EX-13.2 3 mdaex13-2.htm MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF THE REGISTRANT AS AT AND FOR THE PERIOD ENDED SEPTEMBER 30, 2013. CA Filed by Filing Services Canada Inc. 403-717-3898

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 TRANSALTA CORPORATION

 SECOND QUARTER REPORT FOR 2013

 

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 nine months ended Sept. 30, 2013 and 2012, and should also be read in conjunction with the audited consolidated financial statements and MD&A contained within our 2012 Annual Report. In this MD&A, unless the context otherwise requires, ‘we’, ‘our’, ‘us’, the ‘Corporation’, and ‘TransAlta’ refers to TransAlta Corporation and its subsidiaries. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”). All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted. Certain financial measures included in this MD&A do not have a standardized meaning as prescribed by IFRS. These measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. See the Non-IFRS Measures section of this MD&A for additional information. This MD&A is dated Oct. 31, 2013. Additional information respecting TransAlta, including its Annual Information Form, is available on SEDAR at www.sedar.com.

 

 

rESULTS OF OPERATIONS

 

The results of operations are presented on a consolidated basis and by business segment. We have three business segments: Generation, Energy Trading, and Corporate. In this MD&A, the impact of foreign exchange fluctuations on foreign currency denominated transactions and balances is discussed with the relevant Condensed Consolidated Statements of Earnings (Loss) and Condensed Consolidated Statements of Financial Position items. While individual line items in the Condensed Consolidated Statements of Financial Position may be impacted by foreign exchange fluctuations, the net impact of the translation of these items relating to foreign operations to our presentation currency is reflected in Accumulated Other Comprehensive Income (Loss) (“AOCI”) in the equity section of the Condensed Consolidated Statements of Financial Position.

 

 

highlights

 

Third Quarter Highlights

 

Strategic Highlights

 

§   Formation of TransAlta Renewables Inc. (“TransAlta Renewables”), creating a vehicle for enhancing TransAlta’s strategy to grow in renewables.

§   50 megawatt (“MW”) long-term contract with the Salt River Project signed by our CalEnergy, LLC (“CalEnergy”) joint venture.

§   74 MW 20-year long-term power supply contract with the Ontario Power Authority for our Ottawa facility.

§   Restart of Sundance Unit 1 in September and Unit 2 in October.

  

TRANSALTA CORPORATION / Q2 2013  1

   

 

Operational Financial Results

 

§Renewables: Comparable gross margin increased $3 million to $91 million primarily as a result of the addition of the New Richmond wind farm, which more than offset low hydro margins in the quarter.
§Gas: Comparable gross margin, including finance lease income, increased $14 million to $102 million, primarily due to the addition of the Solomon power station.
§Coal: Comparable gross margin, adjusted for the impact of de-designated hedges, decreased $42 million, primarily as a result of higher coal costs at our Alberta coal Power Purchase Arrangement (“PPA”) facilities and lower contract prices at Centralia Thermal.
§Energy Trading: Comparable gross margin increased $38 million due to strong trading performance across all markets.
§Comparable Operations, Maintenance, and Administration (“OM&A”): Comparable OM&A increased $8 million to
$124 million due to higher maintenance costs and lower expense recoveries.
§Overall availability, including finance leases and equity investments, was 85.9 per cent compared to 90.9 per cent in 2012. Adjusting for economic dispatching at Centralia Thermal, availability was 85.9 per cent compared to 91.7 per cent in 2012. The decrease is primarily due to higher unplanned outages associated with the Keephills Unit 1 force majeure outage, which was partially offset by lower planned outages at the Alberta coal PPA facilities and strong performance in the gas fleet.
§Overall production increased 933 gigawatt hours (“GWh”) 11,088 GWh compared to 2012.

 

Consolidated Highlights

 

§Comparable Earnings Before Interest, Taxes, Depreciation, and Amortization (“EBITDA”) increased $11 million in the quarter to $266 million compared to 2012.
§Funds from Operations (“FFO”) decreased $59 million to $174 million compared to the prior year due to differences in timing of cash proceeds associated with power hedges and coal inventories.
§Debt balances declined by $343 million, primarily due to the use of proceeds from the formation of TransAlta Renewables.
§Comparable earnings were $39 million ($0.15 per share), down slightly from $41 million ($0.18 per share) in 2012. The decrease is primarily due to higher net interest and higher foreign exchange losses, partially offset by an increase in Comparable EBITDA.
§Reported net loss attributable to common shareholders was $9 million ($0.03 net loss per share), down from net earnings of $56 million ($0.24 net earnings per share) in 2012. The change is driven by an increase in comparable gross margins of $3 million and the following non-comparable amounts, net of tax:
§Lower asset impairment reversals of $18 million
§Reversal of inventory writedown of $18 million recorded in 2012
§Decrease in gain on sale of collateral of $11 million
§Increase in impact of Sundance Units 1 and 2 return to service of $6 million
§Increase in impact of write off of deferred income tax assets of $40 million
§Decrease in loss on de-designated hedges of $32 million

 

Year-To-Date Highlights

 

Strategic Highlights

 

§Formation of TransAlta Renewables, creating a vehicle for enhancing TransAlta’s strategy to grow in renewables.
§50 MW long-term contract with the Salt River Project signed by CalEnergy.
§74 MW 20-year long-term power supply contract with the Ontario Power Authority for our Ottawa facility.
§Restart of Sundance Unit 1 in September and Unit 2 in October.
§86 MW long-term contract with the City of Riverside signed by CalEnergy.
§Commercial operation of 68 MW long-term contracted New Richmond wind farm.
§Approval of long-term contract with Puget Sound Energy (“PSE”) at Centralia Thermal.

 

  

TRANSALTA CORPORATION / Q2 2013  2

   

 

 

Operational Financial Results

 

§Renewables: Comparable gross margin increased $58 million to $308 million, primarily as a result of favourable prices and the addition of the New Richmond wind farm, which was partially offset by lower wind and hydro volumes.
§Gas: Comparable gross margin, including finance lease income, increased $43 million to $323 million, primarily due to the addition of the Solomon power station.
§Coal: Comparable gross margin, adjusted for the impact of de-designated hedges decreased $112 million, primarily as a result of lower prices at Centralia Thermal, higher coal costs, and higher unplanned outages at Alberta coal PPA facilities.
§Energy Trading: Comparable gross margin increased $63 million due to strong trading performance across all markets.
§OM&A: Comparable OM&A decreased $5 million to $371 million, primarily due to cost savings from the restructuring undertaken in 2012, partially offset by higher maintenance costs and lower expense recoveries.
§Overall availability, including finance leases and equity investments, was 83.1 per cent compared to 88.1 per cent in 2012. Adjusting for economic dispatching at Centralia Thermal, availability was 86.4 per cent compared to 90.3 per cent in 2012. The decrease is primarily due to higher unplanned outages at the Alberta coal PPA facilities, primarily driven by the Keephills Unit 1 force majeure outage, partially offset by lower planned outages at the Alberta coal PPA facilities.
§Overall production increased 1,972 GWh to 29,842 GWh compared to 2012.

 

Consolidated Highlights

 

§Comparable EBITDA increased $79 million to $780 million compared to 2012.
§FFO decreased $22 million to $550 million compared to 2012 primarily due to differences in timing of cash proceeds associated with power hedges and coal inventories.
§Comparable earnings were $80 million ($0.31 per share), up from $62 million ($0.27 per share) in 2012. The increase in comparable earnings is primarily due to higher gross margins from Renewables, Gas, and Energy Trading.
§Reported net loss attributable to common shareholders were $5 million ($0.02 net loss per share), up from net losses attributable to common shareholders of $654 million ($2.86 net loss per share) in 2012. The change is driven by an increase in comparable gross margins and the following non-comparable amounts, net of tax:
§Decrease in asset impairment charges of $342 million
§Decrease in impact of Sundance Units 1 and 2 return to service of $178 million
§Decrease in impact of write off of deferred income tax assets of $129 million
§Decrease in gain on sale of collateral of $11 million
§Increase in loss on assumption of pension obligations of $22 million due to the assumption of mining operations at the Highvale Mine and related pension obligations for mine employees

 

  

TRANSALTA CORPORATION / Q2 2013  3

   

The following table depicts key financial results and statistical operating data:1

 

    3 months ended Sept. 30 9 months ended Sept. 30
    2013 2012 2013 2012
Availability (%)(1) 85.9 90.9 83.1 88.1
Adjusted availability (%)(1),(2) 85.9 91.7 86.4 90.3
Production (GWh)(1) 11,088 10,155 29,842 27,870
Revenues 623 522 1,705 1,564
Gross margin(3)   363 331 1,057 1,056
Comparable gross margin(4) 374 371 1,117 1,074
Operating income (loss)(3) 118 132 277 (93)
Comparable operating income(4) 125 126 355 302
Net earnings (loss) attributable to common shareholders (9) 56 (5) (654)
Net earnings (loss) per share attributable to common
shareholders, basic and diluted		 (0.03) 0.24 (0.02) (2.86)
Comparable net earnings per share(4) 0.15 0.18 0.31 0.27
Comparable EBITDA(4) 266 255 780 701
Funds from operations(4) 174 233 550 572
Funds from operations per share(4) 0.65 1.00 2.10 2.50
Cash flow from operating activities 253 14 601 275
Free cash flow(4) 49 79 134 55
Dividends paid per common share 0.29 0.29 0.87 0.87

 

As at     Sept. 30, 2013 Dec. 31, 2012
Total assets     9,535 9,462
Total long-term liabilities     4,900 4,729

 

 

AVAILABILITY & PRODUCTION

 

Availability for the three and nine months ended Sept. 30, 2013 decreased compared to the same periods in 2012 primarily due to higher unplanned outages at the Alberta coal PPA facilities, primarily driven by the Keephills Unit 1 force majeure outage, partially offset by lower planned outages at the Alberta coal PPA facilities.

 

([1]) Availability and production includes all generating assets (generation operations, finance leases, and equity investments).

 

(2) Adjusted for economic dispatching at Centralia Thermal.

 

(3) These items are Additional IFRS Measures. Refer to the Additional IFRS Measures section of this MD&A for further discussion of these items.

 

(4) 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 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.

 

  

TRANSALTA CORPORATION / Q2 2013  4

   

Production for the three months ended Sept. 30, 2013 increased 933 GWh compared to the same period in 2012 primarily due to lower economic dispatching at Centralia Thermal, lower planned outages at the Alberta coal PPA facilities, higher PPA customer demand, and lower market curtailments, partially offset by higher unplanned outages at the Alberta coal PPA facilities, primarily driven by the Keephills Unit 1 force majeure outage.

 

For the nine months ended Sept. 30, 2013, production increased 1,972 GWh compared to the same period in 2012 primarily due to lower economic dispatching at Centralia Thermal, lower planned outages at the Alberta coal PPA facilities, higher PPA customer demand, and lower market curtailments, partially offset by higher unplanned outages at the Alberta coal PPA facilities, primarily driven by the Keephills Unit 1 force majeure outage, and higher planned and unplanned outages at Centralia Thermal.

 

 

NET EARNINGs attributable to common shareholders

 

The primary factors contributing to the change in net earnings attributable to common shareholders for the three and nine months ended Sept. 30, 2013 are presented below:

 

  3 months ended Sept. 30 9 months ended Sept. 30
Net earnings (loss) attributable to common shareholders, 2012 56 (654)
Decrease in Generation comparable gross margins (35) (40)
Mark-to-market movements and de-designations
on hedges - Generation		 29 (22)
Increase in Energy Trading gross margins 38 63
(Increase) decrease in operations, maintenance,
and administration costs		 (10) 3
(Increase) decrease in depreciation and amortization expense (2) 8
Increase in gain on sale of assets - 7
Decrease in asset impairment charges (reversal) (23) 342
(Increase) decrease in coal inventory writedown (13) 13
Increase in finance lease income 10 29
Decrease in restructuring provision 1 3
Increase in equity income 2 -
(Decrease) increase in foreign exchange gains (losses) (8) 5
Increase in loss on assumption of pension obligations - (29)
Increase in net interest expense (7) (8)
(Increase) decrease in impact of Sundance Units 1 and 2
return to service		 (8) 239
(Increase) decrease in income tax expense (34) 50
Decrease in net earnings attributable to non-controlling interests 10 9
Increase in preferred share dividends (1) (7)
Decrease in reserve on collateral (15) (15)
Other 1 (1)
Net loss attributable to common shareholders, 2013 (9) (5)

 

Generation comparable gross margins for the three and nine months ended Sept. 30, 2013, excluding the impact of mark-to-market movements on de-designations, decreased by $35 million and $40 million, respectively, compared to the same periods in 2012, as there was lower contract pricing at Centralia Thermal, higher unplanned outages at the Alberta coal PPA facilities, and unfavourable coal pricing at the Alberta PPA coal facilities, partially offset by favourable coal pricing at Centralia Thermal, increased volumes due to lower market curtailments, and lower planned outages at Alberta PPA coal facilities.

 

  

TRANSALTA CORPORATION / Q2 2013  5

   

Mark-to-market movements for the three months ended Sept. 30, 2013 increased compared to the same period in 2012 due to a decrease in losses, primarily resulting from lower contracted volumes. 

 

For the nine months ended Sept. 30, 2013, mark-to-market movements decreased compared to the same period in 2012 due to increased average spot rates relative to the contracted prices, offset by a decrease in contracted volumes. 

 

For the three and nine months ended Sept. 30, 2013, Energy Trading gross margin increased compared to the same periods in 2012 due to strong trading performance across all markets and prudent management of risk.

 

OM&A costs for the three months ended Sept. 30, 2013 increased compared to the same period in 2012 primarily due to higher maintenance costs.

 

For the nine months ended Sept. 30, 2013, OM&A decreased compared to the same period in 2012 primarily due to lower compensation costs as a result of restructuring in the fourth quarter of 2012 and a continued focus on managing costs.

 

Depreciation and amortization expense for the nine months ended Sept. 30, 2013 decreased compared to the same period in 2012 primarily due to a lower depreciable base caused by asset impairments, the change in the economic useful lives of Alberta coal-fired plants resulting from amendments to Canadian federal regulations in 2012, and an increase in asset retirements, partially offset by an increased asset base in our mining and thermal operations and the commencement of commercial operations at our New Richmond wind farm.

 

The increase in the gain on sale of assets in the nine months ended Sept. 30, 2013 compared to the same period in 2012 is due to the sale of land during the second quarter of 2013.

 

Asset impairment reversal for the three months ended Sept. 30, 2013 decreased compared to the same period in 2012 primarily due to the reversal of asset impairment charges recognized on Sundance Units 1 and 2 in 2012 due to the change in the economic useful life of these assets and the recognition of lower reversals in 2013.

 

For the nine months ended Sept. 30, 2013, asset impairment charges decreased compared to the same period in 2012 primarily due to the recognition of asset impairment charges on the Centralia Thermal plant and assets within our renewables fleet in 2012 in order to write these assets down to their fair values and a reversal of asset impairment charges in 2013.

 

Coal inventory has been written down to its net realizable value at our Centralia plant.  The writedown for the three months ended Sept. 30, 2013 is higher compared to the same period in 2012 due to a decrease in the future power prices that will be realized in the period the coal will be consumed.

 

Coal inventory writedown for nine months ended Sept. 30, 2013 is lower compared to the same period in 2012 due to an increase in power prices in the Pacific Northwest.

 

Finance lease income for the three and nine months ended Sept. 30, 2013 increased compared to the same periods in 2012 due to the acquisition of the Solomon Power station. We began receiving lease payments in the fourth quarter of 2012.

 

The restructuring provision for the three and nine months ended Sept. 30, 2013 decreased compared to the same periods in 2012 due to a reversal of the provision as a result of a reduction in our total expected costs.

 

Equity income for the three months ended Sept. 30, 2013 increased compared to the same period in 2012 primarily due to favourable pricing, partially offset by higher planned and unplanned outages at CE Generation, LLC (“CE Gen”).

  

TRANSALTA CORPORATION / Q2 2013  6

   

Foreign exchange gains for the three months ended Sept. 30, 2013 decreased compared to the same period in 2012 primarily due to unfavourable changes in foreign exchange rates as a result of the strengthening U.S. dollar.

 

For the nine months ended Sept. 30, 2013, foreign exchange losses decreased compared to the same period in 2012 due to fluctuations in foreign exchange rates on open foreign denominated financial instruments and translation in relation to foreign subsidiaries.

 

Pension obligations for the nine months ended Sept. 30, 2013 increased compared to the same period in 2012 due to assuming certain pension obligations during the first quarter related to assuming operating and management control of the Highvale Mine.

 

Net interest expense for the three and nine months ended Sept. 30, 2013 increased compared to the same periods in 2013 due to higher debt levels, unfavourable foreign exchange, and higher interest rates.

 

The impact of the Sundance Units 1 and 2 return to service increased during the three months compared to the same period in 2012 due to asset retirements recognized during the third quarter of 2013 partially offset by legal recoveries recognized in the prior year.

 

For the nine months ended Sept. 30, 2013, the impact of the Sundance Units 1 and 2 return to service decreased compared to the same period in 2012 as the result of the arbitration ruling was recorded during the second quarter of 2012.

 

Income tax expense for the three months ended Sept. 30, 2013 increased compared to the same period in 2012 due to the impact of the write off of deferred income tax assets.

 

For the nine months ended Sept. 30, 2013, income tax expense decreased compared to the same period in 2012 due to the income tax effect on non-comparable items that were recorded during the second quarter of 2012.

 

Non-controlling interests for the three and nine months ended Sept. 30, 2013 decreased primarily due to lower earnings at TransAlta Cogeneration, L.P (“TA Cogen”).

 

The preferred share dividends for the three and nine months ended Sept. 30, 2013 increased compared to the same periods in 2012 due to a higher balance of preferred shares outstanding during 2013.

 

In 2012, we sold our claim against MF Global Inc. pertaining to the return of collateral, resulting in a gain.

 

 

Funds from operations AND FREE CASH FLOW

 

FFO for the three and nine months ended Sept. 30, 2013 decreased $59 million and $22 million, respectively, compared to the same periods in 2012 to $174 million and $550 million, respectively, due to lower comparable net earnings after adjusting for differences in timing of cash proceeds associated with power hedges and coal inventories.

 

Free cash flow for the three months ended Sept. 30, 2013 decreased $30 million compared to the same period in 2012 due to lower comparable net earnings partially offset by lower cash dividends paid as a result of increased participation in the Premium DividendTM, Dividend Reinvestment and Optional Common Share Purchase Plan (the “Plan”) and lower sustaining capital expenditures.

 

For the nine months ended Sept. 30, 2013, free cash flow increased $79 million compared to the same period in 2012 due to higher net earnings, lower cash dividends paid, and lower sustaining capital expenditures.

  

TRANSALTA CORPORATION / Q2 2013  7

   

significant Events

 

Three months ended Sept. 30, 2013

 

Salt River Project

 

On Sept. 17, 2013, we announced that CalEnergy, a joint venture with MidAmerican Energy Holdings Company, executed a 50 MW long-term contract for renewable geothermal power with Salt River Project, an Arizona utility, which runs from 2016 to 2039.

 

Ontario Power Authority

 

On Aug. 30, 2013, we announced the execution of a new agreement for a 20-year power supply term with the Ontario Power Authority, for our Ottawa gas facility, which is effective January, 2014.

 

Under the new deal the plant will become dispatchable. This will assist in reducing the incidents of surplus baseload generation in the market, while maintaining the ability of the system to reliably produce energy when it is needed.

 

This new contract will benefit our shareholders by providing long-term stable earnings from this facility and will benefit ratepayers of Ontario by securing attractively priced capacity from this existing facility, reducing the need for new capacity to be built in the future and allowing hospitals in the area to continue to be served with the steam they need for heat and other energy processes, in an environmentally friendly manner. 

 

TransAlta Renewables

 

On May 28, 2013 we formed a new subsidiary, TransAlta Renewables, to provide investors with the opportunity to invest directly in a highly contracted portfolio of renewable power generation facilities.  We retain control over TransAlta Renewables, and therefore we consolidate TransAlta Renewables.  As a result, any loans outstanding or transactions between the Corporation and TransAlta Renewables are eliminated on consolidation in our financial statements. 

 

Transfer of Generating Assets

 

On Aug. 9, 2013, we transferred 28 indirectly owned wind and hydroelectric generating assets to TransAlta Renewables through the sale of all the issued and outstanding shares of two subsidiaries: Canadian Hydro Developers, Inc. and Western Sustainable Power Inc. As consideration for the transfer, we received: i) 66.7 million common shares of TransAlta Renewables valued at $10 per share for total share consideration of $667 million; ii) a Closing Note receivable in the amount of $187 million; iii) a Short Term Note receivable in the amount of $250 million; iv) an Acquisition Note receivable in the amount of $30 million; and v) an Amortizing Loan receivable in the amount of $200 million.

 

Initial Public Offering of Common Shares

 

On July 31, 2013, TransAlta Renewables filed a final prospectus to qualify the distribution of 20.0 million of its common shares, to be issued pursuant to the terms of an Underwriting Agreement at a price of $10.00 per common share (the "Offering"). TransAlta Renewables granted to the underwriters an option (the "Over-Allotment Option"), exercisable in whole or in part for a period of 30 days following Closing, to purchase, at the Offering price, up to an additional 3.0 million common shares (representing 15 per cent of the common shares offered under the prospectus).

 

  

TRANSALTA CORPORATION / Q2 2013  8

   

On Aug. 29, 2013, TransAlta Renewables completed the Offering and issued 20.0 million common shares for gross proceeds of $200 million. TransAlta Renewables used the net proceeds of the Offering to repay the $187 million Closing Note issued to the Corporation. On Aug. 29, 2013, the underwriters exercised their Over-Allotment Option in part to purchase an additional 2.1 million common shares at the offering price of $10.00 per common share for gross proceeds of $21.0 million. TransAlta Renewables used the net proceeds received from the partial exercise of the Over-Allotment Option to repay a portion of the amount outstanding under the Acquisition Note issued to TransAlta. The remaining principal amount of $9.0 million outstanding under the Acquisition Note after such payment has been converted into 0.9 million common shares of TransAlta Renewables on the basis of one common share for each $10.00 owing to the Corporation under the Acquisition Note. After completion of the transactions, we own 92.6 million common shares of TransAlta Renewables, representing an 80.7 per cent ownership interest. In total, we received $207 million in cash consideration net of commissions and expenses.

 

Effective Aug. 9, 2013, the net earnings and Total Comprehensive Income (loss) attributable to the 19.3 per cent divested interest are reflected in Net Earnings (loss) Attributable to Non-controlling Interests and Total Comprehensive Income (loss) Attributable to Non-controlling Interests, respectively, on the Condensed Consolidated Statement of Earnings and on the Condensed Consolidated Statement of Comprehensive Income (Loss), respectively.

 

As at Sept. 30, 2013, the net assets attributable to the 19.3 per cent divested interest are reflected in Equity Attributable to
Non-controlling Interests in the Condensed Consolidated Statement of Financial Position.

 

Asset Impairment Charges and Reversals

 

Renewables

 

During the three and nine months ended Sept. 30, 2013, we recognized a total pre-tax impairment charge of $4 million related to three contracted hydro assets within the renewables fleet.  The assets were impaired primarily due to an increase in future capital and operating expenses that resulted from the completion of condition assessments.  The annual impairment assessments are based on estimates of fair value less costs to sell derived from long range forecasts.  The impairment losses are included in the Generation Segment.

 

Alberta Merchant

 

As part of the annual impairment review and assessment process in 2013, it was determined that our Alberta plants that have significant merchant capacity, should be considered one cash-generating unit (the “Alberta merchant CGU”).  Previously, each plant was assessed for impairment individually. The reasons for this change include consideration of the Final Regulations published by the Canadian federal government in September 2012 governing Greenhouse Gas (“GHG”) emissions and the 50-year total life for Canadian coal-fired power plants; and the refinement of our risk management approach and practices regarding our Alberta wholesale market price exposure. The Final Regulations confirmed additional operating time and increased flexibility for our Alberta coal plants and led, in part, to a broadening of our view on the management of our Alberta wholesale market price exposure. While no impairment losses were recognized in 2013 for the Alberta merchant CGU, total pre-tax impairment losses of $23 million that were recognized previously on renewables plants that now form part of the Alberta merchant CGU were reversed. The Alberta merchant CGU’s recoverable amount was based on an estimate of fair value less costs to sell using a discounted cash flow methodology and based on our long range forecasts and prices evidenced in the market place. The pre-tax reversal is recognized in the Generation Segment.

 

Centralia Thermal

 

The TransAlta Energy Bill and a Memorandum of Agreement was signed on Dec. 23, 2011 that provided a framework for the orderly transition from coal-fired energy produced at Centralia Thermal and the shutdown of the units in 2020 and 2025. On July 25, 2012, we announced that we entered into a long-term power agreement to provide electricity from the Centralia Thermal plant to PSE from December 2014 until the facility is fully retired in 2025.  As a result of these agreements, we recognized a pre-tax impairment charge of nil and $347 million included in the Generation Segment during the three and nine months ended Sept. 30, 2012, respectively.  The impairment assessment was based on whether the carrying amount of the Centralia Thermal plant was recoverable based on an estimate of fair value less costs to sell. 

  

TRANSALTA CORPORATION / Q2 2013  9

   

 

In the third quarter of 2013 and the second quarter of 2012, $40 million and $169 million, respectively, of deferred income tax assets were written off related to the tax benefits of losses associated with our U.S. operations. We wrote these assets off as it was no longer considered probable that sufficient taxable income would be available from our U.S. operations to utilize the underlying tax losses.  An increase in future US income will allow The Corporation to write up our deferred income tax assets in future periods.

 

Reversals

 

The impairment charges can be reversed in future periods if the forecasted cash flows to be generated by the impacted plants improve.

 

Nine months ended Sept. 30, 2013

 

Update on Hydro Facilities Due to Southern Alberta Flooding

 

Following extremely high rainfall and flooding during the second quarter in southern Alberta, we continue to safely and efficiently resolve operational challenges related to our hydro systems. Three of the hydro facilities we operate in Alberta in the Bow River Basin continue to be impacted by the flooding events and are currently being repaired. We have assessed any financial impact through the third quarter and continue to believe that we have sufficient insurance coverage for this damage, subject to a $5 million deductible. 

 

City of Riverside

 

On June 18, 2013, we announced that CalEnergy had executed an 86 MW long-term contract for renewable geothermal power with the City of Riverside which runs from 2016 to 2039. CalEnergy will purchase the power from CE Gen’s portfolio of geothermal generating facilities in California’s Imperial Valley.

 

Sundance Units 1 and 2 Return to Service

 

In December 2010, Units 1 and 2 of our Sundance facility were shut down due to conditions observed in the boilers at both units. On July 20, 2012, an arbitration panel concluded that Unit 1 and Unit 2 were not economically destroyed under the terms of the PPA and we were required to restore the facility to service. For the three and nine months ended Sept. 30, 2012, the pre-tax income statement impact of the ruling that has been recorded under the caption “Sundance Units 1 and 2 return to service” in the Condensed Consolidated Statement of Earnings (loss) was $7 million and $254 million, respectively.

 

During the third quarter of 2013, $15 million of components were retired as a result of the work completed on the Sundance Unit 1 to return it to service. Unit 1 returned to service on Sept. 2, 2013. Sundance Unit 2 was returned to service on Oct. 4, 2013. We have issued notices to the buyers regarding the cessation of the force majeure period for the two units.

 

  

TRANSALTA CORPORATION / Q2 2013  10

   

Premium DividendTM Program

 

On May 8, 2013, we announced that as a result of the current low share price environment, we would suspend the Premium Dividend™ component of the Plan following the payment of the quarterly dividend on July 1, 2013. Our Dividend Reinvestment and Optional Common Share Purchase Plan, separate components of the Plan, remain effective in accordance with their current terms.

 

Keephills Unit 1

 

On March 5, 2013, an outage occurred at Unit 1 of our Keephills facility due to a stator winding failure found in the generator. Upon completion of the initial repair work, further condition testing and analysis identified greater winding degradation requiring a full rewind of the generator stator. In response to the event, we gave notice of a High Impact Low Probability event and claimed force majeure relief under the PPA. In the event of a force majeure, we are entitled to continue to receive our PPA capacity payment and are protected under the terms of the PPA from having to pay availability penalties. As a result, we do not expect the outage to have a material financial impact on the Corporation. The Unit was returned to service on Oct. 6, 2013. Arbitration on the matter began during the quarter.

 

New Richmond

 

On March 13, 2013, our 68 MW New Richmond wind farm began commercial operations. The total cost of the project remains at approximately $212 million. The total estimated spend for New Richmond is less than the amount incurred to date due to estimated recoveries to be received in 2013.

 

SunHills Mining Limited Partnership

 

Effective Jan. 17, 2013, we assumed, through our wholly owned SunHills Mining Limited Partnership (“SunHills”), operations and management control of the Highvale Mine from Prairie Mines and Royalty Ltd. (“PMRL”). PMRL employees working at the Highvale Mine were offered employment by SunHills which agreed to assume responsibility for certain pension plan and pension funding obligations, which we previously funded through the payments made under the PMRL mining contracts. A pre-tax loss of
$29 million was recognized during the first quarter, along with the corresponding liabilities.

We also entered into finance leases for mining equipment that was in use, or committed to, by PMRL in mining operations. As a result, $4 million and $33 million in mining equipment have been capitalized to PP&E and the related finance lease obligations recognized during three and nine months ended Sept. 30, 2013. At the end of the lease term, we are eligible to purchase the assets, for a nominal amount.

 

Change in Estimates - Useful Lives

 

During the first quarter, management completed a comprehensive review of the estimated useful lives of our hydro assets, having regard for, among other things, our economic life cycle maintenance program and the existing condition of the assets. As a result, depreciation was reduced by $2 million and $4 million for the three and nine months ended Sept. 30, 2013, respectively. Pre-tax depreciation expense is expected to be reduced by $5 million for the year ended Dec. 31, 2013 and by $5 million annually thereafter.

 

Centralia Coal Inventory Writedown

 

During the three and nine months ended Sept. 30, 2013, we recognized a pre-tax writedown of $5 million and $21 million, respectively, related to the coal inventory at our Centralia plant to write the inventory down to its net realizable value.

 

  

TRANSALTA CORPORATION / Q2 2013  11

   

Subsequent events

 

Western Australia Contract Extension

 

On Oct. 30, 2013, we announced a long-term contract extension to supply power to the BHP Billiton Nickel West operations in Western Australia from our Southern Cross Energy facilities (“Southern Cross”).  The extension is effective immediately and replaces the previous contract which was set to expire at the beginning of 2014. 

 

Operating since 1996, Southern Cross has a total installed capacity of 245 MW from the Kambalda, Mt. Keith, Leinster, and Kalgoorlie power stations.

 

Acquisition by TransAlta Renewables

 

On Oct. 21, 2013, TransAlta Renewables announced the acquisition, through one of our wholly owned subsidiaries, of an economic interest in a 144 MW wind farm in Wyoming for approximately U.S.$102 million from an affiliate of NextEra Energy Resources, LLC.  The wind farm is fully operational and contracted under a long-term PPA until 2028 with an investment grade counterparty.  At closing, the economic interest in the wind farm will be acquired by TransAlta Renewables from the Corporation in consideration for a payment equal to the original purchase price of the acquisition.  We will extend a U.S.$102 million loan to TransAlta Renewables to fund the acquisition. TransAlta Renewables expects to repay the loan with free cash flow from operations over the first 36 months and through a long-term debt refinancing that is expected to be completed in conjunction with other financing needs of TransAlta Renewables.

 

The acquisition is subject to regulatory approvals and is expected to close by the end of December 2013.

 

The acquisition is expected to be accretive to cash flow per share for both the Corporation and TransAlta Renewables.

 

 

BUSINESS environment

 

We operate in a variety of business environments to generate electricity, find buyers for the power we generate, and arrange for its transmission. The major markets we operate in are Western Canada, the Western United States (“U.S.”), and Eastern Canada. For a further description of the regions in which we operate as well as the impact of prices of electricity and natural gas upon our financial results, refer to our 2012 Annual MD&A.

 

Contracted Cash Flows

 

During the third quarter of 2013, approximately 90 per cent of our consolidated power portfolio was contracted through the use of PPAs and other long-term contracts. We also entered into short-term physical and financial contracts for the remaining volumes, which are primarily for periods of up to five years. The average prices of these contracts for the balance of 2013 are approximately $60 per megawatt hour (“MWh”) in Alberta and approximately U.S.$40 per MWh in the Pacific Northwest.

 

  

TRANSALTA CORPORATION / Q2 2013  12

   

Electricity Prices

 

Please refer to the Business Environment section of our 2012 Annual MD&A for a full discussion of the spot electricity market and the impact of electricity prices on our business, as well as our strategy to hedge our risks associated with changes in these prices.

 

The average spot electricity prices for the three and nine months ended Sept. 30, 2013 and 2012 in our three major markets are shown in the following graphs.

 

 

 

 

 

 

For the three and nine months ended Sept. 30, 2013, average spot prices in Alberta increased compared to the same periods in 2012 primarily due to tighter supply and demand growth. In the Pacific Northwest, average spot prices increased due to higher natural gas prices and lower hydro generation.

 

  

TRANSALTA CORPORATION / Q2 2013  13

   

Average spot prices in Ontario for the three months ended Sept. 30, 2013 decreased compared to the same period in 2012 due to an increase in supply as a result of nuclear generating plants returning to service during the fourth quarter of 2012. For the nine months ended Sept. 30, 2013, average spot prices in Ontario increased compared to 2012 due to higher natural gas prices, which was partially offset by an increase in supply as a result of nuclear generating plants returning to service.

 

Over the balance of 2013, power prices in Alberta are expected to be weaker than 2012 with additional coal-fired generation online. However, prices can vary based on supply and weather conditions. In the Pacific Northwest, we expect prices to be significantly stronger than in 2012; however, we expect that overall prices will still remain relatively weak due to low natural gas prices and slow load growth.

 

Spark Spreads

 

Please refer to the Business Environment section of our 2012 Annual MD&A for a full discussion of spark spreads and the impact of spark spreads on our business.

 

The average spark spreads for the three and nine months ended Sept. 30, 2013 and 2012 in our three major markets are shown in the following graphs.

 

(1) For a 7,000 British Thermal Units per Kilowatt hour heat rate plant.

 

  

TRANSALTA CORPORATION / Q2 2013  14

   

(1) For a 7,000 British Thermal Units per Kilowatt hour heat rate plant.

 

For the three and nine months ended Sept. 30, 2013, average spark spreads increased in Alberta compared to the same periods in 2012 due to higher power prices driven by tighter supply. In the Pacific Northwest, average spark spreads increased due to higher power prices driven by lower hydro generation.

 

For the three months ended Sept. 30, 2013, average spark spreads decreased in Ontario compared to the same period in 2012 due to lower power prices driven by an increase in supply as a result of nuclear generating plants returning to service during the fourth quarter of 2012. Average spark spreads in Ontario decreased for the nine months ended Sept. 30, 2013 compared to the same period in 2012 due to natural gas prices rising faster than power prices.

 

 

  

TRANSALTA CORPORATION / Q2 2013  15

   

GENERATION: TransAlta owns and operates hydro, wind, natural gas-fired and coal-fired facilities, and related mining operations in Canada, the U.S., and Australia. Generation revenues and overall profitability are derived from the availability and production of electricity and steam as well as ancillary services such as system support. For a full listing of all of our generating assets and the regions in which they operate, refer to the Plant Summary section of our 2012 Annual MD&A.

 

Generation Operations: During the first quarter of 2013, we began commercial operations at New Richmond, a 68 MW wind farm in Québec. During the third quarter, we completed the restoration of Sundance Unit 1. At Sept. 30, 2013, our generating assets had 8,553 MW of gross generating capacity(1) in operation (8,211 MW net ownership interest) and 280 MW under restoration in the Sundance Units 1 and 2 major project. The following information excludes assets that are accounted for as a finance lease or using the equity method, which are discussed separately within this discussion of the Generation Segment.

 

The results of Generation Operations are as follows:

 

    2013   2012
3 months ended Sept. 30 Total Comparable
adjustments(2)		 Comparable
total(2)		 Per installed
MWh		   Comparable
total(2)		 Per installed
MWh
Revenues   601 11 612 32.40   598 32.98
Fuel and purchased power 260 - 260 13.77   211 11.64
Gross margin 341 11 352 18.63   387 21.34
Operations, maintenance, and administration 103 (4) 99 5.24   88 4.85
Depreciation and amortization 118 - 118 6.25   117 6.45
Asset impairment reversals (18) 18 - -   - -
Inventory writedown 5 - 5 0.26   - -
Restructuring provision (1) 1 - -   - -
Taxes, other than income taxes 7 - 7 0.37   8 0.44
Intersegment cost allocation 4 - 4 0.21   3 0.17
Operating income 123 (4) 119 6.30   171 9.43
Installed capacity (GWh) 18,886   18,886     18,134  
Production (GWh) 10,606   10,606     9,562  
Availability (%) 85.7   85.7     90.5  
Adjusted availability (%)(3) 85.7   85.7     91.4  

 

 

 

 

(1) We measure capacity as net maximum capacity (see glossary for definition of this and other key terms), which is consistent with industry standards. Capacity figures represent capacity owned and in operation unless otherwise stated.

 

(2) Comparable figures are not defined under IFRS. Refer to the Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to net earnings attributable to common shareholders and cash flow from operating activities.

 

(3) Adjusted for economic dispatching at Centralia Thermal

 

  

TRANSALTA CORPORATION / Q2 2013  16

   

 

    2013   2012
9 months ended Sept. 30 Total Comparable
adjustments		 Comparable
total		 Per installed
MWh		   Comparable
total		 Per installed
MWh
Revenues   1,652 60 1,712 31.24   1,632 30.27
Fuel and purchased power 648 - 648 11.82   528 9.79
Gross margin 1,004 60 1,064 19.42   1,104 20.48
Operations, maintenance, and administration 308 (5) 303 5.53   292 5.42
Depreciation and amortization 365 - 365 6.66   375 6.95
Asset impairment reversals (18) 18 - -   - -
Inventory writedown 21 - 21 0.38   9 0.17
Restructuring provision (2) 2 - -   - -
Taxes, other than income taxes 22 - 22 0.40   22 0.41
Intersegment cost allocation 11 - 11 0.20   10 0.19
Operating income 297 45 342 6.25   396 7.34
Installed capacity (GWh) 54,800   54,800     53,922  
Production (GWh) 28,310   28,310     26,327  
Availability (%) 82.7   82.7     87.7  
Adjusted availability (%) 86.1   86.1     89.9  

 

The outages at Centralia Thermal did not negatively impact our gross margins for nine months ended Sept. 30, 2013 as we were able to extend our planned outages to take advantage of lower market prices to purchase power on the market to fulfill our power contracts. Generation availability, after adjusting for economic dispatching at Centralia Thermal, was 86.1 per cent for the nine months ended Sept. 30, 2013. For the three and nine months ended Sept. 30, 2012, Generation availability, after adjusting for economic dispatching, was 91.4 per cent and 89.9 per cent, respectively.

 

  

TRANSALTA CORPORATION / Q2 2013  17

   

Generation Operations Production and Comparable Gross Margins

 

Production volumes, comparable revenues, fuel and purchased power expenses, and comparable gross margins based on geographical regions and fuel types are presented below.

 

3 months ended Sept. 30, 2013 Production (GWh) Installed (GWh) Comparable revenues Comparable fuel & purchased power Comparable
gross margin		 Comparable revenues per
installed MWh		 Comparable fuel & purchased power per installed MWh Comparable
gross margin per
installed MWh
                 
Coal 5,141 7,710 249 117 132 32.30 15.18 17.12
Gas 691 786 29 6 23 36.90 7.63 29.27
Renewables 842 2,953 67 4 63 22.69 1.35 21.34
Total Western Canada 6,674 11,449 345 127 218 30.13 11.09 19.04
                 
Gas 855 1,656 94 46 48 56.76 27.78 28.98
Renewables 297 1,610 30 2 28 18.63 1.24 17.39
Total Eastern Canada 1,152 3,266 124 48 76 37.97 14.70 23.27
                 
Coal 2,421 2,961 110 72 38 37.15 24.32 12.83
Gas 359 1,210 33 13 20 27.27 10.74 16.53
Total International 2,780 4,171 143 85 58 34.28 20.38 13.90
                 
  10,606 18,886 612 260 352 32.40 13.77 18.63

 

3 months ended Sept. 30, 2012 Production (GWh) Installed (GWh) Comparable revenues Comparable
fuel &
purchased
power		 Comparable gross margin Comparable revenues per
installed MWh		 Comparable fuel
& purchased
power per
installed MWh		 Comparable
gross margin per
installed MWh
                 
Coal 4,985 7,110 270 107 163 37.97 15.05 22.92
Gas 633 786 28 5 23 35.62 6.36 29.26
Renewables 1,051 2,953 67 3 64 22.69 1.02 21.67
Total Western Canada 6,669 10,849 365 115 250 33.64 10.60 23.04
                 
Gas 1,036 1,656 86 41 45 51.93 24.76 27.17
Renewables 260 1,458 25 1 24 17.15 0.69 16.46
Total Eastern Canada 1,296 3,114 111 42 69 35.65 13.49 22.16
                 
Coal 1,242 2,961 95 46 49 32.08 15.54 16.54
Gas 355 1,210 27 8 19 22.31 6.61 15.70
Total International 1,597 4,171 122 54 68 29.25 12.95 16.30
                 
  9,562 18,134 598 211 387 32.98 11.64 21.34

 

  

TRANSALTA CORPORATION / Q2 2013  18

   

 

9 months ended Sept. 30, 2013 Production (GWh) Installed (GWh) Comparable revenues Comparable fuel & purchased power Comparable
gross margin		 Comparable revenues per
installed MWh		 Comparable fuel & purchased power per installed MWh Comparable
gross margin per
installed MWh
                 
Coal 14,925 21,639 664 309 355 30.69 14.28 16.41
Gas 1,921 2,333 97 21 76 41.58 9.00 32.58
Renewables 2,435 8,763 211 11 200 24.08 1.26 22.82
Total Western Canada 19,281 32,735 972 341 631 29.69 10.42 19.27
                 
Gas 2,650 4,913 295 143 152 60.04 29.11 30.93
Renewables 1,119 4,775 113 5 108 23.66 1.05 22.61
Total Eastern Canada 3,769 9,688 408 148 260 42.11 15.28 26.83
                 
Coal 4,231 8,786 233 121 112 26.52 13.77 12.75
Gas 1,029 3,591 99 38 61 27.57 10.58 16.99
Total International 5,260 12,377 332 159 173 26.82 12.85 13.97
                 
  28,310 54,800 1,712 648 1,064 31.24 11.82 19.42

 

 



9 months ended Sept. 30, 2012		 Production (GWh) Installed (GWh) Comparable revenues Comparable
fuel &
purchased
power		 Comparable gross margin Comparable revenues per
installed MWh		 Comparable fuel
& purchased
power per
installed MWh		 Comparable
gross margin per
installed MWh
                 
Coal 14,980 21,086 695 273 422 32.96 12.95 20.01
Gas 1,883 2,342 80 15 65 34.16 6.40 27.76
Renewables 2,737 8,795 162 9 153 18.42 1.02 17.40
Total Western Canada 19,600 32,223 937 297 640 29.08 9.22 19.86
                 
Gas 2,997 4,932 271 121 150 54.95 24.53 30.42
Renewables 1,055 4,344 102 5 97 23.48 1.15 22.33
Total Eastern Canada 4,052 9,276 373 126 247 40.21 13.58 26.63
                 
Coal 1,646 8,819 240 83 157 27.21 9.41 17.80
Gas 1,029 3,604 82 22 60 22.75 6.10 16.65
Total International 2,675 12,423 322 105 217 25.92 8.45 17.47
                 
  26,327 53,922 1,632 528 1,104 30.27 9.79 20.48

 

  

TRANSALTA CORPORATION / Q2 2013  19

   

Western Canada

 

Our Western Canada assets consist of coal, natural gas, hydro, and wind facilities. Refer to the Discussion of Segmented Results section of our 2012 Annual MD&A for further details on our Western Canadian operations.

 

The primary factors contributing to the change in production for the three and nine months ended Sept. 30, 2013 are presented below:

 

    3 months ended
Sept. 30		 9 months ended
Sept. 30
    (GWh) (GWh)  
Production, 2012   6,669 19,600  
Higher unplanned outages at the Alberta coal PPA facilities, primarily driven
by the Keephills Unit 1 force majeure outage		   (1,065) (2,467)  
Lower hydro volumes   (195) (248)  
Lower wind volumes   (13) (54)  
Increased volumes due to lower market curtailments   497 801  
Lower planned outages at the Alberta coal facilities   337 799  
Higher PPA customer demand   391 730  
(Higher) lower unplanned outages at Genesee Unit 3 and Keephills Unit 3   (20) 60  
Higher production at natural gas-fired facilities   58 38  
Other   15 22  
Production, 2013   6,674 19,281  
           

 

The primary factors contributing to the change in comparable gross margin for the three and nine months ended Sept. 30, 2013 are presented below:

 

    3 months ended
Sept. 30		 9 months ended
Sept. 30
Comparable gross margin, 2012   250 640
Pricing, net of unrealized mark-to-market movements and provisions   (28) (35)
Unfavourable coal pricing   (14) (29)
Higher unplanned outages at the Alberta coal PPA facilities, primarily driven
by the Keephills Unit 1 force majeure outage		   (11) (16)
Increased volumes due to lower market curtailments   24 38
Lower planned outages at the Alberta coal facilities   16 35
(Lower) higher hydro margins   (12) 9
(Higher) lower unplanned outages at Genesee Unit 3 and Keephills Unit 3   (2) 2
Other   (5) (13)
Comparable gross margin, 2013   218 631

 

  

TRANSALTA CORPORATION / Q2 2013  20

   

Eastern Canada

 

Our Eastern Canada assets consist of natural gas, hydro, and wind facilities. Refer to the Discussion of Segmented Results section of our 2012 Annual MD&A for further details on our Eastern Canadian operations.

 

The primary factors contributing to the change in production for the three and nine months ended Sept. 30, 2013 are presented below:

 

    3 months ended
Sept. 30		 9 months ended
Sept. 30
    (GWh) (GWh)
Production, 2012   1,296 4,052
Curtailments at natural gas-fired facilities   (242) (355)
Lower wind volumes   (10) (18)
Commencement of commercial operations at New Richmond   33 76
Lower planned and unplanned outages at natural gas-fired facilities   60 8
Higher hydro volumes   13 6
Other   2 -
Production, 2013   1,152 3,769

 

The primary factors contributing to the change in gross margin for the three and nine months ended Sept. 30, 2013 are presented below:

 

    3 months ended
Sept. 30		 9 months ended
Sept. 30
Gross margin, 2012   69 247
Commencement of commercial operations at New Richmond   4 9
Lower wind volumes   (1) (1)
Favourable contracted gas input costs   1 -
Other   3 5
Gross margin, 2013   76 260

 

 

International

 

Our International assets consist of coal, natural gas, and hydro facilities in various locations in the U.S., and natural gas and diesel assets in Australia. Refer to the Discussion of Segmented Results section of our 2012 Annual MD&A for further details on our International operations.

 

The primary factors contributing to the change in production for the three and nine months ended Sept. 30, 2013 are presented below:

 

    3 months ended
Sept. 30		 9 months ended
Sept. 30
    (GWh) (GWh)
Production, 2012   1,597 2,675
Lower economic dispatching at Centralia Thermal   1,038 3,092
Lower (higher) planned and unplanned outages at Centralia Thermal   145 (501)
Other   - (6)
Production, 2013   2,780 5,260

 

  

TRANSALTA CORPORATION / Q2 2013  21

   

The primary factors contributing to the change in comparable gross margin for the three and nine months ended Sept. 30, 2013 are presented below:

 

    3 months ended
Sept. 30		 9 months ended
Sept. 30
Comparable gross margin, 2012   68 217
Lower contract pricing, including margins on purchased power   (30) (90)
Coal pricing(1)   13 35
Higher fuel costs at natural gas-fired facilities   (3) (3)
Costs recovered through revenue at natural gas-fired facilities   2 2
Solomon pass through revenue - offset in OM&A   2 3
Other   6 9
Comparable gross margin, 2013   58 173

 

During the three and nine months ended Sept. 30, 2013, we recognized a pre-tax writedown of $5 million and $21 million, respectively, related to the coal inventory at our Centralia plant to write the inventory down to its net realizable value.

 

Comparable Operations, Maintenance, and Administration Expense

 

Comparable OM&A expense for the three and nine months ended Sept. 30, 2013 increased $11 million and $11 million, respectively, compared to the same periods in 2012, primarily due to higher maintenance costs in the third quarter and lower expense recoveries.

 

Depreciation and Amortization Expense

 

The primary factors contributing to the change in depreciation and amortization expense for the three and nine months ended
Sept. 30, 2013 are presented below:

 

    3 months ended
Sept. 30		 9 months ended
Sept. 30
Depreciation and amortization expense, 2012   117 375
Impact of lower asset base due to asset impairments   - (15)
Change in economic life(1)   - (9)
Decrease in asset retirements   (1) (8)
Change in useful lives of hydro assets   (2) (4)
Increase in asset base   2 19
Other   2 7
Depreciation and amortization expense, 2013   118 365

 

(1) Coal price includes the impact of the inventory writedown which is not included in gross margin.

 

(1) As a result of amendments to Canadian federal regulations requiring that coal-fired plants be shut down after a maximum of 50 years of operation. The previous draft regulations proposed shut down after 45 years. The useful lives of these assets were changed in the third quarter of 2012.

 

 

  

TRANSALTA CORPORATION / Q2 2013  22

   

Finance Leases

 

Solomon

 

On Sept. 28, 2012, we completed the acquisition from Fortescue Metals Group Ltd. (“Fortescue”) of its 125 MW natural gas-fired and diesel-fired Solomon power station in Western Australia for U.S.$318 million. The facility and associated Power Purchase Agreement (“Agreement”) are accounted for as a finance lease and we began receiving payments under the Agreement in the fourth quarter of 2012. The facility is currently under construction and is expected to be commissioned during the fourth quarter of 2013.

 

Fort Saskatchewan

 

Fort Saskatchewan is a natural gas-fired facility with a gross generating capacity of 118 MW in operation, of which TransAlta Cogeneration, L.P. has a 60 per cent ownership interest (35 MW net ownership interest). Key operational information adjusted to reflect our interest in the Fort Saskatchewan facility, which we continue to operate, is summarized below:

 

    3 months ended Sept. 30 9 months ended Sept. 30
    2013 2012 2013 2012
Availability (%)   81.7 92.1 93.7 88.1
Production (GWh) 104 113 368 332

 

Availability for the three months ended Sept. 30, 2013 decreased compared to the same period in 2012 due to higher planned outages, partially offset by lower unplanned outages.

 

For the nine months ended Sept. 30, 2013, availability increased compared to the same period in 2012 due to lower planned and unplanned outages.

 

Production for the three months ended Sept. 30, 2013 decreased compared to the same period in 2012 due to higher planned outages, partially offset by lower unplanned outages and increased customer demand.

 

For the nine months ended Sept. 30, 2013, production increased compared to the same period in 2012 due to lower planned and unplanned outages and increased customer demand.

 

Total Finance Lease Income

 

Total finance lease income for the three and nine months ended Sept. 30, 2013 increased $10 million and $29 million, respectively, compared to the same periods in 2012 due to the payments we began receiving in October 2012 under the Agreement with Fortescue.

 

  

TRANSALTA CORPORATION / Q2 2013  23

   

Equity Investments

 

Our investments in joint ventures are accounted for using the equity method and consist of our investments in CE Gen, Wailuku River Hydroelectric, L.P, TAMA Transmission, and CalEnergy.

 

Our interests in the CE Gen and Wailuku River Hydroelectric, L.P. joint ventures are comprised of geothermal, natural gas, and hydro facilities in various locations throughout the U.S., with 839 MW of gross generating capacity (390 MW net ownership interest). The table below summarizes key operational information adjusted to reflect our interest in these investments:

 

    3 months ended Sept. 30 9 months ended Sept. 30
    2013 2012 2013 2012
Availability (%)   91.5 96.8 90.1 94.3
Production (GWh)        
Gas   93 155 301 290
Renewables 285 325 863 921
Total production 378 480 1,164 1,211

 

Availability for the three and nine months ended Sept. 30, 2013 decreased compared to the same periods in 2012 due to higher unplanned outages.

 

For the nine months ended Sept. 30, 2013, availability decreased compared to the same periods in 2012 due to higher planned and unplanned outages.

 

Production for the three months ended Sept. 30, 2013 decreased compared to the same period in 2012 due to higher unplanned outages and lower customer demand.

 

For the nine months ended Sept. 30, 2013, production decreased compared to the same period in 2012 due to higher planned and unplanned outages, partially offset by higher customer demand.

 

Equity income for the three months ended Sept. 30, 2013 was $2 million compared to nil for the same period in 2012. The increase is primarily due to favourable pricing, partially offset by higher unplanned outages.

 

For the nine months ended Sept. 30, 2013, equity loss was comparable to the same period in 2012.

 

Since 2001, a significant portion of the CE Gen plants have been operating under modified fixed energy price contracts.  Commencing May 1, 2012, the terms of the contracts reverted to a pricing clause that permits the power purchaser to pay their short-run avoided costs (“SRAC”) as the price for power.  The SRAC is linked to the price of natural gas.  There can be no assurances that prices based on the avoided cost of energy after May 1, 2012 will result in revenues equivalent to those realized under the fixed energy price structure.

 

On Sept. 17, 2013, we announced that CalEnergy, a joint venture with MidAmerican Energy Holdings Company, executed a 50 MW long-term contract for renewable geothermal power with Salt River Project, an Arizona utility, which runs from 2016 to 2039.

 

On June 18, 2013, we also announced that CalEnergy had executed an 86 MW long-term contract for renewable geothermal power with the City of Riverside which runs from 2016 to 2039. CalEnergy will purchase the power from CE Gen’s portfolio of geothermal generating facilities in California’s Imperial Valley.

 

  

TRANSALTA CORPORATION / Q2 2013  24

   

ENERGY TRADING: Derives revenue and earnings from the wholesale trading of electricity and other energy-related commodities and derivatives. Achieving gross margins, while remaining within Value at Risk (“VaR”) limits, is a key measure of Energy Trading’s activities. Refer to the Value at Risk and Trading Positions discussion in the Risk Management section of our 2012 Annual MD&A for further discussion on VaR.

 

Energy Trading utilizes contracts of various durations for the forward purchase and sale of electricity and for the purchase and sale of natural gas and transmission capacity. If the activities are performed on behalf of the Generation Segment, the results of these activities are included in the Generation Segment.

 

For a more in-depth discussion of our Energy Trading activities, refer to the Discussion of Segmented Results section of our 2012 Annual MD&A.

 

The results of the Energy Trading Segment, with all trading results presented on a net basis, are as follows:

 

  3 months ended Sept. 30 9 months ended Sept. 30
  2013 2012 2013 2012
Revenues 22 (16) 53 (10)
Fuel and purchased power - - - -
Gross margin 22 (16) 53 (10)
Operations, maintenance, and administration 9 7 23 21
Intersegment cost allocation (4) (3) (11) (10)
Operating income (loss) 17 (20) 41 (21)

 

For the three and nine months ended Sept. 30, 2013, Energy Trading gross margins increased compared to the same periods in 2012 due to strong trading performance across all markets and prudent management of risk.

 

OM&A expense for the three and nine months ended Sept. 30, 2013 was comparable to the same periods in 2012.

 

 

CORPORATE: Our Generation and Energy Trading Segments are supported by a Corporate group that provides finance, tax, treasury, legal, regulatory, environmental, health and safety, sustainable development, corporate communications, government and investor relations, information technology, risk management, human resources, internal audit, and other administrative support.

 

The expenses incurred by the Corporate Segment are as follows:

 

  3 months ended Sept. 30   9 months ended Sept. 30
  2013 Comparable adjustments Comparable total 2012   2013 Comparable adjustments Comparable total 2012
Operations, maintenance, and administration 16 - 16 21   45 - 45 63
Depreciation and amortization 6 - 6 5   17 - 17 15
Restructuring provision - - - -   (1) 1 - -
Operating loss 22 - 22 26   61 1 62 78

 

OM&A expense for the three and nine months ended Sept. 30, 2013 decreased compared to the same periods in 2012 primarily due to lower compensation costs as a result of restructuring in the fourth quarter of 2012 and a continued focus on managing costs.

 

 

  

TRANSALTA CORPORATION / Q2 2013  25

   

NET INTEREST EXPENSE

 

The components of net interest expense are shown below:

 

    3 months ended Sept. 30 9 months ended Sept. 30
    2013 2012 2013 2012
Interest on debt   61 54 179 168
Capitalized interest   - (1) (2) (2)
Ineffectiveness on hedges   - - - 2
Interest expense   61 53 177 168
Accretion of provisions   4 5 13 14
Net interest expense   65 58 190 182

 

The change in net interest expense for the three and nine months ended Sept. 30, 2013, compared to the same periods in 2012, is shown below:

 

        3 months ended
Sept. 30		 9 months ended
Sept. 30
Net interest expense, 2012       58 182
Higher debt levels       2 5
Unfavourable foreign exchange impacts     2 3
Higher financing costs       1 2
Higher interest rates     2 1
Lower capitalized interest       1 -
Lower ineffectiveness on hedges     - (2)
Lower accretion       (1) (1)
Net interest expense, 2013       65 190

 

 

 

 

  

TRANSALTA CORPORATION / Q2 2013  26

   

INCOME TAXES

 

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

 

    3 months ended Sept. 30 9 months ended Sept. 30
    2013 2012 2013 2012
Earnings (loss) before income taxes   45 85 80 (517)
(Income) loss attributable to non-controlling interests   3 (7) (16) (25)
Equity (income) loss   (2) - 5 5
Impacts associated with certain de-designated and
ineffective hedges		   11 60 60 58
Asset impairment charges (reversal)   (18) (41) (18) 324
Inventory writedown (reversal)   - (28) - 5
Restructuring provision   (1) - (3) -
Gain on sale of assets   - - (10) (3)
Sundance Units 1 and 2 return to service   15 7 15 254
Gain on sale of collateral   - (15) - (15)
Loss on assumption of pension obligations   - - 29 -
Other non-comparable items   4 2 5 3
Earnings attributable to TransAlta shareholders,
excluding non-comparable items, subject to tax		   57 63 147 89
Income tax expense   48 14 41 91
Income tax recovery related to impacts associated with
certain de-designated and ineffective hedges		   4 21 21 20
Income tax expense related to asset impairment charges
(reversals)		   (5) (10) (5) (5)
Income tax recovery (expense) related to inventory
writedown (reversal)		   - (10) - 2
Income tax expense related to restructuring provision   (1) - (1) -
Income tax expense related to gain on sale of assets   - - (1) (1)
Income tax recovery related to Sundance Units 1 and 2
return to service		   4 2 4 65
Income tax expense related to gain on sale of collateral   - (4) - (4)
Income tax expense related to write off of deferred
income tax assets		   (40) - (40) (169)
Income tax recovery related to deferred tax rate adjustment   - - 7 -
Income tax recovery related to the resolution of certain
outstanding tax matters		   - - - 9
Income tax expense related to changes in corporate
income tax rates		   - - - (8)
Income tax recovery related to loss on assumption of
pension obligations		   - - 7 -
Income tax recovery related to other non-comparable items   1 1 1 1
Income tax expense excluding non-comparable items   11 14 34 1
Effective tax rate on earnings attributable to TransAlta
shareholders excluding non-comparable items (%)		   19 22 23 1

 

The income tax expense excluding non-comparable items for the three months ended Sept. 30, 2013 decreased compared to the same period in 2012 due to lower comparable earnings.

 

  

TRANSALTA CORPORATION / Q2 2013  27

   

The income tax expense excluding non-comparable items for the nine months ended Sept. 30, 2013 increased compared to the same period in 2012 due to higher comparable earnings and the positive resolution of certain tax contingency matters in the prior period.

 

The effective tax rate on earnings attributable to TransAlta shareholders excluding non-comparable items for the three months ended Sept. 30, 2013 decreased compared to the same period in 2012 due to changes in the amount of earnings between the jurisdictions in which pre-tax income is earned and the effect of certain deductions that do not fluctuate with earnings.

 

For the nine months ended Sept. 30, 2013, the effective tax rate on earnings attributable to TransAlta shareholders excluding
non-comparable items increased compared to the same period in 2012 due to changes in the amount of earnings between the jurisdictions in which pre-tax income is earned, the effect of certain deductions that do not fluctuate with earnings, and due to the positive resolution of certain tax contingency matters in the prior period.

 

 

 

NON-CONTROLLING INTERESTS

 

Net earnings attributable to non-controlling interests for the three and nine months ended Sept. 30, 2013 decreased $10 million and $9 million, respectively, compared to the same periods in 2012, primarily due to lower earnings at TA Cogen.

 

 

  

TRANSALTA CORPORATION / Q2 2013  28

   

financial position

 

The following chart highlights significant changes in the Condensed Consolidated Statements of Financial Position from
Dec. 31, 2012 to Sept. 30, 2013:

 

  Increase/    
  (Decrease)   Primary factors explaining change
Cash and cash equivalents 28   Timing of receipts and payments
Accounts receivable (140)   Timing of customer receipts
Prepaid expenses 17   Prepayment of annual insurance premiums, royalties, and service agreements
Inventory 10   Increase in overburden removal activity, and higher average coal costs partially offset by writedown of coal inventory
Investments 11   Additions to equity investments
Property, plant, and equipment, net 94   Additions partially offset by depreciation
Risk management assets (current and long-term) 33   Price movements and changes in underlying positions and settlements
Accounts payable and accrued liabilities (42)   Timing of payments and lower capital accruals
Long-term debt (including current portion) (100)   Use of net proceeds received on sale of the non-controlling interest in TransAlta Renewables to pay down borrowings on our credit facility
Finance lease obligation (including current portion) 26   Finance lease for mining equipment at the Highvale Mine
Deferred credits and other long-term liabilities (21)   Decrease in defined benefit accrual
Deferred income tax liabilities (15)   Net deferred income tax recovery
Risk management liabilities (current and long-term) 96   Price movements and changes in underlying positions and settlements
Equity attributable to shareholders (68)   Share dividends partially offset by issuance of common shares and net earnings for the period
Non-controlling interests 184   Sale of the non-controlling interest in TransAlta Renewables, partially offset by non-controlling interests' portion of net earnings net of distributions to non-controlling interests

 

 

financial instruments

 

Refer to Note 16 of the notes to the audited consolidated financial statements within our 2012 Annual Report and Note 15 of our interim condensed consolidated financial statements as at and for the three and nine months ended Sept. 30, 2013 for details on Financial Instruments. Refer to the Risk Management section of our 2012 Annual Report and Note 16 of our 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, 2012.

 

Energy Trading may enter into commodity transactions involving non-standard features for which market observable 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.

  

TRANSALTA CORPORATION / Q2 2013  29

   

We also have various contracts with terms that extend beyond five years.  As forward market prices are not available for the full period of these contracts, the value of these contracts must be derived by reference to a forecast that is based on a combination of external and internal fundamental modeling, including discounting.  As a result, these contracts are classified in Level III. These contracts are for specified prices with counterparties that we believe to be creditworthy.

 

At Sept. 30, 2013, total Level III financial instruments had a net liability carrying value of $41 million (Dec. 31, 2012 - $31 million net asset).

 

Certain of our hedging relationships had previously been de-designated and deemed ineffective for accounting purposes.  The hedges were in respect of power production and the associated gains remain in AOCI until the underlying production occurs or until such time that the production has been assessed as highly probable not to occur.  No gains related to these previously de-designated hedges were reclassified to earnings during the three and nine months ended Sept. 30, 2013 (Sept. 30, 2012 - nil and $75 million pre-tax gain, respectively).

 

As at Sept. 30, 2013, cumulative gains of $4 million, related to these and other cash flow hedges that were de-designated and no longer meet the criteria for hedge accounting, continued to be deferred in AOCI and will be reclassified to net earnings as the forecasted transactions occur or if the forecasted transactions are assessed as highly probable not to occur. 

 

 

  

TRANSALTA CORPORATION / Q2 2013  30

   

STATEMENTS OF CASH FLOWS

 

The following charts highlight significant changes in the Condensed Consolidated Statements of Cash Flows for the three and nine months ended Sept. 30, 2013 compared to the same periods in 2012:

 

3 months ended Sept. 30 2013 2012 Primary factors explaining change
Cash and cash equivalents, beginning
of period		 67 61  
Provided by (used in):      
Operating activities 253 14 Favourable changes in working capital of $296 million partially offset by lower cash earnings of $57 million
       
Investing activities (150) (483) Decrease in acquisition of finance lease of $312 million, an increase in investing non-cash working capital balances of $20 million, a decrease in additions to PP&E and intangibles of $14 million, an increase on proceeds on disposal of PP&E of $10 million, partially offset by a decrease in the resolution of certain tax matters of $9 million, net negative impact of $8 million related to changes in collateral received from or paid to counterparties, and a decrease in realized gains on financial instruments of $5 million
       
Financing activities (115) 478 Decrease in borrowings under credit facilities of $600 million partially due to the use of net proceeds received from the sale of the non-controlling interest in TransAlta Renewables to pay down borrowings on our credit facility, a decrease in proceeds on issuance of common shares of $292 million, a decrease in proceeds on issuance of preferred shares of $217 million, and a decrease in realized gains on financial instruments of $10 million, partially offset by a decrease in long-term debt payments of $304 million, an increase in proceeds on sale of non-controlling interest in subsidiary of $207 million, and a decrease in common share cash dividends of $17 million
Translation of foreign currency cash - 1  
Cash and cash equivalents, end of period 55 71  

 

  

TRANSALTA CORPORATION / Q2 2013  31

   

 

9 months ended Sept. 30 2013 2012 Primary factors explaining change
Cash and cash equivalents, beginning
of period		 27 49  
Provided by (used in):      
Operating activities 601 275 Favourable changes in working capital of $358 million, net of a $204 million impact associated with the Sundance Units 1 and 2 arbitration in 2012, partially offset by lower cash earnings of $32 million
       
Investing activities (460) (822) Decrease in acquisition of finance lease of $312 million, a decrease in additions to PP&E and intangibles of $49 million, an increase in realized gains on financial instruments of $17 million, and an increase in proceeds on sale of PP&E of $11 million, partially offset by a net negative impact of $14 million related to changes in collateral received from or paid to counterparties, an increase in equity investments of $10 million, and a decrease in the resolution of certain tax matters of $9 million
       
Financing activities (113) 568 Decrease in borrowings under credit facilities of $684 million partially due to the use of net proceeds received from the sale of the non-controlling interest in TransAlta Renewables to pay down borrowings on our credit facility, a decrease in proceeds on issuance of common shares of $293 million, a decrease in proceeds on issuance of preferred shares of $217 million, and a decrease in realized gains on financial instruments of $10 million, partially offset by a decrease in long-term debt payments of $304 million and an increase in proceeds on sale of non-controlling interest in subsidiary of $207 million, and a decrease in common share cash dividends of $22 million due to dividends reinvested through the dividend reinvestment plan
Translation of foreign currency cash - 1  
Cash and cash equivalents, end of period 55 71  

 

 

Liquidity and Capital Resources

 

Liquidity risk arises from our ability to meet general funding needs, engage in trading and hedging activities, and manage the assets, liabilities, and capital structure of the Corporation. Liquidity risk is managed by maintaining sufficient liquid financial resources to fund obligations as they come due in the most cost-effective manner.

 

Our liquidity needs are met through a variety of sources, including cash generated from operations, borrowings under our long-term credit facilities, and long-term debt or equity issued under our Canadian and U.S. shelf registrations. Our primary uses of funds are operational expenses, capital expenditures, dividends, distributions to non-controlling limited partners, and interest and principal payments on debt securities.

 

  

TRANSALTA CORPORATION / Q2 2013  32

   

Debt

 

Long-term debt totalled $4.1 billion as at Sept. 30, 2013 compared to $4.2 billion as at Dec. 31, 2012. Long-term debt decreased from Dec. 31, 2012 primarily due to the use of net proceeds received from the sale of the non-controlling interest in TransAlta Renewables to pay down borrowings on our the credit facility.

Credit Facilities

 

At Sept. 30, 2013, we had a total of $2.1 billion (Dec. 31, 2012 - $2.0 billion) of committed credit facilities, of which $1.0 billion (Dec. 31, 2012 - $0.8 billion) is not drawn and is available, subject to customary borrowing conditions. At Sept. 30, 2013, the $1.1 billion (Dec. 31, 2012 - $1.3 billion) of credit utilized under these facilities was comprised of actual drawings of $0.8 billion (Dec. 31, 2012 - $1.0 billion) and letters of credit of $0.3 billion (Dec. 31, 2012 - $0.3 billion). These facilities are comprised of a $1.5 billion committed syndicated bank facility that matures in 2017, with the remainder comprised of bilateral credit facilities, of which $0.3 billion matures in 2017 and $0.2 billion matures in the fourth quarter of 2014. We anticipate renewing these facilities, based on reasonable commercial terms, prior to their maturities.

 

In addition to the $1.0 billion available under the credit facilities, we have $52 million of available cash.

 

Share Capital

 

On Oct. 30, 2013, we had 268.2 million common shares outstanding, 12.0 million Series A, 11.0 million Series C, and 9.0 million Series E first preferred shares outstanding.  At Sept. 30, 2013, we had 266.3 million (Dec. 31, 2012 - 254.7 million) common shares issued and outstanding. At Sept. 30, 2013, we also had 32.0 million (Dec. 31, 2012 - 32.0 million) preferred shares issued and outstanding.

 

We issue common shares for cash proceeds, on exercise of stock options and other share-based payment plans, or for reinvestment of dividends.  During February 2012, we added a Premium DividendTM component to the Plan. Please refer to Note 28 of our audited consolidated financial statements within our 2012 Annual Report for additional information regarding the amendments. On May 8, 2013, we announced that as a result of the current low share price environment, we would suspend the Premium Dividend™ component of the Plan following the payment of the quarterly dividend on July 1, 2013. Our Dividend Reinvestment and Optional Common Share Purchase Plan, separate components of the Plan, remain effective in accordance with their current terms.

 

During the three months ended Sept. 30, 2013, 4.2 million common shares were issued for $55 million, which was primarily comprised of dividends reinvested under the terms of the Plan. During the three months ended Sept. 30, 2012, 24.1 million common shares were issued for $343 million, which was primarily comprised of common shares issued under a public offering and dividends reinvested under the terms of the Plan. During the nine months ended Sept. 30, 2013, 11.6 million common shares were issued for $161 million, which was primarily comprised of dividends reinvested under the terms of the Plan. During the nine months ended Sept. 30, 2012, 27.5 million common shares were issued for $407 million, which was primarily comprised of common shares issued under a public offering and dividends reinvested under the terms of the Plan.

 

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, energy trading activities, hedging activities, and purchase obligations. At Sept. 30, 2013, we provided letters of credit totalling $348 million (Dec. 31, 2012 - $336 million) and cash collateral of $19 million (Dec. 31, 2012 - $19 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.

  

TRANSALTA CORPORATION / Q2 2013  33

   

Commitments

 

During March 2013, the New Richmond wind farm commenced operations and as such, the 15 year long-term service agreement for repairs and maintenance became effective.  The future payments over the term of the agreement are approximately $42 million. 

 

 

climate change and the environment

 

In Alberta, there are requirements for coal-fired generation units to implement additional air emission controls for oxides of nitrogen (“NOx”), sulphur dioxide (“SO2”), and particulate matter, once they reach the end of their respective PPAs, in most cases at 2020.  These regulatory requirements were developed by the province in 2004 as a result of multi-stakeholder discussions under Alberta’s Clean Air Strategic Alliance (“CASA”).  However, the release of the federal GHG regulations may create a potential misalignment between the CASA air pollutant requirements and schedules, and the GHG retirement schedules for older coal plants, which in themselves will result in significant reductions of NOx, SO2, and particulates.  We are in discussions with the provincial government to ensure coordination between GHG and air pollutant regulations, such that emission reduction objectives are achieved in the most effective manner while taking into consideration the reliability and cost of Alberta’s generation supply.

 

In the U.S., on June 25, 2013, President Obama announced his Climate Action Plan, which sets out plans for GHG emission standards to be imposed by the Environmental Protection Agency (“EPA”) for new and existing power plants.  Subsequently, on Sept. 20, 2013, the EPA issued draft regulations for new coal-fired plants which, if adopted, would require new coal plants to achieve GHG emissions of no more than 1,100 pounds per MWh of carbon dioxide (significantly below current average emissions for coal-fired plants) in order to be approved.  These regulations are expected to be finalized by mid-2014.  These proposed regulations do not currently have an impact on our operations.  Standards for existing units are to be finalized by June 2015.  State implementation plans are to be completed a year later.  There will be few additional details as to how existing coal (and potentially natural gas) units might be treated until the EPA releases a draft rule.  Furthermore, the U.S. Supreme Court has agreed to review a challenge to the EPA’s right to regulate GHG emissions from stationary sources like power plants, so the future of this regulation is uncertain.

 

In December 2011, the EPA issued national standards for mercury emissions from power plants. Existing sources will have up to four years to comply. We have already voluntarily installed mercury capture technology at our Centralia coal-fired plant, and began full capture operations in early 2012. We have also installed additional technology to further reduce NOx, consistent with the Washington State Bill passed in April 2011.

 

We continue to make operational improvements and investments to our existing generating facilities to reduce the environmental impact of generating electricity. We installed mercury control equipment at our Alberta Thermal operations in 2010 in order to meet the province’s 70 per cent reduction objectives, and voluntarily at our Centralia coal-fired plant in 2012. Our Keephills Unit 3 plant began operations in September 2011 using supercritical combustion technology to maximize thermal efficiency, as well as SO2 capture and low NOx combustion technology, which is consistent with the technology that is currently in use at Genesee Unit 3. Uprate projects completed at our Keephills and Sundance plants have improved the energy and emissions efficiency of those units.

 

 

  

TRANSALTA CORPORATION / Q2 2013  34

   

2013 Outlook

 

Business Environment

 

Power Prices

 

Over the balance of 2013, power prices in Alberta are expected to be weaker than 2012 with additional coal-fired generation online. However, prices can vary based on supply and weather conditions. In the Pacific Northwest, we expect prices to be significantly stronger than in 2012; however, we expect that overall prices will still remain relatively weak due to low natural gas prices and slow load growth.

 

Environmental Legislation

 

The finalization of the federal Canadian GHG regulations for coal-fired power has initiated further activities. We are in discussions with the provincial government to ensure coordination between GHG and air pollutant regulations, such that emission reduction objectives are achieved in the most effective manner while taking into consideration the reliability and cost of Alberta’s generation supply. This may provide additional flexibility to coal-fired generators in meeting the regulatory requirements. For further information on the Canadian GHG regulations, please refer to the Significant Events section of our 2012 Annual MD&A.

 

In addition, there are ongoing discussions between the federal and provincial governments regarding a national Air Quality Management System for air pollutants. In Alberta’s recently released Clean Air Strategy, the province indicated that its provincial air quality management system will operationalize any national system. Our current outlook is that, for Alberta, provincial regulations will be considered as equivalent to any future national framework.

 

On Jan. 21, 2013, the Ontario government released a discussion paper for public input on reducing GHG emissions in the province, with the stated intent of developing GHG regulations for all major industrial sectors by 2015. No specific targets or regulatory approaches have yet been proposed.

 

In the U.S., the President’s Climate Action Plan provides an indication of how GHG regulation of existing fossil-fuel based generation may unfold, although we expect the implementation process to take several years. Our agreement with Washington State, established in April 2011, provides regulatory clarity at the state level regarding an emissions regime related to the Centralia Coal plant until 2025. We expect this agreement may mitigate separate federal action from the EPA. Additionally, new federal air pollutant regulations for the power sector are anticipated, but are not expected to directly affect our coal-fired operations in Washington State.

 

Beginning in 2013, direct deliveries of power to the California Independent System Operator are subject to a compliance obligation established by the California Air Resources Board’s (“CARB”) cap and trade program.  As CARB continues to finalize their regulations, we will stay at the forefront of regulatory changes to enable us to remain in compliance with the cap and trade program.

 

In Australia, the carbon tax implemented in July 2012 remains in place.  However, the new Australian government elected on
Sept. 7, 2013 has indicated its intention to repeal the tax on or before July, 2014. There is no clear indication at this point if the government plans to implement a different climate change regulation. While TransAlta’s gas-fired operations are subject to the tax, all related costs are flowed to contracted customers.

 

We continue to closely monitor the progress and risks associated with environmental legislation changes on our future operations.

 

  

TRANSALTA CORPORATION / Q2 2013  35

   

The siting, construction, and operation of electrical energy facilities requires interaction with many stakeholders. Recently, certain stakeholders have brought actions against government agencies and owners over alleged adverse impacts of wind projects. We are monitoring these claims in order to assess the risk associated with these activities.

 

Economic Environment

 

In 2013, we expect slow to moderate growth in Alberta and Australia, and low growth in other markets. We continue to monitor global events and their potential impact on the economy and our supplier and commodity counterparty relationships.

 

We had no material counterparty losses in the third quarter of 2013. We continue to monitor counterparty credit risk and have established risk management policies to mitigate counterparty risk. We do not anticipate any material change to our existing credit practices and continue to deal primarily with investment grade counterparties.

 

Operations

 

Capacity, Production, and Availability

 

Generating capacity is expected to increase for the remainder of 2013 due to Sundance Unit 2 returning to service. Prior to the effect of any economic dispatching, overall production is expected to increase for the remainder 2013 due to lower planned outages, Sundance Units 1 and 2 returning to service, and the completion of the New Richmond wind farm. Adjusted availability, excluding the extended outages at Centralia Thermal due to economic dispatching, is expected to be in the range of 87 to 89 per cent in 2013 due to the impact of the Keephills Unit 1 force majeure outage.

 

On Dec. 16, 2010 and Dec. 19, 2010, Unit 1 and Unit 2, respectively, of our Sundance facility were shut down due to conditions observed in the boilers at both units. On Feb. 8, 2011, we issued a notice of termination for destruction based on the determination that the units could not be economically restored to service under the terms of the PPA. On July 20, 2012, an arbitration panel concluded that Units 1 and 2 were not economically destroyed under the terms of the PPA and required the units to be restored to service. However, the panel affirmed that the event met the criteria of force majeure beginning Nov. 20, 2011 and continuing until such a time as each unit is returned to service.  The cost to repair Sundance Units 1 and 2 is estimated at approximately $215 million. Sundance Unit 1 returned to service on Sept. 2, 2013 and Sundance Unit 2 returned to service on Oct. 4, 2013. The total estimated spend has increased by $25 million due to additional scope of work for balance of plant systems and equipment as well as higher labour costs due to an increase in rates.  This work was performed concurrently with the boiler repairs to prevent the need for a later outage for this work.  We have issued notices to the buyers regarding the cessation of the force majeure period for the two units.

 

Contracted Cash Flows

 

Through the use of Alberta PPAs, long-term contracts, and other short-term physical and financial contracts, on average, approximately 75 per cent of our capacity is contracted over the next seven years. 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 third quarter of 2013, approximately 89 per cent of our 2013 capacity was contracted. The average prices of our short-term physical and financial contracts for the balance of 2013 are approximately $60 per MWh in Alberta and approximately U.S.$40 per MWh in the Pacific Northwest.

 

  

TRANSALTA CORPORATION / Q2 2013  36

   

Fuel Costs

 

Coal costs for 2013, on a standard cost per tonne basis, are expected to be 11 to 13 per cent higher than 2012. Mining coal in Alberta is subject to cost increases due to greater overburden removal, inflation, capital investments, and commodity prices. Seasonal variations in coal costs at our Alberta mine are minimized through the application of standard costing. In January 2013, we assumed, through SunHills, operating and management control of the Highvale Mine from PMRL.

 

Although we own the Centralia mine in the State of Washington, it is not currently operational. Fuel at Centralia Thermal is purchased from external suppliers in the Powder River Basin and delivered by rail. The delivered cost of fuel per MWh for 2013 is expected to decrease between six to eight per cent.

 

The value of coal inventories is assessed for impairment at the end of each reporting period. If the inventory is impaired, further charges will be recognized in net earnings. For more information on the inventory impairment charges recorded in 2013, please refer to the Significant Events section of this MD&A.

 

We purchase natural gas from outside companies coincident with production or have it supplied by our customers, thereby minimizing our risk to changes in prices. The continued success of unconventional gas production in North America could reduce the year-to-year volatility of prices in the near term.

 

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.

 

Operations, Maintenance, and Administration Costs

 

OM&A costs for 2013 are expected to be consistent with 2012 due to costs savings from our organizational restructuring offset by additional costs as Sundance Units 1 and 2 are returned to service, flood recovery costs, and the commencement of operations at New Richmond. 

 

Energy Trading

 

Earnings from our Energy Trading Segment are affected by prices in the market, overall strategies adopted, and changes in legislation. We continuously monitor both the market and our exposure in order to maximize earnings while still maintaining an acceptable risk profile.  Our target was for Energy Trading to contribute between $40 million and $60 million in gross margin for 2013. Given strong performance thus far in the year, our current target has been increased to the $45 million to $65 million range.

 

Exposure to Fluctuations in Foreign Currencies

 

Our strategy is to minimize the impact of fluctuations in the Canadian dollar against the U.S. dollar, Euro, 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 2013 is expected to increase compared to 2012 due to lower capitalized interest. However, changes in interest rates and in the value of the Canadian dollar relative to the U.S. dollar can affect the amount of net interest expense incurred.

 

  

TRANSALTA CORPORATION / Q2 2013  37

   

Liquidity and Capital Resources

 

If there is increased volatility in power and natural gas markets, or if market trading activities increase, we may need additional liquidity in the future. We expect to maintain adequate available liquidity under our committed credit facilities.

 

Accounting Estimates

 

A number of our accounting estimates, including those outlined in the Critical Accounting Policies and Estimates section of our 2012 Annual MD&A, are based on the current economic environment and outlook. As a result of the current economic environment, market fluctuations could impact, among other things, future commodity prices, foreign exchange rates, and interest rates, which could, in turn, impact future earnings and the unrealized gains or losses associated with our risk management assets and liabilities and asset valuation for our asset impairment calculations. 

 

Income Taxes

 

The effective tax rate on earnings excluding non-comparable items for 2013 is expected to be approximately 17 to 22 per cent, which is lower than the statutory tax rate of 25 per cent, due to changes in the amount of earnings between the jurisdictions in which pre-tax income is earned and the effect of certain deductions that do not fluctuate with earnings.

 

Capital Expenditures

 

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

 

Growth and Major Project Expenditures

 

We have one major project with a targeted completion date of Q4 2013. A summary is outlined below:

 

  Total Project   2013 Target    
  Estimated spend Spent to date(1)   Estimated spend Spent to date(1) completion
date		   Details
                 
Growth                
                 
New Richmond 212 218   15 - 25 30 Commercial
operations
began
Q1 2013		   A 68 MW wind farm in Québec
                 
Major projects                
                 
Sundance Units 1 and 2 215 202   155 - 170 158 Sundance Unit 1 completed during Q3 2013 and Sundance Unit 2 completed in Q4 2013   Sundance Units 1 and 2 comprising 560 MW of our Sundance power plant
Total major projects and growth 427 420   170 - 195 188      

 

  

TRANSALTA CORPORATION / Q2 2013  38

   

 

The total estimated spend for Sundance Units 1 and 2 has increased by $25 million due to additional scope of work for balance of plant systems and equipment as well as higher labour costs due to an increase in rates.  This work is being performed concurrently with the boiler repairs to prevent the need for a later outage for this work. 

 

The total estimated spend for New Richmond is less than the amount incurred to date due to estimated recoveries to be received in 2013.

 

Transmission

 

During the quarter, we reversed a provision as a result of a reduction in our expected transmission costs.  As a result, for the three and nine months ended Sept. 30, 2013, we have a net recovery of $4 million and nil, respectively on transmission projects.  The estimated spend for 2013 on transmission projects is $7 million.  Transmission projects consist of the major maintenance and reconfiguration of Alberta’s transmission networks to increase capacity of power flow in the lines. 

 

Sustaining Capital and Productivity Expenditures(1)

 

For 2013, our estimate for total sustaining capital and productivity expenditures, net of any contributions received, is allocated among the following:

 

Category Description     Expected
cost		 Spent to
date(1)
               
Routine capital Expenditures to maintain our existing generating capacity 90 - 100 78
Mining equipment and
land purchases(2)		 Expenditures related to mining equipment and
land purchases		 40 - 50 38
Finance leases Payments related to mining equipment under finance leases 0 - 10 7
Planned major maintenance Regularly scheduled major maintenance 165 - 185 122
Total sustaining expenditures         295 - 345 245
Productivity capital Projects to improve power production efficiency 30 - 50 26
Total sustaining and productivity expenditures     325 - 395 271

 

During the nine months, we acquired $33 million of mining equipment under finance leases and we made principal repayments of
$7 million.

 

(1) Represents amounts spent as of Sept. 30, 2013. During 2013, we also had a reduction of costs of $1 million on facilities that had previously commenced operations.

(1) Represents amounts incurred as of Sept. 30, 2013.

 

((2) An additional $12 million for mining equipment in use is not payable until 2014.

 

  

TRANSALTA CORPORATION / Q2 2013  39

   

Our planned major maintenance program relates to regularly scheduled major maintenance activities and includes costs related to inspection, repair and maintenance, and replacement of existing components. It excludes amounts for day-to-day routine maintenance, unplanned maintenance activities, and minor inspections and overhauls, which are expensed as incurred. Details of the 2013 planned major maintenance program are outlined as follows:

 

        Coal Gas and Renewables Expected
spend
in 2013		 Spent
to date(1)
Capitalized       90 - 105 75 - 80 165 - 185 122
Expensed       - 0 - 5 0 - 5 -
        90 - 105 75 - 85 165 - 190 122
               
        Coal Gas and Renewables Expected
total		 Lost
to date
GWh lost       1,660 - 1,670 420 - 430 2,080 - 2,100 1,485

 

Financing

 

Financing for these capital expenditures is expected to be provided by cash flow from operating activities, existing borrowing capacity, reinvested dividends under the Plan, and capital markets. The funds required for committed growth, sustaining capital, and productivity projects are not expected to be significantly impacted by the current economic environment due to the highly contracted nature of our cash flows, our financial position, and the amount of capital available to us under existing committed credit facilities.

 

 

accounting changes

 

Adoption of New or Amended IFRS

 

On Jan. 1, 2013, we adopted the following new accounting standards that were previously issued by the International Accounting Standards Board (“IASB”):

 

IFRS 10 Consolidated Financial Statements

 

IFRS 10 replaces the parts of International Accounting Standard (“IAS”) 27 Consolidated and Separate Financial Statements that deal with consolidated financial statements and Standing Interpretations Committee (“SIC”) Interpretation 12 Consolidation - Special Purpose Entities.  IFRS 10 defines the principle of control, establishes control as the basis for determining when entities are to be consolidated, and provides guidance on how to apply the principle of control to identify whether an investor controls an investee.  Under IFRS 10, an investor controls an investee when it has all of the following: (i) power over the investee; (ii) exposure, or rights, to variable returns from the investee; and (iii) the ability to affect those returns.

 

We applied IFRS 10 retrospectively by reassessing whether, on Jan. 1, 2013, we had control of all of our previously consolidated entities. As a result of adopting IFRS 10, no changes arose in the entities we controlled and consolidated.

 

 

(1) Represents amounts incurred as of Sept. 30, 2013.

 

  

TRANSALTA CORPORATION / Q2 2013  40

   

IFRS 11 Joint Arrangements

 

IFRS 11 replaces IAS 31 Interests in Joint Ventures and SIC-13 Jointly Controlled Entities – Non-Monetary Contributions by Venturers.  IFRS 11 provides for a principles-based approach to the acwcounting for joint arrangements that requires an entity to recognize its contractual rights and obligations arising from its involvement in joint arrangements.  A joint arrangement is an arrangement in which two or more parties have joint control.  Under IFRS 11, joint arrangements are classified as either a joint operation or a joint venture, whereas under IAS 31, they were classified as a jointly controlled asset, jointly controlled operation or a jointly controlled entity.  IFRS 11 requires the use of the equity method of accounting for interests in joint ventures, whereas IAS 31 permitted a choice of the equity method or proportionate consolidation for jointly controlled entities. Under IFRS 11, for joint operations, each party recognizes its respective share of the assets, liabilities, revenues and expenses of the arrangement, generally resulting in proportionate consolidation accounting. 

 

We applied IFRS 11 retrospectively by reassessing the type of, and accounting for, each joint arrangement in existence at
Jan. 1, 2013. No significant impacts resulted.

 

IFRS 12 Disclosure of Interests in Other Entities

 

IFRS 12 contains enhanced disclosure requirements about an entity’s interests in subsidiaries, joint arrangements, associates, and consolidated and unconsolidated structured entities (special purpose entities). The objective of IFRS 12 is that an entity should disclose information that helps financial statement users evaluate the nature of, and risks associated with, its interests in other entities and the effects of those interests on its financial statements. Disclosures arising from the adoption of IFRS 12 can be found in Notes 11, 14, and 22 of our interim consolidated financial statements.

 

IFRS 13 Fair Value Measurement

 

IFRS 13 establishes a single source of guidance for all fair value measurements required by other IFRS, clarifies the definition of fair value, and enhances disclosures about fair value measurements. IFRS 13 applies when other IFRS require or permit fair value measurements or disclosures. IFRS 13 specifies how an entity should measure fair value and disclose fair value information. It does not specify when an entity should measure an asset, a liability, or its own equity instrument at fair value. Our adoption of IFRS 13, prospectively on Jan. 1, 2013, did not have a material financial impact upon the consolidated financial position or results of operations, however, certain new or enhanced disclosures are required and can be found in Note 15 of our interim consolidated financial statements.

 

IAS 1 Presentation of Financial Statements

 

Amendments to IAS 1 Presentation of Financial Statements issued in June 2011 were intended to improve the consistency and clarity of the presentation of items of comprehensive income by requiring that items presented in OCI be grouped on the basis of whether they subsequently reclassified from OCI to net earnings or not. The Consolidated Statements of Comprehensive Income (Loss) have been reorganized to comply with the required groupings.

 

IAS 19 Employee Benefits

 

Amendments to IAS 19 Employee Benefits are intended to improve the recognition, presentation, and disclosure of defined benefit plans. The amendments require the recognition of changes in defined benefit obligations and in fair value of plan assets when they occur, thus eliminating the “corridor approach” previously permitted. All actuarial gains and losses must be recognized immediately through other comprehensive income and the net pension liability or asset recognized at the full amount of the plan deficit or surplus. Additional changes relate to the presentation, into three components, of changes in defined benefit obligations and plan assets: service cost and net interest cost is recognized in net earnings and remeasurements are recognized in other comprehensive income. The net interest cost introduced in these amendments removes the concept of expected return on plan assets that was previously recognized in net earnings.

  

TRANSALTA CORPORATION / Q2 2013  41

   

 

We calculate the net interest cost for our defined benefit plans by applying the discount rate at the beginning of the reporting period to the net defined benefit liability at the beginning of the reporting period. An expected return on plan assets is no longer calculated and recognized as part of pension expense. The elimination of the corridor method had no impact as we have, since the adoption of IFRS, recognized actuarial gains and losses in OCI in the period in which they occurred.

 

On adoption, we applied the amendments retrospectively. The impacts as at Dec. 31, 2012 and Jan 1, 2012, respectively, were an increase in the cumulative prior periods’ pre-tax pension expense of $17 million and $11 million ($12 million and $8 million after-tax, respectively), as a result of the application of the net interest cost requirements.

 

For the three and nine months ended Sept. 30, 2012, OM&A expense increased by $1 million and $4 million, respectively, as a result of increased pension expense. Net after-tax actuarial losses on defined benefit plans as reported in OCI decreased by $1 million and $3 million, respectively, and basic and diluted net earnings per share attributable to common shareholders decreased by nil and $0.01, respectively.

 

Interpretation 20 Stripping Costs in the Production Phase of a Surface Mine (“IFRIC 20”)

 

IFRIC 20 clarifies the requirements for accounting for stripping costs in the production phase of a surface mine. Stripping costs are costs associated with the process of removing waste from a surface mine in order to gain access to mineral ore deposits. The Interpretation clarifies when production stripping should lead to the recognition of an asset and how that asset should be measured, both initially and in subsequent periods.

 

We recognize a stripping activity asset for our Highvale mine when all of the following are met: (i) it is probable that the future benefit associated with improved access to the coal reserves associated with the stripping activity will be realized; (ii) the component of the coal reserve to which access has been improved can be identified; and (iii) the costs related to the stripping activity associated with that component can be measured reliably. Costs include those directly incurred to perform the stripping activity as well as an allocation of directly attributable overheads. The resulting stripping activity asset is amortized on a unit-of-production basis over the expected useful life of the identified component that it relates to. The amortization is recognized as a component of the standard cost of coal inventory.

 

As required by the transitional provision of IFRIC 20, we applied the Interpretation to production stripping costs incurred on or after Jan 1, 2011, which will be the earliest comparative period presented within our annual financial statements for the year ended Dec. 31, 2013 which will result in adjustments to the 2012 earnings. The impacts on the Condensed Consolidated Statements of Financial Position as at Dec. 31, 2012 were to recognize $9 million in costs as a stripping activity asset, increase coal inventory by $2 million, both classified within Inventory, increase Deferred income tax liabilities by $3 million, and decrease Retained deficit by $8 million. The impacts on the Condensed Consolidated Statements of Financial Position as at Jan. 1, 2012 were to recognize $9 million in costs as a stripping activity asset, decrease coal inventory by $2 million, both classified within Inventory, increase Deferred income tax liabilities by $2 million, and increase Retained earnings by $5 million.

 

The impact of this change in accounting policy on the three and nine months ended Sept. 30, 2012 was a reduction of $1 million in Fuel and purchased power.

 

  

TRANSALTA CORPORATION / Q2 2013  42

   

IFRS 7 Financial Instruments: Disclosures

 

Amendments to IFRS 7 include disclosures about all recognized financial instruments that are set off in accordance with IAS 32. The amendments also require disclosure of information about recognized financial instruments subject to enforceable master netting arrangements and similar agreements even if they are not set off under IAS 32. The resulting disclosures can be found in Note 16 of our interim consolidated financial statements.

 

Annual Improvements 2009-2011

 

In May 2012, the IASB issued a collection of necessary, non-urgent amendments to several IFRS resulting from its annual improvements process. We have applied the amendments, as applicable, on Jan. 1, 2013. None of the amendments, which are generally technical and narrow in scope, had a material financial impact upon the consolidated financial position or results of operations.

 

 

future accounting changes

 

Additional new or amended accounting standards that have been previously issued by the IASB but are not yet effective, and have not yet been applied, are as follows: IFRS 9 Financial Instruments, IAS 32 Financial Instruments: Presentation, and Investment Entities (Amendments to IFRS 10 and 11 and IAS 27). Please refer to the Future Accounting Changes section of our 2012 Annual MD&A for more information.

 

 

Additional 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 nine months ended Sept. 30, 2013 and 2012. Presenting these line items provides management and investors with a measurement of ongoing operating performance that is readily comparable from period to period.

 

 

NON-IFRS MEASURES

 

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

 

  

TRANSALTA CORPORATION / Q2 2013  43

   

Presenting earnings on a comparable basis, comparable gross margin, comparable operating income, and comparable EBITDA from period to period provides management and investors with supplemental information to evaluate earnings trends in comparison with results from prior periods. In calculating these items, we exclude the impact related to certain hedges that are either de-designated or deemed ineffective for accounting purposes, as management believes that these transactions are not representative of our business operations. As these gains (losses) have already been recognized in earnings in current or prior periods, future reported earnings will be lower; however, the expected cash flows from these contracts will not change. In calculating comparable earnings measures we have also excluded the 2012 coal inventory writedown, as the recognition of the writedown is related to the hedges that were de-designated or deemed ineffective during prior quarters.

 

Other adjustments to earnings, such as those included in the earnings on a comparable basis calculation, have also been excluded as management believes these transactions are not representative of our business operations. Earnings on a comparable basis per share are calculated using the weighted average common shares outstanding during the period.

 

Comparable operating income and EBITDA also include the earnings from the finance lease facilities that we operate.  The finance lease income is used as a proxy for the operating income and EBITDA of these facilities.

 

Net Earnings on a Comparable Basis

 

Net earnings on a comparable basis are reconciled to net earnings attributable to common shareholders below:

 

          3 months ended Sept. 30 9 months ended Sept. 30
      2013 2012 2013 2012
Net earnings (loss) attributable to common shareholders (9) 56 (5) (654)
Impacts associated with certain de-designated and
ineffective hedges, net of tax		 7 39 39 38
Asset impairment charges (reversals), net of tax (13) (31) (13) 329
Inventory writedown (reversal), net of tax   - (18) - 3
Restructuring provision, net of tax   - - (2) -
Sundance Units 1 and 2 return to service, net of tax   11 5 11 189
Income tax expense related to write off of deferred
income tax assets		   40 - 40 169
Income tax recovery related to deferred tax rate
adjustment		   - - (7) -
Income tax recovery related to the resolution of certain
outstanding tax matters		   - - - (9)
Income tax expense related to changes in corporate
income tax rates		   - - - 8
Gain on sale of assets, net of tax - - (9) (2)
Writeoff of Project Pioneer costs, net of tax   - 1 - 2
Gain on sale of collateral, net of tax - (11) - (11)
Loss on assumption of pension obligations, net of tax - - 22 -
Flood related maintenance costs, net of tax 3 - 4 -
Net earnings on a comparable basis   39 41 80 62
                 
Weighted average number of common shares
outstanding in the period		 266 234 262 229
Net earnings on a comparable basis per share   0.15 0.18 0.31 0.27

 

 

 

  

TRANSALTA CORPORATION / Q2 2013  44

   

Comparable Gross Margin

 

Comparable gross margin is calculated as follows: 9

 

          3 months ended Sept. 30 9 months ended Sept. 30
      2013 2012 2013 2012
Gross margin       363 331 1,057 1,056
Impacts associated with certain de-designated and
ineffective hedges		   11 60 60 58
Impacts to revenue associated with Sundance
Units 1 and 2(1)		 - - - (20)
Inventory writedown - (20) - (20)
Comparable gross margin   374 371 1,117 1,074

 

Comparable Operating Income

 

A reconciliation of comparable operating income is as follows:

 

          3 months ended Sept. 30 9 months ended Sept. 30
      2013 2012 2013 2012
Operating income (loss)     118 132 277 (93)
Impacts associated with certain de-designated and
ineffective hedges		   11 60 60 58
Asset impairment charges (reversal)   (18) (41) (18) 324
Inventory writedown (reversal) - (28) - 5
Restructuring provision (1) - (3) -
Finance lease income 11 1 34 5
Flood related maintenance costs 4 - 5 -
Writeoff of Project Pioneer costs - 2 - 3
Comparable operating income   125 126 355 302

 

 

(1) The results have been adjusted retroactively for the impact of Sundance Units 1 and 2. Comparative figures have also been adjusted in this table only to provide period over period comparability. 

  

TRANSALTA CORPORATION / Q2 2013  45

   

Comparable EBITDA

 

Presenting comparable EBITDA from period to period provides management and investors with a proxy for the amount of cash generated from operating activities before net interest expense, non-controlling interests, income taxes, and working capital adjustments.

 

A reconciliation of comparable EBITDA to operating income is as follows:

 

          3 months ended Sept. 30 9 months ended Sept. 30
      2013 2012 2013 2012
Operating income (loss)     118 132 277 (93)
Asset impairment charges (reversal)   (18) (41) (18) 324
Inventory writedown (reversal)   - (28) - 5
Restructuring provision     (1) - (3) -
Finance lease income     11 1 34 5
Depreciation and amortization per the Consolidated
Statements of Cash Flows(1)		   141 129 425 419
Impacts associated with certain de-designated and
ineffective hedges		   11 60 60 58
Impacts to revenue associated with Sundance
Units 1 and 2		   - - - (20)
Flood related maintenance costs 4 - 5 -
Writeoff of Project Pioneer costs - 2 - 3
Comparable EBITDA     266 255 780 701

 

Funds from Operations and Funds from Operations per Share

 

Presenting funds from operations and funds from operations per share from period to period provides management and investors with 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. Funds from operations per share is calculated as follows using the weighted average number of common shares outstanding during the period:

 

          3 months ended Sept. 30 9 months ended Sept. 30
      2013 2012 2013 2012
Cash flow from operating activities   253 14 601 275
Impacts to working capital associated with Sundance
Units 1 and 2 arbitration		   - - - 204
Payment of restructuring costs   1 - 5 -
Timing of payments related to assumption of
pension obligations		   (7) - - -
Flood related maintenance costs 4 - 5 -
Change in non-cash operating working capital balances   (77) 219 (61) 93
Funds from operations     174 233 550 572
Weighted average number of common shares
outstanding in the period		   266 234 262 229
Funds from operations per share   0.65 1.00 2.10 2.50

 

 

(1) To calculate comparable EBITDA, we use depreciation and amortization per the Condensed Consolidated Statements of Cash Flows in order to account for depreciation related to mine assets, which is included in fuel and purchased power on the Condensed Consolidated Statements of Earnings.

  

TRANSALTA CORPORATION / Q2 2013  46

   

Free Cash Flow

 

Free cash flow represents the amount of cash generated from operations by our business, before changes in working capital that is available to invest in growth initiatives, make scheduled principal repayments of debt, pay additional common share dividends, or repurchase common shares. Changes in working capital are excluded so as to not distort free cash flow with changes that we consider temporary in nature, reflecting, among other things, the impact of seasonal factors and the timing of capital projects.

 

Sustaining capital and productivity expenditures for the three months ended Sept. 30, 2013 represent total additions to property, plant, and equipment and intangibles per the Condensed Consolidated Statements of Cash Flows less $50 million that we have invested in projects and growth. For the same period in 2012, we invested $62 million in projects and growth. For the nine months ended Sept. 30, 2013 and 2012, we invested $187 million and $144 million, respectively, in projects and growth.

 

The reconciliation between cash flow from operating activities and free cash flow is outlined below:

 

  3 months ended Sept. 30 9 months ended Sept. 30
  2013 2012 2013 2012
Cash flow from operating activities 253 14 601 275
Add (deduct):        
Impacts to working capital associated with Sundance
Units 1 and 2 arbitration		 - - - 204
Changes in non-cash operating working capital (77) 219 (61) 93
Sustaining capital and productivity expenditures (109) (120) (271) (368)
Dividends paid on common shares(1) (1) (18) (64) (86)
Dividends paid on preferred shares (9) (7) (28) (21)
Distributions paid to subsidiaries' non-controlling interests (8) (9) (43) (42)
Free cash flow 49 79 134 55

 

We seek to maintain sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to our business.

 

 

 

(1) Net of dividends reinvested under the Plan

  

TRANSALTA CORPORATION / Q2 2013  47

   

SELECTED QUARTERLY INFORMATION

        Q4 2012 Q1 2013 Q2 2013 Q3 2013
               
Revenue     646 540 542 623
Net earnings (loss) attributable to common shareholders   39 (11) 15 (9)
Net earnings (loss) per share attributable to common shareholders,
basic and diluted		 0.15 (0.04) 0.06 (0.03)
Comparable earnings per share     0.22 0.12 0.03 0.15
               
        Q4 2011 Q1 2012 Q2 2012 Q3 2012
               
Revenue     688 644 398 522
Net earnings (loss) attributable to common shareholders     24 88 (798) 56
Net earnings (loss) per share attributable to common shareholders,
basic and diluted		 0.11 0.39 (3.52) 0.24
Comparable earnings (loss) per share     0.13 0.20 (0.10) 0.18

 

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.

 

 

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 Securities and Exchange Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding our required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating and implementing possible controls and procedures.

 

There has been no change in the internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of Sept. 30, 2013, the end of the period covered by this report, our disclosure controls and procedures were effective at a reasonable assurance level.

 

 

FORWARD-LOOKING STATEMENTS

 

This MD&A, the documents incorporated herein by reference, and other reports and filings made with the securities regulatory authorities include forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of the “safe harbor” provisions of applicable securities legislation. All forward-looking statements are based on our beliefs as well as assumptions based on information available at the time the assumption was 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”, “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.

  

TRANSALTA CORPORATION / Q2 2013  48

   

 

In particular, this MD&A contains forward-looking statements pertaining to our business and anticipated financial performance including, for example: the closing of the acquisition of the Wyoming wind farm; the timing and the completion and commissioning of projects under development, including major projects, and their attendant costs; our estimated spend on matters relating to the recent flood in Alberta, spend on growth and sustaining capital and productivity projects; expectations in terms of the cost of operations, capital spend, and maintenance, and the variability of those costs; the impact of certain hedges on future reported earnings and cash flows; expectations related to future earnings and cash flow from operating and contracting activities; estimates of fuel supply and demand conditions and the costs of procuring fuel; expectations for demand for electricity in both the short term and long term, and the resulting impact on electricity prices; load growth, increased capacity, and natural gas costs on power prices; expectations in respect of generation availability, capacity, and production; expected financing of our capital expenditures; expected governmental regulatory regimes and legislation and their expected impact on us, as well as the cost of complying with resulting regulations and laws; our trading strategy 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; expectations for the outcome of existing or potential legal and contractual claims; expectations for the ability to access capital markets at reasonable terms; the estimated impact of changes in interest rates and the value of the Canadian dollar relative to the U.S. dollar and other currencies in locations where we do business; the monitoring of our exposure to liquidity risk; expectations in respect to the global economic environment; our credit practices; the estimated contribution of Energy Trading activities to gross margin; and expectations relating to the performance of TransAlta Renewables assets.

 

Factors that may adversely impact our forward-looking statements include risks relating to: fluctuations in market prices and the availability of fuel supplies required to generate electricity; our ability to contract our generation for prices that will provide expected returns; the regulatory and political environments in the jurisdictions in which we operate; environmental requirements and changes in, or liabilities under, these requirements; changes in general economic conditions including interest rates; operational risks involving our facilities, including unplanned outages at such facilities; disruptions in the transmission and distribution of electricity; the effects of weather; disruptions in the source of fuels, water, or wind required to operate our facilities; natural disasters; the threat of domestic terrorism and cyber-attacks; equipment failure and our ability to carry out the repairs in a cost effective manner or timely manner; energy trading risks; industry risk and competition; fluctuations in the value of foreign currencies and foreign political risks; the need for additional financing; structural subordination of securities; counterparty credit risk; insurance coverage; our provision for income taxes; legal and contractual proceedings involving the Corporation; reliance on key personnel; labour relations matters; development projects and acquisitions; and the satisfactory receipt of applicable regulatory approvals for the closing of the Wyoming acquisition. The foregoing risk factors, among others, are described in further detail in the Risk Management section of our 2012 Annual MD&A and under the heading “Risk Factors” in our 2013 Annual Information Form.

 

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

 

  

TRANSALTA CORPORATION / Q2 2013  49

   

 

Supplemental information

      Sept. 30, 2013 Dec. 31, 2012
         
Closing market price (TSX) ($)     13.38 15.12
         
Price range for the last 12 months (TSX) ($) High   16.86 21.37
         
  Low   12.91 14.11
         
Debt to invested capital (%)     54.0 55.6
         
Debt to invested capital excluding non-recourse debt (%)(1)     51.6 53.3
         
Debt to invested capital including finance lease obligation and non-recourse debt (%) 54.1 55.6
         
Return on equity attributable to common shareholders (%)     1.5 (23.7)
         
Comparable return on equity attributable to common shareholders(1), (2) (%)     5.8 4.5
         
Return on capital employed(2) (%)     4.9 (3.1)
         
Comparable return on capital employed(1), (2) (%)     6.2 5.3
         
Cash dividends per share(2) ($)     1.16 1.16
         
Price to comparable earnings ratio(2) (times)     24.8 30.2
         
Earnings coverage(2) (times)     1.4 (1.2)
         
Dividend payout ratio based on net earnings(2) (%)     885.3 (44.1)
         
Dividend payout ratio based on comparable earnings(1), (2) (%)     221.3 229.7
         
Dividend payout ratio based on funds from operations(1), (2), (3) (%)     39.7 34.7
         
Dividend yield(2) (%)     8.7 7.7
         
Adjusted cash flow to debt(2), (3) (%)     18.3 19.0
         
Adjusted cash flow to interest coverage(2), (3) (times)     4.2 4.4

 

(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 this calculation, refer to the Non-IFRS Measures section of this MD&A.

 

(2) Last 12 months.

 

(3) The December 2012 ratios have been adjusted for the impact of the Sundance Units 1 and 2 arbitration.

 

Ratio Formulas

 

Debt to invested capital = long-term debt including current portion - cash and cash equivalents / long-term debt including current portion + non-controlling interests + equity attributable to shareholders - cash and cash equivalents

 

Return on equity attributable to common shareholders = net earnings attributable to common shareholders or earnings on a comparable basis / average equity attributable to common shareholders excluding AOCI

 

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

 

Price to comparable earnings ratio = current period’s closing market price / comparable earnings per share

 

Earnings coverage = net earnings attributable to common shareholders + income taxes + net interest expense / interest on debt - interest income

 

Dividend payout ratio = common share dividends / net earnings attributable to common shareholders or earnings on a comparable basis or funds from operations

 

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

 

  

TRANSALTA CORPORATION / Q2 2013  50

   

Adjusted cash flow to debt = cash flow from operating activities before changes in working capital / average total debt - average cash and cash equivalents

 

Adjusted cash flow to interest coverage = cash flow from operating activities before changes in working capital + interest on debt - interest income - capitalized interest / interest on debt - 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.

 

British Thermal Units (Btu) - A measure of energy. The amount of energy required to raise the temperature of one pound of water one degree Fahrenheit, when the water is near 39.2 degrees Fahrenheit.

 

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

 

Derate - To lower the rated electrical capability of a power generating facility or unit.

 

Force Majeure - Literally means “major 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.

 

Geothermal Plant - A plant in which the prime mover is a steam turbine. The turbine is driven either by steam produced from hot water or by natural steam that derives its energy from heat found in rocks or fluids at various depths beneath the surface of the earth. The energy is extracted by drilling and/or pumping.

 

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.

 

Heat Rate - A measure of conversion, expressed as Btu/MWh, of the amount of thermal energy required to generate electrical energy.

 

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.

 

Net Maximum Capacity - The maximum capacity or effective rating, modified for ambient limitations, that a generating unit or power plant can sustain over a specific period, less the capacity used to supply the demand of station service or auxiliary needs.

 

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

 

Renewable Power - Power generated from renewable terrestrial mechanisms including wind, geothermal, and solar with regeneration.

 

Spark Spread - A measure of gross margin per MW (sales price less cost of natural gas).

 

Supercritical Combustion Technology: The most advanced coal-combustion technology in Canada employing a supercritical boiler, high-efficiency multi-stage turbine, flue gas desulphurization unit (scrubber), bag house, and low nitrogen oxide burners.

 

Turbine - A machine for generating rotary mechanical power from the energy of a stream of fluid (such as water, steam, or hot gas). Turbines convert kinetic energy of fluids to mechanical energy through the principles of impulse and reaction or a mixture of the two.

 

Turnaround: Periodic planned shutdown of a generating unit for major maintenance and repairs. Duration is normally in weeks. The time is measured from unit shutdown to putting the unit back on line.

 

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

 

Uprate - To increase the rated electrical capability of a power generating facility or unit.

 

Value at Risk (VaR) - A measure to manage earnings exposure from energy trading activities.

  

TRANSALTA CORPORATION / Q2 2013  51

   

 

TransAlta Corporation

110 - 12th Avenue S.W.

Box 1900, Station “M”

Calgary, Alberta Canada T2P 2M1

Phone

403.267.7110

 

Website

www.transalta.com

 

CIBC Mellon Trust Company

P.O. Box 7010 Adelaide Street Station

Toronto, Ontario Canada M5C 2W9

Phone

Toll-free in North America: 1.800.387.0825

Toronto or outside North America: 416.643.5500

Fax

416.643.5501

Website

www.cibcmellon.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

403.267.2590

E-mail

investor_relations@transalta.com

 

 

  

TRANSALTA CORPORATION / Q2 2013  52