TransAlta Corporation
2015 Annual Integrated Report
Letter to Shareholders
Message from the Chair
Management’s Discussion and Analysis
Consolidated Financial Statements
Notes to Consolidated Financial Statements
Eleven-Year Financial and Statistical Summary
Plant Summary
Sustainability Performance Indicators
Ernst & Young Independent Limited Assurance Statement
Shareholder Information
Shareholder Highlights
Corporate Information
Glossary of Key Terms
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Letter to Shareholders
This was a year of exceptional external challenges by any measure. We began the year
with goals of strengthening our balance sheet to ensure we would maintain solid credit
metrics through a low point in the commodity cycle, and moderately growing the company.
We foresaw the economy slowing in many of our markets but could never have predicted
the dramatic change in the policy framework in Alberta for carbon, the weakening of the
Canadian dollar in response to low oil and gas prices, and the significant lack of confidence
investors had for investments in the energy and power sectors. We met many of the goals
we set for ourselves in 2015, but by the end of the year, these unforeseen events called for
substantive and proactive action.
In mid-January 2016, we announced prudent and proactive
steps we were taking to support our transition from coal to
gas-fired and renewable generation. These steps included a
significant reduction to our dividend, suspension of our
dividend reinvestment plan, and plans to reposition our capital
structure by focusing on raising non-recourse project-level
debt to fund debt maturities over the next few years. These
decisions will provide us with the full flexibility we need to
work with the Government of Alberta on a coal transition
plan, re-align the balance sheets of TransAlta and TransAlta
Renewables, and prepare for the opportunities that will arise
as coal is converted to gas-fired and renewable generation
here in Alberta.
We also separated the financial strategies of TransAlta and
TransAlta Renewables and prepared the company for new
opportunities that will arise as more certainty emerges in
the Alberta market. We will have many opportunities for
investment as the Alberta market eliminates coal from its
generation portfolio by 2030. Our work in the next few years
is to ensure that we have a market structure and policy
environment that supports investment.
You will also see a difference in our annual reporting this year,
as we’ve consolidated our Annual Report and Report on
Sustainability into an Annual Integrated Report for 2015. This
is long overdue. We simply cannot act in the power generation
space without considering a balanced scorecard that includes
economic, operational, safety, people, and environmental
goals and results.
Investment Choices
As we move into 2016, TransAlta is a different investment
choice for shareholders. Investors who choose TransAlta
should be focused on our moderate risk profile given some
exposure to merchant risk and Alberta Power Purchase
Arrangements (PPAs) that expire in 2020, as well as our
ability to leverage our competitive advantages when new
growth opportunities arise in the medium to longer term.
Investors interested in lower risk and the stability of yield that
comes from long-term contracts will be attracted to
TransAlta Renewables. TransAlta will maintain a high level of
ownership in TransAlta Renewables and will use the cash
distributions it receives to support its dividend and take
advantage of gas and renewable growth opportunities.
Through 2016, we will continue to face uncertainty over the
long-term stability of cash flows generated by our coal plants
in Alberta as we work with the government-appointed
negotiator on the transition from coal to renewables and gas
by 2030. Fortunately, your company has a diversified asset
base; Canadian coal accounts for only approximately 25 per
cent of our comparable EBITDA net of sustaining capital
expenditures, and our current PPAs protect our cash flows
until the end of 2020. There is no question in my mind that
the negative perception of TransAlta due to the policy
environment surrounding coal needs to be resolved so that
investors can more easily assess the value of our cash flows.
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TransAlta Corporation | 2015 Annual Integrated Report Letter to Shareholders
2015 Performance
We set out in 2015 to achieve world-class safety performance,
deliver on our operational and financial goals, pay down
$500 million in debt and grow modestly. Anticipating a
prolonged period of low commodity prices, we had been on
a path since 2014 to reduce overhead costs, simplify our
structure and reduce the size of the management team to
ensure stronger accountability and decision-making.
In 2015, we exceeded our safety target and achieved our
best-ever result in this area. We delivered adjusted fleet
availability, which accounts for economic dispatching at U.S.
coal, of a respectable 89 per cent. Additionally, we exceeded
our guidance for comparable free cash flow and generated
comparable funds from operations and comparable EBITDA
at the lower end of our guidance ranges, excluding an
adjustment to provisions relating mostly to prior years.
During the year, we repaid $500 million of U.S. debt and began
2016 with liquidity of approximately $1.4 billion. We
accomplished this by completing two major transactions to
drop-down assets to TransAlta Renewables raising almost
$400 million in equity, and reducing our interest in TransAlta
Renewables by selling an eight per cent share of our TransAlta
Renewables ownership to Alberta Investment Management
Corporation (AIMCo) for $200 million. That said, our net debt
level at the beginning of 2016 is approximately $150 million
higher than it was at the beginning of 2015. This increase is
attributed to funding the construction of the South Hedland
power station in Australia and the acquisition of two renewable
projects in 2015. Also impacting our debt was the severe
depreciation of the Canadian dollar, although the impact to the
company was mitigated by our foreign exchange hedges.
Our cost reduction initiatives led to changes in the operation
of the Highvale mine and Canadian Coal and reduced our
overhead. Our work was thoughtful and we took the time
needed to ensure that the new organization was structured
appropriately and our people would have the capabilities to
make decisions for the future. As well, various restructuring
initiatives across the company reduced the total staff
complement by 17 per cent over the prior year, including a 38
per cent reduction in the total size of our management team
from 225 to 139 positions. The combination of reduced
operating costs, improved operating performance, particularly
in Canadian Coal, and our cost reduction initiatives is expected
to result in annual cost savings of approximately $50 million.
My last comments on our 2015 successes relate to growth
and strategic actions. We continued to advance our position
in Australia as we completed the construction of the natural
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gas pipeline to our Solomon power facility and made great
strides in the construction of the South Hedland power
station, which will bring new cash flows in mid-2017. We also
successfully advanced our contracted asset base. Early in the
year we secured a 15-year contract extension, effective
December 2016, for our Windsor gas facility, and last fall we
reached a strategic agreement with Suncor Energy to extend
the existing arrangements at the Poplar Creek cogeneration
facility until 2030. As part of this transaction, we extended
the contract for our gas-fired assets with Suncor and
transferred the ownership of the steam generator to Suncor.
The transaction included an agreement to acquire Suncor’s
interest in two wind facilities, which increased our renewable
portfolio in Ontario and Alberta. Our transition to renewables
was further enhanced with the acquisition of 71 megawatts
of wind and solar assets in late 2015.
The year was not without its setbacks. We lost our dispute on
the timing of outages taken in late 2010 and early 2011 with
Alberta’s Market Surveillance Administrator. Although we
maintain that we never deliberately set out to break rules in
the Alberta market, we reached a settlement of $56 million,
which allows the market, our customers, our employees and
our shareholders to move forward. We thank our customers
who stayed with us and we continue to work on regaining the
trust the company has enjoyed for more than a century. We
do not, and never will, take our customers’ support for
granted. In April, we will publicly release two independent
reviews on our compliance and outages practices that we
believe will further build trust with all stakeholders.
Our investment grade rating was confirmed by S&P (BBB-),
Fitch (BBB-), and DBRS (BBB). However, in December,
Moody’s reduced our rating to Ba1 from Baa3. This will not
have a material impact on our business. The impacts were
well within the range of the liquidity we have for the company
and we are moving forward with our investment grade ratings
from three rating agencies.
Growing TransAlta Renewables
Today, TransAlta owns 64 per cent of TransAlta Renewables
and remains committed to its position as the majority
shareholder and sponsor. TransAlta Renewables offers
investors who want to participate in gas-fired and renewable
generation the stability of cash flows associated with highly
contracted assets with solid counterparties. The investment
thesis is more about stable yield than growth. Today,
TransAlta Renewables has a direct or indirect investment in
most of our wind assets, our hydro assets outside of Alberta,
our gas portfolio in Australia and our Sarnia cogeneration
plant in Ontario.
TransAlta Corporation | 2015 Annual Integrated Report “
In mid-January 2016, we announced prudent and proactive steps we were taking
to support our transition from coal to gas-fired and renewable generation.
We see the market for contracted gas and renewable assets
slowly growing over the next several years. We have additional
assets that would be a good fit with TransAlta Renewables and
we will continue to grow this entity while maintaining our
ownership in the 60 to 80 per cent range. For TransAlta
shareholders, the cash distributions from TransAlta Renewables
secure the dividend and ensure we have cash to continue
strengthening our balance sheet and grow. Further drop-downs
to TransAlta Renewables will be designed to grow the value
of TransAlta Renewables and raise cash for future growth.
• Continuing to focus on building strong, long-term
relationships with our customers and partners as we near
the end of the PPAs;
• Building options for investment in the Alberta market,
including coal-to-gas conversions and greenfield wind,
solar, and hydro, and ensuring the gas-fired Sundance unit
7 is shelf-ready for investment should the market change;
• Growing TransAlta Renewables’ distributions per share; and
• Creating capital structures for TransAlta and TransAlta
Renewables that are consistent with their value propositions.
Focusing in 2016 and Beyond
In November 2015, the Government of Alberta announced
the Climate Leadership Plan that established several
environmental and energy targets for Alberta, including the
phase out of emissions from coal-fired generation by 2030
and the addition of a significant carbon price to our business
once the coal PPAs roll off. To ensure price stability and
reliability, and to avoid unnecessarily stranding capital, the
conversion of the strategy to policy will require significant
work between industry and government. The government is
expected to appoint a negotiator to work with the coal
generators on a predictable and phased approach to coal
shutdown. The replacement generation will be renewables
and natural gas. However, the manner in which it will all come
together in the current Alberta market is unclear at this time.
Shareholders are facing unprecedented uncertainty regarding
the value of TransAlta’s Alberta assets and this is reflected in
the current market value of the company. As such, our first
priority in 2016 is to reach an agreement with the government
on the path forward for coal. Once this is accomplished, we
believe we will be able to show how coal will support our final
transition to a clean power company. As part of this, we see
important work in ensuring that the Alberta electricity market
structure supports solid returns for our existing gas-fired and
renewable assets and provides the right incentives to attract
new investment for our shareholders.
Our second priority is to ensure that our strategy of raising
non-recourse debt for our contracted assets is executed; this
follows on success in this area in 2015 when we closed a
$442 million bond offering secured by the assets of a
subsidiary of TransAlta Renewables. This strategy will be
employed on an accelerated basis to ensure maximum
financial flexibility as opportunities for growth in the gas and
renewables sectors arise.
Our additional priorities are as follows:
• Completing construction of South Hedland and bringing
And, as always, we’ll continue to focus on delivering strong
operational, safety, financial, people and environmental
performance. We’ve outlined those goals in our report.
Conclusion
Investors desire certainty. We know that, and throughout our
work with government we will be reinforcing that message.
The Alberta electricity market is complex and haste in
implementing the carbon framework could lead to unexpected
results and unintended consequences. So, we’ll be weighing
the pros and cons while taking the time needed to get the
framework right and helping investors understand their
investment in TransAlta.
I am optimistic about the ability of our team to deliver on our
day-to-day and long-term goals. The company is stronger in
2016 due to the actions we’ve taken over the past three
years. The work we completed sets us up for the future. We
have time to ensure that changes to Alberta’s carbon policy
are implemented in a way that meets the objective of
competitive pricing and system reliability for our customers
while allowing us to generate the returns we need for the
remaining life of the coal plants. Our company is equipped
with the right people, information and resources to make this
equation work, and we are ready to ensure our customers
have the right prices and you have the right returns.
Many thanks to our Board of Directors, our management
team, and our employees as we’ve navigated through some
difficult external conditions. To those investors who have
taken the long view, thank you for your confidence.
Dawn L. Farrell
President and Chief Executive Officer
the plant to full operation by mid-2017;
February 17, 2016
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TransAlta Corporation | 2015 Annual Integrated Report Message from the Chair
A prudent and focused management team and Board must make strategic plans based on
available credible information and analysis, while being prepared to use judgment to
adjust if facts and events differ substantially from the underlying assumptions; 2015 was
such a year for TransAlta.
In 2015, the economy of Alberta, where the majority of our
assets are situated, experienced a material and precipitous
deterioration due in large part to the decline in oil prices. This
reduction in economic activity, among other factors, both
dampened demand for electricity and depressed power
prices. In that context, the management team at TransAlta
designed and executed several initiatives that enabled the
company to deliver quality financial, safety, operational and
environmental results. As a consequence, TransAlta entered
2016 with a lower cost structure, a more diversified asset
base and a refined financial strategy designed to address the
market we face, not the one we had hoped for. Among the
significant new facts is an evolving provincial carbon policy
in Alberta that fundamentally alters the long-term economics
associated with our coal-fired generating fleet.
TransAlta is affected in multiple ways by government
regulation and policies and the Board regularly reviews the
company’s compliance policies and practices. As an example,
following the regulatory proceeding with Alberta’s Market
Surveillance Administrator, the Board and management
undertook a thorough review of relevant policies and
practices and we are confident that the company has in place
a rigorous compliance program.
To implement a proactive and solid financial strategy in 2016,
the Board decided to revise the dividend, suspend the
dividend reinvestment plan going forward in order to stop the
dilution of shareholders, and focus on project financing
mechanisms as we restructure debt. These steps were
necessary, as economic volatility and uncertainty concerning
new regulatory policy around our coal fleet requires the
strengthening of our balance sheets. Funds previously
allocated to dividend payments will be employed to reduce
debt and will be reinvested in the company to protect and
enhance the investment made by you, our shareholders. This
firm financial foundation is critical to the future success of
the company in a dynamic environment.
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TransAlta will work diligently and in good faith with the
Alberta government to realize its pledge not to strand capital
unnecessarily, protect consumers and communities, and
implement the transition to gas and renewables through
2030, allowing for a reasonable, workable transition timeline.
Our coal plants and resulting cash flows are supported for
several years by the Alberta Power Purchase Arrangements
and long-term contracts, as TransAlta transitions to even
more natural gas and renewables assets.
As we address current challenges, we are planning now for
the future to provide reliable, sustainable electricity to
consumers in Alberta and other markets in which we operate.
Among our options are conversion of coal plants to gas,
development of new gas-fired plants, enhancement of hydro
power, and expansion of wind and solar. As generating
capacity is removed from the market in Alberta, a healthy
power generating industry is critical to future economic
growth. TransAlta has been providing quality and reliable
service for over 100 years from our Alberta base, and we look
forward to continuing to do so for generations to come.
I can assure you that TransAlta management and your Board
are focused on the future to ensure that the interests of our
customers, investors and employees are advanced every day.
While the developments in 2015 clearly put pressure on our
stock, we believe the more efficient, more diversified, more
financially stable company we are building will be poised to
deliver reliable service to our customers and value to
shareholders as we go forward.
Thank you for your support and I look forward to our
discussions at our annual meeting.
Ambassador Gordon D. Giffin
Chair of the Board of Directors
February 17, 2016
TransAlta Corporation | 2015 Annual Integrated Report Management’s Discussion and Analysis
TRANSALTA CORPORATION
Management’s Discussion and Analysis
Table of Contents
Table of Contents
Forward-Looking Statements
Additional IFRS Measure and Non-IFRS Measures
Forward-Looking Statements
Highlights
Business Model and Competitive Forces
Additional IFRS Measure and Non-IFRS Measures
TransAlta’s Capitals
Highlights
Discussion of Segmented Comparable Results
Business Model and Competitive Forces
Other Consolidated Analysis
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Financial Instruments
2016 Financial Outlook
Financial Instruments
Governance and Risk Management
Critical Accounting Policies and Estimates
2016 Financial Outlook
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Accounting Changes
Governance and Risk Management
Fourth Quarter
Critical Accounting Policies and Estimates
Selected Quarterly Information
TransAlta’s Capitals
Earnings and Other Measures on a Comparable Basis
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Accounting Changes
Disclosure Controls and Procedures
Discussion of Segmented Comparable Results
Other Consolidated Analysis
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Fourth Quarter
Selected Quarterly Information
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Disclosure Controls and Procedures
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This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with our audited annual 2015 consolidated
financial statements and our Annual Information Form for the year ended Dec. 31, 2015. Our consolidated financial statements have
been prepared in accordance with International Financial Reporting Standards (“IFRS”) for Canadian publicly accountable enterprises
as issued by the International Accounting Standards Board (“IASB”) and in effect at Dec. 31, 2015. All dollar amounts in the following
discussion, including the tables, are in millions of Canadian dollars unless otherwise noted and except amounts per share which are in
whole dollars to the nearest two decimals. This MD&A is dated Feb. 17, 2016. Additional information respecting TransAlta Corporation
(“TransAlta”, “we”, “our”, “us”, or the “Corporation”), including our Annual Information Form, is available on SEDAR at
www.sedar.com, on EDGAR at www.sec.gov, and on our website at www.transalta.com. Information on or connected to our website
is not incorporated by reference herein.
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TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Forward-Looking Statements
This MD&A, the documents incorporated herein by reference, and other reports and filings made with securities regulatory
authorities include forward-looking statements or information (collectively referred to herein as “forward-looking statements”)
within the meaning of applicable securities legislation. Forward-looking statements, including the 2016 Financial Outlook section
of this MD&A, are presented for general information purposes only and not as specific investment advice. All forward-looking
statements are based on our beliefs as well as assumptions based on information available at the time the assumptions were
made and on management’s experience and perception of historical trends, current conditions, and expected future
developments, as well as other factors deemed appropriate in the circumstances. Forward-looking statements are not facts, but
only predictions and generally can be identified by the use of statements that include phrases such as “may”, “will”, “believe”,
“expect”, “anticipate”, “intend”, “plan”, “project”, “forecast”, “foresee”, “potential”, “enable”, “continue”, or other comparable
terminology. These statements are not guarantees of our future performance and are subject to risks, uncertainties, and other
important factors that could cause our actual performance to be materially different from that projected.
In particular, this MD&A contains forward-looking statements pertaining to our business and anticipated future financial
performance; our success in executing on our growth projects; the timing of the construction and commissioning of projects
under development, including major projects such as the South Hedland power project and the Sundance 7 project, and their
attendant costs; spending on growth and sustaining capital and productivity projects; expectations in terms of the cost of
operations, capital spending, and maintenance, and the variability of those costs; expected decommissioning costs; the
impact of certain hedges on future reported earnings and cash flows, including future reversals of unrealized gains or losses;
expectations related to future earnings and cash flow from operating and contracting activities (including estimates of full-
year 2016 comparable earnings before interest, taxes, depreciation, and amortization (“EBITDA”), comparable funds from
operations (“FFO”), comparable free cash flow (“FCF”), and expected sustaining capital expenditures for 2016); expectations
in respect of financial ratios and targets (including comparable FFO before interest to adjusted interest coverage, adjusted
comparable FFO to adjusted net debt, and adjusted net debt to comparable EBITDA); the Corporation’s plans and strategies
relating to repositioning its capital structure and strengthening its balance sheet and the debt reductions that are expected to
occur in 2016 and beyond; expected governmental regulatory regimes and legislation (including the Government of Alberta’s
Climate Leadership Plan) and their expected impact on TransAlta and the timing of the implementation of such regimes and
regulations, as well as the cost of complying with resulting regulations and laws; the outcome of negotiations with the
Government of Alberta in relation to coal-fired generation transition under the Climate Leadership Plan; and potential
opportunities for investment in renewable and gas-fired generation; our comparative advantages over our competitors;
estimates of fuel supply and demand conditions and the costs of procuring fuel; expectations for demand for electricity in
both the short term and long term, and the resulting impact on electricity prices; the impact of load growth, increased
capacity, and natural gas costs on power prices; expectations in respect of generation availability, capacity, and production;
expectations regarding the role different energy sources will play in meeting future energy needs; expected financing of our
capital expenditures; including the anticipated financial impact of increased Specified Gas Emitters Regulation (“SGER”)
obligations in Alberta, and the value of offsets generated by our wind facilities in the province; our trading strategies and the
risk involved in these strategies; estimates of future tax rates, future tax expense, and the adequacy of tax provisions;
accounting estimates; anticipated growth rates in our markets; our expectations regarding the outcome of existing or
potential legal and contractual claims, regulatory investigations, and disputes; expectations regarding the renewal of collective
bargaining agreements; expectations for the ability to access capital markets at reasonable terms; the estimated impact of
changes in interest rates and the value of the Canadian dollar relative to the US dollar, the Australian dollar, and other
currencies in which we do business; the monitoring of our exposure to liquidity risk; expectations regarding the impact of the
slowdown in the oil and gas sector; expectations in respect of the global economic environment and growing scrutiny by
investors relating to sustainability performance; our credit practices; expected cost savings following the implementation of
our efficiency and productivity initiatives; the estimated contribution of Energy Marketing activities to gross margin;
expectations relating to the performance of TransAlta Renewables Inc.’s (“TransAlta Renewables”) assets; expectations
regarding our continued ownership of common shares of TransAlta Renewables; expectations in respect of our community
and environmental initiatives; and expectations in respect of the Keephills Unit 1 Force Majeure event, including the impact of
the claim.
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TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Factors that may adversely impact our forward-looking statements include risks relating to: fluctuations in market prices and the
availability of fuel supplies required to generate electricity; our ability to contract our generation for prices that will provide
expected returns; the regulatory and political environments in the jurisdictions in which we operate; increasingly stringent
environmental requirements and changes in, or liabilities under, these requirements; changes in general economic conditions,
including interest rates; operational risks involving our facilities, including unplanned outages at such facilities; disruptions in the
transmission and distribution of electricity; the effects of weather; disruptions in the source of fuels, water, or wind required to
operate our facilities; natural or man-made disasters; the threat of terrorism and cyberattacks; equipment failure and our ability to
carry out or have completed the repairs in a cost-effective or timely manner; commodity risk management; industry risk and
competition; fluctuations in the value of foreign currencies and foreign political risks; the need for additional financing and the
ability to access financing at a reasonable cost; our ability to fund our growth projects; our ability to maintain our investment
grade credit ratings; structural subordination of securities; counterparty credit risk; our ability to recover our losses through our
insurance coverage; our provision for income taxes; legal, regulatory, and contractual proceedings involving the Corporation;
outcomes of investigations and disputes; reliance on key personnel; labour relations matters; development projects and
acquisitions, including delays or changes in costs in the construction of the South Hedland power project; and the satisfactory
receipt of applicable regulatory approvals for existing and proposed operations and growth initiatives.
The foregoing risk factors, among others, are described in further detail in the Governance and Risk Management section of
this MD&A and under the heading “Risk Factors” in our 2016 Annual Information Form.
Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to
place undue reliance on these forward-looking statements. The forward-looking statements included in this document are
made only as of the date hereof and we do not undertake to publicly update these forward-looking statements to reflect new
information, future events, or otherwise, except as required by applicable laws. In light of these risks, uncertainties, and
assumptions, the forward-looking events might occur to a different extent or at a different time than we have described, or
might not occur. We cannot assure that projected results or events will be achieved.
Additional IFRS Measures and Non-IFRS Measures
An additional IFRS measure is a line item, heading, or subtotal that is relevant to an understanding of the financial statements
but is not a minimum line item mandated under IFRS, or the presentation of a financial measure that is relevant to an
understanding of the financial statements but is not presented elsewhere in the financial statements. We have included line
items entitled gross margin and operating income (loss) in our Consolidated Statements of Earnings (Loss) for the years
ended Dec. 31, 2015, 2014, and 2013. Presenting these line items provides management and investors with a measurement of
ongoing operating performance that is readily comparable from period to period.
We evaluate our performance and the performance of our business segments using a variety of measures. Certain of the
financial measures discussed in this MD&A are not defined under IFRS and, therefore, should not be considered in isolation or
as an alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from
operating activities, as determined in accordance with IFRS, when assessing our financial performance or liquidity. These
measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation or
as a substitute for measures prepared in accordance with IFRS. See the Comparable Funds from Operations and Comparable
Free Cash Flow, Discussion of Segmented Comparable Results, and Earnings and Other Measures on a Comparable Basis
sections of this MD&A for additional information.
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TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Highlights
Consolidated Financial Highlights
Year ended Dec. 31
Revenues
Comparable EBITDA(1,2)
Net earnings (loss) attributable to common shareholders
Comparable net earnings (loss) attributable to common shareholders(1)
Comparable funds from operations(1)
Cash flow from operating activities
Comparable free cash flow(1,2)
Net earnings (loss) per share attributable to common
shareholders, basic and diluted
Comparable net earnings (loss) per share(1)
Comparable funds from operations per share(1)
Comparable free cash flow per share(1,2)
Dividends declared per common share
(1)(2) (2)
As at Dec. 31
Total assets
Total credit facilities, long-term debt, tax equity,
and finance lease obligations(3), net of cash
Total long-term liabilities
2015
2,267
945
(24)
(48)
740
432
315
(0.09)
(0.17)
2.64
1.13
0.72
2015
10,947
4,441
5,704
2014
2,623
1,036
141
68
762
796
280
0.52
0.25
2.79
1.03
0.72
2014
9,833
4,013
4,504
2013
2,292
1,023
(71)
81
729
765
288
(0.27)
0.31
2.76
1.09
1.16
2013
9,624
4,305
5,337
Comparable EBITDA decreased by $91 million to $945 million compared to 2014. Excluding a $59 million adjustment to
provisions relating mostly to prior years, comparable EBITDA would have been $1,004 million. A significant part of the year-
over-year reduction in comparable EBITDA is due to Energy Marketing results during the second quarter of 2015, and lower
prices in Alberta and the Pacific Northwest. Energy Marketing delivered strong performance in 2014 because of
extraordinary conditions in the Northeast during the first quarter. Prices in Alberta averaged $33 per megawatt hour
(“MWh”) in 2015 compared $49 per MWh in 2014. Our high level of contracts and hedges mostly mitigated the impact of
low prices, but our wind and hydro businesses in Alberta were impacted. Continued improvement in our mining operations
to reduce fuel costs mitigated the impacts of lower availability in Canadian Coal during the first half of the year.
Comparable FFO decreased by $22 million to $740 million. Lower interest expenses and cash taxes offset some of the
impact from lower comparable EBITDA. The non-cash adjustment to provisions of $59 million does not impact FFO.
Comparable net loss attributable to common shareholders was $48 million ($0.17 net loss per share), down from
comparable net earnings of $68 million ($0.25 net earnings per share) in 2014. The decrease was primarily due to lower
comparable EBITDA and higher earnings attributable to non-controlling interest associated with the sale of additional
non-controlling interests in TransAlta Renewables.
(1) These items are not defined under IFRS. Presenting these items from period to period provides management and investors with the ability to evaluate earnings trends more
readily in comparison with prior periods’ results. Refer to the Comparable Funds from Operations and Comparable Free Cash Flow and Earnings and Other Measures on a
Comparable Basis sections of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.
(2) 2014 and 2013 restated to deduct hydro life extension capital expenditures from comparable FCF. Refer to the Current Accounting Changes section of this MD&A.
(3) Includes current portion.
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TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Reported net loss attributable to common shareholders was $24 million ($0.09 net loss per share) compared to net
earnings of $141 million ($0.52 net earnings per share) in 2014 and a net loss of $71 million ($0.27 net loss per share) in
2013. Reported net earnings includes the gain on the Poplar Creek contract restructuring ($192 million( 1)) and the cost of
the settlement with the Market Surveillance Administrator (the “MSA”) ($55 million(1)) in 2015. Changes in the fair value
of de-designated and economic hedges at U.S. Coal also had a negative impact on our net earnings ($38 million(1,2))
(2014 – $35 million(1,2) positive, 2013 – $67 million(1,2) negative). Deferred income tax expense was also impacted by the
increase in the Alberta corporate tax rate in June 2015 and by the sale of an economic interest in our Australian business
to TransAlta Renewables, offsetting a reversal of a writedown of deferred tax assets associated with movements in
financial instrument values. The loss in 2013 includes a $42 million(1) settlement of a prior year claim relating to power
trading activities in California, a $22 million(1) assumption of pension obligations and $19 million(1) associated with the
return to service of Sundance 1 and 2.
During 2015, credit facilities, long-term debt, and finance lease obligations increased by approximately $439 million
primarily as a result of the stronger US dollar ($392 million) and the acquisition of operating wind and solar facilities
($211 million). Increases in value resulting from the stronger US dollar were offset by corresponding increases in value of
U.S. assets as part of our hedging program. On Jan. 6, 2016, we completed a transaction with TransAlta Renewables to
sell economic interests of certain assets located in Canada and received $173 million in cash proceeds as part of the
transaction. All proceeds were used to reduce amounts borrowed under our credit facilities.
Highlights
During the year, we continued to work on strengthening our financial condition and flexibility, improve our operating
performance, and grow our portfolio of highly contracted assets through the following initiatives:
We raised over $1.0 billion of capital in 2015, including cash proceeds from sale of an economic interest of certain assets
located in Canada to TransAlta Renewables which closed on Jan. 6, 2016, to retire maturing debentures of
US$500 million and $155 million. Of the amount raised, over $575 million represents equity raised through the sale of
non-controlling interests:
•
On May 7, 2015, TransAlta Renewables acquired an economic interest in our Australian assets (the “Transaction”)
for total consideration of $1,278 million, comprised of net cash proceeds of $211 million as well as a combination of
58.3 million common shares and 26.1 million Class B shares of TransAlta Renewables.
On Nov. 26, 2015, we sold 20.5 million common shares of TransAlta Renewables to the Alberta Investment
Management Corporation (“AIMCo”), for net cash proceeds of $193 million.
On Jan. 6, 2016, TransAlta Renewables acquired an economic interest based on the cash flows of the Sarnia
cogeneration facility and of two renewable energy facilities for proceeds valued at $540 million. Net cash proceeds
of this transaction were $173 million. We also received 15.6 million common shares of TransAlta Renewables and a
$215 million convertible debenture.
•
•
We raised $442 million in long-term non-recourse debt, which is secured by three wind projects in Ontario on
Oct. 1, 2015. Project-level debt allows us to align the maturity profile of principal with the realization of value from our
assets, which will be the central piece of our financing strategy to repay debentures maturing in 2017 and 2018.
Over the last three years, we have nearly doubled the weighted average remaining contractual life of our gas fleet from
six years to 12 years. This year, we extended the contractual profile of three facilities:
• We restructured our contractual arrangements at the Poplar Creek facility, to extend the contracted cash flows
attributable to Poplar Creek from 2023 to 2030, and we also acquired two wind facilities, representing 65 megawatts
(“MW”) of capacity. As part of the restructuring, our customer acquired our steam generators and the rights to the
output of the gas generators and will assume operational control of the site. As a result of the transaction, we
recognized a finance lease of $372 million, and increased our long-term assets to reflect the acquisition of two wind
farms for $138 million. The transaction closed on Sept. 1, 2015 and we have recognized a gain of $262 million on the
transaction. The carrying amount of net assets we transferred to the counterparty was $250 million.
• We signed a new 15-year 72 MW power supply contract for our Windsor facility with Ontario’s Independent
Electricity System Operator (“IESO”), taking effect in December 2016.
(1) Net of related income tax expense.
(2) Hedge accounting could not be applied to certain contracts, and accordingly, the mark-to-market on these contracts impacted reporting earnings. The impacts of these
mark-to-market fluctuations have been removed from revenues to arrive at comparable results, which reflect the economic nature of these contracts.
M5
TRANSALTA CORPORATION M5
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
• We extended the contract for our 55 MW Parkeston power station in Australia by a period of 10 years from
November 2016.
We acquired 71 MW of fully contracted renewable generation assets for cash consideration of $106 million together
with the assumption of $105 million of project financing obligations. The assets include our first solar facilities,
representing 21 MW of capacity in Massachusetts, and one 50 MW wind farm in Minnesota. The acquisition of the solar
facilities was completed on Sept. 1, 2015, while the acquisition of the wind farm closed on Oct. 1, 2015.
We reached an agreement with the MSA to settle all outstanding proceedings before the Alberta Utilities Commission
(the “AUC”) for a total amount of $56 million. Of this amount, we paid $31 million in the fourth quarter and $25 million
will be paid in the fourth quarter of 2016.
Overhead reductions and our efficiency and productivity initiatives in Canadian Coal will contribute in excess of
$47 million in cost savings annually.
We received approval from the AUC to construct Sundance 7, an 856 MW high-efficiency natural gas-fired power plant in
Alberta. Construction of Sundance 7 will not commence until we have contracted a significant portion of the plant capacity.
In March, we successfully completed construction of the natural gas pipeline to our Solomon power station. Since then,
the pipeline has contributed $10 million to our EBITDA and FFO.
We continued to advance the construction of the South Hedland power project. Bulk earthworks and civil work were
largely completed during the year, and major equipment has been arriving on schedule. We expect the project to be
delivered on schedule and on budget in mid-2017.
On Nov. 22, 2015, the Government of Alberta announced the Alberta Climate Leadership Plan (the “Plan”). In respect of the
power generation sector, the Plan targets the retirement of coal generation in the Province of Alberta by 2030; replacement of
two-thirds of the retiring coal-fired generation with renewable generation (to achieve a 30 per cent share of generation by
2030) and one-third gas generation; and establishment of a new system of greenhouse gas (“GHG”) obligations and
allowances benchmarked against highly efficient gas-fired generation beginning in 2018, at a price of $30 per tonne. The
Government of Alberta has further stated intentions of providing compensation to coal-fired generators as part of its
commitment to treat them fairly and not unnecessarily strand capital.
On Jan. 14, 2016, we announced key actions to support our transition from coal to gas-fired and renewable generation in the
Province of Alberta and maximize our financial flexibility:
We have revised our dividend to $0.16 per common share on an annualized basis from $0.72 previously. The reduction
will reduce cash required for the dividend to approximately $45 million from approximately $205 million annually. The
revised dividend represents a 15 to 18 per cent payout of our estimated 2016 comparable FCF.
We have suspended our dividend reinvestment plan in order to stop shareholder dilution. We do not currently expect to
raise additional equity in 2016 as the incremental cash from the dividend reduction will be used to strengthen our
balance sheet and financial flexibility.
We will focus on raising non-recourse debt to fund upcoming corporate debt maturities. We expect to raise
$400 million to $600 million of project-level debt in 2016 to fund the next material debt maturity of US$400 million in
2017, and we plan to execute a similar strategy for the 2018 maturities.
We will negotiate with the Government of Alberta, using a principles-based approach, to ensure the Corporation has the
certainty and capacity needed to invest in clean power.
Over the next 15 years, we will focus on replacing coal-fired generation assets with gas-fired and renewable generation assets.
These actions, combined with initiatives completed in 2015, allow us to build the financial capacity and flexibility to address
upcoming debt maturities and capitalize on opportunities in gas-fired and renewable generation that will arise as Alberta
transitions from coal to clean power.
M6
M6 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Segmented Operational Results
Comparable EBITDA and operational performance for the business is as follows:
Year ended Dec. 31
(1)
Availability (%)
Adjusted availability (%)(2)
(1,3)
Production (GWh)
Comparable EBITDA(4)
Canadian Coal
U.S. Coal
Gas
Wind and Solar
Hydro
Energy Marketing
Corporate
Total comparable EBITDA
Management’s Discussion and Analysis
2015
88.7
89.0
2014
89.7
90.5
2013
85.5
87.8
40,673
45,002
42,482
334
67
330
176
73
37
(72)
945
389
65
312
179
87
75
(71)
1,036
311
67
332
181
148
58
(74)
1,023
1
Canadian Coal: Comparable EBITDA decreased by $55 million to $334 million in 2015, compared to $389 million in 2014
and $311 million in 2013. The 2015 EBITDA includes a $59 million adjustment to provisions relating mostly to force
majeure events for the periods between 2013 to 2015. Excluding this adjustment, 2015 comparable EBITDA would have
been $393 million, in line with 2014. Incremental reductions in operating expenses at our Highvale mine offset the
negative impact of lower availability on our comparable EBITDA. Our high level of contracts and hedges in Canadian
Coal continues to mostly offset the impact of lower prices in Alberta compared to 2014 and 2013. In 2013, the Segment
had experienced lower availability.
U.S. Coal: Comparable EBITDA was consistent with our 2014 and 2013 results as the stronger US dollar offset the
impacts of lower pricing in the Pacific Northwest.
Gas: Comparable EBITDA increased by $18 million to $330 million in 2015 compared to $312 million in 2014 and
$332 million in 2013. The increase was a result of additional revenues from the Australian natural gas pipeline and the
positive impact of the strengthening of the US dollar on a US-dollar-denominated contract in Australia. The change in value
in this contract offsets changes in value of our US-dollar-denominated debt. In 2013, the segment had benefitted from
higher Alberta pricing at the Poplar Creek facility and from the last year under a higher-priced contract at the Ottawa plant.
Wind and Solar: Comparable EBITDA was $176 million in 2015 compared to $179 million in 2014 and $181 million in
2013. The decrease in 2015 is primarily due to lower power prices in Alberta. The acquisition of additional assets in the
fourth quarter and the strengthening of the US dollar offset part of this shortfall. In 2014, incremental earnings from the
addition of the Wyoming facility had offset the decline in Alberta prices, compared to 2013.
Hydro: Comparable EBITDA decreased $14 million to $73 million in 2015 compared to $87 million in 2014 and
$148 million in 2013, due to the lower prices and a decrease in price volatility in Alberta, which limits our ability to take
advantage of our flexibility to produce electricity in higher priced hours.
Energy Marketing: Comparable EBITDA decreased by $38 million in 2015 to $37 million, compared to $75 million in
2014 and $58 million in 2013. Comparable EBITDA in the first quarter of 2014 included effects of extraordinary market
conditions caused by unusual weather in the Northeast. The decrease in 2015 is further due to volatile market conditions
in the Alberta and Pacific Northwest regions in the second quarter that negatively affected results.
Corporate: Our Corporate overhead costs have remained comparable to 2014 and 2013.
(1) Availability and production includes all generating assets (generation operations and finance leases that we operate). 2014 and 2013 availability also includes equity
investments, which were sold in May 2014.
(2) Adjusted for economic dispatching at U.S. Coal.
(3) Production includes 314 GWh in 2014 (2013 - 1,556 GWh) from CE Generation LLC and Wailuku Holding Company, LLC, both of which were sold in May 2014.
(4) 2014 and 2013 results restated to reflect the reassignment to the Corporate Segment of $12 million and $7 million, respectively, and to the Energy Marketing Segment of
$1 million and $3 million, respectively, of costs associated with certain functions that were determined to benefit the broader organization, or the Energy Marketing Segment, respectively.
M7
TRANSALTA CORPORATION M7
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Comparable Funds from Operations and Comparable Free Cash Flow
Comparable FFO and comparable FCF provide a proxy for the amount of cash generated from operating activities before
changes in working capital, and provide the ability to evaluate cash flow trends more readily in comparison with results from
prior periods. Comparable FFO per share and comparable FCF per share are calculated using the weighted average number of
common shares outstanding during the period.
(1)
Year ended Dec. 31
Cash flow from operating activities
Change in non-cash operating working capital balances
Cash flow from operations before changes in working capital
Adjustments
MSA Settlement payment and impacts associated with California claim
Decrease in finance lease receivable
Payment of restructuring costs
Maintenance costs related to Alberta flood of 2013,
net of insurance recoveries
Other non-comparable items
Comparable FFO
Deduct:
Sustaining capital
Insurance recoveries of sustaining capital expenditures
Dividends paid on preferred shares
Distributions paid to subsidiaries' non-controlling interests
Comparable FCF
Weighted average number of common shares
outstanding in the year
Comparable FFO per share
Comparable FCF per share
2015
432
242
674
31
23
19
(9)
2
740
(305)
25
(46)
(99)
315
280
2.64
1.13
2014
Restated (1)
2013
Restated (1)
796
(73)
723
33
3
-
1
2
765
(74)
691
27
1
5
5
-
762
729
(361)
4
(41)
(84)
280
273
2.79
1.03
(349)
1
(38)
(55)
288
264
2.76
1.09
(1) Restated to include hydro life extension from growth capital expenditures to sustaining capital expenditures. Refer to the Current Accounting Changes section of this MD&A.
M8
M8 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
A reconciliation of comparable EBITDA to comparable FFO is as follows:
Year ended Dec. 31
Comparable EBITDA
Unrealized losses (gains) from risk management activities
Interest expense
Provisions
Current income tax expense
Realized foreign exchange gain
Decommissioning and restoration costs settled
Gain on curtailment and amendment of employee future benefit plans
Capital insurance recoveries on Canadian Coal facility
Flood-related maintenance costs
Other non-cash items
Comparable FFO
Management’s Discussion and Analysis
2015
945
1
(230)
73
(19)
17
(24)
(8)
(7)
-
(8)
740
2014
1,036
4
(236)
-
(33)
11
(16)
-
-
-
(4)
762
2013
1,023
(27)
(238)
19
(39)
-
(24)
-
-
5
10
729
For the year ended Dec. 31, 2015, comparable FFO decreased by $22 million to $740 million compared to 2014 mainly due to
the reduction in comparable EBITDA, partly offset by lower interest and cash taxes. Part of the reduction in EBITDA was due
to adjustments to provisions, mostly relating to a prior year. The added provision is non-cash and has no impact to our
comparable FFO in 2015. Comparable FFO was also positively impacted by the settlement of foreign exchange contracts
relating to debt maturities in 2015.
For the year ended Dec. 31, 2014, comparable FFO increased $33 million to $762 million compared to 2013. The increase in
FFO outpaced the increase in comparable EBITDA, as the prior year’s comparable EBITDA included $27 million of unrealized
risk management gains.
Comparable FCF for the year ended Dec. 31, 2015 was $315 million, compared to $280 million in 2014. The increase in
comparable FCF was mainly due to lower sustaining capital expenditures as a result of reductions in mining expenditures,
deferral of major work in Centralia as a result of economic dispatching, reductions in our gas-fired capital expenditures caused
by the Poplar Creek re-contracting and condition-based assessments, and higher insurance recoveries associated with the
flood of 2013, partially offset by the reduction in comparable FFO as well as an increase in dividends paid on preferred shares
and in distributions paid to non-controlling interests in subsidiaries.
Comparable FCF for the year ended 2014 was $280 million, down $8 million from 2013, as the increase in comparable FFO
was offset by distributions paid to TransAlta Renewables’ public shareholders and improved performance at TransAlta
Cogeneration L.P (“TA Cogen”).
M9
TRANSALTA CORPORATION M9
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Key Financial Ratios
The methodologies and ratios used by rating agencies to assess our credit rating are not publicly disclosed. We have
developed our own definitions of ratios and targets to help evaluate the strength of our financial position. These metrics and
ratios are not defined under IFRS, and may not be comparable to those used by other entities or by rating agencies. As shown
below, our key financial ratios are currently outside of our target ranges. We are focused on strengthening our financial
position and flexibility and aim to meet all our target ranges by 2018.
Comparable Funds from Operations before Interest to Adjusted Interest Coverage
Year ended Dec. 31
Comparable FFO
Add: Interest on debt net of capitalized interest
Comparable FFO before interest
Interest on debt
Add: 50 per cent of dividends paid on preferred shares
Adjusted interest
Comparable FFO before interest to adjusted interest coverage (times)
2015
2014
740
223
963
232
23
255
3.8
762
236
998
239
21
260
3.8
2013
729
238
967
240
19
259
3.7
Our target for comparable FFO before interest to adjusted interest coverage is four to five times. The ratio is comparable to
last year as the cost of funding the South Hedland project is included in our interest expense by adding back capitalized
interest to the calculation.
Adjusted Comparable Funds from Operations to Adjusted Net Debt
Year ended Dec. 31
Comparable FFO
Less: 50 per cent of dividends paid on preferred shares
Adjusted comparable FFO
(1)
Period-end long-term debt
Add: 50 per cent of issued preferred shares
Less: Cash and cash equivalents
Fair value (asset) liability of hedging instruments on debt(2)
Adjusted net debt
Adjusted comparable FFO to adjusted net debt (%)
1
2015
740
(23)
717
2014
762
(21)
741
2013
729
(19)
710
4,495
4,056
4,347
471
(54)
(190)
4,722
15.2
471
(43)
(96)
4,388
16.9
391
(42)
(16)
4,680
15.2
Our target for adjusted comparable FFO to adjusted net debt is 20 to 25 per cent. The reduction in the ratio during 2015 is due
to lower comparable FFO and the impacts of the strengthening of the US dollar on our US-dollar-denominated debt. Our
US-dollar-denominated debt is fully hedged by US-dollar-denominated assets. Net debt includes the increase in value of
financial instruments used to hedge approximately half of our US debt. The other half of our US debt is hedged with a
US-dollar-denominated financial receivable contract and by our net investment in US operations. The change in value of these
assets resulting from the strengthening of the US currency is not included in net debt; the year-over-year change in our
US-dollar-denominated net asset amount is $201 million. As at Dec. 31, 2015, net debt is also impacted by the addition of
debt resulting from the acquisition of the wind and solar facilities for $211 million. These assets were acquired in September
and October and contributed limited FFO in 2015.
(1) Includes finance lease obligations and tax equity financing.
(2) Included in risk management assets and/or liabilities on the consolidated financial statements as at Dec. 31, 2015 and Dec. 31, 2014.
M10
M10 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Adjusted Net Debt to Comparable EBITDA
Year ended Dec. 31
Period-end long-term debt
(1)
Less: cash and cash equivalents
Add: 50 per cent of issued preferred shares
Fair value (asset) liability of hedging instruments on debt(2)
Adjusted net debt
Comparable EBITDA
Adjusted net debt to comparable EBITDA (times)
1
Management’s Discussion and Analysis
2015
4,495
(54)
471
(190)
4,722
945
5.0
2014
4,056
(43)
471
(96)
4,388
1,036
4.2
2013
4,347
(42)
391
(16)
4,680
1,023
4.6
Our target for adjusted net debt to comparable EBITDA is 3.0 to 3.5 times. During 2015, our ratio deteriorated compared to
Dec. 31, 2014, mainly as a result of lower comparable EBITDA during the period and the strengthening of the US dollar.
Sustainability Performance
Sustainability targets are strategic goals that support the long-term success of our business. Targets are set in line with
business unit goals to manage key areas of concern for stakeholders and ultimately improve our environmental and social
performance in these areas.
On a go-forward basis we are integrating our sustainability measures into this MD&A.
Financial
Results
Comments
2015 Sustainability Targets
1. Maintain our
investment
grade rating
Continue to maintain our investment
grade credit rating.
Partly achieved
2. Increase
focus on FFO
and EBITDA
TransAlta Corporation targets comparable
EBITDA and comparable FFO for 2015 in the
range of $1,000 million to $1,040 million and
$720 million to $770 million respectively.
Partly achieved
TransAlta maintains investment grade ratings
with stable outlooks from three rating agencies:
S&P (BBB-), DBRS (BBB), and Fitch (BBB-). On
Dec. 17, 2015, Moody's reduced our rating to Ba1.
For the year ended December 31, 2015, comparable
EBITDA was $945 million and comparable FFO was
reported at $740 million. Comparable EBITDA
includes an adjustment of provisions relating to prior
year events in the amount of $59 million.
3. Customers
Grow our offering of products and services to
Alberta electricity consumers as the Alberta
PPAs expire to match customer power needs
with TransAlta’s competitive generation.
Achieved
In 2015 we successfully launched a new product to a
specific segment of our customer base that offers the
customers flexibility and some price certainty without
locking them in to a fixed-price, long term agreement.
(1) Includes finance lease obligations and tax equity financing.
(2) Included in risk management assets and/or liabilities on the consolidated financial statements as at Dec. 31, 2015 and Dec. 31, 2014.
M11
TRANSALTA CORPORATION M11
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Power Generating Portfolio
4. Grow asset
portfolio
Grow comparable EBITDA by
$40 million to $60 million.
Results
On track
5. Achieve
top quartile
performance
within the industry
Continue to deliver 88-90 per cent
availability.
Achieved
Comments
In 2015, TransAlta purchased long-term contracted
solar and wind assets expected to add approximately
$20 to $25 million of incremental EBITDA in 2016 and
commissioned the Fortescue River Gas Pipeline, which
is expected to add approximately $10 million of
EBITDA on an annualized basis. TransAlta also
continues to advance the construction of the South
Hedland power project, on budget and on-time. This
project is expected to be commissioned in mid-2017
and add approximately $80 million of incremental
annualized EBITDA.
We achieved adjusted availability in 2015 of 89.0 per
cent, compared to 90.5 per cent in 2014, and higher
than our target of 88 to 90 per cent. Availability is
adjusted for economic dispatching at Centralia.
6. Minimize
fleet-wide
safety incidents
Human and Intellectual
Strive for combined IFR(1) below 0.90 in 2015,
which is a 10 per cent improvement over the
2014 target.
Results
Achieved
Comments
IFR was 0.75, the best ever in our history.
7. Human
Resources
a) Maintain a voluntary turnover percentage
under 8 per cent in 2015.
Achieved
Turnover was 5 per cent in 2015.
b) Achieve 100 per cent completion of
development plans for all high-potential
employees at the top three levels of the
organization in 2015.
c) Maintain a 100 per cent completion rate
on new hire onboarding.
d) The time to fill vacant position rate
remains lower than 60 days for recruiting.
Partly achieved
88 per cent of our employees have
development goals.
Partly achieved
94 per cent completion rate.
Achieved
54 days was the average to fill vacant positions.
1
(1) Injury Frequency Rate (“IFR”) is defined as the number of lost-time and medical injuries for every 200,000 hours worked.
M12
M12 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Environmental
8. Minimize
fleet-wide
environmental
incidents
Keep recorded incidents (including spills and
air infractions) below 18 in 2015, which is a
10 per cent improvement over the 2014
target.
Results
Achieved
Comments
12 recorded incidents in 2015.
9. Mine
reclamation
Maintain annual topsoil replacement rate at
Highvale Mine of 74 acres/year.
Partly achieved
Replaced topsoil on 65 acres in 2015 due to warm
conditions during winter.
10. Maximize by-
product revenue
opportunities
a) Recycle a minimum of two million tonnes
of coal by-product materials during the
period 2015 to 2017.
On track
Recycled approximately 700,000 tonnes of coal by-
products (fly ash, cenosphere, bottom ash, and
gypsum) in 2015.
b) Recycle 2,000 tonnes of scrap metal
materials in 2015.
Partly achieved
Recycled close to 1,000 tonnes.
11. Promoting
biodiversity
Install bird and bat habitat improvements at
Alberta wind facilities in 2015.
Achieved
• Ferruginous hawk nest platform was installed at
Soderglen in March.
• 16 bluebird nest boxes were installed at Soderglen in
April.
• Bat houses were installed at the Pincher Creek and
Fort Macleod yards in December.
12. Air emissions
management
a) 95 per cent reduction from 2005 levels of
TransAlta coal facility NOx and SO2
emissions by 2030.
On track
We are on track to achieve this target in 2030.
b) 20 per cent reduction from 2005 levels by
2021, or the equivalent of 7,000,000 tonnes,
of CO2e per year.
c) 55 per cent reduction from 2005 levels by
2030, or the equivalent of 19,700,000
tonnes, of CO2e per year.
On track
We are on track to achieve this target in 2021.
On track
We are on track to achieve this target in 2030.
13. Water
Management
a) Enter into a permanent agreement with
the Government of Alberta to manage water
on the Bow River to aid in potential flood
mitigation in 2016.
On track
On track. The Alberta government is still modelling
potential solutions and we are waiting for its
information to proceed.
b) Complete third party assurance of
TransAlta water consumption and discharge
in 2015.
Achieved
We completed a successful third party assurance of
water consumption data and processes with
Ernst&Young in 2015.
14. Environmental
Management
Systems (EMS)
Successfully self-audit each wind operations
site against the Operations Environmental
Management Plans created in 2014.
On track
All sites except for our Quebec and New Brunswick
wind farms were audited. We have made good
progress in this area. In 2015 a challenging economic
climate forced us to implement a travel freeze, which
stalled progress on our eastern Canadian sites as
travel is required.
M13
TRANSALTA CORPORATION M13
TransAlta Corporation | 2015 Annual Integrated Report Management’s Discussion and Analysis
15. Stakeholder
Engagement
Local Communities
The TransAlta Stakeholder Engagement
Framework ("SHEF") implementation plan
will be finalized in the first half of 2015, which
will be followed by the completion of short-
term SHEF actions such as internal
stakeholder mapping. Full implementation of
the SHEF will be completed in 2016.
Results
Achieved
Comments
SHEF was finalized in 2015 and high level internal
stakeholder mapping exercise was completed.
16. Community
Involvement
Increase by 2 per cent the number of
company-sponsored volunteering
opportunities in 2015.
Not achieved
In 2014, employees volunteered approximately 3,400
hours; in 2015 the total was below 2,500 hours.
Company restructuring in 2015 reduced the pool of
potential volunteers and expectations were adjusted
accordingly.
17. Aboriginal
Relations
In 2015 TransAlta will increase the quantity
and quality of engagement with First Nation
communities by improving internal systems
that will allow for feedback and tracking of
engagement activities. By 2017, TransAlta is
targeting to achieve gold-level designation in
the Canadian Council for Aboriginal
Bussiness's Progressive Aboriginal Relations
certification program.
Achieved
Created tracking forms for all engagement, which
helped to ensure TransAlta meets both community
and regulatory commitments.
18. Reporting
Comprehensive
Achieve year-over-year improvement in the
Carbon Disclosure Project ("CDP") by
scoring a 90 or greater in 2015.
Results
Achieved
Comments
TransAlta scored 100 in 2015 and was added to the
CDP Climate Disclosure Leadership Index
(representing the top 20 performing companies in
Canada)
19. Supply Chain
Management
(SCM)
In 2015, make available sustainability clauses
for optional inclusion into standard TransAlta
request for proposal template and terms and
conditions for supplier agreements.
Achieved
Increased focus on suppliers to meet sustainability
standards
M14
M14 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report Management’s Discussion and Analysis
Business Model and Competitive Forces
We are one of Canada’s largest publicly traded power generators with over 105 years of operating experience. We own,
operate, and manage a highly contracted and geographically diversified portfolio of assets representing nearly 9,000 MW of
gross generating capacity and use a broad range of generation fuels comprised of coal, natural gas, water, sun, and wind. Our
energy marketing operations maximize margins by securing and optimizing high-value products and markets for ourselves
and our customers in dynamic market conditions.
Vision and Values
Our vision is to be a leading clean energy company, utilizing our expertise, scale, and diversified fuel mix to capitalize on
opportunities in our core markets and growing in areas where our competitive advantage can be employed.
Our values are grounded in accountability, integrity, sustainability, safety, and people which create a strong corporate culture
and allow all of our people to work on a common ground and understanding; these values are at the heart of our success.
Strategy for Value Creation
Our goals are to deliver solid returns by developing and operating assets in our three regions and among four fuel types. By
2030, our fleet will be fully transitioned from coal to natural gas and renewables. We maximize value by contracting assets,
achieving strong availability, and aiming for first-quartile costs. Our Energy Marketing group adds value to merchant assets
through optimization. We develop new greenfield projects and undertake merger and acquisition activities to ensure growth
of cash flows over the long term. The transition from coal to gas and renewables provides significant opportunity for growth in
the future. In 2013, we launched TransAlta Renewables, our sponsored vehicle to own contracted gas and renewable assets.
Regional Competitive Environments
Demand and supply balances are the fundamental drivers of prices for electricity. Underlying economic growth is the main
driver of longer-term changes in the demand for electricity, whereas system capacity, natural gas prices, GHG pricing,
government subsidies, and renewable resource availability are key drivers to the supply. Growth in mining investment is key to
developing our Australian business.
Renewable capacity addition has been strong for the past several years due to government incentives. New supply in the near
term and intermediate term is expected to come primarily from investment in renewable energy as well as natural gas-fired
generation. This expectation is driven by the low prices in the natural gas market combined with public policies that favour
carbon emission reductions.
We have substantial merchant capacity in Alberta and the Pacific Northwest. In those regions, we enter into contracts and
business relationships with commercial and industrial customers to sell power on a long-term basis, up to our available
capacity in the markets. We further reduce the portion of production not sold in advance through short-term physical and
financial contracts, and optimize production in real time against our position and market conditions.
We also compete for long-term contracted opportunities in renewable and gas power generation, including cogeneration,
across Canada, the United States, and Australia. Our target customers in this area are incumbent utility providers and large
industrial and mining operators.
M15
TRANSALTA CORPORATION M15
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Alberta
Approximately 60 to 65 per cent of our capacity is located in
Alberta and more than 65 per cent of it is subject to legislated
Alberta PPAs, which were put in place in 2001 to facilitate the
transition from regulated generation to the current energy market
in the province. Alberta PPAs expire at the end of 2017 (Sundance
1 and 2) and the end of 2020 (Keephills 1 and 2, Sundance 3 to 6,
Sheerness, and Hydro). Coal generation sold under Alberta PPAs
retain some exposure to market prices as we pay penalties or
receive payments for production below or above, respectively, targeted availability based upon a rolling 30-day average of
spot prices. We can also retain proceeds from the sale of energy and ancillary services in excess of obligations on our Hydro
Alberta PPAs (“hydro peaking”). We enter into financial contracts to reduce our exposure to variable power prices for the
significant portion of our remaining generation.
Following the decrease in oil prices, Alberta’s annual average demand growth increased by less than one per cent in 2015
compared to 2014. Concurrently over 2014 and 2015, approximately 1,200 MW of gas generation capacity and approximately
350 MW of wind capacity were added to the market, resulting in a large decrease in power prices, impacting mostly merchant
wind and hydro peaking, which are the portions of our portfolio we cannot effectively hedge.
Our current share of offer control in the province is approximately 11 per cent. After expiry of the PPAs in 2021, our share of
offer control is forecast to increase to approximately 23 to 25 per cent depending on load growth in the province and
excluding Sundance 7.
Alberta’s Climate Leadership Plan, recently announced by the provincial government, may alter Alberta’s competitive
landscape. Currently, the marginal cost of generating power from coal is generally most competitive over alternate sources,
excluding renewables and must-run cogeneration. If implemented as planned, after the carbon pricing and allowance rules
enter into effect in 2018, we expect the incremental cost to coal generation could increase significantly and the production
from coal plants could be dispatched after highly efficient combined-cycle gas sources, potentially resulting in lower coal
production and reduced margins. Power demand growth could also decrease as a result of energy efficiency initiatives. We
expect that the financial impact of the anticipated decrease in our coal production volumes and higher compliance costs could
be partially offset by power price increases, as well as higher benefits from allowances generated by our renewable sources.
Until 2020, the impact of carbon prices is limited due to the pass-through of compliance costs to buyers under the legislated
Alberta PPAs at contracted plants.
The government is appointing a negotiator to ensure that the 14-year transition away from coal does not spike power prices,
impact system reliability, or unnecessarily strand capital. We will be better able to assess the impact of legislation on the
Alberta market after these negotiations are finalized in the 2016 and 2017 timeframe.
We expect that the elimination of current excess system capacity and future growth in Alberta will be primarily driven by the
retirement of coal units over the next 15 years. Alberta’s Climate Leadership Plan projects the replacement of two-thirds of
coal production through renewable sources and one-third through gas. We believe that our extensive portfolio of assets
provides us with brownfield development opportunities in wind, solar, hydro, and gas that provides us a cost advantage over
competitors for construction of new builds.
M16
M16 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
U.S. Pacific Northwest
Our capacity in the U.S. Pacific Northwest is comprised of our 1,340 MW Centralia coal plant. Half of the plant capacity is set
to retire at the end of 2020, and the other half at the end of 2025.
System capacity in the region is primarily comprised of hydro and gas generation, with some wind additions over the last few
years in response to government programs favouring renewable generation. Demand growth in the region has been limited,
and further constrained by emphasis on energy efficiency. Our coal plant can effectively compete against gas generation,
although depressed gas prices following the expansion of shale gas production in North America has added to the downward
pressure on power prices.
Our competitiveness is enhanced by our long-term contract with Puget Sound Energy for up to 380 MW over the remaining
life of the facility. The contract and our hedges allow us to satisfy power requirements from the market when prices fall below
our marginal costs of production.
We maintain an opportunity to redevelop Centralia as a gas plant after coal capacity retires, with permitting provided by our
agreement for coal transition established with the State of Washington in 2011.
Contracted Gas and Renewables
The market for development or acquisition of gas and renewable generation facilities is highly competitive in all markets in
which we operate. Our solid record as operator and developer supports our competitive position. We expect, where possible,
to reduce our cost of capital and improve our competitive profile by using project financing and leveraging the lower cost of
capital with TransAlta Renewables. In the United States, our substantial tax attributes further increase our competitiveness.
While depressed commodity prices have reduced sectoral growth in the oil, gas, and mining industries, the change is also
creating opportunities for us as a service provider as some of our potential customers are more carefully evaluating non-core
activities and driving for operational efficiencies. In renewables, we are primarily evaluating greenfield opportunities in
Western Canada or acquisitions in other markets in which we have existing operations. We maintain highly qualified and
experienced development teams to identify and develop these opportunities.
Some of our older gas plants are now reaching the end of their original contract life. The plants generally have a substantial
cost advantage over new builds and we have been able to add value by re-contracting these plants with limited life-extending
capital expenditures. We have recently extended the life of our Ottawa, Windsor, and Parkeston plants in this manner.
M17
TRANSALTA CORPORATION M17
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
TransAlta’s Capitals
The following discusses TransAlta’s main categories of capital, being Financial, Power Generating Portfolio, Human and
Intellectual, and Environmental and Local Communities.
Financial Capital
Sources of Capital
Our goal over the last 18 months was to build financial flexibility by using multiple sources of funding to reposition our capital
structure. Over the last few years, the rating of our unsecured debt was put under pressure by all the rating agencies1. We
responded to this pressure by taking significant action starting in 2014 and through to today to reduce our indebtedness and
work on strengthening our financial metrics. Since the end of 2013, senior unsecured debt has been reduced by over
$800 million, including a reduction of over $500 million on our credit facility and a $300 million reduction in Canadian and
US bonds. Over the next three years, we plan to continue on this path by replacing $1.2 billion of maturing recourse debt with
non-recourse debt secured by certain projects.
On Dec. 17, 2015, Moody’s lowered the rating of our senior unsecured debt to Ba1 with a stable outlook. As expected, the
direct financial impact of this downgrade has been limited. We have posted additional collateral of nearly $100 million to
certain counterparties, and the cost of borrowing under our credit facilities and US$400 million of debt has been stepped-up
in line with contractual provisions. These costs have been integrated into our 2016 financial outlook. We have investment
grade ratings with stable outlooks from each of DBRS, S&P, and Fitch Ratings. We remain focused on maintaining these
ratings, as strengthening our financial position allows our commercial team to contract our portfolio with a variety of
counterparties on terms and prices that are favourable to our financial results, and provides us with better access to capital
markets through commodity and credit cycles. Risks associated with further reductions in our credit ratings are discussed in
the Liquidity Risk section of this MD&A.
(1) As at Dec. 31, 2015, our senior unsecured debt is rated as investment grade by three rating agencies: BBB (stable), BBB- (stable), and BBB- (stable) by DBRS, Standard and
Poor’s (“S&P”), and Fitch Ratings (“Fitch”), respectively, and Ba1 (stable) by Moody’s Investors Services (“Moody’s”). Our preferred shares are rated P-3 and Pfd-3 by S&P
and DBRS, respectively. Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities. The credit ratings accorded to
our outstanding securities by DBRS, S&P, Moody's, and Fitch, as applicable, are not recommendations to purchase, hold, or sell such securities inasmuch as such ratings do
not comment as to market price or suitability for a particular investor. There is no assurance that the ratings will remain in effect for any given period or that a rating will not
be revised or withdrawn entirely by DBRS, S&P, Moody's, or Fitch in the future if, in its judgment, circumstances so warrant. See the Liquidity Risk section of this MD&A.
M18
M18 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Capital Structure 12
Our capital structure consisted of the following components as shown below:
As at Dec. 31
Net debt
Recourse debt - CAD debentures
Recourse debt - U.S. senior notes
Net credit facilities and other(1)
Total recourse debt
Non-recourse debt
Finance lease obligations
Total net debt
Non-controlling interests
Equity attributable to shareholders
Common shares
Preferred shares
Contributed surplus, deficit, and
Accumulated Other Comprehensive Loss
Total capital
2015
$
1,044
2,221
138
3,403
766
82
4,251
1,029
3,075
942
%
12
26
2
40
9
1
50
12
35
11
(656)
8,641
(8)
100
2014
$
1,043
2,444
(24)
3,463
380
74
3,917
594
2,999
942
(657)
7,795
%
13
31
-
44
5
1
50
8
38
12
(8)
100
2013
$
1,269
1,797
822
3,888
376
25
4,289
517
2,913
781
(788)
7,712
%
17
23
11
51
5
-
56
6
38
10
(10)
100
During 2014 and 2015, we have reduced our corporate senior debt and the amount drawn on our credit facility, primarily through
the sale of non-controlling interests, issuance of project-level debt, divestiture of our equity investments, and the issuance of
preferred shares. The strengthening US dollar added approximately $325 million to our recourse debt over the two-year period,
net of the gain in fair value assets of the derivative hedging instruments on debt. Part of our US-dollar-denominated debt is also
hedged using a US-dollar-denominated financial receivable contract and by our net investment in U.S. operations. During 2015,
we also added $211 million of debt as part of the acquisition of the two renewable projects in the U.S.
The following graph shows the evolution of recourse debt, including credit facilities and tax equity obligations, versus
non-recourse debt, including finance lease obligations, as well as the cumulative effect of foreign exchange:
(1) Includes cash, tax equity financing, and fair value assets of hedging instruments on debt.
M19
TRANSALTA CORPORATION M19
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Over the last two years, the changes in our US-dollar-denominated debt were offset as follows:
For the year ended Dec. 31
Effects of foreign exchange on carrying amounts of U.S. operations
(net investment hedge) and finance lease receivable
Foreign currency cash flow hedges on debt
Economic hedges and other
Total
2015
2014
201
183
8
392
84
79
11
174
On Jan. 15, 2015, our US$500 million 4.75 per cent senior notes matured. On Sept. 1, 2015, $120 million in 5.33 per cent non-
recourse debentures matured. These amounts and were paid out using existing liquidity.
On Oct. 1, 2015, a subsidiary of TransAlta Renewables closed a $442 million bond offering, which is secured by a first-ranking
charge over the subsidiary’s wind farms. The bonds are non-recourse to TransAlta, amortizing, and bear interest at a rate of
3.8 per cent, payable semi-annually and mature on Dec. 31, 2028. Net proceeds of the financing were used to reduce our
balance on the credit facility. On Feb 11, 2015, we also refinanced our $35 million 5.28 per cent Pingston non-recourse debt
with a $45 million 2.95 per cent non-recourse bond due in full in 2023. We also added $105 million of non-recourse debt
relating to the acquisitions of two renewable facilities in the U.S.
The following graph shows our debt maturity schedule as at Dec. 31, 2015, excluding credit facilities, finance lease obligations,
and other debt.
Over the next three years, we have approximately
$1.6 billion of recourse and non-recourse debt maturing. We
will refinance some of these upcoming debt maturities by
raising debt secured by some of our contracted assets in
Canada and the U.S. We are also expecting to continue our
de-leveraging strategy and most of our free cash flow over
the next three years, after funding of the South Hedland
project, will be allocated to debt reduction.
Our credit facilities provide us with significant liquidity. At Dec. 31, 2015, we had a total of $2.2 billion (2014 - $2.1 billion) of
committed credit facilities, of which $1.3 billion (2014 - $1.6 billion) was not drawn. We are in compliance with the terms of the
credit facility and all undrawn amounts are fully available. At Dec. 31, 2015, the $0.9 billion (2014 - $0.5 billion) of credit utilized
under these facilities was comprised of actual drawings of $0.3 billion (2014 - $0.1 billion) and letters of credit of $0.6 billion
(2014 - $0.4 billion). These facilities are comprised of a $1.5 billion committed syndicated bank facility expiring in 2019, and four
bilateral credit facilities expiring in 2017. We anticipate renewing these facilities, based on reasonable commercial terms, prior to
their maturities.
M20
M20 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Working Capital
Including the current portion of long-term debt, the excess of current assets over current liabilities was $311 million as at
Dec. 31, 2015 (2014 - $472 million - excess of current liabilities over current assets). The primary change relates to the timing
of the classification of long-term debt as current. Excluding the current portion of long-term debt, the excess of current assets
over current liabilities as at Dec. 31, 2015, was $383 million (2014 - $266 million). The increase is primarily due to the
assumption of a new finance lease receivable resulting from the Poplar Creek restructuring ($48 million), and timing of
payments and accruals.
Share Capital
On Feb. 17, 2016, we had 287.9 million common shares outstanding, and 12.0 million Series A, 11.0 million Series C, 9.0 million
Series E, and 6.6 million Series G preferred shares outstanding. Preferred shares support our financial position as only half of
their balance is generally considered as debt by credit rating agencies.
The following tables outline the common and preferred shares issued and outstanding:
As at Dec. 31
Common shares issued and outstanding, end of year
Preferred shares
Series A
Series C
Series E
Series G
Preferred shares issued and outstanding, end of year
2015
Number of
shares (millions)
2014
Number of
shares (millions)
284.0
275.0
12.0
11.0
9.0
6.6
38.6
12.0
11.0
9.0
6.6
38.6
Non-Controlling Interests
As of Dec. 31, 2015, we own 66.6 per cent (2014 - 70.3 per cent) of TransAlta Renewables. TransAlta Renewables is a publicly
traded company listed on the Toronto Stock Exchange under the symbol “RNW”. We also own 50.01 per cent of TA Cogen,
which owns, operates, or has an interest in four natural gas-fired facilities and one coal-fired generating facility. Since we own
a controlling interest in TA Cogen and TransAlta Renewables we consolidate the entire earnings, assets, and liabilities in
relation to those assets.
TransAlta Renewables has been the cornerstone of our funding strategy over the last three years, starting with its formation
with some of TransAlta’s wind and hydro assets in mid-2013. TransAlta Renewables forms a diversified, highly contracted
portfolio of assets with comparatively lower carbon intensity. The stable and predictable cash flows generated by these assets
has attracted favourable equity valuations from investors, allowing TransAlta to raise equity capital.
M21
TRANSALTA CORPORATION M21
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
In November 2015, we sold 20.5 million common shares of TransAlta Renewables in a private placement to AIMCo for net
cash consideration of $193 million. During 2015, we initiated two transactions with TransAlta Renewables with concurrent
public equity offerings by TransAlta Renewables:
On May 7, 2015, we completed the sale of an economic interest in our Australian assets to TransAlta Renewables. The
Australian assets consist of six operating assets with an installed capacity of 425 MW, the 150 MW South Hedland
project currently under construction, as well as the recently commissioned 270 kilometre gas pipeline, for total
consideration of $1.78 billion. At the closing of the Transaction, TransAlta Renewables paid the Corporation $217 million
in cash as well as approximately $1,067 million through a combination of common shares and Class B shares in
TransAlta Renewables. TransAlta Renewables has also committed to funding the costs to construct the South Hedland
project incurred after Jan. 1, 2015, representing an estimated amount of $491 million. TransAlta Renewables funded the
cash proceeds through the public issuance of 17,858,423 common shares at a price of $12.65 per share.
On Jan. 6, 2016, we completed the sale of an economic interest of the 506 MW Sarnia cogeneration facility and of two
renewable energy facilities with total capacity of 105 MW for $540 million. Consideration received from TransAlta
Renewables consisted of gross proceeds from a public offering of 17,692,750 common shares at $9.75 per share for
gross proceeds of $173 million, 15.6 million common shares of TransAlta Renewables with a value of $152 million, and a
$215 million unsecured subordinated debenture convertible into common shares of TransAlta Renewables at a price of
$13.16 per common share upon maturity on Dec 31, 2020. After completing this transaction, we own 64 per cent of
TransAlta Renewables.
We remain committed to maintaining our position as the majority shareholder and sponsor of TransAlta Renewables with a
stated goal of maintaining our interest between 60 to 80 per cent.
Returns to Providers of Capital
Net Interest Expense
The components of net interest expense are shown below:
Year ended Dec. 31
Interest on debt
Capitalized interest
Interest on finance lease obligations
Other
Accretion of provisions
Net interest expense
2015
228
(9)
4
7
21
251
2014
238
(3)
1
-
18
254
2013
240
(2)
-
-
18
256
For the year ended Dec. 31, 2015, net interest expense decreased compared to 2014, primarily due to the reduction in debt
during the year and lower interest rates on debt that was refinanced, coupled with higher capitalized interest. Higher interest
expense on foreign-denominated debt due to strengthening of the US dollar and other interest expense associated with the
adjustment to provisions have partially offset these decreases.
In 2014, net interest expense decreased compared to 2013, primarily due to the approximate $500 million reduction in debt
during the year and lower interest rates on debt that was refinanced. Higher interest expense due to strengthening of the US
dollar had partially offset these decreases.
M22
M22 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Dividends to Shareholders
During the year ended Dec. 31, 2015, 9.0 million (2014 - 6.8 million) common shares were issued to shareholders that elected
dividend reinvestment, for a total of $76 million (2014 - $85 million).
On Jan. 14, 2016, we announced the resizing of our common share dividend from $0.72 annually to $0.16 annually and the
suspension of the Premium DividendTM, Dividend Reinvestment and Optional Common Share Purchase Plan effective
immediately. These actions were taken as part of a plan to maximize our long-term financial flexibility. Declaration of
dividends is at the discretion of the board of directors of TransAlta (the “Board”).
On Feb. 16, 2016, we declared a quarterly dividend of $0.04 per share on common shares, payable on April 1, 2016 and a
quarterly dividend of $0.2875 per share on the Series A and Series C preferred shares, $0.3125 per share on the Series E
preferred shares, and $0.33125 per share on the Series G preferred shares, all payable on March 31, 2016.
Non-Controlling Interests
Comparable earnings attributable to non-controlling interests for the year ended Dec. 31, 2015 increased $31 million to
$80 million compared to 2014, primarily due to the additional common shares issued to the public in relation to the Australia
portfolio dropdown in addition to higher earnings of TransAlta Renewables on a larger asset base.
In 2014, comparable earnings attributable to non-controlling interests increased $20 million compared to 2013, primarily due
to the formation of TransAlta Renewables and increased public ownership.
Collectively, the two transactions effected in 2015 and early 2016 have allowed TransAlta Renewables to increase its dividend
by approximately 14 per cent over 2015, with a further six to seven percent increase expected upon commissioning of the
South Hedland project. This corresponds to an average annual increase of approximately six per cent between the 2013 Initial
Public Offering to mid-2017. Through our majority ownership of TransAlta Renewables, we are the primary beneficiary of
these increases.
Ability to Deliver Financial Results
The metrics we are using to track our performance are comparable EBITDA, comparable FFO and comparable FCF. The
following table compares target to actual amounts for each of the three past fiscal years:
1
Year ended Dec. 31
Comparable EBITDA
Comparable FFO
Comparable FCF
(1)
Target
Actual
Target
Actual
Target
Actual
2015
2014
2013
1,000 to 1,040
1,015 to 1,065
Not applicable
945
720 to 770
740
1,036
743 to 793
762
1,023
800 to 900
729
265 to 270
274 to 324
Not applicable
315
280
288
The adjustment to the provision recognized at Dec. 31, 2015, mostly related to prior year events, caused the departure from
the guidance. Before this adjustment was made, comparable EBITDA in 2015 was trending to the low end of the range, as a
result of much lower prices in Alberta and the Pacific Northwest impacting our merchant generation. Our commodity risk
management strategy is designed to protect us from short-term price variations. However, it is challenging to efficiently hedge
our Alberta wind portfolio. Although our hydro portfolio is substantially all contracted, the Alberta hydro PPA allows us to
benefit from price volatility in a low price and volatile price environment; however, we were not able to capture the value of
this flexibility.
(1) 2014 and 2013 restated to deduct hydro life extension capital expenditures from comparable FCF. Refer to the Current Accounting Changes section of this MD&A. Target
range boundaries for 2014 have been adjusted by an amount equal to the change in reported amount.
M23
TRANSALTA CORPORATION M23
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Power Generating Portfolio
Our power generating portfolio is comprised of our fleet of power generating and related assets as well as our finance leases.
We monitor availability closely as a key metric to delivering the required production to meet our contractual obligations and
achieve financial targets. Over the short term and medium term, we adjust our maintenance and sustaining capital
expenditures to optimize financial returns on our investments. We benchmark our performance against peers with the
objective to rank within the first quartile. Over the long term, we adjust our growth capital expenditures to align with our
strategic orientations.
Availability and Production
Our adjusted availability target was 89 to 91 per cent for 2015.
Our availability in 2015, after adjusting for economic dispatching at
U.S. Coal, was 89.0 per cent (2014 - 90.5 per cent; 2013 - 87.8 per
cent). Lower availability for the year ended Dec. 31, 2015 compared
to last year was due to higher unplanned outages and derates at Canadian Coal. On March 17, 2015, an unplanned outage began
at our 395 MW Keephills Unit 1 facility due to a damaged superheater. The unit returned to service on May 17, 2015.
Following the establishment of the plan to return the unit to service and the review of the causes of the outage, we gave notice
under the PPA to the PPA buyer and the Balancing Pool of a “High Impact Low Probability” force majeure event. In the event of
a force majeure event, we are entitled to continue to receive our PPA capacity payment and are exempted, under the terms of
the PPA, from having to pay availability penalties. We expect the counterparty to the PPA to disagree with our determination
that the event qualifies as a force majeure and we recorded a provision to reflect a potential outcome. The costs incurred as a
result of the event was mostly covered by insurance. Consequently, the outage did not have a material financial impact on our
results in 2015.
Production for the year ended Dec. 31, 2015 decreased 4,329
gigawatt hours (“GWh”) compared to 2014, primarily due to lower
availability at our Canadian Coal plants, and increased periods of
lower prices in the Pacific Northwest where it was more economical
to supply our contractual obligation by buying power in the market.
Additionally, the Poplar Creek restructuring deal resulted in lower
production, as the facility is now outside our operational scope.
Production for the year ended Dec. 31, 2014 increased 2,520 GWh compared to 2013, primarily due to a full year of
contribution from Sundance Units 1 and 2, which returned to service in the second half of 2013, as well as the return to service
of Keephills Unit 1, which was unavailable for seven months in 2013.
M24
M24 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Operational
We continuously drive for the cost-effective operation of our facilities. In 2015, we announced the elimination of positions to
reduce our costs. This company-wide initiative is expected to result in annual cost savings in excess of $47 million annually.
In the generation segments, our operations, maintenance, and administration (“OM&A”) costs reflect the cost of operating
our facilities. These costs can fluctuate due to the timing and nature of planned and unplanned maintenance activities. The
remainder of OM&A costs reflects the cost of day-to-day operations. The following table outlines our generation comparable
OM&A over the last three years:
Generation comparable OM&A
2015
418
2014
433
2013
417
Our goal is to reduce our OM&A through cost control and targeted productivity initiatives. We have established long-term
service agreements with third-party suppliers to reduce these costs, as well as maintenance-related sustaining capital costs.
We regularly benchmark our performance against peers to measure our progress. OM&A costs decreased in 2015 due to
changes in operational scope in the Gas segment, with the benefits of the cost-saving initiatives beginning to be realized.
During 2013, OM&A costs were lower due to Sundance Units 1 and 2 returning to service late in the year.
In Canadian Coal, costs associated with our Highvale mine form part of our cost of fuel. In addition to the impact of the
reduction in the number of positions, we have driven reductions in coal costs through improved mine design sequence,
reduced equipment requirements, and optimized contractor usage. Since insourcing the activity in 2013, coal costs per tonne
have decreased by 15 per cent, from approximately $27 to $23.
Sustaining Capital
We are in a long-cycle, capital-intensive business that requires significant capital expenditures. Our goal is to undertake
sustaining capital that ensures our facilities operate reliably and safely over a long period of time. Sustaining capital also
includes capital required following the 2013 flood in Alberta, most of which is recoverable from third parties.
Year ended Dec. 31
Routine capital
Mine capital
Planned major maintenance
Finance leases
Flood-recovery capital
Total sustaining capital expenditures
Insurance recoveries of sustaining capital expenditures
Net amount
Lost production as a result of planned major maintenance is as follows:
Year ended Dec. 31
(2)
GWh lost
12
2015
101
25
162
13
301
4
305
(25)
280
2014
Restated (1)
2013
Restated (1)
135
45
162
10
352
9
361
(4)
357
133
53
153
9
348
1
349
(1)
348
2015
1,409
2014
1,519
2013
1,154
(1) Restated to include hydro life extension from growth capital expenditures to sustaining capital expenditures. Refer to the Current Accounting Changes section of this MD&A.
(2) Lost production excludes periods of planned major maintenance at U.S. Coal, which occur during periods of economic dispatching.
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Management’s Discussion and Analysis
In 2015, routine capital decreased due to the transfer of our Poplar creek facility and condition-based assessments at our
Ontario gas-fired generating stations. Routine capital also included additional expenditures on capital spares and the Keephills
ash solutions project in 2014. The mine capital expenditure was lower in 2015 as 2014 included significant expenditure on
development activities of a new mining area. Finance lease costs increased primarily due to the strengthening of the US dollar
in 2015. Planned major maintenance costs remained stable in 2015 compared to 2014 as scope changes offset the
improvement in efficiency of our major turnaround costs in Canadian Coal. On Nov. 14, 2014, we entered into an agreement
with Alstom to provide major maintenance for our Canadian Coal facilities. The agreement relates to 10 major maintenance
projects over the subsequent three years at our Keephills and Sundance plants. It also expands Alstom’s current scope of
work to service critical power assets, including boilers, steam turbines, generators, and other plant equipment. Alstom will be
accountable for providing its services on budget and on time with a guarantee on performance. Excluding the effects of scope
changes to our Sundance 3 outage this year, the new arrangement is on track to deliver an average 15 per cent cost reduction
per turnaround and shorter turnaround times for major maintenance work, resulting in estimated direct cost savings of
$34 million over the full term of the agreement. Other planned major outages in 2015 included Sundance 5, Keephills 3, and
one outage at Sheerness.
The decrease in mine capital in 2014 compared to 2013 was primarily due to fewer mine support equipment purchases as
mining intensity stabilized. Planned major maintenance costs in 2014 included five planned outages at Sundance Unit 5,
Sundance Unit 6, Keephills Unit 2, U.S. Coal, and Genesee Unit 3 in 2014 compared to four in 2013 at Sundance 4, Keephills 3,
U.S. Coal, and Sheerness.
Growth
We have set out to grow comparable EBITDA by $40 to $60 million annually. Our target investments are focused on highly
contracted gas and renewable power generation.
During 2015 we have acquired the following renewable generation facilities:
On July 26, 2015, we agreed to acquire 71 MW of fully contracted renewable generation assets for cash consideration of
US$76 million together with the assumption of certain tax equity obligations and US$42 million of non-recourse debt.
The assets acquired include 21 MW of solar projects located in Massachusetts and the 50 MW Lakeswind wind project
located in Minnesota. The assets are contracted under long-term power purchase agreements ranging from 20 to 30
years. The purchase of the solar projects in Massachusetts closed on Sept. 1, 2015 and the purchase of the Lakeswind
wind project in Minnesota was completed on Oct. 1, 2015.
As part of the arrangement to restructure our Poplar Creek contract, on Sept. 1, 2015, we acquired the 20 MW Kent
Breeze wind facility located in Ontario and a 51 per cent interest in the 88 MW Wintering Hills wind facility located in
Alberta. The Kent Breeze facility has a 20-year contract with the Ontario IESO.
These assets further supplement our pipeline of potential assets for dropdown into TransAlta Renewables, as part of our
financing strategy.
Previously announced growth projects have progressed in line with expectations:
On March 19, 2015, we completed the Fortescue River Gas Pipeline in Western Australia. The project, our first pipeline,
was completed within a nine-month timeframe and for an estimated total cost of AUD$183 million. We hold a
43 per cent interest in the pipeline. The pipeline delivers gas to our Solomon power station, which services Fortescue
Metals Group’s mining operations at the Solomon Hub.
Construction of the 150 MW gas-fired South Hedland project commenced in January 2015. The civil construction phase
is progressing with all major foundation footings complete, with the exception of the steam turbine. Manufacturing and
factory acceptance testing of primary electrical equipment was completed. Major equipment was received on site.
Installation and testing of the main underground fuel gas pipeline was completed. Integration of the existing balance-of-
plant control systems within the overall station control system and associated plant operation, monitoring, and
communication requirements is progressing well.
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These initiatives will add approximately $35 million in EBITDA in 2016 and an additional $80 million annually when the South
Hedland project will be in service during the second quarter of 2017.
Management’s Discussion and Analysis
Our target investments are focused on highly contracted gas and renewable power generation:
contracted assets support our financial position, as we transition to having increased merchant capacity in Alberta in the
next decade; and
gas and renewable generation is our core orientation towards reducing our impact on the environment and utilizes our
expertise in wind, hydro, and gas.
All investments are subject to due diligence procedures and ultimately reviewed by our investment committee (refer to the
Governance and Risk Management section of this MD&A).
During 2015, we received approval from the AUC to construct and operate an 856 MW combined-cycle natural gas-fired
power plant in Alberta. The Sundance 7 project has received all regulatory approvals after receiving the Environmental
Protection and Enhancement Act approval from Alberta Environment and Parks on Oct. 1, 2015. Construction of Sundance 7 will
not commence until we have contracted a significant portion of the plant capacity. Following changes to market conditions in
Alberta during the past year, we do not anticipate that this condition will be met before the next decade. In December 2015,
we repurchased our partner’s 50 per cent share in TAMA Power, the jointly controlled entity developing this project, for
consideration of $10 million payable in five years, along with an option to buy back into this project or into other projects of
TAMA Power during this period.
Contractual Profile
Approximately 65 per cent of our capacity is sold under long-term contract. Excluding Alberta PPAs for our coal and hydro
facilities, the majority of these contracts have maturities in excess of 10 years. Amongst these groups of facilities, significant
new contracts have been extended in respect of the Poplar Creek, Windsor, and Parkeston facilities, the details of which are
provided below.
With most of our coal and hydro facilities in Alberta rolling off the Alberta PPA in 2021, our focus has been to develop a
portfolio of commercial and industrial customers to sell our generation in the province post PPA. We are now serving a
portfolio of 600 MW.
Poplar Creek
On Sept. 1, 2015, we closed the restructuring of our contractual arrangement for power generation services with Suncor
Energy (“Suncor”) at Suncor’s oil sands base site near Fort McMurray and the acquisition of Suncor’s interest in two wind
projects located in Alberta and Ontario.
The Poplar Creek cogeneration facility, which has a maximum capability of 376 MW, had been built and contracted to provide
steam and electricity to Suncor until 2023. Under the terms of the new arrangement, Suncor acquired from TransAlta two
steam turbines with an installed capacity of 132 MW and certain transmission interconnection assets. In addition, Suncor
assumed full operational control of the cogeneration facility, including responsibility for all capital costs, and the right to use
the full 244 MW capacity of TransAlta’s gas generators until Dec. 31, 2030. We will provide Suncor with centralized
monitoring, diagnostics, and technical support to maximize performance and reliability of plant equipment. Ownership of the
entire Poplar Creek cogeneration facility will transfer to Suncor in 2030.
As part of the arrangement, we acquired Suncor’s 20 MW Kent Breeze wind facility located in Ontario and Suncor’s
51 per cent interest in the 88 MW Wintering Hills wind facility located in Alberta. The Kent Breeze facility has a 20-year
contract with the Ontario IESO.
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Management’s Discussion and Analysis
The transaction creates value by increasing the duration of the contract to 2030 from the prior 2023 expiry, reduces our
exposure to Alberta’s merchant power market, and adds two high quality wind facilities representing 65 MW of capacity. The
addition of a fully contracted gas generating asset and two wind farms supplements our pipeline of assets that we could sell
to TransAlta Renewables in the future. As a result of the transaction, we recognized a finance lease of $372 million and
increased our long-term assets to reflect the acquisition of two wind farms for $138 million. The transaction closed on
Sept. 1, 2015 and we have recognized a gain of $262 million on the transaction. The carrying amount of net assets we
transferred to the counterparty in the transaction was $250 million.
Windsor
During the first quarter of 2015, we executed a new 15-year power supply contract with Ontario’s IESO for our Windsor
facility, which will be effective Dec. 1, 2016. The contract is similar to the contract signed in 2013 for our Ottawa facility. Under
the new contract, the plant will become dispatchable for up to 72 MW of capacity. The new contract provides long-term
stable earnings for this facility.
Parkeston
During the last quarter of 2015, we executed an extension to our power purchase agreement to supply power to the Kalgoorlie
Consolidated Gold Mine from our 55 MW Parkeston power station. The agreement extends the previous contract to October
2026 with options for early termination available to either party beginning in 2021. The risks associated with the extended
agreement remain consistent with the original contract. The contract extension will continue to provide stable cash flow for
the business.
Over the last three years, we have nearly doubled the weighted average remaining contractual life of our gas fleet from
six years to 12 years.
Human and Intellectual Capital
As at Dec. 31, 2015, we had 2,380 active employees. This number has decreased by 17 per cent since the previous year,
following various restructuring initiatives to reduce costs and increase efficiency. A number of unfilled positions have also
been eliminated.
With approximately 54 per cent of our employees being unionized, we strive to maintain open and positive relationships with
union representatives and regularly meet to exchange information, listen to concerns, and share ideas that further our mutual
objectives. Collective bargaining is conducted in good faith, and we respect the rights of all employees to participate in
collective bargaining.
Safety
Safety is our top priority with all of our staff, contractors, and visitors. Injury Frequency Rate (“IFR”) is defined as the number
of lost-time and medical injuries for every 200,000 hours worked. Our ultimate goal is to achieve zero injury incidents. We
achieved our best results ever for safety performance in 2015, exceeding our IFR target of 0.90. We have experienced no
fatalities during the last three years.
Year ended Dec. 31
IFR
2015
0.75
2014
0.86
2013
0.93
During 2015, we designed a new total safety management policy as a two-pronged approach. The policy builds upon our
occupational safety program, Target Zero, which is focused on protecting our workers on site, through means of personal
protection equipment, inspections, safety controls, job safety analyses, field-level hazard assessments, and safety
communications. The policy is supplemented by our newly launched operational integrity program, which is focused on
keeping all hazards inside our equipment, through definition and measurement of safety-critical performance measures and
operating limits.
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Management’s Discussion and Analysis
Employee Benefits
We provide compensation to our employees at levels that are competitive in relation to their respective location. We strive to
be an employer of choice through our total rewards program, which include various incentive plans designed to align
performance with our annual and mid-term targets, as determined annually by the Board.
Also included in compensation are various future benefit plans. We have registered pension plans in Canada and the U.S.
covering substantially all employees of the Corporation, its domestic subsidiaries, and specific named employees working
internationally. These plans have defined benefit and defined contribution options, and in Canada there is an additional
supplemental defined benefit plan for members whose annual earnings exceed the Canadian income tax limit. Except for the
Highvale pension plans acquired in 2013, the Canadian and U.S. defined benefit pension plans are closed to new entrants. The
U.S. defined benefit pension plan was frozen effective Dec. 31, 2010, resulting in no future benefits being earned. The defined
benefit plans are funded by the Corporation in accordance with governing regulations. We provide other health and dental
benefits for disabled members and retired members, typically up to the age of 65. The supplemental pension plan is an
obligation of the Corporation. We are not obligated to fund the supplemental plan but are obligated to pay benefits under the
terms of the plan as they come due. We have posted a letter of credit in the amount of $65 million to secure the obligations
under the supplemental plan.
Organizational Culture and Structure
During 2015 we initiated the Powering Performance organizational design program, with the primary objective of accelerating
decision-making within our organization. The program has had us transition more fully to a decentralized, business-centric
model, with Coal & Mining, Gas & Renewables, Australia, and Energy Marketing defined as our four primary businesses. As
part of the design work, we have transferred accountability for shared services to the businesses and removed a layer of
management. As part of this process, employees also have clearer accountabilities and authority. We are currently focused on
training employees to adapt to these changes.
Fleet Management
TransAlta has maintained its Operations Diagnostic Centre (ODC) since 2008. The ODC monitors coal-fired, gas-fired and
wind-generating assets across Canada, the United States, and Australia. A centralized team of engineers and operations
specialists remotely monitors our power plants for emerging equipment reliability and performance issues. ODC staff are
trained in the development and use of specialized equipment monitoring software and can apply their experience in power
plant operations. If an equipment issue is detected, the ODC notifies plant operations to investigate and remedy the issue
before there is an impact to operations. The monitoring, analysis, and diagnostics completed by the ODC are focused on early
identification of equipment issues based on longer-term trend analysis and complements day-to-day plant operations.
Our energy trading and marketing operations optimize the financial returns of our facilities in real time. The group purchases
fuels to feed plants, bids into energy markets the electricity we generate at our facilities, and mitigates the associated risks
associated with those purchases and sales. In addition, they buy, sell, schedule, and negotiate all of the electricity
transmission for each facility. They do so while applying an overlay of complex, real-time information – about weather, facility
capacity, transmission congestion, and market pricing. Quantitative analysis, forecasting, mathematical models, and forward
curves are key tools used to execute this responsibility. In addition, the application of these skills for proprietary trading allows
us to generate margins ranging from approximately $60 million to $80 million annually and EBITDA of $40 million to
$60 million annually. Effective Jan. 1, 2016, a new Energy Trading and Risk Management System (“ETRMS”) became
operational, to further support optimization and trading capabilities, allowing for streamlined data flows, state-of-the-art
linkages, and enhanced scalability for key optimization tools. The ETRMS had no impact on our internal control over financial
reporting at Dec. 31, 2015. As a result of the implementation of the ETRMS, certain processes supporting our internal control
over financial reporting are expected to change in 2016. Management will continue to monitor these processes going forward.
We seek to optimize cost and reliability of our assets and maintain or increase their capacity. Our decentralized organization
allows the sharing and deployment of technology-specific innovative practices within the respective businesses. A key
resolution achieved during 2015 was the confirmation by the Alberta Electric System Operator that Sundance Units 3 to 6
comply with reactive power standards. Additionally, we set aside annually $10 million to $15 million to invest in productivity
projects and further the innovation from our employees. Productivity projects are evaluated against criteria that include a two-
to three- year financial payback. During 2015, we completed some boiler erosion mitigation projects on Sundance 5. These
improvements to the shielding and support attachments in the boiler are designed to reduce boiler tube leaks and reliability.
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Management’s Discussion and Analysis
During 2015, we set the foundation for our operational integrity program. The program is designed to achieve process and
equipment safety through understanding and monitoring of key risks and implementation of mitigation measures. In 2015, we
completed our risk assessment at all facilities except Australia and Mining. We have also developed operator checks,
maintenance tasks, and proof tests for various safety critical elements at coal plants. Key performance indicators have been
identified and are being integrated in a dashboard for ongoing monitoring. During 2016, we plan to finalize developing the
balance of safety-critical maintenance strategies and related engineering standards. We have observed positive increases in
self-reporting and addressing process safety hazards as awareness and new tools are being introduced.
New or Emerging Technologies
We seek to maintain TransAlta in pace with power technologies that have the potential to re-define power markets today and
in the future. In certain markets, renewables penetration is rapidly changing the economic position of incumbent generators.
As demonstrated by our investments in wind in the past decade, we are intent on adapting our business model to these
changing realities. During 2015, we made our first investment in solar technology with the purchase of the Massachusetts
solar facilities. We are also beginning to experiment with battery storage technology.
Environmental and Local Communities Capital
All energy sources used to generate electricity have some impact on the environment. While we are pursuing a business
strategy that includes investing in low-impact renewable energy resources such as wind, hydro, and solar, we also believe that
coal and natural gas will continue to play an important role in meeting energy needs as part of this transition. Regardless of
the fuel type, we place significant importance on environmental compliance and continued environmental impact mitigation,
while seeking to deliver low-cost electricity.
In the jurisdictions in which we operate, legislators have proposed and enacted regulations to discontinue over time the use of
the technologies that our coal-fuelled plants currently utilize. Our gas and coal facilities can also incur costs in relation to their
carbon emissions, depending on the jurisdiction in which the facility is located. Our contracted facilities can generally recover
those costs from the customer. Conversely, our renewable generation facilities are generally able to realize value from their
environmental attributes. We continue to closely monitor the progress and risks associated with environmental legislation
changes on our future operations.
Reducing the environmental impact of our activities has a benefit not only to our operations and financial results, but also to
the communities in which we operate. We expect that increased scrutiny will be placed on environmental emissions and
compliance, and we therefore have a proactive approach to minimizing risks to our results. Our Board provides oversight to
our environmental management programs and emission reduction initiatives to ensure continued compliance with
environmental regulations. Our environmental initiatives include:
Renewable power growth and offsets portfolio: Over the last three years, we have added approximately 350 MW in
renewable energy capacity. Of these additions, 45 MW of capacity generates offsets that can be used against GHG
emissions in Alberta.
Environmental controls and efficiency: We continue to make operational improvements and investments to our existing
generating facilities to reduce the environmental impact of generating electricity. We installed mercury control
equipment at our Canadian Coal operations in 2010 in order to meet Alberta’s 70 per cent reduction objectives, and
voluntarily at our U.S. coal-fired plant in 2012. Our Keephills 3 and Genesee 3 plants use supercritical combustion
technology to maximize thermal efficiency, as well as sulphur dioxide (“SO2”) capture and low oxides of nitrogen
(“NOx”) combustion technology. Uprate projects completed at our Keephills and Sundance plants, including a 15 MW
uprate finalized in 2015 at Sundance 3, have improved the energy and emissions efficiency of those units.
Planning: With respect to announced environmental rules that have not yet entered into effect, such as Clean Air
Strategic Alliance (“CASA”) rules in Alberta (as detailed in the following Regional Regulation and Compliance sub-
section), we investigate the cost effectiveness of multiple technological solutions and various operating models in order
to prepare appropriate work scopes.
Policy participation: We are active in policy discussions at a variety of levels of government and with industry
participants. Where capacity retirements are being mandated, we advocate minimizing the capital requirements of
incremental regulation, to allow reinvestment in lower-intensity sources during the transition phase. In Washington
State, the retirement of our Centralia coal plant was established through a multi-stakeholder agreement.
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Management’s Discussion and Analysis
In addition to these initiatives, we maintain similar procedures for environmental incidents as we do for safety, with tracking,
analyzing, and active management to eliminate occurrence, and ongoing support from our operational integrity program. With
respect to biodiversity management, we seek to establish robust environmental research and data collection to establish
scientifically sound baselines of the natural environment around our facilities and closely monitor the air, land, and water in
these areas to identify and curtail potential impacts.
Environmental Performance
All of our 69 facilities have Environmental Management Systems (“EMS”) in place. As at Dec. 31, 2015, 67 of the facilities that
we own and our mines have EMS based on the globally recognized ISO 14001 EMS Standard.
We recorded 12 environmental incidents in 2015 (2014 - 15 incidents), which is lower than our target of 18 (2014 - 20). One of
these incidents led to an environmental enforcement action, for which fines were nominal.
Similarly, the volume of spills has been limited, with 19 m3 spilled, of which 99 per cent was recovered (2014 – 463 m3,
96 per cent recovered). This year marked a record year for the low volume of spills and is a testament to our increased focus
and scrutiny placed on reporting all spills in order to understand their causes and take action to mitigate further incidents.
Air Emissions
In 2015, we estimate that 32.2 million tonnes of GHGs with an intensity of 0.87 tonnes per MWh (2014 - 35.1 million tonnes
of GHGs with an intensity of 0.89 tonnes per MWh) were emitted as a result of normal operating activities( 1). Our GHG
emissions decreased in 2015, primarily as a result of lower production from coal plants. Variations in other air emissions
(NOx, SO2, particulate matter, and mercury) trended similarly to GHG emissions.
Other decreases in emissions of the Gas segment are attributable to the transfer of operational control of the Poplar Creek
facility to our customer in September 2015, conversion of the Ottawa plant to a peaking facility in 2013, and conversion of the
Solomon plant in Australia to burn natural gas instead of diesel. Our continued investment in growth from renewable power
generation further supports the decrease in emissions intensity observed in 2015.
We believe in proactive measurement and disclosure of air emissions. In 2015, TransAlta was the only power generation
company recognized as part of the Top 20 in Canada in the Climate Leadership Index.
Resource utilization
Water
Our principal water uses are for cooling and steam generation in coal and gas plants, and for hydro power production.
Typically, TransAlta withdraws in the ranges of 220-240 m3 of water across our fleet. Water is withdrawn primarily from rivers
where we hold permits to withdraw water and adhere to regulations on water quality. We return or discharge approximately
70 per cent of water back to the source, meeting the regulatory quality levels that exist in the various locations we operate.
The difference between withdraw and discharge, representing consumption, is largely due to evaporative loss.
Our areas of higher water risk are situated east of Perth in our single-cycle gas plants in Western Australia and in our
Southern Alberta hydro operations. We continue to maintain ample water at all sites that require water for operation.
In Southern Alberta, following the flood of 2013, our hydro facilities are being solicited for an increased water management role than
they have played in the past. During 2015, we established an interim agreement with the Government of Alberta to use our Ghost
hydro reservoir for potential flood mitigation purposes. As part of the agreement, we lowered the reservoir level below typical
operating levels for a longer period, and received compensation for commercial opportunity costs. We continue to engage with the
government and partners towards a comprehensive water management framework that involves flood and drought mitigation.
(1) 2015 data are estimates based on best available data at the time of report production. GHGs include water vapour, carbon dioxide (“CO2”), methane, nitrous oxide, sulphur
hexafluoride, hydrofluorocarbons, and perfluorocarbons. The majority of our estimated GHG emissions are comprised of CO2 emissions from stationary combustion.
Emissions intensity data has been aligned with the ‘Setting Organizational Boundaries: Operational Control’ methodology set out in The Greenhouse Gas Protocol: A
Corporate Accounting and Reporting Standard. As per the methodology TransAlta reports emissions on an operation control basis, hence we report 100 per cent of emissions
at facilities in which we are the operator. Emissions intensity is calculated by dividing total operational emissions by 100 per cent of production (MWh) from operated
facilities, regardless of financial ownership.
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Management’s Discussion and Analysis
Land
The largest land use associated with our operations is for surface mining of coal. Of the three mines we have operated,
Whitewood is completely reclaimed and the land certification process is ongoing. Centralia is in the reclamation phase, and
Highvale is actively mined with ongoing reclamation. Our reclamation plans are set out on a lifecycle basis and include
contouring disturbed areas, re-establishment of drainage, replacement of topsoil and subsoil, re-vegetation, and land
management. Our mining practice incorporates progressive reclamation where the final end use of the land is considered at
all stages of planning and development. In 2015, we reclaimed 65 acres (26 hectares) at our Higvale mine, slightly below our
target of 74 acres (30 hectares) due to the impact of warm weather on soils in the winter as cold temperatures facilitate
reclamation work and the spreading of topsoil. The variance has been accounted for and incorporated into the mine’s go-
forward reclamation plans.
During 2015, we obtained approvals for our Highvale mine to develop a new area, which we anticipate will be the final area
required to support our Sundance and Keephills facilities through to the end of their operation in 2030.
Also in 2015, we donated 64 acres of land to the Alberta Wildlife Trust Fund. The land includes an area that was once a mine
settling pond and is a site of ecological significance. The donation aligns with our objectives for community participation and
stakeholder engagement.
Waste
Our operating teams work to minimize waste and maximize recoverable value from waste. Over the years, we have invested in
equipment to capture of byproducts from the combustion of coal, such as fly ash, bottom ash, gypsum, and cenospheres, for
subsequent sale. These non-hazardous materials add value to products like cement and asphalt, wallboard, paints, and
plastics. During 2015, our revenue from by-product sales amounted to $28 million (2014 – $31 million). The decrease is
primarily attributable to the lower production.
Regional Regulation and Compliance
Environmental issues and related legislation have, and will continue to have, an impact upon our business. We are committed
to complying with legislative and regulatory requirements and to minimizing the environmental impact of our operations. We
work with governments and the public to develop appropriate frameworks to protect the environment and to promote
sustainable development.
Recent changes to environmental regulations may materially adversely affect us. As indicated under “Risk Factors” in our
Annual Information Form and within the Governance and Risk Management section of this MD&A, many of our activities and
properties are subject to environmental requirements, as well as changes in our liabilities under these requirements, which
may have a material adverse effect upon our consolidated financial results.
Alberta
On Nov. 22, 2015, the Government of Alberta announced its Climate Leadership Plan. That Plan established several
environmental and energy targets for Alberta, including:
maintaining reliability, reasonable prices to customers and businesses, and ensuring capital is not unnecessarily stranded.
the phase-out of emissions from coal-fired generation by 2030;
the replacement of two-thirds of the retiring coal-fired generation with renewable generation and one-third with gas generation;
the objective of achieving up to 30 per cent of Alberta’s electricity production from renewables by 2030; and
The Province of Alberta will develop its associated regulations as well as a compensation plan for coal units in 2016. We will
negotiate with the Government of Alberta, using a principles-based approach, to ensure the Corporation has the certainty and
capacity needed to invest in clean power.
On Sept. 11, 2012, the Canadian federal government published the final regulations governing GHG emissions from coal-fired
power plants. The regulations provide for up to 50 years of life for coal units, at which point units must meet an emissions
performance standard of approximately 420 tonnes per GWh. There are some exceptions that require older units
commissioned before 1975 to reach end of life by Dec. 31, 2019, and units commissioned between 1975 and 1986 to reach end
of life by Dec. 31, 2029.
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We believe the regulations provide additional operating time and increased flexibility for our Canadian Coal units, allowing
those units to comply in a more cost-effective manner. Our Keephills 3, Genesee 3, and Sheerness facilities, however, would
be subject to the shorter 2030 limit proposed by the Alberta government.
Since 2007, we have incurred costs as a result of GHG legislation in Alberta. On June 29, 2015, the Alberta government
announced an increase to its provincial SGER:
On Jan. 1, 2016, an increase in the GHG reduction obligation for large emitters from 12 per cent to 15 per cent of
emissions, with the compliance price of the technology fund rising from $15 per tonne to $20 per tonne.
On Jan. 1, 2017, a further increase to a 20 per cent reduction requirement and a $30 per tonne compliance price.
Our exposure to increased costs as a result of environmental legislation in Alberta is mitigated to some extent through
change-in-law provisions in our PPAs that allow us the opportunity to recover capital and operating compliance costs from
our PPA customers. The GHG offsets created by our Alberta wind facilities are expected to increase in value through 2017, as
GHG emitters can use them as compliance instruments in place of contributing to the technology fund. As part of the Climate
Leadership Plan, the government has stated its intention to establish a new system of obligations and allowances,
benchmarked against highly efficient gas generation, beginning in 2018. The initial compliance price would be set at
$30 per tonne, escalating annually.
In Alberta there are additional requirements for coal-fired generation units to implement additional air emission controls for
oxides of NOx and SO2 once they reach the end of their respective PPAs, in most cases in 2020. These regulatory
requirements were developed by the province in 2004 as a result of multi-stakeholder discussions under Alberta’s CASA. The
release of the federal regulations creates a potential misalignment between the CASA air pollutant requirements and
schedules, and the GHG retirement schedules for older coal plants, which in themselves will result in significant reductions of
NOx, SO2, and particulates.
We are in discussions with the provincial government in an effort to ensure coordination between GHG and air pollutant
regulations, such that emission reduction objectives are achieved in the most effective manner while taking into consideration
the reliability and cost of Alberta’s generation supply.
Pacific Northwest
On Aug. 3, 2015, President Obama announced the Clean Power Plan. The plan sets GHG emission standards for new fossil-
fuel-based power plants and emission limits for individual states. States will have the option of interpreting their limits in
mass-based (tons) or rate-based (pounds per megawatt hour) terms. The plan is intended to achieve an overall reduction in
GHG emissions of 32 per cent from 2005 levels by 2030. It will be implemented in two stages: 2022 to 2029, and 2030 and
beyond.
On Dec. 17, 2014, Washington State Governor Jay Inslee released a carbon-emissions reduction program for the State, where
our U.S. Coal plant is located. Included in this program are a cap-and-trade plan and a low-carbon fuels standard. The
proposed emissions cap will become more stringent over time, providing emitters time to transition their operations.
These additional regulations for existing power plants are not expected to significantly affect our U.S. operations. TransAlta
has agreed with Washington State to retire units in 2020 and 2025. This agreement is formally part of the State’s climate
change program. We believe that there will be no additional GHG regulatory burden on U.S. Coal given these commitments.
The related TransAlta Energy Bill was signed into law in 2011 and provides a framework to transition from coal to other forms
of generation.
Ontario
On April 13, 2015, the Ontario government announced that Ontario will be implementing a GHG cap-and-trade system in an
effort to reduce emissions and fight climate change. The cap-and-trade system will impose a hard ceiling on the GHG
emissions allowed in each sector of the economy. The details of the cap-and-trade system (such as specifics on a potential
cap, covered sectors, or anticipated launch date) have not been determined but are to be developed through stakeholder
consultations. Our contracts at Gas facilities in the province generally include provisions protecting us from adverse changes
in laws.
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Australia
In Australia, the Senate recently passed amendments to the country’s Renewable Energy Target Scheme. The scheme was
initially introduced in 2001 with three objectives: to establish a mandatory renewable energy target to be achieved in 2020; to
provide incentives for large-scale renewable energy generators in the form of one large-scale generation certificate earned for
each MWh of generation; and to require retailers and wholesale industrial customers to purchase a specified volume of their
electricity from large-scale renewable-sourced electricity or incur a penalty of AUD$65/MWh on any shortfall. The
amendments reduced the annual targets for large-scale renewable sourced electricity down from 41,000 GWh in 2020 to
33,000 GWh in 2020, held constant at this level until 2030. It is estimated that this will require an additional
5,000-6,000 MW of new capacity to be installed to add to the slightly more than 4,000 MW already operating. Since the
Australian assets are fully contracted it is not expected that these amendments will have a significant impact.
Climate Change
Abnormal weather events that are sometimes associated with climate change can impact our operations and give rise to
risks. Among other events, variations in wind, solar, water, and temperatures give rise to various levels of volume risk
depending on the input fuel of each facility; events outside the design parameters of our facilities give rise to equipment risk;
and fluctuations in temperatures can cause commodity price risk through impact on customer demand for heating or cooling.
Refer to the Governance and Risk Management section of this MD&A for further discussion of each risk and our related
management strategy.
During the past three years, some deviations from expected weather patterns have negatively impacted our annual financial results:
the Southern Alberta flood of 2013 disrupted our hydro operations and caused us to invest into substantial repair work.
Our losses have been largely covered through insurance; and
warm weather in Alberta in 2015 increased derates at our coal facilities due to its impact on the Sundance cooling ponds.
These cooling ponds are susceptible to warm weather; however, we anticipate that decreased coal production and the
retirement of Sundance Units 1 and 2 in the medium term will reduce the stress from such occurrence.
Over the same period, other deviations have positively impacted our financial results such as the cold temperatures in Eastern
North America in the winter of 2014 that caused market volatility which benefitted our energy marketing group.
Local Communities
We provide public benefit through reliable, cost-efficient power and related outputs or services. In the face of declining social
acceptability of coal and with its phase-out on the horizon, we seek to secure favourable outcomes for our workers and the
communities surrounding our plants. The approach is summarized in CEO Dawn Farrell’s editorial on TransAlta’s Dial Down - Dial
Up submission to the Government of Alberta. “We are prepared to invest hundreds of millions of dollars to dial up the transition
to new renewables, including hydro, wind, and solar. Dial Down - Dial Up starts with an agreement with the province,
environmental groups, the communities in which we operate, and our employees, because jobs matter. Not jobs that will be
created in the future, but thousands of jobs held today by our employees and contractors. That’s almost 3,000 people, not
including jobs in the communities where they work. And electricity prices matter, because there is a real risk to consumers,
including Alberta businesses, of price spikes and volatility.” TransAlta advocated for a sufficiently long timelines for transition,
support for facility redevelopment, funds for retraining, and economic diversification. Our successful agreement with the State of
Washington, in 2011, and our proposal in Alberta leading up to the Climate Leadership Plan illustrate this approach.
Competitive Behaviour
On July 27, 2015, the AUC issued a ruling that found, among other things, that our actions in relation to four outage events at
our coal-fired generating units, spanning 11 days in 2010 and 2011, restricted or prevented a competitive response from the
associated PPA buyers and manipulated market prices away from a competitive market outcome.
On Sept. 30, 2015, TransAlta and the MSA reached an agreement to settle all outstanding proceedings before the AUC. The
settlement, which is in the form of a consent order, was approved by the AUC on Oct. 29, 2015. Under the terms of the
agreement, we will pay a total amount of $56 million that includes approximately $27 million as a repayment of economic
benefit, approximately $4 million to cover the MSA’s legal and related costs, and a $25 million administrative penalty. Of this
amount, $31 million has been paid in the fourth quarter, and the $25 million administrative penalty will be paid in the fourth
quarter of 2016. As a result of the approval, we have discontinued our appeal of the AUC’s decision.
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TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
When we became aware that the market rules governing forced outages were in dispute, we changed our compliance
procedures, and the actions that led to this case have not been repeated. In order to rebuild trust, we have undertaken two
independent, third-party reviews of our current compliance procedures around forced outages, and of our trading compliance
program, the results of which will be made public. We have received findings from these independent reports, including some
recommendations for improvement, and are finalizing our response to the reports and recommendations.
Public Health
We seek to maintain public health and safety by restricting physical access to our operating sites and ongoing monitoring of
air emissions from our coal and gas plants.
During the year, public assertions have been made concerning the impact of coal plants on air quality in the Edmonton area. In
order to verify the veracity of this information, we funded an independent analysis of the sources of air quality issues in and
around the Edmonton area by University of Alberta scientist Dr. Warren Kindzierski, using provincial government monitoring
data from the past nine years.
Dr. Kindzierski’s work has determined that emissions from coal-fired generation are in fact a minor contributor to Edmonton’s
air pollution. Chemical “signatures” for emissions pointed to several sources, including local industries, vehicles, and
wood-burning fireplaces in relation to air quality concerns in Edmonton. Only about 10 per cent or less of all particulate matter
in the airshed can be attributed to coal combustion emissions.
The study also looked at 17 years of wind patterns and confirmed that, in most seasons, the local winds around Edmonton
predominantly blow into the city from the south and southeast, not from the west where coal-fired generation is concentrated.
Stakeholder Engagement
TransAlta is implementing a corporate stakeholder engagement framework, a streamlined corporate-wide approach to ensure
that engagement and relationship-building practices are consistent across TransAlta’s locations and types of work. Our
aboriginal relations group continues to develop and enhance aboriginal relations programming in areas of employment,
economic development, community engagement, and investment to position TransAlta for achieving top standing in 2017.
Since 2014, we have achieved the Canadian Council for Aboriginal Business’ silver-level Progressive Aboriginal Relations
certification, and we are targeting to achieve gold-level by 2017.
Community
During 2015, TransAlta contributed $3.5 million in donations and sponsorships (2014 - $3.6 million).
On July 30, 2015 we announced that we are moving ahead with plans to invest US$55 million over 10 years to support energy
efficiency, economic and community development, and education and retraining initiatives in Washington state. The
US$55 million community investment is part of the TransAlta Energy Transition Bill, passed in 2011. This bill was a historic
agreement between policymakers, environmentalists, labour leaders, and TransAlta to transition away from coal in
Washington State, closing the Centralia facility’s two units, one in 2020 and the other in 2025. Although we did not secure
additional long-term contracts totalling 500 MW as planned in the original agreement as a condition of the investment, we
are following through on our funding pledge and securing mutual benefits agreed with the State for orderly transition.
Stakeholder Communication and Value Creation
The information contained herein seeks to highlight our ability to create value for investors, stakeholders, and society in the
short, medium, and long term. The selection of key information and key metrics disclosed in this integrated report and our full
sustainability disclosures follow a materiality assessment process, which identifies key impact areas to our stakeholders. We
subsequently are guided by and place focus on reporting on these key areas. More information on key areas of materiality can
be found on the sustainability section of our website.
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TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Discussion of Segmented Comparable Results
During the first quarter of 2015 we began reporting Canadian Coal, U.S. Coal, Gas, Wind, and Hydro as separate business
segments. Previously, these were collectively reported as the Generation Segment and were further differentiated by fuel type
within our MD&A to provide additional information to our readers. The change in segmentation under IFRS has minimal
impact on our MD&A. No changes arose in respect of our Energy Marketing and Corporate segments. See the Current
Accounting Changes section of this MD&A for additional information.
Solar facilities acquired in September 2015 have been included in our Wind and Solar Segment as it is integrated to this
business from a management perspective.
Comparable figures are not defined under IFRS. Refer to the Earnings and Other Measures on a Comparable Basis section of
this MD&A for further discussion of these items, including, where applicable, reconciliations to net earnings attributable to
common shareholders.
Canadian Coal
Year ended Dec. 31
Availability (%)
Contract production (GWh)
Merchant production (GWh)
Total production (GWh)
Gross installed capacity (MW)
Revenues
Fuel and purchased power
Comparable gross margin
2015
84.3
2014
88.6
2013
80.9
20,256
21,748
17,789
3,827
3,806
3,779
24,083
25,554
21,568
3,786 3,771
3,771
912
1,023
916
379
436
393
533
587
523
Operations, maintenance, and administration
194
196
203
Taxes, other than income taxes
Gain on sale of assets
Net other operating income
Comparable EBITDA
Depreciation and amortization
Comparable operating income
Sustaining capital:
Routine capital
Mine capital
Finance leases
Planned major maintenance
Total sustaining capital expenditures
12
12 11
-
(1) (2)
(7) (9) -
334
389
311
299 292
292
35
97 19
48
56 69
25
45
65
10
10
9
107
100
94
190
211
237
Insurance recoveries of sustaining capital expenditures
(7) -
-
Net amount
183
211
237
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M36 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
2015
Production for the year ended Dec. 31, 2015 decreased 1,471 GWh compared to 2014, primarily due to unplanned outages in
the first half of the year (Sundance 4, and Keephills 1 Force Majeure outage) and derates due to high temperatures impacting
cooling ponds in the spring and summer months. The planned outage at Sundance 3 was extended as a result of the level of
turbine work found. Generation was also reduced due to economic dispatch resulting from the current low price environment.
Comparable EBITDA in 2015 was $334 million compared to $389 million in 2014. In 2015 comparable EBITDA included a
$59 million adjustment to provisions primarily in relation to prior year events. Excluding the adjustment to provisions,
comparable EBITDA would have been $393 million in 2015, in line with last year. Reductions in operating expenses at our
Highvale mine and mark-to-market gains on certain forward financial contracts that do not qualify for hedge accounting fully
offset the negative impact of year-over-year lower availability on our comparable EBITDA. Our high level of contracts and
hedges in Canadian Coal mostly offset the impact of lower prices in Alberta compared to 2014. Other operating income in
2015 represents insurance recoveries received in connection to the Keephills 1 Force Majeure outage and additional work at
Sundance 3.
Depreciation and amortization for the year ended Dec. 31, 2015 increased by $7 million compared to 2014 due to the addition
of assets at our Highvale mine.
For the year ended Dec. 31, 2015, sustaining capital expenditures decreased by $21 million compared to 2014. In 2014, we
incurred additional cost for the development of a new mining area, and the acquisition and refurbishment of vehicles as part
of our mining operations.
2014
Production for the year ended Dec. 31, 2014 increased 3,986 GWh compared to 2013. Production for 2013 was impacted by a
seven-month outage at our Keephills 1 facility and the return to service of Sundance 1 and 2 in September and October,
respectively.
For the year ended Dec. 31, 2014, comparable gross margin increased by $64 million compared to 2013, primarily as a result
of lower unplanned outages, lower unit coal costs, and contract price escalations. Lower prices in Alberta in 2014 compared to
2013 decreased incentive payments received for generation in excess of PPA targets, offsetting some of the gain in reliability.
We were able to achieve the reduction in coal costs after we took over operations at the Highvale mine in 2013.
OM&A for the year ended Dec. 31, 2014 decreased despite much higher operating capacity with Sundance Units 1 and 2
returning to service. We achieved a reduction in OM&A as a result of reduced maintenance costs associated with lower
unplanned outages and the implementation of initiatives to reduce costs.
Other operating income resulted from the settlement of a dispute with a supplier in relation to an equipment failure in prior years.
Depreciation and amortization for the year ended Dec. 31, 2014 was consistent compared to 2013. The increase in
depreciation and amortization relative to 2013 resulted from an increased asset base, primarily related to Sundance Units 1
and 2 returning to service, was offset by fewer asset retirements during the year and the life extension of certain components.
For the year ended Dec. 31, 2014, sustaining capital decreased $26 million compared to 2013 as a result of the Keephills 1
Force Majeure outage in 2013 and investments required to increase mining intensity.
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TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
U.S. Coal
Year ended Dec. 31
Availability (%)
Adjusted availability (%)(1)
Contract sales volume (GWh)
Merchant sales volume (GWh)
Purchased power (GWh)
Total production (GWh)
Gross installed capacity (MW)
Revenues
Fuel and purchased power
Comparable gross margin
2015
87.4
89.5
2014
82.8
87.7
2013
78.3
91.9
2,868
1,131
996
5,484
6,102
6,459
(3,329) (549) (744)
5,023
6,684
6,711
1,340
1,340
1,340
431
368
346
311
251
227
120
117
119
Operations, maintenance, and administration
50
49
48
Taxes, other than income taxes
Comparable EBITDA
Depreciation and amortization
Comparable operating income
Sustaining capital:
Routine capital
Finance leases
Planned major maintenance
Total
1
3
3
4
67
65 67
63
54
56
4
11
11
2
2
6
3
-
-
10
10
10
15
12 16
2015
Production decreased 1,661 GWh in 2015 compared to 2014, as a result of a reduction in our generation to supply our
contractual obligation by buying cheaper power in the market.
In December 2014, we commenced supplying power to Puget Sound Energy under a 10-year contract. Initial contracted
capacity was 180 MW. Contract volumes escalated to 280 MW in December 2015, and will escalate again by 100 MW in
December 2016. We can also re-supply the contract by buying power from the market when economical to do so and further
improve our margin. Because of this option for financial settlement, it is accounted as a financial contract. Hedge accounting
was applied to this contract, with changes in value recorded in other comprehensive income (“OCI”).
EBITDA for the year ended Dec. 31, 2015 was comparable to 2014. The appreciation of the US dollar was offset by the impacts
of lower prices on our merchant sales.
Depreciation and amortization for 2015 increased by $9 million compared to 2014 due to the strengthening of the US dollar.
For the year ended Dec. 31, 2015, sustaining capital expenditures increased by $3 million compared to last year as a result of
the coal fines recovery finance lease. This operation allows us to recover fuel as part of mine decommissioning activities.
(1) Adjusted for economic dispatching.
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M38 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
2014
Production was stable in 2014 compared to 2013, as higher unplanned outages at U.S. Coal were offset by lower economic
dispatching as certain months during the period had higher prices that made production more economic.
Comparable EBITDA decreased $4 million in 2014, as 2013 comparable EBITDA included the favourable effects of
adjustments to commercial arrangements recognized in prior periods. The effect of prior year adjustments was partially offset
by increased optimization margins earned, as we were able to capitalize on high market volatility early in the year.
For the year ended Dec. 31, 2014, sustaining capital decreased by $4 million compared to 2013 primarily due to reduced
general equipment repair and replacement.
Gas
Year ended Dec. 31
Availability (%)
Contract production (GWh)
Merchant production (GWh)
Total Production (GWh)
Gross installed capacity (MW)(1)
Revenues
Fuel and purchased power
Comparable gross margin
Operations, maintenance, and administration
Taxes, other than income taxes
Net other operating income
Comparable EBITDA
Depreciation and amortization
Comparable operating income
Sustaining capital:
Routine capital
Planned major maintenance
Total
1
2015
94.7
5,078
1,535
2014
94.0
5,363
2,027
2013
94.5
5,892
1,962
6,613
7,390 7,854
1,405
1,531 1,779
650
744
683
229
326
252
421
418 431
88
102
97
3
4
3
-
-
(1)
330
312
332
118
114 108
212 198
224
8
24
17
23
39 41
31
63 58
(1) Includes production capacity for Fort Saskatchewan and Solomon power stations, which have been accounted for as finance leases. During the quarter, operational control
of our Poplar Creek facility was transferred to Suncor. We continue to own a portion of the facility and have included our portion as a part of gross capacity measures. Poplar
Creek has been removed from our availability and production metrics from Sept. 1, 2015, the date of transfer of operational accountability. Refer to TransAlta’s Capitals
section of this MD&A for further information. Assets of the Centralia gas plant were sold in the fourth quarter of 2014 and the production capacity was removed from our
gross capacity measures at that time.
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TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
2015
Production for the year ended Dec. 31, 2015 decreased 777 GWh compared to 2014, predominantly due to the transfer of
operational control of the Poplar Creek facility to our customer, effective Sept. 1, 2015.
Most of our contracts provide for pass-through of fuel cost to the counterparty limiting our exposure to fuel price. In the case
where we have no provision for pass-through, we generally match our obligation to deliver energy and our fuel supply to
minimize our exposure to volatile commodity prices. Revenue and costs of fuel decreased by similar amounts during the first
half of 2015 compared to last year, following the decrease in gas input costs. Also, certain operating costs that are transferred
to customers are now billed directly to the customer, resulting in revenue and OM&A decreasing in 2015 compared to last
year. The Poplar Creek restructuring transaction had a minimal impact on EBITDA compared to last year as a lower gross
margin was offset by lower operating costs. The increase in comparable EBITDA is primarily attributable to revenue from the
Australian natural gas pipeline, which was commissioned in March 2015. Revenue from our Solomon facility was also
positively impacted by the appreciation of the US dollar. The Australian dollar remained at similar levels in relation to the
Canadian dollar during the year.
Depreciation and amortization for 2015 increased by $4 million compared to 2014 due to the increased asset base associated
with the Fortescue River Gas Pipeline completed in the first quarter of 2015, as well as impacts from the Poplar Creek
restructuring deal, and higher asset retirements. These were partially offset through the extension of certain asset lives.
Sustaining capital decreased by $32 million for the year ended Dec. 31, 2015 compared to 2014, due to the transfer of the
Poplar Creek facility at the end of August, and lower planned maintenance activities resulting from condition-based
assessments.
2014
Production for the year ended Dec. 31, 2014 decreased 464 GWh compared to 2013 due to the reduced requirement to run
our Ottawa facility under the terms of its new capacity-based contract. The new contract is consistent with our contracting
strategy and its 20-year duration supports continued investment in the facility.
Comparable EBITDA for the year ended Dec. 31, 2014 decreased by $18 million compared to 2013, primarily due to the impact
of lower Alberta prices on our merchant capacity in Poplar Creek and the reduced contribution from our Ottawa facility under
the terms of the new contract. These decreases in comparable EBITDA were partially offset by the benefits achieved through
resale of higher priced excess gas during unplanned outages in 2014. The 2014 results include an $8 million unrealized loss on
forward purchase and physical gas volumes in Ontario, which is offset by unrealized gains of the same amount in the Energy
Marketing Segment.
For the year ended Dec. 31, 2014, sustaining capital increased by $5 million compared to 2013 mainly due to compressor
repairs at Mississauga.
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TransAlta Corporation | 2015 Annual Integrated Report
Wind and Solar
Year ended Dec. 31
Availability (%)
Contract production (GWh)
Merchant production (GWh)
Total production (GWh)
Gross installed capacity (MW)(1)
Revenues
Fuel and purchased power
Comparable gross margin
Operations, maintenance, and administration
Taxes, other than income taxes
Comparable EBITDA
Depreciation and amortization
Comparable operating income
Sustaining capital:
Routine capital
Planned major maintenance
Total
1
Management’s Discussion and Analysis
2015
95.8
2,146
1,060
2014
94.6
2,228
947
2013
93.8
1,700
1,009
3,206
3,175
2,709
1,424
1,291
1,289
250 247
237
19
14
13
231 233
224
48
48
38
7
6
5
176
179
181
99
88
79
77
91
102
1
2
3
12
10
6
13
12 9
2015
Production for 2015 increased slightly by 31 GWh compared to 2014, primarily due to better wind resources and availability in
Western Canada, and contribution from three additional wind farms and our first solar facility acquired during the second half
of the year (111 GWh). This was partially offset by lower wind resources at Wyoming after high wind volumes in 2014.
Comparable EBITDA for 2015 was lower by $3 million compared to 2014 as lower generation from our Wyoming wind facility
and lower merchant prices in Alberta were not fully offset by additional EBITDA from the acquired assets and the stronger US
dollar positively impacting our U.S. assets.
Depreciation and amortization for 2015 increased by $11 million compared to 2014 primarily due to the additions of new
projects during the year.
Sustaining capital for the year ended Dec. 31, 2015 was comparable to 2014.
2014
Production for the year ended Dec. 31, 2014 increased 466 GWh compared to 2013, primarily due to the contribution from a
full year of operations at Wyoming and New Richmond and higher wind volumes in Eastern Canada.
For the year ended Dec. 31, 2014, comparable EBITDA decreased by $3 million compared to 2013. Lower prices in Alberta in
2014 compared to 2013 more than offset the contribution of new wind projects commissioned or acquired in 2013.
Depreciation and amortization for the year ended Dec. 31, 2014 increased by $9 million compared to 2013, primarily due to
the higher asset base associated with recently added facilities.
For the year ended Dec. 31, 2014, sustaining capital increased by $3 million compared to 2013 mainly due to an increase in
planned major maintenance activities as a result of an outage at Le Nordais.
(1) Includes production capacity for the recent Solar and Wind acquisitions.
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TRANSALTA CORPORATION M41
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Hydro
1
Year ended Dec. 31
Contract Production (GWh)
Merchant production (GWh)
Total production (GWh)
Gross installed capacity (MW)
Revenues
Fuel and purchased power
Comparable gross margin
Operations, maintenance, and administration
Taxes, other than income taxes
Net other operating income
Comparable EBITDA
Depreciation and amortization
Comparable operating income
Sustaining capital(1):
Routine capital, excluding hydro life extension
Hydro life extension
Planned major maintenance
Total before flood-recovery capital
Flood-recovery capital
Total sustaining capital expenditures
Insurance recoveries of sustaining capital expenditures
Net amount
2015
2014
2013
1,662
1,810
2,022
86
75 72
1,748
1,885
2,094
926 913
913
116
131
181
8
9
5
108
122
176
38
38 31
3
3
3
(6) (6) (6)
73
87 148
25
24
25
48
63 123
3
9
8
18
19
8
10
3
5
31
31 21
4
9
1
35
40
22
(18) (4) (1)
17
36 21
2015
Production for 2015 decreased by 137 GWh compared to 2014 as a result of lower water resource.
Comparable EBITDA decreased by $14 million for 2015 compared to 2014, primarily as a result of lower prices and a decrease in
price volatility in Alberta, which limited our ability to take advantage of our flexibility to produce electricity in higher priced hours.
Net other operating income includes business interruption insurance recoveries relating to the 2013 Alberta floods.
Sustaining capital expenditures decreased by $5 million for the year ended Dec. 31, 2015 compared to 2014 mainly due to flood-
recovery capital related to the Alberta flood of 2013. We expect to spend $15 to $20 million to complete the flood recovery.
2014
Production for the year ended Dec. 31, 2014 decreased 200 GWh compared to 2013 due to lower water resource in Western
Canada and optimization of storage capacity to capture highest prices.
Comparable EBITDA decreased by $61 million in 2014 compared to 2013, primarily as a result of lower prices and low price
volatility in Alberta, which limited our ability to take advantage of our flexibility to produce electricity during higher priced hours.
(1) 2014 and 2013 restated to include hydro life extension from growth capital expenditures to sustaining capital expenditures. Refer to the Current Accounting Changes
section of this MD&A.
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M42 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Net other operating income relates to business interruption insurance proceeds received in respect of prior period events.
For the year ended Dec. 31, 2014, total sustaining capital increased by $18 million compared to 2013, mainly due to higher
spending on hydro life extension projects and flood-recovery capital related to the Alberta flood of 2013. The flood-related
expenditures were mostly recovered through insurance proceeds recognized in net earnings in 2014, as non-comparable items.
Equity Investments
We completed the sale of our interests in CE Generation LLC (“CE Gen”) and CalEnergy, LLC (“CalEnergy”) in June 2014 and
Wailuku River Hydroelectric, L.P. (“Wailuku”) in November 2014.
The equity method was used to account for the results of the CE Gen, CalEnergy, and Wailuku joint ventures for the months of
January and February 2014, but ceased effective March 1, 2014. There were no earnings from Equity Investments during the
two-month period in 2014 (2013 annual - loss of $10 million).
Energy Marketing
Year ended Dec. 31
Revenues and comparable gross margin
Operations, maintenance, and administration
Comparable EBITDA
Depreciation and amortization
Comparable operating income
2015
2014
2013
49
108 79
12
37
1
36
33
75
-
75
21
58
1
57
Comparable EBITDA from Energy Marketing totalled $37 million, approximately half of last year’s contribution, due to a return
to normal performance from trading activities in the Northeast after extraordinary market conditions in the first quarter of
2014 and the negative impact from unexpected volatile markets in Alberta and the Pacific Northwest during the second
quarter of 2015. Performance during the second half of the year was largely in line with last year. Lower OM&A costs partially
offset the shortfall in revenue as a significant portion of our costs is incentive compensation that is impacted by lower margins
generated by the business.
Corporate
The expenses incurred by the Corporate Segment are as follows:
Year ended Dec. 31
Operations, maintenance, and administration
and taxes other than income taxes
Depreciation and amortization
Comparable operating loss
Sustaining capital:
Routine capital
2015
2014
2013
72
25
97
71
26
97
74
23
97
21
23
22
Our Corporate overhead costs have remained comparable to 2014 and 2013, and we anticipate to begin realizing benefits of
our overhead reductions during 2016.
Routine capital expenditures for the year ended Dec. 31, 2015 decreased compared to 2014, mainly as a result of a reduction
in corporate information technology costs.
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TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Other Consolidated Analysis
Asset Impairment Charges and Reversals
Alberta Merchant Cash Generating Unit
As part of the annual impairment review and assessment process in 2013, the Corporation’s Alberta plants with significant
merchant capacity were considered one cash-generating unit (the “Alberta Merchant CGU”). While no impairment losses
were recognized in 2013 for the Alberta Merchant CGU, total pre-tax impairment losses of $23 million that were recognized
previously in the Wind Segment plants that became part of the Alberta Merchant CGU were reversed. Please refer to Note 6
of our audited consolidated financial statements within our Annual Report for additional information.
The Alberta Merchant CGU’s recoverable amount was based on an estimate of fair value less costs of disposal using a
discounted cash flow methodology based on our long-range forecasts and prices evidenced in the marketplace. Due to a
substantial excess of fair value over net book value at other plants included within the Alberta Merchant CGU, valuation
assumptions and methodologies were not a significant driver of the impairment reversals.
We consider the relationship between our market capitalization and our book value, among other factors, when reviewing for
indicators of impairment. The slowdown in the oil and gas sector has put Alberta into a recession, and put downward pressure
on demand as well as power prices. Further, on Nov 20, 2015, the Government of Alberta announced its Climate Leadership
Plan which broadly calls for the phase-out of coal-generated electricity by 2030 and proposes the imposition of additional
compliance obligations for GHG emissions in the province. As at Dec. 31, 2015, our market capitalization was below our book
value of equity. The government has stated intentions of providing compensation to coal-fired generators as part of its
commitment to treat them fairly and not unnecessarily strand capital. We intend to negotiate an arrangement with the
government.
As part of our monitoring controls, we estimate a recoverable amount for each Cash Generating Unit (“CGU”) by calculating
an approximate fair value less costs of disposal using discounted cash flow projections based on our long-range forecasts. The
valuations used are subject to measurement uncertainty based on assumptions and inputs to our long-range forecast,
including changes to fuel costs, operating costs, capital expenditures, external power prices, and useful lives of the assets
extending to the last planned asset retirement in 2073. These estimates are used to assess the significance of potential
indicators of impairment and provide a criterion to evaluate adverse changes in operations.
During the fourth quarter, we completed a sensitivity analysis on these estimates to assess potential impacts of the proposed Alberta
government policy on reducing GHG emissions, as well as the mandatory retirement of coal facilities by 2030. The sensitivity
analysis demonstrated an approximate fair value substantially in excess of the carrying amount of the Alberta Merchant CGU, and
accordingly, no further test was performed. The excess is attributable to our large renewable fleet in the province.
M44
M44 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
U.S. Coal
As at Nov. 30, 2014, we identified the decrease in projected growth in Mid-Columbia power prices as an indicator that the
U.S. Coal CGU could be impaired. The U.S. Coal CGU’s carrying amount at that date, net of associated long-term liabilities,
was $372 million. We estimated the fair value less costs of disposal of the CGU, utilizing our long-range forecast, and the
following key assumptions:
Mid-Columbia annual average power prices
On-highway diesel fuel on coal shipments
Discount rates
US$31.00 to 52.00 per MWh
US$3.06 to 3.37 per gallon
5.1 to 6.2 per cent
The valuation is subject to measurement uncertainty based on those assumptions, and on inputs to our long-range forecast,
including changes to fuel costs, operating costs, capital expenses, and the level of contractedness under the Memorandum of
Agreement (“MoA”) for coal transition established with the State of Washington. The valuation period extended to the
assumed decommissioning of the asset, after its projected cessation of operation in its current form in 2025.
Fair value less costs of disposal of the CGU was estimated to approximate its carrying amount, and accordingly, no
impairment charge was recorded. Any adverse change in assumptions, in isolation, would have resulted in an impairment
charge being recorded. We continue to manage risks associated with the CGU through optimization of our operating activities
and capital plan.
We also considered possible impairment at the U.S. Coal CGU in 2015 utilizing a similar process and again found that the fair
value less costs to sell approximates the current carrying amount. Accordingly, there were no impairment charges made
during the year ended Dec. 31, 2015.
Centralia Gas
During 2014 we sold a portion of the assets of the Centralia gas facility to external counterparties and transferred other assets
to other TransAlta facilities. The plant had been fully impaired and idled since 2010. As a result of the transaction, we
recognized impairment reversals of $5 million and the plant’s generating capacity has been removed from TransAlta’s total
owned capacity. In 2015, we reversed $2 million of previously impaired change as a result of additional recoveries.
M45
TRANSALTA CORPORATION M45
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Income Taxes
A reconciliation of income taxes and effective tax rates on earnings, excluding non-comparable items, is presented below:
Year ended Dec. 31
Earnings (loss) before income taxes
Comparable adjustments:
Equity loss
Impacts associated with certain de-designated and economic hedges
Asset impairment charges (reversals)
Restructuring expense (recovery)
Gain on sale of assets
Economic hedges of non-controlling interest in
intercompany foreign exchange contracts
Foreign exchange loss on California claim
Flood-related maintenance costs, net of insurance recovery
TAMA Transmission bid costs
Net other operating losses
Comparable earnings before tax
Comparable (earnings) attributable to non-controlling interests before tax
Comparable earnings attributable to TransAlta shareholders
subject to tax
Comparable income tax expense adjustments:
Income tax (expense) recovery related to impacts associated
with certain de-designated and economic hedges
Income tax expense related to asset impairment charges and reversals
Income tax (expense) recovery related to restructuring provision
Income tax (expense) recovery related to gain on sale of assets
Income tax recovery related to divestiture of investment
Income tax (expense) recovery related to writedown of deferred income
tax assets
Income tax expense related to investment in subsidiary
Income tax (expense) recovery related to changes in corporate income tax rates
Income tax recovery related to non-comparable items attributable to economic
hedges of non-controlling interest in intercompany foreign exchange contracts
Income tax recovery related to flood-related maintenance costs, net of insurance
recovery
Income tax recovery related to TAMA Transmission bid costs
Income tax recovery related to net other operating losses
Total comparable income tax expense adjustments
Income tax expense (recovery)
Comparable income tax expense (recovery)
Comparable income tax expense attributable to non-controlling interest
Comparable income tax expense (recovery)
attributable to TransAlta shareholders
Comparable effective tax rate on earnings attributable to TransAlta
shareholders (%)
M46
M46 TRANSALTA CORPORATION
2015
221
-
60
(2)
22
(262)
8
-
(9)
-
38
76
(85)
(9)
22
(1)
5
(70)
-
56
(95)
(20)
2
(2)
-
(4)
(107)
105
(2)
(5)
(7)
78
2014
239
-
(54)
(6)
-
(2)
-
4
1
5
1
188
(53)
135
(19)
(1)
-
1
35
5
-
-
1
-
1
-
23
7
30
(4)
26
19
2013
(12)
10
103
(18)
(3)
(12)
-
-
7
-
109
184
(31)
153
36
(5)
(1)
(2)
-
(28)
-
5
-
2
-
27
34
(8)
26
(2)
24
16
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
The comparable income tax expense attributable to TransAlta shareholders decreased for the year ended Dec. 31, 2015
compared to 2014 due to lower comparable earnings.
In 2014, the comparable income tax expense increased compared to 2013 due to changes in the amount of earnings between
the jurisdictions in which pre-tax income is earned, offset by lower comparable earnings.
The comparable effective tax rate on earnings attributable to TransAlta shareholders increased for the year ended
Dec. 31, 2015 compared to 2014 due to certain amounts that do not fluctuate with earnings, and changes in the amount of
earnings between the jurisdictions in which pre-tax income is earned.
In 2014, the comparable effective tax rate on earnings attributable to TransAlta shareholders increased compared to 2013 due
to changes in the amount of earnings between the jurisdictions in which pre-tax income is earned and the effect of certain
deductions that do not fluctuate with earnings.
During the year ended Dec. 31, 2015, we reversed a previous writedown of deferred income tax assets of $56 million. The
deferred income tax assets relate mainly to the tax benefits of losses associated with our directly owned U.S. operations. We
had written these assets off as it was no longer considered probable that sufficient future taxable income would be available
from our directly owned U.S. operations to utilize the underlying tax losses, due to reduced price growth expectations.
Recognized other comprehensive income during the year ended Dec. 31, 2015 has given rise to a taxable temporary difference
that forms the primary basis for utilization of some of the tax losses and the reversal of the writedown.
In order to give effect to the Transaction with TransAlta Renewables, a reorganization of certain TransAlta companies was
completed. The reorganization resulted in the recognition in 2015 of $95 million deferred tax liability on TransAlta's
investment in a subsidiary. The deferred tax liability had not been recognized previously, since prior to the reorganization, the
taxable temporary difference was not expected to reverse in the foreseeable future.
During the second quarter of 2015, the Government of Alberta enacted legislation to increase its provincial corporate income
tax rate to 12 per cent from 10 per cent, effective July 1, 2015. This resulted in a net increase in our deferred income tax liability
of $18 million, of which $20 million is recorded in the Consolidated Statement of Earnings with an offsetting $2 million
deferred tax recovery recorded in the Statement of Other Comprehensive Income.
M47
TRANSALTA CORPORATION M47
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Financial Position
The following chart highlights significant changes in the Consolidated Statements of Financial Position from Dec. 31, 2015 to
Dec. 31, 2014:
Trade and other receivables
Inventory
Finance lease receivables (long-term)
Property, plant, and equipment, net
Intangible assets
Deferred income tax assets
Increase/
(decrease)
117
Primary factors explaining change
Timing of customer receipts and increases in collateral paid and
short term portion of finance lease receivables following the
Poplar Creek contract restructuring
23
Increase in coal inventory following lower production, Mass
Solar SREC inventory, and purchase of emission credits
372
60
38
26
Poplar Creek contract restructuring
Acquisition of wind and solar assets ($217 million), sustaining
capital and construction of the South Hedland project ($493
million) and favourable changes in foreign exchange rates
($139 million), partially offset by the net effect of the Poplar
Creek contract restructuring ($130 million), depreciation for the
period ($545 million), and revisions to decommissioning and
restoration costs ($86 million)
Acquisition of Kent Breeze wind farm
Effect of the internal reorganization associated with the
Transaction and an increase in deductible temporary
differences
Risk management assets (current and long-term)
420
Gains on commodity and foreign currency cash flow hedges
Other assets
Other
Total increase in assets
Reclassification of Washington State community investment
contribution funded but not yet disbursed
35
23
1,114
Accounts payable and accrued liabilities
(147)
Timing of payments and accruals
Credit facilities, long-term debt, and finance lease
obligations (including current portion)
Decommissioning and other provisions (current
and long-term)
Deferred income tax liabilities
Risk management liabilities (current and
long-term)
Equity attributable to shareholders
Non-controlling interests
439
42
213
47
77
Unfavourable effects of changes in foreign exchange rates
($392 million) and increase in non-recourse obligations
associated with acquisition of solar and wind facilities ($105
million) and financing of equity to acquire project
($106 million), partially offset by debt repayments
($758 million)
Final installment of MSA settlement ($25 million) and
adjustment to provisions ($66 million)
Effect of the internal reorganization associated with the
Transaction, an increase in the Alberta corporate tax rate, and
an increase in taxable temporary differences
Price movements and changes in underlying positions
and settlements
Gains on cash flow hedges and gains on translating net assets
of foreign operations recognized in other comprehensive
income, and issuance of common shares, partially offset by the
net loss, dividends declared in the period and sale of
investment in subsidiaries to TransAlta Renewables
435
Sale of investment in subsidiaries to TransAlta Renewables and
net earnings for the period, partially offset by distributions paid
and payable to non-controlling interests
Other
Total increase in liabilities and equity
8
1,114
M48
M48 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Cash Flows
The following chart highlights significant changes in the Consolidated Statements of Cash Flows for year ended Dec. 31, 2015
compared to the year ended Dec. 31, 2014:
Year ended Dec. 31
Cash and cash equivalents, beginning of year
Provided by (used in):
Operating activities
2015
43
432
42
796
2014 Primary factors explaining change
Investing activities
(573)
(292)
Financing activities
149
(503)
Translation of foreign currency cash
Cash and cash equivalents, end of year
3
54
-
43
Decrease in cash earnings of $49 million and an adverse change
in non-cash working capital of $315 million
A decrease in proceeds on the sale of investment of
$224 million and the acquisition of solar and wind assets for $101
million
Reduction in the net decrease in borrowings of $500 million, an
increase in proceeds on the sale of non-controlling interest in a
subsidiary of $275 million, and an increase in realized gains on
financial instruments of $52 million, partially offset by a decrease
in net proceeds on the issuance of preferred shares of $161
million
Year ended Dec. 31
Cash and cash equivalents, beginning of year
Provided by (used in):
Operating activities
Investing activities
2014
42
2013 Explanation of change
27
796
765
Increase in cash earnings of $32 million. Refer to our discussion
of funds from operations
(292) (703) Increase in proceeds on sale of investments of $224 million, a
decrease in cash paid on the acquisition of Wyoming Wind of
$109 million, a decrease in additions to property, plant, and
equipment ("PP&E") and intangibles of $72 million, and a
decrease in investing non-cash working capital balances of $31
million, partially offset by a decrease in realized gains on
financial instruments of $16 million and a decrease in proceeds
on disposal of PP&E of $8 million
Financing activities
(503)
(47)
An increase in repayments of borrowings under credit facilities
and in repayments (net of issuances) of long-term debt of $504
million, a decrease in proceeds on sale of non-controlling interest
in a subsidiary of $78 million, an increase in distributions paid to
subsidiaries' non-controlling interests of $29 million, and an
increase in common share cash dividends of $24 million, partially
offset by an increase in proceeds on issuance of preferred shares
of $161 million and an increase in realized gains on financial
instruments of $20 million
Cash and cash equivalents, end of year
43
42
M49
TRANSALTA CORPORATION M49
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Unconsolidated Structured Entities or Arrangements
Disclosure is required of all unconsolidated structured entities or arrangements such as transactions, agreements, or
contractual arrangements with unconsolidated entities, structured finance entities, special purpose entities, or variable
interest entities that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital
resources. We currently have no such unconsolidated structured entities or arrangements.
Guarantee Contracts
We have obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including
those related to potential environmental obligations, commodity risk management and hedging activities, construction
projects, and purchase obligations. At Dec. 31, 2015, we provided letters of credit totalling $575 million (2014 - $396 million)
and cash collateral of $74 million (2014 - $25 million). These letters of credit and cash collateral secure certain amounts
included on our Consolidated Statements of Financial Position under risk management liabilities and decommissioning and
other provisions.
Commitments
Contractual commitments are as follows:
1
2016
2017
2018
2019
2020
2021 and
thereafter
Natural gas, transportation,
and other purchase contracts
Transmission
Coal supply and mining agreements
Long-term service agreements
Non-cancellable operating leases
Long-term debt(1)
Finance lease obligations
Interest on long-term debt
and finance lease obligations(2)
Growth
TransAlta Energy Bill
Total
52
14
151
103
9
72
15
225
85
6
732
17
8
46
110
8
604
14
216
186
6
15
9
50
23
7
947
12
171
6
6
6
7
50
19
7
761
8
138
1
6
1,215
1,246
1,003
6
7
52
36
7
447
7
106
-
6
674
Total
201
51
891
361
88
4,427
82
1,652
278
49
105
6
542
70
50
1,596
26
796
-
19
3,210
8,080
As part of the TransAlta Energy Bill signed into law in the State of Washington and the subsequent MoA, we have committed
to fund US$55 million over the remaining life of the U.S. Coal plant to support economic and community development,
promote energy efficiency, and develop energy technologies related to the improvement of the environment. The MoA
contains certain provisions for termination and in the event of the termination and certain circumstances, this funding or part
thereof would no longer be required.
(1) Repayments of long-term debt include amounts related to our credit facilities that are currently scheduled to mature in 2019.
(2) Interest on long-term debt is based on debt currently in place with no assumption as to re-financing an instrument on maturity.
M50
M50 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Earnings and Other Measures on a Comparable Basis
We evaluate our performance and the performance of our business segments using a variety of measures. Those discussed
below, and elsewhere in this MD&A, are not defined under IFRS and, therefore, should not be considered in isolation or as an
alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from operating
activities, as determined in accordance with IFRS, when assessing our financial performance or liquidity. These measures are
not necessarily comparable to a similarly titled measure of another company.
Each business segment assumes responsibility for its operating results measured to gross margin and operating income.
Operating income and gross margin provides management and investors with a measurement of operating performance that
is readily comparable from period to period.
In calculating these items, we exclude certain items as management believes these transactions are not representative of our
business operations. Earnings on a comparable basis per share are calculated using the weighted average common shares
outstanding during the period.
During 2015, prior period restatements were made to 2014 and 2013. Refer to the Current Accounting Changes section of this
MD&A for a description of these items.
The adjustments made to calculate comparable EBITDA and comparable earnings for the year ended Dec. 31, 2015 and 2014
are as follows. References are to the reconciliation presented on the following pages.
M51
TRANSALTA CORPORATION M51
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Year ended Dec. 31
Reference
number
Adjustment
Reclassifications:
1
2
3
4
Finance lease income used as a proxy for
operating revenue
Decrease in finance lease receivable used as
a proxy for operating revenue and
depreciation
Reclassification of mine depreciation from fuel
and purchased power
Reclassification of comparable gain on sale of
property, plant, and equipment that is included in
depreciation
Segment
Gas
Gas
Canadian Coal
Canadian Coal
Adjustments (increasing (decreasing) earnings to arrive at comparable results):
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Impacts to revenue associated with certain
de-designated and economic hedges
Restructuring expense (recovery)
MSA settlement
Economic hedges of non-controlling interest in
intercompany foreign exchange contracts
Gain on Poplar Creek contract restructuring
Net tax effect on comparable adjustments
subject to tax
(Reversal) accrual of writedown of
deferred income tax assets
Income tax expense related to the Transaction
Deferred income tax rate adjustment
Maintenance costs related to the Alberta flood
of 2013, net of insurance recoveries
Costs related to TAMA Transmission bid
Asset impairment charges (reversals)
California claim
Non-comparable portion of insurance
recovery received
Sundance Units 1 and 2 return to service
Loss on assumption of pension obligation
Foreign exchange on California claim
U.S. Coal
Canadian Coal
U.S. Coal
Gas
Energy Marketing
Corporate
Energy Marketing
Unassigned
Gas
Unassigned
Unassigned
Unassigned
Unassigned
Hydro
Corporate
Gas
Wind
Hydro
Energy Marketing
Hydro
Canadian Coal
Canadian Coal
Unassigned
Non-comparable gain on sale of assets
Equity Investments
Income tax recovery related to sale
of investment
Non-comparable items attributable to
non-controlling interest
Corporate
Unassigned
Unassigned
M52
M52 TRANSALTA CORPORATION
2015
2014
2013
58
23
62
-
49
3
56
1
46
1
58
2
60
(54)
103
11
1
1
3
6
56
8
(262)
48
(56)
95
20
(9)
-
(2)
-
-
-
-
-
-
-
-
-
-
-
18
(5)
-
-
1
5
(6)
-
-
5
(18)
(4)
-
-
-
-
-
-
-
-
4
(2)
-
(36)
14
1
(2)
-
-
-
(1)
-
-
-
(62)
28
-
-
7
-
1
(23)
4
56
(1)
25
29
-
-
(12)
-
-
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
A reconciliation of comparable results to reported results for the year ended Dec. 31, 2015 and 2014 is as follows:
Year ended Dec. 31
2015
2014
Revenues
Fuel and purchased power
Gross margin
Operations, maintenance, and administration
Asset impairment reversals
Restructuring provision
Taxes, other than income taxes
Gain on sale of assets
Net other operating (income) losses
EBITDA
Depreciation and amortization
Operating income
Finance lease income
Foreign exchange gain (loss)
Gain on sale of assets
Earnings (loss) before interest
and taxes
Net interest expense
Income tax expense (recovery)
Net earnings
Non-controlling interests
Net earnings (loss) attributable to
TransAlta shareholders
Preferred share dividends
Net earnings (loss) attributable to
common shareholders
Weighted average number of common
shares outstanding in the year
Net earnings (loss) per share
attributable to common shareholders
Reported
2,267
1,008
1,259
492
(2)
22
29
-
25
693
545
148
58
4
262
472
251
105
116
94
22
46
(24)
280
(0.09)
Comparable
reclassifications
Comparable
adjustments
Comparable
total
(1, 2)
(3)
-
(2, 3)
(1)
81
(62)
143
-
-
-
-
-
-
143
85
58
(58)
-
-
-
-
-
-
-
-
-
-
(5)
(14)
(16)
(6)
(7, 18)
(8)
(9)
(10, 11, 12, 13)
(24)
60
-
60
9
2
(22)
-
-
(38)
109
-
109
-
8
(262)
(145)
-
(107)
(38)
(14)
(24)
-
(24)
2,408
946
1,462
501
-
-
29
-
(13)
945
630
315
-
12
-
327
251
(2)
78
80
(2)
46
(48)
280
Reported
2,623
1,092
1,531
542
(6)
-
29
-
(14)
980
538
Comparable
reclassifications
52
(56)
108
-
-
-
-
(1)
-
109
60
49
(49)
-
-
-
-
-
-
-
-
-
-
442
49
-
2
493
254
7
232
50
182
41
141
273
(1, 2)
(3)
(4)
(2, 3, 4)
(1)
Comparable
adjustments
(54)
-
(54)
(6)
6
-
-
-
(1)
(53)
-
(5)
(14, 15)
(16)
(17, 18)
(21)
(22)
(10, 11)
(23)
(53)
-
4
(2)
(51)
-
23
(74)
(1)
(73)
-
(73)
(0.17)
0.52
Comparable
total
2,621
1,036
1,585
536
-
-
29
(1)
(15)
1,036
598
438
-
4
-
442
254
30
158
49
109
41
68
273
0.25
M53
TRANSALTA CORPORATION M53
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
A reconciliation of comparable results to reported results for the year ended Dec. 31, 2013 is as follows:
2013
Comparable
adjustments
103 (5)
-
103
(5) (14)
(16)
18
(6)
3
-
Comparable
reclassifications
(1, 2)
(3)
47
(58)
105
-
-
-
-
(4)
(2)
-
(109) (17, 18, 19, 20)
196
(14)
(2)
198
-
-
-
(12) (22)
186
-
34
(10, 11)
152
-
152
-
152
-
107
61
46
(2, 3, 4)
(1)
(46)
-
-
-
-
-
-
-
-
-
-
-
Comparable
total
2,442
890
1,552
511
-
-
27
(2)
(7)
1,023
584
439
-
(10)
1
-
430
256
26
148
29
119
38
81
264
0.31
Year ended Dec. 31
Revenues
Fuel and purchased power
Gross margin
Operations, maintenance, and administration
Asset impairment reversal
Restructuring provision
Taxes, other than income taxes
Gain on sale of assets
Net other operating (income) losses
EBITDA
Depreciation and amortization
Operating income
Finance lease income
Equity loss
Foreign exchange gain
Gain on sale of assets
Earnings before interest and taxes
Net interest expense
Income tax recovery
Net earnings (loss)
Non-controlling interests
Net earnings (loss) attributable
to TransAlta shareholders
Preferred share dividends
Net earnings (loss) attributable
to common shareholders
Weighted average number of common shares
outstanding in the year
Net earnings per share attributable to
common shareholders
Reported
2,292
948
1,344
516
(18)
(3)
27
-
102
720
525
195
46
(10)
1
12
244
256
(8)
(4)
29
(33)
38
(71)
264
(0.27)
M54
M54 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Financial Instruments
Financial instruments are used for proprietary trading purposes and to manage our exposure to interest rates, commodity
prices, and currency fluctuations, as well as other market risks. We currently use physical and financial swaps, forward sale
and purchase contracts, futures contracts, foreign exchange contracts, interest rate swaps, and options to achieve our risk
management objectives. Some of our physical commodity contracts have been entered into and are held for the purposes of
meeting our expected purchase, sale or usage requirements (“own use”) and as such, are not considered financial
instruments, and are not recognized as a financial asset or financial liability. Other physical commodity contracts that are not
held for normal purchase or sale requirements and derivative financial instruments are recognized on the Consolidated
Statements of Financial Position and are accounted for using the fair value method of accounting. The initial recognition of fair
value and subsequent changes in fair value can affect reported earnings in the period the change occurs if hedge accounting is
not elected. Otherwise, changes in fair value will generally not affect earnings until the financial instrument is settled.
Some of our financial instruments and physical commodity contracts qualify for, and are recorded under, hedge accounting
rules. The accounting for those contracts for which we have elected to apply hedge accounting depends on the type of hedge.
Our financial instruments are categorized as fair value hedges, cash flow hedges, net investment hedges, or non-hedges.
These categories and their associated accounting treatments are explained in further detail below.
For all types of hedges, we test for effectiveness at the end of each reporting period to determine if the instruments are
performing as intended and hedge accounting can still be applied. The financial instruments we enter into are designed to ensure
that future cash inflows and outflows are predictable. In a hedging relationship, the effective portion of the change in the fair value
of the hedging derivative does not impact net earnings, while any ineffective portion is recognized in net earnings.
We have certain contracts in our portfolio that, at their inception, do not qualify for, or we have chosen not to elect to apply,
hedge accounting. For these contracts, we recognize in net earnings mark-to-market gains and losses resulting from changes
in forward prices compared to the price at which these contracts were transacted. These changes in price alter the timing of
earnings recognition, but do not necessarily determine the final settlement amount received. The fair value of future contracts
will continue to fluctuate as market prices change.
The fair value of derivatives traded by the Corporation that are not traded on an active exchange, or extend beyond the time
period for which exchange-based quotes are available, are determined using valuation techniques or models.
Fair Value Hedges
Fair value hedges are used to offset the impact of changes in the fair value of fixed rate long-term debt caused by variations in
market interest rates. We use interest rate swaps in our fair value hedges.
In a fair value hedge, changes in the fair value of the hedging instrument (an interest rate swap, for example) are recognized in
risk management assets or liabilities, and the related gains or losses are recognized in net earnings. The carrying amount of
long-term debt subject to the hedge is adjusted for losses or gains associated with the hedged risk, with the corresponding
amounts recognized in net earnings. As a result, only the net ineffectiveness is recognized in net earnings.
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TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Cash Flow Hedges
Cash flow hedges are categorized as project, foreign exchange, interest rate, or commodity hedges and are used to offset
foreign exchange, interest rate, and commodity price exposures resulting from market fluctuations.
Foreign currency forward contracts are used to hedge foreign exchange exposures resulting from anticipated contracts and
firm commitments denominated in foreign currencies, primarily related to capital expenditures.
Physical and financial swaps, forward sale and purchase contracts, futures contracts, and options are used primarily to offset
the variability in future cash flows caused by fluctuations in electricity and natural gas prices. Foreign exchange forward
contracts and cross-currency swaps are used to offset the exposures resulting from foreign-denominated long-term debt.
Interest rate swaps are used to convert the fixed interest cash flows related to interest expense at debt to floating rates and
vice versa.
In a cash flow hedge, changes in the fair value of the hedging instrument (a forward contract or financial swap, for example)
are recognized in risk management assets or liabilities, and the related gains or losses are recognized in OCI. These gains or
losses are subsequently reclassified from OCI to net earnings in the same period as the hedged forecast cash flows impact net
earnings, and offset the losses or gains arising from the forecast transactions. For project hedges, the gains and losses
reclassified from OCI are included in the carrying amount of the related PP&E.
When we do not elect hedge accounting, or when the hedge is no longer effective and does not qualify for hedge accounting,
the gains or losses as a result of changes in prices, interest, or exchange rates related to these financial instruments are
recorded in net earnings in the period in which they arise.
Net Investment Hedges
Foreign currency forward contracts and foreign-denominated long-term debt are used to hedge exposure to changes in the
carrying values of our net investments in foreign operations that have a functional currency other than the Canadian dollar.
Gains or losses on these instruments are recognized and deferred in OCI and reclassified to net earnings on the disposal of
the foreign operation. We attempt to manage foreign exchange risk by matching foreign-denominated expenses with
revenues, such as offsetting revenues from our U.S. operations with interest payments on our US dollar debt.
Non-Hedges
Financial instruments not designated as hedges are used for proprietary trading and to reduce commodity price, foreign
exchange, and interest rate risks. Changes in the fair value of financial instruments not designated as hedges are recognized in
risk management assets or liabilities, and the related gains or losses are recognized in net earnings in the period in which the
change occurs.
Fair Values
The majority of fair values for our project, foreign exchange, interest rate, commodity hedges, and non-hedge derivatives are
calculated using adjusted quoted prices from an active market or inputs validated by broker quotes. We may enter into
commodity transactions involving non-standard features for which market-observable data is not available. These
transactions are defined under IFRS as Level III instruments. Level III instruments incorporate inputs that are not observable
from the market, and fair value is therefore determined using valuation techniques. Fair values are validated by using
reasonably possible alternative assumptions as inputs to valuation techniques, and any material differences are disclosed in
the notes to the financial statements. At Dec. 31, 2015, Level III instruments had a net asset carrying value of $542 million.
Refer to the Critical Accounting Policies and Estimates section of this MD&A for further details regarding valuation
techniques. Our risk management profile and practices have not changed materially from Dec. 31, 2014.
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M56 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
2016 Financial Outlook
In consideration of low power prices in Alberta and the Pacific Northwest, anticipated lower cash interest, and higher
distributions to non-controlling interest payments, the following table outlines our expectation on key financial targets for 2016:
Measure
Comparable EBITDA
Comparable FFO
Comparable FCF
Dividend
Target
$990 million to $1,100 million
$755 million to $835 million
$250 million to $300 million
$0.16 per share, 15 to 18 per cent payout of Comparable FCF
Market
For 2016, power prices in Alberta are expected to be comparable to 2015 as a result of persistent low natural gas prices, low
demand growth, and the current level of supply. However, prices can vary based on supply and weather conditions. In the
Pacific Northwest we expect power prices to be lower as well due to low natural gas prices. We do not have significant
uncontracted positions in other jurisdictions.
Operations
Availability
Availability of our coal fleet in Canada is expected to be in the range of 87 to 89 per cent in 2016. Availability of our other
generating assets (gas, renewables) generally exceeds 95 per cent.
Contracted Cash Flows
As a result of Alberta PPAs and long-term contracts, approximately 75 per cent of our capacity is contracted over the next
two years. This is reduced to 65 per cent when our Alberta PPAs expire in 2017. More than half of our non-contracted
generation is sold forward 12 to 18 months ahead of time using short-term physical or financial contracts, such that on an
aggregated portfolio basis, depending on market conditions, we target being up to 90 per cent contracted for the upcoming
calendar year. As at the end of 2015, approximately 87 per cent of our 2016 capacity was contracted. The average prices of
our short-term physical and financial contracts for 2016 are approximately $50 per MWh in Alberta and approximately
US$45 per MWh in the Pacific Northwest.
Fuel Costs
Mining costs at our Alberta coal mine are expected to decrease in 2016 due to effective cost control, and production
improvements. Seasonal variations in coal costs at our Alberta mine are minimized through the application of standard
costing. Coal costs for 2016, on a standard cost per tonne basis, are expected to be one to two per cent lower than 2015 unit
costs.
In the Pacific Northwest, our U.S. Coal mine, adjacent to our power plant, is in the reclamation stage. Fuel at U.S. Coal is
purchased primarily from external suppliers in the Powder River Basin and delivered by rail. The delivered cost of fuel per
MWh for 2016 is expected to decrease by approximately three per cent due to lower diesel surcharge costs on coal deliveries.
The value of coal inventories is assessed for impairment at the end of each reporting period. If the inventory is impaired,
further charges are recognized in net earnings.
Most of our generation from gas is sold under contract with pass-through provisions for fuel. For gas generation with no pass-
through provision, we purchase natural gas from outside companies coincident with production, thereby minimizing our risk
to changes in prices.
We closely monitor the risks associated with changes in electricity and input fuel prices on our future operations and, where we
consider it appropriate, use various physical and financial instruments to hedge our assets and operations from such price risks.
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TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Energy Marketing
EBITDA from our Energy Marketing Segment is affected by prices and volatility in the market, overall strategies adopted, and
changes in regulation and legislation. We continuously monitor both the market and our exposure to maximize earnings while
still maintaining an acceptable risk profile. Energy Marketing historically contributes between $60 million to $80 million in
gross margin.
Exposure to Fluctuations in Foreign Currencies
Our strategy is to minimize the impact of fluctuations in the Canadian dollar against the US dollar and Australian dollar by
offsetting foreign-denominated assets with foreign-denominated liabilities and by entering into foreign exchange contracts. We
also have foreign-denominated expenses, including interest charges, which partly offset our net foreign-denominated revenues.
Net Interest Expense
Net interest expense for 2016 is expected to be lower than in 2015, primarily due to higher capitalized interest and lower debt
balance. However, changes in interest rates and in the value of the Canadian dollar relative to the US dollar can affect the
amount of net interest expense incurred. Most of our debt is at fixed interest rates.
Liquidity and Capital Resources
We expect to maintain adequate available liquidity under our committed credit facilities. Free cash flows generated by the
business should be sufficient to support the construction of the South Hedland project station in 2016.
Income Taxes
The effective tax rate on earnings, excluding non-comparable items for 2016, is expected to be approximately 10 to 15
per cent, which is lower than the statutory tax rate of 26 per cent, due to changes in the amount of earnings between the
jurisdictions in which pre-tax income is earned and the effect of certain deductions that do not fluctuate with earnings.
Capital Expenditures
Our major projects are focused on sustaining our current operations and supporting our growth strategy.
Growth and Major Project Expenditures
A summary of the significant growth and major projects that are in progress is outlined below:
Total Project
Estimated
spend
Spent to
date(1)
2016
Estimated
spend
Target
completion
date
Details
Project
South Hedland
power station(2)
Solomon load bank
facility(3)
589
242
5
2
113
3
Q2 2017
150 MW combined cycle power plant
Q2 2016
Installation of 20 MW load bank facility required
to complete the Solomon power station
Transmission
Not applicable
(4)
13
Ongoing
Regulated transmission that receives a return on
investment
Total
1 234
594
244
129
(1) Represents amounts spent as of Dec. 31, 2015.
(2) Estimated project spend is AUD$570 million. Total estimated project spend is stated in CAD$ and includes estimated capital interest costs. The total estimated project
spend may change due to fluctuation in foreign exchange rates.
(3) Includes certain natural gas conversion costs at the Solomon power station that will be recognized as a finance lease receivable. The total estimated project spend may
change due to fluctuations in foreign exchange rates.
(4) Transmission projects are aggregated and develop on an ongoing basis. Consequently, discrete project spend is not available.
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M58 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Sustaining and Productivity Expenditures
A significant portion of our sustaining and productivity capital is planned major maintenance, which includes inspection,
repair and maintenance of existing components, and the replacement of existing components. Planned major maintenance
costs are capitalized as part of PP&E and are amortized on a straight-line basis over the term until the next major maintenance
event. It excludes amounts for day-to-day routine maintenance, unplanned maintenance activities, and minor inspections and
overhauls, which are expensed as incurred.
Our estimate for total sustaining and productivity capital is allocated among the following:
Category
Description
Routine capital
Capital required to maintain our existing generating capacity
Planned major maintenance
Regularly scheduled major maintenance
Mine capital
Finance leases
Capital related to mining equipment and land purchases
Payments on finance leases
Total sustaining capital excluding flood-recovery capital
Flood-recovery capital
Capital arising from the 2013 Alberta flood
Total sustaining capital
Productivity capital
Projects to improve power production efficiency and
corporate improvement initiatives
Total sustaining and productivity capital
1
Spent
in 2014
Restated (1)
Spent
in 2015
Expected
spend in 2016
135
162
45
10
352
9
361
14
375
101
162
25
13
301
4
305
6
311
100 - 105
170 - 175
30 - 35
15
315 - 330
15 - 20
330 - 350
10 - 20
340 - 370
The planned major maintenance for 2015 included $9 million associated with major maintenance at Poplar Creek, which was
incurred prior to the close of the contractual restructuring. Our customer has assumed capital obligations of the facility arising
after closing, and on an ongoing basis thereafter. Planned major outage for 2016 includes major turnaround of three units that
we operate, and two that our partners operate. Our planned outage also includes significant work at our hydro facilities,
including the Ghost river diversion and a stator/generator replacement.
Lost production as a result of planned major maintenance, excluding planned major maintenance for U.S. Coal, which is
scheduled during a period of economic dispatching, is estimated as follows for 2016:
GWh lost
Coal
Gas and Renewables
Total
945 - 955
135 - 145
1,080 - 1,100
Financing
Financing for these capital expenditures is expected to be provided by cash flow from operating activities. We have access to
approximately $1.4 billion in liquidity, if required. The funds required for committed growth, sustaining capital, and
productivity projects are not expected to be significantly impacted by the current economic environment.
Sustainable Development Targets
Our 2016 and longer-term sustainability targets support the long-term success of our business. Targets are set in line with
business unit goals to manage key areas of concern for stakeholders and ultimately improve our environmental and social
performance in these areas. We continue to evolve and adapt targets to focus on anticipated key areas of materiality to
stakeholders. Targets are outlined below:
(1) Restated to include hydro life extension from growth capital expenditures to sustaining capital expenditures. Refer to the Current Accounting Changes section of this MD&A.
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TRANSALTA CORPORATION M59
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
1. Maintain our investment
grade rating
2. Increase focus on FFO and
EBITDA
Financial
Annual Performance Status
Achieve and maintain investment grade credit metrics.
Consistent with 2015 target
Deliver comparable EBITDA and comparable FFO for 2016 in the
range of $990 million to $1,100 million and $755 million to $835
million respectively
6-8 per cent improvement from
2015
3. Grow asset portfolio
4. Achieve top quartile
performance in Canadian Coal
Power Generating Portfolio
Deliver an average of $40 million to $60 million of additional
EBITDA from growth projects
Continue to deliver 87 to 89 per cent availability in the segment
5. Reduce safety incidents
Achieve an Injury Frequency Rate (IFR) below 0.70
Human and Intellectual
Annual Performance Status
Consistent with 2015 target
Consistent with 2015 target in
respect of the segment
Annual Performance Status
22 per cent improvement over
2015 target of 0.75
6. Manage employee turnover Maintain voluntary turnover percentage under eight percent
Consistent with 2015 target
7. Support employee
development
Achieve 100 per cent completion of development plans for all high-
potential employees at the top three levels of the organization
Consistent with 2015 target
8. Enhance the capability of
TransAlta leaders
Complete the final three stages of our globally recognized leadership
development project to ensure TransAlta’s top three tiers of leaders
have the tools to successfully reposition and grow our business
New target
9. Minimize fleet-wide
environmental incidents
Keep recorded incidents (including spills and air infractions)
below 13
Environmental
Replace annual topsoil at Highvale Mine of 74 acres/year
Annual Performance Status
28 per cent improvement over
2015 target (18)
Consistent with 2015 target (74
acres)
10. Increase mine reclaimed
acreage
11. Utilize coal by-product
12. Reduce air emissions
13. Reduce GHG emissions
Sell a minimum of two million tonnes of coal by-product materials
during the period 2015 to 2017
33 per cent achieved (long-term
target)
95 per cent reduction from 2005 levels of TransAlta coal facility
NOx and SO2 emissions by 2030
Consistent with 2015 (long-term
target)
20 per cent reduction from 2005 levels of TransAlta coal facility
GHG by 2021, or the equivalent of 7,000,000 tonnes, of CO2e per
year
Consistent with 2015 target
(long-term target)
55 per cent reduction from 2005 levels of TransAlta coal facility
GHG by 2030, or the equivalent of 19,700,000 tonnes, of CO2e per
year
Consistent with 2015 target
(long-term target)
14. Combine stakeholder
engagement
Implement final Stakeholder Engagement Framework. In 2016 every
business unit will use a single framework for stakeholder guidance
New target
Local Communities
Annual Performance Status
15. Support youth education
with community investment
50 per cent of total communitiy investment spending will be
directed to supporting youth education
16. Increase internal best
practice Aboriginal engagement
awareness
Work with our aboriginal communities to develop an online best
practice guide for employees on working with and engaging with
aboriginal communities
New target
New target
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M60 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report Management’s Discussion and Analysis
Governance and Risk Management
Our business activities expose us to a variety of risks and opportunities including, but not limited to, regulatory changes,
rapidly changing market dynamics, and increased volatility in our key commodity markets. Our goal is to manage these risks
and opportunities so that we are in position to develop our business and achieve our goals while remaining reasonably
protected from an unacceptable level of risk or financial exposure. We use a multilevel risk management oversight structure to
manage the risks and opportunities arising from our business activities, the markets in which we operate, and the political
environments and structures with which we interface.
Governance
The key elements of our governance practices are:
employees, management and the Board are committed to ethical business conduct, integrity and honesty;
we have established key policies and standards to provide a framework for how we conduct our business;
the Chair of our Board and all directors, other than our Chief Executive Officer (“CEO”) are independent;
the Board is comprised of individuals with a mix of skills, knowledge, and experience that are critical for our business and
our strategy;
the effectiveness of the Board is achieved through annual evaluations and continuing education of our directors; and
our management and Board facilitate and foster an open dialogue with shareholders and community stakeholders.
Commitment to ethical conduct is the foundation of our corporate governance model. We have adopted the following codes
of conduct to guide our business decisions and everyday business activities:
Corporate Code of Conduct, which applies to all employees and officers of TransAlta and its subsidiaries;
Directors’ Code of Conduct;
Finance Code of Ethics, which applies to all financial employees of the Corporation; and
Energy Trading Code of Conduct, which applies to all of our employees engaged in energy marketing.
Our codes of conduct outline the standards and expectations we have for our employees, officers, and directors with respect
to the protection and proper use of our assets. The codes also provide guidelines with respect to securing our assets, conflicts
of interest, respect in the workplace, social responsibility, privacy, compliance with laws, insider trading, environment, health
and safety, and our commitment to ethical and honest conduct. Our Corporate Code of Conduct goes beyond the laws, rules,
and regulations that govern our business in the jurisdictions in which we operate; it outlines the principal business practices
with which all employees must comply.
Our employees, officers, and directors are reminded annually about the importance of ethics and professionalism in their daily
work, and must certify annually that they have reviewed and understand their responsibilities as set forth in the respective
codes of conduct. This certification also requires our employees, officers, and directors to acknowledge that they have
complied with the standards set out in the respective code during the last calendar year.
The Board provides stewardship of the Corporation and ensures that the Corporation establishes key policies and procedures
for the identification, assessment, and management of principal risks and strategic plans. The Board monitors and assesses
the performance and progress of the Corporation’s goals through candid and timely reports from the CEO and the senior
management team. We have also established an annual evaluation process whereby our directors are provided with an
opportunity to evaluate the Board, Board committees, individual directors, and the chair’s performance.
In order to allow the Board to establish and manage the financial, environmental, and social elements of our governance
practices, the Board has established the Audit and Risk Committee (“ARC”), the Governance and Environment Committee
(the “GEC”), and the Human Resources Committee (the “HRC”).
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TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
The ARC, consisting of independent members of the Board, provides assistance to the Board in fulfilling its oversight
responsibility relating to the integrity of our financial statements and the financial reporting process; the systems of internal
accounting and financial controls; the internal audit function; the external auditors’ qualifications and terms and conditions of
appointment, including remuneration; independence; performance and reports; and the legal and risk compliance programs as
established by management and the Board. The ARC approves our Commodity and Financial Exposure Management policies
and reviews quarterly Enterprise Risk Management (“ERM”) reporting.
The GEC is responsible for developing and recommending to the Board a set of corporate governance principles applicable to
the Corporation and for monitoring the compliance with these principles. The GEC is also responsible for Board recruitment
and for the nomination of directors to the Board and its committees. In addition, the GEC assists the Board in fulfilling its
oversight responsibilities with respect to the Corporation’s monitoring of environmental, health and safety regulations and
public policy changes and the establishment and adherence to environmental, health and safety practices, procedures and
policies. The GEC also receives an annual report on the annual Corporate Code of Conduct certification process.
In regards to overseeing and seeking to ensure that the Corporation consistently achieves strong environment, health and
safety (“EH&S”) performance, the GEC undertakes a number of actions that include: (i) receiving regular reports from
management regarding environmental compliance, trends, and TransAlta’s responses; (ii) receiving reports and briefings on
management’s initiatives with respect to changes in climate change legislation, policy developments as well as other draft
initiatives and the potential impact such initiatives may have on our operations; (iii) assessing the impact of the GHG
policies implementation and other legislative initiatives on the Corporation’s business; (iv) reviewing with management the
EH&S policies of the Corporation; (v) reviewing with management the health and safety practices implemented within the
Corporation, as well as the evaluation and training processes put in place to address problem areas; (vi) receiving reports from
management on the near-miss reporting program and discussing with management ways to improve the EH&S processes and
practices; and (vi) reviewing the effectiveness of our response to EH&S issues and any new initiatives put in place to further
improve the Corporation’s EH&S culture.
The HRC is empowered by the Board to review and approve key compensation and human resources policies of the
Corporation that are intended to attract, recruit, retain, and motivate employees of the Corporation. The HRC also makes
recommendations to the Board regarding the compensation of the Corporation’s executive officers, including the review and
adoption of equity-based incentive compensation plans, the adoption of human resources policies which support human
rights and ethical conduct, and the review and approval of executive management succession and development plans.
The responsibilities of other stakeholders within our risk management oversight structure are described below:
The CEO and senior management review key risks quarterly. Specific Trading Risk Management reviews are held monthly by
the Commodity and Compliance Risk Committee, and weekly by the Managing Director Commodity Risk, the commercial
Managing Directors in Trading and Marketing, and the Senior Vice-President Trading and Marketing.
The Investment Committee is chaired by our Chief Financial Officer and is comprised of the Chief Executive Officer, Chief
Financial Officer, Chief Legal and Compliance Officer, and Chief Investment Officer. It reviews and approves all major capital
expenditures including growth, productivity, life extensions, and major coal outages. Projects that are approved by the
committee will then be put forward for approval by the Board, if required.
TransAlta is listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange and is subject to the governance
regulations, rules, and standards applicable under both exchanges. Our corporate governance practices meet the following
governance rules of the TSX and Canadian Securities Administrators: (i) Multilateral Instrument 52-109 - Certification of
Disclosure in Issuers’ Annual and Interim Filings; (ii) Multilateral Instrument 52-110 - Audit Committees; (iii) National Policy
58-201 - Corporate Governance Guidelines; and (iv) National Instrument 58-101 - Disclosure of Corporate Governance
Practices. As a “foreign private issuer” under U.S. securities laws, we are generally permitted to comply with Canadian
corporate governance requirements. Additional information in regards to our governance practices can be found in our
management proxy circular.
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M62 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Risk Controls
Our risk controls have several key components:
Enterprise Tone
We strive to foster beliefs and actions that are true to and respectful of our many stakeholders. We do this by investing in
communities where we live and work, operating and growing sustainably, putting safety first, and being responsible to the
many groups and individuals with whom we work.
Policies
We maintain a comprehensive set of enterprise-wide policies. These policies establish delegated authorities and limits for
business transactions, as well as allow for an exception approval process. Periodic reviews and audits are performed to ensure
compliance with these policies. All employees and directors are required to sign a corporate code of conduct on an annual basis.
Reporting
On a regular basis, residual risk exposures are reported to key decision makers including the Board, senior management, and
the Risk Management Committee (“RMC”). Reporting to the RMC includes analysis of new risks, monitoring of status to risk
limits, review of events that can affect these risks, and discussion and status of actions to minimize risks. This quarterly
reporting provides for effective and timely risk management and oversight.
Whistleblower System
We have a process in place where employees, shareholders, or other stakeholders may anonymously report any potential
ethical concerns. These concerns can be submitted confidentially and anonymously, either directly to the ARC or to
TransAlta’s Ethics Helpline. All complaints are investigated and the ARC receives a report at every scheduled committee
meeting on all findings. If the findings are urgent, they will be reported to the Chair of the Board immediately.
Value at Risk and Trading Positions
Value at risk (“VaR”) is one of the primary measures used to manage our exposure to market risk resulting from commodity
risk management activities. VaR is calculated and reported on a daily basis. This metric describes the potential change in the
value of our trading portfolio over a three-day period within a 95 per cent confidence level, resulting from normal market
fluctuations.
VaR is a commonly used metric that is employed by industry to track the risk in commodity risk management positions and
portfolios. Two common methodologies for estimating VaR are the historical variance/covariance and Monte Carlo approaches.
We estimate VaR using the historical variance/covariance approach. An inherent limitation of historical variance/covariance VaR
is that historical information used in the estimate may not be indicative of future market risk. Stress tests are performed
periodically to measure the financial impact to the trading portfolio resulting from potential market events, including fluctuations
in market prices, volatilities of those prices, and the relationships between those prices. We also employ additional risk mitigation
measures. VaR at Dec. 31, 2015 associated with our proprietary commodity risk management activities was $5 million
(2014 - $5 million). Refer to the Commodity Price Risk section of this MD&A for further discussion.
Risk Factors
Risk is an inherent factor of doing business. The following section addresses some, but not all, risk factors that could affect our
future results and our activities in mitigating those risks. These risks do not occur in isolation, but must be considered in
conjunction with each other.
For some risk factors we show the after-tax effect on net earnings of changes in certain key variables. The analysis is based on
business conditions and production volumes in 2015. Each item in the sensitivity analysis assumes all other potential variables
are held constant. While these sensitivities are applicable to the period and the magnitude of changes on which they are
based, they may not be applicable in other periods, under other economic circumstances, or for a greater magnitude of
changes. The changes in rates should also not be assumed to be proportionate to earnings in all instances.
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TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Volume Risk
Volume risk relates to the variances from our expected production. For example, the financial performance of our Hydro,
Wind, and Solar operations are partially dependent upon the availability of their input resources in a given year. Where we are
unable to produce sufficient quantities of output in relation to contractually specified volumes, we may be required to pay
penalties or purchase replacement power in the market.
We manage volume risk by:
actively managing our assets and their condition through the generation segments in order to be proactive in plant
maintenance so that our plants are available to produce when required;
monitoring water resources throughout Alberta to the best of our ability and optimizing this resource against real-time
electricity market opportunities;
placing our facilities in locations that we believe to have adequate resources to generate electricity to meet the
requirements of our contracts. However, we cannot guarantee that these resources will be available when we need them
or in the quantities that we require; and
diversifying our fuels and geography as one way of mitigating regional or fuel-specific events.
The sensitivities of volumes to our net earnings are shown below:
Factor
Availability/production
Increase or
decrease (%)
1
Approximate impact
on net earnings
19
Generation Equipment and Technology Risk
There is a risk of equipment failure due to wear and tear, latent defect, design error or operator error, among other things,
which could have a material adverse effect on the Corporation. Although our generation facilities have generally operated in
accordance with expectations, there can be no assurance that they will continue to do so. Our plants are exposed to
operational risks such as failures due to cyclic, thermal, and corrosion damage in boilers, generators, and turbines, and other
issues that can lead to outages and increased volume risk. If plants do not meet availability or production targets specified in
their PPA or other long-term contracts, we may be required to compensate the purchaser for the loss in the availability of
production or record reduced energy or capacity payments. For merchant facilities, an outage can result in lost merchant
opportunities. Therefore, an extended outage could have a material adverse effect on our business, financial condition, results
of operations, or our cash flows.
As well, we are exposed to procurement risk for specialized parts that may have long lead times. If we are unable to procure
these parts when they are needed for maintenance activities, we could face an extended period where our equipment is
unavailable to produce electricity.
We manage our generation equipment and technology risk by:
operating our generating facilities within defined and proven operating standards that are designed to maximize the
availability of our generating facilities for the longest period of time;
performing preventative maintenance on a regular basis;
adhering to a comprehensive plant maintenance program and regular turnaround schedules;
adjusting maintenance plans by facility to reflect the equipment type and age;
having sufficient business interruption coverage in place in the event of an extended outage;
having force majeure clauses in our thermal and other PPAs and other long-term contracts;
using proven technology in our generating facilities;
monitoring technological advances and evaluating their impact upon our existing generating fleet and related
maintenance programs;,
negotiating strategic supply agreements with selected vendors to ensure key components are available in the event of a
significant outage;
entering into long-term arrangements with our strategic supply partners to ensure availability of critical spare parts; and
developing a long-term asset management strategy with the objective of maximizing the life cycles of our existing
facilities and/or replacement of selected generating assets.
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M64 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Commodity Price Risk
We have exposure to movements in certain commodity prices, including the market price of electricity and fuels used to
produce electricity in both our electricity generation and proprietary trading businesses.
We manage the financial exposure associated with fluctuations in electricity price risk by:
entering into long-term contracts that specify the price at which electricity, steam, and other services are provided;
maintaining a portfolio of short-, medium-, and long-term contracts to mitigate our exposure to short-term fluctuations
in commodity prices;
purchasing natural gas coincident with production for merchant plants so spot market spark spreads are adequate to
produce and sell electricity at a profit; and
ensuring limits and controls are in place for our proprietary trading activities.
In 2015, we had approximately 90 per cent (2014 - 90 per cent) of production under short-term and long-term contracts and
hedges. In the event of a planned or unplanned plant outage or other similar event, however, we are exposed to changes in
electricity prices on purchases of electricity from the market to fulfill our supply obligations under these short- and long-term
contracts.
We manage the financial exposure to fluctuations in the costs of fuels used in production by:
entering into long-term contracts that specify the price at which fuel is to be supplied to our plants;
hedging emissions costs by entering into various emission trading arrangements; and
selectively using hedges, where available, to set prices for fuel.
In 2015, 66 per cent (2014 - 68 per cent) of our cost of gas used in generating electricity was contractually fixed or passed
through to our customers and 100 per cent (2014 - 100 per cent) of our purchased coal costs were contractually fixed.
The sensitivities of price changes to our net earnings, assuming production consistent with 2015 and applying the contractual
profile in place at Dec. 31, 2015 for 2016, are shown below:
Factor
Electricity price - Canada
Electricity price - U.S.
Natural gas price
Increase or
decrease
Approximate impact on net
earnings and cash flow
$ 1.00/MWh
US$ 1.00/MWh
$ 0.10/GJ
2
2
1
Actual variations in net earnings can vary from calculated sensitivities and may not be linear due to optimization
opportunities, co-dependencies and cost mitigations, production, availability, and other factors.
M65
TRANSALTA CORPORATION M65
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Coal Supply Risk
Having sufficient fuel available when required for generation is essential to maintaining our ability to produce electricity under
contracts and for merchant sale opportunities. At our coal-fired plants, input costs, such as diesel, tires, the price and
availability of mining equipment, the volume of overburden removed to access coal reserves, rail rates, and the location of
mining operations relative to the power plants are some of the exposures in our mining operations. Additionally, the ability of
the mines to deliver coal to the power plants can be impacted by weather conditions and labour relations. At U.S. Coal,
interruptions at our suppliers’ mine, the availability of trains to deliver coal, and the financial viability of our coal suppliers
could affect our ability to generate electricity.
We manage coal supply risk by:
ensuring that the majority of the coal used in electrical generation in Alberta is from reserves permitted through coal
rights we have purchased or for which we have long-term supply contracts, thereby limiting our exposure to fluctuations
in the supply of coal from third parties. The coal used in generating activities in U.S. Coal is secured through long-term
supply contracts;
using longer-term mining plans to ensure the optimal supply of coal from our mines;
sourcing the majority of the coal used at U.S. Coal under a mix of short-, medium-, and long-term contracts and from
multiple mine sources to ensure sufficient coal is available at a competitive cost;
contracting sufficient trains to deliver the coal requirements at U.S. Coal;
ensuring coal inventories on hand at Canadian Coal and U.S. Coal are at appropriate levels for usage requirements;
ensuring efficient coal handling and storage facilities are in place so that the coal being delivered can be processed in a
timely and efficient manner;
monitoring and maintaining coal specifications, carefully matching the specifications mined with the requirements of our
plants;
monitoring the financial viability of U.S. coal suppliers; and
hedging diesel exposure in mining and transportation costs.
Environmental Compliance Risk
Environmental compliance risks are risks to our business associated with existing and/or changes in environmental
regulations. New emission reduction objectives for the power sector are being established by governments in Canada and the
U.S. We anticipate continued and growing scrutiny by investors relating to sustainability performance. These changes to
regulations may affect our earnings by imposing additional costs on the generation of electricity, such as emission caps or tax,
requiring additional capital investments in emission capture technology, or requiring us to invest in offset credits. It is
anticipated that these compliance costs will increase due to increased political and public attention to environmental
concerns.
We manage environmental compliance risk by:
seeking continuous improvement in numerous performance metrics such as emissions, safety, land and water impacts,
and environmental incidents;
having an International Organization for Standardization and Occupational Health and Safety Assessment Series-based
environmental health and safety management system in place that is designed to continuously improve performance;
committing significant experienced resources to work with regulators in Canada and the U.S. to advocate that regulatory
changes are well designed and cost effective;
developing compliance plans that address how to meet or exceed emission standards for GHGs, mercury, SO2, and NOx,
which will be adjusted as regulations are finalized;
purchasing emission reduction offsets;
investing in renewable energy projects, such as wind, solar and hydro generation;
investing in clean coal technology development, which potentially provides long-term promise for large emission
reductions from fossil-fuel-fired generation; and
incorporating change-in-law provisions in contracts that allow recovery of certain compliance costs from our customers.
We strive to be in compliance with all environmental regulations relating to operations and facilities. Compliance with both
regulatory requirements and management system standards is regularly audited through our performance assurance policy
and results are reported quarterly to the Governance and Environment Committee.
M66
M66 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Credit Risk
Credit risk is the risk to our business associated with changes in the creditworthiness of entities with which we have
commercial exposures. This risk results from the ability of a counterparty to either fulfill its financial or performance
obligations to us or where we have made a payment in advance of the delivery of a product or service. The inability to collect
cash due to us or to receive products or services may have an adverse impact upon our net earnings and cash flows.
As at Dec. 31, 2015, we have liquidity of $1.4 billion comprised of amounts not drawn under our committed credit facility and
cash on hand, and have no current need to draw in 2016.
We manage our exposure to credit risk by:
establishing and adhering to policies that define credit limits based on the creditworthiness of counterparties, contract
term limits, and the credit concentration with any specific counterparty;
requiring formal sign-off on contracts that include commercial, financial, legal, and operational reviews;
requiring security instruments, such as parental guarantees, letters of credit, and cash collateral that can be collected if a
counterparty fails to fulfill its obligation or goes over its limits; and
reporting our exposure using a variety of methods that allow key decision-makers to assess credit exposure by
counterparty. This reporting allows us to assess credit limits for counterparties and the mix of counterparties based on
their credit ratings.
If established credit exposure limits are exceeded, we take steps to reduce this exposure, such as by requesting collateral, if
applicable, or by halting commercial activities with the affected counterparty. However, there can be no assurances that we
will be successful in avoiding losses as a result of a contract counterparty not meeting its obligations.
Our credit risk management profile and practices have not changed materially from Dec. 31, 2014. We had no material
counterparty losses in 2015, and we are exposed to minimal credit risk for Alberta PPAs because under the terms of these
arrangements, receivables are substantially all secured by letters of credit. We continue to keep a close watch on changes and
trends in the market and the impact these changes could have on our energy trading business and hedging activities, and will
take appropriate actions as required, although no assurance can be given that we will always be successful.
The following table outlines our maximum exposure to credit risk without taking into account collateral held or right of set-off,
including the distribution of credit ratings, as at Dec. 31, 2015:
Trade and other receivables(1)
Long-term finance lease receivables(2)
Risk management assets(1)
Total
Investment grade
(Per cent)
Non-investment grade
(Per cent)
Total
(Per cent)
90
39
100
10
61
-
100
100
100
Total
Amount
567
775
1,095
2,437
(1) Letters of credit and cash are the primary types of collateral held as security related to these amounts.
(2) Includes balance of $446 million attributable to one non)investment)grade customer. Risl of significant loss arising from this counterparty has been assessed as low in
the near term but could increase to moderate in an environment of sustained low commodity prices over the mid)to)long term. The assessment tales into consideration the
counterparty's financial position, external rating asessments, and how services are provided in an area of the counterparty's lower)cost operations, and TransAlta's other
credit risl management practices.
The maximum credit exposure to any one customer for commodity trading operations, including the fair value of open trading
positions, is $44 million (2014 - $29 million).
M67
TRANSALTA CORPORATION M67
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Currency Rate Risk
We have exposure to various currencies as a result of our investments and operations in foreign jurisdictions, the earnings
from those operations, the acquisition of equipment and services and foreign-denominated commodities from foreign
suppliers, and our US-dollar-denominated debt. Our exposures are primarily to the U.S. and Australian currencies. Changes in
the values of these currencies in relation to the Canadian dollar may affect our earnings or the value of our foreign
investments to the extent that these positions or cash flows are not hedged or the hedges are ineffective.
We manage our currency rate risk by establishing and adhering to policies that include:
hedging our net investments in foreign operations using a combination of foreign-denominated debt and financial
instruments. Our strategy is to offset 90 to 100 per cent of all such foreign currency exposures. At Dec. 31, 2015, we
have hedged approximately 93 per cent (2014 - 95 per cent) of our foreign currency net investment exposure, which we
define to exclude net U.S. risk management assets;
offsetting earnings from our foreign operations as much as possible by using expenditures denominated in the same
foreign currencies and financial instruments to hedge the balance of this exposure; and
entering into forward foreign exchange contracts to hedge future foreign-denominated receipts and expenditures, and all
US-dollar-denominated debt outside of our net investment portfolio.
The sensitivity of our net earnings to changes in foreign exchange rates has been prepared using management’s assessment
that an average four cent increase or decrease in the U.S. or Australian currencies relative to the Canadian dollar is a
reasonable potential change over the next quarter, and is shown below:
Factor
Exchange rate
Increase or decrease
$0.04
Approximate impact
on net earnings
2
Liquidity Risk
Liquidity risk relates to our ability to access capital to be used to engage in trading and hedging activities, capital projects,
debt refinancing and payment of liabilities, capital structure, and general corporate purposes. Investment grade credit ratings
support these activities and provide a more reliable and cost-effective means to access capital markets through commodity
and credit cycles. Changes in credit ratings may also affect our ability and/or the cost of establishing normal course derivative
or hedging transactions, including those undertaken by our Energy Marketing Segment. Counterparties enter into certain
electricity and natural gas purchase and sale contracts for the purposes of asset-backed sales and proprietary trading. The
terms and conditions of these contracts require the counterparties to provide collateral when the fair value of the obligation
pursuant to these contracts is in excess of any credit limits granted. Downgrades in creditworthiness by certain credit rating
agencies may challenge our ability to enter into these contracts or any ordinary course contract, decrease the credit limits
granted, and increase the amount of collateral that may have to be provided. Certain existing contracts contain credit rating
contingent clauses, that, when triggered, automatically increase costs under the contract or require additional collateral to be
posted. Where the contingency is based on the lowest single rating, a one-level downgrade from a credit rating agency with
an originally higher rating may not, however, trigger additional direct adverse impact.
We are focused on strengthening our financial position and flexibility and maintaining stable investment grade credit ratings
with three rating agencies. Credit ratings issued for TransAlta, as well as the corresponding rating agency outlook, are set out
in the Financial Capital section of this MD&A. Credit ratings are subject to revision or withdrawal at any time by the rating
organization, and there can be no assurance that TransAlta’s credit ratings and the corresponding outlook will not be changed,
resulting in adverse possible impacts identified above.
M68
M68 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
We manage liquidity risk by:
monitoring liquidity on trading positions;
preparing and revising longer-term financing plans to reflect changes in business plans and the market availability of capital;
reporting liquidity risk exposure for commodity risk management activities on a regular basis to the RMC, senior
management, and the ARC;
maintaining investment grade credit ratings; and
maintaining sufficient undrawn committed credit lines to support potential liquidity requirements.
Interest Rate Risk
Changes in interest rates can impact our borrowing costs while the opposite impact will be seen on the capacity revenues we
receive from our Alberta PPA plants. Changes in our cost of capital may also affect the feasibility of new growth initiatives.
We manage interest rate risk by establishing and adhering to policies that include:
•
employing a combination of fixed and floating rate debt instruments; and
• monitoring the mixture of floating and fixed rate debt and adjusting where necessary to ensure a continued efficient
mixture of these types of debt.
At Dec. 31, 2015, approximately nine per cent (2014 - four per cent) of our total debt portfolio was subject to changes in
floating interest rates through a combination of floating rate debt and interest rate swaps.
The sensitivity of changes in interest rates upon our net earnings is shown below:
Factor
Interest rate
Increase or
decrease (%)
0.15
Approximate impact
on net earnings
1
Project Management Risk
On capital projects, we face risks associated with cost overruns, delays, and performance.
We manage project risks by:
•
ensuring all projects are reviewed to see that established processes and policies are followed, risks have been properly
identified and quantified, input assumptions are reasonable, and returns are realistically forecasted prior to senior
management and Board of Directors approvals;
using consistent and disciplined project management methodology and processes;
performing detailed analysis of project economics prior to construction or acquisition and by determining our asset contracting
strategy to ensure the right mix of contracted and merchant capacity prior to commencement of construction;
partnering with those who have previously been able to deliver projects economically and on budget,
developing and following through with comprehensive plans that include critical paths identified, key delivery points, and
backup plans;
•
•
•
•
• managing project closeouts so that any learnings from the project are incorporated into the next significant project,
•
fixing the price and availability of the equipment, foreign currency rates, warranties, and source agreements as much as
is economically feasible prior to proceeding with the project; and
entering into labour agreements to provide security around cost and productivity.
•
Human Resource Risk
Human resource risk relates to the potential impact upon our business as a result of changes in the workplace. Human
resource risk can occur in several ways:
•
•
•
•
•
potential disruption as a result of labour action at our generating facilities,
reduced productivity due to turnover in positions,
inability to complete critical work due to vacant positions,
failure to maintain fair compensation with respect to market rate changes, and
reduced competencies due to insufficient training, failure to transfer knowledge from existing employees, or insufficient
expertise within current employees.
M69
TRANSALTA CORPORATION M69
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
We manage this risk by:
monitoring industry compensation and aligning salaries with those benchmarks,
using incentive pay to align employee goals with corporate goals;
monitoring and managing target levels of employee turnover; and
ensuring new employees have the appropriate training and qualifications to perform their jobs.
In 2015, 54 per cent (2014 - 53 per cent) of our labour force was covered by 11 (2014 - 12) collective bargaining agreements.
In 2015, two (2014 - four) agreements were renegotiated. We anticipate the successful negotiation of six collective
agreements in 2016.
Regulatory and Political Risk
Regulatory and political risk describes the risk to our business associated with potential changes to the existing regulatory
structures and the political influence upon those structures. This risk can come from market re-regulation, increased oversight
and control, structural or design changes in markets, or other unforeseen influences. Market rules are often dynamic and we
are not able to predict whether there will be any material changes in the regulatory environment or the ultimate effect of
changes in the regulatory environment on our business. This risk includes the qualification of our renewable facilities in
Alberta to the generation of tradable GHG allowances as part of the transition from the SGER to new regulation to be
formulated to give effect to the Climate Leadership Plan, in 2018, as well as the influence of regulation on the value of
allowances or credits generated.
We manage these risks systematically through our Legal and Regulatory groups and our Compliance program, which is
reviewed periodically to ensure its effectiveness. We work with governments, regulators, electric system operators, and other
stakeholders to resolve issues as they arise. We are actively monitoring changes to market rules and market design, and we
engage in market-sponsored stakeholder engagement processes. Through these and other avenues, we engage in advocacy
and policy discussions at a variety of levels. These stakeholder negotiations have allowed us to engage in proactive
discussions with governments over the longer term.
International investments are subject to unique risks and uncertainties relating to the political, social, and economic
structures of the respective country and such country’s regulatory regime. We mitigate this risk through the use of non-
recourse financing and insurance.
Transmission Risk
Access to transmission lines and transmission capacity for existing and new generation are key in our ability to deliver energy
produced at our power plants to our customers. The risks associated with the aging existing transmission infrastructure in
markets in which we operate continue to increase because new connections to the power system are consuming transmission
capacity quicker than it is being added by new transmission developments.
Reputation Risk
Our reputation is one of our most valued assets. Reputation risk relates to the risk associated with our business because of
changes in opinion from the general public, private stakeholders, governments, and other entities.
We manage reputation risk by:
•
striving as a neighbour and business partner in the regions where we operate to build viable relationships based on
mutual understanding leading to workable solutions with our neighbours and other community stakeholders,
clearly communicating our business objectives and priorities to a variety of stakeholders on a routine basis,
•
• maintaining positive relationships with various levels of government,
•
•
•
• maintaining strong corporate values that support reputation risk management initiatives.
pursuing sustainable development as a longer-term corporate strategy,
ensuring that each business decision is made with integrity and in line with our corporate values,
communicating the impact and rationale of business decisions to stakeholders in a timely manner, and
M70
M70 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Corporate Structure Risk
We conduct a significant amount of business through subsidiaries and partnerships. Our ability to meet and service debt
obligations is dependent upon the results of operations of our subsidiaries and the payment of funds by our subsidiaries in the
form of distributions, loans, dividends, or otherwise. In addition, our subsidiaries may be subject to statutory or contractual
restrictions that limit their ability to distribute cash to us.
General Economic Conditions
Changes in general economic conditions impact product demand, revenue, operating costs, the timing and extent of capital
expenditures, the net recoverable value of PP&E, financing costs, credit and liquidity risk, and counterparty risk.
Income Taxes
Our operations are complex and located in several countries. The computation of the provision for income taxes involves tax
interpretations, regulations, and legislation that are continually changing. Our tax filings are subject to audit by taxation
authorities. Management believes that it has adequately provided for income taxes as required by IFRS, based on all
information currently available.
The Corporation is subject to changing laws, treaties, and regulations in and between countries. Various tax proposals in the
countries we operate in could result in changes to the basis on which deferred taxes are calculated or could result in changes
to income or non-income tax expense. There has recently been an increased focus on issues related to the taxation of
multinational corporations. A change in tax laws, treaties, or regulations, or in the interpretation thereof, could result in a
materially higher income or non-income tax expense that could have a material adverse impact on the Corporation.
The sensitivity of changes in income tax rates upon our net earnings is shown below:
Factor
Tax rate
Increase or
decrease (%)
1
Approximate impact
on net earnings
1
The effective tax rate on comparable earnings before income taxes, equity income, and other items for 2015 was 78 per cent
(2014 – 19 per cent). The effective income tax rate can change depending on the mix of earnings from various countries and
certain deductions that do not fluctuate with earnings.
Legal Contingencies
We are occasionally named as a party in various claims and legal proceedings that arise during the normal course of our
business. We review each of these claims, including the nature of the claim, the amount in dispute or claimed, and the
availability of insurance coverage. There can be no assurance that any particular claim will be resolved in our favour or that
such claims may not have a material adverse effect on us.
Other Contingencies
We maintain a level of insurance coverage deemed appropriate by management. There were no significant changes to our
insurance coverage during renewal of the insurance policies on December 31. Our insurance coverage may not be available in
the future on commercially reasonable terms. There can be no assurance that our insurance coverage will be fully adequate to
compensate for potential losses incurred. In the event of a significant economic event, the insurers may not be capable of fully
paying all claims.
M71
TRANSALTA CORPORATION M71
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Critical Accounting Policies and Estimates
The selection and application of accounting policies is an important process that has developed as our business activities
have evolved and as accounting rules and guidance have changed. Accounting rules generally do not involve a selection
among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment relative to the
circumstances existing in the business. Every effort is made to comply with all applicable rules on or before the effective date,
and we believe the proper implementation and consistent application of accounting rules is critical.
However, not all situations are specifically addressed in the accounting literature. In these cases, our best judgment is used to
adopt a policy for accounting for these situations. We draw analogies to similar situations and the accounting guidelines
governing them, consider foreign accounting standards, and consult with our independent auditors about the appropriate
interpretation and application of these policies. Each of the critical accounting policies involves complex situations and a high
degree of judgment either in the application and interpretation of existing literature or in the development of estimates that
impact our consolidated financial statements.
Our significant accounting policies are described in Note 2 to our audited consolidated financial statements within this
Annual Report. The most critical of these policies are those related to revenue recognition, financial instruments, valuation of
PP&E and associated contracts, project development costs, useful life of PP&E, valuation of goodwill, leases, income taxes,
employee future benefits, decommissioning and restoration provisions, and other provisions. Each policy involves a number of
estimates and assumptions to be made about matters that are uncertain at the time the estimate is made. Different
estimates, with respect to key variables used for the calculations, or changes to estimates, could potentially have a material
impact on our financial position or results of operations.
We have discussed the development and selection of these critical accounting estimates with our ARC and our independent
auditors. The ARC has reviewed and approved our disclosure relating to critical accounting estimates in this MD&A.
These critical accounting estimates are described as follows:
Revenue Recognition
The majority of our revenues are derived from the sale of physical power, leasing of power facilities, and from commodity risk
management activities.
Revenues under long-term electricity and thermal sales contracts generally include one or more of the following components:
fixed capacity payments for availability, energy payments for generation of electricity, incentives or penalties for exceeding or
not meeting availability targets, excess energy payments for power generation above committed capacity, and ancillary
services. Each of these components is recognized upon output, delivery, or satisfaction of contractually specific targets.
Revenues from non-contracted capacity are comprised of energy payments, at market prices, for each MWh produced and
are recognized upon delivery.
In certain situations, a long-term electricity or thermal sales contract may contain, or be considered, a lease. Where the terms
and conditions of the contract result in the customer assuming the principal risks and rewards of ownership of the underlying
asset, the contractual arrangement is considered a finance lease, which results in the recognition of finance lease income.
Where we retain the principal risks and rewards, the contractual arrangement is an operating lease. Rental income, including
contingent rents where applicable, is recognized over the term of the contract. Revenues associated with non-lease elements
are recognized as goods or services revenues as outlined above.
Commodity risk management activities involve the use of derivatives such as physical and financial swaps, forward sales
contracts, and futures contracts and options, to earn trading revenues and to gain market information. These derivatives are
accounted for using fair value accounting when hedge accounting is not applied. The initial recognition of fair value and
subsequent changes in fair value affect reported earnings in the period the change occurs. The fair values of instruments that
remain open at the end of a reporting period represent unrealized gains or losses and are presented on the Consolidated
Statements of Financial Position as risk management assets or liabilities.
M72
M72 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
The determination of the fair value of commodity risk management contracts and derivative instruments is complex and relies
on judgments concerning future prices, volatility, and liquidity, among other factors. Some of our derivatives are not traded on
an active exchange or extend beyond the time period for which exchange-based quotes are available, requiring us to use
internal valuation techniques or models.
Financial Instruments
The fair value of a financial instrument is the price that would be received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the measurement date. Fair values can be determined by reference to
prices for instruments in active markets to which we have access. In the absence of an active market, we determine fair values
based on valuation models or by reference to other similar products in active markets.
Fair values determined using valuation models require the use of assumptions. In determining those assumptions, we look
primarily to external readily observable market inputs. However, if not available, we use inputs that are not based on
observable market data.
Level Determinations and Classifications
The Level I, II, and III classifications in the fair value hierarchy utilized by the Corporation are defined below. The fair value
measurement of a financial instrument is included in only one of the three levels, the determination of which is based on the
lowest level input that is significant to the derivation of the fair value.
Level I
Fair values are determined using inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities
that we have the ability to access. In determining Level I fair values, we use quoted prices for identically traded commodities
obtained from active exchanges such as the New York Mercantile Exchange.
Level II
Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability.
Fair values falling within the Level II category are determined through the use of quoted prices in active markets, which in
some cases are adjusted for factors specific to the asset or liability, such as basis, credit valuation, and location differentials.
Our commodity risk management Level II financial instruments include over-the-counter derivatives with values based on
observable commodity futures curves and derivatives with inputs validated by broker quotes or other publicly available
market data providers. Level II fair values are also determined using valuation techniques, such as option pricing models and
regression or extrapolation formulas, where the inputs are readily observable, including commodity prices for similar assets or
liabilities in active markets, and implied volatilities for options.
In determining Level II fair values of other risk management assets and liabilities, we use observable inputs other than
unadjusted quoted prices that are observable for the asset or liability, such as interest rate yield curves and currency rates. For
certain financial instruments where insufficient trading volume or lack of recent trades exists, we rely on similar interest or
currency rate inputs and other third-party information such as credit spreads.
Level III
Fair values are determined using inputs for the asset or liability that are not readily observable.
We may enter into commodity transactions for which market-observable data is not available. In these cases, Level III fair
values are determined using valuation techniques such as the Black-Scholes, mark-to-forecast, and historical bootstrap
models with inputs that are based on historical data such as unit availability, transmission congestion, demand profiles for
individual non-standard deals and structured products, and/or volatilities and correlations between products derived from
historical prices. We also have various contracts with terms that extend beyond a liquid trading period. As forward market
prices are not available for the full period of these contracts, the value of these contracts is derived by reference to a forecast
that is based on a combination of external and internal fundamental modelling, including discounting. As a result, these
contracts are classified in Level III.
M73
TRANSALTA CORPORATION M73
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
We have a Commodity Exposure Management Policy (the “Policy”), which governs both the commodity transactions
undertaken in our proprietary trading business and those undertaken to manage commodity price exposures in our generation
business. The Policy defines and specifies the controls and management responsibilities associated with commodity trading
activities, as well as the nature and frequency of required reporting of such activities.
Methodologies and procedures regarding commodity risk management Level III fair value measurements are determined by
our risk management department. Level III fair values are calculated within our energy trading risk management system based
on underlying contractual data as well as observable and non-observable inputs. Development of non-observable inputs
requires the use of judgment. To ensure reasonability, system-generated Level III fair value measurements are reviewed and
validated by the risk management and finance departments. Review occurs formally on a quarterly basis or more frequently if
daily review and monitoring procedures identify unexpected changes to fair value or changes to key parameters.
The effect of using reasonably possible alternative assumptions as inputs to valuation techniques from which the Level III
commodity risk management fair values are determined at Dec. 31, 2015 is an estimated upside of $156 million
(2014 - $101 million upside) and downside of $211 million (2014 - $113 million) impact to the carrying value of the financial
instruments. Fair values are stressed for volumes and prices. The amount of $125 million upside (2014 - $76 million upside)
and $186 million downside (2014 - $92 million downside) in the stress values stems from a long-dated power sale contract in
the Pacific Northwest that is designated as a cash flow hedge utilizing assumed power prices ranging from US$28 to US$45
for the period from 2018 to 2025, while the remaining amounts account for the rest of the portfolio. The variable volumes are
stressed up and down one standard deviation from historically available production data. Prices are stressed for longer-term
deals where there are no liquid market quotes using various internal and external forecasting sources to establish a high and a
low price range.
Valuation of PP&E and Associated Contracts
At the end of each reporting period, we assess whether there is any indication that a PP&E or intangible asset is impaired.
Impairment exists when the carrying amount of the asset or CGU to which it belongs exceeds its recoverable amount, which is
the higher of fair value less costs of disposal and value in use.
Factors that could indicate that an impairment exists include: significant underperformance relative to historical or projected
operating results; significant changes in the manner in which an asset is used or in our overall business strategy; or significant
negative industry or economic trends. In some cases, these events are clear. However, in many cases, a clearly identifiable
event indicating possible impairment does not occur. Instead, a series of individually insignificant events occur over a period
of time leading to an indication that an asset may be impaired. This can be further complicated in situations where we are not
the operator of the facility. Events can occur in these situations that may not be known until a date subsequent to their
occurrence.
Our operations, the market, and business environment are routinely monitored, and judgments and assessments are made to
determine whether an event has occurred that indicates a possible impairment. If such an event has occurred, an estimate is
made of the recoverable amount of the PP&E or CGU to which it belongs. Recoverable amount is the higher of an asset’s fair value
less costs of disposal and its value in use. Fair value is the price that would be received to sell an asset in an orderly transaction
between market participants at the measurement date. In determining fair value less costs of disposal, information about third-
party transactions for similar assets is used and if none is available, other valuation techniques, such as discounted cash flows,
are used. Value in use is computed using the present value of management’s best estimates of future cash flows based on the
current use and present condition of the asset. In estimating either fair value less costs of disposal or value in use using
discounted cash flow methods, estimates and assumptions must be made about sales prices, cost of sales, production, fuel
consumed, retirement costs, and other related cash inflows and outflows over the life of the facilities, which can range from 30 to
60 years. In developing these assumptions, management uses estimates of contracted and future market prices based on
expected market supply and demand in the region in which the plant operates, anticipated production levels, planned and
unplanned outages, and transmission capacity or constraints for the remaining life of the facilities. Appropriate discount rates
reflecting the risks specific to the asset under review are used in the assessments. These estimates and assumptions are
susceptible to change from period to period and actual results can, and often do, differ from the estimates, and can have either a
positive or negative impact on the estimate of the impairment charge, and may be material.
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M74 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
The impairment outcome can also be impacted by the determination of CGUs or groups of CGUs for asset and goodwill
impairment testing. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely
independent of the cash inflows from other assets or groups of assets, and goodwill is allocated to each CGU or group of
CGUs that is expected to benefit from the synergies of the acquisition from which the goodwill arose. The allocation of
goodwill is reassessed upon changes in the composition of segments, CGUs, or groups of CGUs. In respect of determining
CGUs, significant judgment is required to determine what constitutes independent cash flows between power plants that are
connected to the same system. We evaluate the market design, transmission constraints, and the contractual profile of each
facility, as well as our commodity price risk management plans and practices, in order to inform this determination. With
regard to the allocation or re-allocation of goodwill, significant judgment is required to evaluate synergies and their impacts.
Minimum thresholds also exist with respect to segmentation and internal monitoring activities. We evaluate synergies with
regards to opportunities from combined talent and technology, functional organization and future growth potential, and we
consider own performance measurement processes in making this determination.
As a result of our review in 2015 and other specific events, various analyses were run to assess the significance of possible
impairment indicators. Refer to the Asset Impairment Charges and Reversals section of this MD&A for further details.
Impairment charges can be reversed in future periods if circumstances improve. No assurances can be given if any reversal
will occur or the amount or timing of any such reversal.
Project Development Costs
Deferred project development costs include external, direct, and incremental costs that are necessary for completing an
acquisition or construction project. These costs are recognized in operating expenses until construction of a plant or
acquisition of an investment is likely to occur, there is reason to believe that future costs are recoverable, and that efforts will
result in future value to us, at which time the costs incurred subsequently are included in PP&E or investments. The
appropriateness of capitalization of these costs is evaluated each reporting period, and amounts capitalized for projects no
longer probable of occurring are charged to net earnings.
Useful Life of PP&E
Each significant component of an item of PP&E is depreciated over its estimated useful life. A component is a tangible asset
that can be separately identified as an asset and is expected to provide a benefit of greater than one year. Estimated useful
lives are determined based on current facts and past experience, and take into consideration the anticipated physical life of
the asset, existing long-term sales agreements and contracts, current and forecasted demand, the potential for technological
obsolescence, and regulations. The useful lives of PP&E and depreciation rates used are reviewed at least annually to ensure
they continue to be appropriate.
In 2015, depreciation and amortization expense per the Consolidated Statements of Cash Flows was $605 million
(2014 - $595 million), of which $59 million (2014 - $56 million) relates to mining equipment and is included in fuel and
purchased power.
As a result of the announcement of Alberta’s Climate Leadership Plan on Nov. 20, 2015, some of our coal plants may no
longer operate as long as originally planned. We have not adjusted the useful life of these plants for depreciation, pending
final ruling, and negotiations with the government in respect of compensation.
Valuation of Goodwill
We evaluate goodwill for impairment at least annually, or more frequently if indicators of impairment exist. If the carrying
amount of a CGU or group of CGUs, including goodwill, exceeds the unit’s fair value, the excess represents a goodwill
impairment loss. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely independent of
the cash inflows from other assets or groups of assets.
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TRANSALTA CORPORATION M75
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
As a result of the re-segmentation described in the Accounting Changes section of this MD&A, we re-allocated goodwill on a
relative fair value basis. The Corporation allocated goodwill of the previous Canadian Renewables and Alberta Merchant
group of CGUs to the Hydro and Wind and Solar segments and the previous U.S. operations goodwill to the Wind and Solar
Segment on the basis of management’s allocations for monitoring and performance measurement purposes. There were no
changes made to the Energy Marketing goodwill.
For purposes of the 2015 and 2014 annual goodwill impairment review, the Corporation determined the recoverable amounts
of the test units by calculating the fair value less costs of disposal using discounted cash flow projections based on the
Corporation’s long-range forecasts for the period extending to the last planned asset retirement in 2073. The resulting fair
value measurement is categorized within Level III of the fair value hierarchy.
We reviewed the carrying amount of goodwill prior to year-end and determined that the fair values of the related CGUs or
groups of CGUs to which goodwill relates, based on estimates of future cash flows, exceeded their carrying amounts, and no
goodwill impairments existed.
Determining the fair value of the CGUs or group of CGUs is susceptible to changes from period to period as management is
required to make assumptions about future cash flows, production and trading volumes, margins, and fuel and operating
costs. Had assumptions been made that resulted in fair values of the CGUs or groups of CGUs declining by five per cent from
current levels, there would not have been any impairment of goodwill.
Leases
In determining whether the Corporation’s PPAs and other long-term electricity and thermal sales contracts contain, or are,
leases, management must use judgment in assessing whether the fulfillment of the arrangement is dependent on the use of a
specific asset and the arrangement conveys the right to use the asset. For those agreements considered to contain, or be,
leases, further judgment is required to determine whether substantially all of the significant risks and rewards of ownership
are transferred to the customer or remain with TransAlta, to appropriately account for the agreement as either a finance or
operating lease. These judgments can be significant to how we classify amounts related to the arrangement as either PP&E or
as a finance lease receivable on the Consolidated Statements of Financial Position, and therefore the value of certain items of
revenue and expense is dependent upon such classifications.
Income Taxes
In accordance with IFRS, we use the liability method of accounting for income taxes. Under the liability method, deferred
income tax assets and liabilities are recognized on the differences between the carrying amounts of assets and liabilities and
their respective income tax basis.
Preparation of the consolidated financial statements involves determining an estimate of, or provision for, income taxes in each of
the jurisdictions in which we operate. The process also involves making an estimate of taxes currently payable and taxes
expected to be payable or recoverable in future periods, referred to as deferred income taxes. Deferred income taxes result from
the effects of temporary differences due to items that are treated differently for tax and accounting purposes. The tax effects of
these differences are reflected in the Consolidated Statements of Financial Position as deferred income tax assets and liabilities.
An assessment must also be made to determine the likelihood that our future taxable income will be sufficient to permit the
recovery of deferred income tax assets. To the extent that such recovery is not probable, deferred income tax assets must be
reduced. The reduction of the deferred income tax asset can be reversed if the estimated future taxable income improves. No
assurances can be given if any reversal will occur or the amount or timing of any such reversal. Management must exercise
judgment in its assessment of continually changing tax interpretations, regulations, and legislation to ensure deferred income tax
assets and liabilities are complete and fairly presented. Differing assessments and applications than our estimates could
materially impact the amount recognized for deferred income tax assets and liabilities. Our tax filings are subject to audit by
taxation authorities. The outcome of some audits may change our tax liability, although we believe that we have adequately
provided for income taxes in accordance with IFRS based on all information currently available. The outcome of pending audits is
not known nor is the potential impact on the consolidated financial statements determinable.
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M76 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Deferred income tax assets of $71 million (2014 - $45 million) have been recorded on the Consolidated Statements of
Financial Position as at Dec. 31, 2015. These assets primarily relate to net operating loss carryforwards. We believe there will
be sufficient taxable income that will permit the use of these loss carryforwards in the tax jurisdictions where they exist.
Deferred income tax liabilities of $647 million (2014 - $434 million) have been recorded on the Consolidated Statements of
Financial Position as at Dec. 31, 2015. These liabilities are comprised primarily of taxes on unrealized gains from risk
management transactions and income tax deductions in excess of related depreciation of PP&E.
Employee Future Benefits
We provide selected pension and post-employment benefits to employees. The cost of providing these benefits is dependent
upon many factors that result from actual plan experience and assumptions of future experience.
The liabilities for future benefits and associated pension costs included in annual compensation expenses are impacted by
employee demographics, including age, compensation levels, employment periods, the level of contributions made to the
plans, and earnings on plan assets.
Changes to the provisions of the plans may also affect current and future pension costs. Pension costs may also be
significantly impacted by changes in key actuarial assumptions, including, for example, the discount rates used in determining
the defined benefit obligation and the net interest cost on the net defined benefit liability. The discount rate used to estimate
our obligation reflects high-quality corporate fixed income securities currently available and expected to be available during
the period to maturity of the pension benefits.
The plan assets are comprised primarily of equity and fixed income investments. Fluctuations in the return on plan assets as a
result of actual equity market returns and changes in interest rates may result in increased or decreased pension costs in
future periods.
Decommissioning and Restoration Provisions
We recognize decommissioning and restoration provisions for PP&E in the period in which they are incurred if there is a legal
or constructive obligation to reclaim the plant or site. The amount recognized as a provision is the best estimate of the
expenditures required to settle the provision. Expected values are probability weighted to deal with the risks and uncertainties
inherent in the timing and amount of settlement of many decommissioning and restoration provisions. Expected values are
discounted at the risk-free interest rate adjusted to reflect the market’s evaluation of our credit standing.
As at Dec. 31, 2015, the decommissioning and restoration provisions recorded on the Consolidated Statements of Financial
Position were $233 million (2014 - $305 million). We estimate the undiscounted amount of cash flow required to settle the
decommissioning and restoration provisions is approximately $1.0 billion, which will be incurred between 2016 and 2073. The
majority of these costs will be incurred between 2020 and 2050. Some of the facilities that are co-located with mining
operations do not currently have any decommissioning obligations recorded as the obligations associated with the facilities
are indeterminate at this time.
Sensitivities for the major assumptions are as follows:
Factor
Discount rate
Undiscounted decommissioning and restoration provision
Increase or
decrease (%)
Approximate impact
on net earnings
1
10
2
2
Other Provisions
Where necessary, we recognize provisions arising from ongoing business activities, such as interpretation and application of
contract terms and force majeure claims. These provisions, and subsequent changes thereto, are determined using our best
estimate of the outcome of the underlying event and can also be impacted by determinations made by third parties, in
compliance with contractual requirements. The actual amount of the provisions that may be required could differ materially
from the amount recognized.
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TRANSALTA CORPORATION M77
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Accounting Changes
A. Current Accounting Changes
I. Operating and Reportable Segments
In January 2015, we completed changes to our internal reporting to systematize allocations of certain costs to each fuel type
within our Generation Segment. This permitted internal reports regularly provided to the chief operating decision maker to be
presented at the disaggregated fuel type level. Accordingly, commencing with first quarter 2015 reporting, we consider the
following distinct fuel types as reportable segments: Canadian Coal, U.S. Coal, Gas, Wind, and Hydro. Previously, these were
collectively reported as the Generation Segment. Comparative results for 2014 have been restated to align with the re-
segmentation: general expenditures of the Generation Segment were allocated to each fuel type segment based on estimated
relative benefit derived from those expenditures. For the years ended Dec. 31, 2014 and 2013, $12 million and $7 million,
respectively, in expenditures associated with certain functions were determined to benefit the broader organization and were
reassigned to the Corporate Segment. For the years ended Dec. 31, 2014 and 2013, $1 million and $3 million, respectively, in
expenditures were determined to benefit the Energy Marketing Segment and were reassigned to that segment.
We have exercised judgment in aggregating the Corporation’s Canadian gas and Australian gas operating segments together
into a single reportable segment, Gas. The operating segments were determined to share the following similar economic
characteristics: nature of revenue sources, level of contractedness, and customer assumption of fuel and regulatory
compliance costs. In addition, the Canadian gas and Australian gas operating segments share substantial similarity in
products (energy), processes (gas turbines), customers (industrial and regional utilities), and distribution methods
(connection to grid or behind-the-fence generation). Commencing Sept. 1, 2015, the solar facilities acquired are included in
the Wind and Solar Segment.
II. Change in Estimates – Useful Lives
During the first quarter, our subsidiary TA Cogen executed a new 15-year power supply contract with Ontario’s IESO for the
Windsor facility, which is effective Dec. 1, 2016. Accordingly, the useful life of the Windsor facility was extended prospectively
to Nov. 30, 2031. As a result, depreciation expense for the year ended Dec. 31, 2015 decreased by $8 million.
III. Inventory Reclassification
During the fourth quarter of 2015, we finalized changes to our accounting system to improve tracking and management of
parts, materials, and supplies that are expected to be consumed in the production process. Previously, these items were
comprised in other capital spare parts. As a result, approximately $116 million was reclassified to inventory in current assets
from PP&E. We restated the Consolidated Statement of Financial Position as at Dec. 31, 2014 to similarly reclassify parts,
materials, and supplies to inventory in the amount of $125 million.
IV. Restatement of a Prior Quarter
During the fourth quarter of 2015, we restated the statement of earnings of the first quarter of 2015, to increase
non-comparable deferred tax expense by $47 million. As a result, net earnings attributable to common shareholders of the
first quarter of 2015 has decreased from $7 million to a net loss of $40 million. The adjustment is due to the correction of the
tax basis of an internally transferred asset as part of the reorganization of companies giving effect to the Transaction with
TransAlta Renewables. Comparative information of the first quarter of 2015 presented in this document has been adjusted
accordingly.
V. Restatement of Prior Year Sustaining Capital
During 2015, we restated the hydro life extension capital spend, previously classified as growth capital, to sustaining capital, in
order to align with the presentation of expenditures associated with projects of a similar nature made in 2015. As a result of
the change, routine capital of the Hydro Segment increased by $19 million, $8 million, and $10 million, respectively, for 2014,
2013, and the fourth quarter of 2014. In consequence, comparable FCF was also reduced by these amounts for each period.
Comparable FCF per share was adjusted accordingly.
M78
M78 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
B. Future Accounting Changes
Accounting standards that have been previously issued by the IASB, but are not yet effective and have not been applied by the
Corporation, include:
I. IFRS 9 Financial Instruments
In July 2014, on completion of the impairment phase of the project to reform accounting for financial instruments and replace
IAS 39 Financial Instruments: Recognition and Measurement, the IASB issued the final version of IFRS 9 Financial Instruments.
IFRS 9 includes guidance on the classification and measurement of financial assets and financial liabilities, impairment of
financial assets (i.e., recognition of credit losses), and a new hedge accounting model.
Under the classification and measurement requirements for financial assets, financial assets must be classified and measured
at either amortized cost or at fair value through profit or loss or through OCI, depending on the basis of the entity’s business
model for managing the financial asset and the contractual cash flow characteristics of the financial asset.
The classification requirements for financial liabilities are unchanged from IAS 39. IFRS 9 requirements address the problem
of volatility in net earnings arising from an issuer choosing to measure certain liabilities at fair value and require that the
portion of the change in fair value due to changes in the entity’s own credit risk be presented in OCI, rather than within net
earnings.
The new general hedge accounting model is intended to be simpler and more closely focus on how an entity manages its risks,
replaces the IAS 39 effectiveness testing requirements with the principle of an economic relationship, and eliminates the
requirement for retrospective assessment of hedge effectiveness.
The new requirements for impairment of financial assets introduce an expected loss impairment model that requires more
timely recognition of expected credit losses. IAS 39 impairment requirements are based on an incurred loss model where
credit losses are not recognized until there is evidence of a trigger event.
IFRS 9 is effective for annual periods beginning on or after Jan. 1, 2018, with early application permitted. We are assessing the
impact of adopting this standard on our consolidated financial statements.
II. IFRS 15 Revenue from Contracts with Customers
In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers , which replaces existing revenue recognition
guidance with a single comprehensive accounting model. The model specifies that an entity recognizes revenue when it
transfers promised goods or services to customers in an amount that reflects the consideration to which it expects to be
entitled in exchange for those goods or services. In 2015, the effective date of IFRS 15 was delayed by one year. IFRS 15 is now
effective for annual reporting periods beginning on or after Jan. 1, 2018 with early application permitted. We are assessing the
impact of adopting this standard on our consolidated financial statements.
III. IFRS 16 Leases
In January 2016, the IASB issued IFRS 16 Leases, which replaces the current IFRS guidance on leases. Under current guidance,
lessees are required to determine if the lease is a finance or operating lease, based on specified criteria. Finance leases are
recognized on the statement of financial position, while operating leases are not. Under IFRS 16, lessees must recognize a
lease liability and a right-of-use asset for virtually all lease contracts. An optional exemption to not recognize certain short-
term leases and leases of low value can be applied by lessees. For lessors, the accounting remains essentially unchanged.
IFRS 16 is effective for annual periods beginning on or after Jan. 1, 2019, with early application permitted if IFRS 15 is also
applied at the same time.
We are assessing the impact of adopting this standard on our consolidated financial statements.
M79
TRANSALTA CORPORATION M79
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Fourth Quarter
Consolidated Financial Highlights
Three months ended Dec. 31
Revenues
Comparable EBITDA(2)
Net earnings (loss) attributable to common shareholders
Comparable net earnings attributable to common shareholders(2)
Comparable funds from operations(2)
Cash flow from operating activities
Comparable FCF(2)
Net earnings (loss) per share attributable to common
shareholders, basic and diluted
Comparable net earnings per share(2)
Comparable FFO per share(2)
Comparable FCF per share(2)
Dividends declared per common share
1 2
2015
595
268
(7)
3
243
118
174
(0.02)
0.01
0.86
0.61
0.18
2014
Restated (1)
718
301
148
46
225
250
97
0.54
0.17
0.82
0.35
0.18
Financial Highlights
Comparable EBITDA for the fourth quarter of 2015 decreased by $33 million to $268 million compared to the same
period in 2014, including an adjustment of $59 million to provisions. Excluding this non-cash adjustment relating mostly
to prior year events, EBITDA would have been $327 million in the fourth quarter. This strong performance resulted from
reductions to our operating expenses at our Highvale mine, solid availability in Canadian Coal, and the addition of wind,
solar, and gas pipeline assets over the last year. Prices in Alberta averaged $21 per MWh during the fourth quarter of
2015, compared to $30 per MWh in the same period in 2014. Our strategy of being highly contracted generally limited
the impacts of lower prices in Alberta, except for the wind and hydro facilities.
Comparable FFO increased by $18 million for the three months ended Dec. 31, 2015 compared to the same period in
2014, as it excluded the effects of the provision adjustment discussed above.
Fourth quarter comparable net earnings attributable to common shareholders was $3 million ($0.01 per share), down
from comparable net earnings of $46 million ($0.17 per share) in the same quarter last year, due to lower comparable
EBITDA described above, higher depreciation expense associated with the increased asset base, and an increase in non-
controlling interest due to the Transaction with TransAlta Renewables.
Reported net loss attributable to common shareholders was $7 million for the fourth quarter ($0.02 net loss per share)
compared to net earnings of $148 million ($0.54 per share) for the same period in 2014. The differences between
comparable and reported net earnings are mainly due to decreases (2014 - increases) in the fair value of de-designated
and economic hedges at U.S. Coal. Reported net earnings of the fourth quarter of 2014 also included a large reversal of a
writedown of deferred tax assets.
(1) Restated to deduct hydro life extension capital expenditures from comparable FCF. Refer to the Current Accounting Changes section of this document.
(2) These items are not defined under IFRS. Presenting these items from period to period provides management and investors with the ability to evaluate earnings trends more
readily in comparison with prior periods’ results. Refer to the Comparable Funds from Operations and Comparable Free Cash Flow and Earnings and Other Measures on a
Comparable Basis sections of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.
M80
M80 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Segmented Operational Results
Comparable EBITDA and operational performance for the business is as follows:
Three months ended Dec. 31
(1)
Availability (%)
Adjusted availability (%)(2)
Production (GWh)
(1)
Comparable EBITDA
Canadian Coal
U.S. Coal
Gas
Wind and Solar
Hydro
Energy Marketing
Corporate
Total comparable EBITDA
Management’s Discussion and Analysis
2015
92.9
88.4
11,107
67
23
90
65
19
26
(22)
268
2014
93.2
93.2
12,207
119
19
80
56
20
26
(19)
301
1
Canadian Coal: Comparable EBITDA decreased $52 million to $67 million in the fourth quarter of 2015 compared to the
same period in 2014. Fourth quarter EBITDA included a $59 million adjustment to provisions relating mostly to force
majeure events from the periods between 2013 to 2015. Excluding this adjustment, 2015 EBITDA would have been
$126 million for the quarter, slightly better than last year.
U.S. Coal: Comparable EBITDA was $23 million in the fourth quarter compared to $19 million for the same period in
2014. The current quarter benefited from a full quarter of contract with Puget Sound Energy and of the appreciation of
the US dollar in 2015.
Gas: Comparable EBITDA was $90 million in the fourth quarter of 2015, an increase of $10 million, compared to the
same period in 2014, primarily due to additional revenues from the Australian natural gas pipeline and the positive
impact of the strengthening of the US dollar on a certain contract in Australia.
Wind and Solar: Comparable EBITDA increased in the fourth quarter to $65 million compared to $56 million for the
same period in 2014, primarily due to the contribution from assets acquired in 2015 and the impact of strengthening of
the U.S. dollar on U.S. facilities.
Hydro: Comparable EBITDA was consistent in the fourth quarter with the same period in 2014.
Energy Marketing: Comparable EBITDA was consistent with the same period in 2014; with gross margin in both periods
exceeded our quarterly expectations of $15 to $20 million per quarter.
Corporate: Higher costs in our Corporate Segment is due to a provision associated with vacant leased office space
following the corporate restructuring.
(1) Availability and production includes all generating assets under generation operations that we operate and finance leases and excludes hydro assets and equity
investments. Production includes all generating assets, irrespective of investment vehicle and fuel type.
(2) Adjusted for economic dispatching at U.S. Coal.
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TRANSALTA CORPORATION M81
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Availability and Production
Availability for the three months ended Dec. 31, 2015 was consistent with the same period in 2014. Lower production for the three
months ended Dec. 31, 2015 compared to the same period in 2014 is primarily due to market curtailments at Canadian Coal.
Comparable Funds from Operations and Comparable Free Cash Flow
Comparable FFO per share and comparable FCF per share are calculated as follows using the weighted average number of
common shares outstanding during the period.
1
Three months ended Dec. 31
Cash flow from operating activities
Change in non-cash operating working capital balances
Cash flow from operations before changes in working capital
Adjustments
MSA settlement payment
Decrease in finance lease receivable
Payment of restructuring costs
Maintenance costs related to Alberta flood of 2013,
net of insurance recoveries
Other non-comparable items
Comparable FFO
Deduct:
Sustaining capital
Insurance recoveries of sustaining capital expenditures
Dividends paid on preferred shares
Distributions paid to subsidiaries' non-controlling interests
Comparable FCF
Weighted average number of common shares
outstanding in the period
Comparable FFO per share
Comparable FCF per share
2015
2014
Restated (1)
118
76
194
31
15
11
(10)
2
243
(52)
23
(11)
(29)
174
284
0.86
0.61
250
(23)
227
-
1
-
(5)
2
225
(97)
3
(13)
(21)
97
275
0.82
0.35
(1) Restated to include hydro life extension from Growth capital expenditures to sustaining capital expenditures. Refer to the Current Accounting Changes section of this
document.
M82
M82 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
A reconciliation of comparable EBITDA to comparable FFO is as follows:
Three months ended Dec. 31
Comparable EBITDA
Unrealized gains from risk management activities
Interest expense
Provisions
Current income tax expense
Realized foreign exchange gain
Decommissioning and restoration costs settled
Non-cash gain on curtailment and amendment
gain on empoyee future benefits
Capital insurance recoveries on Canadian Coal facility
Other non-cash items
Comparable FFO
Management’s Discussion and Analysis
2015
268
(6)
(63)
76
(7)
1
(4)
(8)
(5)
(9)
243
2014
301
(12)
(58)
-
(9)
14
(5)
-
-
(6)
225
Comparable FFO increased by $18 million in the fourth quarter of 2015 compared to the same period in 2014 as lower EBITDA
in the quarter includes the non-cash impact of our adjustment to provisions.
Comparable FCF for the three months ended Dec. 31, 2015 increased $77 million to $174 million compared to the same period in
2014, primarily due to the increase in comparable FFO and a decrease in sustaining capital, partially offset by higher distributions
paid to our subsidiaries’ non-controlling interests as a result of the reduction of our interest in TransAlta Renewables.
M83
TRANSALTA CORPORATION M83
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Earnings on a Comparable Basis
During the fourth quarter of 2015, a restatement was made to tax expense impacting earnings reported in the first quarter of
2015. Refer to the Current Accounting Changes section of this MD&A for a description of this change.
The adjustments made to calculate comparable earnings for the three months ended Dec. 31, 2015 and 2014 are as follows.
References are to the subsequent reconciliation table.
Three months ended Dec. 31
Reference
number
Adjustment
Reclassifications:
1
2
3
4
Finance lease income used as a proxy for
operating revenue
Decrease in finance lease receivable used as
a proxy for operating revenue and
depreciation
Reclassification of mine depreciation from fuel
and purchased power
Reclassification of comparable gain on sale of
property, plant, and equipment that is included in
depreciation
Segment and
fuel type
Gas
Gas
Canadian Coal
Canadian Coal
Adjustments (increasing (decreasing) earnings to arrive at comparable results):
2015
2014
17
15
16
-
13
1
15
1
5
6
7
8
9
10
11
12
13
14
15
16
17
Impacts to revenue associated with certain
de-designated and economic hedges
U.S. Coal
13
(47)
Restructuring expense (recovery)
Canadian Coal
Economic hedges of non-controlling interest in
intercompany foreign exchange contracts
Net tax effect on comparable adjustments
subject to tax
(Reversal) accrual of writedown of deferred
income tax assets
Maintenance costs related to the Alberta flood
of 2013, net of insurance recoveries
Costs related to TAMA Transmission bid
Asset impairment charges (reversals)
Non-comparable portion of insurance
recovery received
Corporate
Unassigned
Unassigned
Unassigned
Hydro
Corporate
Gas
Hydro
Foreign exchange on California claim
Unassigned
Non-comparable gain on sale of assets
Equity Investments
Non-comparable item attributable to
non-controlling interest
Unassigned
Gain on Poplar Creek contract restructuring
Gas
2
2
8
-
6
(10)
-
(1)
(18)
-
-
7
1
-
-
-
20
(68)
(5)
5
(5)
(3)
2
(1)
-
-
M84
M84 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
A reconciliation of comparable results to reported results for the three months ended Dec. 31, 2015 and 2014 is as follows:
Management’s Discussion and Analysis
(3)
(1, 2)
Three months ended Dec. 31, 2015
Comparable
adjustments
13
-
13
10
1
(4)
-
-
18
Comparable
reclassifications
32
(16)
48
-
-
-
-
-
-
(2, 3)
(1)
48
31
17
(17)
-
-
-
-
-
-
-
-
-
-
(12)
-
(12)
-
8
1
(3)
-
(6)
3
(7)
10
-
10
Revenues
Fuel and purchased power
Gross margin
Operations, maintenance, and administration
Asset impairment charges (reversals)
Restructuring provision
Taxes, other than income taxes
Gain on sale of assets
Net other operating (income) losses
EBITDA
Depreciation and amortization
Operating income
Finance lease income
Foreign exchange gain (loss)
Gain (loss) on sale of assets
Earnings before interest and taxes
Net interest expense
Income tax expense (recovery)
Net earnings (loss)
Non-controlling interests
Net earnings (loss) attributable to
TransAlta shareholders
Preferred share dividends
Net earnings (loss) attributable to
common shareholders
Weighted average number of common
shares outstanding in the period
Net earnings (loss) per share attributable
to common shareholders
Reported
595
272
323
109
(1)
4
8
-
(29)
232
136
96
17
3
(1)
115
69
(4)
50
46
4
11
(7)
284
(0.02)
Three months ended Dec. 31, 2014
(5)
(10)
(12)
(6)
(13)
(7)
(17)
(8,9)
(16)
(1, 2)
(3)
(4)
(2, 3, 4)
(1)
Comparable
total
640
256
384
119
-
-
8
-
(11)
Reported
718
268
450
138
(5)
-
8
-
(17)
Comparable
reclassifications
14
(15)
29
-
-
-
-
(1)
-
30
17
13
(13)
-
-
-
-
-
-
-
-
-
-
268
167
101
-
11
-
112
69
(10)
53
39
14
11
3
284
0.01
326
136
190
13
7
1
211
62
(26)
175
14
161
13
148
275
0.54
Comparable
adjustments
(47)
-
(47)
-
5
-
-
-
3
(5)
(10, 11)
(12)
(13)
Comparable
total
685
253
432
138
-
-
8
(1)
(14)
(14)
(15)
(8, 9)
(55)
-
(55)
-
2
(1)
(54)
-
48
(102)
-
(102)
-
(102)
301
153
148
-
9
-
157
62
22
73
14
59
13
46
275
0.17
M85
TRANSALTA CORPORATION M85
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Selected Quarterly Information
Our results are seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are
usually incurred in the spring and fall when electricity prices are expected to be lower, as electricity prices generally increase
in the peak winter and summer months in our main markets due to increased heating and cooling loads. Margins are also
typically impacted in the second quarter due to the volume of hydro production resulting from spring runoff and rainfall in the
Pacific Northwest, which impacts production at U.S. Coal. Typically, hydro facilities generate most of their electricity and
revenues during the spring months when melting snow starts feeding watersheds and rivers. Inversely, wind speeds are
historically greater during the cold winter months and lower in the warm summer months.
Revenue
Comparable EBITDA
Comparable FFO
Net earnings (loss) attributable to common shareholders
Comparable net earnings (loss) attributable to common shareholders
Net earnings (loss) per share attributable to common shareholders,
basic and diluted
Q1 2015
*Restated
593
275
211
(40)
26
(0.14)
Q2 2015
Q3 2015
Q4 2015
438
183
160
(131)
(44)
(0.47)
641
219
126
154
(33)
0.55
595
268
243
(7)
3
(0.02)
Comparable net earnings (loss) per share, basic and diluted
0.09
(0.16)
(0.12)
0.01
Revenue
Comparable EBITDA
Comparable FFO
Net earnings (loss) attributable to common shareholders
Comparable net earnings (loss) attributable to common shareholders
Net earnings (loss) per share attributable to common shareholders,
basic and diluted
Q1 2014
Q2 2014
Q3 2014
Q4 2014
775
310
238
49
47
0.18
491
213
154
(50)
(12)
(0.18)
639
212
145
(6)
(13)
(0.03)
718
301
225
148
46
0.54
Comparable net earnings (loss) per share, basic and diluted
0.17
(0.04)
(0.05)
0.17
* See Accounting Changes note for restatement.
M86
M86 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Basic and diluted earnings per share attributable to common shareholders and comparable earnings per share are calculated
each period using the weighted average common shares outstanding during the period. As a result, the sum of the earnings
per share for the four quarters making up the calendar year may sometimes differ from the annual earnings per share.
Comparable net earnings, comparable EBITDA, and comparable FFO are generally higher in the first and fourth quarters due
to higher demand associated with winter cold in the markets in which we operate and lower planned outages. Market
volatility can also impact quarterly contributions from our Energy Marketing Segment, as the first quarter of 2014 benefitted
from exceptional weather conditions in northeastern North America. Following sales of non-controlling interest in TransAlta
Renewables in the second quarter of 2014 and 2015 and the fourth quarter of 2015, an increasing portion of earnings is
attributable to non-controlling interests.
Revenue is impacted by market and operational factors listed above, and by changes in future power prices in the Pacific
Northwest, which cause de-designated and economic hedges in the region to fluctuate in value. These hedges significantly
depreciated in the fourth quarter of 2013, in the second quarter of 2014, and in the first half of 2015, and significantly
increased in value over the second half of 2014 and in the third quarter of 2015. Revenue of the fourth quarter of 2015 was
also impacted by a significant increase to a provision related to Force Majeure events associated mostly to prior years.
gain on disposal of assets, following the Poplar Creek contract restructuring in the third quarter of 2015;
Net earnings attributable to common shareholders have also been impacted by the following events:
MSA provision in the third quarter of 2015;
writedown of deferred tax assets in the first quarter of 2015 and a recovery in the third quarter of 2015;
change in income tax rates in Alberta in the second quarter of 2015; and
deferred income tax impacts of the Transaction in the first and second quarters of 2015.
M87
TRANSALTA CORPORATION M87
TransAlta Corporation | 2015 Annual Integrated Report
Management’s Discussion and Analysis
Disclosure Controls and Procedures
Management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness
of our disclosure controls and procedures as of the end of the period covered by this report. Disclosure controls and
procedures refer to controls and other procedures designed to ensure that information required to be disclosed in the reports
we file or submit under the Securities Exchange Act of 1934, as amended (“Exchange Act”) are recorded, processed,
summarized, and reported within the time periods specified in the rules and forms of the U.S. Securities and Exchange
Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that
information required to be disclosed by us in our reports that we file or submit under the Exchange Act is accumulated and
communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow
timely decisions regarding our required disclosure. In designing and evaluating our disclosure controls and procedures,
management recognizes that any controls and procedures, no matter how well designed and operated, can provide only
reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in
evaluating and implementing possible controls and procedures.
There has been no change in the internal control over financial reporting during the period covered by this report that has
materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Based on the
foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of Dec. 31, 2015, the end
of the period covered by this report, our disclosure controls and procedures were effective at a reasonable assurance level.
M88
M88 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Consolidated Financial Statements
Consolidated Financial Statements
Management’s Report
To the Shareholders of TransAlta Corporation
The consolidated financial statements and other financial information included in this annual report have been prepared by
management. It is management’s responsibility to ensure that sound judgment, appropriate accounting principles and
methods, and reasonable estimates have been used to prepare this information. They also ensure that all information
presented is consistent.
Management is also responsible for establishing and maintaining internal controls and procedures over the financial reporting
process. The internal control system includes an internal audit function and an established business conduct policy that
applies to all employees. In addition, TransAlta Corporation has a code of conduct that applies to all employees and is signed
annually. The code of conduct can be viewed on TransAlta’s website (www.transalta.com). Management believes the system
of internal controls, review procedures, and established policies provides reasonable assurance as to the reliability and
relevance of financial reports. Management also believes that TransAlta’s operations are conducted in conformity with the law
and with a high standard of business conduct.
The Board of Directors (the “Board”) is responsible for ensuring that management fulfills its responsibilities for financial
reporting and internal control. The Board carries out its responsibilities principally through its Audit and Risk Committee
(the “Committee”). The Committee, which consists solely of independent directors, reviews the financial statements and
annual report and recommends them to the Board for approval. The Committee meets with management, internal auditors,
and external auditors to discuss internal controls, auditing matters, and financial reporting issues. Internal and external
auditors have full and unrestricted access to the Committee. The Committee also recommends the firm of external auditors to
be appointed by the shareholders.
Dawn L. Farrell
President and Chief Executive Officer
Donald Tremblay
Chief Financial Officer
February 17, 2016
TRANSALTA CORPORATION F1
F1
TransAlta Corporation | 2015 Annual Integrated Report
Consolidated Financial Statements
Management's Annual Report on Internal Control over Financial Reporting
To the Shareholders of TransAlta Corporation
The following report is provided by management in respect of TransAlta Corporation’s (“TransAlta”) internal control over
financial reporting (as defined in Rules 13a-15f and 15d-15f under the United States Securities Exchange Act of 1934).
TransAlta’s management is responsible for establishing and maintaining adequate internal control over financial reporting for TransAlta.
Management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) 2013 framework
to evaluate the effectiveness of TransAlta’s internal control over financial reporting. Management believes that the COSO
2013 framework is a suitable framework for its evaluation of TransAlta’s internal control over financial reporting because it is
free from bias, permits reasonably consistent qualitative and quantitative measurements of TransAlta’s internal controls, is
sufficiently complete so that those relevant factors that would alter a conclusion about the effectiveness of TransAlta’s
internal controls are not omitted, and is relevant to an evaluation of internal control over financial reporting.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because
of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance
and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting
also can be circumvented by collusion or improper overrides. Because of such limitations, there is a risk that material
misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these
inherent limitations are known features of the financial reporting process, and it is possible to design safeguards into the
process to reduce, though not eliminate, this risk.
TransAlta proportionately consolidates the accounts of the Sheerness and Genesee Unit 3 joint operations in accordance with
International Financial Reporting Standards (“IFRS”). Management does not have the contractual ability to assess the internal
controls of these joint arrangements. Once the financial information is obtained from these joint arrangements it falls within
the scope of TransAlta’s internal controls framework. Management’s conclusion regarding the effectiveness of internal
controls does not extend to the internal controls at the transactional level of these joint arrangements. The 2015 consolidated
financial statements of TransAlta included $637 million and $612 million of total and net assets, respectively, as of
December 31, 2015, and $168 million and $19 million of revenues and net earnings, respectively, for the year then ended
related to these joint arrangements.
Management has assessed the effectiveness of TransAlta’s internal control over financial reporting, as at December 31, 2015,
and has concluded that such internal control over financial reporting is effective.
Ernst & Young LLP, who has audited the consolidated financial statements of TransAlta for the year ended December 31, 2015,
has also issued a report on internal control over financial reporting under Auditing Standard No. 5 of the Public Company
Accounting Oversight Board (United States). This report is located on the following page of this Annual Report.
Dawn L. Farrell
President and Chief Executive Officer
Donald Tremblay
Chief Financial Officer
February 17, 2016
F2
F2 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
To the Shareholders of TransAlta Corporation
We have audited TransAlta Corporation’s internal control over financial reporting as of December 31, 2015, based on criteria
established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (2013 framework), (the COSO criteria). TransAlta Corporation’s management is responsible for maintaining
effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial
reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our
responsibility is to express an opinion on the corporation’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal
control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A corporation’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A corporation’s internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the corporation; (2) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the corporation are being made only in accordance with authorizations of management and directors of the
corporation; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the corporation’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As indicated in the accompanying Management’s Annual Report on Internal Control over Financial Reporting, management’s
assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal
controls of the Sheerness and Genesee Unit 3 joint arrangements, which are included in the 2015 consolidated financial
statements of the Corporation and constituted $637 million and $612 million of total and net assets, respectively, as of
December 31, 2015, and $168 million and $19 million of revenues and net earnings, respectively, for the year then ended. Our
audit of internal control over financial reporting of the Corporation did not include an evaluation of the internal control over
financial reporting of the Sheerness and Genesee Unit 3 joint arrangements.
In our opinion, TransAlta Corporation maintained, in all material respects, effective internal control over financial reporting as
of December 31, 2015, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated statements of financial position as at December 31, 2015 and 2014, and the related consolidated statements of
earnings (loss), comprehensive income (loss), changes in equity and cash flows for each of the three-year period ended
December 31, 2015 of TransAlta Corporation and our report dated February 17, 2016 expressed an unqualified opinion thereon.
Chartered Professional Accountants
Calgary, Canada
February 17, 2016
F3
TRANSALTA CORPORATION F3
TransAlta Corporation | 2015 Annual Integrated Report
Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
To the Shareholders of TransAlta Corporation
We have audited the accompanying consolidated financial statements of TransAlta Corporation, which comprise the
consolidated statements of financial position as at December 31, 2015 and 2014, and the consolidated statements of earnings
(loss), comprehensive income (loss), changes in equity and cash flows for each of the years in the three-year period ended
December 31, 2015, and a summary of significant accounting policies and other explanatory information.
Management's responsibility for the consolidated financial statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance
with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such
internal control as management determines is necessary to enable the preparation of consolidated financial statements that
are free from material misstatement, whether due to fraud or error.
Auditors’ responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our
audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the
audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated
financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of
material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk
assessments, the auditors consider internal control relevant to the entity's preparation and fair presentation of the
consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also
includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial
statements, evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made
by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of TransAlta
Corporation as at December 31, 2015 and 2014, and its financial performance and its cash flows for each of the years in the
three-year period ended December 31, 2015 in accordance with International Financial Reporting Standards as issued by the
International Accounting Standards Board.
Other Matter
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
TransAlta Corporation's internal control over financial reporting as of December 31, 2015, based on the criteria established in
Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(2013 framework) and our report dated February 17, 2016 expressed an unqualified opinion on TransAlta Corporation’s
internal control over financial reporting.
Chartered Professional Accountants
Calgary, Canada
February 17, 2016
F4
F4 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Consolidated Financial Statements
Consolidated Statements of Earnings (Loss)
Year ended Dec. 31 (in nimmions of Canaeian eommars exceqt xhere notee)
2015
2014
2013
Revenues (Note 33)
Fuel and purchased power (Note 5)
Gross margin
Operations, maintenance, and administration (Note 5)
Depreciation and amortization
Asset impairment charges (reversals) (Note 6)
Restructuring provision (Note 4)
Taxes, other than income taxes
Net other operating (income) losses (Note 8)
Operating income
Finance lease income (Note 7)
Equity loss (Note 4)
Net interest expense (Note 9)
Foreign exchange gain
Gain on sale of assets (Note 4)
Earnings (loss) before income taxes
Income tax expense (recovery) (Note 19)
Net earnings (loss)
Net earnings (loss) attributable to:
TransAlta shareholders
Non-controlling interests (Note 11)
Net earnings (loss) attributable to TransAlta shareholders
Preferred share dividends (Note 24)
Net earnings (loss) attributable to common shareholders
Weighted average number of common shares
outstanding in the year (nimmions)
2,267
1,008
1,259
492
545
(2)
22
29
25
148
58
-
(251)
4
262
221
105
116
22
94
116
22
46
(24)
280
2,623
1,092
1,531
542
538
(6)
-
29
(14)
442
49
-
(254)
-
2
239
7
232
182
50
232
182
41
141
273
2,292
948
1,344
516
525
(18)
(3)
27
102
195
46
(10)
(256)
1
12
(12)
(8)
(4)
(33)
29
(4)
(33)
38
(71)
264
Net earnings (loss) per share attributable to common shareholders,
basic and diluted (Note 23)
(0.09)
0.52
(0.27)
See acconqanzing notes.
F5
TRANSALTA CORPORATION F5
TransAlta Corporation | 2015 Annual Integrated Report
Consolidated Financial Statements
Consolidated Statements of Comprehensive Income (Loss)
Year ended Dec. 31 (in nimmions of Canaeian eommars)
Net earnings (loss)
Other comprehensive income (loss)
Net actuarial gains (losses) on defined benefit plans, net of tax(1)
Gains (losses) on derivatives designated as cash flow hedges, net of tax(2)
Reclassification of losses on derivatives designated as cash flow
hedges to non-financial assets, net of tax(3)
Total items that will not be reclassified subsequently to net earnings
Gains on translating net assets of foreign operations
Reclassification of translation gains on net assets of divested
foreign operations (Note 4)
Losses on financial instruments designated as hedges of
foreign operations, net of tax(4)
Reclassification of losses on financial instruments designated as
hedges of divested foreign operations, net of tax(5) (Note 4)
Gains on derivatives designated as cash flow hedges, net of tax(6)
Reclassification of gains on derivatives designated as
cash flow hedges to net earnings, net of tax(7)
Total items that will be reclassified subsequently to net earnings
Other comprehensive income
Total comprehensive income
Total comprehensive income attributable to:
TransAlta shareholders
Non-controlling interests (Note 11)
(1) Net of incone tax recowerz of nim for the zear eneee Dec. 31, 2915 (2914 ) 7 recowerz, 2913 ) 11 exqense).
(2) Net of incone tax exqense of 1 for the zear eneee Dec. 31, 2915 (2914 ) nim, 2913 ) nim).
(3) Net of incone tax exqense of 1 for the zear eneee Dec. 31, 2915 (2914 ) nim, 2913 ) 1 recowerz).
(4) Net of incone tax exqense of 7 for the zear eneee Dec. 31, 2915 (2914 ) 7 recowerz, 2913 ) 5 recowerz).
(5) Net of incone tax recowerz of 1 for the zear eneee Dec. 31, 2915 (2914 ) 1 recowerz, 2913 ) nim).
(6) Net of incone tax exqense of 138 for the zear eneee Dec. 31, 2915 (2914 ) 91 exqense, 2913 ) 12 exqense).
(7) Net of incone tax exqense of 59 for the zear eneee Dec. 31, 2915 (2914 ) 3 exqense, 2913 ) 1 exqense).
See acconqanzing notes.
2015
116
2014
232
2013
(4)
4
3
-
7
247
(10)
(172)
6
375
(194)
252
259
375
272
103
375
(20)
(1)
-
(21)
75
(7)
(58)
7
215
(45)
187
166
398
348
50
398
31
-
1
32
37
-
(35)
-
76
(24)
54
86
82
41
41
82
F6
F6 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Consolidated Statements of Financial Position
Consolidated Financial Statements
As at Dec. 31 (in nimmions of Canaeian eommars)
Cash and cash equivalents
Trade and other receivables (Note 12)
Prepaid expenses
Risk management assets (Notes 13 ane 14)
Inventory (Note 15)
Long-term portion of finance lease receivables
Property, plant, and equipment (Note 16)
Cost
Accumulated depreciation
Goodwill (Note 17)
Intangible assets (Note 18)
Deferred income tax assets (Note 19)
Risk management assets (Notes 13 ane 14)
Other assets (Note 19)
Total assets
Accounts payable and accrued liabilities
Current portion of decommissioning and other provisions (Note 29)
Risk management liabilities (Notes 13 ane 14)
Income taxes payable
Dividends payable (Note 23)
Current portion of long-term debt and finance lease obligations (Note 21)
Credit facilities, long-term debt, and finance lease obligations (Note 21)
Decommissioning and other provisions (Note 29)
Deferred income tax liabilities (Note 19)
Risk management liabilities (Notes 13 ane 14)
Defined benefit obligation and other long-term liabilities (Note 22)
Equity
Common shares (Note 23)
Preferred shares (Note 24)
Contributed surplus
Deficit
Accumulated other comprehensive income (Note 25)
Equity attributable to shareholders
Non-controlling interests (Note 11)
Total equity
Total liabilities and equity
* See Note 3(A) for qrior qerioe restatenents.
Commitments and contingencies (Note 32)
Subsequent events (Note 34)
See acconqanzing notes.
On behalf of the Board:
2015
54
567
26
298
219
1,164
775
12,854
(5,681)
7,173
465
369
71
797
133
10,947
334
166
200
3
63
87
853
4,408
232
647
69
348
3,075
942
9
(1,018)
353
3,361
1,029
4,390
10,947
2014
*Restatee
43
450
17
273
196
979
403
12,407
(5,294)
7,113
462
331
45
402
98
9,833
481
34
128
2
55
751
1,451
3,305
322
434
94
349
2,999
942
9
(770)
104
3,284
594
3,878
9,833
Gordon D. Giffin
Director
Alan J. Fohrer
Director
F7
TRANSALTA CORPORATION F7
TransAlta Corporation | 2015 Annual Integrated Report
Consolidated Financial Statements
Consolidated Statements of Changes in Equity
(in nimmions of Canaeian eommars)
Common
shares
Preferred
shares
Contributed
surplus
2,913
781
Accumulated other
comprehensive
income (loss)(1)
Attributable to
shareholders
Attributable to
non-controlling
interests
(62)
-
17
169
(20)
166
-
-
-
-
-
-
104
-
71
177
4
(2)
250
-
-
(1)
-
-
2,906
182
17
169
(20)
348
(196)
(41)
20
-
86
161
3,284
22
71
177
4
(2)
272
(203)
(46)
(22)
-
76
3,361
Total
3,423
232
17
169
(20)
398
(196)
(41)
517
50
-
-
-
50
-
-
109
129
(82)
-
-
594
94
-
7
-
2
103
-
-
(82)
86
161
3,878
116
71
184
4
-
375
(203)
(46)
437
415
(105)
(105)
-
76
1,029
4,390
Balance, Dec. 31, 2013
Net earnings
Other comprehensive income (loss):
Net gains on translating net assets of
foreign operations, net of hedges and of tax
Net gains on derivatives designated
as cash flow hedges, net of tax
Net actuarial losses on defined benefits plans,
net of tax
Total comprehensive income
Common share dividends
Preferred share dividends
Changes in non-controlling interests in
TransAlta Renewables (Note 4)
Distributions paid, and payable,
to non-controlling interests
Common shares issued
Preferred shares issued
Balance, Dec. 31, 2014
Net earnings
Other comprehensive income (loss):
Net gains on translating net assets of
foreign operations, net of hedges and of tax
Net gains on derivatives designated
as cash flow hedges, net of tax
Net actuarial gains on defined benefits plans,
net of tax
Intercompany available for sale investments
Total comprehensive income
Common share dividends
Preferred share dividends
Changes in non-controlling interests in
TransAlta Renewables (Note 4)
Distributions paid, and payable,
to non-controlling interests
Common shares issued
Balance, Dec. 31, 2015
-
-
-
-
-
-
-
-
-
161
942
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
86
-
2,999
-
-
-
-
-
-
-
-
-
76
3,075
Deficit
(735)
182
-
-
-
182
(196)
(41)
20
-
-
-
(770)
22
-
-
-
-
22
(203)
(46)
(21)
-
-
9
-
-
-
-
-
-
-
-
-
-
9
-
-
-
-
-
-
-
-
-
-
(1) Refer to Note 25 for eetaims on conqonents of, ane changes in, accunumatee other conqrehensiwe incone (moss).
See acconqanzing notes.
F8
F8 TRANSALTA CORPORATION
942
9
(1,018)
353
TransAlta Corporation | 2015 Annual Integrated Report
Consolidated Financial Statements
Consolidated Statements of Cash Flows
Year ended Dec. 31 (in nimmions of Canaeian eommars)
2015
2014
2013
Operating activities
Net earnings (loss)
Depreciation and amortization (Note 33)
Gain on sale of assets (Note 4)
California claim (Note 8)
Accretion of provisions (Note 29)
116
232
(4)
605
595
585
(262)
(2)
(12)
-
(28)
28
21
18
18
Decommissioning and restoration costs settled (Note 29)
(24)
(16)
(24)
Deferred income tax expense (recovery) (Note 19)
86
(26)
(47)
Unrealized (gain) loss from risk management activities
61
(50)
76
Unrealized foreign exchange (gain) loss
Provisions
Asset impairment charges (reversals) (Note 6)
Sundance Units 1 and 2 return to service (Note 8)
Equity loss, net of distributions received (Note 4)
Other non-cash items
13
11
(1)
101
-
11
(2)
(6)
(18)
-
-
25
-
-
10
(41)
(5)
44
Cash flow from operations before changes in working capital
674
723
691
Change in non-cash operating working capital balances (Note 29)
(242)
73
74
Cash flow from operating activities
Investing activities
432
796
765
Additions to property, plant, and equipment (Notes 16 ane 33)
(476)
(487)
(561)
Additions to intangibles (Notes 18 ane 33)
(26)
(34)
(32)
Acquisition of renewable energy facilities, net of cash acquired (Note 4)
(101)
-
(109)
Addition to assets held for sale
Proceeds on sale of property, plant, and equipment
-
(13)
(17)
7
6
14
Proceeds on sale of investments and development projects (Note 4)
-
224
-
Realized gains (losses) on financial instruments
Decrease in finance lease receivable
Other
(12)
(2)
14
23
3
1
24
9
16
Change in non-cash investing working capital balances
(12)
2
(29)
Cash flow used in investing activities
Financing activities
(573)
(292)
(703)
Net increase (decrease) in borrowings under credit facilities (Note 21)
218
(436)
(119)
Repayment of long-term debt (Note 21)
Issuance of long-term debt (Note 21)
Dividends paid on common shares (Note 23)
Dividends paid on preferred shares (Note 24)
(758)
(551)
(328)
487
434
398
(124)
(140)
(116)
(46)
(41)
(38)
Net proceeds on issuance of preferred shares (Note 24)
-
161
-
Net proceeds on sale of non-controlling interest in subsidiary (Note 4)
404
129
207
Realized gains on financial instruments
87
35
15
Distributions paid to subsidiaries' non-controlling interests (Note 11)
(99)
(84)
(55)
Decrease in finance lease obligations (Note 21)
Other
Cash flow from (used in) financing activities
(13)
(10)
(9)
(7)
-
(2)
149
(503)
(47)
Cash flow from (used in) operating, investing, and financing activities
8
1
15
Effect of translation on foreign currency cash
Increase in cash and cash equivalents
Cash and cash equivalents, beginning of year
Cash and cash equivalents, end of year
Cash income taxes paid
Cash interest paid
See acconqanzing notes.
3
-
-
11
1
15
43
42
27
54
43
42
17
31
46
242
230
240
F9
TRANSALTA CORPORATION F9
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
(Tabular amounts in millions of Canadian dollars, except as otherwise noted)
(Tabumar anounts in nimmions of Canaeian eommars, exceqt as otherxise notee)
1. Corporate Information
A. Description of the Business
TransAlta Corporation (“TransAlta” or the “Corporation”) was incorporated under the Canaea Business Corqorations Act in
March 1985. The Corporation became a public company in December 1992. Its head office is located in Calgary, Alberta.
I. Generation Segments
The five generation segments of the Corporation are as follows: Canadian Coal, U.S. Coal, Gas, Wind and Solar, and Hydro.
The Corporation owns and operates hydro, wind and solar, natural gas- and coal-fired facilities, and related mining operations
in Canada, the United States (“U.S.”), and Australia. Revenues are derived from the availability and production of electricity
and steam as well as ancillary services such as system support. Electricity sales made by the Corporation’s commercial and
industrial group are assumed to be sourced from the Corporation’s production and have been included in the Canadian Coal
Segment.
II. Energy Marketing Segment
The Segment changed its name from “Energy Trading” in 2014 following a shift in focus toward lower risk revenue generation
activities such as asset optimization, customer fee and margin-based growth, and arbitrage trading.
The Energy Marketing Segment derives revenue and earnings from the wholesale trading of electricity and other energy-
related commodities and derivatives.
Energy Marketing manages available generating capacity as well as the fuel and transmission needs of the generation
segments by utilizing contracts of various durations for the forward sales of electricity and for the purchase of natural gas and
transmission capacity. Energy Marketing is also responsible for recommending portfolio optimization decisions. The results of
these other activities are included in each generation segment.
III. Corporate
The Corporate Segment includes the Corporation’s central financial, legal, administrative, and investing functions. Charges
directly or reasonably attributable to other segments are allocated thereto.
B. Basis of Preparation
These consolidated financial statements have been prepared by management in compliance with International Financial
Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).
The consolidated financial statements have been prepared on a historical cost basis except for financial instruments that are
measured at fair value, as explained in the following accounting policies.
These consolidated financial statements were authorized for issue by the Board on Feb. 17, 2016.
C. Basis of Consolidation
The consolidated financial statements include the accounts of the Corporation and the subsidiaries that it controls. Control
exists when the Corporation is exposed, or has rights, to variable returns from its involvement with the subsidiary and has the
ability to affect the returns through its power over the subsidiary. The financial statements of the subsidiaries are prepared for
the same reporting period and apply consistent accounting policies as the parent company.
F10 TRANSALTA CORPORATION
F10
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
2. Significant Accounting Policies
A. Revenue Recognition
The majority of the Corporation’s revenues are derived from the sale of physical power, leasing of power facilities, and from
energy marketing and trading activities.
Revenues are measured at the fair value of the consideration received or receivable.
Revenues under long-term electricity and thermal sales contracts generally include one or more of the following components:
fixed capacity payments for availability, energy payments for generation of electricity, incentives or penalties for exceeding or
not meeting availability targets, excess energy payments for power generation above committed capacity, and ancillary
services. Each component is recognized when: i) output, delivery, or satisfaction of specific targets is achieved, all as governed
by contractual terms; ii) the amount of revenue can be measured reliably; iii) it is probable that the economic benefits will
flow to the Corporation; and iv) the costs incurred or to be incurred in respect of the transaction can be measured reliably.
Revenue from the rendering of services is recognized when criteria ii), iii), and iv) above are met and when the stage of
completion of the transaction at the end of the reporting period can be measured reliably.
Revenues from non-contracted capacity are comprised of energy payments, at market prices, for each megawatt hour
(“MWh”) produced, and are recognized upon delivery.
In certain situations, a long-term electricity or thermal sales contract may contain, or be considered, a lease. Revenues
associated with non-lease elements are recognized as goods or services revenues as outlined above. Revenues associated
with leases are recognized as outlined in Note 2(R).
Commodity risk management activities involve the use of derivatives such as physical and financial swaps, forward sales
contracts, futures contracts, and options, which are used to earn revenues and to gain market information. These derivatives
are accounted for using fair value accounting. The initial recognition and subsequent changes in fair value affect reported net
earnings in the period the change occurs and are presented on a net basis in revenue. The fair values of instruments that
remain open at the end of the reporting period represent unrealized gains or losses and are presented on the Consolidated
Statements of Financial Position as risk management assets or liabilities. Some of the derivatives used by the Corporation in
trading activities are not traded on an active exchange or have terms that extend beyond the time period for which exchange-
based quotes are available. The fair values of these derivatives are determined using internal valuation techniques or models.
B. Foreign Currency Translation
The Corporation, its subsidiary companies, and joint arrangements each determine their functional currency based on the
currency of the primary economic environment in which they operate. The Corporation’s functional currency is the Canadian
dollar, while the functional currencies of its subsidiary companies and joint arrangements are the Canadian, U.S., or Australian
dollar. Transactions denominated in a currency other than the functional currency of an entity are translated at the exchange
rate in effect on the transaction date. The resulting exchange gains and losses are included in each entity’s net earnings in the
period in which they arise.
The Corporation's foreign operations are translated to the Corporation’s presentation currency, which is the Canadian dollar,
for inclusion in the consolidated financial statements. Foreign-denominated monetary and non-monetary assets and liabilities
of foreign operations are translated at exchange rates in effect at the end of the reporting period and revenue and expenses
are translated at exchange rates in effect on the transaction date. The resulting translation gains and losses are included in
Other Comprehensive Income (Loss) (“OCI”) with the cumulative gain or loss reported in Accumulated Other Comprehensive
Income (Loss) (“AOCI”). Amounts previously recognized in AOCI are recognized in net earnings when there is a reduction in a
foreign net investment as a result of a disposal, partial disposal, or loss of control.
F11
TRANSALTA CORPORATION F11
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
C. Financial Instruments and Hedges
I. Financial Instruments
Financial assets and financial liabilities, including derivatives and certain non-financial derivatives, are recognized on the
Consolidated Statements of Financial Position when the Corporation becomes a party to the contract. All financial
instruments, except for certain non-financial derivative contracts that meet the Corporation’s own use requirements, are
measured at fair value upon initial recognition. Measurement in subsequent periods depends on whether the financial
instrument has been classified as: at fair value through profit or loss, available-for-sale, held-to-maturity, loans and
receivables, or other financial liabilities. Classification of the financial instrument is determined at inception depending on the
nature and purpose of the financial instrument.
Financial assets and financial liabilities classified or designated as at fair value through profit or loss are measured at fair value
with changes in fair values recognized in net earnings. Financial assets classified as either held-to-maturity or as loans and
receivables, and other financial liabilities, are measured at amortized cost using the effective interest method of amortization.
Available-for-sale financial assets are those non-derivative financial assets that are designated as such or that have not been
classified as another type of financial asset, and are measured at fair value through OCI. Available-for-sale financial assets are
measured at cost if fair value is not reliably measurable.
Financial assets are assessed for impairment on an ongoing basis and at reporting dates. An impairment may exist if an
incurred loss event has arisen that has an impact on the recoverability of the financial asset. Factors that may indicate an
incurred loss event and related impairment may exist include, for example; if a debtor is experiencing significant financial
difficulty, or a debtor has entered or it is probable that they will enter, bankruptcy or other financial reorganization. The
carrying amount of financial assets, such as receivables, is reduced for impairment losses through the use of an allowance
account, and the loss is recognized in net earnings.
Financial assets are derecognized when the contractual rights to receive cash flows expire. Financial liabilities are
derecognized when the obligation is discharged, cancelled, or expired.
Financial assets and financial liabilities are offset and the net amount is reported in the Consolidated Statements of Financial
Position if there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a
net basis or to realize the assets and settle the liabilities simultaneously.
Derivative instruments that are embedded in financial or non-financial contracts that are not already required to be
recognized at fair value are treated and recognized as separate derivatives if their risks and characteristics are not closely
related to their host contracts and the contract is not measured at fair value. Changes in the fair values of these and other
derivative instruments are recognized in net earnings with the exception of the effective portion of i) derivatives designated as
cash flow hedges and ii) hedges of foreign currency exposure of a net investment in a foreign operation, each of which is
recognized in OCI. Derivatives used in commodity risk management activities are described in more detail in Note 2(A).
Transaction costs are expensed as incurred for financial instruments classified or designated as at fair value through profit or
loss. For other financial instruments, such as debt instruments, transaction costs are recognized as part of the carrying
amount of the financial instrument. The Corporation uses the effective interest method of amortization for any transaction
costs or fees, premiums, or discounts earned or incurred for financial instruments measured at amortized cost.
F12
F12 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
II. Hedges
Where hedge accounting can be applied and the Corporation chooses to seek hedge accounting treatment, a hedge
relationship is designated as a fair value hedge, a cash flow hedge, or a hedge of foreign currency exposures of a net
investment in a foreign operation. A hedging relationship qualifies for hedge accounting if, at inception, it is formally
designated and documented as a hedge, and the hedge is expected to be highly effective at inception and on an ongoing basis.
The documentation includes identification of the hedging instrument and hedged item or transaction, the nature of the risk
being hedged, the Corporation’s risk management objectives and strategy for undertaking the hedge, and how hedge
effectiveness will be assessed. The process of hedge accounting includes linking derivatives to specific recognized assets and
liabilities or to specific firm commitments or highly probable anticipated transactions.
The Corporation formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives used are
highly effective in offsetting changes in fair values or cash flows of hedged items. If hedge criteria are not met or the
Corporation does not apply hedge accounting, the derivative is accounted for on the Consolidated Statements of Financial
Position at fair value, with subsequent changes in fair value recorded in net earnings in the period of change.
a. Fair Value Hedges
In a fair value hedging relationship, the carrying amount of the hedged item is adjusted for changes in fair value attributable to
the hedged risk, with the changes being recognized in net earnings. Changes in the fair value of the hedged item, to the extent
that the hedging relationship is effective, are offset by changes in the fair value of the hedging derivative, which is also
recorded in net earnings. Hedge effectiveness for fair value hedges is achieved if changes in the fair value of the derivative are
highly effective at offsetting changes in the fair value of the item hedged. If hedge accounting is discontinued, the carrying
amount of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying amount of the
hedged item are amortized to net earnings over the remaining term of the original hedging relationship.
The Corporation primarily uses interest rate swaps as fair value hedges to manage the ratio of floating rate versus fixed rate
debt. Interest rate swaps require the periodic exchange of payments without the exchange of the notional principal amount on
which the payments are based. Interest expense on the debt is adjusted to include the payments made or received under the
interest rate swaps.
b. Cash Flow Hedges
In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized
in OCI while any ineffective portion is recognized in net earnings. Hedge effectiveness is achieved if the derivative’s cash flows
are highly effective at offsetting the cash flows of the hedged item and the timing of the cash flows is similar. All components
of each derivative’s change in fair value are included in the assessment of cash flow hedge effectiveness. If hedge accounting
is discontinued, the amounts previously recognized in AOCI are reclassified to net earnings during the periods when the
variability in the cash flows of the hedged item affects net earnings. Gains and losses on derivatives are reclassified to net
earnings from AOCI immediately when the forecasted transaction is no longer expected to occur within the time period
specified in the hedge documentation.
The Corporation primarily uses physical and financial swaps, forward sales contracts, futures contracts, and options as cash
flow hedges to hedge the Corporation’s exposure to fluctuations in electricity and natural gas prices. If hedging criteria are
met, the fair values of the hedges are recorded in risk management assets or liabilities with changes in value being reported in
OCI. Gains and losses on these derivatives are recognized, on settlement, in net earnings in the same period and financial
statement caption as the hedged exposure.
The Corporation also uses foreign currency forward contracts as cash flow hedges to hedge the foreign exchange exposures
resulting from highly probable forecasted project-related transactions denominated in foreign currencies. If the hedging
criteria are met, changes in fair value are reported in OCI with the fair value being reported in risk management assets or
liabilities, as appropriate. Upon settlement of the derivative, any gain or loss on the forward contracts is included in the cost of
the asset acquired or liability incurred.
F13
TRANSALTA CORPORATION F13
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
The Corporation uses forward starting interest rate swaps as cash flow hedges to hedge exposures to anticipated changes in
interest rates for forecasted issuances of debt. If the hedging criteria are met, changes in fair value are reported in OCI with
the fair value being reported in risk management assets or liabilities, as appropriate. When the swaps are closed out on
issuance of the debt, the resulting gains or losses recorded in AOCI are amortized to net earnings over the term of the swap. If
no debt is issued, the gains or losses are recognized in net earnings immediately.
c. Hedges of Foreign Currency Exposures of a Net Investment in a Foreign Operation
In hedging a foreign currency exposure of a net investment in a foreign operation, the effective portion of foreign exchange
gains and losses on the hedging instrument is recognized in OCI and the ineffective portion is recognized in net earnings. The
related fair values are recorded in risk management assets or liabilities, as appropriate. The amounts previously recognized in
AOCI are recognized in net earnings when there is a reduction in the hedged net investment as a result of a disposal, partial
disposal, or loss of control. The Corporation primarily uses foreign currency forward contracts and foreign-denominated debt
to hedge exposure to changes in the carrying values of the Corporation’s net investments in foreign operations that result
from changes in foreign exchange rates.
D. Cash and Cash Equivalents
Cash and cash equivalents are comprised of cash and highly liquid investments with original maturities of three months or less.
E. Collateral Paid and Received
The terms and conditions of certain contracts may require the Corporation or its counterparties to provide collateral when the
fair value of the obligation pursuant to these contracts is in excess of any credit limits granted. Downgrades in
creditworthiness by certain credit rating agencies may decrease the credit limits granted and accordingly increase the amount
of collateral that may have to be provided.
F. Inventory
I. Fuel
The Corporation’s inventory balance is comprised of coal and natural gas used as fuel, which is measured at the lower of
weighted average cost and net realizable value.
The cost of internally produced coal inventory is determined using absorption costing, which is defined as the sum of all
applicable expenditures and charges directly incurred in bringing inventory to its existing condition and location. Available
coal inventory tends to increase during the second and third quarters as a result of favourable weather conditions and lower
electricity production as maintenance is performed. Due to the limited number of processing steps incurred in mining coal
and preparing it for consumption and the relatively low value on a per-unit basis, management does not distinguish between
work in process and coal available for consumption. The cost of natural gas and purchased coal inventory includes all
applicable expenditures and charges incurred in bringing the inventory to its existing condition and location.
II. Energy Marketing
Commodity inventories held in the Energy Marketing Segment for trading purposes are measured at fair value less costs to
sell. Changes in fair value less costs to sell are recognized in net earnings in the period of change.
III. Parts and Materials
Parts, materials, and supplies are recorded at the lower of cost, measured at moving average costs, and net realizable value.
F14
F14 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
G. Property, Plant, and Equipment
The Corporation’s investment in property, plant, and equipment (“PP&E”) is initially measured at the original cost of each
component at the time of construction, purchase, or acquisition. A component is a tangible portion of an asset that can be
separately identified and depreciated over its own expected useful life, and is expected to provide a benefit for a period in
excess of one year. Original cost includes items such as materials, labour, borrowing costs, and other directly attributable
costs, including the initial estimate of the cost of decommissioning and restoration. Costs are recognized as PP&E assets if it is
probable that future economic benefits will be realized and the cost of the item can be measured reliably. The cost of major
spare parts is capitalized and classified as PP&E, as these items can only be used in connection with an item of PP&E.
Planned maintenance is performed at regular intervals. Planned major maintenance includes inspection, repair, and
maintenance of existing components, and the replacement of existing components. Costs incurred for planned major
maintenance activities are capitalized in the period maintenance activities occur and are amortized on a straight-line basis
over the term until the next major maintenance event. Expenditures incurred for the replacement of components during major
maintenance are capitalized and amortized over the estimated useful life of such components.
The cost of routine repairs and maintenance and the replacement of minor parts are charged to net earnings as incurred.
Subsequent to initial recognition and measurement at cost, all classes of PP&E continue to be measured using the cost model
and are reported at cost less accumulated depreciation and impairment losses, if any.
An item of PP&E or a component is derecognized upon disposal or when no future economic benefits are expected from its
use or disposal. Any gain or loss arising on derecognition is included in net earnings when the asset is derecognized.
The estimate of the useful lives of each component of PP&E is based on current facts and past experience, and takes into
consideration existing long-term sales agreements and contracts, current and forecasted demand, and the potential for
technological obsolescence. The useful life is used to estimate the rate at which the component of PP&E is depreciated. PP&E
assets are subject to depreciation when the asset is considered to be available for use, which is typically upon
commencement of commercial operations. Capital spares that are designated as critical for uninterrupted operation in a
particular facility are depreciated over the life of that facility, even if the item is not in service. Other capital spares begin to be
depreciated when the item is put into service. Each significant component of an item of PP&E is depreciated to its residual
value over its estimated useful life, generally using straight-line or unit-of-production methods. Estimated useful lives, residual
values, and depreciation methods are reviewed annually and are subject to revision based on new or additional information.
The effect of a change in useful life, residual value, or depreciation method is accounted for prospectively.
Estimated useful lives of the components of depreciable assets, categorized by asset class, are as follows:
Coal generation
Gas generation
Renewable generation
Mining property and equipment
Capital spares and other
3-50 years
2-30 years
3-60 years
4-50 years
2-50 years
TransAlta capitalizes borrowing costs on capital
invested in projects under construction (see Note 2(S)). Upon
commencement of commercial operations, capitalized borrowing costs, as a portion of the total cost of the asset, are
depreciated over the estimated useful life of the related asset.
H. Intangible Assets
Intangible assets acquired in a business combination are recognized separately from goodwill at their fair value at the date of
acquisition. Intangible assets acquired separately are recognized at cost. Internally generated intangible assets arising from
development projects are recognized when certain criteria related to the feasibility of internal use or sale, and probable future
economic benefits of the intangible asset, are demonstrated.
F15
TRANSALTA CORPORATION F15
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
Intangible assets are initially recognized at cost, which is comprised of all directly attributable costs necessary to create,
produce, and prepare the intangible asset to be capable of operating in the manner intended by management.
Subsequent to initial recognition, intangible assets continue to be measured using the cost model, and are reported at cost
less accumulated amortization and impairment losses, if any. Amortization is included in depreciation and amortization and
fuel and purchased power in the Consolidated Statements of Earnings (Loss).
Amortization commences when the intangible asset is available for use, and is computed on a straight-line basis over the
intangible asset’s estimated useful life, except for coal rights, which are amortized using a unit-of-production basis, based on
the estimated mine reserves. Estimated useful lives of intangible assets may be determined, for example, with reference to the
term of the related contract or licence agreement. The estimated useful lives and amortization methods are reviewed annually
with the effect of any changes being accounted for prospectively.
Intangible assets consist of power sale contracts with fixed prices higher than market prices at the date of acquisition, coal
rights, software, and intangibles under development. Estimated useful lives of intangible assets are as follows:
Software
Power sale contracts
2-7 years
1-30 years
I. Impairment of Tangible and Intangible Assets Excluding Goodwill
At the end of each reporting period, the Corporation assesses whether there is any indication that PP&E and finite life
intangible assets are impaired.
Factors that could indicate that an impairment exists include: significant underperformance relative to historical or projected
operating results; significant changes in the manner in which an asset is used, or in the Corporation’s overall business
strategy; or significant negative industry or economic trends. In some cases, these events are clear. However, in many cases, a
clearly identifiable event indicating possible impairment does not occur. Instead, a series of individually insignificant events
occurs over a period of time leading to an indication that an asset may be impaired. This can be further complicated in
situations where the Corporation is not the operator of the facility. Events can occur in these situations that may not be known
until a date subsequent to their occurrence.
The Corporation’s operations, the market, and business environment are routinely monitored, and judgments and
assessments are made to determine whether an event has occurred that indicates a possible impairment. If such an event has
occurred, an estimate is made of the recoverable amount of the asset or cash-generating unit (“CGU”) to which the asset
belongs. Recoverable amount is the higher of an asset’s fair value less costs of disposal and its value in use. Fair value is the
price that would be received to sell an asset in an orderly transaction between market participants at the measurement date.
In determining fair value, recent market transactions are taken into account. If no such transactions can be identified, an
appropriate valuation model such as discounted cash flows is used. Value in use is the present value of the estimated future
cash flows expected to be derived from the asset from its continued use and ultimate disposal by the Corporation. If the
recoverable amount is less than the carrying amount of the asset or CGU, an asset impairment loss is recognized in net
earnings, and the asset’s carrying amount is reduced to its recoverable amount.
At each reporting date, an assessment is made whether there is any indication that an impairment loss previously recognized
may no longer exist or may have decreased. If such indication exists, the recoverable amount of the asset or CGU to which the
asset belongs is estimated and the impairment loss previously recognized is reversed if there has been an increase in the
recoverable amount. Where an impairment loss is subsequently reversed, the carrying amount of the asset is increased to the
lesser of the revised estimate of its recoverable amount or the carrying amount that would have been determined (net of
depreciation) had no impairment loss been recognized previously. A reversal of an impairment loss is recognized in net earnings.
F16
F16 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
J. Goodwill
Goodwill arising in a business combination is recognized as an asset at the date control is acquired. Goodwill is measured as
the cost of an acquisition plus the amount of any non-controlling interest in the acquiree (if applicable) less the fair value of
the related identifiable assets acquired and liabilities assumed.
Goodwill is not subject to amortization, but is tested for impairment at least annually, or more frequently, if an analysis of
events and circumstances indicate that a possible impairment may exist. These events could include a significant change in
financial position of the CGUs or groups of CGUs to which the goodwill relates or significant negative industry or economic
trends. For impairment purposes, goodwill is allocated to each of the Corporation’s CGUs or groups of CGUs that are expected
to benefit from the synergies of the business combination in which the goodwill arose. To test for impairment, the recoverable
amount of the CGUs or groups of CGUs to which the goodwill relates is compared to its carrying amount. If the recoverable
amount is less than the carrying amount, an impairment loss is recognized in net earnings immediately, by first reducing the
carrying amount of the goodwill, and then by reducing the carrying amount of the other assets in the unit. An impairment loss
recognized for goodwill is not reversed in subsequent periods.
K. Project Development Costs
Project development costs include external, direct, and incremental costs that are necessary for completing an acquisition or
construction project. These costs are recognized as operating expenses until construction of a plant or acquisition of an
investment is likely to occur, there is reason to believe that future costs are recoverable, and that efforts will result in future
value to the Corporation, at which time the costs incurred subsequently are included in other assets. The appropriateness of
capitalization of these costs is evaluated each reporting period, and amounts capitalized for projects no longer probable of
occurring are charged to net earnings.
L. Income Taxes
The Corporation uses the liability method of accounting for income taxes. Under the liability method, deferred income tax
assets and liabilities are recognized on the differences between the carrying amounts of assets and liabilities and their
respective income tax basis (temporary differences). A deferred income tax asset may also be recognized for the benefit
expected from unused tax credits and losses available for carryforward, to the extent that it is probable that future taxable
earnings will be available against which the tax credits and losses can be applied. Deferred income tax assets and liabilities
are measured based on income tax rates and tax laws that are enacted or substantively enacted by the end of the reporting
period and that are expected to apply in the years in which temporary differences are expected to be realized or settled.
Deferred income tax is charged or credited to net earnings, except when related to items charged or credited to either OCI or
directly to equity. The carrying amount of deferred income tax assets is evaluated at the end of each reporting period and is
reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the
asset to be realized.
Deferred income tax liabilities are recognized for taxable temporary differences arising on investments in subsidiaries, except
where the Corporation is able to control the reversal of the temporary difference and it is probable that the temporary
difference will not reverse in the foreseeable future.
M. Employee Future Benefits
The Corporation has defined benefit pension and other post-employment benefit plans. The current service cost of providing
benefits under the defined benefit plans is determined using the projected unit credit method pro-rated based on service. The
net interest cost is determined by applying the discount rate to the net defined benefit liability. The discount rate used to
determine the present value of the defined benefit obligation, and the net interest cost, is determined by reference to market
yields at the end of the reporting period on high-quality corporate bonds with terms and currencies that match the estimated
terms and currencies of the benefit obligations. Remeasurements, which include actuarial gains and losses and the return on
plan assets (excluding net interest), are recognized through OCI in the period in which they occur. Actuarial gains and losses
arise from experience adjustments and changes in actuarial assumptions. Remeasurements are not reclassified to profit or
loss, from OCI, in subsequent periods.
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Notes to Consolidated Financial Statements
Gains or losses arising from either a curtailment or settlement of a defined benefit plan are recognized when the curtailment
or settlement occurs. When the restructuring of a benefit plan gives rise to a curtailment and a settlement of obligations, the
curtailment is accounted for prior to the settlement.
In determining whether statutory minimum funding requirements of the Corporation’s defined benefit pension plans give rise
to recording an additional liability, letters of credit provided by the Corporation as security are considered to alleviate the
funding requirements. No additional liability results in these circumstances.
Contributions payable under defined contribution pension plans are recognized as a liability and an expense in the period in
which the services are rendered.
N. Provisions
Provisions are recognized when the Corporation has a present obligation (legal or constructive) as a result of a past event, it is
probable that the Corporation will be required to settle the obligation, and a reliable estimate can be made of the amount of
the obligation. A legal obligation can arise through a contract, legislation, or other operation of law. A constructive obligation
arises from an entity’s actions whereby through an established pattern of past practice, published policies, or a sufficiently
specific current statement, the entity has indicated it will accept certain responsibilities and has thus created a valid
expectation that it will discharge those responsibilities. The amount recognized as a provision is the best estimate,
remeasured at each period-end, of the expenditures required to settle the present obligation, considering the risks and
uncertainties associated with the obligation. Where expenditures are expected to be incurred in the future, the obligation is
measured at its present value using a current market-based, risk-adjusted interest rate.
The Corporation records a decommissioning and restoration provision for all generating facilities and mine sites for which it is
legally or constructively required to remove the facilities at the end of their useful lives and restore the plant or mine sites. For
some hydro facilities, the Corporation is required to remove the generating equipment, but is not required to remove the
structures. Initial decommissioning provisions are recognized at their present value when incurred. Each reporting date, the
Corporation determines the present value of the provision using the current discount rates that reflect the time value of
money and associated risks. The Corporation recognizes the initial decommissioning and restoration provisions, as well as
changes resulting from revisions to cost estimates and period-end revisions to the market-based, risk-adjusted discount rate,
as a cost of the related PP&E (see Note 2(G)). The accretion of the net present value discount is charged to net earnings each
period and is included in net interest expense. Where the Corporation expects to receive reimbursement from a third party for
a portion of future decommissioning costs, the reimbursement is recognized as a separate asset when it is virtually certain
that the reimbursement will be received. Decommissioning and restoration obligations for coal mines are incurred over time,
as new areas are mined, and a portion of the provision is settled over time as areas are reclaimed prior to final pit reclamation.
Reclamation costs for mining assets are recognized on a unit-of-production basis.
Changes in other provisions resulting from revisions to estimates of expenditures required to settle the obligation or period-
end revisions to the market-based, risk-adjusted discount rate are recognized in net earnings. The accretion of the net present
value discount is charged to net earnings each period and is included in net interest expense.
O. Share-Based Payments
The Corporation measures share-based awards compensation expense at grant date fair value and recognizes the expense
over the vesting period based on the Corporation’s estimate of the number of units that will eventually vest. Any award that
vests in instalments is accounted for as a separate award with its own distinct fair value measurement.
Compensation expense associated with equity-settled and cash-settled awards are recognized within equity and liability,
respectively. The liability associated with cash-settled awards is remeasured to fair value at each reporting date up to, and
including, the settlement date, with changes in fair value recognized within compensation expense.
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Notes to Consolidated Financial Statements
P. Emission Credits and Allowances
Emission credits and allowances are recorded as inventory at cost. Those purchased for use by the Corporation are recorded at
cost and are carried at the lower of weighted average cost and net realizable value. Credits granted to, or internally generated by,
TransAlta are recorded at nil. Emission liabilities are recorded using the best estimate of the amount required by the Corporation
to settle its obligation in excess of government-established caps and targets. To the extent compliance costs are recoverable
under the terms of contracts with third parties, the amounts are recognized as revenue in the period of recovery.
Emission credits and allowances that are held for trading and that meet the definition of a derivative are accounted for using
the fair value method of accounting. Allowances that do not satisfy the criteria of a derivative are accounted for using the
accrual method.
Q. Assets Held for Sale
Assets are classified as held for sale if their carrying amount will be recovered primarily through a sale as opposed to
continued use by the Corporation. Assets classified as held for sale are measured at the lower of their carrying amount and
fair value less costs of disposal. Any impairment is recognized in net earnings. Depreciation and equity accounting ceases
when an asset or equity investment, respectively, is classified as held for sale. Assets classified as held for sale are reported as
current assets in the Consolidated Statements of Financial Position.
R. Leases
A lease is an arrangement whereby the lessor conveys to the lessee, in return for a payment or series of payments, the right to
use an asset for an agreed period of time.
Power purchase arrangements (“PPA”) and other long-term contracts may contain, or may be considered, leases where the
fulfillment of the arrangement is dependent on the use of a specific asset (e.g. a generating unit) and the arrangement
conveys to the customer the right to use that asset.
Where the Corporation determines that the contractual provisions of a contract contain, or are, a lease and result in the
customer assuming the principal risks and rewards of ownership of the asset, the arrangement is a finance lease. Assets
subject to finance leases are not reflected as PP&E and the net investment in the lease, represented by the present value of
the amounts due from the lessee, is recorded in the Consolidated Statements of Financial Position as a financial asset,
classified as a finance lease receivable. The payments considered to be part of the leasing arrangement are apportioned
between a reduction in the lease receivable and finance lease income. The finance lease income element of the payments is
recognized using a method that results in a constant rate of return on the net investment in each period and is reflected in
finance lease income on the Consolidated Statements of Earnings (Loss).
Where the Corporation determines that the contractual provisions of a contract contain, or are, a lease and result in the
Corporation retaining the principal risks and rewards of ownership of the asset, the arrangement is an operating lease. For
operating leases, the asset is, or continues to be, capitalized as PP&E and depreciated over its useful life. Rental income,
including contingent rent, from operating leases is recognized over the term of the arrangement and is reflected in revenue on
the Consolidated Statements of Earnings (Loss). Contingent rent may arise when payments due under the contract are not
fixed in amount but vary based on a future factor such as the amount of use or production.
Leasing or other contractual arrangements that transfer substantially all of the risks and rewards of ownership to the
Corporation are considered finance leases. A leased asset and lease obligation are recognized at the lower of the fair value or
the present value of the minimum lease payments. Lease payments are apportioned between interest expense and a
reduction of the lease liability. Contingent rents are charged as expenses in the periods incurred. The leased asset is
depreciated over the shorter of the estimated useful life of the asset and the lease term.
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Notes to Consolidated Financial Statements
S. Borrowing Costs
TransAlta capitalizes borrowing costs that are directly attributable to, or relate to general borrowings used for, the
construction of qualifying assets. Qualifying assets are assets that take a substantial period of time to prepare for their
intended use and typically include generating facilities or other assets that are constructed over periods of time exceeding
12 months. Borrowing costs are considered to be directly attributable if they could have been avoided if the expenditure on the
qualifying asset had not been made. Borrowing costs that are capitalized are included in the cost of the related PP&E
component. Capitalization of borrowing costs ceases when substantially all the activities necessary to prepare the asset for its
intended use are complete.
All other borrowing costs are expensed in the period in which they are incurred.
T. Non-Controlling Interests
Non-controlling interests arise from business combinations in which the Corporation acquires less than a 100 per cent
interest. Non-controlling interests are initially measured at either fair value or at the non-controlling interest’s proportionate
share of the acquiree’s identifiable net assets. The Corporation determines on a transaction by transaction basis which
measurement method is used. Non-controlling interests also arise from other contractual arrangements between the
Corporation and other parties, whereby the other party has acquired an interest in a specified asset or operation, and the
Corporation retains control.
Subsequent to acquisition, the carrying amount of non-controlling interests is increased or decreased by the non-controlling
interest’s share of subsequent changes in equity and payments to the non-controlling interest. Total comprehensive income is
attributed to the non-controlling interests even if this results in the non-controlling interests having a negative balance.
U. Joint Arrangements
A joint arrangement is a contractual arrangement that establishes the terms by which two or more parties agree to undertake
and jointly control an economic activity. TransAlta’s joint arrangements are generally classified as two types: joint operations
and joint ventures.
A joint operation arises when the parties that have joint control have rights to the assets and obligations for the liabilities
relating to the arrangement. Generally, each party takes a share of the output from the asset and each bears an agreed upon
share of the costs incurred in respect of the joint operation. The Corporation reports its interests in joint operations in its
consolidated financial statements using the proportionate consolidation method by recognizing its share of the assets,
liabilities, revenues, and expenses in respect of its interest in the joint operation.
In a joint venture, the venturers do not have rights to individual assets or obligations of the venture. Rather, each venturer has
rights to the net assets of the arrangement. The Corporation reports its interests in joint ventures using the equity method.
Under the equity method, the investment is initially recognized at cost and the carrying amount is increased or decreased to
recognize the Corporation’s share of the joint venture’s net earnings or loss after the date of acquisition. The impact of
transactions between the Corporation and joint ventures is eliminated based on the Corporation’s ownership interest.
Distributions received from joint ventures reduce the carrying amount of the investment. Any excess of the cost of an
acquisition less the fair value of the recognized identifiable assets, liabilities, and contingent liabilities of an acquired joint
venture is recognized as goodwill and is included in the carrying amount of the investment and is assessed for impairment as
part of the investment.
Investments in joint ventures are evaluated for impairment at each reporting date by first assessing whether there is objective
evidence that the investment is impaired. If such objective evidence is present, an impairment loss is recognized if the
investment’s recoverable amount is less than its carrying amount. The investment’s recoverable amount is determined as the
higher of value in use and fair value less costs of disposal.
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Notes to Consolidated Financial Statements
V. Government Incentives
Government incentives are recognized when the Corporation has reasonable assurance that it will comply with the conditions
associated with the incentive and that the incentive will be received. When the incentive relates to an expense item, it is
recognized in net earnings over the same period in which the related costs or revenues are recognized. When the incentive
relates to an asset, it is recognized as a reduction of the carrying amount of PP&E and released to earnings as a reduction in
depreciation over the expected useful life of the related asset.
W. Earnings per Share
Basic earnings per share is calculated by dividing net earnings attributable to common shareholders by the weighted average
number of common shares outstanding in the year.
Diluted earnings per share is calculated by dividing net earnings attributable to common shareholders, adjusted for the
after-tax effects of dividends, interest, or other changes in net earnings that would result from potential dilutive instruments,
by the weighted average number of common shares outstanding in the year, adjusted for additional common shares that
would have been issued on the conversion of all potential dilutive instruments.
X. Business Combinations
Transactions in which the acquisition constitutes a business are accounted for using the acquisition method. Identifiable
assets acquired and liabilities assumed are measured at their acquisition date fair values. Goodwill is measured as the excess
of the fair value of consideration transferred less the fair value of the identifiable assets acquired and liabilities assumed.
Acquisition-related costs to effect the business combination, with the exception of costs to issue debt or equity securities, are
recognized in net earnings as incurred.
Y. Stripping Costs
A mine stripping activity asset is recognized 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.
Z. Significant Accounting Judgments and Key Sources of Estimation Uncertainty
The preparation of financial statements requires management to make judgments, estimates, and assumptions that could
affect the reported amounts of assets, liabilities, revenues, expenses, and disclosures of contingent assets and liabilities
during the period. These estimates are subject to uncertainty. Actual results could differ from those estimates due to factors
such as fluctuations in interest rates, foreign exchange rates, inflation and commodity prices, and changes in economic
conditions, legislation, and regulations.
In the process of applying the Corporation’s accounting policies, management has to make judgments and estimates about
matters that are highly uncertain at the time the estimate is made and that could significantly affect the amounts recognized
in the consolidated financial statements. Different estimates with respect to key variables used in the calculations, or changes
to estimates, could potentially have a material impact on the Corporation’s financial position or performance. The key
judgments and sources of estimation uncertainty are described below:
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Notes to Consolidated Financial Statements
I. Impairment of PP&E and Goodwill
Impairment exists when the carrying amount of an asset, CGU or group of CGUs to which goodwill relates exceeds its
recoverable amount, which is the higher of its fair value less costs of disposal and its value in use. An assessment is made at
each reporting date as to whether there is any indication that an impairment loss may exist or that a previously recognized
impairment loss may no longer exist or may have decreased. In determining fair value less costs of disposal, information
about third-party transactions for similar assets is used and if none is available, other valuation techniques, such as
discounted cash flows, are used. Value in use is computed using the present value of management’s best estimates of future
cash flows based on the current use and present condition of the asset. In estimating either fair value less costs of disposal or
value in use using discounted cash flow methods, estimates and assumptions must be made about sales prices, cost of sales,
production, fuel consumed, capital expenditures, retirement costs, and other related cash inflows and outflows over the life of
the facilities, which can range from 30 to 60 years. In developing these assumptions, management uses estimates of
contracted and future market prices based on expected market supply and demand in the region in which the plant operates,
anticipated production levels, planned and unplanned outages, changes to regulations, and transmission capacity or
constraints for the remaining life of the facilities. Discount rates are determined by employing a weighted average cost of
capital methodology that is based on capital structure, cost of equity, and cost of debt assumptions based on comparable
companies with similar risk characteristics and market data as the asset, CGU, or group of CGUs subject to the test. These
estimates and assumptions are susceptible to change from period to period and actual results can, and often do, differ from
the estimates, and can have either a positive or negative impact on the estimate of the impairment charge, and may be
material. The impairment outcome can also be impacted by the determination of CGUs or groups of CGUs for asset and
goodwill impairment testing. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely
independent of the cash inflows from other assets or groups of assets, and goodwill is allocated to each CGU or group of
CGUs that is expected to benefit from the synergies of the acquisition from which the goodwill arose. The allocation of
goodwill is reassessed upon changes in the composition of segments, CGUs, or groups of CGUs. In respect of determining
CGUs, significant judgment is required to determine what constitutes independent cash flows between power plants that are
connected to the same system. The Corporation evaluates the market design, transmission constraints, and the contractual
profile of each facility, as well as the Corporation’s own commodity price risk management plans and practices, in order to
inform this determination. With regard to the allocation or reallocation of goodwill, significant judgment is required to
evaluate synergies and their impacts. Minimum thresholds also exist with respect to segmentation and internal monitoring
activities. The Corporation evaluates synergies with regards to opportunities from combined talent and technology, functional
organization, future growth potential, and considers its own performance measurement processes in making this
determination. Information regarding significant judgments and estimates in respect of impairment during 2013 to 2015 is
found in Notes 6 and 17.
II. Leases
In determining whether the Corporation’s PPAs and other long-term electricity and thermal sales contracts contain, or are,
leases, management must use judgment in assessing whether the fulfillment of the arrangement is dependent on the use of a
specific asset and the arrangement conveys the right to use the asset. For those agreements considered to contain, or be,
leases, further judgment is required to determine whether substantially all of the significant risks and rewards of ownership
are transferred to the customer or remain with the Corporation, to appropriately account for the agreement as either a finance
or operating lease. These judgments can be significant and impact how the Corporation classifies amounts related to the
arrangement as either PP&E or as a finance lease receivable on the Consolidated Statements of Financial Position, and
therefore the amount of certain items of revenue and expense is dependent upon such classifications.
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Notes to Consolidated Financial Statements
III. Income Taxes
Preparation of the consolidated financial statements involves determining an estimate of, or provision for, income taxes in
each of the jurisdictions in which the Corporation operates. The process also involves making an estimate of income taxes
currently payable and income taxes expected to be payable or recoverable in future periods, referred to as deferred income
taxes. Deferred income taxes result from the effects of temporary differences due to items that are treated differently for tax
and accounting purposes. The tax effects of these differences are reflected in the Consolidated Statements of Financial
Position as deferred income tax assets and liabilities. An assessment must also be made to determine the likelihood that the
Corporation’s future taxable income will be sufficient to permit the recovery of deferred income tax assets. To the extent that
such recovery is not probable, deferred income tax assets must be reduced. Management uses the Corporation’s long-range
forecasts as a basis for evaluation of recovery of deferred income tax assets. Management must exercise judgment in its
assessment of continually changing tax interpretations, regulations, and legislation to ensure deferred income tax assets and
liabilities are complete and fairly presented. Differing assessments and applications than the Corporation’s estimates could
materially impact the amounts recognized for deferred income tax assets and liabilities. See Note 10 for further details on the
impacts of the Corporation’s tax policies.
IV. Financial Instruments and Derivatives
The Corporation’s financial instruments and derivatives are accounted for at fair value, with the initial and subsequent
changes in fair value affecting earnings in the period the change occurs. The fair values of financial instruments and
derivatives are classified within three levels, with Level III fair values determined using inputs for the asset or liability that are
not readily observable. These fair value levels are outlined and discussed in more detail in Note 13. Some of the Corporation’s
fair values are included in Level III because they are not traded on an active exchange or have terms that extend beyond the
time period for which exchange-based quotes are available and require the use of internal valuation techniques or models to
determine fair value.
The determination of the fair value of these contracts and derivative instruments can be complex and relies on judgments and
estimates concerning future prices, volatility, and liquidity, among other factors. These fair value estimates may not
necessarily be indicative of the amounts that could be realized or settled, and changes in these assumptions could affect the
reported fair value of financial instruments. Fair values can fluctuate significantly and can be favourable or unfavourable
depending on current market conditions. Judgment is also used in determining whether a highly probable forecasted
transaction designated in a cash flow hedge is expected to occur based on the Corporation’s estimates of pricing and
production to allow the future transaction to be fulfilled.
V. Joint Control
In January 2014, the Corporation, through a wholly owned subsidiary, formed an unincorporated joint venture named
Fortescue River Gas Pipeline, of which it has a 43 per cent interest. Management, using judgment, assessed whether the
Corporation’s sole partner had control over the joint venture, or whether joint control existed. The contractual terms of the
joint venture agreement and the management agreement were reviewed and management concluded that joint control exists
as decisions regarding the relevant activities of the joint venture require a special majority vote (at least 70 per cent in
favour). Accordingly, the business is accounted for as a joint operation.
VI. Project Development Costs
Project development costs are capitalized in accordance with the accounting policy in Note 2(K). Management is required to
use judgment to determine if there is reason to believe that future costs are recoverable, and that efforts will result in future
value to the Corporation, in determining the amount to be capitalized.
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Notes to Consolidated Financial Statements
VII. Provisions for Decommissioning and Restoration Activities
TransAlta recognizes provisions for decommissioning and restoration obligations as outlined in Note 2(N) and Note 20. Initial
decommissioning provisions, and subsequent changes thereto, are determined using the Corporation’s best estimate of the
required cash expenditures, adjusted to reflect the risks and uncertainties inherent in the timing and amount of settlement.
The estimated cash expenditures are present valued using a current, risk-adjusted, market-based, pre-tax discount rate. A
change in estimated cash flows, market interest rates, or timing could have a material impact on the carrying amount of the
provision.
VIII. Useful Life of PP&E
Each significant component of an item of PP&E is depreciated over its estimated useful life. Estimated useful lives are
determined based on current facts and past experience, and take into consideration the anticipated physical life of the asset,
existing long-term sales agreements and contracts, current and forecasted demand, the potential for technological
obsolescence, and regulations. The useful lives of PP&E are reviewed at least annually to ensure they continue to be
appropriate. Information on changes in useful lives of facilities is disclosed in Note 3(A)(II).
As a result of the announcement of Alberta’s Climate Leadership Plan on Nov. 20, 2015, some of the Corporation’s coal plants
may no longer operate as long as originally planned. The Corporation has not adjusted the useful life of these plants for
depreciation, pending final ruling and negotiations with the government in respect of compensation.
IX. Employee Future Benefits
The Corporation provides pension and other post-employment benefits, such as health and dental benefits, to employees. The
cost of providing these benefits is dependent upon many factors, including actual plan experience and estimates and
assumptions about future experience.
The liability for pension and post-employment benefits and associated costs included in annual compensation expenses are
impacted by estimates related to:
employee demographics, including age, compensation levels, employment periods, the level of contributions made to the
plans, and earnings on plan assets;
the effects of changes to the provisions of the plans; and
changes in key actuarial assumptions, including rates of compensation and health-care cost increases, and discount rates.
Due to the complexity of the valuation of pension and post-employment benefits, a change in the estimate of any one of these
factors could have a material effect on the carrying amount of the liability for pension and other post-employment benefits or
the related expense. These assumptions are reviewed annually to ensure they continue to be appropriate. See Note 27 for
disclosures on employee future benefits.
X. Other Provisions
Where necessary, TransAlta recognizes provisions arising from ongoing business activities, such as interpretation and
application of contract terms, ongoing litigation, and force majeure claims. These provisions, and subsequent changes thereto,
are determined using the Corporation’s best estimate of the outcome of the underlying event and can also be impacted by
determinations made by third parties, in compliance with contractual requirements. The actual amount of the provisions that
may be required could differ materially from the amount recognized. More information is disclosed in Notes 4 and 20 with
respect to other provisions.
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Notes to Consolidated Financial Statements
3. Accounting Changes
A. Current Accounting Changes
I. Operating and Reportable Segments
In January 2015, the Corporation completed changes to its internal reporting to systematize allocations of certain costs to
each fuel type within its generation segment. This permitted internal reports regularly provided to the chief operating decision
maker to be presented at the disaggregated generation segment level. Accordingly, the Corporation considers the following
distinct generation segments as reportable segments: Canadian Coal, U.S. Coal, Gas, Wind, and Hydro. Previously, these were
collectively reported as the generation segment. Comparative results for 2014 and 2013 have been restated to align with the
re-segmentation: general expenditures of the generation segment were allocated to each fuel type segment based on
estimated relative benefit derived from those expenditures. For the years ended Dec. 31, 2014 and 2013, $12 million and
$7 million, respectively, in expenditures associated with certain functions were determined to benefit the broader organization
and were reassigned to the Corporate Segment. For the years ended Dec. 31, 2014 and 2013, $1 million and $3 million,
respectively, in expenditures were determined to benefit the Energy Marketing Segment and were reassigned to that segment.
Management has exercised judgment in aggregating the Corporation’s Canadian gas and Australian gas operating segments
together into a single reportable segment, Gas. The operating segments were determined to share the following similar
economic characteristics: nature of revenue sources, level of contractedness, and customer assumption of fuel and regulatory
compliance costs. In addition, the Canadian gas and Australian gas operating segments share substantial similarity in
products (energy), processes (gas turbines), customers (industrial and regional utilities), and distribution methods
(connection to grid or behind-the-fence generation).
Commencing Sept. 1, 2015, the Wind Segment has been redefined as the Wind and Solar Segment, following the acquisition of
solar facilities (Note 4).
II. Change in Estimates – Useful Lives
During the first quarter of 2015, the Corporation’s subsidiary, TransAlta Cogeneration, L.P. (“TA Cogen”), executed a new
15-year power supply contract with Ontario’s Independent Electricity System Operator for the Windsor facility, which is
effective Dec. 1, 2016. Accordingly, the useful life of the Windsor facility was extended prospectively to Nov. 30, 2031. As a
result, depreciation expense for the year ended Dec. 31, 2015 decreased by $8 million. The full year 2016 depreciation
expense is expected to be lower by $9 million.
III. Inventory Reclassification
During the fourth quarter of 2015, the Corporation finalized changes to its accounting system to improve tracking and
management of parts, materials, and supplies that are expected to be consumed in the production process. Previously, these
items were comprised in other capital spare parts. As a result, approximately $116 million was reclassified to inventory in
current assets from PP&E. The Corporation restated the Consolidated Statement of Financial Position as at Dec. 31, 2014 to
similarly reclassify parts, materials, and supplies to inventory in the amount of $125 million.
B. Future Accounting Changes
Accounting standards that have been previously issued by the IASB, but are not yet effective and have not been applied by the
Corporation, include:
I. IFRS 9 Financial Instruments
In July 2014, on completion of the impairment phase of the project to reform accounting for financial instruments and replace
IAS 39 Financiam Instrunents: Recognition ane Measurenent, the IASB issued the final version of IFRS 9 Financiam
Instrunents. IFRS 9 includes guidance on the classification and measurement of financial assets and financial liabilities,
impairment of financial assets (i.e., recognition of credit losses), and a new hedge accounting model.
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Notes to Consolidated Financial Statements
Under the classification and measurement requirements, financial assets must be classified and measured at either amortized
cost, at fair value through profit or loss, or through OCI, depending on the basis of the entity’s business model for managing
the financial asset and the contractual cash flow characteristics of the financial asset.
The classification requirements for financial liabilities are unchanged from IAS 39. IFRS 9 requirements address the problem
of volatility in net earnings arising from an issuer choosing to measure certain liabilities at fair value and require that the
portion of the change in fair value due to changes in the entity’s own credit risk be presented in OCI, rather than within net
earnings.
The new general hedge accounting model is intended to be simpler and more closely focus on how an entity manages its risks,
replaces the IAS 39 effectiveness testing requirements with the principle of an economic relationship, and eliminates the
requirement for retrospective assessment of hedge effectiveness.
The new requirements for impairment of financial assets introduce an expected loss impairment model that requires more
timely recognition of expected credit losses. IAS 39 impairment requirements are based on an incurred loss model where
credit losses are not recognized until there is evidence of a trigger event.
IFRS 9 is effective for annual periods beginning on or after Jan. 1, 2018 with early application permitted. The Corporation is
assessing the impact of adopting this standard on its consolidated financial statements.
II. IFRS 15 Revenue from Contracts with Customers
In May 2014, the IASB issued IFRS 15 Re wenue fron Contracts xith Custoners, which replaces existing revenue recognition
guidance with a single comprehensive accounting model. The model specifies that an entity recognizes revenue when it
transfers promised goods or services to customers in an amount that reflects the consideration to which it expects to be
entitled in exchange for those goods or services. In 2015, the IASB delayed the effective date of IFRS 15 by one year. IFRS 15 is
now effective for annual reporting periods beginning on or after Jan. 1, 2018 with early application permitted. The Corporation
is assessing the impact of adopting this standard on its consolidated financial statements.
III. IFRS 16 Leases
In January 2016, the IASB issued IFRS 16 Leases, which replaces the current IFRS guidance on leases. Under current guidance,
lessees are required to determine if the lease is a finance or operating lease, based on specified criteria. Finance leases are
recognized on the statement of financial position, while operating leases are not. Under IFRS 16, lessees must recognize a
lease liability and a right-of-use asset for virtually all lease contracts. An optional exemption to not recognize certain short-
term leases and leases of low value can be applied by lessees. For lessors, the accounting remains essentially unchanged.
IFRS 16 is effective for annual periods beginning on or after Jan. 1, 2019, with early application permitted if IFRS 15 is also
applied at the same time.
The Corporation is assessing the impact of adopting this standard on its consolidated financial statements.
C. Comparative Figures
Certain comparative figures have been reclassified to conform to the current period’s presentation. These reclassifications did
not impact previously reported net earnings.
F26
F26 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
4. Significant Events
A. Restructured Poplar Creek Contract and Acquisition of Wind Farms
On Sept. 1, 2015, the Corporation and Suncor Energy (“Suncor”) restructured their arrangement for power generation services
at Suncor’s oil sands base site near Fort McMurray.
The Corporation’s Poplar Creek cogeneration facility, which has a maximum capacity of 376 megawatts (“MW”), had been built and
contracted to provide steam and electricity to Suncor until 2023 and is recorded in the gas segment. Under the terms of the new
arrangement, Suncor acquired from TransAlta two steam turbines with an installed capacity of 132 MW and certain transmission
interconnection assets. The Corporation retained two gas turbines and heat recovery steam generators (“gas generators”), which are
leased to Suncor. Suncor assumed full operational control of the cogeneration facility, including responsibility for all capital costs, and
has the right to use the full 244 MW capacity of the Corporation’s gas generators until Dec. 31, 2030. The Corporation will provide
Suncor with centralized monitoring, diagnostics, and technical support to maximize performance and reliability of plant equipment.
Ownership of the entire Poplar Creek cogeneration facility will transfer to Suncor in 2030. As the new contract was determined to
constitute a finance lease, the full carrying amounts of the facility were derecognized.
As part of the transaction, the Corporation acquired Suncor’s interest in two wind farms: the 20 MW Kent Breeze facility
located in Ontario and Suncor’s 51 per cent interest in the 88 MW Wintering Hills facility located in Alberta. The
Corporation’s interest in the Wintering Hills facility is accounted for as a joint operation.
The following table outlines the impacts of the transaction, including assets and liabilities disposed of and the fair value of
assets acquired and liabilities assumed:
Assets
Finance lease receivable(1)
Property, plant, and equipment
Intangibles
Net working capital
Total assets acquired
Liabilities
Decomissioning and restoration provision
Net assets acquired
Consideration transferred
Property, plant, and equipment
Net working capital
Decommissioning and restoration provision
Carrying amount of transferred net assets
Gain recognized
372
104
37
2
515
3
512
234
27
(11)
250
262
(1) Future qaznents uneer the finance mease incmuee $57 nimmion annuammz fron 2916 to 2918, ane $29 nimmion annuammz fron 2919 to 2939.
Paznents hawe been eiscountee at a rate of 2.68%, basee on conqaratiwe zieme on borroxings of the counterqartz xith eruiwament
naturities at the tine of cmosing.
The acquired wind farms’ contribution to the Corporation’s revenue and operating income since the date of acquisition has
been nominal. Had the acquisition taken place at the beginning of the year, the wind farms would have contributed $8 million
to revenues and reduced earnings before tax by $2 million.
F27
TRANSALTA CORPORATION F27
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
B. U.S. Solar and Wind Acquisition
On Oct. 1, 2015, the Corporation closed the acquisition of 100 per cent of the membership interests of Odin Wind Power LLC,
owner of the 50 MW Lakeswind wind facility located in Minnesota, for cash consideration of $49 million and the assumption
of certain tax equity obligations. The facility is contracted under long-term power purchase agreements until 2034.
On Sept. 1, 2015, the Corporation closed the acquisition of 100 per cent of the membership interests of RC Solar LLC for cash
consideration of $55 million. The assets acquired include 21 MW of fully contracted solar projects located in Massachusetts,
which are contracted under long-term power purchase agreements ranging from 20 to 30 years, and are qualified under
phase one of the Massachusetts Solar Renewable Energy Credit program (“SREC-I”).
At the acquisition dates, the preliminary fair values of the identifiable assets and liabilities of Odin Wind Power LLC and RC
Solar LLC were as follows:
Assets(1)
Property, plant, and equipment
Inventory (SREC-I)
Net working capital
Total assets acquired
Liabilities
(1)
Non-recourse debt
Tax equity liability
Deferred tax liabilities(2)
Decomissioning and restoration provision
Total liabilities assumed
Total consideration transferred(1)
217
10
6
233
55
50
18
4
127
106
(1) The Corqoration exqects to finamize tax ane net xorling caqitam reconcimiations xith the semmer euring the first hamf of 2916.
(2) The Corqoration has recognizee a corresqoneing eeferree tax recowerz in the Consomieatee Statenent of Earnings uqon acruisition,
reqresenting eeeuctibme tenqorarz eifferences nox exqectee to be recoweree.
The acquired assets’ contribution to the Corporation’s revenue and operating income since the date of acquisition has been
nominal. Had the acquisition taken place at the beginning of the year, the assets would have contributed $14 million to
revenues and reduced earnings before taxes by $6 million.
F28
F28 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
C. Sale of Economic Interest in Australian Assets to TransAlta Renewables Inc.
On May 7, 2015, the Corporation closed the acquisition by TransAlta Renewables Inc. (“TransAlta Renewables”) of an
economic interest based on the cash flows of the Corporation’s Australian assets (the “Transaction”). The Corporation’s
Australian assets consist of 575 MW of power generation from six operating assets and the South Hedland power project
currently under construction, as well as the recently commissioned 270 kilometre gas pipeline (collectively, the “Portfolio”).
TransAlta Renewables’ investment consists of the acquisition of securities that, in aggregate, provide an economic interest
based on cash flows of the Australian assets broadly equal to the underlying net distributable profits. The combined value of
the Transaction was $1.78 billion. The Corporation continues to own, manage, and operate the Australian assets.
With the closing of the Transaction, the Corporation received net cash proceeds of $211 million as well as approximately
$1,067 million through a combination of common shares and Class B shares of TransAlta Renewables. The Class B shares
provide voting rights equivalent to the common shares, are non-dividend paying, and will convert into common shares once
the South Hedland power project is completed and commissioned.
The number of common shares that the Corporation will receive on the conversion of the Class B shares will be adjusted to
reflect the actual amount funded by TransAlta Renewables for the construction and commissioning of the South Hedland
power project relative to target costs of $491 million.
TransAlta Renewables funded the cash proceeds through the public issuance of 17,858,423 common shares at a price of
$12.65 per share. The offering closed in two parts on April 15 and 23, 2015. TransAlta Renewables shareholder approval was
received on May 7, 2015. TransAlta Renewables received approximately $226 million in gross proceeds, and in total, incurred
$11 million in share issue costs, net of $3 million of income tax recovery. Proceeds to equity were further reduced by dividend
equivalent payments of $1 million.
D. Investment in Sarnia Cogeneration Plant, Le Nordais Wind Farm, and Ragged Chute Hydro Facility
On Nov. 23, 2015, the Corporation entered into an investment agreement with TransAlta Renewables, pursuant to which it has
agreed to acquire an economic interest based on the cash flows of the Corporation’s Sarnia cogeneration plant, Le Nordais
wind farm, and Ragged Chute hydro facility (the “Canadian Assets”) for a combined value of approximately $540 million. The
Canadian Assets consist of approximately 611 MW of highly contracted power generation assets located in Ontario and
Quebec. TransAlta Renewables’ investment consists of the acquisition of tracking preferred shares of a subsidiary of the
Corporation that will provide TransAlta Renewables with an economic interest based on cash flows broadly equal to the
underlying net distributable profits of the Canadian Assets. The Corporation will continue to own, manage, and operate the
Canadian Assets.
TransAlta Renewables financed the investment through a combination of cash, unsecured debentures, and shares issued to
the Corporation.
In order to fund the cash consideration payable to the Corporation, TransAlta Renewables issued 15,385,000 subscription
receipts at a price of $9.75 per subscription receipt for gross proceeds of approximately $150 million. In addition, TransAlta
Renewables granted an over-allotment option to the underwriters to purchase up to 2,307,750 subscription receipts at the
same price for gross proceeds of up to approximately $23 million. The underwriters exercised in full the over-allotment option.
The offering and the over-allotment option closed on Dec. 2, 2015. TransAlta Renewables received approximately $173 million
in gross proceeds ($166 million in net proceeds). The proceeds from the sale of the subscription receipts have been directed
to an escrow agent and invested in a demand deposit account with a Canadian chartered bank until the closing of this
investment and that will be released to TransAlta Renewables upon the closing of this transaction. As at Dec. 31, 2015, a
substantive closing condition remained outstanding and accordingly the investment in Canadian Assets and associated
financing are not reflected in these financial statements.
On Jan. 6, 2016, the Corporation announced the closing of the investment in the Canadian Assets for a combined value of
$540 million. Refer to Note 34 for further details.
F29
TRANSALTA CORPORATION F29
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
E. Sale of TransAlta Renewables Shares to Alberta Investment Management Corporation
On Nov. 26, 2015, TransAlta completed the sale to Alberta Investment Management Corporation (“AIMCo”) of 20,512,820
common shares of TransAlta Renewables for gross proceeds of $200 million (net proceeds of $193 million). As a result,
TransAlta’s ownership interest was reduced from approximately 76.1 per cent to approximately 66.6 per cent (including the
Class B common shares).
As part of the AIMCo investment, TransAlta Renewables granted to AIMCo a pre-emptive right to purchase such number of
common shares of TransAlta Renewables in respect of any future offerings of common shares, or securities convertible into
common shares, in order to allow AIMCo to maintain its proportionate shareholdings in TransAlta Renewables, provided that
AIMCo's ownership remains above a specific threshold.
F. Provision Adjustment
As part of its regular year-end process, the Corporation reviewed its provisions in respect of force majeure outages associated
with its power purchase arrangements and as well as various other claims or disputes, including potential claims or disputes
that may lead to litigation or arbitration. In 2015, following its review, the Corporation increased a provision by
$66 million, including interest, as at Dec. 31, 2015. The adjustment decreased Canadian Coal revenue by $59 million and
increased interest expense by $7 million.
G. Restructuring Provision
On Jan. 14, 2015, the Corporation initiated a significant cost-reduction initiative at its Canadian Coal power generation
operations, resulting in the elimination of positions. On Sept. 29, 2015, the Corporation further reduced its overhead costs by
eliminating positions primarily at its corporate head office in Calgary.
H. Changes in Internal Capitalization of U.S. Entities
On Dec. 15, 2015, the Corporation partially redeemed its net investment in a wholly owned subsidiary. As a result, the
Corporation reclassified from OCI pro rata cumulative translation gains of $10 million, offset by related pro rata cumulative
after-tax losses of $6 million from the net investment hedge.
I. Disposal of CE Generation, LLC
On June 12, 2014, the Corporation closed the sale of its 50 per cent ownership of CE Generation, LLC (“CE Gen”), CalEnergy
LLC, and the Blackrock development project to MidAmerican Renewables for gross proceeds of US$200.5 million. The original
consideration of US$188.5 million was increased as a result of a US$12 million contribution made by the Corporation in May
2014. As a result of the sale, the Corporation recognized a pre-tax gain of $1 million ($2 million after-tax) as part of the gain
on sale of assets.
On Nov. 25, 2014, the Corporation closed the sale of its 50 per cent ownership of Wailuku Holding Company, LLC for gross
proceeds of US$5 million. A pre-tax gain of $1 million ($1 million after-tax) was recognized as part of the gain on sale of assets.
The gains include reclassified cumulative translation gains of $7 million on the divested net assets, offset by related
cumulative after-tax losses of $7 million from the related net investment hedge.
F30
F30 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
J. Acquisition of Wyoming Wind Farm
On Dec. 20, 2013, the Corporation completed the acquisition of a 144 MW wind farm in Wyoming from an affiliate of NextEra
Energy Resources, LLC. The total cash consideration transferred was US$102 million ($109 million). The acquisition was
TransAlta’s first wind project in the U.S.
At the acquisition date, the fair value of assets acquired and liabilities assumed was as follows:
Assets:
Property, plant, and equipment
Intangible assets
Goodwill
Total assets acquired
Liabilities:
Decommissioning and restoration provision
Total consideration transferred
79
20
13
112
3
109
Goodwill arose in the acquisition primarily as a result of the expectation by the Corporation of future market growth and
development opportunities in the region. These benefits are not recognized separately from goodwill as they do not meet the
recognition criteria for identifiable intangible assets. All of the goodwill is expected to be deductible for tax purposes.
K. Formation of TransAlta Renewables and Secondary Offering
On May 28, 2013, the Corporation 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. The Corporation retains control over
TransAlta Renewables, and therefore consolidates TransAlta Renewables.
On Aug. 9, 2013, the Corporation 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.
(“CHD”) and Western Sustainable Power Inc. On Aug. 29, 2013, TransAlta Renewables completed an Initial Public Offering
and issued 22.1 million common shares for gross proceeds of $221 million. In total, the Corporation received $207 million in
cash consideration net of commissions and expenses. The excess of consideration received over the net book value of the
Corporation’s divested interest was $4 million and was recognized in retained earnings (deficit).
On April 29, 2014, the Corporation completed a secondary offering of 11,950,000 common shares of TransAlta Renewables at a
price of $11.40 per common share. The offering resulted in gross proceeds to the Corporation of approximately $136 million. As a
result of the transaction, the carrying amount of the non-controlling interests was increased by $109 million to reflect the
approximate 10.4 per cent increase in their relative interest in TransAlta Renewables and a $20 million gain, net of tax and
issuance costs, attributable to common shareholders, was recognized directly in retained earnings (deficit).
F31
TRANSALTA CORPORATION F31
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
5. Expenses by Nature
Expenses classified by nature are as follows:
Year ended Dec. 31
2015
2014
2013
Fuel and
purchased
power
Operations,
maintenance, and
administration
Fuel and
purchased
power
Operations,
maintenance, and
administration
Fuel and
purchased
power
Operations,
maintenance, and
administration
Fuel
Coal inventory writedown
Purchased power
Mine depreciation
Salaries and benefits
Other operating expenses
Total
775
22
147
59
5
-
1,008
-
-
-
-
250
242
492
937
19
75
56
5
-
1,092
-
-
-
-
280
262
542
778
22
85
58
5
-
948
-
-
-
-
251
265
516
6. Asset Impairment Charges and Reversals
A. 2015
The Corporation considers the relationship between its market capitalization and its book value, among other factors, when
reviewing for indicators of impairment. The slowdown in the oil and gas sector has put Alberta into a recession, and
downward pressure on demand as well as power prices. Further, on Nov 20, 2015, the government of Alberta announced its
Climate Leadership Plan, which broadly calls for the phase-out of coal-generated electricity by 2030, and proposes the
imposition of additional compliance obligations for Greenhouse Gas (“GHG”) emissions in the province. As at Dec. 31, 2015,
the market capitalization of the Corporation was below the book value of its equity. The Government has stated intentions of
providing compensation to coal-fired generators as part of its commitment to treat them fairly and not unnecessarily strand
capital. The Corporation intends to negotiate an arrangement with the government.
As part of its monitoring controls, the Corporation estimates a recoverable amount for each CGU by calculating an
approximate fair value less costs of disposal using discounted cash flow projections based on the Corporation’s long-range
forecasts. The valuations used are subject to measurement uncertainty based on assumptions and inputs to the Corporation’s
long-range forecast, including changes to fuel costs, operating costs, capital expenditures, external power prices, and useful
lives of the assets extending to the last planned asset retirement in 2073. These estimates are used to assess the significance
of potential indicators of impairment and provide a criterion to evaluate adverse changes in operations.
During the fourth quarter, the Corporation completed a sensitivity analysis on these estimates to assess potential impacts of
the proposed Alberta government policy on reducing GHG emissions, as well as the mandatory retirement of coal facilities by
2030. The sensitivity demonstrated an approximate fair value substantially in excess of the carrying amount of the Alberta
Merchant CGU, and accordingly, no further test was performed. The excess is attributable to the Corporation’s large
renewable fleet in the province.
The Corporation also considered possible impairment at the U.S. Coal CGU utilizing a similar process as noted in the 2014
section below, and again found that the fair value, less costs to sell, approximates the current carrying amount.
Accordingly, there were no impairment charges made during the year ended Dec. 31, 2015. Impairment reversals of $2 million
resulted from additional recoveries from the disposal of the Centralia gas plant in 2014.
F32
F32 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
B. 2014
I. U.S. Coal
As at Nov. 30, 2014, the Corporation identified the decrease in projected growth in Mid-Columbia power prices as an
indicator that the U.S. Coal CGU could be impaired. The U.S. Coal CGU’s carrying amount at that date, net of associated long-
term liabilities, was $372 million. The Corporation estimated the fair value less costs of disposal of the CGU, a Level III fair
value measurement, utilizing the Corporation’s long-range forecast and the following key assumptions:
Mid-Columbia annual average power prices
On-highway diesel fuel on coal shipments
Discount rates
US$31.00 to 52.00 per MWh
US$3.06 to 3.37 per gallon
5.1 to 6.2 per cent
The valuation is subject to measurement uncertainty based on those assumptions, and on inputs to the Corporation’s long-
range forecast, including changes to fuel costs, operating costs, capital expenses, and the level of contractedness under the
Memorandum of Agreement for coal transition established with the State of Washington. The valuation period extended to
the assumed decommissioning of the asset, after its projected cessation of operation in its current form in 2025.
Fair value less costs of disposal of the CGU was estimated to approximate its carrying amount, and accordingly, no
impairment charge was recorded. Any adverse change in assumptions, in isolation, would have resulted in an impairment
charge being recorded. The Corporation continues to manage risks associated with the CGU through optimization of its
operating activities and capital plan.
II. Centralia Gas
During 2014, the Corporation sold to external counterparties and transferred to other owned facilities for productive use,
assets of the Centralia gas facility that had been fully impaired and had remained idled since 2010. As a result of the
transactions, the Corporation recognized pre-tax impairment reversals of $5 million in the gas segment.
C. 2013
I. Alberta Merchant
As part of the annual impairment review and assessment process in 2013, it was determined that the Corporation’s 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 emissions
and the 50-year total life for Canadian coal-fired power plants; and the Corporation’s refinement of its risk management
approach and practices regarding its Alberta wholesale market price exposure. The final regulations confirmed additional
operating time and increased flexibility for the Corporation’s Alberta coal plants and led, in part, to the Corporation
broadening its view on the management of its Alberta wholesale market price exposure.
The Corporation reversed previous pre-tax impairment losses of $23 million in the Wind Segment, on various plants that
became part of the Alberta Merchant CGU. The Alberta Merchant CGU’s recoverable amount was based on an estimate of
fair value less costs of disposal using a discounted cash flow methodology based on the Corporation’s long-range forecasts
and prices evidenced in the marketplace. Due to a substantial excess of fair value over net book value at other plants included
within the Alberta Merchant CGU, valuation assumptions and methodologies were not a significant driver of the impairment
reversals.
II. Renewables
During 2013, the Corporation recognized a total pre-tax impairment charge of $4 million in the Hydro Segment, related to
three contracted hydro assets. 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 were based on estimates of
fair value less costs of disposal derived from long-range forecasts.
F33
TRANSALTA CORPORATION F33
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
7. Finance Lease Receivables
Amounts receivable under the Corporation’s finance leases, associated with the Fort Saskatchewan cogeneration facility, the
Solomon power station, and, beginning in 2015, the Poplar Creek cogeneration facility, are as follows:
As at Dec. 31
Within one year
Second to fifth years inclusive
More than five years
Less: Unearned finance lease income
Add: Unguaranteed residual value
Total finance lease receivables
Included in the Consolidated Statements of Financial Position as:
Current portion of finance lease receivables (Note 12)
Long-term portion of finance lease receivables
2015
2014
Minimum
lease
payments
Present value of
minimum lease
payments
Minimum
lease
payments
Present value of
minimum lease
payments
121
414
714
1,249
648
229
830
55
775
830
51
157
162
370
-
38
408
116
326
337
779
-
51
830
55
229
479
763
546
191
408
5
403
408
8. Net Other Operating Income and Losses
Net other operating (income) losses are comprised of the following:
Year ended Dec. 31
MSA settlement
Insurance recoveries
California claim
Supplier settlement
Sundance Units 1 and 2 return to service
Loss on assumption of pension obligations
Net other operating (income) losses
2015
56
(31)
-
-
-
-
25
2014
2013
-
(10)
5
(9)
-
-
(14)
-
(8)
56
-
25
29
102
F34
F34 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
A. Settlement with the Market Surveillance Administrator
On March 21, 2014, the Alberta Market Surveillance Administrator (the “MSA”) filed an application with the Alberta Utilities
Commission (the “AUC”) alleging, among other things, that TransAlta manipulated the price of electricity in the Province of
Alberta when it took outages at certain of its coal-fired generating units in late 2010 and early 2011. The Corporation denied
the MSA’s allegations. An oral hearing took place before the AUC in December 2014. A written argument was filed in
February 2015. In May 2015, further submissions were filed on a recent Supreme Court of Canada decision relevant to expert
evidence. On July 27, 2015, the AUC issued a decision finding, among other things, that (i) the Corporation’s actions in
relation to four outage events at its coal-fired generating units, spanning 11 days in 2010 and 2011, restricted or prevented a
competitive response from the associated Power Purchase Arrangement buyers and manipulated market prices away from a
competitive market outcome and (ii) the Corporation breached applicable legislation by allowing one of its employees to
trade while in possession of non-public outage records. The AUC also found that the MSA did not prove, on the balance of
probabilities, that the Corporation breached applicable legislation on the basis that its compliance policies, practices, and
oversight thereof, were inadequate and deficient.
This AUC decision marked the end of the first phase of the proceedings. TransAlta filed for leave to appeal the AUC decision
with the Alberta Court of Appeal in August 2015. The second phase of the AUC proceedings was to consider what penalty the
AUC might impose against the Corporation. On Sept. 30, 2015, TransAlta and the MSA reached an agreement to settle all
outstanding proceedings before the AUC. The settlement, which is in the form of a consent order, was approved by the AUC
on Oct. 29, 2015. Under the terms of the consent order, the Corporation will pay a total amount of $56 million that includes
approximately $27 million as a repayment of economic benefit, $4 million to cover the MSA’s legal and related costs, and a
$25 million administrative penalty. Of this amount, $31 million has been paid in the fourth quarter, and the $25 million
administrative penalty will be paid one year after this first payment. As a result of the approval, the Corporation has
discontinued the appeal of the AUC’s decision.
B. Insurance Recoveries
During 2015, the Corporation received $31 million in insurance recoveries (2014 - $10 million, 2013 - $8 million), of which
$18 million (2014 - $4 million, 2013 - $1 million) relates to claims for the replacement and refurbishment of equipment for
certain hydro facilities as a result of flooding in Southern Alberta in 2013 and $7 million in insurance proceeds relating to
claims for repair costs on one of the Corporation’s Canadian Coal facilities. The balance, in the amount of $6 million (2014 -
$6 million, 2013 - $7 million), relates to business interruption insurance for various prior years’ claims.
Additionally, $12 million (2014 - $18 million, 2013 - $7 million) of insurance proceeds were received related to claims for
repair costs on certain hydro facilities as a result of flooding in Southern Alberta in 2013 and were accounted for as a
reduction to period operations, maintenance, and administration.
C. California Claim
On May 30, 2014, the Corporation announced that its settlement with California utilities, the California Attorney General, and
certain other parties (the “California Parties”) to resolve claims related to the 2000-2001 power crisis in the State of
California had been approved by the Federal Energy Regulatory Commission. The settlement provides for the payment by the
Corporation of US$52 million in two equal payments and a credit of approximately US$97 million for monies owed to the
Corporation from accounts receivable. The first payment of US$26 million was paid in June 2014 and the second was paid in
2015. In 2013, the Corporation accrued for the then expected settlement of these disputes with the California Parties, which
resulted in a pre-tax charge to 2013 earnings of approximately US$52 million. The finalization of the settlement in May 2014
resulted in an additional pre-tax charge to 2014 earnings of US$5 million.
D. Supplier Settlement
During 2014, the Corporation settled a dispute with a supplier in relation to an equipment failure in prior years.
F35
TRANSALTA CORPORATION F35
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
E. Sundance Units 1 and 2 Return to Service
In December 2010, Units 1 and 2 of the Corporation’s 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 the Corporation was required to restore the units to service. For the year ended Dec. 31, 2012,
a $254 million pre-tax impact of the ruling has been recognized. During 2013, $25 million of components were retired as a
result of the work completed on the units to return them to service. Sundance Unit 1 returned to service on Sept. 2, 2013 and
Unit 2 returned to service on Oct. 4, 2013.
F. Loss on Assumptions of Pension Obligations
Effective Jan. 17, 2013, the Corporation assumed, through its wholly owned subsidiary, 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 the Corporation previously funded through the payments made
under the PMRL mining contracts. As a result, a pre-tax loss of $29 million was recognized in 2013, along with the
corresponding liabilities.
9. Net Interest Expense
The components of net interest expense are as follows:
Year ended Dec. 31
Interest on debt
Capitalized interest (Note 16)
Interest on finance lease obligations
Other (Note 4)
Accretion of provisions (Note 29)
Net interest expense
2015
2014
2013
228 238
240
(9) (3) (2)
4
1
-
7
-
-
21 18 18
251
254
256
F36
F36 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
10. Income Taxes
A. Consolidated Statements of Earnings (Loss)
I. Rate Reconciliations
Year ended Dec. 31
Earnings (loss) before income taxes
Equity loss
2015
2014
2013
221 239
(12)
-
-
10
Net earnings attributable to non-controlling interests not subject to tax
(34) (37) (29)
Adjusted earnings (loss) before income taxes
Statutory Canadian federal and provincial income tax rate (%)
Expected income tax expense (recovery)
Increase (decrease) in income taxes resulting from:
Lower effective foreign tax rates
Deferred income tax expense related to temporary difference on
investment in subsidiary
MSA settlement
187 202
(31)
25.9
25.0
25.0
48
51 (8)
(16) (3) (21)
95
-
-
14 -
-
Writedown (reversal of writedown) of deferred income tax assets
(56) (5) 28
Statutory and other rate differences
Resolution of uncertain tax matters
Divestiture of investment
Other
Income tax expense (recovery)
Effective tax rate (%)
20
-
(5)
-
(1) (1)
-
(38) -
-
3
(1)
105
7
(8)
56
3
26
F37
TRANSALTA CORPORATION F37
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
II. Components of Income Tax Expense
The components of income tax expense (recovery) are as follows:
Year ended Dec. 31
Current income tax expense
2015
2014
2013
24
33
38
Adjustments in respect of current income tax of previous years
(5) -
1
Adjustments in respect of deferred income tax of previous years
5
2
(1)
Deferred income tax expense (recovery) related to the
origination and reversal of temporary differences
Deferred income tax expense related to temporary difference on
investment in subsidiary(1)
Deferred income tax expense (recovery) resulting from changes
in tax rates or laws(2)
Benefit arising from previously unrecognized tax loss, tax
credit, or temporary difference of a prior period used to
reduce deferred income tax expense
Deferred income tax expense (recovery) arising from the writedown
(reversal of writedown) of deferred income tax assets(3)
Income tax expense (recovery)
Year ended Dec. 31
Current income tax expense
Deferred income tax expense (recovery)
Income tax expense (recovery)
22
12 (68)
95
-
-
20
-
(5)
-
(35) (1)
(56) (5) 28
105
7
(8)
2015
2014
2013
19
33
39
86
(26) (47)
105
7
(8)
(1) In order to give effect to the Transaction with TransAlta Renewables, a reorganization of certain TransAlta companies was completed. The reorganization resulted in the
recognition of a $95 million deferred tax liability on TransAlta’s investment in a subsidiary. The deferred tax liability had not been recognized previously, as prior to the
reorganization, the taxable temporary difference was not expected to reverse in the foreseeable future.
(2) During the second quarter of 2015, the Government of Alberta substantively enacted legislation to increase its provincial corporate income tax rate to 12 per cent from
10 per cent, effective July 1, 2015. This resulted in a net increase in the Corporation’s deferred income tax liability of $18 million, of which $20 million is recorded in the
Consolidated Statement of Earnings with an offsetting $2 million deferred tax recovery recorded in the Consolidated Statement of Other Comprehensive Income.
(3) During the year ended Dec. 31, 2015, the Corporation reversed a previous writedown of deferred income tax assets of $56 million (2014 - $5 million writedown reversal,
2013 - $28 million writedown), of which $7 million during the year has been applied to offset an adjustment in respect of deferred income tax of prior periods. The deferred
income tax assets relate mainly to the tax benefits of losses associated with the Corporation’s directly owned U.S. operations. The Corporation had written these assets off as
it was no longer considered probable that sufficient future taxable income would be available from the Corporation’s directly owned U.S. operations to utilize the underlying
tax losses, due to reduced price growth expectations. Net operating losses expire between 2021 and 2035. Recognized other comprehensive income during the years ended
Dec. 31, 2015 and 2014 have given rise to taxable temporary differences, which forms the primary basis for utilization of some of the tax losses and the reversal of the
writedown.
B. Consolidated Statements of Changes in Equity
The aggregate current and deferred income tax related to items charged or credited to equity are as follows:
Year ended Dec. 31
Income tax expense (recovery) related to:
Net impact related to cash flow hedges
Net impact related to net investment hedges
Net actuarial gains (losses)
Share issuance costs
Loss on sale of investment in subsidiary
Income tax expense reported in equity
F38
F38 TRANSALTA CORPORATION
2015
2014
2013
88
88 12
8
(8) (5)
-
(7) 11
(4) (1) -
(8) -
-
84
72
18
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
C. Consolidated Statements of Financial Position
Significant components of the Corporation’s deferred income tax assets (liabilities) are as follows:
As at Dec. 31
Net operating loss carryforwards
Future decommissioning and restoration costs
Property, plant, and equipment
Risk management assets and liabilities, net
Employee future benefits and compensation plans
Interest deductible in future periods
Foreign exchange differences on U.S.-denominated debt
Deferred coal revenues
Other deductible temporary differences
Net deferred income tax liability, before writedown of deferred income tax assets
Writedown of deferred income tax assets
Net deferred income tax liability, after writedown of deferred income tax assets
2015
2014
822
716
91
101
(1,124) (916)
(250) (144)
70
68
91
81
74
48
16
14
(4) 2
(214) (30)
(362) (359)
(576) (389)
The net deferred income tax liability is presented in the Consolidated Statements of Financial Position as follows:
As at Dec. 31
Deferred income tax assets(1)
Deferred income tax liabilities
Net deferred income tax liability
2015
2014
71
45
(647) (434)
(576)
(389)
(1) The eeferree incone tax assets qresentee on the Consomieatee Statenents of Financiam Position are recowerabme basee on estinatee future earnings ane tax qmanning
strategies. The assunqtions usee in the estinate of future earnings are basee on the Corqoration’s mong)range forecasts.
D. Contingencies
As of Dec. 31, 2015, the Corporation had recognized a net liability of $7 million (2014 - $7 million) related to uncertain tax
positions. The change in the liability for uncertain tax positions is as follows:
Balance, Dec. 31, 2013
Decrease as a result of settlements with taxation authorities
Balance, Dec. 31, 2014 and Dec. 31, 2015
(8)
1
(7)
F39
TRANSALTA CORPORATION F39
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
11. Non-Controlling Interests
The Corporation’s subsidiaries and operations that have non-controlling interests are as follows:
Subsidiary/Operation
TransAlta Cogeneration L.P.
TransAlta Renewables
Kent Hills wind farm(2)
(1) As at Dec. 31, 2914, the non)contromming interest xas 29.79%.
(2) Oxnee bz TransAmta Renexabmes.
Non-controlling interest as at Dec. 31, 2015
49.99% - Canadian Power Holdings Inc.
37.96% - Public shareholders(1)
17% - Natural Forces Technologies Inc.
TA Cogen operates a portfolio of cogeneration facilities in Canada, and owns 50 per cent of a coal facility. TransAlta
Renewables owns and operates a portfolio of renewable power generation facilities in Canada, and owns economic interests in
various other gas and renewable facilities of the Corporation.
Summarized financial information relating to subsidiaries with significant non-controlling interests is as follows:
A. TransAlta Renewables
The net earnings, distributions, and equity attributable to non-controlling interests include the 17 per cent non-controlling
interest in the 150 MW Kent Hills wind farm located in New Brunswick.
As a result of the transactions described in Note 4, the Corporation’s share of ownership and equity participation fluctuated
since the formation of TransAlta Renewables as follows:
Period
Inception to Aug. 8, 2013
Aug. 9, 2013 to April 28, 2014
April 29, 2014 to May 6, 2015
May 7, 2015 to Nov. 25, 2015
Nov. 26, 2015 to Jan. 5, 2016
Jan. 6, 2016
Ownership and voting
rights percentage
Equity participation
percentage
100
80.7
70.3
76.1
66.6
64.0
100
80.7
70.3
72.8
62.0
59.8
As the Class B shares issued to the Corporation in the Transaction were determined to constitute financial liabilities of
TransAlta Renewables and do not participate in earnings until commissioning of South Hedland, they are excluded from the
allocation of equity and earnings.
Year ended Dec. 31
Revenues
Net earnings
Total comprehensive income
Amounts attributable to the non-controlling interests:
Net earnings
Total comprehensive income
Distributions paid to non-controlling interests
F40
F40 TRANSALTA CORPORATION
2015
236
198
204
63
65
43
2014
233
52
52
15
15
28
2013
245
53
54
5
5
9
TransAlta Corporation | 2015 Annual Integrated Report
As at Dec. 31
Current assets
Long-term assets
Current liabilities
Long-term liabilities
Total equity
Equity attributable to non-controlling interests
Non-controlling interests' share (per cent)
B. TA Cogen
Year ended Dec. 31
Results of operations
Revenues
Net earnings
Total comprehensive income
Amounts attributable to the non-controlling interest:
Net earnings
Total comprehensive income
Distributions paid to Canadian Power Holdings Inc.
As at Dec. 31
Current assets
Long-term assets
Current liabilities
Long-term liabilities
Total equity
Equity attributable to Canadian Power Holdings Inc.
Non-controlling interest share (per cent)
12. Trade and Other Receivables
As at Dec. 31
Trade accounts receivable
Income taxes receivable
Current portion of finance lease receivables (Note 7)
Collateral paid (Note 14)
Trade and other receivables
Notes to Consolidated Financial Statements
2015
288
61
77
31
38
56
2015
74
3,262
(190)
(1,120)
(2,026)
(787)
37.96
2014
61
1,903
(241)
(682)
(1,041)
(334)
29.7
2014
2013
305
71
72
35
35
56
2015
82
535
(75)
(54)
(488)
(242)
49.99
295
48
71
24
36
46
2014
58
588
(64)
(59)
(523)
(260)
49.99
2015
2014
433
415
5
5
55
5
74
25
567
450
F41
TRANSALTA CORPORATION F41
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
13. Financial Instruments
A. Financial Assets and Liabilities – Classification and Measurement
Financial assets and financial liabilities are measured on an ongoing basis at cost, fair value, or amortized cost (see
Note 2(C)). The following table outlines the carrying amounts and classifications of the financial assets and liabilities:
Derivatives
used for
hedging
Derivatives
classified as
held for
trading
Loans and
receivables
Other
financial
liabilities
-
-
-
101
808
-
-
57
45
-
-
-
-
197
(11)
-
-
143
24
-
54
567
775
-
-
.
-
-
-
-
-
-
-
-
-
-
334
63
-
-
Total
54
567
775
298
797
334
63
200
69
4,495
4,495
Carrying value as at Dec. 31, 2015
Financial assets
Cash and cash equivalents
Trade and other receivables
Long-term portion of finance lease receivables
Risk management assets
Current
Long-term
Financial liabilities
Accounts payable and accrued liabilities
Dividends payable
Risk management liabilities
Current
Long-term
Credit facilities, long-term debt and
finance lease obligations(1)
(1) Incmuees current qortion.
F42
F42 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Carrying value as at Dec. 31, 2014
Financial assets
Cash and cash equivalents
Trade and other receivables
Long-term portion of finance lease receivables
Risk management assets
Current
Long-term
Financial liabilities
Accounts payable and accrued liabilities
Dividends payable
Risk management liabilities
Current
Long-term
Credit facilities, long-term debt and
finance lease obligations(1)
(1) Incmuees current qortion.
Notes to Consolidated Financial Statements
Derivatives
used for
hedging
Derivatives
classified as
held for trading
Loans and
receivables
Other
financial
liabilities
-
-
-
93
393
-
-
39
75
-
-
-
-
180
9
-
-
89
19
-
43
450
403
-
-
-
-
-
-
-
Total
43
450
403
273
402
481
55
128
94
-
-
-
-
-
481
55
-
-
4,056
4,056
B. Fair Value of Financial Instruments
The fair value of a financial instrument is the price that would be received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the measurement date. Fair values can be determined by reference to
prices for that instrument in active markets to which the Corporation has access. In the absence of an active market, the
Corporation determines fair values based on valuation models or by reference to other similar products in active markets.
Fair values determined using valuation models require the use of assumptions. In determining those assumptions, the
Corporation looks primarily to external readily observable market inputs. However, if not available, the Corporation uses
inputs that are not based on observable market data.
I. Level I, II, and III Fair Value Measurements
The Level I, II, and III classifications in the fair value hierarchy utilized by the Corporation are defined below. The fair value
measurement of a financial instrument is included in only one of the three levels, the determination of which is based on the
lowest level input that is significant to the derivation of the fair value.
a. Level I
Fair values are determined using inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities
that the Corporation has the ability to access at the measurement date. In determining Level I fair values, the Corporation uses
quoted prices for identically traded commodities obtained from active exchanges such as the New York Mercantile Exchange.
F43
TRANSALTA CORPORATION F43
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
b. Level II
Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability.
Fair values falling within the Level II category are determined through the use of quoted prices in active markets, which in
some cases are adjusted for factors specific to the asset or liability, such as basis, credit valuation, and location differentials.
The Corporation’s commodity risk management Level II financial instruments include over-the-counter derivatives with values
based on observable commodity futures curves and derivatives with inputs validated by broker quotes or other publicly
available market data providers. Level II fair values are also determined using valuation techniques, such as option pricing
models and regression or extrapolation formulas, where the inputs are readily observable, including commodity prices for
similar assets or liabilities in active markets, and implied volatilities for options.
In determining Level II fair values of other risk management assets and liabilities and long-term debt measured and carried at
fair value, the Corporation uses observable inputs other than unadjusted quoted prices that are observable for the asset or
liability, such as interest rate yield curves and currency rates. For certain financial instruments where insufficient trading
volume or lack of recent trades exists, the Corporation relies on similar interest or currency rate inputs and other third-party
information such as credit spreads.
c. Level III
Fair values are determined using inputs for the assets or liabilities that are not readily observable.
The Corporation may enter into commodity transactions for which market-observable data is not available. In these cases,
Level III fair values are determined using valuation techniques such as the Black-Scholes, mark-to-forecast, and historical
bootstrap models with inputs that are based on historical data such as unit availability, transmission congestion, demand
profiles for individual non-standard deals and structured products, and/or volatilities and correlations between products
derived from historical prices.
The Corporation also has various commodity contracts with terms that extend beyond a liquid trading period. As forward
market prices are not available for the full period of these contracts, the value of these contracts is derived by reference to a
forecast that is based on a combination of external and internal fundamental modelling, including discounting. As a result,
these contracts are classified in Level III.
The Corporation has a Commodity Exposure Management Policy (the “Policy”), which governs both the commodity
transactions undertaken in its proprietary trading business and those undertaken to manage commodity price exposures in its
generation business. The Policy defines and specifies the controls and management responsibilities associated with
commodity trading activities, as well as the nature and frequency of required reporting of such activities.
Methodologies and procedures regarding commodity risk management Level III fair value measurements are determined by
the Corporation’s risk management department. Level III fair values are calculated within the Corporation’s energy trading risk
management system based on underlying contractual data as well as observable and non-observable inputs. Development of
non-observable inputs requires the use of judgment. To ensure reasonability, system-generated Level III fair value
measurements are reviewed and validated by the risk management and finance departments. Review occurs formally on a
quarterly basis or more frequently if daily review and monitoring procedures identify unexpected changes to fair value or
changes to key parameters.
Information on risk management contracts or groups of risk management contracts that are included in Level III
measurements and the related unobservable inputs and sensitivities, is as follows, and excludes the effects on fair value of
observable inputs such as liquidity and credit discount (described as “base fair values”), as well as inception gains or losses.
Sensitivity ranges for the base fair values are determined using reasonably possible alternative assumptions for the key
unobservable inputs, which may include forward commodity prices, commodity volatilities and correlations, delivery volumes,
and shapes.
F44
F44 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
As at Dec. 31
Description
Long-term power sale - U.S.
Long-term power sales - Alberta
Unit contingent power purchases
Structured products - Eastern U.S.
Hydro slice products - Western U.S.
Others
2015
2014
Base fair value
Sensitivity
Base fair value
Sensitivity
863
(13)
(70)
18
(6)
(3)
+125
-186
+13
-7
+9
-8
+6
-4
+1
-4
+2
-2
511
(13)
(53)
2
-
(4)
+76
-92
+13
-8
+9
-8
+1
-1
-
-
+2
-4
i. Long-Term Power Sale - U.S.
The Corporation has a long-term fixed price power sale contract in the U.S. for delivery of power at the following capacity
levels: 280 MW through Nov. 30, 2016, 380 MW through Dec. 31, 2024, and 300 MW through Dec. 31, 2025. The contract is
designated as an all-in-one cash flow hedge.
For periods beyond 2017, market forward power prices are not readily observable. For these periods, fundamental-based
forecasts and market indications have been used to determine proxies for base, high, and low power price scenarios. The base
price forecast has been developed by averaging external fundamental based forecasts (providers are independent and widely
accepted as industry experts for scenario and planning views) and market indicators. Forward power price ranges per MWh
used in determining the Level III base fair value at Dec. 31, 2015 are US$28 - US$45 (2014 - US$41 - US$50).
The contract is denominated in US dollars. With the continued strengthening of the US dollar relative to the Canadian dollar
from Dec. 31, 2014 to Dec. 31, 2015, the base fair value and the sensitivity values have increased by approximately
$136 million and $29 million, respectively, as a result of the currency movement.
ii. Long-Term Power Sales - Alberta
The Corporation has a long-term 12.5 MW fixed price power sale contract (monthly shaped) in the Alberta market through
December 2024. The contract is accounted for as held for trading.
For periods beyond 2020, market forward power prices are not readily observable. For these periods, fundamental-based
price forecasts and market indications have been used as proxies to determine base, high, and low power price scenarios. The
base scenario uses the most recent price view from an independent external forecasting service that is accepted within
industry as an expert in the Alberta market. Forward power price ranges per MWh used in determining the Level III base fair
value at Dec. 31, 2015 are $86 - $93 (2014 - $91 - $99).
iii. Unit Contingent Power Purchases
Under the unit contingent power purchase agreements the Corporation has agreed to purchase power contingent upon the
actual generation of specific units owned and operated by third parties. Under these types of agreements, the purchaser pays
the supplier an agreed upon fixed price per MWh of output multiplied by the pro rata share of actual unit production (nil if a
plant outage occurs). The contracts are accounted for as held for trading.
F45
TRANSALTA CORPORATION F45
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
The key unobservable inputs used in the valuations are delivered volume expectations and hourly shapes of production.
Hourly shaping of the production will result in realized prices that may be at a discount (or premium) relative to the average
settled power price. Reasonably possible alternative inputs were used to determine sensitivity on the fair value
measurements.
In particular, a one standard deviation movement upward and downward in the volumetric and price discount rates was
assessed. This analysis is based on historical production data of the generation units for available history. Price and volumetric
discount ranges per MWh used in the Level III base fair value measurement at Dec. 31, 2015 are 0 per cent to 2.8 per cent
(2014 - 0.3 per cent to 1.5 per cent) and 1.7 per cent to 7.4 per cent (2014 - 0 per cent to 10 per cent), respectively.
iv. Structured Products - Eastern U.S.
The Corporation has fixed priced power and heat rate contracts in the eastern United States. Under the fixed priced power
contracts the Corporation has agreed to buy or sell power at non-liquid locations, or during non-standard hours. The
Corporation has also bought and sold heat rate contracts at both liquid and non-liquid locations. Under a heat rate contract,
the buyer has the right to purchase power at times when the market heat rate is higher than the contractual heat rate.
The key unobservable inputs in the valuation of the fixed priced power contracts are market forward spreads and non-
standard shape factors. A historical regression analysis has been performed to model the spreads between non-liquid and
liquid hubs. The non-standard shape factors have been determined using the historical data. Basis relationship and non-
standard shape factors used in the Level III base fair value measurement at Dec. 31, 2015 are 85 per cent to 116 per cent and
65 per cent to 109 per cent (Dec. 31, 2014 – nil and 69 per cent to 103 per cent), respectively.
The key unobservable inputs in the valuation of the heat rate contracts are implied volatilities and correlations. Implied
volatilities and correlations used in the Level III base fair value measurement at Dec. 31, 2015 are 18 per cent to 71 per cent
and 39 per cent to 80 per cent (Dec. 31, 2014 – 26 per cent to 86 per cent and 53 per cent to 82 per cent), respectively.
v. Hydro Slice Products – Western U.S.
The Corporation has agreed to purchase power contingent upon the actual generation of specific hydro units owned and
operated by third parties. Under these types of agreements, the purchaser pays the supplier an agreed upon fixed capacity
payment. The contracts are accounted for as held for trading.
The key unobservable inputs used in the valuations are delivered volume expectations. Reasonably possible alternative inputs
were used to determine sensitivity on the fair value measurements. This analysis is based on historical production of the
generation units for available history. Volumes used in the Level III base fair value measurement at Dec. 31, 2015 are within the
50th percentile of the historical production.
II. Commodity Risk Management Assets and Liabilities
Commodity risk management assets and liabilities include risk management assets and liabilities that are used in the energy
marketing and generation businesses in relation to trading activities and certain contracting activities. To the extent
applicable, changes in net risk management assets and liabilities for non-hedge positions are reflected within earnings of
these businesses.
F46
F46 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
The following tables summarize the key factors impacting the fair value of the commodity risk management assets and
liabilities by classification level during the years ended Dec. 31, 2015 and 2014, respectively:
Net risk management assets (liabilities) at
Dec. 31, 2014
Changes attributable to:
Market price changes on existing
contracts
Market price changes on new contracts
Contracts settled
Net risk management assets
(liabilities) at Dec. 31, 2015
Additional Level III information:
Gains recognized in OCI
Total gains (losses) included in earnings
before income taxes
Unrealized losses included in earnings
before income taxes relating to net
liabilities held at Dec. 31, 2015
Net risk management assets (liabilities) at
Dec. 31, 2013
Changes attributable to:
Market price changes on existing
contracts
Market price changes on new contracts
Contracts settled
Transfers out of Level III
Net risk management assets
(liabilities) at Dec. 31, 2014
Additional Level III information:
Gains recognized in OCI
Total gains (losses) included in earnings
before income taxes
Unrealized losses included in earnings
before income taxes relating to net assets
held at Dec. 31, 2014
Hedges
Non-Hedges
Total
Level I
Level II
Level III
Level I
Level II
Level III
Level I
Level II
Level III
-
-
-
-
-
(59)
314
(26)
354
1
26
-
(28)
(58)
640
-
-
-
-
-
180
(97)
56
51
(159)
(29)
(48)
76
128
(98)
-
-
-
-
-
121
217
30
52
(133)
325
(48)
48
70
542
354
28
-
-
(77)
(1)
354
(49)
(1)
Hedges
Non-Hedges
Total
Level I
Level II
Level III
Level I
Level II
Level III
Level I
Level II
Level III
-
-
-
-
-
-
(66)
55
(13)
260
3
17
-
-
(1)
-
(59)
314
-
-
-
-
-
-
14
11
6
131
29
20
(80)
(48)
180
(97)
-
-
-
-
-
-
260
1
-
-
(60)
(108)
(52)
66
(7)
134
46
-
121
280
(80)
(49)
-
217
260
(59)
(108)
Significant changes in commodity net risk management assets (liabilities) during the year ended Dec. 31, 2015 are primarily
attributable to the following factors:
maturities and increases in value related to market movements for power contracts in the Pacific Northwest
(Level II non-hedge); and
changes in value of the long-term power sale contract (Level III hedge) as discussed in the preceding section (B)(I)(c)(i)
of this note.
F47
TRANSALTA CORPORATION F47
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
III. Other Risk Management Assets and Liabilities
Other risk management assets and liabilities primarily include risk management assets and liabilities that are used in hedging
non-energy marketing transactions, such as interest rates, the net investment in foreign operations, and other foreign
currency risks. Changes in other risk management assets and liabilities related to hedge positions are reflected within net
earnings when such transactions have settled during the period or when ineffectiveness exists in the hedging relationship.
Other risk management assets and liabilities with a total net asset fair value of $214 million as at Dec. 31, 2015
(2014 - $115 million net asset) are classified as Level II fair value measurements. The significant changes in other risk
management assets (liabilities) during the year ended Dec. 31, 2015 are primarily attributable to the strengthening of the US
dollar relative to the Canadian dollar on the Corporation’s foreign currency hedges.
IV. Other Financial Assets and Liabilities
The fair value of financial assets and liabilities measured at other than fair value is as follows:
Long-term debt(1) - Dec. 31, 2015
Long-term debt(1) - Dec. 31, 2014
Fair value
Level I
Level II
Level III
Total
-
-
4,067
4,091
-
-
4,067
4,091
Total
carrying
value
4,344
3,918
(1) Incmuees current qortion ane excmuees $69 nimmion (Dec. 31, 2914 ) $64 nimmion) of eebt neasuree ane carriee at fair wamue.
The fair values of the Corporation’s debentures and senior notes are determined using prices observed in secondary markets.
Non-recourse and other long-term debt fair values are determined by calculating an implied price based on a current
assessment of the yield to maturity.
The carrying amount of other short-term financial assets and liabilities (cash and cash equivalents, trade accounts receivable,
collateral paid, accounts payable and accrued liabilities, collateral received, and dividends payable) approximates fair value
due to the liquid nature of the asset or liability.
C. Inception Gains and Losses
The majority of derivatives traded by the Corporation are based on adjusted quoted prices on an active exchange or extend
beyond the time period for which exchange-based quotes are available. The fair values of these derivatives are determined
using inputs that are not readily observable. Refer to section B of this note for fair value Level III valuation techniques used. In
some instances, a difference may arise between the fair value of a financial instrument at initial recognition (the “transaction
price”) and the amount calculated through a valuation model. This unrealized gain or loss at inception is recognized in net
earnings (loss) only if the fair value of the instrument is evidenced by a quoted market price in an active market, observable
current market transactions that are substantially the same, or a valuation technique that uses observable market inputs.
Where these criteria are not met, the difference is deferred on the Consolidated Statements of Financial Position in risk
management assets or liabilities, and is recognized in net earnings (loss) over the term of the related contract. The difference
between the transaction price and the fair value determined using a valuation model, yet to be recognized in net earnings, and
a reconciliation of changes is as follows:
As at Dec. 31
Unamortized net gain at beginning of year
New inception gains
Change in foreign exchange rates
Amortization recorded in net earnings during the year
Unamortized net gain at end of year
2015
188
28
28
(42)
202
2014
160
23
14
(9)
188
2013
5
156
-
(1)
160
F48
F48 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
14. Risk Management Activities
A. Net Risk Management Assets and Liabilities
Aggregate net risk management assets and (liabilities) are as follows:
As at Dec. 31, 2015
Commodity risk management
Current
Long-term
Net commodity risk
management assets
Other
Current
Long-term
Net other risk management
assets (liabilities)
Total net risk management
assets (liabilities)
As at Dec. 31, 2014
Net
investment
hedges
Cash flow
hedges
Fair value
hedges
Not
designated
as a hedge
-
-
-
(7)
-
(7)
31
551
582
20
207
227
(7)
809
-
-
-
-
5
5
5
19
826
Net
investment
hedges
Cash flow
hedges
Fair value
hedges
Not
designated
as a hedge
Commodity risk management
Current
Long-term
Net commodity risk management assets
Other
Current
Long-term
Net other risk management assets (liabilities)
Total net risk management assets
-
-
-
-
-
-
-
(2)
257
255
56
55
111
366
-
-
-
-
6
6
6
Additional information on derivative instruments has been presented on a net basis below.
Total
88
524
612
10
204
214
Total
91
247
338
54
61
115
57
(27)
30
(3)
(8)
(11)
93
(10)
83
(2)
-
(2)
81
453
F49
TRANSALTA CORPORATION F49
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
I. Netting Arrangements
Information about the Corporation’s financial assets and liabilities that are subject to enforceable master netting
arrangements or similar agreements is as follows:
As at Dec. 31
Gross amounts recognized
Gross amounts set-off
Net amounts as presented in
the Consolidated Statements
of Financial Position
Current
financial
assets
534
(105)
2015
Long-term
financial
assets
1,048
(12)
Current
financial
liabilities
(350)
105
Long-term
financial
liabilities
(93)
12
Current
financial
assets
578
(204)
2014
Long-term
financial
assets
608
(10)
Current
financial
liabilities
(380)
204
Long-term
financial
liabilities
(98)
10
429
1,036
(245)
(81)
374
598
(176)
(88)
II. Hedges
a. Net Investment Hedges
The Corporation’s hedges of its net investment in foreign operations are comprised of U.S.-dollar-denominated long-term
debt with a face value of US$580 million (2014 - US$580 million) and the following foreign currency forward contracts:
As at Dec. 31
Notional
amount
sold
Notional
amount
purchased
Foreign Currencz Forxare Contracts
2015
Fair
value
liability
2014
Notional
amount
sold
Notional
amount
purchased
Fair
value
liability
Maturity
Maturity
AUD297
USD76
CAD293
CAD104
(6)
(1)
2016
2016
AUD235
CAD221
-
-
-
-
2015
-
During 2014, following the divestiture of CE Gen (see Note 4), the Corporation de-designated US$180 million of
US-denominated debt from its net investment hedge of U.S. operations. Reclassification from AOCI of the cumulative
translation adjustment of the disposed foreign operation and the related cumulative net investment hedge amounts have been
included in the gain on disposition. In 2014, the Corporation also de-designated an additional US$90 million of US-dollar-
denominated debt from its net investment hedge of other U.S. operations. This change did not impact earnings or AOCI in the
period. Prospectively, the de-designated tranches of US-dollar-denominated debt are being hedged with foreign currency
derivative instruments.
b. Cash Flow Hedges
i. Commodity Risk Management
The Corporation’s outstanding commodity derivative instruments designated as hedging instruments are as follows:
As at Dec. 31
Type
(thousands)
Electricity (MWh)
Natural gas (GJ)
Diesel (gammons)
2015
Notional
amount
sold
7,006
-
-
Notional
amount
purchased
-
22,485
-
2014
Notional
amount
sold
Notional
amount
purchased
4,977
963
-
-
32,113
6,720
During 2015, net unrealized pre-tax losses of $6 million (2014 - $3 million, 2013 - $1 million) were released from AOCI and
recognized in earnings due to hedge de-designations for accounting purposes. All designated hedging relationships are
effective as of Dec. 31, 2015.
F50
F50 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
During 2015, additional unrealized pre-tax gains of $3 million (2014 - $2 million, 2013 - nil) related to certain power hedging
relationships that were previously de-designated and deemed ineffective for accounting purposes were released from AOCI
and recognized in net earnings. The cash flow hedges were in respect of future power production expected to occur between
2012 and 2017. In the first quarter of 2011, the production was assessed as highly probable not to occur based on then
forecast prices. These unrealized gains were calculated using then current forward prices that changed between then and the
time the contracts settled. Had these hedges not been deemed ineffective for accounting purposes, the revenues associated
with these contracts would have been recorded in net earnings when settled, the majority of which occurred during 2012;
however, the expected cash flows from these contracts would not change.
As at Dec. 31, 2015, cumulative gains of $4 million (2014 - $3 million) related to certain cash flow hedges that were previously
de-designated and no longer meet the criteria for hedge accounting continue to be deferred in AOCI and will be reclassified to
net earnings as the forecasted transactions occur or immediately if the forecasted transactions are no longer expected to
occur.
ii. Foreign Currency Rate Risk Management
The Corporation uses foreign exchange forward contracts to hedge a portion of its future foreign-denominated receipts and
expenditures, and both foreign exchange forward contracts and cross-currency swaps to manage foreign exchange exposure
on foreign-denominated debt not designated as a net investment hedge.
As at Dec. 31
Notional
amount
sold
Notional
amount
purchased
2015
Fair value
asset
Maturity
2014
Notional
amount
sold
Notional
amount
purchased
Fair value
asset
(liability)
Foreign Exchange Forxare Contracts ) foreign)eenoninatee receiqts/exqeneitures
CAD138
AUD19
USD126
JPY1,683
36
1
2016-2018
CAD194
2016-2017
AUD49
USD180
JPY4,522
Foreign Exchange Forxare Contracts ) foreign)eenoninatee eebt
CAD95
USD70
Cross)Currencz Sxaqs ) foreign)eenoninatee eebt
-
CAD434
CAD306
-
USD400
USD270
2
-
116
72
2016-2018
CAD59
USD50
-
2017
2018
CAD530
CAD434
CAD192
USD500
USD400
USD180
16
(1)
-
50
28
18
Maturity
2015-2018
2015-2017
2015
2015
2017
2018
F51
TRANSALTA CORPORATION F51
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
iii. Effect of Cash Flow Hedges
The following tables summarize the pre-tax amounts recognized in and reclassified out of OCI related to cash flow hedges:
Year ended Dec. 31, 2015
Effective portion
Ineffective portion
Derivatives in cash
flow hedging
relationships
Pre-tax
gain (loss)
recognized in OCI
Location of (gain) loss
reclassified
from OCI
Pre-tax (gain) loss
reclassified
from OCI
Location of (gain) loss
reclassified
from OCI
Pre-tax
(gain) loss
recognized in
earnings
Commodity contracts
308
Revenue
Fuel and purchased
power
Foreign exchange forwards
on commodity contracts
Foreign exchange forwards
on project hedges
Foreign exchange forwards
on U.S. debt
Cross-currency
swaps
Forward starting interest
rate swaps
OCI impact
32
Revenue
Property, plant,
and equipment
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
4
10
163
-
Interest expense
517
OCI impact
(110)
Revenue
Fuel and purchased
power
41
(12)
Revenue
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
(1)
(12)
(163)
7
Interest expense
(250)
Net earnings impact
5
-
-
-
-
-
-
5
Year ended Dec. 31, 2014
Effective portion
Ineffective portion
Derivatives in cash
flow hedging
relationships
Pre-tax
gain (loss)
recognized in OCI
Location of (gain) loss
reclassified
from OCI
Pre-tax (gain) loss
reclassified
from OCI
Location of (gain) loss
reclassified
from OCI
Pre-tax
(gain) loss
recognized in earnings
Commodity contracts
Foreign exchange forwards
on commodity contracts
Foreign exchange forwards
on project hedges
Foreign exchange forwards
on U.S. debt
Cross-currency
swaps
Forward starting interest
rate swaps
OCI impact
Revenue
Fuel and purchased
power
212
14
Revenue
Property, plant,
and equipment
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
(1)
(9)
89
-
Interest expense
305
OCI impact
24
Revenue
Fuel and purchased
power
14
(1)
Revenue
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
-
6
(94)
6
Interest expense
(45)
Net earnings impact
(3)
-
-
-
-
-
-
(3)
F52
F52 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
Year ended Dec. 31, 2013
Effective portion
Ineffective portion
Derivatives in cash
flow hedging
relationships
Pre-tax
gain (loss)
recognized in OCI
Location of (gain) loss
reclassified
from OCI
Pre-tax (gain) loss
reclassified
from OCI
Location of (gain) loss
reclassified
from OCI
Pre-tax
(gain) loss
recognized in earnings
Commodity contracts
11
Revenue
Fuel and purchased
power
Foreign exchange forwards
on commodity contracts
Foreign exchange forwards
on project hedges
Foreign exchange forwards
on U.S. debt
Cross-currency
swaps
Forward starting interest
rate swaps
OCI impact
11
-
33
33
-
88
Revenue
Property, plant,
and equipment
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
Interest expense
OCI impact
17
Revenue
Fuel and purchased
power
Revenue
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
19
2
2
(38)
(29)
6
Interest expense
(21)
Net earnings impact
(2)
-
-
-
-
-
-
(2)
Over the next 12 months, the Corporation estimates that $38 million of after-tax gains will be reclassified from AOCI to net
earnings. These estimates assume constant natural gas and power prices, interest rates, and exchange rates over time;
however, the actual amounts that will be reclassified may vary based on changes in these factors.
c. Fair Value Hedges
i. Interest Rate Risk Management
The Corporation has converted a portion of its fixed interest rate debt with a rate of 6.65 per cent (2014 - 6.65 per cent) to a
floating interest rate based on the U.S. LIBOR rate using interest rate swaps as outlined below:
As at Dec. 31
Notional
amount
USD50
2015
Fair
value
asset
5
Maturity
2018
2014
Fair
value
asset
6
Notional
amount
USD50
Maturity
2018
Including interest rate swaps, 9 per cent of the Corporation’s debt as at Dec. 31, 2015 is subject to floating interest rates
(2014 - 4 per cent).
ii. Effects of Fair Value Hedges
The following table summarizes the pre-tax impact on the Consolidated Statements of Earnings (Loss) of fair value hedges,
including any ineffective portion:
Year ended Dec. 31
Derivatives in fair value
hedging relationships
Interest rate contracts
Long-term debt
Earnings (loss) impact
Location of gain (loss)
recognized in earnings
Net interest expense
Net interest expense
2015
2014
2013
(1)
1
-
(1)
1
-
(2)
2
-
F53
TRANSALTA CORPORATION F53
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
III. Non-Hedges
The Corporation enters into various derivative transactions as well as other contracting activities that do not qualify for hedge
accounting or where a choice was made not to apply hedge accounting. As a result, the related assets and liabilities are
classified as held for trading. The net realized and unrealized gains or losses from changes in the fair value of these derivatives
are reported in earnings in the period the change occurs.
a. Commodity Risk Management
As at Dec. 31
Type
(thousands)
Electricity (MWh)
Natural gas (GJ)
Transmission (MWh)
Emissions (tonnes)
b. Other Non-Hedge Derivatives
2015
2014
Notional
amount
sold
42,975
106,203
-
960
Notional
amount
purchased
38,565
101,100
5,014
960
Notional
amount
sold
30,821
156,898
-
50
Notional
amount
purchased
23,685
198,969
3,904
75
As at Dec. 31
Notional
amount
sold
Notional
amount
purchased
2015
Fair value
asset
(liability)
Maturity
2014
Notional
amount
sold
Notional
amount
purchased
Fair value
asset
(liability)
Foreign Exchange Forxare Contracts
USD41
AUD89
AUD5
CAD54
CAD79
USD4
-
Deriwatiwes enbeeeee in suqqmier contracts (1)
-
USD4
-
AUD5
-
(3)
(8)
1
-
(1)
-
2016-2018
CAD264
USD227
2016-2020
2016
-
2016
-
AUD63
AUD47
AUD10
USD40
EUR7
CAD61
USD40
EUR7
AUD47
AUD10
1
1
3
-
(7)
-
(1) Resumt fron qaznents that are not eenoninatee in the functionam currencz of either qartz uneer a contract xith a suqqmier.
Maturity
2015
2015
2015-2016
2015
2015-2016
2015
c. Total Return Swaps
The Corporation has certain compensation, deferred, and restricted share unit programs, the values of which depend on the
common share price of the Corporation. The Corporation has fixed a portion of the settlement cost of these programs by
entering into a total return swap for which hedge accounting has not been applied. The total return swap is cash settled every
quarter based upon the difference between the fixed price and the market price of the Corporation’s common shares at the
end of each quarter.
d. Effect of Non-Hedges
For the year ended Dec. 31, 2015, the Corporation recognized a net unrealized loss of $51 million (2014 - gain of $54 million,
2013 - loss of $40 million) related to commodity derivatives.
For the year ended Dec. 31, 2015, a loss of $1 million (2014 - gain of $10 million, 2013 - gain of $8 million) related to foreign
exchange and other derivatives was recognized and is comprised of a net unrealized losses of $11 million (2014 - gain of
$2 million, 2013 - loss of $1 million) and net realized gains of $10 million (2013 - gain of $8 million, 2013 - gain of $9 million).
F54
F54 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
B. Nature and Extent of Risks Arising from Financial Instruments
The following discussion is limited to the nature and extent of certain risks arising from financial instruments.
I. Market Risk
a. Commodity Price Risk
The Corporation has exposure to movements in certain commodity prices in both its electricity generation and proprietary
trading businesses, including the market price of electricity and fuels used to produce electricity. Most of the Corporation’s
electricity generation and related fuel supply contracts are considered to be contracts for delivery or receipt of a non-financial
item in accordance with the Corporation’s expected own use requirements and are not considered to be financial instruments.
As such, the discussion related to commodity price risk is limited to the Corporation’s proprietary trading business and
commodity derivatives used in hedging relationships associated with the Corporation’s electricity generating activities.
i. Commodity Price Risk – Proprietary Trading
The Corporation’s Energy Marketing Segment conducts proprietary trading activities and uses a variety of instruments to
manage risk, earn trading revenue, and gain market information.
In compliance with the Policy, proprietary trading activities are subject to limits and controls, including Value at Risk (“VaR”)
limits. The Board approves the limit for total VaR from proprietary trading activities. VaR is the most commonly used metric
employed to track and manage the market risk associated with trading positions. A VaR measure gives, for a specific
confidence level, an estimated maximum pre-tax loss that could be incurred over a specified period of time. VaR is used to
determine the potential change in value of the Corporation’s proprietary trading portfolio, over a three-day period within a
95 per cent confidence
is estimated using the historical
variance/covariance approach.
level, resulting from normal market fluctuations. VaR
VaR is a measure that has certain inherent limitations. The use of historical information in the estimate assumes that price
movements in the past will be indicative of future market risk. As such, it may only be meaningful under normal market
conditions. Extreme market events are not addressed by this risk measure. In addition, the use of a three-day measurement
period implies that positions can be unwound or hedged within three days, although this may not be possible if the market
becomes illiquid.
The Corporation recognizes the limitations of VaR and actively uses other controls, including restrictions on authorized
instruments, volumetric and term limits, stress-testing of individual portfolios and of the total proprietary trading portfolio,
and management reviews when loss limits are triggered.
Changes in market prices associated with proprietary trading activities affect net earnings in the period that the price changes
occur. VaR at Dec. 31, 2015 associated with the Corporation’s proprietary trading activities was $5 million (2014 - $5 million,
2013 - $2 million).
F55
TRANSALTA CORPORATION F55
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
ii. Commodity Price Risk - Generation
The generation segments utilize various commodity contracts to manage the commodity price risk associated with electricity
generation, fuel purchases, emissions, and by-products, as considered appropriate. A Commodity Exposure Management
Policy is prepared and approved annually, which outlines the intended hedging strategies associated with the Corporation’s
generation assets and related commodity price risks. Controls also include restrictions on authorized instruments,
management reviews on individual portfolios, and approval of asset transactions that could add potential volatility to the
Corporation’s reported net earnings.
TransAlta has entered into various contracts with other parties whereby the other parties have agreed to pay a fixed price for
electricity to TransAlta. While not all of the contracts create an obligation for the physical delivery of electricity to other
parties, the Corporation has the intention and believes it has sufficient electrical generation available to satisfy these
contracts and, where able, has designated these as cash flow hedges for accounting purposes.
As a result, changes in market prices associated with these cash flow hedges do not affect net earnings in the period in which
the price change occurs. Instead, changes in fair value are deferred until settlement through AOCI, at which time the net gain
or loss resulting from the combination of the hedging instrument and hedged item affects net earnings.
VaR at Dec. 31, 2015 associated with the Corporation’s commodity derivative instruments used in generation hedging
activities was $24 million (2014 - $27 million, 2013 - $42 million).
On asset-backed physical transactions, the Corporation’s policy is to seek own use contract status or hedge accounting
treatment. For positions and economic hedges that do not meet hedge accounting requirements or for short-term
optimization transactions such as buybacks entered into to offset existing hedge positions, these transactions are marked to
the market value with changes in market prices associated with these transactions affecting net earnings in the period in
which the price change occurs. VaR at Dec. 31, 2015 associated with these transactions was $1 million (2014 - $7 million,
2013 - $11 million).
b. Interest Rate Risk
Interest rate risk arises as the fair value or future cash flows of a financial instrument can fluctuate because of changes in
market interest rates. Changes in interest rates can impact the Corporation’s borrowing costs and the capacity payments
received under the PPAs. Changes in the cost of capital may also affect the feasibility of new growth initiatives.
The possible effect on net earnings and OCI due to changes in market interest rates affecting the Corporation’s floating rate
debt, interest-bearing assets, financial instruments measured at fair value through profit or loss, and hedging interest rate
derivatives, is outlined below. The sensitivity analysis has been prepared using management’s assessment that a 15 basis
point (2014 - 15 basis point, 2013 - 25 basis point) increase or decrease is a reasonable potential change over the next quarter
in market interest rates.
Year ended Dec. 31
Basis point change
2015
Net earnings
increase(1)
1
OCI loss(1)
-
2014
Net earnings
increase(1)
-
OCI loss(1)
-
2013
Net earnings
increase(1)
OCI loss(1)
2
-
(1)This camcumation assunes a eecrease in narlet interest rates. An increase xoume hawe the oqqosite effect.
F56
F56 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
c. Currency Rate Risk
The Corporation has exposure to various currencies, such as the euro, the U.S. dollar, the Japanese yen, and the Australian
dollar (“AUD”), as a result of investments and operations in foreign jurisdictions, the net earnings from those operations, and
the acquisition of equipment and services from foreign suppliers.
As part of the Transaction described in Note 4, the Corporation has entered into foreign exchange hedging contracts with
TransAlta Renewables to mitigate the risks to TransAlta Renewables shareholders of adverse changes in AUD in respect of
AUD$326 million remaining investments to fund the South Hedland project. In addition, the Corporation has agreed to
mitigate the risks to TransAlta Renewables shareholders of adverse changes in USD and AUD in respect of cash flows from
the Australian assets in relation to the Canadian dollar for the first five years from the time of the Transaction. The financial
effects of these contracts and agreements eliminate on consolidation.
In order to mitigate some of the risk that is attributable to non-controlling interests, the Corporation has entered into foreign
currency hedges with third parties to the extent of the non-controlling interest percentage of the expected cash flow over five
years. Hedge accounting is not applied to these foreign currency hedges and accordingly the gain on the contracts, recognized
as a foreign exchange loss, was $8 million for the year ended Dec. 31, 2015.
The foreign currency risk sensitivities outlined below are limited to the risks that arise on financial instruments denominated
in currencies other than the functional currency.
The possible effect on net earnings and OCI, due to changes in foreign exchange rates associated with financial instruments
denominated in currencies other than the Corporation’s functional currency, is outlined below. The sensitivity analysis has
been prepared using management’s assessment that an average four cent (2014 - four cent, 2013 - five cent) increase or
decrease in these currencies relative to the Canadian dollar is a reasonable potential change over the next quarter.
Year ended Dec. 31
2015
2014
2013
Currency
USD
AUD
Total
Net earnings
increase
(decrease)(1)
2
(3)
(1)
OCI gain(1), (2)
5
-
5
Net earnings
increase(1)
4
(2)
2
OCI gain(1), (2)
5
Net earnings
decrease(1)
2
-
5
-
2
OCI gain(1), (2)
8
-
8
(1) These camcumations assune an increase in the wamue of these currencies rematiwe to the Canaeian eommar. A eecrease xoume hawe the oqqosite effect.
(2) The foreign exchange inqact rematee to financiam instrunents eesignatee as heeging instrunents in net inwestnent heeges has been excmueee.
F57
TRANSALTA CORPORATION F57
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
II. Credit Risk
Credit risk is the risk that customers or counterparties will cause a financial loss for the Corporation by failing to discharge
their obligations, and the risk to the Corporation associated with changes in creditworthiness of entities with which
commercial exposures exist. The Corporation actively manages its exposure to credit risk by assessing the ability of
counterparties to fulfill their obligations under the related contracts prior to entering into such contracts. The Corporation
makes detailed assessments of the credit quality of all counterparties and, where appropriate, obtains corporate guarantees,
cash collateral, and/or letters of credit to support the ultimate collection of these receivables. For commodity trading and
origination, the Corporation sets strict credit limits for each counterparty and monitors exposures on a daily basis. TransAlta
uses standard agreements that allow for the netting of exposures and often include margining provisions. If credit limits are
exceeded, TransAlta will request collateral from the counterparty or halt trading activities with the counterparty. TransAlta is
exposed to minimal credit risk for Alberta Coal PPAs as receivables are substantially all secured by letters of credit.
The Corporation uses external credit ratings, as well as internal ratings in circumstances where external ratings are not
available, to establish credit limits for customers and counterparties. In certain cases, the Corporation will require security
instruments such as parental guarantees, letters of credit, cash collateral or third party credit insurance to reduce overall
credit risk. The following table outlines the Corporation’s maximum exposure to credit risk without taking into account
collateral held or right of set-off, including the distribution of credit ratings, as at Dec. 31, 2015:
Trade and other receivables(1)
Long-term finance lease receivables(2)
Risk management assets(1)
Total
Investment grade
(Per cent)
Non-investment grade
(Per cent)
Total
(Per cent)
90
39
100
10
61
-
100
100
100
Total
Amount
567
775
1,095
2,437
(1) Letters of creeit ane cash are the qrinarz tzqes of commateram heme as securitz rematee to these anounts.
(2) Incmuees bamance of $446 nimmion attributabme to one)non)inwestnent graee custoner. Risl of significant moss arising fron this counterqartz has
been assessee as mox in the near)tern but coume increase to noeerate in an enwironnent of sustainee mox connoeitz qrices ower the nie to mong)tern.
The assessnent tales into consieeration the counterqartz's financiam qosition, externam rating asessnents, ane hox serwices are qrowieee in an area of
the counterqartz's moxer)cost oqerations, ane TransAmta's other creeit risl nanagenent qractices.
The Corporation’s maximum exposure to credit risk at Dec. 31, 2015, without taking into account collateral held or right of set-
off, is represented by the current carrying amounts of receivable and risk management assets as per the Consolidated
Statements of Financial Position. Letters of credit and cash are the primary types of collateral held as security related to these
amounts. The maximum credit exposure to any one customer for commodity trading operations and hedging, including the
fair value of open trading, net of any collateral held, at Dec. 31, 2015 was $44 million (2014 - $29 million).
F58
F58 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
III. Liquidity Risk
Liquidity risk relates to the Corporation’s ability to access capital to be used for proprietary trading activities, commodity
hedging, capital projects, debt refinancing, and general corporate purposes. In December 2015, Moody’s downgraded the
senior unsecured rating on TransAlta’s US bonds one notch from Baa3 to Ba1. As at Dec. 31, 2015 TransAlta maintains
investment grade ratings with stable outlooks from three credit rating agencies, including BBB- by Standard & Poor’s, BBB by
DBRS, and BBB- by Fitch Ratings. TransAlta is focused on strengthening its financial position and maintaining investment
grade credit ratings with these major rating agencies.
Counterparties enter into certain commodity agreements, such as electricity and natural gas purchase and sale contracts, for
the purposes of asset-backed sales and proprietary trading. The terms and conditions of these agreements may contain
credit-contingent features (such as downgrades in creditworthiness), which if triggered may result in the Corporation having
to post collateral to its counterparties.
TransAlta manages liquidity risk by monitoring liquidity on trading positions; preparing and revising longer-term financing
plans to reflect changes in business plans and the market availability of capital; and reporting liquidity risk exposure for
proprietary trading activities on a regular basis to the Risk Management Committee, senior management, and the Board.
A maturity analysis of the Corporation’s financial liabilities is as follows:
Accounts payable and accrued liabilities
Long-term debt(1)
Commodity risk management (assets) liabilities
Other risk management (assets) liabilities
Finance lease obligations
Interest on long-term debt and finance lease obligations(2)
Dividends payable
Total
2016
2017
2018
2019
2020
334
72
(65)
(10)
15
225
63
634
-
604
(60)
(126)
14
216
-
-
947
(40)
(83)
12
171
-
648
1,007
-
761
(62)
4
8
138
-
849
-
447
(66)
1
7
106
-
495
2021 and
thereafter
-
Total
334
1,596
4,427
(319)
-
26
(612)
(214)
82
796
1,652
-
63
2,099
5,732
(1) Excmuees inqact of heege accounting ane incmuees eraxn creeit facimities that are currentmz scheeumee to nature in 2919.
(2) Not recognizee as a financiam miabimitz on the Consomieatee Statenents of Financiam Position.
F59
TRANSALTA CORPORATION F59
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
C. Collateral
I. Financial Assets Provided as Collateral
At Dec. 31, 2015, the Corporation provided $74 million (2014 - $25 million) in cash as collateral to regulated clearing agents
as security for commodity trading activities. These funds are held in segregated accounts by the clearing agents.
II. Financial Assets Held as Collateral
At Dec. 31, 2015, the Corporation received $15 million (2014 - nil) in cash collateral associated with counterparty obligations.
Under the terms of the contracts, the Corporation may be obligated to pay interest on the outstanding balances and to return
the principal when the counterparties have met their contractual obligations, or when the amount of the obligation declines as
a result of changes in market value. Interest payable to the counterparties on the collateral received is calculated in
accordance with each contract.
II. Contingent Features in Derivative Instruments
Collateral is posted in the normal course of business based on the Corporation’s senior unsecured credit rating as determined
by certain major credit rating agencies. Certain of the Corporation’s derivative instruments contain financial assurance
provisions that require collateral to be posted only if a material adverse credit-related event occurs. If a material adverse event
resulted in the Corporation’s senior unsecured debt falling below investment grade, the counterparties to such derivative
instruments could request ongoing full collateralization.
As at Dec. 31, 2015, the Corporation had posted collateral of $220 million (Dec. 31, 2014 - $73 million) in the form of letters of
credit on derivative instruments in a net liability position. Certain derivative agreements contain credit-risk-contingent
features, which if triggered could result in the Corporation having to post an additional $44 million (Dec. 31, 2014 -
$86 million) of collateral to its counterparties.
F60
F60 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
15. Inventory
Inventory held in the normal course of business, which includes coal, emission credits, parts and materials, and natural gas, is
valued at the lower of cost and net realizable value. Inventory held for Energy Marketing, which includes natural gas and
emission credits and allowances, is valued at fair value less costs to sell.
The components of inventory are as follows:
As at Dec. 31
Parts and materials
Coal
Deferred stripping costs
Natural gas
Purchased emission credits
Total
* See Note 3A(III) for qrior qerioe restatenents.
The change in inventory is as follows:
Balance, Dec. 31, 2013
Net additions
Writedowns
Change in foreign exchange rates
Previously reported balance, Dec. 31, 2014
Transfer of parts and materials (Note 3A(III))
Restated balance, Dec. 31, 2014
Net additions
Acquisition (Note 4)
Writedowns
Change in foreign exchange rates
Balance, Dec. 31, 2015
No inventory is pledged as security for liabilities.
2015
2014
(Restatee)*
116
56
14
8
25
219
125
39
15
12
5
196
77
14
(19)
(1)
71
125
196
47
10
(22)
(12)
219
F61
TRANSALTA CORPORATION F61
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
16. Property, Plant, and Equipment
A reconciliation of the changes in the carrying amount of PP&E is as follows:
Coal
Land
generation Gas generation
Renewable
generation
Mining property
and equipment
Assets under
construction
Capital spares
and other(1)
77
5,644
1,858
2,857
1,066
153
466
369
18
Cost
As at Dec. 31, 2013
Additions
Additions - finance lease
Disposals
Impairment charges (Note 6)
Impairment reversals (Note 6)
Revisions and additions to
decommissioning and restoration
costs
Retirement of assets
Change in foreign exchange rates
Transfers
Previously reported balance, Dec. 31, 2014
Transfer of parts and materials (Note 3)
Restated balance, Dec. 31, 2014
Additions
Acquisitions (Note 4)
Additions - finance lease
Disposals
Disposals - Poplar Creek (Note 4)
Impairment reversals (Note 6)
Revisions and additions to
decommissioning and restoration
costs
Retirement of assets
Change in foreign exchange rates
Transfers
As at Dec. 31, 2015
Accumulated depreciation
As at Dec. 31, 2013
Depreciation
Retirement of assets
Disposals
Change in foreign exchange rates
Impairment reversals (Note 6)
Transfers
As at Dec. 31, 2014
Depreciation
Retirement of assets
Disposals
Disposals - Poplar Creek (Note 4)
Change in foreign exchange rates
Transfers
As at Dec. 31, 2015
Carrying amount
As at Dec. 31, 2013
As at Dec. 31, 2014
As at Dec. 31, 2015
-
-
-
-
-
-
-
2
3
82
-
82
1
-
-
(2)
-
-
-
-
3
11
95
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
77
82
95
3
-
-
-
-
11
(96)
92
149
5,803
5,803
-
-
-
-
-
-
(42)
(106)
220
216
6,091
2,692
272
(84)
-
61
-
-
2,941
279
(96)
-
155
1
3,280
2,952
2,862
2,811
-
-
(34)
-
9
4
(20)
4
48
1,869
-
1,869
3
-
-
(13)
(429)
2
(10)
(19)
33
48
-
-
(1)
(2)
2
(1)
(4)
7
24
2,882
-
2,882
-
321
-
-
-
-
(21)
(18)
27
74
-
58
-
-
-
10
(4)
4
25
1,159
-
1,159
-
-
13
-
-
-
(13)
(11)
18
42
1,484
3,265
1,208
615
98
(1)
-
1
-
-
713
107
(12)
-
2
-
488
55
(2)
-
3
-
-
544
60
(7)
-
7
-
810
604
946
103
(19)
(29)
4
3
(15)
993
85
(15)
(8)
(202)
21
(1)
873
912
876
611
-
1
-
-
-
-
(6)
(273)
341
-
341
474
-
-
-
-
-
-
-
16
(480)
351
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Total
12,024
487
58
(34)
(2)
11
24
(124)
106
(18)
12,532
(125)
12,407
476
321
13
(15)
(436)
2
(86)
(158)
325
5
12,854
4,831
541
(106)
(29)
69
3
(15)
5,294
545
(134)
(8)
(202)
186
-
5,681
7,193
7,113
7,173
-
-
-
-
-
-
3
6
396
(125)
271
(2)
-
-
-
(7)
-
-
(4)
8
94
360
90
13
-
-
-
-
-
103
14
(4)
-
-
1
-
114
279
168
246
2,242
2,169
2,455
578
615
604
153
341
351
(1) Incmuees nakor sqare qarts ane stane)bz eruiqnent awaimabme, but not in serwice, ane sqare qarts usee for routine, qrewentatiwe, or qmannee naintenance.
The Corporation capitalized $9 million of interest to PP&E in 2015 (2014 - $3 million) at a weighted average rate of 5.83
per cent (2014 - 5.75 per cent).
F62
F62 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
In 2014, operations began at a processing facility that the Corporation contracted a third party to construct and operate. The
facility recovers fine coal out of pond slurry at the Corporation’s Centralia mine as part of restoration activities. Recovered coal
fines can be used as fuel at the coal plant. As a result of certain contractual provisions, the Corporation recognized a finance lease
asset and an obligation in the amount of estimated minimum lease payments of US$34 million, corresponding at inception to the
penalties payable by the Corporation if it elects to terminate the agreement. Coal volume and slurry processing payments, net of
the amortization and accretion of the financial lease obligation, are deemed to constitute contingent rents under the
arrangement. Other finance lease additions in 2015 and 2014 are for mining equipment at the Highvale mine. The carrying
amount of total assets under finance leases as at Dec. 31, 2015 was $81 million (2014 - $78 million).
17. Goodwill
As a result of the re-segmentation described in Note 3, the Corporation re-allocated goodwill on a relative fair value basis. The
Corporation allocated goodwill of the previous Canadian Renewables and Alberta Merchant group of CGUs to the Hydro and
Wind and Solar segments and the previous U.S. Operations goodwill to the Wind and Solar Segment on the basis of
management’s allocations for monitoring and performance measurement purposes. There were no changes made to the
Energy Marketing goodwill.
As at Dec. 31
Groups of CGUs
Canadian Renewables and Alberta Merchant
U.S. Operations
Energy Marketing
Total goodwill
2014
Previously
recorded
goodwill
417
15
30
462
2015
Segment
Re-allocated
Goodwill
Hydro
259
Wind and Solar
176
Energy Marketing
30
465
For purposes of the 2015 and 2014 annual goodwill impairment review, the Corporation determined the recoverable amounts
of the test units by calculating the fair value less costs of disposal using discounted cash flow projections based on the
Corporation’s long-range forecasts for the period extending to the last planned asset retirement in 2073. The resulting fair
value measurement is categorized within Level III of the fair value hierarchy.
The key assumption impacting the determination of fair value for the wind and hydro segments (2014 - Canadian Renewables
and Alberta Merchant CGUs) are electricity production and sales prices. Forecasts of electricity production for each facility
are determined taking into consideration contracts for the sale of electricity, historical production, regional supply-demand
balances, and capital maintenance and expansion plans. Forecasted sales prices for each facility are determined by taking into
consideration contract prices for facilities subject to long- or short-term contracts, forward price curves for merchant plants,
and regional supply-demand balances. Where forward price curves are not available for the duration of the facility’s useful life,
prices are determined by extrapolation techniques using historical industry and company-specific data. Electricity prices used
in these 2015 models ranged between $26 to $311 per MWh during the forecast period (2014 - $31 to $276 per MWh).
Discount rates used for the goodwill impairment calculation in 2015 ranged from 5.3 per cent to 6.5 per cent (2014 –
5.4 per cent to 6.9 per cent). No reasonable possible change in the assumptions would have resulted in an impairment of
goodwill.
F63
TRANSALTA CORPORATION F63
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
18. Intangible Assets
A reconciliation of the changes in the carrying amount of intangible assets is as follows:
Coal rights
Software
and other
Power
sale
contracts
Intangibles
under
development
178
180
186
-
-
-
-
8
(3)
3
18
178
206
-
-
-
-
-
178
104
2
-
-
106
3
-
-
109
74
72
69
1
-
(1)
8
42
256
104
21
(3)
2
124
20
3
(5)
142
76
82
114
-
-
-
-
186
-
37
-
-
-
223
35
8
-
-
43
9
-
-
52
151
143
171
22
26
-
-
(14)
34
25
-
-
-
(44)
15
-
-
-
-
-
-
-
-
-
22
34
15
Cost
As at Dec. 31, 2013
Additions
Retirements
Change in foreign exchange rates
Transfers
As at Dec. 31, 2014
Additions
Acquisitions (Note 4)
Retirements
Change in foreign exchange rates
Transfers
As at Dec. 31, 2015
Accumulated amortization
As at Dec. 31, 2013
Amortization
Retirements
Change in foreign exchange rates
As at Dec. 31, 2014
Amortization
Change in foreign exchange rates
Transfers
As at Dec. 31, 2015
Carrying amount
As at Dec. 31, 2013
As at Dec. 31, 2014
As at Dec. 31, 2015
F64
F64 TRANSALTA CORPORATION
Total
566
34
(3)
3
4
604
26
37
(1)
8
(2)
672
243
31
(3)
2
273
32
3
(5)
303
323
331
369
TransAlta Corporation | 2015 Annual Integrated Report
19. Other Assets
The components of other assets are as follows:
As at Dec. 31
Deferred licence fees
Project development costs
Deferred service costs
Long-term prepaids, receivables, and other
Keephills Unit 3 transmission deposit
Total other assets
Notes to Consolidated Financial Statements
2015
2014
16
42
17
52
6
133
16
29
18
29
6
98
Deferred license fees consist primarily of licenses to lease the land on which certain generating assets are located, and are
amortized on a straight-line basis over the useful life of the generating assets to which the licenses relate.
Project development costs are primarily comprised of the Corporation’s Sundance 7 and Dunvegan projects in Alberta. In
December 2015, the Corporation repurchased its partner’s 50 per cent share in TAMA Power, the jointly controlled entity
developing the Sundance 7 project, for consideration of $10 million, payable in five years and an option for its partner to re-
enter the development projects of TAMA Power at accumulated cost during this period.
Deferred service costs are TransAlta's contracted payments for shared capital projects required at the Genesee Unit 3 and
Keephills Unit 3 sites. These costs are amortized over the life of these projects.
Long-term prepaids, receivables, and other assets include the funded portion of the TransAlta Energy Bill commitments
presented in Note 32.
The Keephills Unit 3 transmission deposit is TransAlta's proportionate share of a provincially required deposit. The full amount
of the deposit is anticipated to be reimbursed over the next six years to 2021, as long as certain performance criteria are met.
F65
TRANSALTA CORPORATION F65
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
20. Decommissioning and Other Provisions
The change in decommissioning and other provision balances is as follows:
Decommissioning and
restoration
270
3
(16)
18
-
24
-
6
305
6
7
(24)
(11)
20
1
(89)
-
18
233
Other
62
19
(31)
-
3
-
(2)
-
51
58
-
(14)
(1)
1
71
-
(2)
1
165
Total
332
22
(47)
18
3
24
(2)
6
356
64
7
(38)
(12)
21
72
(89)
(2)
19
398
Decommissioning and
restoration
Other
Total
305
28
277
233
30
203
51
6
45
165
136
29
356
34
322
398
166
232
Balance, Dec. 31, 2013
Liabilities incurred
Liabilities settled
Accretion
Revisions in estimated cash flows
Revisions in discount rates
Reversals
Change in foreign exchange rates
Balance, Dec. 31, 2014
Liabilities incurred
Liabilities acquired (Note 4)
Liabilities settled
Liabilities disposed (Note 4)
Accretion
Revisions in estimated cash flows (Note 4)
Revisions in discount rates
Reversals
Change in foreign exchange rates
Balance, Dec. 31, 2015
Balance, Dec. 31, 2014
Current portion
Non-current portion
Balance, Dec. 31, 2015
Current portion
Non-current portion
F66
F66 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
A. Decommissioning and Restoration
A provision has been recognized for all generating facilities and mines for which TransAlta is legally, or constructively, required
to remove the facilities at the end of their useful lives and restore the sites to their original condition. TransAlta estimates that
the undiscounted amount of cash flow required to settle these obligations is approximately $1.0 billion, which will be incurred
between 2016 and 2073. The majority of the costs will be incurred between 2020 and 2050. At Dec. 31, 2015, the
Corporation had provided a surety bond in the amount of US$139 million (2014 - US$140 million) in support of future
decommissioning obligations at the Centralia coal mine. At Dec. 31, 2015, the Corporation had provided letters of credit in the
amount of $115 million (2014 - $115 million) in support of future decommissioning obligations at the Alberta mine. Some of
the facilities that are co-located with mining operations do not currently have any decommissioning obligations recorded as
the obligations associated with the facilities are indeterminate at this time.
B. Other Provisions
Other provisions include amounts related to a portion of the Corporation’s fixed price commitments under several natural gas
transportation contracts for firm transportation that is not expected to be used and for vacant leased premises. Accordingly,
the unavoidable costs of meeting these obligations exceed the economic benefits expected to be received. The contracts
extend to 2023.
Other provisions also include provisions arising from ongoing business activities and include amounts related to commercial
disputes between the Corporation and customers or suppliers. Information about the expected timing of settlement and
uncertainties that could impact the amount or timing of settlement has not been provided as this may impact the
Corporation’s ability to settle the provisions in the most favourable manner. During 2015, the Corporation recorded a
significant adjustment to other provisions, as disclosed in Note 4.
F67
TRANSALTA CORPORATION F67
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
21. Credit Facilities, Long-Term Debt, and Finance Lease Obligations
A. Credit Facilities, Debt and Letters of Credit
The amounts outstanding are as follows:
As at Dec. 31
Credit facilities(2)
Debentures
Senior notes(3)
Non-recourse(4)
Other(5)
Finance lease obligations
Less: current portion of long-term debt
Less: current portion of finance lease obligations
Total current long-term debt and finance lease obligations
Total credit facilities, long-term debt,
and finance lease obligations
2015
Carrying
Face
value
value
Interest(1)
315
1,044
2,221
766
67
315
1,051
2,221
773
67
4,413
4,427
3.1%
6.0%
4.9%
4.5%
9.3%
Carrying
value
96
2014
Face
value
96
1,043
1,051
2,444
2,436
380
19
383
19
3,982
3,985
Interest(1)
2.8%
6.1%
4.9%
5.9%
5.9%
82
4,495
(72)
(15)
(87)
4,408
74
4,056
(738)
(13)
(751)
3,305
(1) Interest is an awerage rate xeightee bz qrinciqam anounts outstaneing before the effect of heeging.
(2) Conqosee of banlers' acceqtances ane other connerciam borroxings uneer mong)tern connittee creeit facimities.
(3) US face wamue at Dec. 31, 2915 ) US$1.6 bimmion (Dec. 31, 2914 ) US$2.1 bimmion).
(4) Incmuees US$59 nimmion at Dec. 31, 2915 (Dec. 31, 2914 ) US$29 nimmion).
(5) Incmuees US$36 nimmion at Dec. 31, 2915 (Dec. 31, 2914 ) nim) of tax eruitz financing.
Credit facilities are drawn on the Corporation’s $1.5 billion committed syndicated bank credit facility and on the Corporation’s
US$300 million committed bilateral facility. The $1.5 billion committed syndicated bank facility is the primary source for
short-term liquidity after the cash flow generated from the Corporation’s business. The Corporation’s four-year revolving
$1.5 billion committed syndicated credit facility, last renewed in June 2015, expires in 2019. The US$300 million bilateral
credit facility has a four-year term to 2017. Interest rates on the credit facilities vary depending on the option selected -
Canadian prime, bankers’ acceptances, U.S. LIBOR, or U.S. base rate - in accordance with a pricing grid that is standard for
such facilities. The Corporation also has $240 million available in committed bilateral credit facilities, which expire in 2017.
Of the $2.2 billion (2014 - $2.1 billion) of committed credit facilities, $1.3 billion (2014 - $1.6 billion) is not drawn. The
Corporation is in compliance with the terms of the credit facility and all undrawn amounts are fully available. In addition to the
$1.3 billion available under the credit facilities, TransAlta also has $54 million of available cash and cash equivalents.
Debentures bear interest at fixed rates ranging from 5.0 per cent to 7.3 per cent and have maturity dates ranging from 2019 to 2030.
Senior notes bear interest at rates ranging from 1.90 per cent to 6.65 per cent and have maturity dates ranging from 2017 to 2040.
On Jan. 15, 2015, the Corporation’s US$500 million 4.75 per cent senior notes matured and were paid out using existing liquidity.
F68
F68 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
In June 2014, the Corporation issued US$400 million of senior notes due in 2017 that carry a coupon rate of 1.90 per cent,
payable semi-annually, at an issue price equal to 99.887 per cent of the principal amount of the notes.
A total of US$580 million of the senior notes has been designated as a hedge of the Corporation’s net investment in U.S.
foreign operations.
Non-recourse debt consists of bonds and debentures that have maturity dates ranging from 2016 to 2028 and bear interest at
rates ranging from 2.95 per cent to 7.3 per cent.
Non-recourse debentures have maturity dates ranging from 2016 to 2018 and bear interest rates ranging from 5.7 per cent to
7.3 per cent.
On Feb. 11, 2015, the Corporation and its partner issued non-recourse bonds secured by their jointly owned Pingston facility.
The Corporation’s share of gross proceeds was $45 million. The non-recourse bonds bear interest at the annual fixed interest
rate of 2.95 per cent, payable semi-annually with no principal repayments until maturity in May 2023. Proceeds were used to
repay the $35 million non-recourse debenture bearing interest at 5.28 per cent related to the Pingston facility.
On Sept. 1, 2015, the Corporation’s $120 million 5.33 per cent non-recourse debentures matured and were paid out using
existing liquidity. The Corporation also closed the acquisition of solar assets (see Note 4) and assumed approximately
US$42 million of non-recourse variable rate debt, of which approximately US$32 million is hedged to a fixed rate of
1.7 per cent.
On Oct. 1, 2015, the Corporation issued a non-recourse bond in the amount of $442 million bearing interest at 3.834 per cent,
with principal and interest payable semi-annually in blended payments until maturity on Dec. 31, 2028.
Other consists of an unsecured commercial loan obligation that bears interest at 5.9 per cent and matures in 2023, requiring
annual payments of interest and principal, and tax equity financing assumed in the Lakeswind wind acquisition (see
Note 4). Notes payable for the Windsor plant matured and were paid out in November 2014.
TransAlta's debt has terms and conditions, including financial covenants, that are considered normal and customary. As at
Dec. 31, 2015, the Corporation was in compliance with all debt covenants.
B. Restrictions on Non-Recourse Debt
Non-recourse debentures of $230 million (2014 - $344 million) issued by the Corporation’s CHD subsidiary include
restrictive covenants requiring the proceeds received from the sale of assets to be reinvested into similar renewable assets or
to repay the non-recourse debentures.
Other non-recourse debt of $536 million (2014 - $35 million) is secured by certain renewable generation facilities and subject
to customary financing restrictions that restrict the Corporation’s ability to access funds generated by the facilities’
operations. The total carrying amount of renewable generation facilities provided as security is $798 million at Dec. 31, 2015
(2014 - $50 million).
C. Principal Repayments
Principal repayments(1)
2016
72
2017
604
2018
947
2019
2020
2021 and
thereafter
Total
761
447
1,596
4,427
(1) Excmuees inqact of eeriwatiwes ane incmuees eraxn creeit facimities that are currentmz scheeumee to exqire in 2919.
F69
TRANSALTA CORPORATION F69
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
D. Finance Lease Obligations
Amounts payable for mining assets and other finance leases are as follows:
As at Dec. 31
2015
2014
Minimum
lease
payments
Present value of
minimum lease
payments
Minimum
lease
payments
Present value of
minimum lease
payments
Within one year
Second to fifth years inclusive
More than five years
Less: interest costs
Total finance lease obligations
Included in the Consolidated Statements of Financial Position as:
Current portion of finance lease obligations
Long-term portion of finance lease obligations
18
49
29
96
14
82
15
67
82
16
37
21
74
-
74
18
44
20
82
-
82
16
43
30
89
15
74
13
61
74
E. Letters of Credit
Letters of credit are issued to counterparties under various contractual arrangements with the Corporation and certain
subsidiaries of the Corporation. If the Corporation or its subsidiary does not perform under such contracts, the counterparty
may present its claim for payment to the financial institution through which the letter of credit was issued. Any amounts owed
by the Corporation or its subsidiaries under these contracts are reflected in the Consolidated Statements of Financial Position.
All letters of credit expire within one year and are expected to be renewed, as needed, in the normal course of business. The
total outstanding letters of credit as at Dec. 31, 2015 was $575 million (2014 - $396 million) with no (2014 - nil) amounts
exercised by third parties under these arrangements.
22. Defined Benefit Obligation and Other Long-Term Liabilities
The components of defined benefit obligation and other long-term liabilities are as follows:
As at Dec. 31
Defined benefit obligation (Note 27)
Deferred coal revenues
Long-term incentive accruals (Note 26)
Other
Total
2015
222
60
8
58
348
2014
226
58
13
52
349
Deferred coal revenues consist of amounts received from the Corporation’s Keephills Unit 3 joint operation partner for future
coal deliveries. These amounts are being amortized into revenue over the life of the coal supply agreement, since commercial
operations of Keephills Unit 3 began on Sept. 1, 2011.
Other includes $11 million (2014 - $12 million) relating to a reimbursement received for costs of the New Richmond terminal
station, which is being amortized to revenue over the term of the related PPA.
F70
F70 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
23. Common Shares
A. Issued and Outstanding
TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value.
As at Dec. 31
Issued and outstanding, beginning of year
Issued under the dividend
reinvestment and share purchase plan
Amounts receivable under
Employee Share Purchase Plan
Issued and outstanding, end of year
2015
Common
shares
(nimmions)
275.0
9.0
284.0
-
284.0
Amount
3,001
76
3,077
(2)
3,075
2014
Common
shares
(nimmions)
268.2
6.8
275.0
-
275.0
Amount
2,916
85
3,001
(2)
2,999
B. Shareholder Rights Plan
The Corporation initially adopted the Shareholder Rights Plan in 1992, which has been revised since that time to ensure
conformity with current practices. As required, the Shareholder Rights Plan must be put before the Corporation’s shareholders
every three years for approval, and it was last approved on April 23, 2013. As such, the Shareholder Rights Plan will expire
unless it is approved by a majority of shareholders at the April 22, 2016 meeting. The primary objective of the Shareholder
Rights Plan is to provide the Board sufficient time to explore and develop alternatives for maximizing shareholder value if a
takeover bid is made for the Corporation and to provide every shareholder with an equal opportunity to participate in such a
bid. When an acquiring shareholder commences a bid to acquire 20 per cent or more of the Corporation's common shares,
other than by way of a “permitted bid” (as defined in the Shareholder Rights Plan), where the offer is made to all shareholders
by way of a takeover bid circular, the rights granted under the Shareholder Rights Plan become exercisable by all shareholders
except those held by the acquiring shareholder. Each right will entitle a shareholder, other than the acquiring shareholder, to
acquire an additional $200 worth of common shares for $100.
C. Premium DividendTM, Dividend Reinvestment, and Optional Common Share Purchase Plan (the
“Plan”)
On Feb. 21, 2012, the Corporation added a Premium DividendTM Component to its existing dividend reinvestment plan. The
amended and restated plan provided eligible shareholders with two options: i) to reinvest dividends at a current three per cent
discount to the average market price towards the purchase of new common shares of the Corporation (the Dividend
Reinvestment Component) or; ii) to receive a premium cash payment equivalent to 102 per cent of the reinvested dividends
(the Premium DividendTM Component).
The Corporation suspended the Premium DividendTM Component of the Plan following the payment of the quarterly dividend
on July 1, 2013. The Corporation’s Dividend Reinvestment and Optional Common Share Purchase Plan, separate components
of the Plan, remained effective in accordance with their current terms. These features were suspended on Jan. 14, 2016. Refer
to Note 34 for further details.
On Jan. 1, 2016, 3.8 million common shares were issued for dividends reinvested.
F71
TRANSALTA CORPORATION F71
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
D. Earnings per Share
Year ended Dec. 31
Net earnings (loss) attributable to common shareholders
Basic and diluted weighted average number of common shares
outstanding (millions)
Net earnings (loss) per share attributable to common shareholders,
basic and diluted
2015
(24)
280
(0.09)
2014
141
273
0.52
2013
(71)
264
(0.27)
E. Dividends
On Oct. 29, 2015, the Corporation declared a quarterly dividend of $0.18 per common share, payable on Jan. 1, 2016. On
Jan. 14, 2016, the Corporation announced the resizing of its dividend from $0.72 annually to $0.16 annually. Refer to Note 34
for further details.
On Feb. 16, 2016, the Corporation declared a quarterly dividend of $0.04 per share on common shares, payable on
April 1, 2016.
There have been no other transactions involving common shares between the reporting date and the date of completion of
these consolidated financial statements.
24. Preferred Shares
A. Issued and Outstanding
All preferred shares issued and outstanding are non-voting cumulative redeemable fixed rate first preferred shares.
As at Dec. 31
2015
2014
Series
Series A
Series C
Series E
Series G
Issued and outstanding, end of year
Number of shares
(nimmions)
Amount
Number of shares
(nimmions)
Amount
12.0
11.0
9.0
6.6
38.6
293
269
219
161
942
12.0
11.0
9.0
6.6
38.6
293
269
219
161
942
The holders are entitled to receive cumulative fixed quarterly cash dividends at a specified rate, as approved by the Board.
After an initial period of approximately five years from issuance and every five years thereafter (“Rate Reset Date”), the fixed
rate resets to the sum of the then five-year Government of Canada bond yield (the fixed rate “Benchmark”) plus a specified
spread. Upon each Rate Reset Date, they are also:
Redeemable at the option of the Corporation, in whole or in part, for $25.00 per share, plus all declared and unpaid
dividends at the time of redemption.
Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred
shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then
Government of Canada three-month Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The
cumulative floating rate first preferred shares are also redeemable at the option of the Corporation and convertible back
into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same
terms as noted above.
F72
F72 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
Characteristics specific to each first preferred share series as at Dec. 31, 2015, are as follows:
Series
Rate during term
Annual dividend
rate per share ($)
A
B
C
D
E
F
G
H
Fixed
Floating
Fixed
Floating
Fixed
Floating
Fixed
Floating
1.15
-
1.15
-
1.25
-
1.325
-
First Rate
Reset Date
March 31, 2016
-
June 30, 2017
-
Sept. 30, 2017
-
Sept. 30, 2019
-
Rate spread
over Benchmark
(qer cent)
Convertible to
Series
2.03
2.03
3.10
3.10
3.65
3.65
3.80
3.80
B
A
D
C
F
E
H
G
B. Dividends
The following table summarizes the preferred share dividends declared in 2015, 2014, and 2013:
Series
A
C
E
G(1)
Total for the year
(1) 2914 incmuees eiwieenes for the qerioe fron issuance on Aug. 15, 2914 to Dec. 31, 2914.
Total dividends declared ($)
2015
2014
2013
14
13
11
8
46
14
13
11
3
41
14
13
11
-
38
On Feb. 16, 2016, the Corporation declared a quarterly dividend of $0.2875 per share on the Series A and Series C preferred
shares, $0.3125 per share on the Series E preferred shares, and $0.33125 per share on the Series G preferred shares, all
payable March 31, 2016.
F73
TRANSALTA CORPORATION F73
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
25. Accumulated Other Comprehensive Income
The components of, and changes in, accumulated other comprehensive income (loss) are as follows:
Currency translation adjustment
Opening balance, Jan. 1
Gains on translating net assets of foreign operations, net of
reclassifications to net earnings
Losses on financial instruments designated as hedges of foreign
operations, net of reclassifications to net earnings, net of tax(1)
Balance, Dec. 31
Cash flow hedges
Opening balance, Jan. 1
Gains on derivatives designated as cash flow hedges, net of
reclassifications to net earnings and to non-financial assets, net of tax(2)
Balance, Dec. 31
Employee future benefits
Opening balance, Jan. 1
Net actuarial gains (losses) on defined benefit plans, net of tax(3)
Balance, Dec. 31
Others
Opening balance, Jan. 1
Intercompany available for sale investments
Balance, Dec. 31
Accumulated other comprehensive income
(1) Net of incone tax exqense of 8 for the zear eneee Dec. 31, 2915 (2914 ) 9 recowerz).
(2) Net of incone tax exqense of 88 for the zear eneee Dec. 31, 2915 (2914 ) 88 exqense).
(3) Net of incone tax recowerz of nim for the zear eneee Dec. 31, 2915 (2914 ) 7 recowerz).
2015
2014
(19)
(36)
237
(166)
52
173
177
350
(50)
4
(46)
-
(3)
(3)
68
(51)
(19)
4
169
173
(30)
(20)
(50)
-
-
-
353
104
F74
F74 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
26. Share-Based Payment Plans
The Corporation has the following share-based payment plans:
A. Performance Share Unit (“PSU”) and Restricted Share Unit (“RSU”) Plan
Under the PSU and RSU Plan, grants may be made annually, but are measured and assessed over a three-year performance
period. Grants are determined as a percentage of participants’ base pay and are converted to PSUs or RSUs on the basis of the
Corporation’s common share price at the time of grant. Vesting of PSUs is subject to achievement over a three-year period of
three performance measures: growth in funds from operation per share, growth in free cash flow per share, and growth in the
Corporation’s total shareholder return relative to the S&P/TSX Composite Index. RSUs are subject to a three-year cliff-vesting
requirement. RSUs and PSUs track the Corporation’s share price over the three-year period and accrue dividends as additional
units at the same rate as dividends paid on the Corporation’s common shares. The Human Resources Committee of the Board
has the discretion to determine whether payments on settlement are made through purchase of shares on the open market or
in cash. The expense related to this plan is recognized during the period earned, with the corresponding payable recorded in
liabilities. The liability is valued at the end of each reporting period using the closing price of the Corporation’s common
shares on the Toronto Stock Exchange (“TSX”).
The pre-tax reversal of compensation expense related to PSUs and RSUs in 2015 was $3 million (2014 - $8 million expense,
2013 - $6 million expense), which is included in operations, maintenance, and administration expense in the Consolidated
Statements of Earnings (Loss).
B. Deferred Share Unit (“DSU”) Plan
Under the DSU Plan, members of the Board and executives may, at their option, purchase DSUs using certain components of
their fees or pay. A DSU is a notional share that has the same value as one common share of the Corporation and fluctuates
based on the changes in the value of the Corporation’s common shares in the marketplace. DSUs accrue dividends as
additional DSUs at the same rate as dividends are paid on the Corporation’s common shares.
DSUs are redeemable in cash and may not be redeemed until the termination or retirement of the director or executive from
the Corporation.
The Corporation accrues a liability and expense for the appreciation in the common share value in excess of the DSU’s
purchase price and for dividend equivalents earned. The pre-tax reversal of compensation expense related to the DSUs was
$2 million in 2015 (2014 and 2013 - nil)
F75
TRANSALTA CORPORATION F75
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
C. Stock Option Plans
The Corporation is authorized to grant options to purchase up to an aggregate of 13.0 million common shares at prices based
on the market price of the shares on the TSX as determined on the grant date. The plan provides for grants of options to all
full-time employees, including executives, designated by the Human Resources Committee from time to time.
The total options outstanding and exercisable under these stock option plans at Dec. 31, 2015 are outlined below:
Range of
exercise
prices
($ qer share)
22.46 - 28.81
31.97 - 48.02
22.46 - 48.02
Options outstanding and exerciseable
Number of
options at
Dec. 31, 2015
(nimmions)
0.6
0.5
1.1
Weighted
average
remaining
contractual
life (zears)
4.1
2.1
3.1
Weighted
average
exercise
price
($ qer share)
23.76
34.63
29.13
No stock options were granted and no expense was recognized over the last three-year period.
D. Employee Share Purchase Plan
Under the terms of the employee share purchase plan, the Corporation extended interest-free loans (up to 30 per cent of an
employee's base salary) to employees below executive level and allowed for payroll deductions over a three-year period to
repay the loan. Executives were not eligible for this program in accordance with the Sarbanes-Oxley legislation. An agent
purchased these common shares on the open market on behalf of employees at prices based on the market price of the
shares as determined on the date of purchase. Employee sales of these shares were handled in the same manner. At
Dec. 31, 2015, amounts receivable from employees under the plan totalled $2 million (2014 - $2 million).
On Jan. 14, 2016, the Corporation suspended its employee share purchase plan.
F76
F76 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
27. Employee Future Benefits
A. Description
The Corporation sponsors registered pension plans in Canada and the U.S. covering substantially all employees of the
Corporation in these countries and specific named employees working internationally. These plans have defined benefit and
defined contribution options, and in Canada there is an additional supplemental defined benefit plan for certain employees
whose annual earnings exceed the Canadian income tax limit. Except for the Highvale pension plan acquired in 2013, the
Canadian and U.S. defined benefit pension plans are closed to new entrants. The U.S. defined benefit pension plan was frozen
effective Dec. 31, 2010, resulting in no future benefits being earned.
The latest actuarial valuations for accounting purposes of the Canadian and U.S. pension plans were at Dec. 31, 2015 and
Jan. 1, 2015, respectively. The latest actuarial valuation for accounting purposes of the Highvale pension plan was at
Dec. 31, 2013. The measurement date used for all plans to determine the fair value of plan assets and the present value of the
defined benefit obligation was Dec. 31, 2015.
Funding of the registered pension plans complies with applicable regulations that require actuarial valuations of the pension
funds at least once every three years in Canada, or more, depending on funding status, and every year in the United States.
The latest actuarial valuation for funding purposes of the Canadian registered plans was completed in early 2015 with an
effective date of Dec. 31, 2014. The latest actuarial valuation for funding purposes of the U.S. pension plan was Jan. 1, 2015.
The supplemental pension plan is solely the obligation of the Corporation. The Corporation is not obligated to fund the
supplemental plan but is obligated to pay benefits under the terms of the plan as they come due. The Corporation has posted
a letter of credit in the amount of $65 million to secure the obligations under the supplemental plan.
The Corporation provides other health and dental benefits to the age of 65 for both disabled members and retired members
through its other post-employment benefits plans. The latest actuarial valuations for accounting purposes of the Canadian
and U.S. plans were as at Dec. 31, 2013 and Jan. 1, 2015, respectively. The measurement date used to determine the present
value of the defined benefit obligation for both plans was Dec. 31, 2015.
During 2015, the Corporation recognized a $5 million gain on amendment of the supplemental plan in connection with a
reduction of benefits. The Corporation has also recognized a $3 million curtailment gain on other post-retirement benefit
plans, due to the reduction in the number of employees, associated with the restructuring initiative described in Note 4.
F77
TRANSALTA CORPORATION F77
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
B. Costs Recognized
The costs recognized in net earnings during the year on the defined benefit, defined contribution, and other post-employment
benefits plans are as follows:
Registered
Supplemental
Other
Total
7
2
21
(16)
-
14
21
35
2
-
3
-
2
-
1
-
(5)
(3)
-
-
-
-
-
-
11
2
25
(16)
(8)
14
21
35
Registered
Supplemental
Other
Total
6
2
23
(18)
13
20
33
2
-
4
-
6
-
6
2
-
1
-
3
-
3
10
2
28
(18)
22
20
42
Registered
Supplemental
Other
Total
6
2
21
(15)
14
20
34
3
-
3
-
6
-
6
2
-
1
-
3
-
3
11
2
25
(15)
23
20
43
Year ended Dec. 31, 2015
Current service cost
Administration expenses
Interest cost on defined benefit obligation
Interest on plan assets
Curtailment and amendment gain
Defined benefit expense
Defined contribution expense
Net expense
Year ended Dec. 31, 2014
Current service cost
Administration expenses
Interest cost on defined benefit obligation
Interest on plan assets
Defined benefit expense
Defined contribution expense
Net expense
Year ended Dec. 31, 2013
Current service cost
Administration expenses
Interest cost on defined benefit obligation
Interest on plan assets
Defined benefit expense
Defined contribution expense
Net expense
F78
F78 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
C. Status of Plans
The status of the defined benefit pension and other post-employment benefit plans is as follows:
As at Dec. 31, 2015
Fair value of plan assets
Present value of defined benefit obligation
Funded status - plan deficit
Amount recognized in the consolidated financial statements:
Accrued current liabilities
Other long-term liabilities
Total amount recognized
As at Dec. 31, 2014
Fair value of plan assets
Present value of defined benefit obligation
Funded status - plan deficit
Amount recognized in the consolidated financial statements:
Accrued current liabilities
Other long-term liabilities
Total amount recognized
Registered
Supplemental
Other
429
(566)
(137)
(11)
(126)
(137)
9
(80)
(71)
(5)
(66)
(71)
-
(32)
(32)
(2)
(30)
(32)
Registered
Supplemental
Other
427
(565)
(138)
(14)
(124)
(138)
8
(86)
(78)
(5)
(73)
(78)
-
(30)
(30)
(1)
(29)
(30)
D. Plan Assets
The fair value of the plan assets of the defined benefit pension and other post-employment benefit plans is as follows:
Registered
Supplemental
Other
Fair value of plan assets as at Dec. 31, 2013
Interest on plan assets
Net return on plan assets
Contributions
Benefits paid
Administration expenses
Effect of translation on U.S. plans
Fair value of plan assets as at Dec. 31, 2014
Interest on plan assets
Net return on plan assets
Contributions
Benefits paid
Administration expenses
Effect of translation on U.S. plans
Fair value of plan assets as at Dec. 31, 2015
394
18
33
14
(33)
(2)
3
427
16
6
12
(36)
(2)
6
429
7
-
-
5
-
-
-
1
(4)
(1)
-
-
8
-
-
7
(6)
-
-
9
-
-
-
-
-
1
(1)
-
-
-
Total
438
(678)
(240)
(18)
(222)
(240)
Total
435
(681)
(246)
(20)
(226)
(246)
Total
401
18
33
20
(38)
(2)
3
435
16
6
20
(43)
(2)
6
438
F79
TRANSALTA CORPORATION F79
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
The fair value of the Corporation’s defined benefit plan assets by major category is as follows:
Year ended Dec. 31, 2015
Equity securities
Canadian
U.S.
International
Private
Bonds
AAA
AA
A
BBB
Below BBB
Money market and cash and cash equivalents
Total
Year ended Dec. 31, 2014
Equity securities
Canadian
U.S.
International
Private
Bonds
AAA
AA
A
BBB
Below BBB
Money market and cash and cash equivalents
Total
Level I
Level II
Level III
Total
-
-
-
-
-
-
1
1
-
4
6
70
32
120
-
53
57
60
21
4
12
429
-
-
-
3
-
-
-
-
-
-
3
70
32
120
3
53
57
61
22
4
16
438
Level I
Level II
Level III
Total
-
-
-
-
-
1
1
-
-
4
6
102
49
70
-
57
54
64
16
1
11
424
-
-
-
5
-
-
-
-
-
-
5
102
49
70
5
57
55
65
16
1
15
435
Plan assets do not include any common shares of the Corporation at Dec. 31, 2015 and Dec. 31, 2014. The Corporation
charged the registered plan $0.1 million for administrative services provided for the year ended Dec. 31, 2015 (2014 -
$0.1 million).
F80
F80 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
E. Defined Benefit Obligation
The present value of the obligation for the defined benefit pension and other post-employment benefit plans is as follows:
Registered
Supplemental
Other
Total
Present value of defined benefit obligation as at Dec. 31, 2013
Current service cost
Interest cost
Benefits paid
Actuarial (gain) loss arising from demographic assumptions
Actuarial gain arising from financial assumptions
Actuarial (gain) loss arising from experience adjustments
Effect of translation on U.S. plans
Present value of defined benefit obligation as at Dec. 31, 2014
Current service cost
Interest cost
Benefits paid
Actuarial gain arising from demographic assumptions
Actuarial loss arising from financial assumptions
Actuarial gain arising from experience adjustments
Curtailment and amendment
Effect of translation on U.S. plans
Present value of defined benefit obligation
as at Dec. 31, 2015
517
6
23
(33)
4
50
(5)
3
565
7
21
(36)
(1)
3
-
-
7
566
74
2
4
(4)
-
8
2
-
86
2
3
(6)
-
2
(2)
(5)
-
80
27
2
1
(1)
(2)
3
(1)
1
30
2
1
(1)
-
2
(2)
(3)
3
618
10
28
(38)
2
61
(4)
4
681
11
25
(43)
(1)
7
(4)
(8)
10
32
678
The weighted average duration of the defined benefit plan obligation as at Dec. 31, 2015 is 13.5 years.
F. Contributions
The expected employer contributions for 2016 for the defined benefit pension and other post-employment benefit plans are
as follows:
Expected employer contributions
Registered
Supplemental
Other
11
5
2
Total
18
F81
TRANSALTA CORPORATION F81
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
G. Assumptions
The significant actuarial assumptions used in measuring the Corporation's defined benefit obligation for the defined benefit
pension and other post-employment benefit plans are as follows:
(qer cent)
Accrued benefit obligation
Discount rate
Rate of compensation increase
Assumed health care cost trend rate
Health care cost escalation
Dental care cost escalation
Provincial health care premium escalation
Benefit cost for the year
Discount rate
Rate of compensation increase
Assumed health care cost trend rate
Health care cost escalation
Dental care cost escalation
Provincial health care premium escalation
As at Dec. 31, 2015
As at Dec. 31, 2014
Registered
Supplemental
Other
Registered
Supplemental
Other
3.8
3.0
-
-
-
3.8
3.0
-
-
-
3.6
3.0
-
-
-
3.8
3.0
-
-
-
3.8
-
7.8(1)
4.0
5.0
3.8
-
7.5(2)
4.0
5.0
3.8
3.0
-
-
-
4.6
3.0
-
-
-
3.8
3.0
-
-
-
4.5
3.0
-
-
-
3.8
-
7.6(3)
4.0
5.0
4.5
-
7.8(4)
4.0
5.0
(1) Post ane Pre 65 rates; eecreasing graeuammz to 4.5% bz 2924 ane renaining at that mewem thereafter for the U.S. ane eecreasing graeuammz bz
9.35% qer zear to 5% in 2924 for Canaea.
(2) Post ane Pre 65 rates; eecreasing graeuammz to 5% bz 2919)2929 ane renaining at that mewem thereafter for the U.S. ane eecreasing graeuammz bz
9.35% qer zear to 5% in 2924 for Canaea.
(3) Post ane Pre 65 rates; eecreasing graeuammz to 5% bz 2916)2919 ane renaining at that mewem thereafter for the U.S. ane eecreasing graeuammz bz
9.35% qer zear to 5% in 2924 for Canaea.
(4) Post ane Pre 65 rates; eecreasing graeuammz to 5% bz 2916)2919 ane renaining at that mewem thereafter for the U.S. ane eecreasing graeuammz bz
9.35% qer zear to 5% in 2924 for Canaea.
H. Sensitivity Analysis
The following table outlines the estimated increase in the net defined benefit obligation assuming certain changes in key
assumptions:
Year ended Dec. 31, 2015
1% decrease in the discount rate
1% increase in the salary scale
1% increase in the health care cost trend rate
10% improvement in mortality rates
Canadian plans
U.S. plans
Registered
Supplemental
Other
Pension
Other
73
8
-
17
12
1
-
3
2
-
2
-
3
-
-
1
1
-
1
-
F82
F82 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
28. Joint Arrangements
Joint arrangements at Dec. 31, 2015 included the following:
Joint operations
Sheerness
Segment
Coal
Ownership
(qer cent)
50
Genesee Unit 3
Keephills Unit 3
Goldfields Power
Fort Saskatchewan
Fortescue River Gas
Pipeline
Wintering Hills
McBride Lake
Soderglen
Pingston
Coal
Coal
Gas
Gas
Gas
Wind
Wind
Wind
Hydro
50
50
50
60
43
51
50
50
50
Description
Coal-fired plant in Alberta, of which TA Cogen has a 50 per cent interest,
operated by ATCO Power
Coal-fired plant in Alberta operated by Capital Power Corporation
Coal-fired plant in Alberta operated by TransAlta
Gas-fired plant in Australia operated by TransAlta
Cogeneration plant in Alberta, of which TA Cogen has a 60 per cent interest,
operated by TransAlta
Natural gas pipeline in Western Australia, operated by DBP
Development Group
Wind generation facility in Alberta operated by TransAlta
Wind generation facility in Alberta operated by TransAlta
Wind generation facility in Alberta operated by TransAlta
Hydro facility in British Columbia operated by TransAlta
29. Change in Non-Cash Operating Working Capital
Year ended Dec. 31
(Use) source:
Accounts receivable
Prepaid expenses
Income taxes receivable
Inventory
Accounts payable, accrued liabilities, and provisions
Income taxes payable
Change in non-cash operating working capital
2015
2014
2013
(77)
(3)
1
(9)
(152)
(2)
(242)
59
(1)
1
7
8
(1)
73
125
(7)
(14)
15
(51)
6
74
F83
TRANSALTA CORPORATION F83
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
30. Capital
TransAlta’s capital is comprised of the following:
As at Dec. 31
Long-term debt(1)
Equity
Common shares
Preferred shares
Contributed surplus
Deficit
Accumulated other comprehensive income
Non-controlling interests
Less: available cash and cash equivalents(2)
Less: fair value asset of hedging instruments on long-term debt(3)
Total capital
2015
4,495
3,075
942
9
(1,018)
353
1,029
(54)
(190)
8,641
2014
4,056
2,999
942
9
(770)
104
594
(43)
(96)
7,795
Increase/
(decrease)
439
76
-
-
(248)
249
435
(11)
(94)
846
(1) Incmuees finance mease obmigations, anounts outstaneing uneer creeit facimities, tax eruitz miabimitz, ane current qortion of mong)tern eebt.
(2) The Corqoration incmuees awaimabme cash ane cash eruiwaments as a reeuction in the camcumation of caqitam as caqitam is nanagee internammz ane
ewamuatee bz nanagenent using a net eebt qosition. In this regare, these funes naz be awaimabme, ane usee to facimitate reqaznent of eebt.
(3) The Corqoration incmuees the fair wamue of heeging instrunents on eebt in an asset, or miabimitz, qosition as a reeuction, or increase, in the
camcumation of caqitam, as the carrzing wamue of the rematee eebt has either increasee, or eecreasee, eue to changes in foreign exchange rates.
In 2016, the Corporation is focused on raising non-recourse debt to fund upcoming corporate debt maturities. The
Corporation’s overall capital management strategy and its objectives in managing capital have remained unchanged from
Dec. 31, 2014 and are as follows:
A. Maintain an Investment Grade Credit Rating
The Corporation operates in a long-cycle and capital-intensive commodity business, and it is therefore a priority to maintain
an investment grade credit rating as it allows the Corporation to access capital markets at reasonable interest rates. Key rating
agencies assess TransAlta’s credit rating using a variety of methodologies, including financial ratios. These methodologies and
ratios are not publicly disclosed. TransAlta’s management has developed its own definitions of metrics, ratios, and targets to
manage the Corporation’s capital. These metrics and ratios are not defined under IFRS, and may not be comparable to those
used by other entities or by rating agencies.
The Corporation has an investment grade credit rating from S&P, DBRS, and Fitch with stable outlooks. On Oct. 1, 2015,
Moody’s placed the rating of the Corporation’s senior unsecured debt under review for possible downgrade. On Dec. 17, 2015,
Moody's downgraded the Corporation below investment grade to Ba1 with a stable outlook. The Corporation is focused on
strengthening its financial position and cash flow coverage ratios to support stable investment grade credit ratings.
Strengthening the Corporation’s financial position allows its commercial team to contract the Corporation’s portfolio with a
variety of counterparties on terms and prices that are favourable to the Corporation’s financial results, and provides the
Corporation with better access to capital markets through commodity and credit cycles.
F84
F84 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
As at Dec. 31
Comparable funds from operations to adjusted interest coverage (times)
Adjusted comparable funds from operations to adjusted net debt (%)
Adjusted net debt to comparable earnings before interest,
taxes, depreciation, and amortization (times)
2015
3.8
15.2
5.0
2014
3.8
16.9
Target
4 to 5
20 to 25
4.2
3.0 to 3.5
Comparable Funds from Operations (“FFO”) before Interest to Adjusted Interest Coverage is calculated as comparable
FFO plus interest on debt (net of interest income and capitalized interest) divided by interest on debt plus 50 per cent of
dividends paid on preferred shares less interest income. Comparable FFO is calculated as cash flow from operating activities
before changes in working capital and is adjusted for transactions and amounts that the Corporation believes are not
representative of ongoing cash flows from operations. Comparable FFO to adjusted interest coverage in 2015 is consistent
with 2014. The Corporation’s goal is to maintain this ratio in a range of four to five times.
Adjusted Comparable FFO to Adjusted Net Debt is calculated as comparable FFO less 50 per cent of dividends paid on
preferred shares divided by net debt (current and long-term debt plus 50 per cent of outstanding preferred shares less
available cash and cash equivalents and including fair value assets of hedging instruments on debt). Adjusted comparable
FFO to adjusted net debt decreased in 2015 compared to 2014 due to lower comparable EBITDA and the impacts of the
strengthening of the U.S. dollar on US-dollar-denominated debt. The Corporation’s goal is to maintain this ratio in a range of
20 to 25 per cent.
Adjusted Net Debt to Comparable Earnings before Interest, Taxes, Depreciation, and Amortization (“EBITDA”) is
calculated as net debt divided by comparable EBITDA. Comparable EBITDA is calculated as earnings before interest, taxes,
depreciation, and amortization and is adjusted for transactions and amounts that the Corporation believes are not
representative of ongoing business operations. Adjusted net debt to comparable EBITDA in 2015 deteriorated compared to
2014 due to lower comparable EBITDA and the impacts of the strengthening of the U.S. dollar on US-dollar-denominated
debt. The Corporation’s goal is to maintain this ratio in a range of 3.0 to 3.5 times.
At times, the credit ratios may be outside of the specified target ranges while the Corporation realigns its capital structure.
During 2015, the Corporation took several steps to strengthen its financial position and reduce debt, using proceeds from the
dropdown of the Australian assets, the dropdown of the three Canadian Assets, and the sell-down of ownership interest in
TransAlta Renewables to pay down credit facility borrowings, fund growth, and increase liquidity.
In 2014, the Corporation used the proceeds from the sale of CE Gen, Blackrock, CalEnergy, and Wailuku (see Note 4), the
secondary offering of TransAlta Renewables common shares (see Note 4), and the offering of preferred shares (see Note 24)
to pay down debt.
Management routinely monitors forecasted net earnings, cash flows, capital expenditures, and scheduled repayment of debt
with a goal of meeting the above ratio targets and to meet dividend and PP&E expenditure requirements.
F85
TRANSALTA CORPORATION F85
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
B. Ensure Sufficient Cash and Credit is Available to Fund Operations, Pay Dividends, Distribute
Payments to Subsidiaries’ Non-Controlling Interests, Invest in Property, Plant, and Equipment,
and Make Acquisitions
For the year ended Dec. 31, 2015 and 2014, net cash outflows, are summarized below. The Corporation manages variations in
working capital using existing liquidity under credit facilities.
Year ended Dec. 31
Cash flow from operating activities
Change in non-cash working capital
Cash flow from operations before changes in working capital
Dividends paid on common shares
Dividends paid on preferred shares
Distributions paid to subsidiaries' non-controlling interests
Property, plant, and equipment expenditures(1)
Acquisitions
Outflow
2015
432
242
674
(124)
(46)
(99)
(476)
(101)
(172)
2014
796
(73)
723
(140)
(41)
(84)
(487)
-
(29)
Increase
(decrease)
(364)
315
(49)
16
(5)
(15)
11
(101)
(143)
(1) Includes growth capital associated with the South Hedland power project.
TransAlta maintains sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to its
business. At Dec. 31, 2015, $1.3 billion (2014 - $1.6 billion) of the Corporation’s available credit facilities were not drawn.
Periodically, TransAlta accesses capital markets, as required, to help fund some of these periodic net cash outflows, to
maintain its available liquidity, and to maintain its capital structure and credit metrics within targeted ranges. TransAlta is
focused on raising non-recourse debt to fund upcoming corporate debt maturities.
During 2015, the Corporation repaid US$500 million of senior notes that matured; completed a refinancing at the Pingston
facility for gross proceeds of $45 million; entered into an investment agreement to dropdown the Australian portfolio to
TransAlta Renewables for gross proceeds of $217 million; and issued $442 million of senior secured amortizing debt through
Melancthon Wolfe Wind LP with proceeds partially used to repay the $120 million CHD maturity.
During 2014, the Corporation completed a secondary offering of the common shares of TransAlta Renewables for gross
proceeds to the Corporation of approximately $136 million; issued 6.6 million Series G preferred shares for gross proceeds of
$165 million; issued US$400 million of senior notes; and repaid $200 million of medium-term notes that matured.
These activities supplement the equity offerings discussed in the preceding section.
F86
F86 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
31. Related-Party Transactions
Details of the Corporation’s principal operating subsidiaries at Dec. 31, 2015 are as follows:
Subsidiary
TransAlta Generation Partnership
TransAlta Cogeneration, L.P.
TransAlta Centralia Generation, LLC
TransAlta Energy Marketing Corp.
TransAlta Energy Marketing (U.S.), Inc.
TransAlta Energy (Australia), Pty Ltd.
TransAlta Renewables Inc.
Country
Canada
Canada
U.S.
Canada
U.S.
Australia
Canada
Ownership
(per cent)
Principal activity
100
Generation and sale of electricity
50.01
Generation and sale of electricity
100
100
100
100
Generation and sale of electricity
Energy marketing
Energy marketing
Generation and sale of electricity
66.61
Generation and sale of electricity
Transactions between the Corporation and its subsidiaries have been eliminated on consolidation and are not disclosed.
Transactions with Key Management Personnel
TransAlta’s key management personnel include the President and CEO and members of the senior management team that
report directly to the President and CEO, and the members of the Board.
Key management personnel compensation is as follows:
Year ended Dec. 31
Total compensation
Comprised of:
Short-term employee benefits
Post-employment benefits
Other long-term benefits
Termination benefits
Share-based payments
2015
9
8
2
-
1
(2)
2014
13
2013
15
8
2
-
-
3
7
2
1
2
3
F87
TRANSALTA CORPORATION F87
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
32. Commitments and Contingencies
In addition to commitments disclosed elsewhere in the financial statements, the Corporation has entered into a number of
fixed purchase and transportation contracts, transmission and electricity purchase agreements, coal supply and mining
agreements, long-term service agreements, and agreements related to growth and major projects either directly or through its
interests in joint ventures. Approximate future payments under these agreements are as follows:
Natural gas, transportation,
and other purchase contracts
Transmission
Coal supply and mining agreements
Long-term service agreements
Non-cancellable operating leases
Growth
TransAlta Energy Bill
Total
2016
2017
2018
2019
2020
2021 and
thereafter
Total
52
14
151
103
9
85
6
420
17
8
46
110
8
186
6
381
15
9
50
23
7
6
6
116
6
7
50
19
7
1
6
96
6
7
52
36
7
-
6
105
6
542
70
50
-
19
201
51
891
361
88
278
49
114
792
1,919
A. Natural Gas, Transportation, and Other Purchase Contracts
Several of the Corporation’s plants have fixed price natural gas purchase and related transportation contracts in place. Other
fixed price purchase contracts relate to commitments for services at certain facilities.
B. Transmission
The Corporation has several agreements to purchase transmission network capacity in the Pacific Northwest. Provided certain
conditions for delivering the service are met, the Corporation is committed to the transmission at the supplier’s tariff rate
whether it is awarded immediately or delivered in the future after additional facilities are constructed.
C. Coal Supply and Mining Agreements
Various coal supply and associated rail transport contracts are in place to provide coal for use in production at the Centralia
coal plant. The coal supply agreements allow TransAlta to take delivery of coal at fixed volumes and prices, with dates
extending to 2024.
Commitments related to mining agreements include the Corporation’s share of commitments for mining agreements related
to its Sheerness and Genesee Unit 3 joint operations, and certain other mining royalty agreements.
F88
F88 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
D. Long-Term Service Agreements
TransAlta has various service agreements in place, primarily for inspections and repairs and maintenance that may be
required on natural gas facilities, coal facilities, and turbines at various wind facilities.
E. Operating Leases
TransAlta has operating leases in place for buildings, vehicles, and various types of equipment.
During the year ended Dec. 31, 2015, $9 million (2014 - $10 million, 2013 - $10 million) was recognized as an expense in
respect of these operating leases. Sublease payments received during 2015 were less than $1 million. No contingent rental
payments were made in respect of these operating leases.
F. Growth
Commitments for growth primarily relate to the construction of the South Hedland power project.
G. TransAlta Energy Bill Commitments
On July 30, 2015, the Corporation announced that it would formalize its commitment to invest US$55 million over the
remaining 10 year life of the Centralia coal plant to support energy efficiency, economic and community development, and
education and retraining initiatives in Washington State by waiving its right to terminate the commitment on the basis of the
level of contract sales of the Centralia plant. As of Dec. 31, 2015, the Corporation has funded US$18 million of the
commitment, which is recognized in other assets in the Consolidated Statements of Financial Position.
H. Other
A significant portion of the Corporation’s electricity and thermal production are subject to PPAs and long-term contracts. The
majority of these contracts include terms and conditions customary to the industry in which the Corporation operates. The
nature of commitments related to these contracts includes: electricity and thermal capacity, availability, and production
targets; reliability and other plant-specific performance measures; specified payments for deliveries during peak and off-peak
time periods; specified prices per MWh; risk sharing of fuel costs; and retention of heat rate risk.
I. Contingencies
TransAlta is occasionally named as a party in various claims and legal and regulatory proceedings that arise during the normal
course of its business. TransAlta reviews each of these claims, including the nature of the claim, the amount in dispute or
claimed, and the availability of insurance coverage. There can be no assurance that any particular claim will be resolved in the
Corporation’s favour or that such claims may not have a material adverse effect on TransAlta. Inquiries from regulatory bodies
may also arise in the normal course of business, to which the Corporation responds as required.
F89
TRANSALTA CORPORATION F89
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
33. Segment Disclosures
A. Description of Reportable Segments
The Corporation has seven reportable segments as described in Note 1. During 2015, the Corporation completed changes to
its internal reporting to systematize allocations of certain costs to each fuel type within its generation segments. See Note 3
for further details.
B. Reported Segment Earnings (Loss) and Segment Assets
Canadian
Coal
912
441
471
194
237
-
11
12
(7)
24
-
-
U.S.
Coal
371
311
60
50
63
-
1
3
-
(57)
-
-
Gas
569
229
340
88
95
(2)
1
3
-
155
58
262
Wind and
Solar
Energy
Marketing
Hydro
Corporate
Total
250
19
231
48
99
-
-
7
-
77
-
-
116
8
108
29
25
-
-
3
(24)
75
-
-
49
-
49
12
1
-
3
-
56
(23)
-
-
-
-
-
71
25
-
6
1
-
(103)
-
-
2,267
1,008
1,259
492
545
(2)
22
29
25
148
58
262
(251)
4
221
Canadian
Coal
U.S.
Coal
Gas
Wind
Hydro
Energy
Marketing
Corporate
Total
1,023
492
531
196
235
-
12
(9)
97
-
422
251
171
49
54
-
3
-
65
-
692
326
366
102
111
(6)
4
-
155
49
247
14
233
48
88
-
6
-
91
-
131
9
122
39
24
-
3
(10)
66
-
108
-
108
33
-
-
-
5
70
-
-
-
-
75
26
-
1
-
(102)
-
2,623
1,092
1,531
542
538
(6)
29
(14)
442
49
2
(254)
239
I. Earnings Information
Year ended Dec. 31, 2015
Revenues
Fuel and purchased power
Gross margin
Operations, maintenance, and administration
Depreciation and amortization
Asset impairment recovery
Restructuring provision
Taxes, other than income taxes
Net other operating (income) loss
Operating income (loss)
Finance lease income
Gain on sale of assets
Net interest expense
Foreign exchange gain
Earnings before income taxes
Year ended Dec. 31, 2014
(Restatee ) see Note 3)
Revenues
Fuel and purchased power
Gross margin
Operations, maintenance, and administration
Depreciation and amortization
Asset impairment reversal
Taxes, other than income taxes
Net other operating (income) losses
Operating income (loss)
Finance lease income
Gain on sale of assets
Net interest expense
Earnings before income taxes
F90
F90 TRANSALTA CORPORATION
TransAlta Corporation | 2015 Annual Integrated Report
Year ended Dec. 31, 2013
(Restatee ) see Note 3)
Revenues
Fuel and purchased power
Gross margin
Operations, maintenance, and administration
Depreciation and amortization
Asset impairment charges (reversals)
Restructuring provision
Taxes, other than income taxes
Net other operating (gains) losses
Operating income (loss)
Finance lease income
Gain on sale of assets
Equity loss
Net interest expense
Foreign exchange gain
Loss before income taxes
Canadian
Coal
916
451
465
203
232
-
(2)
11
54
(33)
-
-
U.S.
Coal
243
227
16
48
56
-
-
4
-
(92)
-
-
Notes to Consolidated Financial Statements
Gas
Wind
Hydro
Energy
Trading
Corporate
Total
636
252
384
97
107
1
-
3
(1)
177
46
-
237
13
224
38
79
(23)
-
5
-
125
-
-
181
5
176
36
27
4
-
3
(7)
113
-
-
79
-
79
21
1
-
-
-
56
1
-
-
-
-
-
73
23
-
(1)
1
-
(96)
-
12
2,292
948
1,344
516
525
(18)
(3)
27
102
195
46
12
(10)
(256)
1
(12)
Included in revenues of the Wind and Solar Segment for the year ended Dec. 31, 2015 are $20 million (2014 - $21 million,
2013 - $22 million) of incentives received under a Government of Canada program in respect of power generation from
qualifying wind projects.
Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of
operating leases, is included in revenues, and was $230 million for the year ended Dec. 31, 2015 (2014 - $219 million, 2013 -
$208 million).
II. Selected Consolidated Statements of Financial Position Information
As at Dec. 31, 2015
Goodwill
PP&E
Intangible assets
As at Dec. 31, 2014
Goodwill
PP&E (Restatee ) Note 3)
Intangible assets
Canadian
Coal
-
3,061
92
Canadian
Coal
-
3,211
91
U.S.
Coal
-
484
6
U.S.
Coal
-
455
5
Gas
-
1,071
15
Gas
-
1,152
12
Wind
and Solar
176
1,992
176
Hydro
259
486
3
Energy
Marketing
Corporate
30
2
17
-
77
60
Total
465
7,173
369
Wind
Hydro
173
1,729
145
259
482
3
Energy
Marketing
Corporate
Total
30
1
14
-
83
61
462
7,113
331
F91
TRANSALTA CORPORATION F91
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
III. Selected Consolidated Statements of Cash Flows Information
Year ended
Dec. 31, 2015
Canadian
Coal
U.S.
Coal
Wind
and Solar
Gas
Hydro
Energy
Marketing
Corporate
Total
Additions to non-current assets:
PP&E
Intangible assets
179
6
13
-
223
-
13
-
43
-
1
3
4
17
476
26
Year ended
Dec. 31, 2014
Canadian
Coal
U.S.
Coal
Gas
Wind
Hydro
Energy
Marketing
Corporate
Total
Additions to non-current assets:
PP&E
Intangible assets
206
2
14
-
206
7
13
-
42
-
1
8
5
17
487
34
Year ended
Dec. 31, 2013
Canadian
Coal
U.S.
Coal
Gas
Wind
Hydro
Energy
Marketing
Corporate
Total
Additions to non-current assets:
PP&E
Intangible assets
403
3
19
-
59
-
48
-
25
1
-
7
7
21
561
32
Additions to non-current assets exclude amounts arising from acquisitions outlined in Note 4.
IV. Depreciation and Amortization on the Consolidated Statements of Cash Flows
The reconciliation between depreciation and amortization reported on the Consolidated Statements of Earnings (Loss) and
the Consolidated Statements of Cash Flows is presented below:
Year ended Dec. 31
Depreciation and amortization expense on the Consolidated Statements of Earnings
Depreciation included in fuel and purchased power (Note 5)
Loss on disposal of property, plant, and equipment
Depreciation and amortization on the Consolidated Statements of Cash Flows
2015
2014
2013
545
538
525
59
56 58
1 1
2
605
595
585
C. Geographic Information
I. Revenues
Year ended Dec. 31
Canada
U.S.
Australia
Total revenue
F92
F92 TRANSALTA CORPORATION
2015
1,705
448
114
2,267
2014
1,989
516
118
2,623
2013
1,898
287
107
2,292
TransAlta Corporation | 2015 Annual Integrated Report
Notes to Consolidated Financial Statements
II. Non-Current Assets
As at Dec. 31
Canada
U.S.
Australia
Total
Property, plant, and
equipment
2015
5,898
799
476
7,173
2014
6,317
532
264
7,113
Intangible assets
Other assets
Goodwill
2015
328
28
13
369
2014
296
25
10
331
2015
2014
2015
2014
79
37
17
133
66
14
18
98
417
48
-
465
417
45
-
462
D. Significant Customer
During the year ended Dec. 31, 2015, sales to one customer in Canadian Coal represented 13 per cent of the Corporation’s
total revenue (2014 - 12 per cent).
34. Subsequent Events
A. Closing of Investment in Canadian Assets by TransAlta
On Jan. 6, 2016, the Corporation announced the closing of the investment in the Canadian Assets by TransAlta Renewables
for a combined value of $540 million (see Note 4).
As consideration, TransAlta Renewables provided to the Corporation $172.5 million in cash, issued 15,640,583 common
shares with a value of $152.5 million, and issued a $215 million convertible unsecured subordinated debenture. The debenture
issued by TransAlta Renewables to the Corporation is on an interest-only basis at a coupon of 4.5 per cent per annum payable
semi-annually in arrears on June 30th and December 31st and will mature on Dec. 31, 2028. On the maturity date, the
Corporation will have the right, at its sole option, to convert the outstanding principal amount of the debenture, in whole or in
part, into common shares of TransAlta Renewables at a conversion price of $13.16 per common share, being a
35 per cent premium to the offering price on the closing date of the investment in the Canadian Assets. The debenture is a
direct unsecured obligation of TransAlta Renewables ranking subordinate to all liabilities, except liabilities which by their
terms rank in rights of payment equally with or subordinate to the debenture. The debenture ranks equal with all subordinate
debenture issued by TransAlta Renewables from time to time.
TransAlta Renewables funded the cash proceeds through the public issuance of 17,692,750 subscription receipts at a price of
$9.75 per subscription receipt. Upon the closing of the transaction, each holder of subscription receipts received one common
share of TransAlta Renewables and a cash dividend equivalent payment of $0.07 for each subscription receipt held. As a
result, TransAlta Renewables issued 17,692,750 common shares and paid a total dividend equivalent of $1.2 million. On
Jan. 6, 2016, TransAlta Renewables declared a dividend increase of 5 per cent.
B. Changes to Dividend Policies
On Jan. 14, 2016, the Corporation announced the resizing of its dividend from $0.72 annually to $0.16 annually and the
suspension of the Premium DividendTM , Dividend Reinvestment and Optional Common Share Purchase Plan (the “DRIP”)
effective immediately. These actions were taken as part of a plan to maximize the Company’s long-term financial flexibility, as
well as to stop shareholder dilution relating to the DRIP.
F93
TRANSALTA CORPORATION F93
TransAlta Corporation | 2015 Annual Integrated Report
Eleven-Year Financial and Statistical Summary
(in millions of Canadian dollars, except where noted)
Year ended Dec. 31
Financial Summary
Statement of Earnings
Revenues
Operating income
Net earnings (loss) attributable to common shareholders
Statement of Financial Position
Total assets
Current portion of long-term debt, net of cash and cash equivalents
Credit facilities, long-term debt, and finance lease obligations
Non-controlling interests
Preferred shares
Equity attributable to common shareholders
Fair value (asset) liability of hedging instruments on debt
Total invested capital(1)
Cash Flows
Cash flow from operating activities
Cash flow used in investing activities
Common Share Information (per share)
Net earnings (loss)
Comparable earnings(2)
Dividends paid on common shares
Book value per common share (at year-end)
Market price:
High
Low
Close (Toronto Stock Exchange at Dec. 31)
Ratios (percentage except where noted)
Adjusted net debt to invested capital
Adjusted net debt to invested capital excluding non-recourse debt
Adjusted net debt to comparable EBITDA (times)(2)
Return on equity attributable to common shareholders
Comparable return on equity attributable to common shareholders(2)
Return on capital employed
Comparable return on capital employed(2)
Earnings coverage (times)
Dividend payout ratio based on comparable funds from operations(2)
Comparable EBITDA (in millions of Canadian dollars)(2)
Dividend coverage (times)
Dividend yield
Adjusted comparable funds from operations to adjusted net debt
Comparable funds from operations before interest to adjusted interest coverage (times)
Weighted average common shares for the year (in millions)
Common shares outstanding at Dec. 31 (in millions)
Statistical Summary
Number of employees
Generating Capacity (MW)(3)
Coal (Canadian and U.S.)
Gas(4)
Renewables (wind, solar and hydro)
Equity investments
Total generating capacity
Total generation production (GWh)
2015
2014
2013
2,267
148
(24)
10,947
33
4,408
1,029
942
2,419
(190)
8,641
432
(573)
(0.09)
(0.17)
0.72
8.52
12.34
4.13
4.91
54.6
50.2
5.0
(1.2)
(2.3)
4.6
3.0
1.5
28.3
945
3.6
14.7
15.2
3.8
280
284
2,623
442
141
9,833
708
3,305
594
942
2,342
(96)
7,795
796
(292)
0.52
0.25
0.83
8.52
14.94
9.81
10.52
56.3
54.1
4.2
6.3
3.0
5.8
5.1
1.7
26.4
1,036
5.7
7.9
16.9
3.8
273
275
2,292
195
(71)
9,624
175
4,130
517
781
2,125
(16)
7,712
765
(703)
(0.27)
0.31
1.16
7.92
16.86
12.91
13.48
60.7
58.7
4.6
(3.2)
3.7
2.8
5.2
0.8
43.1
1,023
6.3
8.6
15.2
3.7
264
268
2,380
2,786
2,772
5,126
1,405
2,350
-
8,881
40,673
5,111
1,531
2,204
-
8,846
45,002
5,111
1,779
2,202
396
9,488
42,482
Financial data presented is based on IFRS. Financial data for 2009 and prior is based on Canadian
GAAP. Prior year figures that appear within the MD&A have been restated to conform with the
current year’s presentation. All other prior year figures have not been restated.
(1) Total invested capital for 2014 to 2009 has been revised to align with the 2015 calculation methodology.
(2) These ratios were calculated using non-IFRS measures. Periods for which the non-IFRS measure
was not previously disclosed have not been calculated.
(3) 2015, 2014, 2013, and 2012 are gross capacity which reflects the basis of underlying results. Prior
year figures are as previously reported.
(4) Includes finance leases.
Ratio Formulas
Adjusted net debt to invested capital = long-term debt and finance lease obligations including current
portion and fair value (asset) liability of hedging instruments on debt + 50 per cent issued preferred
shares - cash and cash equivalents / long-term debt and finance lease obligations including current
portion + non-controlling interests + equity attributable to shareholders - 50 per cent issued preferred
shares - cash and cash equivalents
Adjusted net debt to comparable EBITDA= long-term debt and finance lease obligations including
current portion and fair value (asset) liability of hedging instruments on debt - cash and cash
equivalents + 50 per cent issued preferred shares / comparable EBITDA
Return on equity attributable to common shareholders = net earnings attributable to common
shareholders excluding gain on discontinued operations or earnings on a comparable basis / equity
attributable to common shareholders excluding Accumulated Other Comprehensive Income (“AOCI”)
186
TransAlta Corporation | 2015 Annual Integrated Report Eleven-Year Financial and Statistical Summary
2012
2011
2010
2009
2008
2007
2006
2005
2,210
(214)
(615)
9,503
582
3,610
330
-
3,018
50
7,590
520
(1,048)
(2.62)
0.50
1.16
8.78
21.37
14.11
15.12
61.0
59.0
4.6
(25.9)
4.9
(3.1)
5.3
(1.0)
25.1
1,015
4.7
7.7
16.7
3.3
235
255
2,618
645
290
9,780
284
3,721
358
-
3,274
32
7,669
690
(608)
1.31
1.05
1.16
12.08
23.24
19.45
21.02
52.5
60.0
3.8
10.6
8.4
8.3
7.0
2.7
24.0
1,044
3.5
5.5
20.1
4.4
222
224
2,673
487
255
9,635
202
3,823
431
-
3,120
41
7,617
838
(765)
1.16
0.97
1.16
12.85
23.98
19.61
21.15
53.1
50.7
-
9.6
8.0
6.6
6.0
2.2
39.6
955
4.0
5.5
19.6
4.6
219
220
2,770
378
181
9,762
(51)
4,411
478
-
2,929
16
7,783
580
(1,598)
0.90
0.90
1.16
13.41
25.30
18.11
23.48
56.1
52.6
-
6.9
6.9
5.7
5.8
1.9
-
888
2.6
4.9
20.5
4.9
201
218
3,110
533
235
7,815
194
2,564
469
-
2,510
-
5,737
1,038
(581)
1.18
1.46
1.08
12.70
37.50
21.00
24.30
48.1
45.6
-
9.4
11.6
7.7
9.6
2.8
-
1,006
4.8
4.4
31.7
7.2
199
198
2,775
541
309
7,157
600
1,837
496
-
2,299
-
5,232
847
(410)
1.53
1.31
1.00
11.39
34.00
23.79
33.35
46.8
44.0
-
13.1
10.5
9.8
9.7
3.3
-
980
4.2
3.0
30.7
6.6
202
201
2,677
157
45
7,460
296
2,221
535
175
2,428
-
5,655
490
(261)
0.22
1.16
1.00
11.99
26.91
20.22
26.64
44.5
41.0
-
1.8
9.2
2.4
9.0
0.5
-
-
2.4
3.8
26.2
5.5
201
202
2,664
421
199
7,741
(66)
2,605
559
175
2,543
-
5,816
619
(242)
1.01
0.88
1.00
12.80
26.66
17.67
25.41
43.9
39.9
-
7.0
6.8
7.1
7.4
2.3
-
-
3.1
3.9
23.0
4.7
197
199
2,084
2,235
2,389
2,343
2,200
2,201
2,687
2,657
4,551
1,731
2,058
390
8,730
38,750
4,325
1,567
1,974
390
8,256
41,012
4,688
1,648
1,950
390
8,676
48,614
4,967
1,843
1,965
-
8,775
45,736
4,942
1,913
1,218
-
8,073
48,891
4,942
1,960
1,122
-
8,024
50,395
4,887
1,953
1,122
-
7,962
48,213
4,885
1,933
1,117
-
7,935
51,810
Earnings coverage = net earnings attributable to shareholders + income taxes + net interest expense /
50 per cent dividends paid on preferred shares + interest on debt - interest income
Dividend coverage = comparable cash flow from operating activities / cash dividends paid on
common shares
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 / invested capital excluding AOCI
Dividend yield = dividends paid per common share / current year’s close price
Dividend payout ratio = common share dividends declared / comparable funds from operations - 50
per cent dividends paid on preferred shares.
Comparable funds from operations before interest to adjusted interest coverage = comparable funds
from operations + interest on debt - interest income - capitalized interest / interest on debt + 50 per
cent dividends paid on preferred shares - interest income
Adjusted comparable funds from operations to adjusted net debt = comparable funds from operations
- 50 per cent dividends paid on preferred shares/ period end long-term debt and finance lease
obligations including fair value (asset) liability of hedging instruments on debt + 50 per cent issued
preferred shares - cash and cash equivalents
Comparable EBITDA = operating income + depreciation and amortization per the Consolidated
Statements of Cash Flows +/- non-comparable items
187
TransAlta Corporation | 2015 Annual Integrated Report
Capacity
(MW)(1)
2,141
Ownership
(%)
100%
Net capacity
ownership
interest (MW)(1)(2)
Region
2,141 Western Canada
Plant Summary
As of
January 2016
Coal
6 Facilities
Total Coal
Gas
13 Facilities
Total Gas
Wind
22 Facilities
Total Wind
Solar
1 Facility
Total Solar
Hydro
27 Facilities
Total Hydro
Total
Facility
Sundance, AB
Keephills, AB
Keephills 3, AB
Genesee 3, AB
Sheerness, AB
Centralia, WA
Poplar Creek, AB
Fort Saskatchewan, AB
Sarnia, ON
Mississauga, ON
Ottawa, ON
Windsor, ON
Southern Cross, WA(8)(9)
South Hedland, WA(9)(10)
Solomon, WA(9)
Parkeston, WA
Summerview 1, AB
Summerview 2, AB
Ardenville, AB
Blue Trail, AB
Wintering Hills, AB
Castle River, AB(11)
McBride Lake, AB
Soderglen, AB
Cowley Ridge, AB
Cowley North, AB
Sinnott, AB
Macleod Flats, AB
Melancthon, ON(12)
Wolfe Island, ON
Kent Breeze, ON
Kent Hills, NB(12)
Le Nordais, QC
New Richmond, QC
Wyoming Wind, WY
Lakeswind, MN
Mass Solar, MA(13)
Brazeau, AB
Big Horn, AB
Spray, AB
Ghost, AB
Rundle, AB
Cascade, AB
Kananaskis, AB
Bearspaw, AB
Pocaterra, AB
Horseshoe, AB
Barrier, AB
Taylor, AB
Interlakes, AB
Belly River, AB
Three Sisters, AB
Waterton, AB
St. Mary, AB
Upper Mamquam, BC
Pingston, BC
Bone Creek, BC
Akolkolex, BC(14)
Ragged Chute, ON
Misema, ON
Galetta, ON
Appleton, ON
Moose Rapids, ON
Skookumchuck, WA
100%
50%
50%
25%
100%
100%
30%
100%
50%
50%
50%
100%
100%
100%
50%
100%
100%
100%
100%
51%
100%
50%
50%
100%
100%
100%
100%
100%
100%
100%
83%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
50%
100%
100%
100%
100%
100%
100%
100%
100%
790
463
466
780
1,340
5,980
230
118
506
108
74
72
245
150
125
110
1,738
70
66
69
66
88
44
75
71
16
20
7
3
200
198
20
150
98
68
144
50
1,521
21
21
355
120
112
54
50
36
19
17
15
14
13
13
5
3
3
3
2
25
45
19
10
7
3
2
1
1
1
948
10,208
Revenue
source
Alberta PPA(3)/
Merchant(4)
Alberta PPA/
Merchant(5)
Merchant
Merchant
Alberta PPA
LTC/Merchant
LTC(7)
LTC
LTC
LTC
LTC/Merchant
LTC/Merchant
LTC
LTC
LTC
LTC
Merchant
Merchant
Merchant
Merchant
Merchant
Merchant
LTC
Merchant
Merchant
Merchant
Merchant
Merchant
LTC
LTC
LTC
LTC
LTC
LTC
LTC
LTC
Contract
expiry date
2017-2020
2020
-
-
2020
2020-2025(6)
2030
2019
2022-2025
2018
2017-2033
2031
2023
2042
2028
2026
-
-
-
-
-
-
2024
-
-
-
-
-
2026-2028
2029
2031
2033-2035
2033
2033
2028
2034
790 Western Canada
232 Western Canada
233 Western Canada
195 Western Canada
United States
1,340
4,931
230 Western Canada
35 Western Canada
Eastern Canada
Eastern Canada
Eastern Canada
Eastern Canada
Australia
Australia
Australia
Australia
506
54
37
36
245
150
125
55
1,473
70 Western Canada
66 Western Canada
69 Western Canada
66 Western Canada
45 Western Canada
44 Western Canada
38 Western Canada
35 Western Canada
16 Western Canada
20 Western Canada
7 Western Canada
3 Western Canada
Eastern Canada
Eastern Canada
Eastern Canada
Eastern Canada
Eastern Canada
Eastern Canada
United States
United States
200
198
20
125
98
68
144
50
1,379
21
United States
LTC
2032-2045
21
355 Western Canada
120 Western Canada
112 Western Canada
54 Western Canada
50 Western Canada
36 Western Canada
19 Western Canada
17 Western Canada
15 Western Canada
14 Western Canada
13 Western Canada
13 Western Canada
5 Western Canada
3 Western Canada
3 Western Canada
3 Western Canada
2 Western Canada
25 Western Canada
23 Western Canada
19 Western Canada
10 Western Canada
Eastern Canada
7
Eastern Canada
3
Eastern Canada
2
Eastern Canada
1
Eastern Canada
1
1
United States
926
8,730
Alberta PPA
Alberta PPA
Alberta PPA
Alberta PPA
Alberta PPA
Alberta PPA
Alberta PPA
Alberta PPA
Merchant
Alberta PPA
Alberta PPA
Merchant
Alberta PPA
Merchant
Alberta PPA
Merchant
Merchant
LTC
LTC
LTC
LTC
LTC
LTC
LTC
LTC
LTC
LTC
2020
2020
2020
2020
2020
2020
2020
2020
-
2020
2020
-
2020
-
2020
-
-
2025
2023
2031
2015
2029
2027
2030
2030
2030
2020
(1) Megawatts are rounded to the nearest whole number; columns may not add due to rounding.
(2) Accounts for 100% of TransAlta Renewables assets. As of January 6, 2016, TransAlta owns
approximately 64% of the outstanding voting shares of TransAlta Renewables.
(3) PPA refers to Power Purchase Arrangement.
(4) Merchant capacity refers to uprates on unit 3 (15 MW), unit 4 (53 MW), unit 5 (53 MW),
and unit 6 (44 MW).
(5) Merchant capacity refers to uprates on unit 1 (12 MW) and unit 2 (12 MW).
(6) Contract is in place until 2025; however, one unit is set to retire in 2020.
(7) LTC refers to Long-Term Contract.
(8) Comprised of four facilities.
(9) Gas/diesel.
(10) Plant is under construction and expected to be fully commissioned in mid-2017.
(11) Includes seven individual turbines at other locations.
(12) Comprised of two facilities.
(13) Comprised of four ground-mounted projects and four roof-top projects.
(14) Contract terms remain unchanged until the renewal process is finalized.
188
TransAlta Corporation | 2015 Annual Integrated Report Sustainability Performance Indicators
Corporate Statistics
Environment, Health and Safety Management Systems
2015
2014
2013
Facilities with ISO 14001 and/or OHSAS 18001-based management systems(1)
Generation capacity with ISO 14001 and OHSAS 18001-based management systems (%)
2
3 Management system audits(2)
4
Compliance audits(3)
Special audits(4)
67
97
8
9
6
62
98
9
9
8
62
98
14
14
0
Environmental Performance
2015
2014
2013
1
5
6
7
8
9
10
Air Emissions(5)
Sulphur dioxide (tonnes) 3
Sulphur dioxide emission intensity (kg/MWh)(6) 3
Nitrogen oxide (tonnes) 3
Nitrogen oxide emission intensity (kg/MWh)(6) 3
Particulate matter (tonnes) 3
Particulate matter emission intensity (kg/MWh)(6) 3
11
12 Mercury (kilograms) 3
13 Mercury emission intensity (mg/MWh)(6) 3
Greenhouse Gas Emissions(7)
Carbon dioxide (tonnes CO2e) 3
Methane (tonnes CO2e) 3
Nitrous oxide (tonnes CO2e) 3
Sulfur hexafluoride (tonnes CO2e)(8)
Gross emissions totals (tonnes CO2e)(9) 3
Gross emission intensity (kg CO2e/MWh)(10) 3
Scope 1 GHG emissions(11) 3
Scope 2 GHG emissions(12) 3
Total transportation greenhouse gas emissions (tonnes CO2e)(13) 3
Land Use and Reclamation(14)
Land use – disturbed (cumulative hectares) 3
Land use – reclaimed (cumulative hectares) 3
Land reclamation (% of former land reclaimed) 3
Land used in mining activities (hectares)(15) 3
Land used by plants, offices, and equipment (hectares)(16) 3
Environmental Incidents
Total environmental incidents(17) 3
Environmental enforcement actions
Environmental fines ($ thousands)
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Spills(18)
Volume of significant spills (m3) 3
31
32 Volume of significant spills recovered (m3) 3
33 % of spills recovered
41,800
1.13
48,000
1.30
4,900
0.13
170
4.50
47,600
1.20
52,900
1.34
5,200
0.13
220
5.66
36,200
1.00
42,900
1.19
3,300
0.09
170
4.77
31,902,700
112,600
212,400
18
34,724,400
119,200
231,200
10
30,417,500
92,800
199,100
10
32,227,700
0.87
32,041,400
186,400
119,700
35,074,800
0.89
34,892,400
182,300
118,500
30,709,400
0.85
30,522,100
187,300
101,200
11,800
4,900
42
6,900
3,900
12
1
2
19
19
99
11,700
4,900
42
6,800
3,700
15
0
0
463
446
96
11,600
4,800
42
6,800
3,700
14
4
0
1,155
520
45
189
TransAlta Corporation | 2015 Annual Integrated Report Sustainability Performance Indicators
Social Performance
2015
2014
2013
2,380
2,301
26
53
54
5.22
18
25
30
10
53
38
0
0
0
3
11
14
0.57
0.12
0
2
9
11
1.24
0.23
0.75
28
3.5
2,786
2,629
79
78
53
6.97
19
35
36
12
51
37
0
0
0
5
13
18
0.96
0.27
0
0
4
4
0.58
0.00
0.86
37
3.6
2,772
2,624
87
61
33
7.31
22
32
27
13
51
36
0
0
0
3
12
15
0.74
0.15
0
0
14
14
1.27
0.00
0.93
42
3.8
Workplace Practices
Employees
34
35 Number of full-time employees
36 Number of part-time employees
37 Number of contingent employees
38
39 Voluntary employee turnover rate (%)(20) 3
Employees represented by independent trade union organizations (%)(19)
Diversity
40 Women in workforce (%)(21) 3
41 Women in senior management (%)(22) 3
42 Women on Board of Directors (%)
43 Workforce under age 30 (%)
44 Workforce between ages 30 and 50 (%)
45 Workforce over age 50 (%)
Health and Safety
46 Health and safety enforcement actions(23)
47 Health and safety fines ($ thousands)
48
Employee fatalities 3
Lost time injury (LTI) (absence from work) 3
49
50 Medical aids (MA) (no absence from work) 3
51
Total injuries to employees 3
Employee recordable (LTI & MA) injury frequency rate (injuries/200,000 hours)(24) 3
Employee disabling (LTI) injury frequency rate (injuries/200,000 hours)(25) 3
52
53
54 Contractor fatalities 3
Lost time injury (LTI) (absence from work) for contractors 3
55
56 Medical aids (MA) (no absence from work) for contractors 3
57
58 Contractor recordable (LTI & MA) injury frequency rate (injuries/200,000 hours)(24) 3
59 Contractor disabling (LTI) injury frequency rate (injuries/200,000 hours)(25) 3
Total injuries to contractors 3
Total IFR (employees and contractors)(24) 3
60
Reportable vehicle incidents
Community Relations
Community investments ($ millions)(26) 3
61
2015 data has been third-party assured to a limited assurance level by Ernst & Young LLP.
3
Please see “Discussion and Notes on Numbers” for footnote explanations.
190
TransAlta Corporation | 2015 Annual Integrated Report Sustainability Performance Indicators
Discussion and Notes on Numbers
TransAlta continually strives to improve the accuracy and coverage of our sustainability performance reporting to
stakeholders. We review our processes and controls relating to the measurement and calculation of key sustainability
data annually. Several footnotes appear throughout the statistical summary and are intended to provide clarity on
specific boundary conditions, changes in methodology, and definitions. For questions or clarity on any key performance
indicators, please contact us at sustainability@transalta.com.
(1)
ISO 14001 and ISO 18001 are the world’s most recognized standards for Environmental Management and Health and Safety Management systems. TransAlta
has ownership in 69 facilities.
Internal audits conducted against ISO management systems.
Internal audits conducted against regulatory frameworks.
(2)
(3)
(4) Part of the Alberta Certificate of Recognition audit. Audits only applicable in Alberta.
(5) Air emissions are reported from TransAlta-operated facilities, where we report 100 per cent of emissions despite having a lower percentage of financial ownership
in some facilities. Air emissions are expressed in tonnes, except for mercury emissions, which are represented in kilograms. Historic 2013 and 2014 particulate
matter emissions were restated in 2015 to account for emissions that were not being captured in our reporting from our Centralia facility.
(6) Emissions intensity data has been aligned with the ‘Setting Organizational Boundaries: Operational Control’ methodology set out in The Greenhouse Gas
Protocol: A Corporate Accounting and Reporting Standard. Air emissions, although not greenhouse gas (GHG), are coincidentally aligned with this reporting
boundary for consistency. As per the methodology, TransAlta reports emissions on an operation control basis and hence we therefore report 100 per cent of
emissions at facilities in which we are the operator. Emission intensity is calculated by dividing total operational emissions by 100 per cent of production (MWh)
from operated facilities, regardless of financial ownership. Previously, emission intensities were calculated by dividing operational control emissions by financial
production volumes (MWh), which we have deemed to be an inaccurate representation of our emission intensity. Historical 2013 and 2014 emission intensities
have been restated to align with this approach.
(7) Greenhouse gas emissions are calculated across our fleet, typically in line with carbon regulation where the facility is located, and include emissions from
stationary combustion, transportation use, building use, and fugitive emissions. Historical 2014 emission data was restated in 2015 as a result of an incorrect use
of an emission factor when calculating CO2 emissions at our Ottawa facility and incorrect emission factor use when calculating wind and head office natural gas
consumption emissions. Historical 2013 emission data was restated to account for incorrect emission factor use when calculating wind and head office natural
gas consumption emissions. Changes resulted to approximately a 0.02 per cent adjustment in 2014 and less than 0.01 per cent in 2013. Subtotals, carbon
dioxide, methane, and nitrous oxide have been restated to include transportation emissions.
(8) Sulfur hexafluoride emissions from our Australia facilities were revised to align with guidance from the National Greenhouse and Energy Reporting regulation.
(9) Gross CO2e emissions or gross GHG emissions is the sum of carbon dioxide, methane, nitrous oxide, and sulfur hexafluoride. Coincidentally, the sum of scope 1
and 2 emissions will equate to gross CO2e emissions or gross GHG emissions.
(10) Emissions intensity data has been aligned with the ‘Setting Organizational Boundaries: Operational Control’ methodology set out in The Greenhouse Gas
Protocol: A Corporate Accounting and Reporting Standard. As per the methodology, TransAlta reports emissions on an operation control basis and hence we
therefore report 100 per cent of emissions at facilities in which we are the operator. Emission intensity is calculated by dividing total operational emissions by 100
per cent of production (MWh) from operated facilities, regardless of financial ownership. Previously, emission intensities were calculated by dividing operational
control emissions by financial production volumes (MWh), which we have deemed to be an inaccurate representation of our emission intensity. Historical 2013
and 2014 emission intensities have been restated to align with this approach.
(11) Scope 1 GHG emissions are all direct GHG emissions. For example, coal or gas combusted in one of our plants.
(12) Scope 2 GHG emissions are all indirect GHG emissions. For example, the consumption of purchased electricity, heat, and steam.
(13) Total transportation GHG emissions are reported in order to track our performance in this area. Total transportation GHGs are accounted for in gross emission totals.
(14) Centralia land disturbed and reclamation data has been restated for 2013 and 2014 due to data alignment with reporting to the Office of Surface Mining in Washington
State. The change impacted overall disturbed and reclaimed totals. The resulting change increased our total percentage of land reclamation. Land reclaimed includes
the percentage of mined land reclaimed at the Whitewood and Highvale coal mines at Wabamun, Alberta, and our surface mine in Centralia, Washington.
(15) Mining land use is total land disturbed minus reclaimed area.
(16) Historical land use data for 2014 was revised to include our Solomon gas facility, which is located in north Western Australia. The restatement was minor, as
adding eight hectares, and after rounding no change is evident.
(17) All environmental incidents are reported to an external regulatory agency, which may result in a fine, penalty, or corrective action.
(18) Substances released to the environment include, but are not limited to, ash, glycol, diesel, oils, and other chemicals. Our 2014 environmental spills and spill
recovery volumes were restated due to revision of the reporting boundary for spills.
(19) TransAlta acquired SunHills in 2013 and with it over 600 employees, the majority of which are unionized. The value of 33 per cent in 2013 is not inclusive of
unionized employees from SunHills as at year-end December 31, 2013. Employee-specific data from SunHills was integrated further in 2014.
(20) The process to determine voluntary turnover has been revised to align with our HR voluntary turnover reporting methodology. As per this methodology,
voluntary turnover is any exit initiated by a full-time, part-time, or contingent employee, excluding retirement. Summer students and temporary workers are not
considered within voluntary turnover. Historical values for 2013 and 2014 have been revised to align with this approach. In 2015 we began including employees
from SunHills in our turnover calculations. SunHills was acquired in 2013 and represents our employees at the Highvale mine, which is adjacent to our Alberta
coal operations west of Edmonton.
(21) Our total percentage of women in the workforce declined slightly as a result of corporate restructuring in 2015.
(22) Our total percentage of women in senior management declined as a result of corporate restructuring in 2015. Our pool of Vice-Presidents and Directors was
reduced from 70 employees to 23 employees in 2015 and combined into a Managing Director level.
(23) Health and safety incidents resulting in a regulatory enforcement action. Enforcement actions could take the form of a warning letter, fine, or non-financial
reprimand or restriction on operations.
(24) The injury frequency rate (IFR) measures work-related medical aid and lost-time injuries per 200,000 hours worked. IFR is calculated using a combination of
actual and estimated exposure hours. During the course of the year, all work-related safety incidents are investigated. These investigations may provide new
information that would result in an incident being reclassified.
(25) The disabling injury frequency rate is calculated based on the number of injuries requiring absence from work (lost-time incidents) only.
(26) Cumulative of donations and sponsorship totals in the respective calendar year. This investment figure does not include donations from our employees.
191
TransAlta Corporation | 2015 Annual Integrated Report Ernst & Young Independent Limited Assurance Statement
To the Board of Directors and Management of TransAlta Corporation (“TransAlta”).
Our Responsibilities
Our limited assurance engagement has been planned and
performed in accordance with the International Standard on
Assurance Engagements (ISAE) 3000 “Assurance
Engagements Other than Audits or Reviews of Historical
Financial Information.”
Subject Matter
We have performed a limited assurance engagement on the
following quantitative sustainability performance indicators
that are presented on pages 189 to 191 of the TransAlta
Annual Integrated Report (“the Report”) for the year ended
December 31, 2015:
• Sulphur dioxide emissions and emission intensity
(tonnes, kg/MWh)
• Nitrogen oxide emissions and emission intensity
(tonnes, kg/MWh)
• Particulate matter emissions and emission intensity
(tonnes, kg/MWh)
• Mercury emissions and emission intensity
(kg, mg/MWh)
• Carbon dioxide emissions (tonnes CO2e)
• Methane emissions (tonnes CO2e)
• Nitrous oxide emissions (tonnes CO2e)
• Total transportation greenhouse gas emissions
(tonnes CO2e)
• Gross greenhouse gas emissions and emission intensity
(tonnes CO2e, tonnes CO2e/GWh)
• Scope 1 GHG emissions (tonnes CO2e)
• Scope 2 GHG emissions (tonnes CO2e)
• Land use – Disturbed, reclaimed (cumulative hectares)
• Land reclamation (% of former land reclaimed)
• Land used in mining activities (hectares)
• Land used by plants, offices, and equipment (hectares)
• Total environmental incidents
• Volume of spills (m3)
• Voluntary employee turnover rate (%)
• Women in the workforce (%)
• Women in senior management (%)
• Employee and contractor fatalities
• Lost-time injuries for employees and contractors
(LTI) (absence from work)
• Medical aids (MA) for employees and contractors
(no absence from work)
• Total injuries to employees and contractors
• Employee and contractor recordable (LTI & MA)
injury frequency rate (injuries/200,000 hours)
• Employee and contractor disabling (LTI) injury
frequency rate (injuries/200,000 hours)
• Community investments ($ millions)
Criteria
TransAlta has prepared its specified performance information
in accordance with industry standards and, where relevant,
internally developed criteria.
TransAlta Management Responsibilities
The Report was prepared by the management of TransAlta,
who is responsible for the collection and presentation of the
performance indicators, statements, claims in the Report,
and the criteria used in determining that the information
is appropriate for the purpose of disclosure in the Report.
In addition, management is responsible for maintaining
adequate records and internal controls that are designed
to support the reporting process.
Level of Assurance
Our procedures were designed to obtain a limited level of
assurance on which to base our conclusions. The procedures
conducted do not provide all the evidence that would be
required in a reasonable assurance engagement and,
accordingly, we do not express a conclusion conveying
a reasonable level of assurance. While we obtained an
understanding of management’s internal processes when
determining the nature and extent of our procedures, our
limited assurance engagement was not designed to express
a conclusion on internal controls.
192
TransAlta Corporation | 2015 Annual Integrated Report Work Performed
In order for us to express a conclusion in relation to the above
scope of work, we have sought to answer the following
questions for the performance indicators reviewed:
Completeness
•
Has TransAlta fairly presented performance information
concerning the selected performance indicators with
respect to the boundaries and time period defined in
the Report?
Has TransAlta included sustainability performance
information from all material entities in its defined
boundary for its reporting of the selected performance
indicators?
Has TransAlta accurately collated corporate data r
elating to the selected performance indicators from
operations-level data?
•
•
Accuracy
• Is the data reported for the selected performance
indicators sufficiently accurate and detailed for
stakeholders to assess TransAlta’s performance?
Our assurance procedures at TransAlta’s corporate head
office included but were not limited to:
• Interviewing selected personnel at Corporate and selected
sites to understand the key sustainability issues related to
the selected performance data and processes for the
collection and accurate reporting of performance
information
• Where relevant, obtaining an understanding of the design
and implementation of systems and processes for data
aggregation and reporting
• Checking key assumptions against the evidence to support
the assumptions
• Checking the accuracy of calculations performed, on a test
basis, primarily through inquiry, variance analysis, and
re-performance of calculations and analytical procedures
• Checking that data and statements had been correctly
transcribed from corporate systems and/or supporting
evidence into the Report
Ernst & Young Independent Limited Assurance Statement
Limitations of our Work Performed
Our scope of work did not include expressing conclusions in
relation to:
• The materiality, completeness, or accuracy of data sets or
information relating to areas other than the selected
performance data, and any site-specific information
• Information reported outside of the Report
• Management’s forward-looking statements
• Any comparisons made by TransAlta against historical data
• The appropriateness of definitions for internally developed
criteria
Our Conclusion
Based on our procedures for this limited assurance
engagement described in this Report, nothing has come
to our attention that causes us to believe that the Subject
Matter is not, in all material respects, reported in accordance
with the relevant criteria.
Ernst & Young LLP
Calgary, Canada
February 17, 2016
193
TransAlta Corporation | 2015 Annual Integrated Report Shareholder Information
Special Services for Registered Shareholders
Service
Description
Direct deposit for
dividend payments
Account
consolidations
Automatically have dividend payments deposited
to your bank account
Eliminate costly duplicate mailings by consolidating
account registrations
Address changes and
share transfers
Receive tax slips and dividends without the delays
resulting from address and ownership changes
Stock Splits and Share Consolidations
Date
Events
May 8, 1980
Feb. 1, 1988
Dec. 31, 1992
Stock split
Stock split(1)
Reorganization – TransAlta Utilities shares exchanged
for TransAlta Corporation shares(2) 1:1
The valuation date value of common shares owned on Dec. 31, 1971, adjusted for stock splits, is $4.54 per share.
(1) The adjusted cost base for shares held on Jan. 31, 1988, was reduced by $0.75 per share following the Feb. 1,
1988 share split.
(2) TransAlta Utilities Corporation became a wholly owned subsidiary of TransAlta Corporation as a result of
this reorganization.
Dividend Declaration for Common Shares
Dividends are paid quarterly as determined by the Board. Dividends on our
common shares are at the discretion of the Board. In determining the payment and
level of future dividends, the Board considers our financial performance, results of
operations, cash flow and needs, with respect to financing our ongoing operations
and growth, balanced against returning capital to shareholders. The Board
continues to focus on building sustainable earnings and cash flow growth.
Common Share Dividends Declared in 2015
Record Date
Payment Date
Ex-Dividend Date
April 1, 2015
July 1, 2015
Oct. 1, 2015
Jan. 1, 2016
March 2, 2015
June 1, 2015
Sept. 1, 2015
Dec. 1, 2015
Feb. 26, 2015
May 28, 2015
Aug. 28, 2015
Nov. 27, 2015
Dividend
$0.18
$0.18
$0.18
$0.18
Dividends are paid on the first of the month in January, April, July and October. When a dividend payment date
falls on a weekend or holiday, the payment is made on the following business day. Only dividend payments that
have been approved by the Board of Directors are included in this table.
Submission of Concerns Regarding Accounting
or Auditing Matters
TransAlta has adopted a procedure for employees, shareholders or others to report
concerns or complaints regarding accounting or other matters on an anonymous,
confidential basis to the Audit and Risk Committee of the Board of Directors. Such
submissions may be directed to the Audit and Risk Committee c/o the Chief Legal
and Compliance Officer and Corporate Secretary of the Corporation.
Annual Meeting
The Annual Meeting of Shareholders
will be held at 10:00 a.m. MST,
on Friday, April 22, 2016 at Hotel Arts
119 - 12th Avenue SW, Calgary, Alberta.
Transfer Agent
CST Trust Company*
P.O. Box 700 Station “B”
Montreal, Quebec H3B 3K3
Phone
North America:
1.800.387.0825 toll-free
Toronto/outside North America:
416.682.3860
E-mail
inquiries@canstockta.com
Fax
514.985.8843
Website
www.canstockta.com
Exchanges
Toronto Stock Exchange (TSX)
New York Stock Exchange (NYSE)
Ticker Symbols
TransAlta Corporation common shares:
TSX: TA, NYSE: TAC
TransAlta Corporation preferred shares:
TSX: TA.PR.D, TA.PR.F, TA.PR.H, TA.PR.J
* CST Trust Company has succeeded CIBC Mellon Trust
Company as our transfer agent. On Nov. 1, 2010, CIBC
Mellon Trust Company sold its issuer services business
to Canadian Stock Transfer Company Inc., which
operated the business on their behalf until Aug. 30,
2013, at which time CST Trust Company, an affiliate of
Canadian Stock Transfer Company Inc., received federal
approval to commence business.
194
TransAlta Corporation | 2015 Annual Integrated Report Shareholder Information
Dividend Declaration for Preferred Shares
Series A: Fixed cumulative preferential cash dividends are paid quarterly when
declared by the Board at the annual rate of $1.15 per share from the date of issue
Dec. 10, 2010 to but excluding March 31, 2016.
Voting Rights
Common shareholders receive one
vote for each common share held.
Additional Information
Requests can be directed to:
Investor Relations
TransAlta Corporation
110 - 12th Avenue S.W.
P.O. Box 1900, Station “M”
Calgary, Alberta T2P 2M1
Phone
North America:
1.800.387.3598 toll-free
Calgary/outside North America:
403.267.2520
E-mail
investor_relations@transalta.com
Fax
403.267.7405
Website
www.transalta.com
Series C: Fixed cumulative preferential cash dividends are paid quarterly when
declared by the Board at the annual rate of $1.15 per share from the date of issue
Nov. 29, 2011 to but excluding June 30, 2017.
Series E: Fixed cumulative preferential cash dividends are paid quarterly when
declared by the Board at the annual rate of $1.25 per share from the date of issue
Aug. 10, 2012 to but excluding Sept. 30, 2017.
Series G: Fixed cumulative preferential cash dividends are paid quarterly when
declared by the Board at the annual rate of $1.325 per share from the date of issue
Aug. 15, 2014 to but excluding Sept. 30, 2019.
Preferred Share Dividends Declared in 2015
Series A
Payment Date
March 31, 2015
June 30, 2015
Sept. 30, 2015
Dec. 31, 2015
Series C
Payment Date
March 31, 2015
June 30, 2015
Sept. 30, 2015
Dec. 31, 2015
Series E
Payment Date
March 31, 2015
June 30, 2015
Sept. 30, 2015
Dec. 31, 2015
Series G
Payment Date
March 31, 2015
June 30, 2015
Sept. 30, 2015
Dec. 31, 2015
Record Date
March 2, 2015
June 1, 2015
Sept. 1, 2015
Dec. 1, 2015
Record Date
March 2, 2015
June 1, 2015
Sept. 1, 2015
Dec. 1, 2015
Record Date
March 2, 2015
June 1, 2015
Sept. 1, 2015
Dec. 1, 2015
Record Date
March 2, 2015
June 1, 2015
Sept. 1, 2015
Dec. 1, 2015
Ex-Dividend Date
Feb. 26, 2015
May 28, 2015
Aug. 28, 2015
Nov. 27, 2015
Ex-Dividend Date
Feb. 26, 2015
May 28, 2015
Aug. 28, 2015
Nov. 27, 2015
Ex-Dividend Date
Feb. 26, 2015
May 28, 2015
Aug. 28, 2015
Nov. 27, 2015
Ex-Dividend Date
Feb. 26, 2015
May 28, 2015
Aug. 28, 2015
Nov. 27, 2015
Dividend
$0.2875
$0.2875
$0.2875
$0.2875
Dividend
$0.2875
$0.2875
$0.2875
$0.2875
Dividend
$0.3125
$0.3125
$0.3125
$0.3125
Dividend
$0.33125
$0.33125
$0.33125
$0.33125
Dividends are paid on the last day of the month in March, June, September, and December. When a dividend
payment date falls on a weekend or holiday, the payment is made on the following business day. Only dividend
payments that have been approved by the Board of Directors are included in this table.
195
TransAlta Corporation | 2015 Annual Integrated Report Shareholder Highlights
150
125
100
75
50
25
Total Shareholder Return vs. S&P/TSX Composite Index
Year ended Dec. 31 ($)
TransAlta
S&P/TSX Composite
06
100
100
07
130
107
08
98
70
09
100
10
95
91
104
11
100
93
12
77
96
13
74
106
14
62
113
15
31
101
This chart compares what $100 invested in TransAlta and the S&P/TSX Composite at the end of 2006 would be
worth today, assuming the reinvestment of all dividends.
06
07
08
09
10
11
12
13
14
15
TransAlta
S&P/TSX Composite
Source: Thomson Financial
40.00
30.00
20.00
10.00
Ten-Year Trading Range and Market Value vs. Book Value
Year ended Dec. 31 ($ per share)
06
07
08
09
10
11
12
13
14
Market Value
26.64 33.35 24.30 23.48
21.15
21.02
15.12
13.48
10.52
Book Value
11.99
11.39
12.70
13.41
12.85
12.08
8.78
7.92
8.52
15
4.91
8.52
Amounts presented or included in calculations prior to 2010 represent Canadian Generally Accepted Accounting
Principles (GAAP) figures and have not been restated under International Financial Reporting Standards (IFRS).
06
07
08
09
10
11
12
13
14
15
Market Value
Book Value
Trading Range
Source: Thomson Financial and TransAlta
60
50
40
30
20
10
15.00
10.00
5.00
Monthly Volume and Market Prices
(2015)
Volume (millions)
Jan
15
Feb Mar Apr May
18
21
15
14
Jun
25
Jul Aug
Sep Oct Nov Dec
20
24
56
31
42
29
TSX closing price
11.12 11.78 11.75 12.00 10.80 9.68 8.29 6.58 6.20 6.10 5.37 4.91
Source: Thomson Financial
J
JMAMF
DNOSAJ
Volume
(millions of shares)
TSX closing price
($ per share)
Return on Common Shareholders’ Equity
(%)
ROE
06
1.8
07
13.1
08
9.4
09
6.9
10
9.6
11
12
13
10.6 (25.9)
(3.2)
14
6.3
15
(1.2)
Amounts presented or included in calculations prior to 2010 represent GAAP figures and have not been restated
under IFRS.
The methodologies and ratios used by rating agencies to assess our credit rating are not publicly disclosed. We
have developed our own definitions of ratios and targets to manage our capital. These metrics and ratios are not
defined under IFRS, and may not be comparable to those used by other entities or by rating agencies.
Source: TransAlta
06
07
08
09
10
11
12
13
14
15
30
20
10
0
(10)
(20)
(30)
196
TransAlta Corporation | 2015 Annual Integrated Report Corporate Information
Corporate Governance:
New York Stock Exchange Disclosure Differences
TransAlta’s Corporate Governance Guidelines, Board Charter, Committee
Charters, position descriptions for the Chair, Committee Chair, President & CEO,
and codes of business conduct and ethics are available on our website at www.
transalta.com. Also available on our website is a summary of the significant ways
in which TransAlta’s corporate governance practices differ from those required
to be followed by U.S. domestic companies under the New York Stock Exchange’s
listing standards. Currently there are no differences between our governance
practices and those of the New York Stock Exchange.
Ethics Helpline
The Board of Directors has established an anonymous and confidential internet
portal, email address and toll-free telephone number for employees, contractors,
shareholders and other stakeholders to contact with respect to accounting
irregularities, ethical violations or any other matters they wish to bring to the
attention of the Board.
The Ethics Helpline phone number is 1.855.374.3801 (U.S./Canada)
and 1.800.339276 (Australia)
Internet portal: transalta.ethicspoint.com
E-mail: TA_ethics_helpline@transalta.com
Any communications to the Board of Directors may also be sent to
corporate_secretary@transalta.com
TransAlta Corporate Officers
Dawn L. Farrell
President and Chief Executive Officer
Donald Tremblay
Chief Financial Officer
Brett M. Gellner
Chief Investment Officer
Dawn E. de Lima
Chief Administrative Officer
John H. Kousinioris
Chief Legal and Compliance Officer
and Corporate Secretary
Cynthia Johnston
Executive Vice-President, Gas,
Renewables & Operations Services
Wayne A. Collins
Executive Vice-President,
Coal and Mining Operations
Jennifer M. Pierce
Senior Vice-President,
Trading & Marketing
Todd J. Stack
Managing Director and Treasurer
Ben Park
Managing Director,
Corporate Controller
Scott Jeffers
Assistant Corporate Secretary
and Legal Counsel
197
TransAlta Corporation | 2015 Annual Integrated Report Glossary of Key Terms
Alberta 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.
Availability
A measure of 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.
Boiler
A device for generating steam for power, processing or
heating purposes, or for producing hot water for heating
purposes or hot water supply. Heat from an external
combustion source is transmitted to a fluid contained within
the tubes of the boiler shell.
Capacity
The rated continuous load-carrying ability, expressed in
megawatts, of generation equipment.
Cogeneration
A generating facility that produces electricity and another
form of useful thermal energy (such as heat or steam) used
for industrial, commercial, heating, or cooling purposes.
Combined Cycle
An electric generating technology in which electricity is
produced from otherwise lost waste heat exiting from one or
more gas (combustion) turbines. The exiting heat is routed to
a conventional boiler or to a heat recovery steam generator for
use by a steam turbine in the production of electricity. This
process increases the efficiency of the electric generating unit.
Derate
To lower the rated electrical capability of a power generating
facility or unit.
Expected Capacity
Plant capacity after consideration of station service use,
planned outages, forced and maintenance outages, and derates.
Force Majeure
Literally means “greater force.” These clauses excuse a party
from liability if some unforeseen event beyond the control of
that party prevents it from performing its obligations under
the contract.
Gigajoule (GJ)
A metric unit of energy commonly used in the energy industry.
One GJ equals 947,817 Btu.
Gigawatt (GW)
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)
A gas that has the 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.
Merchant Assets
TransAlta uses the term merchant to describe assets that
have contracts with terms of less than five years. Given our
low-to-moderate risk profile, TransAlta contracts a significant
portion of its merchant capability through short- and medium-
term contracts.
198
TransAlta Corporation | 2015 Annual Integrated Report Glossary of Key Terms
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.
Renewable Power
Power generated from renewable terrestrial mechanisms
including wind, geothermal, solar, and biomass with
regeneration.
Reserve Margin
An indication of a market’s capacity to meet unusual demand
or deal with unforeseen outages/shutdowns of generating
capacity.
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 the 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 shutdown 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 used to manage exposure to market risk from
commodity risk management activities.
In an effort to be environmentally responsible, please notify your financial institution if you are receiving duplicate mail ings of this annual report.
The TransAlta design and TransAlta wordmark are trademarks of TransAlta Corporation.
This report was printed in Canada. The paper, paper mills, and printer are all Forest Stewardship Council certified, which is an
international network that promotes environmentally appropriate and socially beneficial management of the world’s forests.
Design & Production: One Design Inc.
Printing: McAra Printing
TransAlta Corporation
110 - 12th Avenue SW
Box 1900, Station “M”
Calgary, Alberta
Canada T2P 2M1
403.267.7110
www.transalta.com