generation of Sundance Units 3 to 6 and Keephills Units 1 and 2; 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 section titled “2017 Outlook”; coal supply constraints for our facilities in Alberta and their impact on our mining costs and power generation at our Sundance coal-fired generating units 1 to 6 and Keephills units 1 to 3; 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; expectations related to future earnings and cash flow from operating and contracting activities (including estimates of full-year 2017 comparable EBITDA, FFO, FCF, and expected sustaining capital expenditures); expectations in respect of financial ratios and targets and the timing associated with meeting such targets (including FFO before interest to adjusted interest coverage, adjusted 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 anticipated debt reductions during 2017 and beyond; project Greenlight; expected governmental regulatory regimes, 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, the expected impact on us 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 Off-Coal Agreement (“OCA”) and Memorandum of Understanding with the Government of Alberta on our business and financial performance; the outcome of discussions with the Government of Canada and 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; 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 prices (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 on 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; our exposure to liquidity risk; expectations regarding the impact of the general slowdown in the oil and gas sector; expectations in respect of the global economic environment and growing scrutiny by investors relating to sustainability performance; our credit practices; expected cost savings following the implementation of our efficiency and productivity initiatives; the estimated contribution of Energy Marketing activities to gross margin; expectations relating to the performance of TransAlta Renewables Inc.’s (“TransAlta Renewables”) assets; expectations regarding our continued ownership of common shares of TransAlta Renewables; 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 FCF 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.

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Factors that may adversely impact our forward-looking statements include risks relating to: fluctuations in market prices, 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, sun, 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 and on reasonable terms; 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; outcomes of 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 and commissioning of the South Hedland power project; and the maintenance or adoption of enabling regulatory frameworks or the satisfactory receipt of applicable regulatory approvals for existing and proposed operations and growth initiatives, including as it pertains to coal-to-gas conversions.

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 for the fiscal year ended Dec. 31, 2016.

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.

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Highlights

Consolidated Financial Highlights

	3 months ended June 30					6 months ended June 30
	2017			2016		2017			2016
Revenues		503			492		1,081			1,060
Net earnings (loss) attributable to common shareholders		(18	)		6		(18	)		68
Cash flow from operating activities		63			119		344			394
Comparable EBITDA(1)		268			248		542			527
FFO(1)		187			175		389			372
FCF(1)		30			56		125			140
Net earnings (loss) per share attributable to common   shareholders, basic and diluted		(0.06	)		0.02		(0.06	)		0.24
FFO per share(1)		0.65			0.61		1.35			1.29
FCF per share(1)		0.10			0.19		0.43			0.49
Dividends declared per common share		0.04			0.04		0.04			0.08

As at	June 30, 2017		Dec. 31, 2016
Total assets		10,419		10,996
Net debt(2)		3,709		3,893
Total long-term liabilities		4,313		5,116

Comparable EBITDA was up $20 million for the three months ended June 30, 2017 compared to same period in 2016. During the second quarter, all segments, with the exception of Canadian Coal, delivered better or comparable results over last year. We benefited from favourable mark-to-market gains on economic hedges in US Coal, stronger wind resources in Eastern Canada, and higher levels of water flow at Alberta Hydro. At Canadian Coal, higher fuel costs caused by a higher expected strip ratio and lower planned equipment availability at our mine, and lower prices due to the rolling off of certain hedges, negatively impacted our results.

Comparable EBITDA was up $15 million for the six months ended June 30, 2017 compared to the same period in 2016, mostly due to the settlement of the contract indexation dispute with the Ontario Electricity Financial Corporation (“OEFC”) relating to the Ottawa and Windsor generating facilities, totalling $34 million, at Canadian Gas. At US Coal, favourable mark-to-market on economic hedges that do not qualify for hedge accounting and higher merchant and contracted revenues contributed to higher comparable EBITDA. Energy Marketing was impacted by unusual weather in the Northeast and the Pacific Northwest and delivered below expected performance in the first quarter of 2017. As expected, Canadian Coal was negatively impacted by the rolling off of higher priced hedges and higher mining costs. This was partially offset by the OCA payments.

FFO for the three and six months ended June 30, 2017 was up $12 million and $17 million, respectively, compared to the same periods in 2016, due mostly to higher comparable EBITDA. The timing of sustaining and productivity expenditures and higher distributions paid to subsidiaries’ non-controlling interests negatively impacted our FCF by $26 million and $15 million during the second quarter of 2017 and year-to-date, respectively, compared to the same periods in 2016.

(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 Reconciliation of Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.

(2) Net debt includes current portion, amounts due under credit facilities, long-term debt, tax equity, and finance lease obligations, net of cash and the fair value of economic hedging instruments on debt. See the table in the Capital Structure and Liquidity section of this MD&A for more details on the composition of net debt.

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Reported net loss attributable to common shareholders for the second quarter of 2017 was $18 million ($0.06 loss per share) compared to $6 million net earnings ($0.02 earnings per share) during the same period in 2016. An impairment charge of $20 million was recognized in the quarter as a result of our decision to early retire Sundance Unit 1 at the end of 2019. Year-to-date, reported net earnings was down $86 million ($0.30 loss per share). Last year, net earnings in the first quarter were positively impacted by lower depreciation due to the reduction of our reclamation obligation at our Centralia mine caused by a higher discount rate. This year, higher depreciation arose due to the shortening of useful lives of Keephills 3, Genesee 3, and to a lesser extent, Sundance Unit 1. Higher earnings attributable to non-controlling interests also negatively impacted net earnings.

Segmented Comparable EBITDA Results

	3 months ended June 30						6 months ended June 30
	2017			2016			2017			2016
Comparable EBITDA
Canadian Coal		85			93			176			196
U.S. Coal		34			18			44			14
Canadian Gas		57			56			145			121
Australian Gas		32			33			63			64
Wind and Solar		42			36			110			97
Hydro		28			25			42			43
Energy Marketing		12			6			8			29
Corporate		(22	)		(19	)		(46	)		(37	)
Total comparable EBITDA		268			248			542			527

Significant Events

During the first half of the year, we continued to work on strengthening our financial flexibility, improving our operating performance, and progressing our transition to clean power generation through the following initiatives:

§ On July 24, 2017, TransAlta Renewables entered into a syndicated credit agreement giving TransAlta Renewables access to $500 million in direct borrowings. The agreement is fully committed for four years, expiring in 2021. At the same time, our credit facilities were reduced by a similar amount and also expire in 2021. Our consolidated liquidity will remain unchanged. See the Significant and Subsequent Events section of this MD&A for further details.

§ Entered into a long-term contract for the Kent Hills 3 expansion project located in New Brunswick, which is expected to begin construction in the spring of 2018. The 17.25 MW expansion will be funded through a project financing of $240 million to $275 million at Kent Hills.

§ Closed the previously announced sale of our 51 per cent interest in the Wintering Hills merchant wind facility for approximately $61 million. The sale provided us with near-term liquidity, increased our financial flexibility, and reduced our merchant exposure in Alberta.

§ Achieved commercial operation on our South Hedland power project achieved on July 28, 2017. The project is expected to generate approximately $80 million of comparable EBITDA annually. See the Significant and Subsequent Events section of this MD&A for further details. On July 28, 2017, TransAlta Renewables announced the conversion of the Class B shares we own into common shares on Aug. 1, 2017, and also increased their monthly dividend by approximately 7 per cent.

§ Announced the acceleration of our transition to gas and renewables generation with the retirement of Sundance Unit 1, the mothballing of Sundance Unit 2, and the conversion of Sundance Units 3 to 6, and Keephills Units 1 and 2 from coal-fired generation to gas-fired generation between 2021 to 2023. The retirement of Sundance Unit 1 and mothballing of Sundance Unit 2 is not expected to have a material impact on our forecasted cash flow for 2018 and 2019. We received approval to extend the life of Sundance Unit 2 to the end of 2021 on coal. This unit will qualify for the capacity market auctions in the 2019 timeframe.

§ Settled the contract indexation dispute with the OEFC. The settlement consisted of a $34 million payment by the OEFC to TransAlta.

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Adjusted Availability and Production

Adjusted availability for the three and six months ended June 30, 2017 was 84.0 per cent and 86.2 per cent, respectively, compared to 86.5 per cent and 89.4 per cent for the same periods in 2016. The main causes of the decreases were higher planned outages at Canadian and US Coal, a planned maintenance outage at our Sarnia facility, and Windsor’s cycling conversion project. Lower availability had a minimal impact on our results due to current low prices in Alberta and the Pacific Northwest.

Production for the three and six months ended June 30, 2017 was 7,707 GWh and 16,758 GWh, respectively, compared to 7,899 GWh and 16,766 GWh for the same periods in 2016. The cessation of operations at our Mississauga cogeneration facility effective Jan. 1, 2017 and planned major maintenance at US Coal were the main drivers of the production decrease in the second quarter of 2017. This was partially offset by higher generation from Alberta Hydro and Eastern Wind and stronger customer demand in Australia. On a year-to-date basis, US Coal had higher production compared to 2016 as a result of later economic dispatching in the first quarter due to slightly higher prices in the first quarter of 2017. Higher water resources at Hydro also contributed to higher production in 2017. In accordance with the terms of Mississauga’s new contract with Ontario’s Independent Electricity System Operator (“IESO”), we continue to receive monthly capacity payments from the IESO until Dec. 31, 2018.

Electricity Prices

The average spot electricity prices for the three and six months ended June 30, 2017 increased compared to the same periods in 2016 in Alberta due to higher environmental levies as compliance costs have increased the marginal cost to producers, while excess water resources during the second quarter of 2017 in the Pacific Northwest caused prices to decline compared to the same period in 2016.

 

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Funds from Operations and Free Cash Flow

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. 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 FFO and FCF with changes that we consider temporary in nature, reflecting, among other things, the impact of seasonal factors and the timing of capital projects. FFO per share and 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 FFO and FCF.

	3 months ended June 30						6 months ended June 30
	2017			2016			2017			2016
Cash flow from operating activities		63			119			344			394
Change in non-cash operating working capital balances		109			40			14			(54	)
Cash flow from operations before changes in working capital		172			159			358			340
Adjustments:
Decrease in finance lease receivable		15			15			30			29
Other		-			1			1			3
FFO		187			175			389			372
Deduct:
Sustaining capital		(87	)		(66	)		(133	)		(125	)
Productivity capital		(7	)		(4	)		(9	)		(4	)
Dividends paid on preferred shares		(10	)		(10	)		(20	)		(22	)
Distributions paid to subsidiaries' non-controlling interests		(51	)		(37	)		(98	)		(76	)
Other		(2	)		(2	)		(4	)		(5	)
FCF		30			56			125			140
Weighted average number of common shares outstanding in the period		288			288			288			288
FFO per share		0.65			0.61			1.35			1.29
FCF per share		0.10			0.19			0.43			0.49

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Comparable EBITDA

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. In addition, we reclassify certain transactions to facilitate the discussion on the performance of our business: i) Certain assets we own in Canada and Australia are fully contracted and recorded as finance leases under IFRS. We believe it is more appropriate to reflect the payment we received under the contracts as a capacity payment in our revenues instead of as finance lease income and a decrease in finance lease receivables. We depreciate these assets over their expected lives. ii) We also reclassify the deprecation on our mining equipment from fuel and purchased power to reflect the actual cash cost of our business in our comparable EBITDA. iii) In December 2016, we agreed to terminate our existing arrangement with the IESO relating to our Mississauga cogeneration facility in Ontario and entered into a new Non-Utility Generator Contract (the “NUG Contract”) effective Jan. 1, 2017. Under the new NUG Contract, we receive fixed monthly payments until December 31, 2018 with no delivery obligations. Under IFRS, for our reported results in 2016, as a result of the NUG Contract, we recognized a receivable of $207 million (discounted), a pre-tax gain of approximately $191 million net of costs to mothball the units, and accelerated depreciation of $46 million. In 2017 and 2018, on a comparable basis, we record the payments we receive as revenues as a proxy for operating income, and continue to depreciate the facility until Dec. 31, 2018.

A reconciliation of reported operating income to EBITDA and comparable EBITDA results for the three and six months ended
June 30, 2017 and 2016, is set out below:

	3 months ended June 30				6 months ended June 30
	2017		2016		2017		2016
Operating income		24		41		86		148
Depreciation and amortization		154		147		297		269
EBITDA		178		188		383		417
Comparable reclassifications
Finance leases income		16		17		32		33
Decrease in finance lease receivables		15		15		30		29
Mine depreciation		19		15		36		30
Adjustments to earnings to arrive at comparable results:
Impacts to revenue associated with certain de-designated and economic hedges		2		13		2		18
Impacts associated with Mississauga recontracting(1)		18		-		39		-
Asset impairment charge		20		-		20
Comparable EBITDA		268		248		542		527

(1) Impacts associated with Mississauga recontracting for the six months ended June 30, 2017 are as follows: Revenue ($50 million), fuel and purchased power de-designated hedges ($8 million), and Operations, maintenance, and administration ($3 million).

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Discussion of Consolidated Financial Results

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.

Reconciliation of Non-IFRS Measures

	3 months ended June 30						6 months ended June 30
	2017			2016			2017			2016
Comparable EBITDA		268			248			542			527
Provisions		-			(8	)		-			(7	)
Interest expense		(56	)		(57	)		(113	)		(115	)
Unrealized (gains) losses from risk management activities		(16	)		9			(21	)		2
Current income tax recovery		(6	)		(6	)		(12	)		(11	)
Decommissioning and restoration costs settled		(3	)		(5	)		(7	)		(8	)
Realized foreign exchange gain (loss)		3			-			6			(1	)
Other		(3	)		(6	)		(6	)		(15	)
FFO		187			175			389			372
Deduct:
Sustaining capital		(87	)		(66	)		(133	)		(125	)
Productivity capital		(7	)		(4	)		(9	)		(4	)
Dividends paid on preferred shares		(10	)		(10	)		(20	)		(22	)
Distributions paid to subsidiaries' non-controlling interests		(51	)		(37	)		(98	)		(76	)
Other		(2	)		(2	)		(4	)		(5	)
FCF		30			56			125			140
Weighted average number of common shares outstanding in the period		288			288			288			288
FFO per share		0.65			0.61			1.35			1.29
FCF per share		0.10			0.19			0.43			0.49

FCF for the second quarter and year-to-date was down by $26 million and $15 million, respectively, compared to the same periods in 2016, mostly due to the timing of sustaining and productivity capital expenditures and higher distributions to our subsidiaries’ non-controlling interests as a result of the settlement of the indexation dispute for our long-term contracts at Ottawa and Windsor, which are held by TransAlta Cogeneration L.P (“TA Cogen”). Higher comparable EBITDA was offset by higher unrealized mark-to-market gains excluded to arrive at FCF.

Segmented Comparable Results

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.

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Canadian Coal

	3 months ended June 30					6 months ended June 30
	2017			2016		2017			2016
Availability (%)		84.5			85.7		84.1			86.1
Contract production (GWh)		4,430			4,335		9,400			9,254
Merchant production (GWh)		920			986		1,923			1,895
Total production (GWh)		5,350			5,321		11,323			11,149
Gross installed capacity (MW)		3,791			3,791		3,791			3,791
Revenues		248			229		498			463
Fuel and purchased power		122			90		244			173
Comparable gross margin		126			139		254			290
Operations, maintenance, and administration		47			43		91			88
Taxes, other than income taxes		4			3		7			6
Net other operating income		(10	)		-		(20	)		-
Comparable EBITDA		85			93		176			196
Depreciation and amortization		96			79		183			155
Comparable operating income (loss)		(11	)		14		(7	)		41
Sustaining capital:
Routine capital		5			11		10			13
Mine capital		3			7		6			7
Finance leases		4			3		7			6
Planned major maintenance		17			13		35			50
Total sustaining capital expenditures		29			34		58			76
Productivity capital		4			1		5			1
Total sustaining and productivity capital expenditures		33			35		63			77

Production for the three months ended June 30, 2017 increased 29 GWh compared to the same period in 2016. Lower availability caused by higher outages was offset by lower derates and paid curtailments on contracted assets as a result of slightly higher pricing. Production for the six months ended June 30, 2017 increased 174 GWh compared to the same period in 2016. Lower availability caused by higher planned and unplanned outages was offset by lower paid curtailment on contracted assets and lower levels of economic dispatching on our non-contracted generation as a result of slightly higher prices.

Comparable EBITDA for the three and six months ended June 30, 2017 decreased by $8 million and $20 million, respectively, compared to the same periods in 2016. Revenues for the quarter and year-to-date were positively impacted by the pass through of higher environmental compliance costs to the PPA buyer ($26 million). Lower realized prices on our uncontracted volumes and changes in our mark-to-market positions attributable to long-term financial contracts to economically hedge our future generation partially offset the increase in revenues. As expected, fuel and purchased power was impacted by higher coal costs related to the expected higher strip ratio and availability of equipment at our mine, and higher environmental compliance costs in 2017. Most of our higher environmental compliance costs are passed through to the PPA buyer. For the three and six months ended June 30, 2017, comparable EBITDA also included $10 million and $20 million, respectively, related to OCA payment accruals included in net other operating income. We expect to receive our OCA payment in the third quarter.

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Depreciation and amortization for the three and six months ended June 30, 2017 increased $17 million and $28 million, respectively, compared to the same periods in 2016, mainly due to shortening of the useful lives of the Keephills 3, Genesee 3, and Sundance 1 facilities and on mine equipment at the Sunhills mine as a result of the Alberta Climate Leadership Plan. See the Accounting Changes section of this MD&A for further details.

Sustaining capital expenditures for the three and six months ended June 30, 2017 were lower by $2 million and $14 million, respectively, compared to the same periods in 2016, when pit stops were executed on our Sundance 1 and 2 units. Productivity capital spending is expected to provide pay back in less than 2 years. See the Corporate Transformation section of this MD&A for further details.

US Coal

	3 months ended June 30						6 months ended June 30
	2017			2016			2017			2016
Availability (%)		18.8			68.8			36.7			84.4
Adjusted availability (%)(1)		67.1			72.1			76.8			86.1
Contract sales volume (GWh)		915			916			1,820			1,831
Merchant sales volume (GWh)		-			186			959			588
Purchased power (GWh)		(915	)		(923	)		(1,967	)		(1,868	)
Total production (GWh)		-			179			812			551
Gross installed capacity (MW)		1,340			1,340			1,340			1,340
Revenues		61			54			149			115
Fuel and purchased power		15			23			79			75
Comparable gross margin		46			31			70			40
Operations, maintenance, and administration		11			12			24			24
Taxes, other than income taxes		1			1			2			2
Comparable EBITDA		34			18			44			14
Depreciation and amortization		16			27			31			24
Comparable operating income (loss)		18			(9	)		13			(10	)
Sustaining capital:
Routine capital		2			1			2			2
Finance leases		1			2			2			2
Planned major maintenance		22			8			27			11
Total sustaining capital expenditures		25			11			31			15
Productivity capital		2			-			3			-
Total sustaining and productivity capital expenditures		27			11			34			15

Availability for the three and six months ended June 30, 2017 was down compared to 2016 due to a forced outage on Unit 1 in January. Both Units were taken out of service in February as a result of seasonally lower prices in the Pacific Northwest. We performed major maintenance on both units during this time. The lower availability had a nominal impact on our results as our contractual obligations were supplied with less expensive power purchased in the market.

Production was up 261 GWh during the first half of 2017 compared to 2016, due mainly to the timing of economic dispatching in 2017.

(1) Adjusted for economic dispatching.

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Comparable EBITDA improved by $16 million during the second quarter of 2017 compared to 2016, largely due to favourable impacts of mark-to-market positions on certain forward financial contracts that do not qualify for hedge accounting, higher contracted revenues, lower prices on purchased power, and favourable exchange rates in 2017. Comparable EBITDA improved by $30 million for the first half of 2017 compared to the same period in 2016, due to favourable impacts of mark-to-market positions on certain forward financial contracts that do not qualify for hedge accounting, higher merchant and contracted revenues, and lower prices on purchased power.

Depreciation and amortization for the second quarter of 2017 was lower by $11 million compared to 2016, due to an increase in our decommissioning obligation for the Centralia Mine in the second quarter of 2016. On a year-to-date basis, depreciation and amortization was up $7 million compared to 2016, due to a lower discount rate applied to the decommissioning obligation. As the mine is in the reclamation stage, adjustments to the decommissioning obligation are recognized in earnings.

Sustaining capital expenditures for the three and six months ended June 30, 2017 increased $16 million and $19 million, respectively, due to planned outages executed during the second quarter of 2017. Productivity capital relates to project Greenlight, our Corporate transformation project, which is intended to provide long-term cost savings. See the Strategic Growth and Corporate Transformation section of this MD&A for further details.

Canadian Gas

	3 months ended June 30				6 months ended June 30
	2017		2016		2017		2016
Availability (%)		82.3		95.5		91.6		97.5
Contract production (GWh)		379		712		772		1,455
Merchant production (GWh)		5		66		50		66
Total production (GWh)		384		778		822		1,521
Gross installed capacity (MW)(1)		953		1,057		953		1,057
Revenues		91		105		237		227
Fuel and purchased power		19		35		62		77
Comparable gross margin		72		70		175		150
Operations, maintenance, and administration		15		14		29		28
Taxes, other than income taxes		-		-		1		1
Comparable EBITDA		57		56		145		121
Depreciation and amortization		29		27		58		55
Comparable operating income		28		29		87		66
Sustaining capital:
Routine capital		4		2		4		2
Planned major maintenance		16		-		19		2
Total sustaining capital		20		2		23		4

Availability for the three and six months ended June 30, 2017 decreased by 13 per cent and 6 per cent compared to the same periods in 2016, primarily due to a planned major inspection at Sarnia, the base cycling conversion project at Windsor, and an unplanned steam turbine outage at Windsor.

(1) Includes production capacity for the Fort Saskatchewan power station, which has been accounted for as a finance lease, the portion of the Poplar Creek facility we continue to own and excludes the Mississauga cogeneration facility, which has been shutdown temporarily due to the recontracting in the fourth quarter of 2016.

M12 transalta corporation / Q2 2017

Production for the three and six months ended June 30, 2017 decreased by 394 GWh and 699 GWh compared to the same periods in 2016, primarily due to softer markets in Ontario in 2017 and the change in contracts at Mississauga and Windsor at the end of 2016. The Mississauga facility has been temporarily shut down effective Jan. 1, 2017, as we have no delivery obligations under the new agreement. We will continue to receive monthly capacity payments until the end of 2018 under the NUG Contract.

Comparable EBITDA for the six months ended June 30, 2017 increased by $24 million compared to 2016, primarily due to the settlement with OEFC for the retroactive adjustment to price indices at Ottawa and Windsor, partially offset by unfavourable changes in unrealized mark-to-market positions on gas contracts that do not qualify for hedge accounting, and higher labour costs. The Mississauga, Ottawa, and Windsor facilities are owned through our 50.01 per cent interest in TA Cogen.

Depreciation for the three and six months ended June 30, 2017 increased by $2 million and $3 million, respectively, compared to the same periods in 2016. We record the decrease in the finance lease receivable as a comparable increase in depreciation, as this amount, and the finance lease income, is included in comparable revenues as a proxy for capacity revenues for this segment.

Sustaining capital for the three and six months ended June 30, 2017 increased by $18 million and $19 million, respectively, compared to the same periods in 2016, primarily due to the scheduled maintenance at Sarnia and the base cycling conversion project at Windsor to increase its flexibility to respond to market prices.

Australian Gas

	3 months ended June 30				6 months ended June 30
	2017		2016		2017		2016
Availability (%)		93.9		94.3		91.9		92.2
Contract production (GWh)		472		371		870		743
Gross installed capacity (MW)(1)		425		425		425		425
Revenues		42		45		82		87
Fuel and purchased power		4		6		6		11
Comparable gross margin		38		39		76		76
Operations, maintenance, and administration		6		6		13		12
Comparable EBITDA		32		33		63		64
Depreciation and amortization		8		3		16		8
Comparable operating income		24		30		47		56
Sustaining capital:
Routine capital		2		-		2		1
Planned major maintenance		-		5		1		5
Total sustaining capital		2		5		3		6

Production for the three and six months ended June 30, 2017 increased 101 GWh and 127 GWh, respectively, compared to the same periods in 2016, mostly due to an increase in customer load. Due to the nature of our contracts, the increases did not have a significant financial impact on our results as our contracts are structured as capacity payments with a pass-through of fuel costs.

Comparable EBITDA was consistent across all periods.

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

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Depreciation and amortization for the three and six months ended June 30, 2017 increased by $5 million and $8 million, respectively, compared to the same periods in 2016, due mostly to the advanced start-up of one of the gas turbines at our South Hedland project in late December 2016. The remaining two other gas and steam turbines were completed and the South Hedland power project was fully commissioned on July 28, 2017. See the Significant and Subsequent Events section of this MD&A for further details.

Wind and Solar

	3 months ended June 30				6 months ended June 30
	2017		2016		2017		2016
Availability (%)		96.5		95.0		96.5		95.9
Contract production (GWh)		521		486		1,263		1,197
Merchant production (GWh)		254		245		567		665
Total production (GWh)		775		731		1,830		1,862
Gross installed capacity (MW)		1,363		1,408		1,363		1,408
Revenues		59		55		146		139
Fuel and purchased power		3		3		8		12
Comparable gross margin		56		52		138		127
Operations, maintenance, and administration		12		14		24		26
Taxes, other than income taxes		2		2		4		4
Comparable EBITDA		42		36		110		97
Depreciation and amortization		28		29		55		59
Comparable operating income		14		7		55		38
Sustaining capital:
Routine capital		-		1		-		1
Planned major maintenance		2		4		5		6
Total sustaining capital expenditures		2		5		5		7
Productivity capital		-		3		-		3
Total sustaining and productivity capital expenditures		2		8		5		10

Production for the three months ended June 30, 2017 increased by 44 GWh compared to same period in 2016, primarily due to higher availability and stronger wind resources, partially offset by sale of the Wintering Hills wind facility in the first quarter of 2017. Production for the six months ended June 30, 2017 decreased by 32 GWh compared to same period in 2016, as stronger wind resources in the first quarter did not fully offset the lost generation from the Wintering Hills wind facility, which was sold in the first quarter of 2017.

Comparable EBITDA for the three and six months ended June 30, 2017 increased by $6 million and $13 million, respectively, compared to the same periods in 2016, primarily due to better generation than last year at our contracted facilities in Eastern Canada and lower operations, maintenance, and administration expenses after renegotiating Long Term Service Agreements with service providers.

Depreciation and amortization was lower by $4 million for the first half of 2017 compared to 2016, primarily due to the disposition of our Wintering Hills merchant wind facility, which closed on March 1, 2017.

M14 transalta corporation / Q2 2017

Hydro

	3 months ended June 30				6 months ended June 30
	2017		2016		2017		2016
Contract production (GWh)		695		482		1,062		899
Merchant production (GWh)		31		37		39		41
Total production (GWh)		726		519		1,101		940
Gross installed capacity (MW)		926		926		926		926
Revenues		40		38		64		66
Fuel and purchased power		2		2		3		4
Comparable gross margin		38		36		61		62
Operations, maintenance, and administration		9		10		17		17
Taxes, other than income taxes		1		1		2		2
Comparable EBITDA		28		25		42		43
Depreciation and amortization		9		6		17		13
Comparable operating income		19		19		25		30
Sustaining capital:
Routine capital, excluding hydro life extension		1		2		3		2
Hydro life extension		-		3		-		6
Planned major maintenance		1		-		2		2
Total		2		5		5		10

Production for the three and six months ended June 30, 2017 increased by 207 GWh and 161 GWh, respectively, compared to the same periods in 2016, primarily due to higher water resources from spring run-off in Alberta.

This higher volume of generation positively impacted comparable EBITDA for the three months ended June 30, 2017, which increased by $3 million compared to the same period in 2016. Last year, we recorded a $3 million positive adjustment in the first quarter relating to a prior year metering issues at one of our facilities.

Depreciation for the three and six months ended June 30, 2017 increased by $3 million and $4 million, respectively, compared to the same periods in 2016, primarily due to a higher asset base and the recognition of a decommissioning obligation on transmission lines recently taken out of service. As the lines are not in service, the recognition of the obligation impacts depreciation.

Sustaining capital for the second quarter and year-to-date 2017 decreased $3 million and $5 million, respectively, compared to the same periods in 2016, primarily due to life extension projects at Bighorn and Brazeau last year.

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Energy Marketing

	3 months ended June 30				6 months ended June 30
	2017		2016		2017		2016
Revenues and comparable gross margin		18		11		19		43
Operations, maintenance, and administration		6		5		11		14
Comparable EBITDA		12		6		8		29
Depreciation and amortization		1		-		1		1
Comparable operating income		11		6		7		28

For the three months ended June 30, 2017, comparable EBITDA exceeded our 2016 results by $6 million due to a return to normal level of gross margin and better performance in certain markets. On a year to date basis, results were lower compared to 2016, due to unfavourable first quarter of 2017 results impacted by warm weather during the winter in the Northeast, significant precipitation in the Pacific Northwest, and reduced margins from our customer business.

Corporate

Our Corporate overhead costs were $4 million and $10 million higher for the three and six months ended June 30, 2017, respectively, compared to the same periods in 2016. Corporate costs in the second quarter include certain costs relating to our corporate transformation that we expect will translate into significant long-term cost savings. See the Strategic Growth and Corporate Transformation section of this MD&A for further details. The first quarter of 2017 also includes the reclassification of incentives for 2016 between our operational segments and our Corporate segment.

Key Financial Ratios

The methodologies and ratios used by rating agencies to assess our credit ratings 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.

FFO before Interest to Adjusted Interest Coverage

As at	June 30, 2017(1)		Dec. 31, 2016
FFO		780		763
Add:  Interest on debt net of interest income and capitalized interest		222		223
FFO before interest		1,002		986
Interest on debt net of interest income		239		239
Add:  50 per cent of dividends paid on preferred shares		20		21
Adjusted interest		259		260
FFO before interest to adjusted interest coverage (times)		3.9		3.8

Our target for FFO before interest to adjusted interest coverage is four to five times. The ratio improved slightly compared to 2016 due to stronger FFO. We expect this metric to improve towards our targeted level as a result of increased comparable EBITDA from operations at our South Hedland power project. See the Significant and Subsequent Events section of this MD&A for further details on South Hedland’s commissioning.

(1) Last 12 months. Our target range for FFO in 2017 is $765 million to $820 million.

M16 transalta corporation / Q2 2017

Adjusted FFO to Adjusted Net Debt

As at	June 30, 2017			Dec. 31, 2016
FFO(1)		780			763
Less:  50 per cent of dividends paid on preferred shares(1)		(20	)		(21	)
Adjusted FFO(1)		760			742
Period-end long-term debt(2)		3,803			4,361
Less:  Cash and cash equivalents		(50	)		(305	)
Add:  50 per cent of issued preferred shares		471			471
Fair value asset of economic hedging instruments on debt(3)		(44	)		(163	)
Adjusted net debt		4,180			4,364
Adjusted FFO to adjusted net debt (%)		18.2			17.0

Our adjusted FFO to adjusted net debt ratio improved to 18.2 per cent, due to the reduction in our net debt year-to-date and the improvement in FFO. We expect this metric to improve towards our targeted level of 20 to 25 per cent as a result of increased comparable EBITDA from our operations at our South Hedland power project. See the Significant and Subsequent Events section of this MD&A for further details on South Hedland’s commissioning.

Adjusted Net Debt to Comparable EBITDA

As at	June 30, 2017			Dec. 31, 2016
Period-end long-term debt(1)		3,803			4,361
Less:  Cash and cash equivalents		(50	)		(305	)
Add:  50 per cent of issued preferred shares		471			471
Fair value asset of economic hedging instruments on debt(3)		(44	)		(163	)
Adjusted net debt		4,180			4,364
Comparable EBITDA		1,160			1,145
Adjusted net debt to comparable EBITDA (times)		3.6			3.8

As at June 30, 2017 our adjusted net debt to comparable EBITDA ratio improved compared to 2016, mainly due to the significant reduction in our net debt during the year. Our target for adjusted net debt to comparable EBITDA is 3.0 to 3.5 times. We expect this metric to trend towards our targeted level due to the expected increase in comparable EBITDA of approximately $80 million annually from operations at our South Hedland power project. See the Significant and Subsequent Events section of this MD&A for further details on South Hedland’s commissioning.

(1) Last 12 months. Our target range for FFO in 2017 is $765 million to $820 million.

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

(3) Included in risk management assets and/or liabilities on the condensed consolidated financial statements as at June 30, 2017 and Dec. 31, 2016. During the first quarter of 2017, we discontinued hedge accounting on certain US-denominated debt hedges. The foreign currency derivatives remain in place as economic hedges. See the Financial Instruments section of this MD&A for further details.

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Strategic Growth and Corporate Transformation

Kent Hills 3 Wind Project

During the second quarter of 2017, TransAlta Renewables entered into a long-term contract with the New Brunswick Power Corporation for the sale of all power generated by an additional 17.25 MW of capacity to be installed at our Kent Hills wind project.

This is an expansion project of our existing Kent Hills wind project on approximately five to ten acres of Crown land, increasing the total operating capacity of the Kent Hills wind project to approximately 167 MW. As part of the regulatory process, we are submitting an Environmental Impact Assessment to the province of New Brunswick in the third quarter. If environmental approvals are received, we expect to begin the construction phase in the spring of 2018.

Brazeau Hydro Pumped Storage

The Brazeau Hydro Pumped Storage project is an innovative way to generate and shape clean electricity. It will store water that can be used to both generate power when it is needed and store excess power supply when demand is low. When there is excess renewable generation in periods of low demand, water will be pumped from the lower reservoir and stored in the upper reservoir to be used later. When demand is high and generation from other renewables generation is not sufficient, water will flow back through a turbine using gravity to generate clean electricity. The Brazeau Pumped storage project is a focus for us, as it has existing infrastructure that reduces the cost of the project, is situated close to existing transmission infrastructure, and allows for increased renewable development by balancing intermittent generation from wind and solar.

We are currently working to secure a path that will advance our investment in the project and secure a long-term contract for the project. The Brazeau Hydro Pumped Storage project is expected to have new capacity ranging between 600 MW to 900 MW, bringing the total Brazeau facility to 955 – 1,255 MW, post-completion. We estimate an investment in the range of $1.8 billion to $2.5 billion and expect construction to begin upon receipt of a long-term contract and regulatory approvals, between 2020 and 2021, and operations to commence in 2025. This year we are investing $5 million to $10 million to advance the environmental study, work with stakeholders, and execute geotechnical work to help further our design and construction phase.

Corporate Transformation - Project Greenlight

Our major corporate transformation project, called “Greenlight”, is a top priority for us. Driven by engagement from all employees, the intent is to deliver ambitious improvements in every part of our company. Initiatives include increasing revenue, improving generation, reducing operating and maintenance costs, reducing overhead costs and financing costs, and optimizing our capital spend. We expect Greenlight to deliver sustainable pre-tax savings of approximately $50 million to $70 million annually, commencing in 2018. We are on track to achieve our expected annual savings targets. Our internal cost to run these initiatives is expected to be between $10 million to $15 million in 2017.

Significant and Subsequent Events

Commissioning of South Hedland Facility and Conversion of Class B Shares

During, and subsequent to, the quarter, the final stages of construction of our South Hedland Facility, including reliability runs, were completed. The facility achieved commercial operation on July 28, 2017. On Aug. 1, 2017, TransAlta Renewables announced the conversion of the Class B Shares to common shares and an increase in monthly dividend rate by approximately 7 per cent.

On Aug. 1, 2017, Fortescue Metals Group Ltd. (“FMG”) issued a news release indicating that it had notified us that in its view the South Hedland Facility has not yet satisfied the requisite performance criteria under the South Hedland power purchase agreement between FMG and TransAlta. Our view is that all the conditions to establishing that commercial operations have been achieved under the terms of the power purchase agreement with FMG have been satisfied in full.  

M18 transalta corporation / Q2 2017

Termination of Solomon Power Purchase Arrangement

On Aug. 1, 2017, we received notice that FMG intends to repurchase the Solomon Power facility from TEC Pipe Pty Ltd., a wholly-owned subsidiary of the Corporation, for approximately US$335 million. FMG is expected to complete its acquisition of the Solomon Power Station in November 2017. We will utilize the proceeds in part to repay the credit facility used to fund the development of the South Hedland power station, for other future growth opportunities, and for general corporate purposes.

TransAlta Renewables Credit Facility

On July 24, 2017, TransAlta Renewables entered into a syndicated credit agreement giving it access to a $500 million committed credit facility. The agreement is fully committed for four years, expiring in 2021. The facility is subject to a number of customary covenants and restrictions in order to maintain access to the funding commitments. In conjunction with the new credit agreement, the existing $350 million credit facility currently provided by TransAlta was cancelled. At the same time, we also extended our credit facility, expiring in 2021 and reduced its credit facility by $500 million to $1 billion in total.

Appointment of Director

On July 13, 2017, the Board of Directors (the “Board”) appointed the Honourable Rona Ambrose to the Board effective July 13, 2017. We believe that Ms. Ambrose’s extensive public policy experience and demonstrated ability to bring people of divergent views together for a common purpose will strengthen our Board. Her experience, along with her Alberta roots, will also help further our strategy of becoming Canada’s leading clean power company through good governance, operational excellence, and growth. Ms. Ambrose was the former Leader of Canada’s Official Opposition in the House of Commons and former leader of the Conservative Party of Canada. She also acted as Minister of the Crown across nine government departments, including serving as Vice Chair of the Treasury Board and Chair of the cabinet committee for public safety, justice and aboriginal issues.

In addition to serving as an independent director, Ms. Ambrose is a Global Fellow at the Wilson Center Canada Institute in Washington, D.C. focusing on key Canada-U.S. bilateral trade and competitiveness issues. We look forward to the contributions of Ms. Ambrose to the Board of Directors.

Balancing Pool PPA Termination Consultation

On July 4, 2017, the Balancing Pool announced its intention to consult with customer representatives regarding the termination of the Alberta PPAs that it holds for Sundance A, Sundance B and Sundance C (the “Sundance PPAs”). It also stated that it considered the termination of the Sundance PPAs to be reasonable.

Under Section 97 of the Electric Utilities Act (Alberta), the Balancing Pool may terminate the PPAs if it:

§ Consults with representatives of customers and the Minister of Energy about the reasonableness of the termination;

§ Gives to the owner of the generating unit to which the PPA applies 6 months’ notice, or any shorter period agreed to by the owner, of its intention to terminate, and;

§ Pays the owner or ensures that the owner receives an amount equal to the remaining closing net book value of the generating unit, determined in accordance with the PPA, as if the generating unit had been destroyed, less any insurance proceeds.

We have 3,770 MW of gross capacity under PPAs, including hydro, representing approximately 23 per cent of the generation capacity in Alberta.  If, after meeting the requirements, the Balancing Pool chooses to terminate the Sundance B and C PPAs, we expect to receive approximately $231 million in payment for the net book value of the assets. Proceeds from any termination would be used to reduce outstanding debt, fund growth opportunities, and replace current gross margin from the existing PPAs. The Sundance A PPA expires at the end of 2017 and, as such, it was not included in the Balancing Pool’s initial PPA termination considerations.

Termination of the Sundance PPAs is expected to provide us with increased operational flexibility, including with respect to offer pricing for generation from the affected units, maintenance and turnaround schedules, and the timing of the coal-to-gas conversions.

transalta corporation /Q2 2017 m19

Series C Preferred Share Conversion Results and Rate Reset

On June 16, 2017, the Corporation announced that the minimum election notices received did not meet the requirements required to give effect to the conversion of the Series C Preferred Shares into the Series D Preferred Shares. As a result, none of the Series C Preferred Shares were converted into Series D Preferred Shares on June 30, 2017, and the dividend rate will remain fixed for the subsequent five-year period.

Transition to Clean Power in Alberta and Impairment Charge

On April 19, 2017, we announced our strategy to accelerate our transition to gas and renewables generation. The strategy includes the following steps:

§ retirement of Sundance Unit 1 effective Jan. 1, 2018;

§ mothballing of Sundance Unit 2 effective Jan. 1, 2018, for a period of 2 years; and

§ conversion of Sundance Units 3 to 6 and Keephills Units 1 and 2 from coal-fired generation to gas-fired generation in the 2021 to 2023 timeframe, thereby extending the useful lives of these units until the mid-2030's.

The retirement of Sundance Unit 1 and mothballing of Sundance Unit 2 reflects the limited economic viability of the units upon the expiry of their PPA due to the current oversupplied Alberta power market and low power price environment and is not expected to materially impact our forecasted cash flows for 2018 and 2019.

The benefits of converting coal-fired units to gas-fired generation include:

§ significantly lowering carbon intensities, emissions, and carbon costs;

§ significantly lowering operating and sustaining capital costs;

§ increasing operating flexibility; and

§ adding between five-to-ten years of economic life to each converted unit.

Sundance Units 1 and 2

Federal regulations stipulate that all coal plants built before 1975 must cease to operate on coal by the end of 2019, which includes Sundance Units 1 and 2.  Given that Sundance Unit 1 will be shut down two years early, the federal Minister of Environment has agreed to extend the life of Sundance Unit 2 from 2019 to 2021. This will provide us with flexibility to respond to the regulatory environment for coal-to-gas conversions and the new upcoming Alberta capacity market.

Sundance Units 1 and 2 collectively comprise 560 MW of the 2,141 MW at the Sundance power plants, which serves as a baseload provider for the Alberta electricity system. The PPA with the Balancing Pool relating to Sundance Units 1 and 2 expires on Dec. 31, 2017.

In the second quarter of 2017, we recognized an impairment loss on Sundance Unit 1 in the amount of $20 million due to our decision to early retire Sundance Unit 1. Previously, we had expected Sundance Unit 1 to operate in the merchant market in 2018 and 2019.  The impairment assessment was based on value in use and included the estimated future cash flows expected to be derived from the Unit until its retirement on Jan. 1, 2018. Discounting did not have a material impact.

No change in estimated useful life or separate stand-alone impairment test arose for Sundance Unit 2, as mothballing the Unit maintains our flexibility to operate the Unit beyond the expiry of the PPA to 2021.

Coal-to-Gas Conversions

In December 2016, notice was given by Environment and Climate Change Canada of its intention to amend regulations to phase out coal-fired generation by 2030 while permitting the conversion of boiler units from coal to natural gas fired generation for a period of up to 15 years or until 2045, whichever comes first. These regulations, which will facilitate our proposed coal-to-gas conversions, remain a work-in-progress. We are engaged with the Government of Canada in the development of required regulatory regime.

We are planning the conversion of Sundance Units 3 and 6 and Keephills Units 1 and 2 to gas-fired generation in the 2021 to 2023 timeframe, thereby extending the useful lives of these units until the mid-2030’s. We expect that the capacity of Sundance Units 3 to 6 and Keephills 1 and 2 will not change following conversion, which will result in a reduction of approximately 40 per cent of carbon emissions while maintaining approximately 2,400 MWs in the Alberta power grid.

M20 transalta corporation / Q2 2017

Our total capital commitment for the coal-to-gas conversions is expected to be approximately $300 million, mostly invested between 2021 to 2023. We anticipate funding the conversions with free cash flow at that time. These units are expected to provide low cost capacity and to be competitive in the upcoming capacity market auctions; we expect the first auction to occur in 2019 for 2021 and that Federal and Provincial regulations will be adopted to facilitate coal-to-gas conversions. We continue to be engaged with government in the development of the required regulatory regime. This year, we are committing $3 million to $5 million to advance engineering for the conversion.

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 receive annual cash payments on or before July 31 of approximately $39.7 million ($37.2 million, net to the Corporation), commencing Jan. 1, 2017 and terminating at the end of 2030.  We recognize the OCA payments evenly throughout the year. Accordingly, during the three and six months ended June 30, 2017, approximately $10 million and $20 million, respectively, was recognized in Net Other Operating Income in the Condensed Consolidated Statement of Earnings. Receipt of the payments is subject to certain terms and conditions. The OCA’s main condition is the cessation of all coal-fired emissions 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 are expecting to receive our first payment under the OCA in the third quarter of 2017.

Mississauga Cogeneration Facility New Contract

On Dec. 22, 2016, we announced that we had signed a NUG Contract with the Independent Electricity System Operator for our Mississauga cogeneration facility. The NUG Contract became effective on Jan. 1, 2017, and in conjunction with the execution of the NUG Contract, we agreed to terminate effective Dec. 31, 2016, the Mississauga cogeneration 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 totalling approximately $209 million until Dec. 31, 2018.

Refer to our 2016 Annual MD&A for further information regarding the Mississauga NUG Contract.

Wintering Hills Sale

On March 1, 2017, we closed the previously announced sale of our 51 per cent interest in the Wintering Hills merchant wind facility for approximately $61 million. Proceeds from the sale have been used for general corporate purposes, including reducing our debt and funding future renewables growth.

Credit Ratings Change

We maintain investment grade ratings from three credit rating agencies. Earlier this year, Fitch Ratings reaffirmed our Unsecured Debt rating and Issuer Rating of BBB- and changed their outlook from negative to stable, DBRS Limited changed our Unsecured Debt rating and Medium-Term Notes rating from BBB to BBB (low), the Preferred Shares rating from Pfd-3 to Pfd-3 (low), and Issuer Rating BBB to BBB (low) (changed to stable from negative), and Standard and Poor’s reaffirmed our Unsecured Debt rating and Issuer Rating of BBB- but changed the outlook from stable to negative.

Environmental Regulation Updates

Refer to the Regional Regulation and Compliance discussion in our 2016 Annual MD&A for further details that supplement the recent developments as discussed below.

Alberta

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

In January 2017, the AESO commenced consultation sessions and initiated the process for the development of a capacity market for the Province of Alberta. In May 2017, the AESO published a Straw Alberta market proposal for discussion.

transalta corporation /Q2 2017 m21

The AESO has now assembled five working groups to develop and provide recommendations on the design of Alberta’s capacity market.  The groups are comprised of industry stakeholders that are working collaboratively across five design streams for the market.  The working groups are tasked with developing their recommendations into papers that will be publicly issued for stakeholder comment.  The comments received from the stakeholder process will be considered by the working groups to refine the recommendations.  The first paper is planned to be released in September 2017, followed by papers issued in December 2017 and March 2018 and culminating in a final recommendation paper being issued to the AESO in June 2018.  The AESO will begin formalizing the capacity market design and implementing it in the second half of 2018 with first procurement expected in second half of 2019, to be effective in 2021 with first capacity contracts awarded at that time.

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 PPAs.

Capital Structure and Liquidity

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

	June 30, 2017						Dec. 31, 2016
	$			%			$			%
Recourse debt - CAD debentures		1,046			13			1,045			12
Recourse debt - U.S. senior notes		1,551			19			2,151			25
Credit facilities		100			1			-			-
U.S. tax equity financing		35			-			39			1
Other		14			-			15			-
Less: cash and cash equivalents		(50	)		(1	)		(305	)		(4	)
Less: fair value asset of economic hedging instruments on debt(1)		(44	)		(1	)		(163	)		(2	)
Net recourse debt		2,652			31			2,782			32
Non-recourse debt		992			12			1,038			12
Finance lease obligations		65			1			73			1
Total net debt		3,709			44			3,893			45
Non-controlling interests		1,124			14			1,152			14
Equity attributable to shareholders
Common shares		3,094			37			3,094			36
Preferred shares		942			11			942			11
Contributed surplus, deficit, and accumulated other comprehensive income		(560	)		(6	)		(525	)		(6	)
Total capital		8,309			100			8,556			100

We continued down our path of strengthening our financial position during the first half of 2017 and reduced our total net debt by $184 million. We made a scheduled US$400 million US Senior Note repayment. This repayment was hedged with a cross currency swap entered into on issuance of the debt that effectively reduced our Canadian dollar repayment by approximately $107 million.

(1) During the first quarter of 2017, we discontinued hedge accounting on certain US-denominated debt hedges. The foreign currency derivatives remain in place as economic hedges. See the Financial Instruments section of this MD&A for further details.

M22 transalta corporation / Q2 2017

On Jan. 18, 2017, we renewed a US base shelf prospectus that allows for the issuance of up to $2.0 billion aggregate principal amount (or its equivalent in other currencies) of common shares, first preferred shares, warrants, subscription receipts and debt securities from time to time. We also have a Canadian base shelf prospectus, which would allow for the issuance of common shares, first preferred shares, warrants, subscription receipts and debt securities from time to time. The specific terms of any offering of securities is to be determined at the date of issue.

The weakening of the US dollar has decreased our long-term debt balances by $61 million compared to Dec. 31, 2016. Almost all our U.S.-denominated debt is hedged⁽¹⁾ 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	June 30, 2017			Dec. 31, 2016
Effects of foreign exchange on carrying amounts of U.S. operations   (net investment hedge) and finance lease receivable		(44	)		(35	)
Foreign currency economic cash flow hedges on debt		(14	)		(29	)
Economic hedges and other		(3	)		(3	)
Total		(61	)		(67	)

During the period through Dec. 31, 2020, we have approximately $2.0 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 over the next 12 months. The expected proceeds from FMG, for the repurchase of the Solomon Power Facility will provide us more financial flexibility in executing the plan and the timing of financings will be adjusted to match the redeployment of capital. For further details see the Significant and Subsequent Events section of this MD&A. We also expect to continue our deleveraging strategy, as a significant part of our FCF over the next four years will be allocated to debt reduction.

Our credit facilities provide us with significant liquidity. At June 30, 2017, we had a total of $2.0 billion (Dec. 31, 2016 - $2.0 billion) of committed credit facilities, of which $1.3 billion (Dec. 31, 2016 - $1.4 billion) was available for use. We are in compliance with the terms of the credit facilities. At June 30, 2017, the $0.7 billion (Dec. 31, 2016 - $0.6 billion) of credit utilized under these facilities was comprised of actual drawings of $0.1 billion (Dec. 31, 2016 - nil) and letters of credit of $0.6 billion (Dec. 31, 2016 - $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. On July 24, 2017, TransAlta Renewables entered into a $500 million syndicated credit agreement, expiring in 2021. At the same time, we agreed to reduce our facility by the same amount, also expiring in 2021.

The Melancthon, Wolfe Wind, Pingston, TAPC Holdings LP, New Richmond and Mass Solar bonds are subject to customary financing conditions and covenants that may restrict the Corporation’s ability to access funds generated by the 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. These conditions include meeting a debt service coverage ratio prior to distribution, which was met by these entities in the second quarter. However, funds in these entities that have accumulated since the second quarter test, will remain there until the next debt service coverage ratio can be calculated in the third quarter of 2017. At June 30, 2017, $20 million (Dec. 31, 2016 - $24 million) of cash was subject to these financial restrictions.

Additionally, certain non-recourse bonds require that certain reserve accounts be established and funded through cash held on deposit and/or by providing letters of credit. The Corporation has elected to use letters of credit as at June 30, 2017. As at June 30, 2017, $1 million of cash was on deposit for certain reserves and was not available for general use.

(1) During the first quarter of 2017, we discontinued hedge accounting on certain US-denominated debt hedges. The foreign currency derivatives remain in place as economic hedges. See the Financial Instruments section of this MD&A for further details.

transalta corporation /Q2 2017 m23

Share Capital

The following table outlines the common and preferred shares issued and outstanding:

As at	Aug. 9, 2017		June 30, 2017		Dec. 31, 2016
	Number of shares (millions)
Common shares issued and outstanding, end of period		287.9		287.9		287.9
Preferred shares
Series A		10.2		10.2		10.2
Series B		1.8		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

Non-Controlling Interests

As of June 30, 2017, we own 64.0 per cent (Dec. 31, 2016 – 64.0 per cent) of TransAlta Renewables. The stable and predictable cash flows generated by TransAlta Renewables’ assets has attracted favourable equity valuations from investors, allowing TransAlta to raise equity capital. 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 TA Cogen which owns, operates, or has an interest in four natural-gas-fired facilities and a 50 per cent interest in a coal-fired generating facility.

Returns to Providers of Capital

Net Interest Expense

The components of net interest expense are shown below:

	3 months ended June 30						6 months ended June 30
	2017			2016			2017			2016
Interest on debt		56			54			112			111
Interest income		(1	)		-			(2	)		(1	)
Capitalized interest		(5	)		(4	)		(8	)		(7	)
Loss on redemption of bonds		-			1			-			1
Interest on finance lease obligations		1			1			2			2
Other(1)		3			5			7			9
Accretion of provisions		5			5			10			11
Net interest expense		59			62			121			126

Net interest expense decreased during the first half of 2017 compared to 2016 due to higher interest income and higher capitalized interest, which was slightly offset by higher interest on debt. During 2016, interest accruals were included relating to our Keephills 1 outage arbitration.

(1) 2016 includes interest accrued related to the Keephills 1 outage arbitration.

M24 transalta corporation / Q2 2017

Dividends to Shareholders

On Dec. 19, 2016, we declared quarterly dividends per common share and preferred shares payable to shareholders relating to the period covering the first quarter of 2017. A total of $12 million and $10 million in common and preferred share dividends were paid during the first quarter of 2017, respectively.

On April 19, 2017, we declared a dividend of $0.04 per common share, payable on July 1, 2017. We also declared a quarterly dividend of $0.16931 per share on the Series A preferred shares, $0.15645 per share on the Series B preferred shares, $0.2875 per share on the Series C preferred shares, $0.3125 per share on the Series E preferred shares, and $0.33125 per share on the Series G preferred shares, all payable on June 30, 2017.

On July 18, 2017, we declared a dividend of $0.04 per common share, payable on Oct. 1, 2017. We also declared a quarterly dividend of $0.16931 per share on the Series A preferred shares, $0.16125 per share on the Series B preferred shares, $0.25169 per share on the Series C preferred shares, $0.3125 per share on the Series E preferred shares, and $0.33125 per share on the Series G preferred shares, all payable on Sept. 30, 2017.

Non-Controlling Interests

Reported earnings attributable to non-controlling interests for the three and six months ended June 30, 2017 increased by $8 million and $43 million, respectively, compared to the same periods in 2016, due mostly to higher earnings at TransAlta Renewables. In both periods, higher earnings at TransAlta Renewables resulted from a lower unrealized change in fair value of the Class B shares liability. Year-to-date, favourable reductions in unrealized foreign exchange losses on financial interests in the Australian Assets also contributed to the increase.

transalta corporation /Q2 2017 m25

Other Consolidated Analysis

Financial Position

The following chart highlights significant changes in the Condensed Consolidated Statements of Financial Position from Dec. 31, 2016 to June 30, 2017:

	Increase/
Assets	(decrease)			Primary factors explaining change
Cash and cash equivalents		(255	)	Repayment of long-term debt ($480 million), net of cross currency swap, partially offset by proceeds from sale of our Wintering Hills merchant wind facility ($61 million)
Trade and other receivables		(32	)	Timing of customer receipts and seasonality of revenue
Prepaid expenses		35		Timing of payments of insurance, deposits, and other prepayments
Inventory		34		Increase in coal inventory following lower production in the US and transfer of inventory from PP&E
Assets held for sale		(61	)	Closing of the sale of the Wintering Hills merchant wind facility
Finance lease receivables (long term)		(47	)	Unfavourable changes in foreign exchange rates ($14 million) and scheduled receipts ($30 million)
Property, plant, and equipment, net		(120	)	Depreciation for the period ($303 million) and unfavourable changes in foreign exchange rates ($14 million), partially offset by additions ($157 million), and revisions to decommissioning and restoration costs ($78 million)
Risk management assets (current and long term)		(68	)	Contract settlements and unfavourable changes in foreign exchange rates, partially offset by market price movements
Other assets		(50	)	Primarily the transfer of portion of Mississauga recontracting receivable to current assets
Other		(13	)
Total decrease in assets		(577	)

M26 transalta corporation / Q2 2017

	Increase/
Liabilities and equity	(decrease)			Primary factors explaining change
Dividends payable		(28	)	Timing of the declaration of common dividends
Credit facilities, long term debt, and finance lease obligations (including current portion)		(558	)	Repayments ($587 million) and favourable effects of changes in foreign exchange rates ($61 million), partially offset by increase in credit facility ($100 million)
Decommissioning and other provisions (current and long term)		78		Impact of lower discount rate due to shortened useful lives on certain Alberta coal assets
Deferred income tax liabilities		(38	)	Reversal of a writedown of deferred tax assets mainly related to our US business and reversals of taxable temporary differences
Equity attributable to shareholders		(35	)	Common share dividends ($12 million), preferred share dividends ($10 million), net loss ($8 million), and net other comprehensive loss ($5 million)
Non-controlling interests		(28	)	Distributions ($91 million), partially offset by net earnings ($44 million) and other comprehensive income ($19 million)
Other		32
Total decrease in liabilities and equity		(577	)

Cash Flows

The following chart highlights significant changes in the Condensed Consolidated Statements of Cash Flows for the three and six months ended June 30, 2017 compared to the same periods in 2016:

3 months ended June 30	2017			2016			Increase/ (decrease)			Primary factors explaining change
Cash and cash equivalents, beginning of period		504			30			474
Provided by (used in):
Operating activities		63			119			(56	)	Unfavourable change in non-cash working capital ($69 million), partially offset by an increase in cash earnings ($13 million)
Investing activities		(74	)		(76	)		2		Favaourable change in investing working capital ($39 million), partially offset by lower realized gains on financial instruments ($15 million) and higher additions to property, plant and equipment ($21 million)
Financing activities		(442	)		20			(462	)	Higher repayment of long-term debt ($499 million), higher distributions paid to subsidiaries' non-controlling interests ($14 million), lower net borrowings on credit facilities and issuance of long-term debt ($59 million), partially offset by higher realized gain on financial instrument ($107 million)
Translation of foreign currency cash		(1	)		-			(1	)
Cash and cash equivalents, end of period		50			93			(43	)

transalta corporation /Q2 2017 m27

6 months ended June 30	2017			2016			Increase/ (decrease)			Primary factors explaining change
Cash and cash equivalents, beginning of year		305			54			251
Provided by (used in):
Operating activities		344			394			(50	)	Unfavourable change in non-cash working capital of ($68 million), partially offset by higher cash earnings ($18 million)
Investing activities		(69	)		(143	)		74		Proceeds on sale of the Wintering Hills merchant wind facility in the first quarter of 2017 ($61 million) and favourable change in non-cash investing working capital ($30 million)
Financing activities		(530	)		(210	)		(320	)	Higher repayment of long-term debt ($523 million) and lower proceeds on sale of non-controlling interest in subsidiary ($162 million), partially offset by lower net borrowings on credit facilities and issuance of long-term debt ($256 million), lower dividends paid on common shares ($23 million), and higher realized gain on financial instrument ($107 million)
Translation of foreign currency cash		-			(2	)		2
Cash and cash equivalents, end of period		50			93			(43	)

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 June 30, 2017, we had provided letters of credit totalling $556 million (Dec. 31, 2016 - $566 million) and cash collateral of $69 million (Dec. 31, 2016 - $77 million). These letters of credit and cash collateral secure certain amounts included on our Condensed Consolidated Statements of Financial Position under risk management liabilities and decommissioning and other provisions.

Commitments

During the first quarter of 2017, we extended and revised our existing agreement with Alstom to provide major maintenance for our Canadian Coal facilities. The agreement relates to major maintenance projects over the 2017 through 2020 years at our Keephills plants and on some Sundance plants. Alstom will be accountable for providing its services on budget and on time with a guarantee on performance.

M28 transalta corporation / Q2 2017

Contingencies

I. Line Loss Rule Proceeding

TransAlta is participating in a line loss rule proceeding (the "LLRP") that is currently before the Alberta Utilities Commission (“AUC”). The AUC determined that it had the ability to retroactively adjust line loss rates going back to 2006 and directed the Alberta Electric System Operator (the "AESO") to, among other things, perform such retroactive calculations. The various decisions by the AUC are, however, subject to appeal and challenge. TransAlta may incur additional transmission charges as a result of the LLRP. The outcome of the LLRP, however, currently remains uncertain and the total potential exposure faced by TransAlta, if any, cannot be calculated with certainty until retroactive calculations using a AUC-approved methodology are made available, and until the AUC determines what methodology will be used for retroactive calculations. The AESO expects retroactive calculations for each year using a AUC-approved methodology to begin to be available later in 2017. Further, certain PPAs for TransAlta’s facilities provide for the pass through of these types of transmission charges to the PPA buyers.

As a result, no provision has been recorded at this time.  

Financial Instruments

Refer to Note 13 of the notes to the audited annual consolidated financial statements within our 2016 Annual Integrated Report and Note 8 of our unaudited interim condensed consolidated financial statements as at and for the three and six months ended June 30, 2017 for details on Financial Instruments. Refer to the Governance and Risk Management section of our 2016 Annual Integrated Report and Note 9 of our unaudited interim condensed consolidated financial statements for further details on our risks and how we manage them. Our risk management profile and practices have not changed materially from Dec. 31, 2016.

During the first quarter of 2017, we discontinued hedge accounting for certain foreign currency cash flow and fair value hedges on US$690 million and US$50 million of debt, respectively. As at March 31, 2017, cumulative gains on the cash flow hedges of approximately $3 million will continue to be deferred in Accumulated Other Comprehensive Income (“AOCI”) and will be reclassified to net earnings as the forecasted transactions (interest payments) occur. As at March 31, 2017, cumulative losses of approximately $2 million related to the fair value hedge, and recognized as part of the carrying value of the hedged debt, will be amortized to net earnings over the period to the debt’s maturity. Changes in these risk management assets and liabilities related to these discontinued hedge positions will be reflected within net earnings prospectively.

We may enter into commodity transactions involving non-standard features for which observable market data is not available. These are defined under IFRS as Level III financial instruments. Level III financial instruments are not traded in an active market and fair value is, therefore, developed using valuation models based upon internally developed assumptions or inputs. Our Level III fair values are determined using data such as unit availability, transmission congestion, or demand profiles. Fair values are validated on a quarterly basis by using reasonably possible alternative assumptions as inputs to valuation techniques, and any material differences are disclosed in the notes to the financial statements.

As at June 30, 2017, total Level III financial instruments had a net asset carrying value of $807 million (Dec. 31, 2016 - $758 million net asset). The increase during the period is primarily due to the changes in value of the long-term power sale contract designated as an all-in-one cash flow hedge, for which changes in fair value are recognized in other comprehensive income.

transalta corporation /Q2 2017 m29

2017 Financial Outlook

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

Measure	Target
Comparable EBITDA	$1,025 million to $1,100 million
Comparable FFO	$765 million to $820 million
Comparable FCF	$270 million to $310 million
Canadian Coal fleet availability	81 to 83 per cent
Dividend	$0.16 per common share annualized, 15 to 17 per cent payout of FCF

2017 Outlook Update

During the first half of the year, emerging labour constraints at our Alberta coal mine have impacted productivity at the mine, significantly reducing our coal inventory and causing coal supply constraints for our facilities in Alberta. The shortfall affects our Sundance coal-fired generating units 1 to 6 and Keephills units 1 to 3. We expect additional mining costs at our Highvale mine operations for the remainder of 2017, and a shorter-term reduction in the power generation at Sundance and Keephills, in order to rebuild our coal inventory. Also, higher productivity capital and higher distributions to non-controlling interests have negatively impacted FCF. Accordingly, we have reduced the following 2017 targets: FCF target range to $270 million to $310 million from the previously announced target range of $300 to $365 million, Comparable EBITDA from the previously announced target range of $1,025 to $1,135 million to $1,025 to $1,100 million, and FFO from the previously announced target range of $765 to $855 million to $765 to $820 million.

Availability

Availability of our Canadian coal fleet is expected to be in range of 81 to 83 per cent in 2017, lower than our target during the first quarter of 2017 of 86 to 88 per cent due to attrition, unforeseen maintenance, and other issues at the Highvale mine. Availability of our other generating assets (gas, renewables) generally exceeds 95 per cent.

Prices

For the remainder of 2017, power prices in Alberta are expected to be slightly higher than 2016 as a result of carbon costs that increase the variable cost of generation year-over-year. However, prices can vary based on supply and weather conditions. In the Pacific Northwest power prices for the third and fourth quarter are expected to be comparable to 2016. In Ontario, power prices are expected to be lower due to weak weather driven demand, ample baseload nuclear generation, and demand side management.

Contractual Profile

As a result of Alberta PPAs and long-term contracts, approximately 80 per cent of our capacity is contracted over the next two years. With the announced closure of Sundance Unit 1 and the mothballing of Sundance Unit 2, this level of contracted capacity is relatively stable until the end of 2020 when the PPA's on our Alberta coal fleet end. More than half of our non-contracted generation is sold forward 12 to 18 months ahead of time using short-term physical or financial contracts, such that on an aggregated portfolio basis, depending on market conditions, we target being up to 90 per cent contracted for the upcoming calendar year. As at the end of the second quarter, approximately 91 per cent of our 2017 capacity was contracted. The average prices of our short-term physical and financial contracts for 2017 are approximately $45 per MWh in Alberta and approximately US$45 per MWh in the Pacific Northwest.

Any termination of the Sundance PPAs by the Balancing Pool that may arise is not expected to have an impact in 2017 due to the 6 month notice requirement that is required to be given to the owner of the generating unit prior to any termination becoming effective.

M30 transalta corporation / Q2 2017

Fuel Costs

As disclosed previously, the cost to mine coal at our Alberta mine is expected to increase due to a major outage of a dragline and a higher strip ratio in 2017. Seasonal variations in coal costs at our Alberta mine are minimized through the application of standard costing. In addition, coal costs for 2017, on a standard cost per tonne basis, are expected to be affected by the loss on sale of inventory and lower availability of large equipment. As a result, we now expect our standard coal costs to be 21 per cent in 2017, up from 12 per cent. The development of Pit 9 in 2018 is expected to improve our strip ratio.

In the Pacific Northwest, our US Coal mine, adjacent to our power plant, is in the reclamation stage. Fuel at US Coal has been purchased primarily from external suppliers in the Powder River Basin and delivered by rail. The delivered fuel cost will decrease slightly in 2017 primarily due to lower transportation costs resulting from lower expected natural gas prices.

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 third parties 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 exposures to maximize earnings while still maintaining an acceptable risk profile. Our revised 2017 target is for Energy Marketing to contribute between $50 million to $70 million in gross margin for the year, down from our $60 million to $70 million target in the first quarter, and below our initial target of $70 million to $90 million.

Exposure to Fluctuations in Foreign Currencies

Our strategy is to minimize the impact of fluctuations in the Canadian dollar against the U.S. 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.

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 $1.3 billion in liquidity. Our continued focus will be toward repositioning our capital structure and we expect to be well positioned to address the upcoming debt maturities in 2018.

transalta corporation /Q2 2017 m31

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		364		210 - 230	Q3 2017	150 MW combined-cycle power plant
Solomon load bank facility		5		2		3	Q4 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		366		216 - 236

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

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 property, plant and equipment (“PP&E”) and are amortized either on a straight-line basis over the term until the next major maintenance event or on a unit-of-production basis. These costs exclude 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 to date(1)		Expected spend in 2017
Routine capital(4)	Capital required to maintain our existing generating capacity		30		85 - 90
Planned major maintenance	Regularly scheduled major maintenance		89		125 - 130
Mine capital	Capital related to mining equipment and land purchases		6		25 - 30
Finance leases	Payments on finance leases		8		15 - 20
Total sustaining capital			133		250 - 270
Productivity capital	Projects to improve power production efficiency and   corporate improvement initiatives		9		20 - 25
Total sustaining and productivity capital			142		270 - 295

(1) Represents amounts spent as of June 30, 2017.

(2) Estimated project expenditures are AUD$553 million. Total estimated project expenditures are stated in CAD$ and include estimated capital interest costs. The total estimated project expenditures may change due to fluctuations in foreign exchange rates. Approximately $160 million in project expenditures relate to infrastructure acquisition and network, water and gas access deposits, and prepayments, most of which is due to be paid on commissioning.

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

(4) Includes hydro life extension spend.

M32 transalta corporation / Q2 2017

While we decreased our target on sustaining capital, we shifted the productivity capital expected spend for 2017 as these relate to the funding of some Greenlight transformation initiatives. In certain cases, payback is expected to be achieved within two years. The total sustaining and productivity capital remains unchanged.

To date we have completed major planned outages at Sundance Unit 6, Keephills Unit 2, Centralia Unit 2, and Windsor.

Significant planned major outages remaining for 2017 include the following: 

§ a turnaround on Keephills 3 in the third quarter, Sheerness 1 in the fourth quarter, and a major overhaul to one of our draglines at our Highvale mine,

§ one major outage in our Canadian Gas segment related to our Sarnia facility, scheduled for the fourth quarter.

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		Lost to date(1)
GWh lost		940 - 950		235 - 265		1,175 - 1,215		1,191

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 $2.0 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.

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Accounting Changes

A. Current Accounting Changes

I. Change in Estimates – Useful Lives

As a result of the OCA with the Government of Alberta described in the Significant Events section of this MD&A and in our 2016 annual consolidated financial statements, we will cease coal-fired emissions by the end of 2030. On Jan. 1, 2017, the useful lives of the PP&E and amortizable intangibles associated with some of our Alberta coal assets were reduced to 2030. As a result, depreciation expense and intangibles amortization for the three months ended June 30, 2017 increased by approximately $28 million and the full year 2017 depreciation and amortization expense are expected to increase by approximately $58 million. The useful lives may be revised or extended in compliance with our accounting policies, dependent upon future operating decisions and events, such as coal-to-gas conversions.

As a result of our decision to retire Sundance Unit 1 effective Jan. 1, 2018 (see the Significant and Subsequent Events section of this MD&A for further details), the useful lives of the Sundance Unit 1 PP&E and amortizable intangibles were reduced in the second quarter of 2017 by two years to Dec. 31, 2017. As a result, depreciation expense and intangibles amortization for the three months ended June 30, 2017 increased in total by approximately $4 million and the full year 2017 depreciation and amortization expense is expected to increase by approximately $15 million.

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 IFRS 9 Financial Instruments, IFRS 15 Revenue from Contracts with Customers, and IFRS 16 Leases. Refer to Note 3 of our most recent annual consolidated financial statements for information regarding the requirements of IFRS 9, IFRS 15, and IFRS 16. We continue to make progress on the implementation plan for each standard. As part of each implementation plan, a centralized project team has been created to manage project activities. A stakeholder committee has been formed to oversee the implementation process and it includes individuals from the relevant functions and business units.

With respect to IFRS 9, we are in the process of completing an assessment of the classification and measurement portion of the standard. Activities to identify and calculate impacts from the impairment portion of the standard have commenced. In addition, the review of process and disclosure requirements have commenced. It is not yet possible to make a reliable estimate of the impact of IFRS 9 on the financial statements and disclosures. Our current estimate of the time and effort necessary to complete the implementation plan for IFRS 9 extends into late 2017.

With respect to IFRS 15, the Corporation is in the process of completing the accounting assessment of its revenue streams and underlying contracts with customers. In addition, the review of process and disclosure requirements have commenced. The majority of our revenues within the scope of IFRS 15 are earned through the sale of capacity and energy under both long-term arrangements and merchant mechanisms. Commentary on implementation issues specific to the power and utilities industry is in the process of being discussed and issued by standard setters in the United States. Certain implementation commentary is expected to be relevant to the Corporation’s long term arrangements. We currently estimate that the time and effort necessary to complete our implementation plan for IFRS 15 will extend into late 2017. We anticipate finalizing a decision with respect to the transition method in late 2017. It is not yet possible to make a reliable estimate of the impact IFRS 15 will have on our financial statements and disclosures.

We are in the process of completing our initial scoping assessment for IFRS 16 and have prepared a detailed project plan. It is anticipated that most of 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 impact of IFRS 16 on the financial statements and disclosures.

M34 transalta corporation / Q2 2017

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.

	Q3 2016			Q4 2016		Q1 2017		Q2 2017
Revenues		620			717		578		503
Comparable EBITDA		244			374		274		268
Comparable FFO		163			228		203		187
Net earnings (loss) attributable to common shareholders		(12	)		61		-		(18	)
Net earnings (loss) per share attributable to common shareholders,    basic and diluted(1)		(0.04	)		0.21		-		(0.06	)

	Q3 2015		Q4 2015			Q1 2016		Q2 2016
Revenues		641		595			568		492
Comparable EBITDA		219		268			279		248
Comparable FFO		126		243			196		175
Net earnings (loss) attributable to common shareholders		154		(7	)		62		6
Net earnings (loss) per share attributable to common shareholders,    basic and diluted(1)		0.55		(0.02	)		0.22		0.02

(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.

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Reported net earnings, comparable EBITDA, and 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 third quarter of 2015, the first and second quarters of 2016, and the second quarter of 2017,

§ 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 unrealized losses on intercompany financial instruments that are attributable only to the non-controlling interests in the first, second, and third quarters of 2016, and unrealized gains in the first quarter of 2017,

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

§ effects of the Keephills 1 outage provision, and

§ effects of the Wintering Hills impairment charge during the fourth quarter of 2016, and the Sundance Unit 1 impairment charge during the second quarter of 2017.

Disclosure Controls and Procedures

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

There have been no changes in our internal control over financial reporting during the three months ended June 30, 2017 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 June 30, 2017, the end of the period covered by this report, our disclosure controls and procedures were effective.

M36 transalta corporation / Q2 2017

Supplemental Information

		June 30, 2017		Dec. 31, 2016
Closing market price (TSX) ($)			8.29		7.43
Price range for the last 12 months (TSX) ($)	High		8.30		7.54
	Low		5.17		3.76
Adjusted net debt to invested capital(1) (%)			50.3		51
Adjusted net debt to comparable EBITDA(1, 2) (times)			3.6		3.8
Return on equity attributable to common shareholders(2)(%)			1.4		5.4
Return on capital employed(2)(%)			4.3		5.3
Earnings coverage(2)(times)			1.3		1.7
Dividend payout ratio based on FFO(1, 2, 3)(%)			6.2		7.8
Dividend coverage(2,3)(times)			16.2		11.5
Dividend yield(2,3)			1.9		4.0
Adjusted FFO to adjusted net debt(2)(%)			18.2		17.0
FFO before interest to adjusted interest coverage(2)(times)			3.9		3.8

Ratio Formulas

Adjusted net debt to invested capital = long-term debt and finance lease obligations including current portion and fair value (asset) liability of hedging instruments on debt + 50 per cent issued preferred shares - cash and cash equivalents / adjusted net debt + non-controlling interests + equity attributable to shareholders - 50 per cent issued preferred shares

Adjusted net debt to comparable EBITDA = long-term debt and finance lease obligations including current portion and fair value (asset) liability of hedging instruments on debt - cash and cash equivalents + 50 per cent issued preferred shares / comparable EBITDA

Return on equity attributable to common shareholders = net earnings attributable to common shareholders / equity attributable to common shareholders excluding AOCI

Return on capital employed = earnings before non-controlling interests and income taxes + net interest expense before non-controlling interests and income taxes + net interest expense / invested capital excluding AOCI

Earnings coverage = net earnings attributable to shareholders + income taxes + net interest expense / interest on debt + 50 per cent dividends paid on preferred shares - interest income

(1) These ratios incorporate items that are not defined under IFRS. None of these measurements should be used in isolation or as a substitute for the Corporation’s reported financial performance or position as presented in accordance with IFRS. These ratios are useful complementary measurements for assessing the Corporation’s financial performance, efficiency, and liquidity and are common in the reports of other companies but may differ by definition and application. For a reconciliation of the non-IFRS measures used in these calculations, refer to the Additional IFRS and Non-IFRS Measures section of this MD&A.

(2) Last 12 months.

(3) On Jan. 14, 2016, we revised our dividend to $0.16 per common share on an annualized basis from $0.72 previously. The effect of the change is not reflected in these historical ratios.

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Dividend payout ratio = dividends declared per common / FFO - 50 per cent dividends paid on preferred shares

Dividend coverage ratio = cash flow from operating activities / cash dividends paid on common shares

Dividend yield = dividend paid per common share / current period’s closing market price

Adjusted FFO to adjusted net debt = FFO - 50 per cent dividends paid on preferred shares / period end long-term debt and finance lease obligations including fair value (asset) liability of hedging instruments on debt + 50 per cent issued preferred shares - cash and cash equivalents

FFO before interest to adjusted interest coverage = FFO + interest on debt - interest income - capitalized interest / interest on debt + 50 per cent dividends paid on preferred shares - interest income

Glossary of Key Terms

Availability - A measure of the time, expressed as a percentage of continuous operation 24 hours a day, 365 days a year that a generating unit is capable of generating electricity, regardless of whether or not it is actually generating electricity.

Capacity - The rated continuous load-carrying ability, expressed in megawatts, of generation equipment.

Force Majeure - Literally means “greater force”. These clauses excuse a party from liability if some unforeseen event beyond the control of that party prevents it from performing its obligations under the contract.

Gigawatt - A measure of electric power equal to 1,000 megawatts.

Gigawatt Hour (GWh) - A measure of electricity consumption equivalent to the use of 1,000 megawatts of power over a period of one hour.

Greenhouse Gas (GHG) - Gases having potential to retain heat in the atmosphere, including water vapour, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, and perfluorocarbons.

Megawatt (MW) - A measure of electric power equal to 1,000,000 watts.

Megawatt Hour (MWh) - A measure of electricity consumption equivalent to the use of 1,000,000 watts of power over a period of one hour.

Power Purchase Arrangement (PPA) - A long-term arrangement established by regulation for the sale of electric energy from formerly regulated generating units to buyers.

Unplanned Outage - The shut down of a generating unit due to an unanticipated breakdown.

M38 transalta corporation / Q2 2017

TransAlta Corporation

110 - 12th Avenue S.W.

Box 1900, Station “M”

Calgary, Alberta Canada T2P 2M1

Phone

403.267.7110

Website

www.transalta.com

AST Trust Company (Canada)

P.O. Box 700 Station “B”

Montreal, Québec Canada H3B 3K3

Phone

Toll-free in North America: 1.800.387.0825

Toronto or outside North America: 416.682.3860

Fax

514.985.8843

E-mail

inquiries@canstockta.com

Website

www.canstockta.com

FOR MORE INFORMATION

Media and Investor Inquiries

Investor Relations

Phone

1.800.387.3598 in Canada and United States

or 403.267.2520

Fax

403.267.7405

E-mail

investor_relations@transalta.com

transalta corporation /Q2 2017 m39