Balance Wins
TransAlta Corporation
2016 Annual Integrated Report
Letter to Shareholders
Management’s Discussion and Analysis
Consolidated Financial Statements
Notes to Consolidated Financial Statements
Eleven-Year Financial and Statistical Summary
Plant Summary
Sustainability Performance Indicators
Independent Sustainability Assurance Statement
Shareholder Information
Shareholder Highlights
Corporate Information
Glossary of Key Terms
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Letter to Shareholders
2016 was a remarkable, challenging and productive year for TransAlta. With
the parameters of our company’s new carbon obligations defined, we can turn
our attention to our strategic vision for the future of the company: becoming
Canada’s leading clean power company. We believe the achievements of 2016
have restored value to TransAlta in the market and the execution of our strategy
will continue to do so.
Throughout 2016, our actions were guided by three strategic themes: Execution
Advantage, Balance Wins and History Repeats.
Execution Advantage
The execution of a mutually acceptable coal transition
agreement with the Government of Alberta was the
culmination of our top priority for 2016. With that overhang
relieved, investors once again can see TransAlta as a leading
power generator with competitive assets in strategic
energy markets.
3. Begin to develop our Brazeau Pumped Storage project,
one of the leading hydro power projects on the drawing
board in Canada; and
4. Develop a capacity market in Alberta that ensures both
current and new electricity generators will have a level
economic playing field to build, buy and sell electricity.
Our experienced, skilled and hard-working teams
accomplished the following:
• We signed an Off-Coal Agreement with the Government
of Alberta to eliminate coal-fired emissions from our
Keephills 3, Genesee 3 and Sheerness generating plants by
2030. This agreement entitles the company to 14 annual
payments of $37.4 million, starting in 2017.
• We signed a Memorandum of Understanding (MOU) with
the Government of Alberta that outlines our future
co-operative work to:
1. Enable our Alberta coal plants to transition to natural
gas and extend their useful lives;
2. Realize additional value in our hydro and wind assets
through greenhouse gas offset credits;
• Financially, we met our 2016 goals by delivering comparable
EBITDA of $1.15 billion, comparable funds from operations
of $763 million and comparable free cash flow of $299
million. And we did this in one of the lowest commodity
price cycles ever experienced in the Alberta market.
• We raised approximately $360 million of project debt and
now have access to $1.7 billion in liquidity. This will be used
to settle the US$400 million of senior notes with maturities
coming due in June 2017. We continue to make progress on
our goal to reposition our capital structure and strengthen
the balance sheet. We maintained our investment grade
credit ratings with S&P, Fitch and DBRS.
• Operationally, we delivered fleet availability of 89%, just
ahead of 2015. Our Injury Frequency Rate of 0.85 was the
second-best in our company’s history, but unfortunately
higher than our record of 0.75 set in 2015. Safety remains
a top priority.
TransAlta Corporation | 2016 Annual Integrated Report
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Letter to Shareholders
• We advanced construction of our South Hedland 150
megawatt (MW) combined cycle gas-fired power plant in
Port Hedland, Australia, which we expect to commission
in mid-2017.
• We executed a new contract with the Ontario Independent
Electricity System Operator for the 108 MW Mississauga
cogeneration facility. The new contract will provide us with
fixed monthly payments until the end of 2018, with no
delivery obligations.
• We won an arbitration upholding TransAlta’s force majeure
claim at Keephills, which allowed us to reverse the
approximately $95 million provision.
We are proud of our accomplishments in 2016. We enter
2017 with initiatives to push even harder on safety, availability
and costs. We want our customers to continue to receive the
highest value for their money. We know that standing still
leads to complacency, and that managing change, disruption
and innovation are necessary to succeed in meeting the
needs of our customers and investors.
Balance Wins
Our second strategic theme was “Balance Wins.” The 2015
Alberta Climate Leadership Plan set out challenging goals,
including the phase-out of coal by 2030, paying a $30 per
tonne carbon tax starting in 2018 and adding 5,000 MW of
renewables over the next 13 years. To put this renewables
growth target in context, it has taken approximately 105 years
to develop Alberta’s 16,400 MW system of power generation.
Last year, the Canadian federal government also proposed a
framework in which each province is expected to implement
a greenhouse gas policy equivalent to a carbon price of $50
per tonne by 2022.
Our challenge was to create a transition plan that would
restore value in TransAlta’s existing coal-fired plants. This
meant the need to devise solutions that would maintain
Alberta’s competitiveness and keep prices reasonable and
affordable for consumers and our customers, while preserving
positive economics for the company.
The combination of the Off-Coal Agreement, the MOU, and
the Province’s move to a capacity market struck the balance
needed to move forward constructively. Our next step is to
work with the Government of Alberta to create the rules and
systems that will support a functioning, resilient capacity
market. This will be complicated and will take time.
Our expectation is that by the end of 2020, when the current
coal and hydro Power Purchase Arrangements (PPAs) roll off,
we will transition to a new market that will price capacity and
energy payments separately for our assets. In this interim
period, our current PPAs will continue to provide a secure
source of cash flows from our Alberta assets.
We expect that all our assets will continue to be competitive
in this new market. We also expect that new regulations on
coal-to-gas conversions will permit us to extend the useful
lives of our existing coal assets. This is necessary to maintain
our cash flow and to keep prices affordable for consumers in
the new capacity-based regime.
The best news is that the continued cash flow from our
generating assets will provide investors with a clear line of
sight as to how we can refinance debt during this transition
to a new market structure. This sustains investor confidence.
There is more work ahead as we advocate for the necessary
rules to permit and regulate coal-to-gas conversions and
operate in a new capacity market. We must ensure we can
economically transition our plants, and receive fair returns on
the capital invested on behalf of investors.
Our “Balance Wins” strategy will continue to guide us. We
know that what works for customers in the long run also
protects investors.
History Repeats
Our journey to become the largest electric power generator
in Alberta started in 1911, when Calgary Power’s entrepreneurs
built the first hydro plant on the Bow River. Today, these
original hydro plants continue to operate and support
Alberta’s power system.
In 1956, TransAlta commissioned its first large, centralized
coal-fired generating plants, and in the 1980s added natural
gas and cogeneration plants. In the new millennium, we built
and acquired wind power, and in 2015 we invested in our first
solar plant. As a result, TransAlta today is a 105-year old
company with a diversified fleet of more than 70 power
plants across Canada, the United States and Australia.
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TransAlta Corporation | 2016 Annual Integrated Report
“
Our Balance Wins strategy will continue to guide us. We know that what works
for customers in the long run also protects investors.
Many of our Alberta assets were developed and paid for
under a regulated power regime. Since 2000, some plants,
such as Genesee 3 and Keephills 3, were commissioned
under a deregulated power regime. A price on carbon was
not included in either system. Going forward, electricity
pricing will continue to be deregulated, but will now include
a new cost input: a price on carbon.
• Commission the South Hedland power station, which will
contribute new cash flows for investors in TransAlta and in
TransAlta Renewables;
• Work with the Government of Alberta to design a path
that will advance our investment in the Brazeau Pumped
Storage project;
Customers will always need affordable and reliable power.
Our job now is to make power affordable by finding ways to
mitigate expensive carbon taxes.
• Work to help design a capacity market that will be fair to
existing generators, keep prices affordable for consumers,
and incent new investment;
Our non-emitting hydro assets are even more valuable in this
system. Investing in projects such as our Brazeau Pumped
Storage hydro expansion will be good for both investors and
customers. This 600 MW to 900 MW project will act like a
storage battery to support intermittent renewable power.
Our journey back to our historic roots in hydro and the
repurposing of our existing coal plants to burn lower-
emitting, on-demand natural gas are both important. These
actions ensure that TransAlta will remain an important player
in the Alberta power market.
Looking Ahead
Today, TransAlta is a multi-regional power company that
generates baseload electricity with low-cost coal as part of
its competitive advantage. We have the asset base and the
optionality to remain strong in our regions. As we strengthen
our balance sheet, we will have the additional financial
flexibility to make sound and profitable investments for the
future. Our goal to be Canada’s leading clean power company
remains front and center in all our decisions.
In 2017, our three themes will continue to guide us. We will
add a fourth theme: “Accelerating Competitiveness.” We will
accelerate investments to create new competitive pricing
and environmental advantages that will permit our company
to excel in a world in which carbon will be expensive and
customers continue to want affordable and clean power.
Our specific goals for 2017 are to:
• Execute on all our financial and operational goals, using the
cash generated to both reduce debt and invest for the
future. Our 2017 Financial Outlook, found on page M60 of
this report, outlines these goals;
• Establish the detailed terms and conditions to extend the
useful lives of our coal fleet by converting them to gas fuel
and preparing them for the new capacity market;
• Pursue new long-term contracts on proposed wind
projects in Saskatchewan and Alberta;
• Evolve and implement a more competitive business model
and cost structure that works for more distributed gas and
renewable plants across several regions.
There is a lot to do and we are already moving to execute our
plans to achieve each of these goals.
The hard work of 2016 demonstrates that TransAlta can and
will successfully transition into the evolving clean power era.
It also lays the foundation for continued cash flow from
existing assets that will support the investments for what we
do best – generate affordable and reliable power for all our
customers. 2016 was a transformational year and we look
forward to the future.
Thank you.
Dawn L. Farrell
President and Chief Executive Officer
Ambassador Gordon D. Giffin
Chair of the Board of Directors
March 2, 2017
TransAlta Corporation | 2016 Annual Integrated Report
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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
Business Model
Highlights
Additional IFRS Measures and Non-IFRS Measures
Reconciliation of Non-IFRS Measures
Business Model
Comparable Results
Highlights
Competitive Forces
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M5
M3
M8
M4
M12
M5
M26
Financial Instruments
2017 Financial Outlook
Financial Instruments
Governance and Risk Management
Critical Accounting Policies and Estimates
2017 Financial Outlook
M58
M60
M58
M64
M75
M60
Accounting Changes
Governance and Risk Management
Fourth Quarter
Critical Accounting Policies and Estimates
Reconciliation of Non-IFRS Measures
Reconciliation of Non-IFRS Measures
TransAlta’s Capitals
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M28
Accounting Changes
Selected Quarterly Information
Other Consolidated Analysis
Comparable Results
M50
M12
Disclosure Controls and Procedures
Fourth Quarter
Competitive Forces
TransAlta’s Capital
Other Consolidated Analysis
M26
M28
M50
Reconciliation of Non-IFRS Measures
Selected Quarterly Information
Disclosure Controls and Procedures
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M82
M84
M75
M86
M82
M90
M91
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M86
M90
M91
This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with our audited annual 2016 consolidated
financial statements and our Annual Information Form for the year ended Dec. 31, 2016. Our consolidated financial statements have
been prepared in accordance with International Financial Reporting Standards (“IFRS”) for Canadian publicly accountable enterprises
as issued by the International Accounting Standards Board (“IASB”) and in effect at Dec. 31, 2016. All dollar amounts in the following
discussion, including the tables, are in millions of Canadian dollars unless otherwise noted and except amounts per share which are in
whole dollars to the nearest two decimals. This MD&A is dated March 2, 2017. Additional information respecting TransAlta
Corporation (“TransAlta”, “we”, “our”, “us”, or the “Corporation”), including our Annual Information Form, is available on SEDAR at
www.sedar.com, on EDGAR at www.sec.gov, and on our website at www.transalta.com. Information on or connected to our website
is not incorporated by reference herein.
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TransAlta Corporation | 2016 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 2017 Financial Outlook section
and Sustainable Development Targets section of this MD&A, are presented for general information purposes only and not as
specific investment advice. All forward-looking statements are based on our beliefs as well as assumptions based on information
available at the time the assumptions were made and on management’s experience and perception of historical trends, current
conditions, and expected future developments, as well as other factors deemed appropriate in the circumstances. Forward-
looking statements are not facts, but only predictions and generally can be identified by the use of statements that include
phrases such as “may”, “will”, “believe”, “expect”, “anticipate”, “intend”, “plan”, “project”, “forecast”, “foresee”, “potential”,
“enable”, “continue”, or other comparable terminology. These statements are not guarantees of our future performance and are
subject to risks, uncertainties, and other important factors that could cause our actual performance to be materially different
from that projected.
In particular, this MD&A contains forward-looking statements pertaining to our business and anticipated future financial
performance; our success in executing on our growth projects; the timing of the construction and commissioning of projects
under development, including major projects such as the South Hedland power project and the Sundance 7 project, and their
attendant costs; spending on growth and sustaining capital and productivity projects; expectations in terms of the cost of
operations, capital spending, and maintenance, and the variability of those costs; expected decommissioning costs; the
impact of certain hedges on future reported earnings and cash flows, including future reversals of unrealized gains or losses,
expectations relating to the dispositions of assets and the completion of sale transactions including the disposition of our
interest in the Wintering Hills wind facility; expectations related to future earnings and cash flow from operating and
contracting activities (including estimates of full-year 2017 comparable earnings before interest, taxes, depreciation, and
amortization (“EBITDA”), comparable funds from operations (“FFO”), comparable free cash flow (“FCF”), and expected
sustaining capital expenditures); expectations in respect of financial ratios and targets and the timing associated with meeting
such targets (including comparable FFO before interest to adjusted interest coverage, adjusted comparable FFO to adjusted
net debt, and adjusted net debt to comparable EBITDA); the Corporation’s plans and strategies relating to repositioning its
capital structure and strengthening its balance sheet and the debt reductions that are expected to occur in 2017 and beyond;
expected governmental regulatory regimes and legislation (including the Government of Alberta’s Climate Leadership Plan)
and proposed regulations to discontinue over time the use of technologies that our coal-fired plants currently utilize, and their
expected impact on TransAlta and the timing of the implementation of such regimes and regulations, as well as the cost of
complying with resulting regulations and laws; the expected results and impact of the recently signed Off-Coal Agreement
(“OCA”) and Memorandum of Understanding (“MOU”) with the Government of Alberta on our business and financial
performance; the outcome of discussions with the Government of Alberta in relation to potential opportunities for investment
in renewable and gas-fired generation; our comparative advantages over our competitors; estimates of fuel supply and
demand conditions and the costs of procuring fuel; expectations for demand for electricity in both the short term and long
term, and the resulting impact on electricity prices; our share of offer control in the Province of Alberta after the expiry of the
Power Purchase Arrangements (“PPAs”) at the end of 2020; the impact of load growth, increased capacity, and natural gas
costs on power prices; expectations in respect of generation availability, capacity, and production; expectations regarding the
role different energy sources will play in meeting future energy needs, including the impact of the anticipated elimination of
current excess system capacity and future growth in Alberta driven by the retirement of coal units over the next 15 years;
expected financing of our capital expenditures; the anticipated financial impact of increased carbon price (including under the
existing Specified Gas Emitters Regulation) (“SGER”) in Alberta; expectations in respect of our environmental initiatives; our
trading strategies and the risk involved in these strategies; estimates of future tax rates, future tax expense, and the adequacy
of tax provisions; accounting estimates; anticipated growth rates in our markets; our expectations regarding the outcome of
existing or potential legal and contractual claims, regulatory investigations, and disputes; expectations regarding the renewal
of collective bargaining agreements; expectations for the ability to access capital markets at reasonable terms; the estimated
impact of changes in interest rates and the value of the Canadian dollar relative to the US dollar, the Australian dollar, and
other currencies in which we do business; the monitoring of our exposure to liquidity risk; expectations regarding the impact
of the slowdown in the oil and gas sector; expectations in respect of the global economic environment and growing scrutiny
by investors relating to sustainability performance; our credit practices; expected cost savings following the implementation
of our efficiency and productivity initiatives; the estimated contribution of Energy Marketing activities to gross margin;
TransAlta Corporation | 2016 Annual Integrated Report
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Management’s Discussion and Analysis
expectations relating to the performance of TransAlta Renewables Inc.’s (“TransAlta Renewables”) assets; expectations
regarding our continued ownership of common shares of TransAlta Renewables; the refinancing our upcoming debt maturities
over the next two years by raising $700 million to $900 million of debt secured by contracted cash flows; expectations
regarding our de-leveraging strategy, including applying a portion of our free cash flow over the next four years to reduce debt
expectations in respect of our community initiatives; impacts of future IFRS standards; and amendments or interpretations by
accounting standard setters prior to initial adoption of those standards.
Factors that may adversely impact our forward-looking statements include risks relating to: fluctuations in market prices and the
availability of fuel supplies required to generate electricity; our ability to contract our generation for prices that will provide
expected returns; the regulatory and political environments in the jurisdictions in which we operate; increasingly stringent
environmental requirements and changes in, or liabilities under, these requirements; changes in general economic conditions,
including interest rates; operational risks involving our facilities, including unplanned outages at such facilities; disruptions in the
transmission and distribution of electricity; the effects of weather; disruptions in the source of fuels, water, or wind required to
operate our facilities; natural or man-made disasters; the threat of terrorism and cyberattacks and our ability to manage such
attacks; equipment failure and our ability to carry out or have completed the repairs in a cost-effective or timely manner;
commodity risk management; industry risk and competition; fluctuations in the value of foreign currencies and foreign political
risks; the need for additional financing and the ability to access financing at a reasonable cost; our ability to fund our growth
projects; our ability to maintain our investment grade credit ratings; structural subordination of securities; counterparty credit
risk; our ability to recover our losses through our insurance coverage; our provision for income taxes; legal, regulatory, and
contractual proceedings involving the Corporation; outcomes of investigations and disputes; reliance on key personnel; labour
relations matters; development projects and acquisitions, including delays or changes in costs in the construction of the South
Hedland power project; and the satisfactory receipt of applicable regulatory approvals for existing and proposed operations and
growth initiatives.
The foregoing risk factors, among others, are described in further detail in the Governance and Risk Management section of
this MD&A and under the heading “Risk Factors” in our 2017 Annual Information Form.
Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to
place undue reliance on these forward-looking statements. The forward-looking statements included in this document are
made only as of the date hereof and we do not undertake to publicly update these forward-looking statements to reflect new
information, future events, or otherwise, except as required by applicable laws. In light of these risks, uncertainties, and
assumptions, the forward-looking events might occur to a different extent or at a different time than we have described, or
might not occur. We cannot assure that projected results or events will be achieved.
Additional IFRS Measures and Non-IFRS Measures
An additional IFRS measure is a line item, heading, or subtotal that is relevant to an understanding of the financial statements
but is not a minimum line item mandated under IFRS, or the presentation of a financial measure that is relevant to an
understanding of the financial statements but is not presented elsewhere in the financial statements. We have included line
items entitled gross margin and operating income (loss) in our Consolidated Statements of Earnings (Loss) for the years
ended Dec. 31, 2016, 2015, and 2014. Presenting these line items provides management and investors with a measurement of
ongoing operating performance that is readily comparable from period to period.
We evaluate our performance and the performance of our business segments using a variety of measures. Certain of the
financial measures discussed in this MD&A are not defined under IFRS and, therefore, should not be considered in isolation or
as an alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from
operating activities, as determined in accordance with IFRS, when assessing our financial performance or liquidity. These
measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation or
as a substitute for measures prepared in accordance with IFRS. See the Comparable Funds from Operations and Comparable
Free Cash Flow, Discussion of Segmented Comparable Results, and Earnings on a Comparable Basis sections of this MD&A
for additional information.
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TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Business Model
Our Business
We are one of Canada’s largest publicly traded power generators with over 105 years of operating experience. We own,
operate, and manage a highly contracted and geographically diversified portfolio of assets representing nearly 9,000 MW(1) of
net generating capacity and use a broad range of generation fuels that include coal, natural gas, water, sun, and wind. We are
Canada’s largest generator of wind power and the largest generator of renewable energy in Alberta. Our energy marketing
operations maximize margins by securing and optimizing high-value products and markets for ourselves and our customers in
dynamic market conditions.
Vision and Values
Our vision is to be a leading clean energy company, using our expertise, scale, and diversified fuel mix to capitalize on
opportunities in our core markets and growing in areas where our competitive advantages can be employed. Our values are
grounded in accountability, integrity, safety, respect for people, innovation and loyalty which together create a strong
corporate culture and allow all of our people to work on a common ground and understanding. These values are at the heart of
our success.
Strategy for Value Creation
Our goals are to deliver solid returns by developing and operating assets in our three regions and among five fuel types. By
2030, our fleet will be fully transitioned from coal to natural gas and renewables. We maximize value by contracting assets,
achieving strong availability, and aiming for first-quartile costs. Our Energy Marketing group adds value to merchant assets
through optimization. We develop new greenfield projects and undertake merger and acquisition activities to ensure strategic
growth of cash flows over the long term. The transition from coal to natural gas and renewables provides significant
opportunity for future growth. In 2013, we launched TransAlta Renewables, our sponsored vehicle to own contracted gas and
renewable assets.
(1) We measure capacity as net maximum capacity (see Glossary of Key Terms for definition of this and other key terms), which is consistent with industry standards.
Capacity figures represent capacity owned and in operation unless otherwise stated, and reflect the basis of consolidation of underlying assets.
TransAlta Corporation | 2016 Annual Integrated Report
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Management’s Discussion and Analysis
Highlights
Consolidated Financial Highlights (1)(2) (2)
Year ended Dec. 31
Revenues
Comparable EBITDA(1)
Net earnings (loss) attributable to common shareholders
Comparable net earnings (loss) attributable to common shareholders(1)
Comparable FFO(1)
Cash flow from operating activities
Comparable FCF(1)
Net earnings (loss) per share attributable to common
shareholders, basic and diluted
Comparable net earnings (loss) per share(1)
Comparable FFO per share(1)
Comparable FCF per share(1)
Dividends declared per common share
As at Dec. 31
Total assets
Total debt(2)
Total long-term liabilities
2016
2,397
1,145
117
34
763
744
299
0.41
0.12
2.65
1.04
0.20
2016
10,996
4,056
5,116
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
In 2016, comparable EBITDA increased by $200 million to $1,145 million compared to 2015, with all segments other than U.S.
Coal delivering improved results over last year. The improved results throughout the year are a result of positive contributions
from renewable assets acquired in the second half of 2015, solid performance from our gas and renewables portfolios, cost
reduction initiatives across the fleet implemented in 2015, and the reversal of the $80 million provision relating to our Keephills 1
outage in 2013. Our highly contracted profile and hedging strategy mitigated the impact of lower prices during the year. The
decreased contribution from U.S. Coal is attributable to unfavourable market conditions in the Pacific Northwest. Last year’s
comparable EBITDA was impacted by a $59 million increase in our provision relating to the Keephills 1 outage in 2013.
Comparable FFO increased by $23 million to $763 million. The increase was lower than the increase in comparable EBITDA,
primarily due to the non-cash impact of the provision relating to our Keephills 1 outage, which was approximately $139 million
of the change in comparable EBITDA.
Reported net earnings attributable to common shareholders was $117 million ($0.41 net earnings per share) compared to a
net loss of $24 million ($0.09 net loss per share) in 2015. Comparable net earnings attributable to common shareholders was
$34 million ($0.12 net earnings per share), up from a comparable net loss of $48 million ($0.17 net loss per share) in 2015.
The improvements year-over-year primarily relate to contributions from assets we acquired in 2015, solid performance from
the renewable asset portfolio, and cost reduction initiatives. The Keephills 1 outage provision reversal also favourably
impacted 2016 net earnings. Our reported net earnings attributable to common shareholders in 2016 was impacted positively
by the Mississauga cogeneration recontracting ($48 million(3)) and negatively by the Wintering Hills wind facility impairment
($21 million(3)). Changes in the fair value of de-designated and economic hedges at U.S. Coal also had a negative impact on
our reported net earnings of $17 million(3,4) in 2016 (2015 – $38 million(3,4)).
(1) These items are not defined under IFRS. Presenting these items from period to period provides management and investors with the ability to evaluate earnings trends more
readily in comparison with prior periods’ results. Refer to the Comparable Funds from Operations and Comparable Free Cash Flow and Earnings on a Comparable Basis
sections of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.
(2) Total debt includes current portion, amounts due under credit facilities, long-term debt, tax equity, and finance lease obligations net of cash.
(3) Net of related income tax expense.
(4) Hedge accounting could not be applied to certain contracts, and accordingly, the mark-to-market on these contracts impacted reported earnings. The impacts of these
mark-to-market fluctuations have been removed from revenues to arrive at comparable results, which reflect the economic nature of these contracts.
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TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
2015’s reported net loss also included the gain on the Poplar Creek restructuring ($192 million(1)), the cost of the settlement
with the Market Surveillance Administrator (the “MSA”) ($55 million(1)), and a $95 million income tax expense related to an
internal reorganization. These items are not included in our comparable net earnings.
The decrease of $385 million in total debt, net of cash, is primarily due to repayment of debt using the proceeds received from
the sale to TransAlta Renewables of economic interests in the Canadian Assets (as defined below) completed in January
2016, free cash flows generated by the business, and the strengthening of the Canadian dollar.
Significant Events
At the beginning of the year we had three strategic objectives: first, work with the Government of Alberta to develop a plan
that would facilitate our transition from coal to natural gas and renewables; second, continue to improve our financial
condition and flexibility by reducing our total outstanding corporate debt and better aligning our debt maturities with the life
of our assets; and third, commit ourselves to achieving our operational goals (health and safety, equipment availability, and
environment). We made significant progress on our strategic objectives in 2016. Our results for the year demonstrate our
financial and operating stability. Specifically, we:
(cid:131)
Entered into an OCA with the Government of Alberta (the “Government”) for the cessation of coal-fired emissions at our
Alberta coal facilities. Under the terms of the OCA, we will receive transition payments of approximately $37.4 million
(our net share) from 2017 to 2030 for a total amount of approximately $524 million.
Entered into an MOU with the Government to collaborate and co-operate in the development of a policy framework to
facilitate coal-to-gas conversions and renewable electricity development, and ensure existing generation is able to
effectively participate in a future capacity market.
Signed a new contract for our Mississauga cogeneration facility effective Jan. 1, 2017, with Ontario’s Independent
Electricity System Operator (“IESO”) and terminated our existing contract early. The new contract, which expires in
December 2018, provides us with monthly payments totalling approximately $209 million over the term of the contract
with no delivery obligations. The new contract will allow us to reduce operational costs for this facility while retaining
flexibility to operate the facility should economic conditions permit.
Completed the sale to TransAlta Renewables of an economic interest in the Sarnia cogeneration facility and two
renewable energy facilities (collectively, the “Canadian Assets”) for aggregate proceeds valued at $540 million. Cash
proceeds of this transaction were $173 million. We also received 15.6 million common shares of TransAlta Renewables
and a $215 million convertible debenture. Proceeds were used to reduce TransAlta’s indebtedness. In November 2016,
the economic interest was converted to direct ownership of the Canadian Assets by TransAlta Renewables.
Repositioned our capital structure through two non-recourse bond issuances in 2016, through our subsidiaries, New
Richmond Wind L.P. and TAPC Holdings L.P., in the amounts of $159 million and $202.5 million, respectively. These
financings have aligned debt maturities with the contracted cash flows of the underlying assets.
Announced the sale of our 51 per cent interest in the 88 MW Wintering Hills merchant wind facility, located in Alberta,
for approximately $61 million in early 2017. The sale provides us with near-term liquidity, increases our financial
flexibility, and reduces our merchant exposure in Alberta.
Continued to advance the construction of the South Hedland power project. We expect the project to be delivered on
schedule and on budget in mid-2017.
Announced a reduction of our dividend to $0.16 per common share on an annualized basis from $0.72 previously. As a
result, our annual dividend is approximately $46 million, down from $205 million, thereby increasing our financial
flexibility.
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
These actions, coupled with our solid financial performance in 2016, are expected to build the financial capacity and flexibility
to address upcoming debt maturities and capitalize on growth opportunities in gas-fired and renewable generation that are
expected to arise as Alberta transitions from its reliance on coal-fired generation to cleaner sources of power generation.
(1) Net of related income tax expense.
TransAlta Corporation | 2016 Annual Integrated Report
M6
Management’s Discussion and Analysis
Reconciliation of Non-IFRS Measures
We evaluate our performance and the performance of our business segments using a variety of measures. Those discussed
below, and elsewhere in this MD&A, are not defined under IFRS and, therefore, should not be considered in isolation or as an
alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from operating
activities, as determined in accordance with IFRS, when assessing our financial performance or liquidity. These measures are
not necessarily comparable to a similarly titled measure of another company.
Comparable Funds from Operations and Comparable Free Cash Flow
Comparable FFO is an important metric as it provides a proxy for the amount of cash generated from operating activities
before changes in working capital, and provides the ability to evaluate cash flow trends more readily in comparison with
results from prior periods. Comparable FCF is an important metric as it represents the amount of cash generated by our
business, before changes in working capital, that is available to invest in growth initiatives, make scheduled principal
repayments on debt, repay maturing debt, pay common share dividends, or repurchase common shares. Changes in working
capital are excluded so as to not distort comparable FFO and comparable FCF with changes that we consider temporary in
nature, reflecting, among other things, the impact of seasonal factors and the timing of capital projects. Comparable FFO per
share and comparable FCF per share are calculated using the weighted average number of common shares outstanding during
the period.
(
The table below reconciles our cash flow from operating activities to our comparable FFO.
Year ended Dec. 31
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 California claim
Decrease in finance lease receivable
Restructuring costs
Maintenance costs related to Alberta flood of 2013,
net of insurance recoveries
Other
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
2016
744
(73)
671
25
57
4
-
6
763
(272)
1
(42)
(151)
299
288
2.65
1.04
2015
432
242
674
31
23
19
(9)
2
740
(305)
25
(46)
(99)
315
280
2.64
1.13
2014
796
(73)
723
33
3
-
1
2
762
(361)
4
(41)
(84)
280
273
2.79
1.03
M7
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Reconciliation of Comparable EBITDA and Comparable Net Earnings
Comparable EBITDA is a widely adopted valuation metric and an important metric for management that represents our core
business profitability. Interest, taxes, and depreciation and amortization are not included, as differences in accounting,
treatments may distort our core business results. A reconciliation of reported results to comparable results for the year ended
Dec. 31, 2016, is as follows:
Year ended Dec. 31
2016
Reported
Comparable
reclassifications
Comparable
adjustments
Comparable
total
Revenues
Fuel and purchased power
Gross margin
Operations, maintenance, and administration
Asset impairment
Restructuring
Taxes, other than income taxes
Net other operating (income) losses
EBITDA
Depreciation and amortization
Operating income
Finance lease income
Foreign exchange loss
Gain on sale of assets
Earnings (loss) before interest and taxes
Net interest expense
Income tax expense
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
2,397
963
1,434
489
28
1
31
(194)
1,079
601
478
66
(5)
4
543
229
38
276
107
169
52
117
288
0.41
(1, 2)
(3)
123
(65)
188
-
-
-
-
-
188
122
66
(2, 3, 4)
(66)
(1)
-
-
-
-
-
-
-
-
-
-
(5)
(9)
(8)
(10)
(9)
(9)
(17)
(15)
(18, 19, 20, 21)
(23)
26
(14)
40
-
(28)
(1)
-
191
(122)
(46)
(76)
-
(3)
(4)
(83)
-
4
(87)
(4)
(83)
-
(83)
2,546
884
1,662
489
-
-
31
(3)
1,145
677
468
-
(8)
-
460
229
42
189
103
86
52
34
288
0.12
TransAlta Corporation | 2016 Annual Integrated Report
M8
Management’s Discussion and Analysis
A reconciliation of reported results to comparable results for the year ended Dec. 31, 2015, is as follows:
Year ended Dec. 31
2015
Reported
Comparable
reclassifications
Comparable
adjustments
Comparable
total
Revenues
Fuel and purchased power
Gross margin
Operations, maintenance, and administration
Asset impairment reversals
Restructuring
Taxes, other than income taxes
Net other operating (income) losses
EBITDA
Depreciation and amortization
Operating income
Finance lease income
Foreign exchange gain
Gain on sale of assets
Earnings (loss) before interest and taxes
Net interest expense
Income tax expense
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 loss per share attributable
to common shareholders
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)
(1, 2)
(3)
81
(62)
143
-
-
-
-
-
143
85
58
(2, 3, 4)
(58)
(1)
-
-
-
-
-
-
-
-
-
-
(5)
(6)
(8)
(10)
(7, 11)
(17)
(12)
(18,19,20,21)
(23)
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
(0.17)
M9
TransAlta Corporation | 2016 Annual Integrated Report
A reconciliation of reported results to comparable results for the year ended Dec. 31, 2014, is as follows:
Management’s Discussion and Analysis
Year ended Dec. 31
Revenues
Fuel and purchased power
Gross margin
Operations, maintenance, and administration
Asset impairment reversal
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
Gain on sale of assets
Earnings before interest and taxes
Net interest expense
Income tax expense
Net earnings
Non-controlling interests
Net earnings 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
Comparable
reclassifications
2014
Comparable
adjustments
(54) (5)
-
(54)
(6) (6, 13)
(8)
6
-
-
(1) (7, 14)
(53)
-
(53)
-
4
(16)
(2) (15)
(51)
-
23
(18, 20, 22)
(74)
(1) (23)
(73)
-
(73)
(1, 2)
52
(3)
(56)
108
-
-
-
(4)
(1)
-
109
60
49
(2, 3, 4)
(1)
(49)
-
-
-
-
-
-
-
-
-
-
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
2,623
1,092
1,531
542
(6)
29
-
(14)
980
538
442
49
-
2
493
254
7
232
50
182
41
141
273
0.52
TransAlta Corporation | 2016 Annual Integrated Report
M10
Management’s Discussion and Analysis
The adjustments made to calculate comparable earnings for the years ended Dec. 31, 2016, 2015 and 2014 are as follows.
References are to the previous reconciliation tables.
Year ended Dec. 31
Reference
number
Adjustment
Reclassifications:
Segment
Financial Statement
line item
2016
2015
2014
1
2
3
4
Finance lease income used as a proxy for
operating revenue
Australian Gas
Revenues
Canadian Gas
Revenues
Decrease in finance lease receivable used as
a proxy for operating revenue and depreciation
Canadian Gas
Revenues
Australian Gas
Revenues
Reclassification of mine depreciation from fuel
and purchased power
Canadian Coal
Fuel and
purchased power
Reclassification of comparable gain on sale of
property, plant, and equipment that is included
in depreciation
Canadian Coal
Gain on sale of assets
Adjustments (increasing (decreasing) earnings to arrive at comparable results):
52
14
54
3
65
-
49
9
23
-
62
-
42
7
4
(1)
56
1
U.S. Coal
Revenues
26
60
(54)
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Impacts to revenue associated with certain
de-designated and economic hedges
Maintenance costs related to the Alberta flood
of 2013, net of insurance recoveries
Non-comparable portion of insurance
recovery received
Hydro
Hydro
Asset impairment charges (reversals)
U.S. Coal
Canadian Gas
Wind and Solar
Mississauga recontracting(1)
Canadian Gas
OM&A
Net other operating
(income) losses
Asset impairment
(reversals)
Asset impairment
(reversals)
Asset impairment
(reversals)
Net other operating
(income) losses
Restructuring expense
Canadian Coal
Restructuring
U.S. Coal
Restructuring
Canadian Gas
Restructuring
Hydro
Restructuring
Energy Marketing
Restructuring
Corporate
Restructuring
MSA settlement
Energy Marketing
Net other operating
(income) losses
Gain on Poplar Creek contract restructuring
Canadian Gas
Gain on sale of assets
Costs related to TAMA Transmission bid
Corporate
OM&A
California claim
Energy Marketing
Net other operating
(income) losses
Non-comparable gain on sale of assets
Equity Investments Gain on sale of assets
Corporate
Gain on sale of assets
Foreign exchange on California claim
Unassigned
Economic hedges of non-controlling interest in
intercompany foreign exchange contracts
Net tax effect on comparable adjustments
subject to tax
Deferred income tax rate adjustment
Reversal of writedown of
deferred income tax assets
Income tax expense related to temporary
difference on investment in subsidiary
Income tax recovery related to sale
of investment
Non-comparable items attributable to
non-controlling interest
Unassigned
Unassigned
Unassigned
Unassigned
Unassigned
Unassigned
Unassigned
Foreign exchange gain
(loss)
Foreign exchange gain
(loss)
Income tax expense
(recovery)
Income tax expense
(recovery)
Income tax expense
(recovery)
Income tax expense
(recovery)
Income tax expense
(recovery)
Non-controlling
interests
-
-
-
-
28
(131)
-
-
-
-
-
1
-
-
-
-
-
(4)
-
(3)
2
1
(9)
(18)
(2)
-
-
-
11
1
1
-
3
6
56
(262)
-
-
-
-
-
8
48
20
1
(4)
(5)
(1)
-
-
-
-
-
-
-
-
-
-
5
5
(2)
-
4
-
18
-
(10)
(56)
(5)
3
-
4
95
-
14
-
(36)
1
(1) Reported in net other operating (income) loss of ($191 million), depreciation and amortization of ($46 million), and fuel and purchased power of ($14 million).
M11
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Comparable Results
Discussion of Comparable FFO and Comparable FCF
The table below provides a reconciliation of our comparable EBITDA to our comparable FFO and comparable FCF.
Year ended Dec. 31
Comparable EBITDA
Provisions
Unrealized losses from risk management activities
Interest expense
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
Other non-cash 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
2016
1,145
(85)
3
(219)
(23)
1
(23)
-
(1)
(35)
763
(272)
1
(42)
(151)
299
2015
945
73
1
(230)
(19)
17
(24)
(8)
(7)
(8)
740
(305)
25
(46)
(99)
315
2014
1,036
-
4
(236)
(33)
11
(16)
-
-
(4)
762
(361)
4
(41)
(84)
280
Comparable FFO was $763 million for 2016 as compared to $740 million for 2015. The full year contribution from renewable
assets we acquired in late 2015 added $25 million to our comparable EBITDA and comparable FFO. Operations, maintenance,
and administration (“OM&A”) cost reduction initiatives across the fleet also increased comparable EBITDA and comparable
FFO. Lower prices in Alberta and the Pacific Northwest negatively impacted our business, but the impact was mitigated by the
high level of contracts and hedges in each market.
For the year ended Dec. 31, 2015, comparable FFO decreased by $22 million to $740 million compared to 2014, mainly due to
the higher outages and derates in Alberta, and lower prices in Alberta and the Pacific Northwest.
Comparable FCF for 2016 was down by $16 million, largely related to higher distributions paid to subsidiaries’ non-controlling
interests. Higher comparable FCF in 2015 compared to 2014 was mostly due to lower sustaining capital expenditures as a
result of reductions in mining expenditures, deferral of major work in Centralia as a result of economic dispatching, and
reductions in our gas-fired capital expenditures caused by the Poplar Creek recontracting.
Discussion of Segmented Comparable Results
In 2016, we disaggregated presentation of the previous Gas reportable segment into its two operating segments: Canadian
Gas and Australian Gas. Previously included legacy costs of the non-operating U.S. Gas function have been reallocated to U.S.
Coal to align with management’s internal monitoring practices. Comparative segmented results for 2015 and 2014 have been
restated to align with separate reporting of the two segments and the reallocation of the non-operating costs.
We evaluate our performance and the performance of our business segments using a variety of measures. Comparable figures
are not defined under IFRS. Refer to the Reconciliation of Non-IFRS Measures section of this MD&A for further discussion of
these items, including, where applicable, reconciliations to net earnings attributable to common shareholders.
TransAlta Corporation | 2016 Annual Integrated Report
M12
Management’s Discussion and Analysis
Each business segment assumes responsibility for its operating results measured to comparable EBITDA. Operating income
and gross margin are also useful measures as they provide management and investors with a measurement of operating
performance that is readily comparable from period to period.
Canadian Coal
Year ended Dec. 31
Availability (%)
Contract production (GWh)
Merchant production (GWh)
Total production (GWh)
Gross installed capacity (MW)
Revenues
Fuel and purchased power
Comparable gross margin
2016
85.3
19,823
2015
84.3
20,256
3,787
3,827
2014
88.6
21,748
3,806
23,610
24,083
25,554
3,791
3,786
3,771
1,048
912
1,023
386
379
436
662
533 587
Operations, maintenance, and administration
178 194
196
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
13
12 12
-
-
(1)
(2) (7) (9)
473
334
389
307
299
292
166
35
97
33
48
56
23
25
45
13
10
10
100
107
100
169
190
211
Insurance recoveries of sustaining capital expenditures
-
(7) -
Net amount
169
183
211
M13
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
2016
Production for the year ended Dec. 31, 2016, decreased 473 gigawatt hours (“GWh”) compared to 2015, primarily due to
higher paid curtailments in the first half of the year and higher levels of economic dispatching, in both cases caused by lower
prices in Alberta. This was partially offset by lower planned outages and derates. Unplanned outages remained at a similar
level compared to last year.
Comparable EBITDA for the year ended Dec. 31, 2016, increased $139 million compared to 2015, primarily due to the reversal
of the $80 million provision relating to the Keephills 1 outage in 2013. The year-over-year impact to comparable EBITDA of
this provision was $139 million, as last year’s comparable EBITDA was reduced by $59 million due to this provision. Our high
level of contracted generation and hedging strategy largely mitigated the impact of low power prices in Alberta. Comparable
EBITDA was also positively impacted by a reduction in our operations, maintenance, and administration costs.
For the year ended Dec. 31, 2016, sustaining capital expenditures decreased by $21 million compared to 2015, mainly due to
lower expenditures on our turnaround outages executed on two of our operated units and deferral of discretionary projects
into 2017.
2015
Production for the year ended Dec. 31, 2015, decreased 1,471 GWh compared to 2014, primarily due to unplanned outages in
the first half of 2015 (Sundance 4 and the Keephills 1 outage) and derates due to high temperatures impacting cooling ponds
in the spring and summer months. The planned outage at Sundance 3 was extended as a result of the level of turbine work
required. Generation was also reduced due to economic dispatching resulting from the low price environment in 2015.
In 2015, comparable EBITDA included a $59 million adjustment to provisions primarily in relation to prior year events.
Excluding the adjustment to provisions, comparable EBITDA would have been $393 million in 2015, in line with 2014.
Reductions in operating expenses at our Highvale mine and mark-to-market gains on certain forward financial contracts that
do not qualify for hedge accounting fully offset the negative impact of year-over-year lower availability on our comparable
EBITDA. Our high level of contracts and hedges in Canadian Coal mostly offset the impact of lower prices in Alberta
compared to 2014. Other operating income in 2015 represents insurance recoveries received in connection with the
Keephills 1 force majeure outage and additional work at Sundance 3.
For the year ended Dec. 31, 2015, sustaining capital expenditures decreased by $21 million compared to 2014. In 2014, we
incurred additional costs for the development of a new mining area, and the acquisition and refurbishment of vehicles as part
of our mining operations.
TransAlta Corporation | 2016 Annual Integrated Report
M14
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
2016
88.1
88.9
2015(2)
87.4
89.5
3,535
2,868
4,896
5,484
2014(2)
82.8
87.7
1,131
6,102
(3,854) (3,329) (549)
4,577
5,023
6,684
1,340
1,340
1,340
380 432
369
281
316
255
99
116
114
Operations, maintenance, and administration
54
50
49
Taxes, other than income taxes
Comparable EBITDA
Depreciation and amortization
Comparable operating income (loss)
Sustaining capital:
Routine capital
Finance leases
Planned major maintenance
Total
1
4
3
3
41
63
62
61
63
54
(20) -
8
3
2
2
3
3
-
11 10
10
17
15 12
2016
Production was down 446 GWh in 2016 compared to 2015, due mainly to increased economic dispatching in the first half of
the year caused by lower prices. We supplied our contractual obligations by buying less expensive power in the market during
such periods.
Comparable EBITDA decreased by $22 million compared to 2015 as a result of reduced margins due to lower prices and the
unfavourable impact of mark-to-market on certain forward financial contracts that do not qualify for hedge accounting. This
was partially offset by lower coal transportation costs and a reduction in our coal impairment charges.
Depreciation and amortization for 2016 decreased by $2 million compared to 2015 due to higher discount rates being applied
to our decommissioning obligation for the Centralia mine. As the mine is in the reclamation stage, the adjustment flows
directly to earnings.
Sustaining capital expenditures for 2016 were $2 million higher compared to 2015, primarily due to higher planned outages.
(1) Adjusted for economic dispatching.
(2) Restated to include non-operating legacy U.S. Gas costs. Refer to the Accounting Changes section of this MD&A.
M15
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
2015
Production decreased 1,661 GWh in 2015 compared to 2014, as a result of a higher level of economic dispatching caused by
lower prices.
In December 2014, we began supplying power to Puget Sound Energy under a 10-year contract. Initial contracted capacity
was 180 MW. Contract volumes escalated to 280 MW in December 2015 and to 380 MW in 2016. We can supply the
contract by buying power from the market when economical to do so and further improve our margin. The contract is
accounted for as a financial contract. Hedge accounting was applied to this contract, with changes in value recorded in other
comprehensive income (“OCI”).
EBITDA for the year ended Dec. 31, 2015, was comparable to 2014. The appreciation of the US dollar and lower pricing on
uncontracted generation was offset by the increased contracted volumes with Puget Sound Energy.
Depreciation and amortization for 2015 increased by $9 million compared to 2014 due to the strengthening of the US dollar.
For the year ended Dec. 31, 2015, sustaining capital expenditures increased by $3 million compared to last year as a result of
the coal fines recovery finance lease. This operation allows us to recover fuel as part of mine decommissioning activities.
Canadian Gas
Year ended Dec. 31
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
2016
95.7
2,784
2015
95.6
3,697
2014
94.9
4,096
288
1,535
2,027
3,072 5,232
6,123
1,057
1,057
1,183
470
486
584
171
204
299
299
282
285
54
67 69
1
3
4
244
212
212
108
98 98
136 114
114
7
4
22
5
19
33
12
23
55
(1) Includes production capacity for the Fort Saskatchewan power station, which has been accounted for as a finance lease. During 2015, operational control of our Poplar Creek
facility was transferred to Suncor Energy (“Suncor”). We continue to own a portion of the facility and have included our portion as a part of gross capacity measures. Poplar
Creek has been removed from our availability and production metrics, effective Sept. 1, 2015.
TransAlta Corporation | 2016 Annual Integrated Report
M16
Management’s Discussion and Analysis
2016
Production for the year decreased 2,160 GWh compared to 2015, primarily due to the restructuring of our contract with
Suncor at the Poplar Creek facility in the third quarter of 2015 and higher economic dispatching in Ontario driven by lower
prices.
Comparable EBITDA for 2016 increased by $32 million compared to 2015, as result of a year-over-year change in unrealized
mark-to-market on our gas position, cost-efficiency initiatives, and favourable pricing in Ontario from our contracts for power
and gas. The recontracting of the Poplar Creek facility reduced our OM&A by more than $9 million in 2016, compared to last
year.
Sustaining capital totalled $12 million in 2016, a decrease of $11 million. In 2015, we refurbished two engines in Ontario. The
change in our Poplar Creek operation also lowered our sustaining capital by approximately $7 million compared to 2015.
2015
Production for the year ended Dec. 31, 2015, decreased 891 GWh compared to 2014, also as a result of the restructuring of
our contract with Suncor at Poplar Creek, effective Sept. 1, 2015.
The Poplar Creek transaction had a minimal impact on EBITDA in 2015 compared to 2014.
Sustaining capital decreased by $32 million for the year ended Dec. 31, 2015 compared to 2014, due to the transfer of the
Poplar Creek facility at the end of August, and lower planned maintenance activities resulting from condition-based
assessments.
Australian Gas
1
Year ended Dec. 31
Availability (%)
Contract production (GWh)
Gross installed capacity (MW)(1)
Revenues
Fuel and purchased power
Comparable gross margin
2016
93.1
1,529
2015
92.4
1,381
2014
91.4
1,267
425
348
348
174
163
159
20
20
23
154
143
136
Operations, maintenance, and administration
25
21 33
Taxes, other than income taxes
Comparable EBITDA
Depreciation and amortization
Comparable operating income
Sustaining capital:
Routine capital
Planned major maintenance
Total
1
-
-
128
122
103
20
20
16
108
102
87
3
4
2
11 4
6
14
8
8
(1) Includes production capacity for the Solomon power station, which has been accounted for as a finance lease.
M17
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
2016
Production for 2016 increased 148 GWh compared to 2015 mostly from an increase in customer load. Due to the nature of
our contracts, the increase did not have a significant financial impact as our contracts are structured as capacity payments
with a pass-through of fuel costs.
Comparable EBITDA for the year increased by $6 million compared to 2015, mainly due to the addition of capacity payments
for the gas conversion project at our Solomon gas plant that was completed in May 2016, as well as the uplift from our natural
gas pipeline that was commissioned in March 2015. The change in value of the Australian dollar had limited impact on our
comparable EBITDA in 2016.
Sustaining capital increased by $6 million compared to 2015, mainly driven by maintenance projects on two engines in 2016
compared to maintenance projects on only one engine in 2015.
2015
Production for the year ended Dec. 31, 2015, increased 114 GWh compared to 2014 due to an increase in the power import
regime at one of our customer’s locations. Due to the nature of our contracts, the change did not have a significant financial
impact as our contracts are structured as capacity payments with a pass-through of fuel costs.
The increase in comparable EBITDA was primarily attributable to revenue from the Australian natural gas pipeline, which was
commissioned in March 2015. Revenue from our Solomon facility was also positively impacted by the appreciation of the US
dollar. The Australian dollar remained at similar levels in relation to the Canadian dollar during 2015.
Most of our contracts provide for the pass-through of fuel costs to the counterparty, limiting our exposure to fluctuations in
fuel prices. In the case where we have no provision for pass-through, we generally match our obligation to deliver energy and
our fuel supply to minimize our exposure to volatile commodity prices. Revenue and costs of fuel decreased by similar
amounts during the first half of 2015 compared to 2014, following the decrease in gas input costs. Also, certain operating
costs that are transferred to customers are now billed directly to the customer, resulting in revenue and OM&A decreasing in
2015 compared to 2014.
Depreciation and amortization for 2015 increased by $4 million compared to 2014 due to the increased asset base associated
with the Fortescue River Gas Pipeline completed in the first quarter of 2015.
Sustaining capital remained at similar levels in 2015 compared to 2014.
TransAlta Corporation | 2016 Annual Integrated Report
M18
Management’s Discussion and Analysis
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
2016
94.9
2,301
1,212
2015
95.8
2,146
1,060
2014
94.6
2,228
947
3,513 3,206 3,175
1,408
1,424
1,291
272
250
247
18
19
14
254
231
233
Operations, maintenance, and administration
52
48
48
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 sustaining capital expenditures
Insurance recoveries of sustaining capital expenditures
Net amount
1
2016
8
7
6
(1) -
-
195
176
179
119
99 88
76
77
91
2
1
2
11 12 10
13
13 12
(1) -
-
12
13
12
Production for 2016 increased by 307 GWh compared to 2015, mainly due to the full year contribution from assets acquired
during the second half of 2015, partly offset by lower wind resources negatively impacting generation across Canada.
Comparable EBITDA for 2016 increased $19 million compared to 2015, as assets acquired in the second half of 2015
contributed approximately $23 million to the increase. Lower merchant prices in Alberta and lower generation in Canada
negatively impacted our EBITDA.
Depreciation and amortization increased by $20 million compared to 2015, primarily due to the addition of assets acquired
during the second half of 2015.
2015
Production for 2015 increased slightly by 31 GWh compared to 2014, due to contributions from three additional wind farms
and our first solar facility acquired during the second half of 2015 (111 GWh). This was partially offset by lower wind resources
at Wyoming in 2015 compared to relatively high wind volumes in 2014.
Comparable EBITDA for 2015 was lower by $3 million compared to 2014 as lower generation from our Wyoming wind facility
and lower merchant prices in Alberta were not fully offset by additional EBITDA from the acquired assets and the stronger US
dollar.
Depreciation and amortization for 2015 increased by $11 million compared to 2014, primarily due to the acquisition of new
assets during the year and a stronger US dollar.
(1) Our 2015 capacity excludes acquisitions completed during the second half of 2015.
M19
TransAlta Corporation | 2016 Annual Integrated Report
Hydro
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
Management’s Discussion and Analysis
2016
2015
2014
1,768
1,662 1,810
88
86 75
1,856
1,748
1,885
926
926
913
126
116
131
8
8
9
118
108
122
Operations, maintenance, and administration
33
38
38
Taxes, other than income taxes
Net other operating income
Comparable EBITDA
Depreciation and amortization
Comparable operating income
Sustaining capital:
3
3
3
-
(6) (6)
82
73
87
33
25
24
49
48
63
Routine capital, excluding hydro life extension
8
3
9
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
9
18
19
10 10
3
27
31 31
2
4
9
29
35
40
-
(18) (4)
29
17 36
2016
Production for 2016 increased by 108 GWh over 2015, primarily due to better water resources.
Comparable EBITDA for 2016 increased $9 million compared to 2015. Higher generation contributed to higher revenues. Our
financial contracts partially offset lower levels of revenues in the Alberta ancillary market, and we also benefited from
cost-reduction initiatives implemented in late 2015.
Depreciation and amortization for 2016 increased by $8 million compared to 2015 due to the recognition of decommissioning
obligations on certain transmission lines that were taken out of service. As these transmission lines are in the reclamation
stage, the adjustment flows directly to earnings.
Sustaining capital (before insurance recoveries) for 2016 decreased $6 million compared to 2015 due to lower expenditures
on hydro life extension projects, partially offset by higher expenditures on routine capital.
2015
Production for 2015 decreased by 137 GWh compared to 2014, primarily as a result of lower water resources.
Comparable EBITDA decreased by $14 million for 2015 compared to 2014, primarily as a result of lower prices and a decrease
in price volatility in Alberta, which limited our ability to take advantage of our flexibility to produce electricity in higher-priced
hours. Net other operating income includes business interruption insurance recoveries relating to the 2013 Alberta flood.
Sustaining capital expenditures (before insurance recoveries) decreased by $5 million for the year ended Dec. 31, 2015 compared
to 2014 mainly due to flood-recovery capital related to the Alberta flood of 2013.
TransAlta Corporation | 2016 Annual Integrated Report
M20
Management’s Discussion and Analysis
Energy Marketing
Year ended Dec. 31
Revenues and comparable gross margin
Operations, maintenance, and administration
Comparable EBITDA
Depreciation and amortization
Comparable operating income
2016
2015
2014
76
49
108
24
52
3
49
12
37
1
36
33
75
-
75
Comparable EBITDA from Energy Marketing increased $15 million compared to 2015, as a result of solid performances in all
markets where we are active. During the second quarter of 2015, unexpectedly volatile markets in Alberta and the Pacific
Northwest negatively impacted gross margin. Operating, maintenance, and administration costs increased $12 million to $24
million in 2016 compared to 2015, due to increases in share-based incentive compensation and lower charges to other
business segments for energy hedging and optimization services.
Corporate
Our Corporate overhead costs of $70 million were lower in 2016 compared to 2015 and 2014 ($72 million and $71 million,
respectively), as we realized benefits of cost-efficiency initiatives that were offset by reduced allocations to our business
segments.
Key Financial Ratios
The methodologies and ratios used by rating agencies to assess our credit rating are not publicly disclosed. We have
developed our own definitions of ratios and targets to help evaluate the strength of our financial position. These metrics and
ratios are not defined under IFRS, and may not be comparable to those used by other entities or by rating agencies. We are
focused on strengthening our financial position and flexibility and aim to meet all our target ranges by 2018.
Comparable Funds from Operations before Interest to Adjusted Interest Coverage
As at Dec. 31
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)
2016
763
223
986
239
21
260
3.8
2015
740
223
963
232
23
255
3.8
2014
762
236
998
239
21
260
3.8
Our target for comparable FFO before interest to adjusted interest coverage is four to five times. This ratio is comparable to
last year, as 2016’s higher comparable FFO was offset by higher interest on debt, which includes interest capitalized on our
South Hedland power project. We expect this metric to improve towards our targeted level in the future, due the South
Hedland power project, once commissioned.
M21
TransAlta Corporation | 2016 Annual Integrated Report
Adjusted Comparable Funds from Operations to Adjusted Net Debt
As at Dec. 31
Comparable FFO
Less: 50 per cent of dividends paid on preferred shares
Adjusted comparable FFO
Period-end long-term debt(1)
Less: Cash and cash equivalents
Add: 50 per cent of issued preferred shares
Fair value asset of hedging instruments on debt(2)
Adjusted net debt
Adjusted comparable FFO to adjusted net debt (%)
1
Management’s Discussion and Analysis
2016
763
(21)
742
4,361
(305)
471
(163)
4,364
17.0
2015
740
(23)
717
2014
762
(21)
740
4,495
4,056
(54)
471
(190)
4,722
15.2
(43)
471
(96)
4,388
16.9
Our adjusted comparable FFO to adjusted net debt ratio improved to 17.0 per cent, mostly due to the increase in comparable
FFO, and lower net debt due to repayments, and the strengthening of the Canadian dollar in 2016. We expect this metric to
improve towards our targeted level of 20 to 25 in the future, due the South Hedland power project, once commissioned.
Adjusted Net Debt to Comparable EBITDA
As at Dec. 31
Period-end long-term debt(1)
Less: Cash and cash equivalents
Add: 50 per cent of issued preferred shares
Fair value asset of hedging instruments on debt(2)
Adjusted net debt
Comparable EBITDA
Adjusted net debt to comparable EBITDA (times)
2016
4,361
(305)
471
(163)
4,364
1,145
3.8
2015
4,495
(54)
471
(190)
4,722
945
5.0
2014
4,056
(43)
471
(96)
4,388
1,036
4.2
During the year, our adjusted net debt to comparable EBITDA ratio improved compared to 2015, mainly because of a lower
debt balance due to repayments and the strengthening of the Canadian dollar, and higher comparable EBITDA. Our target for
adjusted net debt to comparable EBITDA is 3.0 to 3.5 times. We expect this metric to improve towards our targeted level in
the future due to the expected increase in comparable EBITDA of approximately $80 million annually from the South Hedland
power project, once commissioned.
Sustainability Performance
Stakeholder Communication and Value Creation
The information contained herein seeks to highlight our ability to create value for investors, stakeholders, and society in the
short, medium, and long term. The selection of key information and key metrics disclosed in this integrated report and our full
sustainability disclosures follow a materiality assessment process, which identifies key impact areas to our stakeholders. We
subsequently are guided by, and place focus on, reporting on these key areas. More information on key areas of materiality
can be found on the sustainability section of our website.
(1) Includes finance lease obligations and tax equity financing.
(2) Included in risk management assets and/or liabilities on the consolidated financial statements as at Dec. 31, 2016, Dec. 31, 2015, and Dec. 31, 2014.
TransAlta Corporation | 2016 Annual Integrated Report
M22
Management’s Discussion and Analysis
Sustainability Targets and Results
Sustainability targets are strategic goals that support the long-term success of our business. Targets are set in line with
business unit goals to manage key areas of concern for stakeholders and ultimately improve our environmental and social
performance in these areas.
Financial
Achieve and maintain investment grade
credit metrics
2016 Sustainability Targets
Results
Partly achieved
1. Maintain our
investment
grade rating
2. Increase
focus on FFO
and EBITDA
TransAlta targeted comparable EBITDA and
comparable FFO for 2016 in the range of
$990 million to $1,100 million and $755
million to $835 million respectively
Achieved
3. Grow asset
portfolio
Power Generating Portfolio
Deliver an average of $40 million to $60
million of additional EBITDA from growth
projects
Results
On track
4. Achieve
top-quartile
performance in
Canadian Coal
Continue to deliver 87 to 89 per cent
availability in the segment
Not achieved
Comments
TransAlta maintains investment grade ratings
from three rating agencies: S&P (BBB-) stable, DBRS
(BBB) negative outlook, and Fitch (BBB-) negative
outlook. On Dec. 17, 2015, Moody's reduced our
rating to Ba1
For the year ended Dec. 31, 2016, comparable EBITDA
was $1,145 million and comparable FFO was reported
at $763 million. Comparable EBITDA includes the
reversal of provisions relating to the Keephills 1 force
majeure event in the amount of $80 million
Comments
In 2016, we continued to exercise prudence and
discipline in growing our cash flow. The wind and
solar pojects acquired in late 2015 contributed
approximately $25 million of comparable EBITDA in
2016. We continue to advance the construction of the
South Hedland power project, on budget and on time.
This project is expected to be commisioned by mid-
2017 and add approximately $80 million of
incremental annualized EBITDA
We achieved availability in 2016 of 85.3 per cent,
compared to 84.3 per cent in 2015, lower than our
targeted availability of at least 87 per cent. Our high
level of contracted generation and hedging strategy
mitgated lower power prices in Alberta. We continue
to drive towards our targets
M23
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Human and Intellectual
Results
Comments
5. Reduce safety
incidents
Achieve an Injury Frequency Rate below 0.70 Not achieved
IFR was 0.85 in 2016, up from 0.75 in 2015. We will
continue to seek improvement in this area through
deployment of additional targeted initiatives in 2017
6. Human
Resources
a) Maintain voluntary turnover percentage
under eight per cent
Achieved
Voluntary turnover was 6.7 per cent in 2016
b) Achieve 100 per cent completion of
development plans for all high-potential
employees at the top three levels of the
organization
Achieved
c) Complete the final three stages of our
globally recognized leadership development
project to ensure TransAlta’s top three levels
of leaders have the tools to successfully
reposition and grow our business
Partly achieved
Final stages to be completed in Q1 2017
7. Minimize
fleet-wide
environmental
incidents
Natural
Results
Comments
Keep recorded incidents (including spills and
air infractions) below 13
Not achieved
We recorded 16 reportable environmental incidents in
2016, none of which had a material environmental
impact
8. Increase mine
reclaimed acreage
Replace annual topsoil rate at Highvale mine
at a rate of 74 acres/year
Partly achieved
Replaced topsoil on 38 acres in 2016. A warmer
winter and early spring limited our ability to transport
topsoil for placement without adversely impacting the
ground surface (the preference is to drive on frozen
soil)
9. Utilize coal
byproduct
Sell a minimum of two million tonnes of coal
byproduct materials during the period 2015
to 2017
On track
70 per cent achieved (long-term target)
10. Reduce air
emissions
95 per cent reduction from 2005 levels of
TransAlta coal facility NOx and SO2
emissions by 2030
11. Reduce
greenhouse gas
emissions
a) 20 per cent reduction from 2005 levels of
TransAlta coal facility GHG by 2021, or the
equivalent of 7 million tonnes, of CO2e per
year
On track
On track
b) 55 per cent reduction from 2005 levels by
2030, or the equivalent of 19.7 million
tonnes, of CO2e per year.
On track
We reduced levels of NOx and SO2 in 2016 and
remain on track to realize these emission reductions
by 2030
We reduced GHG emissions in 2016, primarily as a
result of lower coal production, and we remain on
track to realize emission reductions by 2021/2030
TransAlta Corporation | 2016 Annual Integrated Report
M24
Management’s Discussion and Analysis
12. Combine
stakeholder
engagement
Social and Relationship Capital
Implement final Stakeholder Engagement
Framework. In 2016, every business unit will
use a single framework for stakeholder
guidance
Results
Achieved
13. Support youth
education with
community
investment
50 per cent of total communitiy investment
spending will be directed to supporting youth
education
Partly achieved
Comments
A corporate-wide framework was implemented and
we introduced our Stakeholder and Aboriginal
Relations (“STAR”) tracking program. STAR is a
communication record-keeping tool and fulfils our
requirements for consultation with both stakeholders
and aboriginal groups
In 2016 we spent approximately $0.75 million out of
$2.5 million (30 per cent) on youth education. Funds
were directed to the University of Calgary, University
of Alberta, Southern Alberta Institute of Technology,
Mount Royal University, The Banff Centre (indigenous
leadership scholarships), Mother Earth's Children's
Charter School (indigenous kindergarten to grade 9),
Calgary Stampede (the Young Canadians - ages 7 to
18) and national Canada and U.S. indigenous
scholarships (post-secondary for trades and
academic)
14. Increase
internal best
practice aboriginal
engagement
awareness
Work with our aboriginal communities to
develop an online best practice guide for
employees on working with and engaging
with aboriginal communities
Achieved
With the help of the First Nations groups and voices
of those communities, we produced an Indigenous
Awareness Training handbook for all our employees.
This achievement is in line with a commitment to
support the United Nations Sustainable Development
Goals, specifically, goal 10: reduced inequalities
M25
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Competitive Forces
Demand and supply balances are the fundamental drivers of prices for electricity. Underlying economic growth is the main
driver of longer-term changes in the demand for electricity, whereas system capacity, natural gas prices, GHG pricing,
government subsidies, and renewable resource availability are key drivers to the supply. Growth in behind-the-fence
generation for mining investments is key to developing our Australian gas segment.
Renewable capacity addition has been strong for the past several years due to government incentives. New supply in the near
term and intermediate term is expected to come primarily from investment in renewable energy as well as natural-gas-fired
generation. This expectation is driven by the low prices in the natural gas market combined with public policies that favour
carbon emission reductions.
We have substantial merchant capacity in Alberta and the Pacific Northwest. In those regions, we enter into contracts and
business relationships with commercial and industrial customers to sell power on a long-term basis, up to our available
capacity in the markets. We further reduce the portion of production not sold in advance through short-term physical and
financial contracts, and we optimize production in real time against our position and market conditions.
We also compete for long-term contracted opportunities in renewable and gas power generation, including cogeneration,
across Canada, the United States, and Australia. Our target customers in this area are incumbent utility providers and large
industrial and mining operators.
Alberta
Approximately 63 per cent of our gross capacity is located
in Alberta and more than 65 per cent of this is subject to
legislated Alberta PPAs, which were put in place in 2001 to
facilitate the transition from regulated generation to the
current energy market in the province. Alberta PPAs expire
at the end of 2017 (Sundance 1 and 2) and the end of 2020
(Keephills 1 and 2, Sundance 3 to 6, Sheerness, and Hydro). Coal generation sold under Alberta PPAs retains some exposure
to market prices as we pay penalties or receive payments for production below or above, respectively, targeted availability
based upon a rolling 30-day average of spot prices. We can also retain proceeds from the sale of energy and ancillary services
in excess of obligations on our Hydro Alberta PPAs (“hydro peaking”). We enter into financial contracts to reduce our
exposure to variable power prices for a significant portion of our remaining generation.
Following the decrease in oil prices, Alberta’s annual demand for power decreased by approximately 1.1 per cent in 2016
compared to 2015. Since 2014, approximately 1,000 MW of gas and wind generation capacity were added to the market. As a
result, power pool prices trended to their lowest levels in the last 10 years, dropping to an average of $18/MWh in 2016, due
to an oversupply of energy as well as bidding behaviour in the market that kept prices low. The decline impacted merchant
wind and hydro peaking, which are the portions of our portfolio we cannot effectively hedge.
Our current share of offer control in the province is approximately 12 per cent. After the expiry of the PPAs at the end of 2020,
our share of offer control is forecast to increase to approximately 28 per cent depending on load and supply growth in the
province.
In late November 2016, we announced that we had entered into an OCA with the Government of Alberta that provides
transition payments for the cessation of coal-fired emissions from the Keephills 3, Genesee 3 and Sheerness coal-fired plants
on or before Dec. 31, 2030. The affected plants are not, however, precluded from generating electricity at any time by any
method other than the combustion of coal. We also entered into the MOU with the Government of Alberta to collaborate and
co-operate in the development of a capacity market in Alberta that ensures both current and new electricity generators will
have a level economic playing field to build, buy, and sell electricity, and to develop a policy framework to facilitate the
conversion of coal-fired generation to gas-fired generation. We expect additional compliance costs as a result of the federal
government’s proposed framework in which each province is expected to implement a greenhouse gas (“GHG”) policy
equivalent to a carbon price of $50 per tonne by 2022. We believe that our extensive portfolio of assets provides us with
brownfield development opportunities in wind, solar, hydro, and gas that give us a cost advantage over competitors when
constructing generation facilities that use these fuel types.
TransAlta Corporation | 2016 Annual Integrated Report
M26
Management’s Discussion and Analysis
In March and May 2016, the buyers under the legislated Sundance, Sheerness, and Keephills PPAs announced their intention
to terminate the PPAs and transfer their respective obligations under the PPAs to the Balancing Pool because of a change in
Alberta law. Accordingly, the Balancing Pool began its investigation to determine whether these transfers are permitted by
the terms of the PPAs in the current circumstances and, if so, when the transfers would become effective. On July 25, 2016,
the Attorney General for the Province of Alberta commenced legal proceedings seeking relief against: all buyers who
purported to transfer their respective obligations under the PPAs, the owner of the Battle River #5 PPA, the Alberta Utilities
Commission (“AUC”), and the Balancing Pool. In this claim, the Attorney General challenges, among other things, the basis
on which the buyers purported to terminate the PPAs and transfer their PPA obligations to the Balancing Pool.
Recently, the Attorney General announced that it entered into settlement agreements with the buyers of the PPAs for
Sheerness, Sundance A, Sundance B, and Sundance C, and therefore discontinued its claims against those buyers. As part of
the settlement, the Balancing Pool confirmed the terminations of the PPAs for Sheerness and Sundance A, B, and C and, as a
result, the Balancing Pool assumed the role of buyer and is carrying out the responsibilities of the buyer under each of those
PPAs, including dispatching the generating units and making the capacity and energy payments to TransAlta until the end of
the PPA terms. TransAlta does not presently expect the transfer of the role of PPA buyer to the Balancing Pool to have a
material impact on its business.
Pursuant to the Electric Utilities Act (Alberta), the Balancing Pool may also choose to terminate the PPAs after following the
legislative requirements, which would include paying TransAlta an amount essentially equal to the applicable closing net
book value of the generating units.
The Attorney General has not entered into a settlement agreement with the buyer under the Keephills PPA and the Balancing
Pool has not confirmed the termination of that PPA. The outcome of the Attorney General’s proceeding and any investigation
by the Balancing Pool into the purported termination of the Keephills PPA is uncertain.
Notwithstanding all the above events, TransAlta continues to operate the PPA generating units in their ordinary course and
receives the capacity and energy payments due to TransAlta under the PPAs.
U.S. Pacific Northwest
Our capacity in the U.S. Pacific Northwest is represented by our
1,340 MW Centralia coal plant. Half of the plant capacity is scheduled to
retire at the end of 2020 and the other half at the end of 2025.
System capacity in the region is primarily comprised of hydro and gas
generation, with some wind additions over the last few years in response
to government programs favouring renewable generation. Demand
growth in the region has been limited and further constrained by emphasis on energy efficiency. Our coal plant can effectively
compete against gas generation, although depressed gas prices following the expansion of shale gas production in North
America has added to the downward pressure on power prices.
Our competitiveness is enhanced by our long-term contract with Puget Sound Energy for up to 380 MW over the remaining
life of the facility. The contract and our hedges allow us to satisfy power requirements from the market when prices fall below
our marginal cost of production.
We maintain an opportunity to redevelop Centralia as a gas plant after coal capacity retires, with permitting provided for in
our agreement for coal transition established with the State of Washington in 2011.
M27
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Contracted Gas and Renewables
The market for developing or acquiring gas and renewable generation facilities is highly competitive in all markets in which we
operate. Our solid record as operator and developer supports our competitive position. We expect, where possible, to reduce
our cost of capital and improve our competitive profile by using project financing and leveraging the lower cost of capital with
TransAlta Renewables. In the United States, our substantial tax attributes further increase our competitiveness.
While depressed commodity prices have reduced sectoral growth in the oil, gas, and mining industries, the change is also
creating opportunities for us as a service provider as some of our potential customers are more carefully evaluating non-core
activities and driving for operational efficiencies. In renewables, we are primarily evaluating greenfield opportunities in
Western Canada or acquisitions in other markets in which we have existing operations. We maintain highly qualified and
experienced development teams to identify and develop these opportunities.
Some of our older gas plants are now reaching the end of their original contract life. The plants generally have a substantial
cost advantage over new builds and we have been able to add value by recontracting these plants with limited life-extending
capital expenditures. We have recently extended the life of our Ottawa (2033 expiry), Windsor (2031 expiry), and Parkeston
(2026 expiry) plants in this manner. During the fourth quarter of 2016, we entered into a new contract with the IESO for our
Mississauga cogeneration facility. The new contract took effect on Jan. 1, 2017, and has resulted in the termination of the
existing contract, which would have otherwise terminated in December 2018. See the Significant Events section for further
details. The new contract provides us with additional financial flexibility to pay down upcoming debt maturities.
TransAlta’s Capital
The following discusses TransAlta’s main categories of capital, being Financial, Power Generating Portfolio, Human and
Intellectual, Social and Relationship, and Natural.
Financial Capital
Sources of Capital
Our goal over the last two years was to build financial flexibility by using multiple sources of funding to reposition our capital
structure. Over the last few years, the rating of our unsecured debt was put under pressure by all the rating agencies.(1) We
responded to this pressure by taking significant action starting in 2014 and through to today to reduce our indebtedness and
work on strengthening our financial metrics. Since the end of 2013, senior unsecured debt has been reduced by $1.1 billion,
including a reduction of over $800 million on our credit facility and a $300 million reduction in Canadian and U.S. bonds. Over
the next two years, we plan to continue on this path by replacing an additional $700 million to $900 million of maturing
recourse debt with debt secured by contracted cash flows.
On Dec. 17, 2015, Moody’s lowered the rating of our senior unsecured debt to Ba1 with a stable outlook. The direct financial
impact of this downgrade has been limited. We have posted additional collateral (including letters of credit) of nearly
$130 million to certain counterparties, and the cost of borrowing under our credit facilities and US$400 million of debt has
been stepped up in line with contractual provisions. During the first quarter of 2016, DBRS and Fitch Ratings (“Fitch”) changed
their outlooks from stable to negative. Their negative outlooks are a reflection of low energy prices and concerns over coal
generation transition in Alberta. We have investment grade ratings from each of DBRS, S&P, and Fitch. We remain focused on
maintaining these ratings, as strengthening our financial position allows our commercial team to contract our portfolio with a
variety of counterparties on terms and prices that are favourable to our financial results and provides us with better access to
capital markets through commodity and credit cycles. Risks associated with further reductions in our credit ratings are
discussed in the Liquidity Risk section of this MD&A.
(1) As at Dec. 31, 2016, our senior unsecured debt is rated as investment grade by three rating agencies: BBB (negative), BBB- (stable), and BBB- (negative) by DBRS,
Standard and Poor’s (“S&P”), and Fitch Ratings (“Fitch”), respectively, and Ba1 (stable) by Moody’s Investors Service (“Moody’s”). Our preferred shares are rated P-3
(stable) and Pfd-3 (negative) by S&P and DBRS, respectively. Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of
securities. The credit ratings accorded to our outstanding securities by DBRS, S&P, Moody's, and Fitch, as applicable, are not recommendations to purchase, hold, or sell
such securities inasmuch as such ratings do not comment as to market price or suitability for a particular investor. There is no assurance that the ratings will remain in
effect for any given period or that a rating will not be revised or withdrawn entirely by DBRS, S&P, Moody's, or Fitch in the future if, in their judgment, circumstances so
warrant. See the Liquidity Risk section of this MD&A.
TransAlta Corporation | 2016 Annual Integrated Report
M28
Management’s Discussion and Analysis
Capital Structure
Our capital structure consists of the following components as shown below:
As at Dec. 31
Recourse debt - CAD debentures
Recourse debt - U.S. senior notes
Credit facilities
U.S. tax equity financing
Other
Less: cash and cash equivalents
Less: fair value asset of hedging instruments on debt
Net 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 income
Total capital
2016
$
1,045
2,151
-
39
15
(305)
(163)
2,782
1,038
73
3,893
1,152
3,094
942
%
12
25
-
1
-
(4)
(2)
32
12
1
45
14
36
11
(525)
8,556
(6)
100
2015
$
1,044
2,221
315
50
17
(54)
(190)
3,403
766
82
4,251
1,029
3,075
942
(656)
8,641
%
12
26
4
1
-
(1)
(2)
40
9
1
50
12
35
11
2014
$
1,043
2,444
96
-
19
(43)
(96)
3,463
380
74
3,917
594
2,999
942
%
13
31
1
-
-
-
(1)
44
5
1
50
8
38
12
(8)
100
(657)
7,795
(8)
100
During 2016, we continued to work on strengthening our financial position and executing on our debt deleveraging strategy. Our
total debt, net of cash on hand and the fair value of our financial instruments hedging our U.S. debt, was reduced by more than
$350 million, from a combination of cash flows from operations and cash proceeds of $173 million received from the sale of the
economic interest in the Canadian Assets. Furthermore, we extended $1.8 billion of our $2.0 billion credit facilities to 2020 and
the remaining were extended to 2018. Since 2014, we acquired one wind and five solar projects for a total consideration of
approximately $200 million, including the assumption of debt. These projects contributed approximately $25 million of
comparable EBITDA in 2016. We also funded $336 million for the construction of the South Hedland project. In total, the South
Hedland project is expected to cost approximately $576 million and add $80 million of EBITDA annually over the 25-year life of
the long-term contract (including approximately $29 million of EBITDA relating to TransAlta Renewables’ non-controlling interest
share). We expect the project to commence operations in mid-2017.
During the year, we continued implementing our strategy to raise debt secured by our contracted cash flows and completed the
following debt offerings:
(cid:131)
a non-recourse bond in the amount of $202.5 million, with principal and interest payable quarterly, maturing on
Dec. 31, 2030, secured by our Poplar Creek finance lease contract, and
a non-recourse bond in the amount of $159 million, with principal and interest payable semi-annually, and maturing on June
30, 2032, secured by our New Richmond Wind project in Quebec.
(cid:131)
In 2015, we completed a $442 million bond offering, secured by two wind projects located in Ontario. The bonds are
non-recourse to TransAlta, amortizing, and bear interest at a rate of 3.8 per cent, payable semi-annually, and mature on
Dec. 31, 2028. On Feb 11, 2015, we also refinanced our $35 million 5.28 per cent Pingston non-recourse debt with a
$45 million 2.95 per cent non-recourse bond due in full in 2023. We also added $105 million of non-recourse debt relating to the
acquisitions of two renewable facilities in the U.S.
M29
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Non-recourse debt of $845 million in total (2015 - $536 million) is subject to customary financing restrictions that restrict our
ability to access funds generated by certain facilities’ operations. Upon meeting certain distribution tests, typically performed
once per quarter, the funds are able to be distributed by the subsidiary entities to their respective parent entity. At Dec. 31, 2016,
$24 million of cash was subject to these financial restrictions. Non-recourse debts of $644 million are each secured by a first
ranking charge over all of the respective assets of our subsidiaries that issued the bonds, which includes renewable generation
facilities with total carrying amounts of $956 million at Dec. 31, 2016 (2015 - $798 million). A non-recourse bond of
approximately $201 million is secured by a first ranking charge over the equity interests of the issuer that issued the non-recourse
bond.
The weakening of the US dollar has decreased our long-term debt balances by $67 million in 2016. Almost all our U.S.-
denominated debt is hedged either through financial contracts or net investments in our U.S. operations. During the period,
these changes in our U.S.-denominated debt were offset as follows:
As at Dec. 31
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
2016
2015
(35)
(29)
(3)
(67)
201
183
8
392
Over the next four years, we have approximately $2.2 billion of recourse and non-recourse debt maturing. We expect to
refinance some of these upcoming debt maturities by raising $700 million to $900 million of debt secured by our contracted
cash flows. We also expect to continue our deleveraging strategy, as a significant part of our free cash flow over the next four
years will be allocated to debt reduction. The reduction of our common share dividend in January 2016 is expected to provide
additional funds which may be used for debt reduction.
Our credit facilities provide us with significant liquidity. At Dec. 31, 2016, we had a total of $2.0 billion (2015 - $2.2 billion) of
committed credit facilities, of which $1.4 billion (2015 - $1.3 billion) was available for use. We are in compliance with the terms of
the credit facilities. At Dec. 31, 2016, the $0.6 billion (2015 - $0.9 billion) of credit utilized under these facilities was comprised of
actual drawings of nil (2015 - $0.3 billion) and letters of credit of $0.6 billion (2015 - $0.6 billion). These facilities are comprised
of a $1.5 billion committed syndicated bank facility expiring in 2020, one bilateral credit facility of US$200 million, expiring in
2020, and three bilateral credit facilities, totalling $240 million, expiring in 2018.
Working Capital
Including the current portion of long-term debt, the excess of current assets over current liabilities was $337 million as at
Dec. 31, 2016 (2015 - $311 million). Although our working capital has not changed significantly, the timing of the classification
of long-term debt as current has negatively impacted our current period-end working capital. Excluding the current portion of
long-term debt of $639 million, the excess of current assets over liabilities was $976 million as at Dec. 31, 2016
(2015 - $398 million). Working capital as at Dec. 31, 2016, also includes approximately $93 million of receivables related to
the Mississauga recontracting and $61 million related to the Wintering Hills wind facility reclassified as assets held for sale.
Last year, working capital included a $59 million provision relating to the Keephill 1 outage. We reversed a total of $94 million
of this provision in the fourth quarter of 2016.
Share Capital
Our Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares reset in 2016 at a coupon rate of 2.709 per cent. As
permitted under the terms of the Preferred Shares, some shareholders elected to convert to a floating rate and 1,824,620 of
our 12 million Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares were tendered for conversion, on a one-for-
one basis, into the Series B Cumulative Redeemable Floating Rate Preferred Shares.
TransAlta Corporation | 2016 Annual Integrated Report
M30
Management’s Discussion and Analysis
The following tables outline the common and preferred shares issued and outstanding:
As at
Common shares issued and outstanding, end of period
March 2, 2017
Dec. 31, 2016
Dec. 31, 2015
Number of shares (millions)
287.9
287.9
284.0
Preferred shares
Series A
Series B
Series C
Series E
Series G
Preferred shares issued and outstanding, end of period
10.2
1.8
11.0
9.0
6.6
38.6
10.2
1.8
11.0
9.0
6.6
38.6
12.0
-
11.0
9.0
6.6
38.6
The Series C and Series E preferred shares will also reset in 2017. The rate spread on the Series C and Series E over the then 5-
year Government of Canada bond rate is 3.10 per cent and 3.65 per cent, respectively.
Non-Controlling Interests
As of Dec. 31, 2016, we own 64.0 per cent (2015 – 66.6 per cent) of TransAlta Renewables. On January 2016, we completed
the sale to TransAlta Renewables of an economic interest in the 506 MW Sarnia cogeneration facility and of two renewable
energy facilities with total capacity of 105 MW for $540 million. Consideration received from TransAlta Renewables consisted
of gross proceeds from a public offering of 17,692,750 common shares at $9.75 per share for gross proceeds of $173 million,
15.6 million common shares of TransAlta Renewables with a value of $152 million, and a $215 million unsecured subordinated
debenture convertible into common shares of TransAlta Renewables at a price of $13.16 per common share upon maturity on
Dec 31, 2020. In November 2016, the economic interest was converted to direct ownership of the Canadian Assets by
TransAlta Renewables.
TransAlta Renewables is a publicly traded company whose common shares are listed on the Toronto Stock Exchange under
the symbol “RNW”. TransAlta Renewables holds a diversified, highly contracted portfolio of assets with comparatively lower
carbon intensity. The stable and predictable cash flows generated by these assets has attracted favourable equity valuations
from investors, allowing TransAlta to raise equity capital.
In November 2015, we sold 20.5 million common shares of TransAlta Renewables in a private placement to AIMCo for net
cash consideration of $193 million.
On May 7, 2015, we completed the sale of an economic interest in our Australian assets to TransAlta Renewables. The
Australian assets consist of six operating assets with an installed capacity of 425 MW, the 150 MW South Hedland project
currently under construction, as well as a 270-kilometre gas pipeline, for total consideration of $1.78 billion. At the closing of
the transaction, TransAlta Renewables paid the Corporation $217 million in cash as well as approximately $1,067 million
through a combination of common shares and Class B shares in TransAlta Renewables. TransAlta Renewables has also
committed to funding the costs to construct the South Hedland project incurred after Jan. 1, 2015, representing an estimated
amount of $474 million. TransAlta Renewables funded the cash proceeds through the public issuance of 17,858,423 common
shares at a price of $12.65 per share.
We remain committed to maintaining our position as the majority shareholder and sponsor of TransAlta Renewables with a
stated goal of maintaining our interest between 60 to 80 per cent.
We also own 50.01 per cent of TransAlta Cogeneration L.P (“TA Cogen”), which owns, operates, or has an interest in three
natural-gas-fired facilities and one coal-fired generating facility. We recently recontracted our Mississauga cogeneration
facility, which resulted in a pre-tax gain of approximately $191 million, accelerated depreciation of $46 million, and a fuel
charge for the de-designation of gas hedges of $14 million. Since we own a controlling interest in TA Cogen and TransAlta
Renewables, we consolidate the entire earnings, assets, and liabilities in relation to those assets.
M31
TransAlta Corporation | 2016 Annual Integrated Report
Returns to Providers of Capital
Net Interest Expense
The components of net interest expense are shown below:
Year ended Dec. 31
Interest on debt
Loss on redemption of bonds
Capitalized interest
Interest on finance lease obligations
Other
Keephills 1 outage interest accruals (reversals)
Accretion of provisions
Net interest expense
Management’s Discussion and Analysis
2016
236
1
(16)
3
(5)
(10)
20
229
2015
228
2014
238
-
(9)
4
(2)
9
21
-
(3)
1
(1)
1
18
251
254
Net interest expense decreased in 2016 compared to 2015, primarily as a result of higher capitalized interest relating to the
South Hedland power project and the reversal of the accrued interest component of the Keephills 1 provision. See the Other
Consolidated Analysis section of this MD&A for further details. These decreases were partially offset by higher interest on
debt, due partially to the downgrade to our credit rating from Moody’s and higher average interest rates in 2016 as compared
to 2015.
For the year ended Dec. 31, 2015, net interest expense decreased compared to 2014, primarily due to the reduction in debt
during the year and lower interest rates on debt that was refinanced, coupled with higher capitalized interest. Higher interest
expense on foreign-denominated debt due to the strengthening of the US dollar and other interest expense associated with
the adjustment to provisions have partially offset these decreases.
Dividends to Shareholders
On Jan. 14, 2016, we announced a reduction of our common share dividend from $0.72 annually to $0.16 annually. This action
was taken as part of a plan to improve our long-term financial flexibility. The declaration of dividends is at the discretion of the
Board.
The following are the 2016 common and preferred shares dividends declared each quarter:1
Year ended Dec. 31, 2016
First quarter
Second quarter
Third quarter
Fourth quarter
Fourth quarter (1)
Common
dividends
per share
0.04
0.04
0.04
0.04
0.04
Preferred Series dividends per share
A
0.2875
0.16931
0.16931
0.16931
0.16931
B
-
0.15490
0.16144
0.15974
0.15651
C
0.2875
0.2875
0.2875
0.2875
0.2875
E
0.3125
0.3125
0.3125
0.3125
0.3125
G
0.33125
0.33125
0.33125
0.33125
0.33125
During the year ended Dec. 31, 2016, 3.9 million (2015 – 9.0 million) common shares were issued to shareholders that elected
to reinvest their dividends, for a total of $18 million (2015 - $76 million). On Jan. 14, 2016, we suspended the Premium
DividendTM, Dividend Reinvestment and Optional Common Share Purchase Plan (the “DRIP”).
(1) On Dec. 19, 2016 the Board declared quarterly dividends per common share and preferred shares payable to shareholders of record at the close of business on
March 1, 2017.
TransAlta Corporation | 2016 Annual Integrated Report
M32
Management’s Discussion and Analysis
Non-Controlling Interests
Comparable earnings attributable to non-controlling interests for the year ended Dec. 31, 2016 increased, $23 million to
$103 million compared to 2015, primarily due to the public offering of additional common shares by TransAlta Renewables to
finance its investments in the Australian and Canadian portfolios in May 2015 and January 2016, respectively.
In 2015, comparable earnings attributable to non-controlling interests increased $31 million to $80 million compared to 2014,
primarily due to the additional common shares issued to the public by TransAlta Renewables to fund its investment in the
Australian portfolio.
Ability to Deliver Financial Results1
The metrics we use to track our performance are comparable EBITDA, comparable FFO, and comparable FCF. The following
table compares target to actual amounts for each of the three past fiscal years:
Year ended Dec. 31
Comparable EBITDA
Comparable FFO
Comparable FCF
Target
Actual(1)
Target
Actual
Target
Actual
2016
2015
2014
990 - 1,100
1,000 - 1,040
1,015 - 1,065
1,145
755 - 835
763
250 - 300
299
945
720 - 770
740
265 - 270
315
1,036
743 - 793
762
274 - 324
280
Power Generating Portfolio Capital
We monitor availability closely as a key metric to achieving our financial targets. We adjust our maintenance and sustaining
capital expenditures to optimize financial returns on our investments and to align with our strategic orientations.
Availability and Production
Our adjusted availability target was 89 to 91 per cent
for 2016.
Our availability in 2016, after adjusting for economic
dispatching at U.S. Coal, was 89.2 per cent
(2015 – 89.0 per cent, 2014 - 90.5 per cent) and was comparable to last year. Lower outages and derates at Canadian Coal were
mostly offset by higher unplanned outages at our Eastern Wind facilities. Similar availability year-over-year did not impact our
performance metrics.
Production for the year ended Dec. 31, 2016, decreased
2,516 GWh compared to 2015, primarily due to the Poplar
Creek restructuring that occurred in late 2015 and lower
generation from our coal portfolio due to lower prices in
the Pacific Northwest and Alberta. Under our new
arrangement with Suncor, they now operate the facilities and pay us a fixed monthly fee. Production from renewable assets
acquired in the second half of 2015 contributed to partially offset generation lost from Poplar Creek. The Pacific Northwest
continues to be dampened by lower prices, where it was more economic to supply our contractual obligation by buying power in
the market, rather than through our own generation. In Alberta, lower prices impacted both paid and unpaid curtailments in 2016.
(1) Over the last three years we have had a track record of delivering financial results well within or above guidance. Comparable EBITDA in 2015 and 2016 was impacted by
non-cash adjustments related to the Keephills 1 provision. Excluding these adjustments, our Comparable EBITDA would have been $1,065 million in 2016 and $1,004
million in 2015.
M33
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Operational
In the generation segments, our OM&A costs reflect the cost of operating our facilities. These costs can fluctuate due to the
timing and nature of planned and unplanned maintenance activities. The remainder of OM&A costs reflect the cost of day-to-
day operations.
OM&A costs were $22 million lower in 2016 compared to 2015 as we realized benefits from our cost control and targeted
productivity initiatives. Over the last two years we reduced our OM&A costs by almost $40 million. The Poplar Creek
restructuring also reduced OM&A costs throughout the year as the facility falls outside our operational scope.
The following table outlines our generation comparable OM&A over the last three years:
Generation comparable OM&A
2016
396
2015
418
2014
433
We continuously drive for the cost-effective operation of our facilities. In 2015, we introduced multiple initiatives to reduce
our overhead and increase efficiency and productivity at Canadian Coal. Aside from the reduction in the number of positions
in Canadian Coal, we have driven reductions in coal costs through improved mine planning and mining methodologies,
reduced equipment requirements, and optimized contractor usage.
Sustaining Capital
We are in a long-cycle, capital-intensive business that requires significant capital expenditures. Our goal is to undertake
sustaining capital that ensures our facilities operate reliably and safely over a long period of time. Sustaining capital also
includes capital required following the 2013 flood in Alberta, most of which has been recovered from third parties.
Year ended Dec. 31
Routine capital
Mine capital
Planned major maintenance
Finance leases
Flood-recovery capital
Total sustaining capital expenditures
Insurance recoveries of sustaining capital expenditures
Net amount
2016
2015
2014
83
23
148
16
270
2
272
(1)
271
101
25
162
13
301
4
305
(25)
280
135
45
162
10
352
9
361
(4)
357
Lost production as a result of planned major maintenance is as follows:
1
Year ended Dec. 31
GWh lost(1)
2016
938
2015
1,409
2014
1,519
(1) Lost production excludes periods of planned major maintenance at U.S. Coal, which occur during periods of economic dispatching.
TransAlta Corporation | 2016 Annual Integrated Report
M34
Management’s Discussion and Analysis
Total sustaining capital expenditures were $33 million lower compared to 2015. At Canadian Coal, sustaining capital
expenditures decreased by $21 million compared to 2015, mainly due to a reduction in maintenance projects without
impacting our availability. At our Canadian Gas segment, sustaining capital expenditures decreased by $11 million compared
to 2015, as we have been able to reschedule a large inspection of our gas generation units at Sarnia due to a lower number of
operating hours. At our Australian Gas segment, planned major maintenance was up by $7 million in 2016 compared to 2015,
driven by maintenance projects on two engines at our Kambalda and Kalgoorlie plants.
Strategic Growth
In 2016 we continued to explore opportunities to grow our cash flow but remained prudent and disciplined before allocating
capital. We are focused on highly contracted gas and renewable power generation to support our financial position as we
transition to having increased merchant capacity in Alberta post-2021. All investments are subject to due diligence
procedures and are ultimately reviewed by our investment committee (refer to the Governance and Risk Management section
of this MD&A).
Our South Hedland power project continues to progress in line with expectations. At the end of 2016 construction work was
largely complete and the project team is now focusing on commissioning activities. The combined-cycle gas turbines
achieved first fire in the fourth quarter and commissioning activities continue on these units. We expect to invest $230 million
to $250 million to complete the construction of South Hedland, for a total cost of $576 million. We continue to expect the
project to be delivered on schedule and on budget in mid-2017. The project is expected to add an additional $80 million of
EBITDA annually, when fully in service.
In 2015 we completed two transactions and acquired:
(cid:131)
71 MW of fully contracted renewable generation assets for cash consideration of US$76 million together with the
assumption of certain tax equity obligations and US$42 million of non-recourse debt. The assets acquired include
21 MW of solar projects located in Massachusetts and the 50 MW Lakeswind wind project located in Minnesota. The
assets are contracted under long-term power purchase agreements ranging from 20 to 30 years.
As part of the restructuring of our Poplar Creek contract, we acquired the 20 MW Kent Breeze wind facility located in
Ontario, which has a 20-year contract with the Ontario IESO and a 51 per cent interest in an 88 MW non-contracted
wind facility in Alberta. Our interest in the Alberta wind facility was sold in early 2017.
(cid:131)
During 2015, we received approval from the AUC to construct and operate an 856 MW combined-cycle natural-gas-fired
power plant in Alberta. The Sundance 7 project has received all regulatory approvals after receiving the Environmental
Protection and Enhancement Act approval from Alberta Environment and Parks on Oct. 1, 2015. Construction of Sundance 7 will
not commence until we have contracted a significant portion of the plant capacity. Following changes to market conditions in
Alberta during the last few years, we do not anticipate that this condition will be met before the next decade. In December
2015, we repurchased our partner’s 50 per cent share in TAMA Power, the jointly controlled entity developing this project, for
consideration of $10 million payable over five years, along with an option permitting the partner to buy back into this project
or into other projects of TAMA Power during this period.
Contractual Profile
Approximately 73 per cent of our capacity over the next two years is sold under long-term contracts. Excluding Alberta PPAs
for our coal and hydro facilities, the majority of these contracts have maturities in excess of 10 years. In 2016, we entered into
a long term contract for the Akolkolex hydro facility in B.C., expiring in 2045. Our South Hedland power project is expected to
commence operations mid-2017, which will add stable contracted cash flows until the end of its 25-year contract life. Last
year, significant contracts were extended at our Poplar Creek, Windsor, and Parkeston facilities, as discussed in more detail
below. The average life of these contracts is approximately 12 years.
With most of our coal and hydro facilities in Alberta rolling off the Alberta PPAs at the end of 2020, we continue to develop a
portfolio of commercial and industrial customers to sell our generation to the province. We are now serving a portfolio of
approximately 450 MW.
M35
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Poplar Creek
In late 2015, we closed the restructuring of our contractual arrangement for power generation services with Suncor at
Suncor’s oil sands base site near Fort McMurray and the acquisition of Suncor’s interest in two wind projects located in
Alberta and Ontario.
The Poplar Creek cogeneration facility had been built and contracted to provide steam and electricity to Suncor until 2023.
Under the terms of the new arrangement, Suncor acquired from TransAlta two steam turbines with an installed capacity of
132 MW and certain transmission interconnection assets. In addition, Suncor assumed full operational control of the
cogeneration facility, including responsibility for all capital costs and the right to use the full 244 MW capacity of TransAlta’s
gas generators until Dec. 31, 2030. We provide Suncor with technical support to maximize performance and reliability of plant
equipment. Ownership of the entire Poplar Creek cogeneration facility will transfer to Suncor in 2030.
As part of the arrangement, we acquired Suncor’s 20 MW Kent Breeze wind facility located in Ontario and Suncor’s
51 per cent interest in the 88 MW Wintering Hills merchant wind facility located in Alberta. The Kent Breeze facility has a 20-
year contract with the Ontario IESO. On Jan. 26, 2017, we announced the sale of our 51 per cent interest in the Wintering Hills
merchant wind facility for approximately $61 million.
The Poplar Creek transaction creates value by increasing the duration of the contract to 2030 from the prior 2023 expiry,
while the sale of Wintering Hills reduces our exposure to Alberta’s merchant power market, and allows us an injection of near-
term liquidity and financial flexibility to pay down debt. Additionally, we were able to further leverage our interest in the Poplar
Creek cogeneration facility by completing a private placement in late December, of $202.5 million bonds that mature in 2030
and are secured by a first ranking charge over the equity interests of the issuer that issued such bonds, further allowing us to
deleverage our corporate debt.
Windsor
During the first quarter of 2015, we executed a new 15-year power supply contract with the Ontario IESO for our Windsor
facility, which was effective Dec. 1, 2016. The contract is similar to the contract signed in 2013 for our Ottawa facility. Under
the new contract, the plant will become dispatchable for up to 72 MW of capacity. The new contract provides long-term
stable earnings for this facility.
Parkeston
During the last quarter of 2015, we executed an extension to our power purchase agreement to supply power to the Kalgoorlie
Consolidated Gold Mine from our 55 MW share of the Parkeston power station. The agreement extends the previous contract
to October 2026 with options for early termination available to either party beginning in 2021. The contract extension will
continue to provide stable cash flow for the business.
Over the last three years, we have nearly doubled the weighted average remaining contractual life of our gas fleet from six
years to 12 years.
TransAlta Corporation | 2016 Annual Integrated Report
M36
Management’s Discussion and Analysis
Human Capital
Engaging our workforce, developing our employees, and minimizing safety incidents are the keys to human capital value
creation at TransAlta. The most material impacts an our human capital performance are an engaged workforce and keeping
our employees safe.
As at Dec. 31, 2016, we had 2,341 active employees. This number has decreased by two per cent since the previous year,
following various restructuring initiatives to reduce costs and increase efficiency. A number of unfilled positions have also
been eliminated.
With approximately 53 per cent of our employees being unionized, we strive to maintain open and positive relationships with
union representatives and regularly meet to exchange information, listen to concerns, and share ideas that further our mutual
objectives. Collective bargaining is conducted in good faith, and we respect the rights of all employees to participate in
collective bargaining.
Organizational Culture and Structure
Our employees are central to our value creation. Our corporate culture is one that has been cultivated throughout our more
than 100-year heritage of pioneering innovative ways to safely and responsibly generate reliable and affordable electricity. In
2016 we formalized our core values to help provide strategic clarity for our employees. We want our people to align with and
live our core values, which are: innovation, respect, loyalty, accountability, integrity, and safety. TransAlta has a stimulating
work environment and we seek to challenge our employees to maximize their potential. We encourage alignment with our
values and work ethic, while providing a foundation for leadership, collaboration, community support, growth, and work life
balance.
During 2015 we initiated the Powering Performance organizational design program, with the primary objective of accelerating
decision-making within our organization. The program has had us transition more fully to a decentralized, business-centric
model, with Coal & Mining, Gas & Renewables, Australia, and Energy Marketing defined as our four primary businesses. As
part of the design work, we have transferred accountability for shared services to the businesses and removed a layer of
management. As part of this process, employees also have clearer accountabilities and authority.
Employee Benefits
TransAlta is an attractive employer in all three countries in which we operate. We provide compensation to our employees at
levels that are competitive in relation to their respective location. We strive to be an employer of choice through our total
rewards program, which includes various incentive plans designed to align performance with our annual and mid-term targets,
as determined annually by the Board.
Also included in compensation are various future benefit plans. We have registered pension plans in Canada and the U.S.
covering substantially all employees of the Corporation, its domestic subsidiaries, and specific named employees working
internationally. These plans have defined benefit and defined contribution options, and in Canada there is an additional
supplemental defined benefit plan for members whose annual earnings exceed the Canadian income tax limit. Except for the
Highvale pension plans acquired in 2013, the Canadian and U.S. defined benefit pension plans are closed to new entrants. The
U.S. defined benefit pension plan was frozen effective Dec. 31, 2010, resulting in no future benefits being earned. The defined
benefit plans are funded by the Corporation in accordance with governing regulations. We provide other health and dental
benefits for disabled members and retired members, typically up to the age of 65. The supplemental pension plan is an
obligation of the Corporation. We are not obligated to fund the supplemental pension plan but are obligated to pay benefits
under the terms of the plan as they come due. We have posted a letter of credit in the amount of $73 million to secure the
obligations under the supplemental pension plan.
Safety
At TransAlta we operate large and complex facilities. The environments in which we work – including Canadian winters and
the Australian outback, often add an additional challenge to keep our employees safe. The safety of our staff, contractors, and
visitors is one of the top priorities, if not the top priority, of our social performance. Our safety culture is further embedded
into TransAlta culture each year. Every meeting of more than four people starts with a “safety moment,” which helps share key
safety learnings across our company. Our Operational Integrity program is focused on reducing safety hazards. Our core
values include the safety of our people.
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TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
In 2016 our IFR was 0.85. IFR is defined as the number of lost-time and medical injuries for every 200,000 hours worked. Our
ultimate goal is to achieve zero injury incidents, but annually we seek improvement over the prior year. We have experienced
no fatalities during the last three years.
Year ended Dec. 31
IFR
2016
0.85
2015
0.75
2014
0.86
During 2015, we designed a new total safety management policy as a two-pronged approach. The policy builds on our
occupational safety program, Target Zero, which is focused on protecting our workers on site, through means of personal
protection equipment, inspections, safety controls, job safety analyses, field-level hazard assessments, and safety
communications. The policy is supplemented by our newly launched Operational Integrity program, which is focused on
preventing all hazards from equipment, through definition and measurement of safety-critical performance measures and
operating limits.
Intellectual Capital
Intellectual capital at TransAlta is another key to our value creation. We have developed innovative solutions to optimize and
maximize value from our fleet. We are constantly exploring use of applied or new technologies to find solutions to expand or
adapt our fleet in an ever-changing world, which helps protect our shareholder value and maintain delivery of reliable and
affordable electricity.
Operations Diagnostic Centre
TransAlta has maintained its Operations Diagnostic Centre (“ODC”) since 2008. The ODC monitors coal-fired, gas-fired, and
wind-generating assets across Canada, the United States, and Australia. A centralized team of engineers and operations
specialists remotely monitors our power plants for emerging equipment reliability and performance issues. ODC staff are
trained in the development and use of specialized equipment monitoring software and can apply their experience in power
plant operations. If an equipment issue is detected, the ODC notifies plant operations to investigate and remedy the issue
before there is an impact to operations. The monitoring, analysis, and diagnostics completed by the ODC are focused on early
identification of equipment issues based on longer-term trend analysis and complements day-to-day plant operations.
Operational Integrity Program
During 2015, we set the foundation for our Operational Integrity program. The program is designed to achieve process and
equipment safety through understanding and monitoring of key risks and implementing of mitigation measures. In 2015, we
completed our risk assessment at all facilities except Australia and Mining. We have also developed operator checks,
maintenance tasks, and proof tests for various safety-critical elements at coal plants. Key performance indicators have been
identified and are being integrated in a dashboard for ongoing monitoring. During 2016, we finalized developing the balance of
safety-critical maintenance strategies and related engineering standards. We seek to optimize cost and reliability of our
assets and maintain or increase their capacity. Our decentralized organization allows the sharing and deployment of
technology-specific innovative practices within the respective businesses. Productivity projects are evaluated against criteria
that include a two- to three- year financial payback. We also incurred $3 million in 2016 on a productivity improvement blade
enhancement technology at our Wolfe Island wind project. This investment is expected to increase the annual energy
production of the Wolfe Island wind project by approximately three per cent. In 2017 we are planning to put into place our
Total Safety Management System where we integrate our work in Process Safety with our existing Occupational Safety
programs. We continue to observe a positive increase in self-reporting and addressing process safety hazards as awareness
and new tools are being introduced.
Energy Trading and Marketing
Our energy trading and marketing operations optimize the financial returns of our facilities in real time. The group purchases
fuels to feed plants, bids the electricity we generate at our facilities into energy markets, and mitigates the associated risks
associated with those purchases and sales. In addition, they buy, sell, schedule, and negotiate all of the electricity
transmission for each facility. They do so while applying an overlay of complex, real-time information about weather, facility
capacity, transmission congestion, and market pricing. Quantitative analysis, forecasting, mathematical models, and forward
curves are key tools used to execute this responsibility. In addition, the application of these skills for proprietary trading allows
us to generate positive margins.
TransAlta Corporation | 2016 Annual Integrated Report
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Management’s Discussion and Analysis
Effective Jan. 1, 2016, a new Energy Trading and Risk Management System (“ETRMS”) became operational, to further support
optimization and trading capabilities, allowing for streamlined data flows, state-of-the-art linkages, and enhanced scalability
for key optimization tools. The ETRMS was integrated into our internal control over financial reporting for the year ended Dec.
31, 2016.
Innovation: Applied Technologies
TransAlta has been at the forefront of innovation in the power generation sector since the early 1900s when we developed
hydro assets. To add context, these assets were developed at the same time as the automobile. We have been an early
adopter of wind technology in Canada and today are the largest wind generator in the country. Today we run a Wind Control
Centre, the only one of its kind in Canada, that monitors, to the second, each and every wind turbine we operate across North
America. In 2015 we made our first investment in solar technology with the purchase of the Massachusetts solar facilities.
As we move towards becoming the leading clean power company in Canada by 2030 we will continue to seek solutions to
innovate. The announcement of our proposed Brazeau hydro expansion, a 600-900 MW pumped hydro expansion, which will
double our hydro capacity in Alberta, demonstrates our ability to seek solutions to create value for both our shareholders and
society. Hydro is a clean alternative to both coal and gas and has long-term life. We still operate some of our legacy hydro
assets from the early 1900s today.
We strive to keep up to date with power technologies that have the potential to redefine power markets today and in the
future. Innovation is constantly happening on a more micro scale at TransAlta. For further communication on innovation at
TransAlta please visit www.transalta.com/about-us/innovation.
Social and Relationship Capital
Creating shared value for our stakeholders is the key to social and relationship value creation at TransAlta. The most material
impacts to our social and relationship performance are public health and safety, anti-competitive behaviour and fostering
better relationships and conditions with all stakeholders, but with a key focus on indigenous groups. Each year we strive to do
better in each of these areas.
Public Health and Safety
We seek to ensure public health and safety through measures such as restricting physical access to our operating sites and by
minimizing our environmental impact. It is our goal to both keep our employees safe and the peoples and the communities in
which we operate.
We specifically look to protect against the following risks:
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harm to person(s),
damage to property,
increased liability due to negligence, and
loss of organizational reputation and integrity.
When addressing concerns such as occupiers liability, our Corporate Security team liaises with stakeholders to facilitate
appropriate security countermeasures and controls to prevent or reduce the identified risk. For example, in 2016 our
Corporate Security term initiated a security/safety signage campaign across the Hydro fleet to elevate the awareness of the
safety risks associated with dams. By implementing signage from a safety perspective, Corporate Security and TransAlta also
benefited from a security perspective. Signage gave notice of potential physical dangers, but also allows as an organization
and landowner to reduce liability and increase safety through notice, awareness, and mitigation of trespassing and vandalism.
We actively monitor air emissions from our coal and gas plants. Our large coal facilities have Continuous Emissions
Monitoring Systems (“CEMS”) in place, which help us monitor our pollutant emission levels in line with acceptable limits.
When we are in breach of regulatory limits we report this to Alberta Environment & Parks and conduct a root cause analysis
to understand how we can eliminate future breaches from occurring. In 2016 we had two breaches at our Alberta coal
facilities. Both breaches were minor and due to an instrumentation calibration failure at Keephills 3 and an opacity CEMS
analyzer failure at the Sundance operations.
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TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Of note, our coal plants currently capture 80 per cent of mercury emissions and the majority of particulate matter emissions.
Both have been deemed harmful to human health, which we recognize and work to minimize through capture. The health
impact risk from emissions that do reach our environment is minimized due to the location of our plants, which are located
away from urban environments. Independent studies conducted by University of Alberta scientist Dr. Warren Kindzierski,
using provincial government monitoring data from the past nine years, also show that only approximately 10 per cent or less
of all particulate matter in the airshed in the largest urban environment close to our facilities, Edmonton, can be attributed to
coal combustion emissions. Chemical “signatures” for emissions pointed to several sources of air quality concern in
Edmonton, including local industries, vehicles, and wood-burning fireplaces.
We are currently evaluating the option of converting some of our coal-fired units to natural gas units in 2022 and 2023, which
will represent 90 per cent of our coal fleet at that point in time. This action will reduce our GHG emissions by close to
50 per cent. It will also eliminate the majority, if not all, of our mercury emissions and nitrogen oxide emissions from our
Alberta coal facilities.
Stakeholder Relations
TransAlta implemented a corporate stakeholder engagement framework in 2016, a streamlined corporate-wide approach to
ensure that engagement and relationship-building practices are consistent across TransAlta’s locations and types of work.
This framework is modelled and closely tied to the stakeholder engagement aspect of ISO 14001, which is an internationally
recognized environmental management standard.
In 2016 we introduced our Stakeholder and Aboriginal Relations (“STAR”) tracking program. STAR functions as a
communication record-keeping tool, which is managed by our Stakeholder and Aboriginal Relations team. This capacity fulfils
our requirements for consultation with stakeholders and aboriginal groups alike, and is capable of producing reports (notably,
government reports) as proof of engagement and consultation efforts. Built as a SharePoint page, STAR has the capacity to
centralize information and grant different levels of access to the information it stores.
Some features of the STAR program include:
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in-house application with no operating cost or fees,
centralized for the entire company to use,
different levels of accessibility (privileges),
can store email conversations, documents, and voice-mail messages related to any project, event, or issue; and use them
in reports, and
produces an array of statistical reports showing frequencies and volumes of engagement based on project, stakeholder,
stakeholder group, issue, or keywords.
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The Board believes that it is important to have constructive engagement with its shareholders and other stakeholders and has
established means for the shareholders of the Company and other stakeholders to communicate with the Board through the
use of a confidential Ethics Helpline or by writing directly to the Board. The contact information for communicating with the
Board is published in Whistleblower section of this MD&A. Shareholders and other stakeholders may, at their option,
communicate with the Board on an anonymous basis. In addition, the Board has adopted an annual non-binding advisory vote
on the Company’s approach to executive compensation. The Company is committed to ensuring continued good relations and
communications with its shareholders and other stakeholders and will continue to evaluate its practices in light of any new
governance initiatives or developments.
Aboriginal Relations
The focus of our efforts in this area is to establish solid relationships with indigenous and Métis communities, recognizing and
respecting their rights and focusing on engaging them at the earliest stages of any project or development. Specifically, our
aboriginal relations team continues to develop and enhance aboriginal relations in areas of employment, economic
development, community engagement, and investment. Since 2014, we have achieved the Canadian Council for Aboriginal
Business’s silver-level Progressive Aboriginal Relations certification. As noted above, in 2016 we introduced our STAR tracking
program, which functions a communication record-keeping and engagement measurement tool.
TransAlta Corporation | 2016 Annual Integrated Report
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Management’s Discussion and Analysis
Local Communities
We provide public benefit through reliable, cost-efficient power and related outputs or services. With the phase-out of coal on
the horizon, we seek to secure favourable outcomes for our workers and the communities surrounding our plants. Our
proposed coal-to-gas conversions provide the opportunity to maintain some jobs during conversions, to support sector jobs,
and to redeploy some of our workforce in the plants or toward renewables growth. Electricity and energy have always been at
the heart of the economy in Alberta, and any changes in the industry must therefore support our communities. Conversion
will also help keep municipal, provincial, and federal tax revenues supporting these communities. TransAlta advocates for
sufficiently long timelines for transition, support for facility redevelopment, funds for retraining, and economic diversification.
Community
During 2016, TransAlta contributed $2.5 million in donations and sponsorships (2015 - $3.5 million).
On July 30, 2015, we announced that we were moving ahead with plans to invest US$55 million over 10 years to support
energy efficiency, economic and community development, and education and retraining initiatives in Washington State. The
US$55 million community investment is part of the TransAlta Energy Transition Bill, passed in 2011. This bill was a historic
agreement between policymakers, environmentalists, labour leaders, and TransAlta to transition away from coal in
Washington State, closing the Centralia facility’s two units, one in 2020 and the other in 2025. Although we did not secure
additional long-term contracts totalling 500 MW as planned in the original agreement as a condition of the investment, we
are following through on our funding pledge and securing mutual benefits agreed with the State for orderly transition.
Competitive Behaviour
On July 27, 2015, the AUC issued a ruling that found, among other things, that our actions in relation to four outage events at
our coal-fired generating units, spanning 11 days in 2010 and 2011, restricted or prevented a competitive response from the
associated PPA buyers and manipulated market prices away from a competitive market outcome.
On Sept. 30, 2015, TransAlta and the Alberta Market Surveillance Administrator (“MSA”) reached an agreement to settle all
outstanding proceedings before the AUC. The settlement, which was in the form of a consent order, was approved by the
AUC on Oct. 29, 2015. Under the terms of the agreement, we agreed to pay a total amount of $56 million that included
approximately $27 million as a repayment of economic benefits, approximately $4 million to cover the MSA’s legal and related
costs, and a $25 million administrative penalty. Of this amount, $31 million was paid in the fourth quarter of 2015, and $25
million was paid in the fourth quarter of 2016.
When we became aware that the market rules governing forced outages were in dispute, we changed our compliance
procedures, and the actions that led to this case have not been repeated. In order to rebuild trust, we asked a national law firm
with expertise in electricity markets, and a national accounting firm, to complete independent third-party reviews of our then
current compliance procedures around forced outages. We also asked them to review our trading compliance program to
ensure that our current practices met the company’s legal and ethical obligations and the high expectations of our customers
and stakeholders, the results of which were made public during the first half of 2016.
The national law firm assessment concluded that:
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outage practices are consistent with the law in Alberta, and
senior management has demonstrated a strong commitment to compliance.
Recommendations were provided to formalize the outage practices and procedures and related document management, and to
incorporate the procedures into the existing TransAlta Compliance programs in terms of training, investigation procedures and
annual reviews.
Using a 10-point compliance effectiveness review framework, the national accounting firm’s assessment of TransAlta’s Energy
Trading Compliance Program concluded that:
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from a program design perspective, TransAlta’s program contains each of the 10 components of an effective compliance
program, and includes the key elements required and normally seen at industry peers, and
in terms of operational effectiveness, TransAlta’s program meets or exceeds current industry practice in each of the
10 components.
TransAlta Corporation | 2016 Annual Integrated Report
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Management’s Discussion and Analysis
Recommendations were provided in 5 of the 10 areas, for increasing cross functional communications, cross-training of
compliance staff, scheduling of training components more frequently throughout a year, formalizing documentation of
monitoring tools and performance review assessments for compliance.
TransAlta has accepted all of the recommendations in both reports.
Natural Capital
All energy sources used to generate electricity have some impact on the environment. While we are pursuing a business
strategy that includes investing in low-impact renewable energy resources such as wind, hydro, and solar, we also believe that
natural gas will continue to play an important role in meeting energy needs as part of this transition. Regardless of the fuel
type, we place significant importance on environmental compliance and continued environmental impact mitigation, while
seeking to deliver low-cost electricity. Currently the most material natural or environmental capital impacts to our business
are GHG emissions, air emissions (pollutants, metals), and energy use. Material impacts that we manage and track include
our environmental management systems, environmental incidents and spills, land use, water usage, and waste management.
In the jurisdictions in which we operate, legislators have proposed and enacted regulations to discontinue, over time, the use
of the technologies our coal-fuelled plants currently utilize. Our gas and coal facilities can also incur costs in relation to their
carbon emissions, depending on the jurisdiction in which the facility is located. Our contracted facilities can generally recover
those costs from the customer. Conversely, our renewable generation facilities are generally able to realize value from their
environmental attributes. We continue to closely monitor the progress and risks associated with environmental legislation
changes on our future operations.
Reducing the environmental impact of our activities has a benefit not only to our operations and financial results, but also to
the communities in which we operate. We expect that increased scrutiny will be placed on environmental emissions and
compliance, and therefore we have a proactive approach to minimizing risks to our results. Our Board provides oversight to
our environmental management programs and emission reduction initiatives to ensure continued compliance with
environmental regulations.
Our environmental initiatives include:
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Renewable power growth and offsets portfolio: Over the last 10 years, we have added approximately 1,300 MW in
renewable energy capacity. From our Alberta wind fleet, 360 MW of capacity generates offsets that can be applied
against GHG emissions in Alberta. Annual revenue generation from these offsets is in the range of $10 million to
$15 million.
Environmental controls and efficiency: We continue to make operational improvements and investments to our existing
generating facilities to reduce the environmental impact of generating electricity. We installed mercury control
equipment at our Canadian Coal operations in 2010 in order to meet Alberta’s 70 per cent reduction objectives, and
voluntarily at our U.S. coal-fired plant in 2012. In 2016 we achieved an 80 per cent capture rate of mercury at all coal
facilities. Our Keephills 3 and Genesee 3 plants use supercritical combustion technology to maximize thermal efficiency,
as well as sulphur dioxide (“SO2”) capture and low oxides of nitrogen (“NOx”) combustion technology. Uprate or
energy- efficiency projects completed at our Keephills and Sundance plants, including a 15 MW uprate finalized in 2015
at Sundance 3, have improved the energy and emissions efficiency of those units.
Planning: With respect to environmental rules (as detailed in the following Regional Regulation and Compliance
subsection), we investigate the cost effectiveness of multiple technological solutions and various operating models in
order to prepare appropriate work scopes. In 2016 we announced our proposed coal to natural gas conversions and
support for the Government of Alberta’s renewable electricity plans.
Policy participation: We are active in policy discussions at a variety of levels of government and with industry
participants. Where capacity retirements are being mandated, we advocate minimizing the capital requirements of
incremental regulation, to allow reinvestment in lower-intensity sources during the transition phase. In Washington
State, the retirement of our Centralia coal plant was established through a multi-stakeholder agreement. In 2016 we
entered into the MOU with the Government of Alberta, which entails co-operation and collaboration to enable the
conversion of coal-fired generation to gas-fired generation.
TransAlta Corporation | 2016 Annual Integrated Report
M42
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, the majority of which closely mimic the
internationally recognized ISO 14001 EMS standard. We have operated our facilities in line with ISO 14001 for 17 years, and
our systems and knowledge of management systems are therefore mature. In 2016 we moved to no longer certify our Alberta
coal plants as ISO 14001, but the plants continue to run best practice EMS, as do 97 per cent of our facilities. Only two of our
facilities do not closely track ISO 14001, which is due to commercial arrangements (we are not the primary operator), but
these facilities still have EMS in place.
Environmental Incidents and Spills
We recorded 16 reportable environmental incidents in 2016 (2015 - 12 incidents), which was above our target of 13. None of
these incidents resulted in a material environmental impact. Our Gas & Renewables fleet recorded only three incidents in
2016, a record year. The remainder of our 13 environmental incidents occurred at our Alberta Coal business unit. Incident
types included spills, which were highly recoverable, air emission exceedances or instrument failures, wastewater sampling
errors, effluent releases, water blowdown exceedances, and process safety incidents. We will continue to target improvement
in 2017 with a specific focus on Alberta Coal. Our corporate-wide 2017 target is 11 or fewer incidents. We also continue to
track and manage all non-reportable (minor) environmental incidents, which helps us identify what leads to an incident.
Understanding the root cause of incidents helps with incident prevention planning and education.
Typical spills at TransAlta are hydrocarbon spills, which happen in low environmental impact areas and are almost always
contained and recovered. It is extremely rare that we experience large spills with impact on the environment. Spills that do
occur that we must report are typically just above acceptable regulatory spill limits and these are always addressed with a
critical time factor. The volume of spills in 2016 was 61 m3 (2015 - 19 m3), of which 78 per cent was recovered (2015 – 99 per
cent recovered). The increase is attributable to three large spills, two at our Sundance coal operations and one at Mt Keith in
southwestern Australia. All three incidents were contained at our sites and were reported to the appropriate bodies.
Energy Use (1)
TransAlta uses energy in a number of different ways. We burn coal, gas, and diesel to generate electricity. We harness the
kinetic energy of water and wind to generate electricity. We also utilize the sunshine to generate electricity. In addition to
combustion of fuel sources we also track combustion of fuel in the vehicles we use and energy use in the buildings we occupy.
Knowledge of how much energy we use allows us to optimize and create energy efficiencies.
The following are our millions of gigajoules of energy use. On a comparable basis, our energy use has declined over the last
three years as a result of lower generation from our coal-generating assets.
Year ended Dec. 31
Coal
Gas and Renewables
Corporate
Total energy use
2016
469.1
59.2
0.1
528.4
2015(1)
483.4
58.7
0.1
542.2
2014
529.7
54.3
0.1
584.1
(1) Gas & Renewable 2015 volumes were restated due to a diesel volume reporting error at our Solomon facility.
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TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Greenhouse Gas Emissions
In 2016, we estimate that 30.7 million tonnes of GHGs with an intensity of 0.84 tonnes per MWh (2015 - 32.2 million tonnes
of GHGs with an intensity of 0.87 tonnes per MWh) were emitted as a result of normal operating activities.(1) Our GHG
emissions decreased slightly in 2016, primarily as a result of lower production from coal plants. Other decreases in emissions
of the Canadian Gas segment are attributable to the transfer of operational control of the Poplar Creek facility to our customer
in September 2015, conversion of the Ottawa plant to a peaking facility in 2013, and conversion of the Solomon plant in
Australia to burn natural gas instead of diesel.
The following are our GHG emissions in million tonnes CO2:
Year ended Dec. 31
Coal
Gas and renewables
Total GHG emissions
2016
27.7
3.0
30.7
2015
29.2
3.0
32.2
2014
32.3
2.7
35.0
Our continued investment in growth from renewable power generation further supports the decrease in emissions intensity
observed in 2016. We believe in proactive measurement and disclosure of air emissions.
In 2016, TransAlta improved its scoring on the Carbon Disclosure Project Climate Change report to a B, our highest integrated
score yet. We were also highlighted by Chartered Professional Accountants of Canada as the only company in Canada, out of
75 companies, that reports on climate change across all levels of disclosure: the annual information form, this MD&A, and our
information circular.
Refer to the Climate Change section of this MD&A for further information.
Air Emissions
In 2016 air emissions were down compared with 2015. Air emissions decreased slightly in line with reduction in coal power
generation.
Year ended Dec. 31
Sulphur dioxide (tonnes)
Nitrogen oxide (tonnes)
Particulate matter (tonnes)
Mercury (kilograms)
2016
39,600
48,400
4,900
130
2015
41,800
48,000
4,900
170
2014
47,600
52,900
5,200
220
Our continued investment in growth from renewable power generation further supports the decrease in emissions intensity
observed in 2016. We believe in proactive measurement and disclosure of air emissions.
(1) 2016 data are estimates based on best available data at the time of report production. GHGs include water vapour, carbon dioxide (“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 GHG Protocol: A Corporate
Accounting and Reporting Standard. As per the methodology, TransAlta reports emissions on an operation control basis, hence we report 100 per cent of emissions at
facilities in which we are the operator. Emissions intensity is calculated by dividing total operational emissions by 100 per cent of production (MWh) from operated
facilities, regardless of financial ownership.
TransAlta Corporation | 2016 Annual Integrated Report
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Management’s Discussion and Analysis
Water
Our principal water uses are for cooling and steam generation in coal and gas plants, and for hydro power production.
Typically, TransAlta withdraws in the range of 220-240 million m3 of water across our fleet. In 2016 we withdrew 247 million
m3 and returned approximately 188 million m3 back to its source. Water is withdrawn primarily from rivers where we hold
permits to withdraw water and adhere to regulations on water quality. We return or discharge approximately 70 per cent of
water back to the source, meeting the regulatory quality levels that exist in the various locations in which we operate. The
difference between withdraw and discharge, representing consumption, is largely due to evaporation loss.
The following represents our total water consumption (million m3 ) over the last three years:
Year ended Dec. 31
Water from environment
Water to environment
Total water consumption
2016
247
188
59
2015
272
198
74
2014
243
172
71
Our areas of higher water risk are situated east of Perth in our simple-cycle gas plants in Western Australia and in our
Southern Alberta hydro operations. We monitor and manage water risk in our operating areas east of Perth.
In Southern Alberta, following the flood of 2013, our hydro facilities are being used for an increased water management role than they
have played in the past. During 2016, we signed a five-year agreement with the Government of Alberta to manage water on the Bow
River at our Ghost reservoir facility to aid in potential flood mitigation efforts, as well as at our Kananaskis Lakes System (which
includes Interlakes, Pocaterra and Barrier), for drought mitigation efforts.
Land Use
The largest land use associated with our operations is for surface mining of coal. Of the three mines we have operated,
Whitewood is completely reclaimed and the land certification process is ongoing. Centralia is in the reclamation phase, and
Highvale is actively mined with ongoing reclamation. Our reclamation plans are set out on a lifecycle basis and include
contouring disturbed areas, re-establishing of drainage, replacing topsoil and subsoil, re-vegetation, and land management.
Our mining practice incorporates progressive reclamation where the final end use of the land is considered at all stages of
planning and development.
In 2016, we reclaimed 39 acres (16 hectares) at our Highvale mine, which was below our target of 74 acres (30 hectares) due
to the impact of warm weather on soils in the winter, as cold temperatures facilitate reclamation work and the spreading of
topsoil. The Centralia mine is no longer actively used for coal operations, but reclamation activity is ongoing. In 2016 we
reclaimed 38 hectares of land.
Also in 2015, we donated 64 acres of land to the Alberta Wildlife Trust Fund. The land includes an area that was once a mine
settling pond and is a site of ecological significance. The donation aligns with our objectives for community participation and
stakeholder engagement.
Waste
Our operating teams work to minimize waste and maximize recoverable value from waste. Over the years, we have invested in
equipment to capture byproducts from the combustion of coal, such as fly ash, bottom ash, gypsum, and cenospheres, for
subsequent sale. These non-hazardous materials add value to products like cement and asphalt, wallboard, paints, and
plastics. Byproduct sales and associated annual revenue generation typically ranges from $25 million to $35 million.
Coal Transition
Our coal transition, whether it is executing on our coal-to-gas conversion plans or completing a full phase-out by 2030, will
vastly improve our environmental performance. Energy use, GHG, air emissions, waste generation, and water usage will all
significantly decline. A conversion of coal-fired power generation to gas-fired generation is expected to eliminate all mercury
emissions and the majority of nitrogen oxide emissions.
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TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Climate Change
Governance
TransAlta's Governance and Environment Committee (“GEC”) is a Board-appointed committee that reports directly to the
Board of Directors to help fulfil oversight responsibility with respect to environment, health, and safety. In conjunction, the
GEC and Board hold the highest levels of oversight in regards to TransAlta’s climate change policy and sustainability
initiatives.
Strategy
Climate change related risks are monitored through our company-wide risk management processes and actively managed.
Identified climate change risks and opportunities are also reviewed by our management team . We attribute regionally specific
carbon pricing, both current and anticipated, as a mechanism to manage future risks pertaining to uncertainty in the carbon
market and as a safeguard to anticipate future impacts of regulatory changes on facilities. It is also a method of modelling for
future electricity prices and to analyze the viability of acquisitions. Identified climate change risks or opportunities and carbon
pricing are recognized in the annual TransAlta long-and-medium range forecasting processes. Regulatory risk/compliance
(coal electricity generation), physical risks (hydro and drought/floods), and monetary opportunities (gas and renewable
electricity generation) are the main drivers of integration into business strategy.
Aligned with our business strategy is our climate change strategy, which is implemented and managed on a corporate-wide
business unit level, consisting of four main areas of focus:
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Energy-efficiency improvements,
Development of emissions offsets portfolios to achieve emissions reductions at competitive costs,
Development of clean combustion technologies,
Growth of our renewables portfolio as an increasing component of our total generation portfolio.
We seek investment in climate change related mitigation solutions where we can maximize value creation for our
shareholders, local communities, and the environment. Anticipated conversion of our large coal fleet to gas-fired generation
highlights this approach, which will allow us to run our assets longer than the federally mandated coal retirement schedule.
Our anticipated actions maximize value for our shareholders, ensure low-cost and reliable power for Albertans, and reduce
the environmental impact from coal-fired generation.
Our investment and growth in renewable energy is highlighted by our diverse portfolio of renewable energy generating assets.
We currently operate and are invested in over 2,200 MW of hydro, wind, and solar power. We are the largest producer of
wind power in Canada and the largest producer of hydro in Alberta. Production from renewable energy in 2016 resulted in
avoidance of over 3.1 million tonnes of CO2e, which is equivalent to removing over 730,000 vehicles from North American
roads. For further details on governance and risk, see our Governance and Risk Management section of this MD&A.
Targets
We recognize climate change risk and the goal set out in the 2015 Paris Agreement to prevent two degrees Celsius of global
warming above pre-industrial levels. Our GHG reduction targets have been established to align with the UN Sustainable
Development Goals, specifically Goal 13, which calls for “urgent action to combat climate change and its impacts.” Our 2030
GHG reduction target is set based on climate-based science and the goal of preventing two degrees Celsius of global
warming. This target is approved by the Science Based Targets initiative, which is a partnership between the Carbon
Disclosure Project, UN Global Compact, World Resources Institute and World Wildlife Fund, which helps companies
determine how much they must cut emissions to prevent the worst impacts of climate change.
Our GHG reduction targets are as follows:
1. Our goal, in line with a commitment to the UN Sustainable Development Goals (“SDGs”), is to reduce our total
GHG emissions in 2021 to 30 per cent below 2015 levels.
2. Our goal, in line with a commitment to the UN SDGs and prevention of two degrees Celsius of global warming, is to
reduce our total GHG emissions in 2030 to 60 per cent below 2015 levels.
TransAlta Corporation | 2016 Annual Integrated Report
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Management’s Discussion and Analysis
Regional Regulation and Compliance
Carbon issues and related legislation will continue to have an impact on our business. We are committed to complying with
legislative and regulatory requirements and to minimizing the environmental impact of our operations. We work with
governments and the public to develop appropriate frameworks to protect the environment and to promote sustainable
development.
Recent changes to carbon regulations may materially adversely affect us. As indicated under “Risk Factors” in our Annual
Information Form and within the Governance and Risk Management section of this MD&A, many of our activities and
properties are subject to carbon requirements, as well as changes in our liabilities under these requirements, which may have
a material adverse effect upon our consolidated financial results.
Canadian Federal Government
In November 2016, the Canadian federal government announced that coal-fired generation would be phased out by 2030,
following a similar commitment by the Alberta provincial government in November 2015. These two decisions changed the
coal plant closure requirements, which had previously been guided by the federal regulations that became effective on
July 1, 2015 which provided for up to 50 years of life for coal units. According to the new shut-down requirements, the
Corporation’s older coal units (which retire prior to 2030) will be guided by the 50-year life rule, while newer units (which
were previously scheduled to retire post-2030) will face the new 2030 shutdown date. In November 2016, the Corporation
signed an OCA with the Alberta Government that confirmed the 2030 shutdown commitment for the impacted units.
On Nov. 21, 2016, the Canadian federal government announced that the Department of Environment and Climate Change will
be developing regulations for gas-fired generation. The announcement confirmed plans to include specific rules for coal-to-
gas converted units, including a proposed 15-year life and a separate emissions intensity standard. The Canadian federal
government will conduct consultations on the proposed regulation in the first two quarters of 2017. Finalized regulations are
currently expected by the end of 2018.
On Oct. 3, 2016, the Canadian federal government announced its intention to implement a national price on GHG emissions.
Under this proposal, beginning in 2018, there would be a price of $10 per tonne of carbon dioxide equivalent emitted, rising to
$50 per tonne by 2022, or a comparable reduction in GHGs under a cap-and-trade program. The application of the price
would be co-ordinated with provincial jurisdictions. We do not yet know how such a price mechanism will affect our
operations.
Alberta
On Nov. 22, 2015, the Government of Alberta announced through the Climate Leadership Plan its intent, among other things,
to phase out emissions from coal-fired generation by 2030, replace two-thirds of the retiring coal-fired generation with
renewable generation, and impose a new carbon price of $30 per tonne of CO2 emissions based on an industry-wide
performance standard. On March 16, 2016, the Government of Alberta announced the appointment of a Coal Phase-out
Facilitator to work with coal-fired electricity generators, the Alberta Electric System Operator (“AESO”), and the Government
of Alberta to develop options to phase out emissions from coal-fired generation by 2030. The Coal Phase-out Facilitator was
tasked with presenting options to the Government of Alberta that would strive to maintain the reliability of Alberta’s
electricity grid, maintain stability of prices for consumers, and avoid unnecessarily stranding capital.
In March 2016, Alberta began development of its renewable energy procurement process design for the AESO to procure a first
block of renewable generation projects to be in-service by mid-2019. On Sept. 14, 2016, the Government of Alberta reconfirmed
its commitment to achieve 30 per cent renewables in Alberta’s electricity energy mix by 2030.
On May 24, 2016, the Government of Alberta passed the Climate Leadership Implementation Act which establishes the carbon tax
framework for its application to fuels. It is expected that additional regulations will be developed governing the treatment of large
industrial emitters. The Climate Leadership Plan will be implemented for the electricity sector on January 1, 2018.
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TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
On Nov. 24, 2016, we announced that we had entered into the OCA, which provides for transition payments for the cessation
of coal-fired emissions from the Keephills 3, Genesee 3 and Sheerness coal-fired plants on or before Dec. 31, 2030. The
affected plants are not, however, precluded from generating electricity at any time by any method other than the combustion
of coal. Under the terms of the OCA, the Corporation will receive annual cash payments of approximately $37.4 million, net
to the Corporation, commencing in 2017 and terminating in 2030. For further details, refer to the Highlights section of this
MD&A.
Additionally, we announced that we had reached an understanding set out in the MOU to collaborate and co-operate with the
Government of Alberta in the development of a policy framework to facilitate the conversion of coal-fired generation to gas-
fired generation, facilitate existing and new renewable electricity development through supportive and enabling policy, and
ensure existing generation and new electricity generation are able to effectively participate in the recently announced capacity
market to be developed for the Province of Alberta.
Since 2007, we have incurred costs as a result of GHG legislation in Alberta. On June 29, 2015, the Alberta government
announced an increase to its provincial Specified Gas Emitters Regulation:
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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.
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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 the units reach the end of their respective PPAs, in most cases in 2020. These regulatory
requirements were developed by the province in 2004 as a result of multi-stakeholder discussions under Alberta’s Clean Air
Strategic Alliance (“CASA”). The release of the federal regulations in 2012 adopted by the Government of Canada and the
Government of Alberta, and the accelerated coal-fired generation retirement schedule, creates a potential misalignment
between the CASA air pollutant requirements and schedules, and the retirement schedules for the coal plants, which in
themselves will result in significant reductions of NOx, SO2, and particulate emissions, something which has been identified
as a matter yet to be addressed in the MOU.
The Government of Alberta’s Renewable Electricity Program is intended to encourage the development of 5,000 MW of new
renewable electricity capacity by 2030. The AESO is currently soliciting interest in the first competitive procurement for 400
MW under the program. Proponents must submit an expression of interest by late March 2017. The process will be followed
by a request for qualification in late April 2017, request for proposal in mid-September 2017 and successful proponents
announced in December 2017. Eligible projects must be 5 MW or larger and can be hydro, wind, solar, and certain biomass.
The successful projects will be awarded a Renewable Electricity Supply Agreements that utilizes an indexed renewable energy
credit or contract for difference mechanism that will fix the price to the proponent over 20 years. The contracts are expected
to require the facility to be operational by 2019.
The Government of Alberta has tasked the AESO with transitioning Alberta’s energy-only market to a capacity market structure.
The capacity market will help to ensure that there is sufficient supply adequacy as over 6,000 MW of coal generation retires by
2030. The new market structure is expected to reduce the reliance on scarcity pricing, which drives energy price volatility and the
price signal for new investment, and compensate resource owners with monthly capacity payments for making their capacity
available in the energy and ancillary services market. The AESO plans to engage stakeholders in determining the design and
implementation of the capacity market over 2017 and 2018 and conduct the first auction in 2019 with a contract delivery year
targeted for 2021. The AESO has suggested they will need new capacity in 2021.
TransAlta Corporation | 2016 Annual Integrated Report
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Management’s Discussion and Analysis
Pacific Northwest
On Dec. 17, 2014, Washington State Governor Jay Inslee released a carbon-emissions reduction program for the state, which
is where our U.S. Coal plant is located. Included in this program are a cap-and-trade plan and a low-carbon fuels standard. The
proposed emissions cap will become more stringent over time, providing emitters time to transition their operations.
On Aug. 3, 2015, former U.S. President Obama announced the Clean Power Plan. The plan sets GHG emission standards for
new fossil-fuel-based power plants and emission limits for individual states. States will have the option of interpreting their
limits in mass-based (tons) or rate-based (pounds per MWh) terms. The plan is intended to achieve an overall reduction in
GHG emissions of 32 per cent from 2005 levels by 2030. It will be implemented in two stages: 2022 to 2029, and 2030 and
beyond.
On Feb. 9, 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan pending consideration as to
whether the regulations are lawful. It is not clear yet how this may affect the future of the Clean Power Plan. As a result of our
2011 agreement for coal transition with the State of Washington, we do not expect the proposed regulations to significantly
affect our U.S. operations.
These additional regulations for existing power plants are not expected to significantly affect our U.S. operations. TransAlta
has agreed with Washington State to retire units in 2020 and 2025. This agreement is formally part of the State’s climate
change program. We currently believe that there will be no additional GHG regulatory burden on U.S. Coal given these
commitments. The related TransAlta Energy Bill was signed into law in 2011 and provides a framework to transition from coal
to other forms of generation.
Ontario
On Feb. 25, 2016, Ontario released draft regulations for its GHG cap-and-trade program that were finalized on
May 19, 2016. The regulations became effective Jan. 1, 2017, and will apply to all fossil fuels used for electricity generation. The
majority of our gas-fired generation in Ontario will not be significantly impacted by virtue of change-in-law provisions within
existing power purchase agreements.
Australia
In Australia, the Senate recently passed amendments to the country’s Renewable Energy Target Scheme. The scheme was
initially introduced in 2001 with three objectives: to establish a mandatory renewable energy target to be achieved in 2020; to
provide incentives for large-scale renewable energy generators in the form of one large-scale generation certificate earned for
each MWh of generation; and to require retailers and wholesale industrial customers to purchase a specified volume of their
electricity from large-scale renewable-sourced electricity or incur a penalty of AUD$65/MWh on any shortfall. The
amendments reduced the annual targets for large-scale renewable sourced electricity down from 41,000 GWh in 2020 to
33,000 GWh in 2020, held constant at this level until 2030. It is estimated that this will require an additional
5,000-6,000 MW of new renewables capacity to be installed to add to the slightly more than 4,000 MW already operating.
Since our Australian assets are fully contracted it is not expected that these amendments will have a significant impact on our
operations.
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TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Weather
Abnormal weather events can impact our operations and give rise to risks. In addition, normal year-over-year variations in
wind, solar, water, and temperatures give rise to various levels of volume risk depending on the input fuel of each facility;
events outside the design parameters of our facilities give rise to equipment risk; and fluctuations in temperatures can cause
commodity price risk through impact on customer demand for heating or cooling. Refer to the Governance and Risk
Management section of this MD&A for further discussion of each risk and our related management strategy.
During the past three years, some deviations from expected weather patterns have negatively impacted our annual financial results:
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the Southern Alberta flood of 2013 disrupted our hydro operations and caused us to invest in substantial repair work.
Our losses have been largely covered through insurance,
warm weather in Alberta in 2015 increased derates at our coal facilities due to its impact on the Sundance cooling ponds.
These cooling ponds are susceptible to warm weather; however, we anticipate that decreased coal production and the
retirement of Sundance Units 1 and 2 in the medium term will reduce the stress from such occurrence, and
our Alberta mine was susceptible to significant rain starting in August of 2016, which resulted in several weeks of
flooding and impacted our coal deliveries. We focused on improving drainage infrastructure and use of stockpiles to
mitigate future risks.
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Over the same period, other deviations have positively impacted our financial results, such as the cold temperatures in
Eastern North America in the winter of 2014 that caused market volatility and benefitted our Energy Marketing Group.
Other Consolidated Analysis
Asset Impairment Charges and Reversals
As part of our monitoring controls, long-range forecasts are prepared for each Cash Generating Unit (“CGU”). The long-range
forecast estimates are used to assess the significance of potential indicators of impairment and provide a criteria to evaluate
adverse changes in operations. When indicators of impairment are present, we estimate a recoverable amount for each CGU
by calculating an approximate fair value less costs of disposal using discounted cash flow projections based on the
Corporation’s long-range forecasts. The valuations used are subject to measurement uncertainty based on assumptions and
inputs to our long-range forecast, including changes to fuel costs, operating costs, capital expenditures, external power prices,
and useful lives of the assets extending to the last planned asset retirement in 2073.
In 2016, we concluded that an indicator of possible impairment existed with respect to our U.S. Coal facility as the plant has
merchant exposure and price expectations in the Pacific Northwest region continued to decline. The results of the impairment
analysis are outlined in section III below.
During 2016, uncertainty continued to exist within the province of Alberta regarding the government’s previously announced
Climate Leadership Plan and the future design parameters of the electricity market. Additionally, economic conditions, while
more stable than in 2014 and 2015, contributed to continued over-supply conditions and depressed market prices. We
assessed whether these factors presented an indicator of impairment for our Alberta Merchant CGU, and in consideration of
the composition of this CGU and events arising during the latter part of 2016, which are more fully discussed below in I,
determined that no indicators of impairment were present with respect to the Alberta Merchant CGU. Due to this
determination, we did not perform an in-depth impairment analysis, but sensitivities associated with these factors were
performed to confirm the continued existence of an adequate excess of estimated recoverable amount over net book value.
There was one impairment charge of $28 million (2015 - $2 million reversal) made during the year ended Dec. 31, 2016 as a
result of the sale of our 51 per cent interest in the Wintering Hills merchant wind facility as discussed below in II.
TransAlta Corporation | 2016 Annual Integrated Report
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Management’s Discussion and Analysis
I. Alberta Merchant CGU
In 2015, the Government of Alberta announced its Climate Leadership Plan (“CLP”), which broadly called for the phase-out of
coal-generated electricity by 2030, and proposed the imposition of additional compliance obligations for GHG emissions in
the province. In 2016, the Government of Alberta refined its approach to GHG by instituting a levy on carbon emissions in
excess of defined limits, amounting to $20 per tonne in 2017 and $30 per tonne in 2018. At the federal level, the Canadian
government announced its intention to implement a national price on GHG emissions. Under this proposal, beginning in 2018,
there would be a price of $10 per tonne of carbon dioxide equivalent emitted, rising to $50 per tonne by 2022.
On November 24, 2016, we entered into the OCA with the Government of Alberta to receive annual cash payments of
approximately $37.4 million, net to us in return for ceasing coal-fired generation by the end of 2030, among other conditions.
Furthermore, we entered into an MOU on Nov. 24, 2016, with the purpose of collaborating and co-operating to advance
objectives of the Alberta CLP. Specifically, the parties collaborated on initiatives that included:
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a move toward a capacity market, commencing 2021, compared to the current energy-only market. Under a capacity
market, generators are compensated for their available capacity;
development of a policy and to facilitate the economic conversion of some coal-fired generation to natural gas-fired
generation in Alberta, including securing regulatory co-operation from the federal government; and
development of supportive and enabling policy, including policy that addresses the value of carbon reductions in the
generation of electricity from existing wind and hydro generation, the development of effective supporting mechanisms
to ensure that existing renewables generation is not adversely impacted by the implementation of a capacity market in
Alberta, and the development of regulatory clarity and alignment so as to permit the economic and timely development
of hydroelectric projects within Alberta.
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The MOU does not create any legally binding obligations between the Government of Alberta and the Corporation and does
not impose any obligations on, or constrain the discretion and authority of the Government of Alberta. The announcement of
the intention to move to a capacity market is expected to impact the Alberta market mechanisms. The Government of
Alberta has not provided further detail on the market rules or construct. The introduction of a capacity market to replace
Alberta’s current market structure could impact our determination of the Alberta Merchant CGU; however, there is not
currently sufficient information from the Government of Alberta to determine if a change is required. We have not modified
its previous conclusions on the determination of the Alberta Merchant CGU.
During the year, we monitored the potential impacts of the CLP and other announcements on the Alberta CGU. A sensitivity
analysis on these estimates to assess potential impacts of the Alberta and federal government policies on the carbon levy and
GHG emissions, as well as the impacts of the OCA and MOU. The analysis of the Alberta Merchant CGU, with its large
merchant renewable fleet, resulted in no impairment in 2016.
II. Wintering Hills
On Jan. 26, 2017, we announced the sale of our 51 per cent interest in the Wintering Hills merchant wind facility for
approximately $61 million. In connection with this sale, the Wintering Hills assets were accounted for as held for sale at
December 31, 2016. As required, we assessed the assets for impairment prior to classifying them as held for sale.
Accordingly, we have recorded an impairment charge of $28 million using the purchase price in the sale agreement as the
indicator of fair value less cost of disposal.
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TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
III. U.S. Coal
We considered possible impairment at the U.S. Coal CGU, and again found that the fair value less costs to sell approximates
the current carrying amount. We estimated the fair value less costs of disposal of the CGU, a Level III fair value measurement,
utilizing our long-range forecast and the following key assumptions:
Mid-Columbia annual average power prices
On-highway diesel fuel on coal shipments
Discount rates
US$22.68 to 45.65 per MWh
US$1.69 to 2.09 per gallon
5.4 to 5.7 per cent
The valuation is subject to measurement uncertainty based on those assumptions, and on inputs to our long-range forecast,
including changes to fuel costs, operating costs, capital expenses, and the level of contractedness under the Memorandum of
Agreement (“MoA”) for coal transition established with the State of Washington. The valuation period extended to the
assumed decommissioning of the asset, after its projected cessation of operation in its current form in 2025.
Fair value less costs of disposal of the CGU was estimated to approximate its carrying amount, and accordingly, no
impairment charge was recorded. Any adverse change in assumptions, in isolation, would have resulted in an impairment
charge being recorded. We continue to manage risks associated with the CGU through optimization of its operating activities
and capital plan.
Centralia Gas
During 2014 we sold a portion of the assets of the Centralia gas facility to external counterparties and transferred other assets
to other TransAlta facilities. The plant had been fully impaired and idled since 2010. As a result of the transaction, we
recognized impairment reversals of $5 million and the plant’s generating capacity has been removed from TransAlta’s total
owned capacity. In 2015, we reversed $2 million of previously impaired change as a result of additional recoveries. No further
reversals or impairments were recorded in 2016.
Other Significant and Subsequent Events
Alberta Off-Coal Agreement
On Nov. 24, 2016, we announced that we entered into the OCA with the Government of Alberta on transition payments in
exchange for the cessation of coal-fired emissions from the Keephills 3, Genesee 3 and Sheerness coal-fired plants on or
before Dec. 31, 2030.
Under the terms of the OCA, we will receive annual cash payments of approximately $37.4 million, net to the Corporation,
commencing in 2017 and terminating in 2030. Receipt of the payments is subject to terms and conditions. The OCA’s main
condition is the cessation of all coal-fired emissions in 2030. Other conditions include maintaining prescribed spending on
investment and investment-related activities in Alberta, maintaining a significant business presence in Alberta (including
through the maintenance of prescribed employment levels), and maintaining spending on programs and initiatives to support
the communities surrounding the plants, and the employees of the Corporation negatively impacted by the phase-out of coal
generation and fulfilling all obligations to affected employees. The affected plants are not, however, precluded from generating
electricity at any time by any method, other than the combustion of coal.
Force Majeure Relief - Keephills 1
Keephills 1 tripped off-line on March 5, 2013, due to a suspected winding failure within the generator. After extensive testing
and analysis, it was determined that a full rewind of the generator stator was required. After completing the repairs, the unit
returned to service on Oct. 6, 2013. We claimed force majeure relief on March 26, 2013. The buyer, ENMAX, disputed the
claim of force majeure, which triggered the need for an arbitration hearing that took place in May 2016. On
Nov. 18, 2016, we announced that the independent arbitration panel confirmed our claim for force majeure relief. Accordingly,
we reversed a provision of approximately $94 million. The buyer and the Balancing Pool are seeking to appeal or set the
arbitration panel’s decision aside in the Court of Queen’s Bench of Alberta. We oppose these steps and believe they are
without merit.
TransAlta Corporation | 2016 Annual Integrated Report
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Management’s Discussion and Analysis
Memorandum of Understanding with the Government
In November 2016, we additionally reached an understanding with the Government of Alberta pursuant to an MOU to
collaborate and co-operate in the development of a policy framework to facilitate the conversion of coal-fired generation to
gas-fired generation, facilitate existing and new renewable electricity development through supportive and enabling policy,
and ensure existing generation and new electricity generation are able to effectively participate in the recently announced
capacity market to be developed for the province of Alberta. Specifically, the parties undertook to collaborate on, among other
things:
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work to ensure existing incumbents and new electricity generation are able to effectively participate in capacity payment
auctions to be established as part of the development of a capacity market,
development of a policy environment to facilitate the economic and environmentally responsible conversion of some
coal-fired generation to natural gas-fired generation in Alberta, including securing regulatory cooperation from the
federal government, and
development of supportive and enabling policy, including policy that addresses the value of carbon reductions in the
generation of electricity from existing wind and hydro generation, the development of effective supporting mechanisms
to ensure that existing renewables generation is not adversely impacted by the implementation of a capacity market in
Alberta, and the development of regulatory clarity and alignment so as to permit the economic and timely development
of hydroelectric projects within Alberta.
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The MOU does not create any legally binding obligations between the Government of Alberta and the Corporation and does
not impose any obligations on, or constrain the discretion and authority of, the Government of Alberta.
Mississauga Cogeneration Facility New Contract
On Dec. 22, 2016, we announced that we had signed a Non-Utility Generator (“NUG”) Enhanced Dispatch Contract
(the “NUG Contract”) with the IESO for our Mississauga cogeneration facility (the “Mississauga Facility”). The NUG Contract
is effective on Jan. 1, 2017, and in conjunction with the execution of the NUG Contract, we agreed to terminate effective
Dec. 31, 2016, the Facility’s pre-existing contract with the Ontario Electricity Financial Corporation, which would have
otherwise terminated in December 2018.
The NUG Contract provides us stable monthly payments until Dec. 31, 2018, totalling approximately $209 million, reduced
operational costs, and the ability to maintain operational flexibility to pursue opportunities for the Mississauga Facility to meet
power market needs in northeastern Ontario.
As a result of the NUG Contract, we recognized a pre-tax gain of approximately $191 million. The predominant components of
the gain relate to recognition of a one-time discounted revenue amount of approximately $207 million, offset by onerous
contract expenses and other termination charges totalling $15 million. We also recognized $46 million in accelerated
depreciation resulting from the change in useful life of the asset. We released and recognized in earnings unrealized pre-tax
losses of net $14 million from Accumulated Other Comprehensive Income (“AOCI”) due to cash flow hedges de-designated
for accounting purposes. The cash flow hedges were in respect of future gas purchases denominated in US dollars expected to
occur between 2017 and 2018. In the fourth quarter of 2016, the forecasted gas consumption was no longer expected to
occur, which resulted in the cumulative loss on the hedging instruments being released from AOCI and recognized in earnings.
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Management’s Discussion and Analysis
Investment and Acquisition by TransAlta Renewables of the Sarnia Cogeneration Plant, Le Nordais Wind Farm, and Ragged
Chute Hydro Facility
On Jan. 6, 2016, TransAlta Renewables completed its investment in an economic interest based on the cash flows of the
Corporation’s Canadian Assets for a combined aggregate value of approximately $540 million. The Canadian Assets consist
of approximately 611 MW of highly contracted power generation assets located in Ontario and Québec. The transaction was
originally announced on Nov. 23, 2015.
As consideration, TransAlta Renewables provided to the Corporation $173 million in cash, issued 15,640,583 common shares
with an aggregate value of $152 million, and issued a $215 million convertible unsecured subordinated debenture. The
debenture issued by TransAlta Renewables to the Corporation is on an interest-only basis at a coupon of 4.5 per cent per
annum payable semi-annually in arrears on June 30 and December 31, and will mature on Dec. 31, 2020. On the maturity
date, the Corporation will have the right, at its sole option, to convert the outstanding principal amount of the debenture, in
whole or in part, into common shares of TransAlta Renewables at a conversion price of $13.16 per common share, being a
35 per cent premium to the offering price on the closing date of the investment in the Canadian Assets. If TransAlta does not
exercise its conversion option, TransAlta Renewables may satisfy the principal obligation through issuance of common shares
with a unit value corresponding to 95 per cent of its then-current common share value.
TransAlta Renewables funded the cash proceeds through the public issuance of 17,692,750 subscription receipts at a price of
$9.75 per subscription receipt. Upon the closing of the transaction, each holder of subscription receipts received, for no
additional consideration, one common share of TransAlta Renewables and a cash dividend equivalent payment of $0.07 for
each subscription receipt held. As a result, TransAlta Renewables issued 17,692,750 common shares and paid a total dividend
equivalent of $1 million. Share issuance costs amounted to $8 million, net of $2 million income tax recovery. On Jan. 6, 2016,
TransAlta Renewables declared a dividend increase of 5 per cent.
On Nov. 30, 2016, TransAlta Renewables acquired direct ownership of the Canadian Assets from the Corporation for a
purchase price of $520 million by issuing a promissory note. At the same time, the Corporation’s subsidiary redeemed the
preferred shares that it had issued to TransAlta Renewables in January 2016 when TransAlta Renewables acquired an
economic interest in the Canadian Assets as described above for $520 million. The two transactions were subject to a set-off
arrangement and resulted in no cash payments. TransAlta Renewables also acquired working capital and certain capital
spares totalling $19 million through the issuance of a non-interest bearing loan payable to the Corporation.
Wintering Hills Sale
On Jan. 26, 2017, we announced the sale of our 51 per cent interest in the Wintering Hills merchant wind facility for
approximately $61 million. Proceeds from the sale will be used for general corporate purposes, including reducing our debt
and funding future renewables growth. The sale closed March 1, 2017. We acquired the interest in Wintering Hills in 2015 in
connection with the restructuring of the arrangements associated with our Poplar Creek cogeneration facility. As at
Dec. 31, 2016, the assets are classified as held for sale, and were measured at the lower of carrying amount and fair value less
costs to sell, resulting in an impairment charge of $28 million, included in the Wind and Solar segment. This arrangement
provides us with near-term liquidity and increases our financial flexibility to pay down debt maturities.
Preferred Share Exchange
On Feb. 10, 2017, we announced that we would not proceed with the transaction previously announced Dec. 19, 2016 pursuant
to which all currently outstanding first preferred shares in the capital of the Corporation would be exchanged for shares in a
single new series of cumulative redeemable minimum rate reset first preferred shares.
TransAlta Corporation | 2016 Annual Integrated Report
M54
Management’s Discussion and Analysis
Financial Position
The following chart highlights significant changes in the Consolidated Statements of Financial Position from Dec. 31, 2016, to
Dec. 31, 2015:
Assets
Cash and cash equivalents
Trade and other receivables
Increase/
(decrease)
251
Primary factors explaining change
Timing of receipts and payments, and non-recourse bond
offerings
136
Timing of customer receipts and seasonality of revenue, and
current Mississauga facility recontracting receivable ($91
million)
Assets held for sale
61
Transfer of Wintering Hills wind facility from PP&E
Finance lease receivables (long term)
(56)
Property, plant, and equipment, net
(349)
Unfavourable changes in foreign exchange rates
($12 million) and scheduled receipts ($56 million), partially
offset by an increase due to completion of gas conversion work
at the Solomon gas plant ($14 million)
Depreciation for the period ($607 million), unfavourable
changes in foreign exchange rates ($46 million), retirement of
assets ($21 million), partially offset by additions ($358 million),
revisions to decommissioning and restoration costs ($71
million), and transfer of Wintering Hills to assets held for sale
($61 million)
Intangible assets
(14)
Amortization ($38 million), partially offset by additions ($24
million)
Deferred income tax assets
(18)
Decreases in deductible temporary differences
Risk management assets (current and long term)
Other assets
Other
Total decrease in assets
Liabilities and equity
Accounts payable and accrued liabilities
Credit facilities, long term debt, and finance lease
obligations (including current portion)
Decommissioning and other provisions (current
and long term)
Defined benefit obligation and other
long term liabilities
Deferred income tax liabilities
Risk management liabilities (current and
long term)
(61)
109
(10)
49
Increase/
(decrease)
79
(134)
(55)
(18)
65
Unfavourable changes in foreign exchange rates and contract
settlements, partially offset by favourable market price
movements
Mississauga facility recontracting long term receivable
($116 million)
Primary factors explaining change
Timing of payments and accruals
Credit facility repayment ($315 million), repayment of long
term debt ($88 million), and favourable effects of changes in
foreign exchange rates ($67 million), partially offset by bond
issuances ($362 million)
Keephills 1 provision reversal ($94 million) and liabilities
settled ($59 million), partially offset by a decrease in risk-
adjusted discount rates ($44 million)
Amortization of deferred revenue ($7 million) and actuarial
gains ($8 million)
Mississauga recontracting and increase in taxable temporary
differences
(155)
Favourable market price movements and contract settlements
Equity attributable to shareholders
150
Non-controlling interests
Other
Total decrease in liabilities and equity
123
(6)
49
Net earnings ($169 million), issuance of common shares
($19 million), gains on cash flow hedges ($106 million), and
changes in non-controlling interests in TransAlta Renewables
($26 million), partially offset by net losses on translating net
assets of foreign operations ($53 million) and common and
preferred share dividends ($110 million)
Sale of economic interests to TransAlta Renewables, partially
offset by distributions paid and payable to non-controlling
interests
M55
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Cash Flows
The following chart highlights significant changes in the Consolidated Statements of Cash Flows for the year ended Dec. 31,
2016, compared to the years ended Dec. 31, 2015 and Dec. 31, 2014:
Year ended Dec. 31
Cash and cash equivalents, beginning of year
Provided by (used in):
Operating activities
2016
54
2015 Primary factors explaining change
43
744
432
Favourable change in non-cash working capital of $315 million
Investing activities
(327) (573) Lower additions to property, plant, and equipment
Financing activities
(163)
149
($118 million), a higher decrease in finance lease receivables
($33 million), and a decrease in our renewable asset acquisitions
($101 million)
Increase in repayments of borrowings under credit facilities
($533 million), lower issuance of long-term debt ($126 million),
lower proceeds on the sale of non-controlling interest in a
subsidiary ($242 million), higher distributions paid to
subsidiaries' non-controlling interests ($52 million), and lower
realized gains on financial instruments ($89 million), partially
offset by lower dividends paid to common shareholders ($55
million) and lower repayment of long-term debt ($670 million).
Translation of foreign currency cash
Cash and cash equivalents, end of year
Year ended Dec. 31
Cash and cash equivalents, beginning of year
Provided by (used in):
Operating activities
(3)
305
2015
43
432
42
796
3
54
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)
TransAlta Corporation | 2016 Annual Integrated Report
M56
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, 2016, we provided letters of credit totalling $566 million (2015 - $575 million)
and cash collateral of $77 million (2015 - $74 million). These letters of credit and cash collateral secure certain amounts
included on our Consolidated Statements of Financial Position under risk management liabilities and decommissioning and
other provisions.
Commitments 1
Contractual commitments are as follows:
2017
2018
2019
2020
2021
Natural gas, transportation,
and other purchase contracts
Transmission
Coal supply and mining agreements(1)
Long-term service agreements
Non-cancellable operating leases(2)
Long-term debt(3)
Principal payments on finance
lease obligations
Interest on long-term debt and
finance lease obligations(4)
Growth
TransAlta Energy Bill
Total
40
9
163
79
7
623
16
219
181
6
13
11
48
29
7
959
14
174
5
6
1,343
1,266
6
8
49
24
7
461
10
143
1
6
715
5
8
51
41
7
460
8
117
-
6
703
2022 and
thereafter
100
3
472
51
68
Total
169
43
835
254
103
1,745
4,311
19
73
764
1,508
-
12
187
42
5
4
52
30
7
63
6
91
-
6
264
3,234
7,525
As part of the TransAlta Energy Bill signed into law in the State of Washington and the subsequent MoA, we have committed
to fund US$55 million over the remaining life of the U.S. Coal plant to support economic and community development,
promote energy efficiency, and develop energy technologies related to the improvement of the environment. The MoA
contains certain provisions for termination and in the event of the termination and certain circumstances, this funding or part
thereof would no longer be required.
I. Line Loss Rule Proceeding
TransAlta is participating in a line loss rule proceeding (the "LLRP") which is currently before the AUC. The AUC determined
that it had the ability to retroactively adjust line loss rates beginning in 2006 and has directed the Alberta Electric System
Operator (the "AESO"), among other actions, to perform such calculations. The various decisions by the AUC are subject to
appeal and challenge. TransAlta may incur additional transmission charges as a result of the LLRP. The outcome of the LLRP
remains uncertain and the potential exposure, if any, cannot be calculated with any degree of certainty until the retroactive
calculations are made available. The AESO expects retroactive calculations to be available mid-2017, at the earliest. As a
result, no provision has been recorded. Certain PPAs for TransAlta’s Alberta facilities provide for the pass through of these
types of transmission charges to TransAlta’s buyers.
(1) Commitments related to Sheerness and Genesee 3 may be impacted by the cessation of coal-fired emissions on or before Dec. 31, 2030.
(2) Includes amounts under certain evergreen contracts on the assumption of the Corporation's continued operations.
(3) Excludes impact of derivatives.
(4) Interest on long-term debt is based on debt currently in place with no assumption as to refinancing on maturity.
M57
TransAlta Corporation | 2016 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.
TransAlta Corporation | 2016 Annual Integrated Report
M58
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 have historically been used to hedge exposure to
changes in the carrying values of our net investments in foreign operations that have a functional currency other than the
Canadian dollar. In late 2016 we modified our net investment hedging practices and are no longer using foreign currency
forward contracts in our hedges. Our net investment hedges using U.S.-denominated debt remain effective and in place. Gains
or losses on these instruments are recognized and deferred in OCI and reclassified to net earnings on the disposal of the
foreign operation. We also manage foreign exchange risk by matching foreign-denominated expenses with revenues, such as
offsetting revenues from our U.S. operations with interest payments on our US dollar debt.
Non-Hedges
Financial instruments not designated as hedges are used for proprietary trading and to reduce commodity price, foreign
exchange, and interest rate risks. Changes in the fair value of financial instruments not designated as hedges are recognized in
risk management assets or liabilities, and the related gains or losses are recognized in net earnings in the period in which the
change occurs.
Fair Values
The majority of fair values for our project, foreign exchange, interest rate, commodity hedges, and non-hedge derivatives are
calculated using adjusted quoted prices from an active market or inputs validated by broker quotes. We may enter into
commodity transactions involving non-standard features for which market-observable data is not available. These
transactions are defined under IFRS as Level III instruments. Level III instruments incorporate inputs that are not observable
from the market, and fair value is therefore determined using valuation techniques. Fair values are validated by using
reasonably possible alternative assumptions as inputs to valuation techniques, and any material differences are disclosed in
the notes to the financial statements. At Dec. 31, 2016, Level III instruments had a net asset carrying value of $758 million.
Refer to the Critical Accounting Policies and Estimates section of this MD&A for further details regarding valuation
techniques. Our risk management profile and practices have not changed materially from Dec. 31, 2015, with the exception of
the changes to our net investment hedge strategy, as discussed above and in the Governance and Risk Management section
of this MD&A.
M59
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
2017 Financial Outlook
For 2017, we expect our results to be slightly better than 2016 given the positive contribution from South Hedland, which is
expected to be operational by mid-2017, and the receipt of the first coal transition payment from the Government of Alberta.
The outlook also accounts for expected continuing weak power prices in Alberta, the Pacific Northwest, and the impact of
lower priced power hedges in 2017. Approximately 85 per cent of our capacity in Alberta is contracted, either through power
PPAs or financial contracts at an average price of $45 MWh to $50 MWh. Our performance next year will also be impacted
by an increase in our fuel costs caused by a planned major outage to one of the large draglines at the Highvale Mine.
The following table outlines our expectation on key financial targets for 2017:
Measure
Comparable EBITDA
Comparable FFO
Comparable FCF
Dividend
Target
$1,025 million to $1,135 million
$765 million to $855 million
$300 million to $365 million
$0.16 per share annualized, 13 to 15 per cent payout of Comparable FCF
Operations
Availability
Availability of our coal fleet is expected to be in the range of 86 to 88 per cent in 2017. Availability of our other generating
assets (gas, renewables) generally exceeds 95 per cent.
Fuel Costs
The cost to mine coal in Alberta is expected to increase due to a major outage of a dragline. Seasonal variations in coal costs
at our Alberta mine are minimized through the application of standard costing. Coal costs for 2017, on a standard cost per
tonne basis, are expected to be approximately 12 per cent higher than 2016 unit costs.
In the Pacific Northwest, our U.S. Coal mine, adjacent to our power plant, is in the reclamation stage. Fuel at U.S. Coal has
been purchased primarily from external suppliers in the Powder River Basin and delivered by rail. The delivered fuel cost will
increase slightly in 2017 primarily due to higher transportation costs.
Most of our generation from gas is sold under contract with pass-through provisions for fuel. For gas generation with no pass-
through provision, we purchase natural gas from outside companies coincident with production, thereby minimizing our risk
to changes in prices.
We closely monitor the risks associated with changes in electricity and input fuel prices on our future operations and, where we
consider it appropriate, use various physical and financial instruments to hedge our assets and operations from such price risks.
Energy Marketing
EBITDA from our Energy Marketing segment is affected by prices and volatility in the market, overall strategies adopted, and
changes in regulation and legislation. We continuously monitor both the market and our exposure to maximize earnings while
still maintaining an acceptable risk profile. Our 2017 objective for Energy Marketing is for the segment to contribute between
$70 million to $90 million in gross margin for the year.
Exposure to Fluctuations in Foreign Currencies
Our strategy is to minimize the impact of fluctuations in the Canadian dollar against the US dollar, and Australian dollar by
offsetting foreign-denominated assets with foreign-denominated liabilities and by entering into foreign exchange contracts.
We also have foreign-denominated expenses, including interest charges, which largely offset our net foreign-denominated
revenues.
TransAlta Corporation | 2016 Annual Integrated Report
M60
Management’s Discussion and Analysis
Net Interest Expense
Net interest expense for 2017 is expected to be higher than in 2016 largely due to lower capitalized interest. However,
changes in interest rates and in the value of the Canadian dollar relative to the US dollar can affect the amount of net interest
expense incurred.
Net Debt, Liquidity, and Capital Resources
We expect to maintain adequate available liquidity under our committed credit facilities. We currently have access to
$1.7 billion in liquidity including more than $300 million in cash. Our continued focus will be toward repositioning our capital
structure and we expect to be well positioned to address the upcoming debt maturities in 2017 and 2018.
Capital Expenditures
Our major projects are focused on sustaining our current operations and supporting our growth strategy in our renewables
platform.
A summary of the significant growth and major projects that are in progress is outlined below:
Total Project
Estimated
spend
Spent to
date(1)
2017
Estimated
spend
Target
completion
date
Details
576
336
230 - 250
Q2 2017
150 MW combined-cycle power plant
Project
South Hedland
power project(2)
Solomon load bank
facility
5
2
Transmission
Not applicable(3)
3
3
Q1 2017
Installation of 20MW load bank facility required
to support the operation of the Solomon power
station
Ongoing
Regulated transmission that receives a return on
investment
Total
581
338
256 - 276
Cash required to fund the construction of the South Hedland power project is expected to be partially funded by proceeds
from project financing and cash generated by our business.
1 234
(1) Represents amounts spent as of Dec. 31, 2016.
(2) Estimated project expenditures are AUD$553 million. Total estimated project expenditures are stated in CAD$ and includes estimated capital interest costs. The total
estimated project expenditures may change due to fluctuations in foreign exchange rates.
(3) Transmission projects are aggregated and develop on an ongoing basis. Consequently, discrete project expenditures are not available.
M61
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
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(1)
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 2015
Spent in
2016
101
162
25
13
301
4
305
6
311
83
148
23
16
270
2
272
8
280
Expected
spend
in 2017
85 - 90
125 - 130
30 - 35
20 - 25
260 - 280
-
260 - 280
10 - 15
270 - 295
Significant planned major outages for 2017 include the following:
(cid:131)
(cid:131)
(cid:131)
four major outages in which two relate to our partners, and a major outage to draglines at our Canadian Coal segment,
three major outages in our Canadian Gas segment related to our Sarnia and Windsor facilities,
one major outage in our Alberta Hydro segment and distributed planned maintenance expenditures across the entire
fleet, and
distributed expenditures across our wind fleet, focusing on planned component replacements.
(cid:131)
Lost production as a result of planned major maintenance, excluding planned major maintenance for U.S. Coal, which is
scheduled during a period of economic dispatching, is estimated as follows for 2017:
GWh lost
Coal
Gas and
Renewables
Total
895 - 905
200 - 230
1,095 - 1,135
Funding of Capital Expenditures
Funding for these planned capital expenditures is expected to be provided by cash flow from operating activities, existing
liquidity, and capital raised from our contracted cash flows. We have access to approximately $1.7 billion in liquidity, if
required. The funds required for committed growth, sustaining capital, and productivity projects are not expected to be
significantly impacted by the current economic environment.
(1) Includes hydro life extension expenditures.
TransAlta Corporation | 2016 Annual Integrated Report
M62
Management’s Discussion and Analysis
Sustainable Development Targets
Our 2017 and longer-term sustainability targets support the long-term success of our business. Targets are set in line with
business unit goals to manage key areas of concern for stakeholders and ultimately improve our environmental and social
performance in these areas. We continue to evolve and adapt targets to focus on anticipated key areas of materiality to
stakeholders. Targets are outlined below:
1. Reduce safety incidents
Achieve an Injury Frequency Rate below 0.50
Human and Intellectual
2. Manage employee turnover Maintain voluntary turnover percentage under eight per cent
Annual Performance Status
33 per cent improvement over
2016 target of 0.75
Consistent with 2016 target, we
seek to maintain voluntary
turnover under 8 per cent as this
is considered a healthy amount
of turnover
3. Support employee
development
Continue development plans for all high-potential employees at the
top three levels of the organization
Consistent with 2016 target,
ongoing leadership development
Natural
4. Minimize fleet-wide
environmental incidents
Keep recorded incidents (including spills and air infractions)
below 11
5. Increase mine reclaimed
acreage
Replace annual topsoil at Highvale mine at a rate of
74 acres/year
Annual Performance Status
15 per cent improvement over
2016 target (13)
Consistent with 2016 target (74
acres)
6. Utilize coal by-product
Sell a minimum of two million tonnes of coal byproduct materials
during the period 2015 to 2017
70 per cent achieved (on a target
to meet 2 million tonnes in 2017)
7. Reduce air emissions
8. Reduce GHG emissions
95 per cent reduction from 2005 levels of TransAlta coal facility
NOx and SO2 emissions by 2030
Our goal, in line with a commitment to the UN Sustainable
Development Goals (SDGs), is to reduce our total GHG emissions in
2021 to 30 per cent below 2015 levels
Our goal, in line with a commitment to the UN SDGs and prevention
of two degrees Celsius of global warming, is to reduce our total
greenhouse gas emissions in 2030 to 60 per cent below 2015 levels
Consistent with 2016 (long-term
target)
Revised baseline to align with
COP21 commitments and target
aligned with UN Sustainable
Development Goals
Revised baseline to align with
COP21 commitments; target
aligned with Science Based
Targets Initiative and prevention
of two degrees Celsius of global
warming; and target aligned with
UN SDGs
9. Support youth education with
community investment
Approximately $0.75 million of community investment spending will
be directed to supporting youth education
Revision from 2015, which was
50% of total community
Social and Relationship
Annual Performance Status
10. Increase internal best
practice Aboriginal engagement
awareness
Develop an engagement and consultation best practices document
for project planning and development as a guide for employees to
work with indigenous communities and stakeholders
New target
d
d
d
Comprehensive
10. Transition from coal to gas-
fired and renewable generation
Continue negotiations with the Government of Alberta, using a
principles based approach, to ensure we have regulation certainty
and the capacity needed to invest in clean power.
Annual Performance Status
New target
M63
TransAlta Corporation | 2016 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:
(cid:131)
(cid:131)
(cid:131)
(cid:131)
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.
(cid:131)
(cid:131)
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:
(cid:131)
(cid:131)
(cid:131)
(cid:131)
Corporate Code of Conduct, which applies to all employees and officers of TransAlta and its subsidiaries,
Directors’ Code of Conduct,
Finance Code of Ethics, which applies to all financial employees of the Corporation, and
Energy Trading Code of Conduct, which applies to all of our employees engaged in energy marketing.
Our codes of conduct outline the standards and expectations we have for our employees, officers, and directors with respect
to the protection and proper use of our assets. The codes also provide guidelines with respect to securing our assets, conflicts
of interest, respect in the workplace, social responsibility, privacy, compliance with laws, insider trading, environment, health
and safety, and our commitment to ethical and honest conduct. Our Corporate Code of Conduct goes beyond the laws, rules,
and regulations that govern our business in the jurisdictions in which we operate; it outlines the principal business practices
with which all employees must comply.
Our employees, officers, and directors are reminded annually about the importance of ethics and professionalism in their daily
work, and must certify annually that they have reviewed and understand their responsibilities as set forth in the respective
codes of conduct. This certification also requires our employees, officers, and directors to acknowledge that they have
complied with the standards set out in the respective code during the last calendar year.
The Board provides stewardship of the Corporation and ensures that the Corporation establishes key policies and procedures
for the identification, assessment, and management of principal risks and strategic plans. The Board monitors and assesses
the performance and progress of the Corporation’s goals through candid and timely reports from the CEO and the senior
management team. We have also established an annual evaluation process whereby our directors are provided with an
opportunity to evaluate the Board, Board committees, individual directors, and the chair’s performance.
In order to allow the Board to establish and manage the financial, environmental, and social elements of our governance
practices, the Board has established the Audit and Risk Committee (“ARC”), the GEC, and the Human Resources Committee
(the “HRC”).
TransAlta Corporation | 2016 Annual Integrated Report
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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 reporting.
The GEC is responsible for developing and recommending to the Board a set of corporate governance principles applicable to
the Corporation and for monitoring the compliance with these principles. The GEC is also responsible for Board recruitment
and for the nomination of directors to the Board and its committees. In addition, the GEC assists the Board in fulfilling its
oversight responsibilities with respect to the Corporation’s monitoring of environmental, health and safety regulations and
public policy changes and the establishment and adherence to environmental, health and safety practices, procedures, and
policies. The GEC also receives an annual report on the annual Corporate Code of Conduct certification process.
In regards to overseeing and seeking to ensure that the Corporation consistently achieves strong environment, health, and
safety (“EH&S”) performance, the GEC undertakes a number of actions that include: (i) receiving regular reports from
management regarding environmental compliance, trends, and TransAlta’s responses; (ii) receiving reports and briefings on
management’s initiatives with respect to changes in climate change legislation, policy developments as well as other draft
initiatives and the potential impact such initiatives may have on our operations; (iii) assessing the impact of the GHG policies
implementation and other legislative initiatives on the Corporation’s business; (iv) reviewing with management the EH&S
policies of the Corporation; (v) reviewing with management the health and safety practices implemented within the
Corporation, as well as the evaluation and training processes put in place to address problem areas; (vi) receiving reports from
management on the near-miss reporting program and discussing with management ways to improve the EH&S processes and
practices; and (vi) reviewing the effectiveness of our response to EH&S issues and any new initiatives put in place to further
improve the Corporation’s EH&S culture.
The HRC is empowered by the Board to review and approve key compensation and human resources policies of the
Corporation that are intended to attract, recruit, retain, and motivate employees of the Corporation. The HRC also makes
recommendations to the Board regarding the compensation of the Corporation’s executive officers, including the review and
adoption of equity-based incentive compensation plans, the adoption of human resources policies that support human rights
and ethical conduct, and the review and approval of executive management succession and development plans.
The responsibilities of other stakeholders within our risk management oversight structure are described below:
The CEO and senior management review key risks quarterly. Specific Trading Risk Management reviews are held monthly by
the Commodity and Compliance Risk Committee, and weekly by the Managing Director Commodity Risk, the commercial
managing directors in Trading and Marketing, and the Senior Vice-President Trading and Marketing.
The Investment Committee is chaired by our Chief Financial Officer and is comprised of the CEO, Chief Financial Officer,
Chief Legal and Compliance Officer and Corporate Secretary, and Chief Investment Officer. It reviews and approves all major
capital expenditures including growth, productivity, life extensions, and major coal outages. Projects that are approved by the
committee will then be put forward for approval by the Board, if required.
The Commodity Risk & Compliance Committee is chaired by our Chief Financial Officer and is comprised of the Chief
Financial Officer, Chief Legal and Compliance Officer and Senior Vice President, Energy Marketing. It oversees the risk and
compliance program in trading and ensures that this program is adequately resourced to monitor trading operations from a
risk and compliance perspective. It also ensures the existence of appropriate controls, processes, systems and procedures to
monitor adherence to policy.
TransAlta is listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange and is subject to the governance
regulations, rules, and standards applicable under both exchanges. Our corporate governance practices meet the following
governance rules of the TSX and Canadian Securities Administrators: (i) Multilateral Instrument 52-109 - Certification of
Disclosure in Issuers’ Annual and Interim Filings; (ii) Multilateral Instrument 52-110 - Audit Committees; (iii) National Policy
58-201 - Corporate Governance Guidelines; and (iv) National Instrument 58-101 - Disclosure of Corporate Governance
M65
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Practices. As a “foreign private issuer” under U.S. securities laws, we are generally permitted to comply with Canadian
corporate governance requirements. Additional information regarding our governance practices can be found in our
management proxy circular.
Risk Controls
Our risk controls have several key components:
Enterprise Tone
We strive to foster beliefs and actions that are true to, and respectful of, our many stakeholders. We do this by investing in
communities where we live and work, operating and growing sustainably, putting safety first, and being responsible to the
many groups and individuals with whom we work.
Policies
We maintain a comprehensive set of enterprise-wide policies. These policies establish delegated authorities and limits for
business transactions, as well as allow for an exception approval process. Periodic reviews and audits are performed to ensure
compliance with these policies. All employees and directors are required to sign a code of conduct on an annual basis.
Reporting
On a regular basis, residual risk exposures are reported to key decision makers including the Board, senior management, and
the Commodity Risk & Compliance Committee. Reporting to this committee includes analysis of new risks, monitoring of
status to risk limits, review of events that can affect these risks, and discussion and review of the status of actions to minimize
risks. This quarterly reporting provides for effective and timely risk management and oversight.
Whistleblower System
We have a process in place where employees, shareholders, or other stakeholders may anonymously report any potential
ethical concerns. These concerns can be submitted confidentially and anonymously, either directly to the ARC or to
TransAlta’s Ethics Helpline. All complaints are investigated and the ARC receives a report at every scheduled committee
meeting on all findings. If the findings are urgent, they will be reported to the Chair of the Board immediately.
Value at Risk and Trading Positions
Value at risk (“VaR”) is one of the primary measures used to manage our exposure to market risk resulting from commodity
risk management activities. VaR is calculated and reported on a daily basis. This metric describes the potential change in the
value of our trading portfolio over a three-day period within a 95 per cent confidence level, resulting from normal market
fluctuations.
VaR is a commonly used metric that is employed by industry to track the risk in commodity risk management positions and
portfolios. Two common methodologies for estimating VaR are the historical variance/covariance and Monte Carlo approaches.
We estimate VaR using the historical variance/covariance approach. An inherent limitation of historical variance/covariance VaR
is that historical information used in the estimate may not be indicative of future market risk. Stress tests are performed
periodically to measure the financial impact to the trading portfolio resulting from potential market events, including fluctuations
in market prices, volatilities of those prices, and the relationships between those prices. We also employ additional risk mitigation
measures. VaR at Dec. 31, 2016, associated with our proprietary commodity risk management activities was $2 million
(2015 - $5 million). Refer to the Commodity Price Risk section of this MD&A for further discussion.
Risk Factors
Risk is an inherent factor of doing business. The following section addresses some, but not all, risk factors that could affect our
future results and our activities in mitigating those risks. These risks do not occur in isolation, but must be considered in
conjunction with each other.
For some risk factors we show the after-tax effect on net earnings of changes in certain key variables. The analysis is based on
business conditions and production volumes in 2016. Each item in the sensitivity analysis assumes all other potential variables
are held constant. While these sensitivities are applicable to the period and the magnitude of changes on which they are
based, they may not be applicable in other periods, under other economic circumstances, or for a greater magnitude of
changes. The changes in rates should also not be assumed to be proportionate to earnings in all instances.
TransAlta Corporation | 2016 Annual Integrated Report
M66
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 is partially dependent upon the availability of their input resources in a given year. Where we are
unable to produce sufficient quantities of output in relation to contractually specified volumes, we may be required to pay
penalties or purchase replacement power in the market.
We manage volume risk by:
(cid:131)
actively managing our assets and their condition in order to be proactive in plant maintenance so that our plants are
available to produce when required;
(cid:131) 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.
(cid:131)
(cid:131)
The sensitivity of volumes to our net earnings is shown below:
Factor
Availability/production
Increase or
decrease (%)
1
Approximate impact
on net earnings
10
Generation Equipment and Technology Risk
There is a risk of equipment failure due to wear and tear, latent defect, design error or operator error, among other things,
which could have a material adverse effect on the Corporation. Although our generation facilities have generally operated in
accordance with expectations, there can be no assurance that they will continue to do so. Our plants are exposed to
operational risks such as failures due to cyclic, thermal, and corrosion damage in boilers, generators, and turbines, and other
issues that can lead to outages and increased volume risk. If plants do not meet availability or production targets specified in
their PPA or other long-term contracts, we may be required to compensate the purchaser for the loss in the availability of
production or record reduced energy or capacity payments. For merchant facilities, an outage can result in lost merchant
opportunities. Therefore, an extended outage could have a material adverse effect on our business, financial condition, results
of operations, or our cash flows.
As well, we are exposed to procurement risk for specialized parts that may have long lead times. If we are unable to procure
these parts when they are needed for maintenance activities, we could face an extended period where our equipment is
unavailable to produce electricity.
We manage our generation equipment and technology risk by:
(cid:131)
operating our generating facilities within defined and proven operating standards that are designed to maximize the
availability of our generating facilities for the longest period of time,
performing preventive maintenance on a regular basis,
adhering to a comprehensive plant maintenance program and regular turnaround schedules,
adjusting maintenance plans by facility to reflect the equipment type and age,
having sufficient business interruption coverage in place in the event of an extended outage,
having force majeure clauses in our thermal and other PPAs and other long-term contracts,
using proven technology in our generating facilities,
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131) monitoring technological advances and evaluating their impact upon our existing generating fleet and related
(cid:131)
(cid:131)
(cid:131)
maintenance programs,
negotiating strategic supply agreements with selected vendors to ensure key components are available in the event of a
significant outage,
entering into long-term arrangements with our strategic supply partners to ensure availability of critical spare parts, and
developing a long-term asset management strategy with the objective of maximizing the life cycles of our existing
facilities and/or replacing of selected generating assets.
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TransAlta Corporation | 2016 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,
(cid:131)
(cid:131) 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.
(cid:131)
(cid:131)
In 2016, we had approximately 88 per cent (2015 - 90 per cent) of production under short-term and long-term contracts and
hedges. In the event of a planned or unplanned plant outage or other similar event, however, we are exposed to changes in
electricity prices on purchases of electricity from the market to fulfil our supply obligations under these short- and long-term
contracts.
We manage the financial exposure to fluctuations in the costs of fuels used in production by:
(cid:131)
(cid:131)
(cid:131)
entering into long-term contracts that specify the price at which fuel is to be supplied to our plants,
hedging emissions costs by entering into various emission trading arrangements, and
selectively using hedges, where available, to set prices for fuel.
In 2016, 79 per cent (2015 - 66 per cent) of our cost of gas used in generating electricity was contractually fixed or passed
through to our customers and 100 per cent (2015 - 100 per cent) of our purchased coal costs were contractually fixed.
The sensitivities of price changes to our net earnings, assuming production consistent with 2016 and applying the contractual
profile in place at Dec. 31, 2016, are shown below:
Factor
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.
Coal Supply Risk
Having sufficient fuel available when required for generation is essential to maintaining our ability to produce electricity under
contracts and for merchant sale opportunities. At our coal-fired plants, input costs, such as diesel, tires, the price and
availability of mining equipment, the volume of overburden removed to access coal reserves, rail rates, and the location of
mining operations relative to the power plants are some of the exposures in our operations. Additionally, the ability of the
mines to deliver coal to the power plants can be impacted by weather conditions and labour relations. At U.S. Coal,
interruptions at our supplier’s mine, the availability of trains to deliver coal, and the financial viability of our coal suppliers
could affect our ability to generate electricity.
TransAlta Corporation | 2016 Annual Integrated Report
M68
Management’s Discussion and Analysis
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
We manage coal supply risk by:
(cid:131)
ensuring that the majority of the coal used in electrical generation in Alberta is from reserves permitted through coal
rights we have purchased or for which we have long-term supply contracts, thereby limiting our exposure to fluctuations
in the supply of coal from third parties,
using longer-term mining plans to ensure the optimal supply of coal from our mines,
sourcing the majority of the coal used at U.S. Coal under a mix of short-, medium-, and long-term contracts and from
multiple mine sources to ensure sufficient coal is available at a competitive cost,
contracting sufficient trains to deliver the coal requirements at U.S. Coal,
ensuring coal inventories on hand at Canadian Coal and U.S. Coal are at appropriate levels for usage requirements,
ensuring efficient coal handling and storage facilities are in place so that the coal being delivered can be processed in a
timely and efficient manner,
(cid:131) monitoring and maintaining coal specifications, carefully matching the specifications mined with the requirements of our
plants,
(cid:131) monitoring the financial viability of U.S. coal suppliers, and
hedging diesel exposure in mining and transportation costs.
(cid:131)
Environmental Compliance Risk
Environmental compliance risks are risks to our business associated with existing and/or changes in environmental
regulations. New emission reduction objectives for the power sector are being established by governments in Canada
(including as set forth in the Alberta Climate Leadership Plan) and the U.S. We anticipate continued and growing scrutiny by
investors relating to sustainability performance. These changes to regulations may affect our earnings by reducing the
operating life of generating facilities, imposing additional costs on the generation of electricity, such as emission caps or tax,
requiring additional capital investments in emission capture technology, or requiring us to invest in offset credits. It is
anticipated that these compliance costs will increase due to increased political and public attention to environmental
concerns.
We manage environmental compliance risk by:
(cid:131)
seeking continuous improvement in numerous performance metrics such as emissions, safety, land and water impacts,
and environmental incidents,
having an International Organization for Standardization and Occupational Health and Safety Assessment Series-based
environmental health and safety management system in place that is designed to continuously improve performance,
committing significant experienced resources to work with regulators in Canada and the U.S. to advocate that regulatory
changes are well designed and cost effective,
developing compliance plans that address how to meet or surpass emission standards for GHGs, mercury, 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, and
incorporating change-in-law provisions in contracts that allow recovery of certain compliance costs from our customers.
We strive to be in compliance with all environmental regulations relating to operations and facilities. Compliance with both
regulatory requirements and management system standards is regularly audited through our performance assurance policy
and results are reported quarterly to the GEC.
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TransAlta Corporation | 2016 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 fulfil its financial or performance
obligations to us or where we have made a payment in advance of the delivery of a product or service. The inability to collect
cash due to us or to receive products or services may have an adverse impact upon our net earnings and cash flows.
We manage our exposure to credit risk by:
(cid:131)
(cid:131)
(cid:131)
(cid:131)
establishing and adhering to policies that define credit limits based on the creditworthiness of counterparties, contract
term limits, and the credit concentration with any specific counterparty,
requiring formal sign-off on contracts that include commercial, financial, legal, and operational reviews,
requiring security instruments, such as parental guarantees, letters of credit, and cash collateral that can be collected if a
counterparty fails to fulfil its obligation or goes over its limits, and
reporting our exposure using a variety of methods that allow key decision-makers to assess credit exposure by
counterparty. This reporting allows us to assess credit limits for counterparties and the mix of counterparties based on
their credit ratings.
If established credit exposure limits are exceeded, we take steps to reduce this exposure, such as by requesting collateral, if
applicable, or by halting commercial activities with the affected counterparty. However, there can be no assurances that we
will be successful in avoiding losses as a result of a contract counterparty not meeting its obligations.
Our credit risk management profile and practices have not changed materially from Dec. 31, 2015. We had no material
counterparty losses in 2016. We continue to keep a close watch on changes and trends in the market and the impact these
changes could have on our energy trading business and hedging activities, and will take appropriate actions as required,
although no assurance can be given that we will always be successful.
The following table outlines our maximum exposure to credit risk without taking into account collateral held or right of set-off,
including the distribution of credit ratings, as at Dec. 31, 2016:
1
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)
92
36
100
8
64
-
100
100
100
Total
amount
703
719
1,034
2,456
The maximum credit exposure to any one customer for commodity trading operations, including the fair value of open trading
positions net of any collateral held, is $14 million (2015 - $44 million).
(1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts.
(2) We have one non-investment grade customer whose outstanding balance accounted for $445 million (Dec. 31, 2015 - $446 million). Risk of significant loss arising from
this counterparty has been assessed as low in the near term, but could increase to moderate in an environment of sustained low commodity prices over the mid to long
term. The Corporation's assessment takes into consideration the counterparty's financial position, external rating assessments, how the Corporation provides its services in
an area of the counterparty's lower-cost operations, and the Corporation's other credit risk management practices.
TransAlta Corporation | 2016 Annual Integrated Report
M70
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 U.S. denominated debt. Our exposures are primarily to the U.S. and Australian currencies. Changes in the
values of these currencies in relation to the Canadian dollar may affect our earnings or the value of our foreign investments to
the extent that these positions or cash flows are not hedged or the hedges are ineffective.
We manage our currency rate risk by establishing and adhering to policies that allow for both designated hedges and
economic hedges and include:
(cid:131)
(cid:131)
hedging our net investments in U.S. operations using U.S.-denominated debt,
entering into forward foreign exchange contracts to hedge future foreign denominated expenditures including our U.S.-
denominated debt that is outside the net investment portfolio, and
hedging our expected foreign operating cash flows. Our target is to hedge a minimum of 60 per cent of our forecasted
foreign operating cash flows over a four-year period, with a minimum of 90 per cent in the current year, 70 per cent in
the next year, 50 per cent in the third year, and 30 per cent in the fourth year. The U.S. exposure will be managed with a
combination of interest expense on our U.S.-denominated debt and forward foreign exchange contracts; the Australian
exposure will be managed with forward foreign exchange contracts.
(cid:131)
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
12
Liquidity Risk
Liquidity risk relates to our ability to access capital to be used to engage in trading and hedging activities, capital projects,
debt refinancing and payment of liabilities, capital structure, and general corporate purposes. Investment grade credit ratings
support these activities and provide a more reliable and cost-effective means to access capital markets through commodity
and credit cycles. Changes in credit ratings may also affect our ability and/or the cost of establishing normal course derivative
or hedging transactions, including those undertaken by our Energy Marketing segment. Counterparties enter into certain
electricity and natural gas purchase and sale contracts for the purposes of asset-backed sales and proprietary trading. The
terms and conditions of these contracts require the counterparties to provide collateral when the fair value of the obligation
pursuant to these contracts is in excess of any credit limits granted. Downgrades in creditworthiness by certain credit rating
agencies may challenge our ability to enter into these contracts or any ordinary course contract, decrease the credit limits
granted, and increase the amount of collateral that may have to be provided. Certain existing contracts contain credit rating
contingent clauses, that, when triggered, automatically increase costs under the contract or require additional collateral to be
posted. Where the contingency is based on the lowest single rating, a one-level downgrade from a credit rating agency with
an originally higher rating may not, however, trigger additional direct adverse impact.
We are focused on strengthening our financial position and flexibility and achieving stable investment grade credit ratings
with rating agencies. Credit ratings issued for TransAlta, as well as the corresponding rating agency outlooks, are set out in the
Financial Capital section of this MD&A. Credit ratings are subject to revision or withdrawal at any time by the rating
organization, and there can be no assurance that TransAlta’s credit ratings and the corresponding outlook will not be changed,
resulting in the adverse possible impacts identified above.
As at Dec. 31, 2016, we have liquidity of $1.7 billion comprised of amounts not drawn under our committed credit facilities and
cash on hand, and foresee no current need to draw down on this liquidity in 2017.
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TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
We manage liquidity risk by:
(cid:131) monitoring liquidity on trading positions,
(cid:131)
(cid:131)
preparing and revising longer-term financing plans to reflect changes in business plans and the market availability of capital,
reporting liquidity risk exposure for commodity risk management activities on a regular basis to the Commodity Risk &
Compliance Committee, senior management, and the ARC,
(cid:131) maintaining investment grade credit ratings; and
(cid:131) maintaining sufficient undrawn committed credit lines to support potential liquidity requirements.
Interest Rate Risk
Changes in interest rates can impact our borrowing costs and the capacity revenues we receive from our Alberta PPA plants.
Changes in our cost of capital may also affect the feasibility of new growth initiatives.
We manage interest rate risk by establishing and adhering to policies that include:
employing a combination of fixed and floating rate debt instruments, and
(cid:131)
(cid:131) monitoring the mixture of floating and fixed rate debt and adjusting where necessary to ensure a continued efficient
mixture of these types of debt.
At Dec. 31, 2016, approximately six per cent (2015 - nine per cent) of our total debt portfolio was subject to changes in
floating interest rates through a combination of floating rate debt and interest rate swaps.
The sensitivity of changes in interest rates upon our net earnings is shown below:
Factor
Interest rate
Increase or
decrease (%)
0.15
Approximate impact
on net earnings
-
Project Management Risk
On capital projects, we face risks associated with cost overruns, delays, and performance.
We manage project risks by:
(cid:131)
ensuring all projects are reviewed to see that established processes and policies are followed, risks have been properly
identified and quantified, input assumptions are reasonable, and returns are realistically forecasted prior to senior
management and Board of Directors approvals,
using consistent and disciplined project management methodologies and processes,
performing detailed analysis of project economics prior to construction or acquisition and by determining our asset
contracting strategy to ensure the right mix of contracted and merchant capacity prior to commencement of
construction,
partnering with those who have previously been able to deliver projects economically and on budget;
developing and following through with comprehensive plans that include critical paths identified, key delivery points, and
backup plans,
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131) managing project closeouts so that any learnings from the project are incorporated into the next significant project;
(cid:131)
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.
(cid:131)
TransAlta Corporation | 2016 Annual Integrated Report
M72
Management’s Discussion and Analysis
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:
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
potential disruption as a result of labour action at our generating facilities,
reduced productivity due to turnover in positions,
inability to complete critical work due to vacant positions,
failure to maintain fair compensation with respect to market rate changes, and
reduced competencies due to insufficient training, failure to transfer knowledge from existing employees, or insufficient
expertise within current employees.
We manage this risk by:
(cid:131) monitoring industry compensation and aligning salaries with those benchmarks,
using incentive pay to align employee goals with corporate goals,
(cid:131)
(cid:131) monitoring and managing target levels of employee turnover, and
(cid:131)
ensuring new employees have the appropriate training and qualifications to perform their jobs.
In 2016, 53 per cent (2015 - 54 per cent) of our labour force was covered by 11 (2015 - 11) collective bargaining agreements. In
2016, five (2015 - two) agreements were renegotiated. We anticipate the successful negotiation of five collective agreements
in 2017.
Regulatory and Political Risk
Regulatory and political risk is the risk to our business associated with potential changes to the existing regulatory structures
and the political influence upon those structures. This risk can come from market regulation and re-regulation, increased
oversight and control, structural or design changes in markets, or other unforeseen influences. Market rules are often dynamic
and we are not able to predict whether there will be any material changes in the regulatory environment or the ultimate effect
of changes in the regulatory environment on our business. This risk includes, among other things, uncertainties associated
with the development of capacity markets for electricity in the provinces of Alberta and Ontario, uncertainties associated with
the development of carbon pricing policies, the qualification of our renewable facilities in Alberta to the generation of tradable
GHG allowances as part of the transition from the Specified Gas Emitters Regulation to new regulation to be formulated to
give effect to the Alberta Climate Leadership Plan in 2018, as well as the influence of regulation on the value of allowances or
credits generated.
We manage these risks systematically through our Legal and Regulatory groups and our Compliance program, which is
reviewed periodically to ensure its effectiveness. We work with governments, regulators, electricity system operators, and
other stakeholders to resolve issues as they arise. We are actively monitoring changes to market rules and market design, and
we engage in market-sponsored stakeholder engagement processes. Through these and other avenues, we engage in
advocacy and policy discussions at a variety of levels. These stakeholder negotiations have allowed us to engage in proactive
discussions with governments over the longer term.
International investments are subject to unique risks and uncertainties relating to the political, social, and economic
structures of the respective country and such country’s regulatory regime. We mitigate this risk through the use of non-
recourse financing and insurance.
Transmission Risk
Access to transmission lines and transmission capacity for existing and new generation are key in our ability to deliver energy
produced at our power plants to our customers. The risks associated with the aging existing transmission infrastructure in
markets in which we operate continue to increase because new connections to the power system are consuming transmission
capacity quicker than it is being added by new transmission developments.
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TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
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:
(cid:131)
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,
(cid:131)
(cid:131) maintaining positive relationships with various levels of government,
(cid:131)
(cid:131)
(cid:131)
(cid:131) 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
Corporate Structure Risk
We conduct a significant amount of business through subsidiaries and partnerships. Our ability to meet and service debt
obligations is dependent upon the results of operations of our subsidiaries and the payment of funds by our subsidiaries in the
form of distributions, loans, dividends, or otherwise. In addition, our subsidiaries may be subject to statutory or contractual
restrictions that limit their ability to distribute cash to us.
Cyber Security Risk
We rely on our information technology to process, transmit and store electronic information, including information we use to
safely operate our assets. Cyber-attacks or other breaches of network or information technology systems security may cause
disruptions to our operations. Cyber attackers may use a range of techniques, from manipulating people to using
sophisticated malicious software and hardware on a single or distributed basis. Some cyber attackers use a combination of
techniques in their attempt to evade safeguards such as firewalls, intrusion prevention systems, and antivirus software found
in our systems and networks. A successful attack on our systems, networks, and infrastructure may allow for the unauthorized
interception, destruction, use, or dissemination of our information and may cause disruptions to our operations.
We take measures to secure our infrastructure against potential cyber-attacks that may damage our infrastructure, systems
and data. Our cyber security program aligns with industry best practices to ensure that a holistic approach to security is
maintained. We have implemented security controls to help secure our data and business operations, including access control
measures, intrusion detection and prevention systems, logging and monitoring of network activities, and implementing
policies and procedures to ensure the secure operations of the business.
While we have systems, policies, hardware, practices, data backups, and procedures designed to prevent or limit the effect of
the security breaches of our generation facility and infrastructure, there can be no assurance that these measures will be
sufficient and that such security breaches will not occur or, if they do occur, that they will be adequately addressed in a timely
manner. We closely monitor both preventive and detective measures to manage these risks.
General Economic Conditions
Changes in general economic conditions impact product demand, revenue, operating costs, the timing and extent of capital
expenditures, the net recoverable value of PP&E, financing costs, credit and liquidity risk, and counterparty risk.
Income Taxes
Our operations are complex and located in several countries. The computation of the provision for income taxes involves tax
interpretations, regulations, and legislation that are continually changing. Our tax filings are subject to audit by taxation
authorities. Management believes that it has adequately provided for income taxes as required by IFRS, based on all
information currently available.
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Management’s Discussion and Analysis
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
3
Legal Contingencies
We are occasionally named as a party in various claims and legal regulatory proceedings that arise during the normal course
of our business. We review each of these claims, including the nature of the claim, the amount in dispute or claimed, and the
availability of insurance coverage. There can be no assurance that any particular claim or proceedings will be resolved in our
favour or that such claims may not have a material adverse effect on us.
Other Contingencies
We maintain a level of insurance coverage deemed appropriate by management. There were no significant changes to our
insurance coverage during renewal of the insurance policies on December 31. Our insurance coverage may not be available in
the future on commercially reasonable terms. There can be no assurance that our insurance coverage will be fully adequate to
compensate for potential losses incurred. In the event of a significant economic event, the insurers may not be capable of fully
paying all claims.
Critical Accounting Policies and Estimates
The selection and application of accounting policies is an important process that has developed as our business activities
have evolved and as accounting rules and guidance have changed. Accounting rules generally do not involve a selection
among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment relative to the
circumstances existing in the business. Every effort is made to comply with all applicable rules on or before the effective date,
and we believe the proper implementation and consistent application of accounting rules is critical.
However, not all situations are specifically addressed in the accounting literature. In these cases, our best judgment is used to
adopt a policy for accounting for these situations. We draw analogies to similar situations and the accounting guidelines
governing them, consider foreign accounting standards, and consult with our independent auditors about the appropriate
interpretation and application of these policies. Each of the critical accounting policies involves complex situations and a high
degree of judgment either in the application and interpretation of existing literature or in the development of estimates that
impact our consolidated financial statements.
Our significant accounting policies are described in Note 2 to our audited consolidated financial statements within this
Annual Report. The most critical of these policies are those related to revenue recognition, financial instruments, valuation of
PP&E and associated contracts, project development costs, useful life of PP&E, valuation of goodwill, leases, income taxes,
employee future benefits, decommissioning and restoration provisions, and other provisions. Each policy involves a number of
estimates and assumptions to be made about matters that are uncertain at the time the estimate is made. Different
estimates, with respect to key variables used for the calculations, or changes to estimates, could potentially have a material
impact on our financial position or results of operations.
We have discussed the development and selection of these critical accounting estimates with our ARC and our independent
auditors. The ARC has reviewed and approved our disclosure relating to critical accounting estimates in this MD&A.
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Management’s Discussion and Analysis
These critical accounting estimates are described as follows:
Revenue Recognition
The majority of our revenues are derived from the sale of physical power, leasing of power facilities, and from commodity risk
management activities.
Revenues under long-term electricity and thermal sales contracts generally include one or more of the following components:
fixed capacity payments for availability, energy payments for generation of electricity, incentives or penalties for exceeding or
not meeting availability targets, excess energy payments for power generation above committed capacity, and ancillary
services. Each of these components is recognized upon output, delivery, or satisfaction of contractually specific targets.
Revenues from non-contracted capacity are comprised of energy payments, at market prices, for each MWh produced and
are recognized upon delivery.
In certain situations, a long-term electricity or thermal sales contract may contain, or be considered, a lease. Where the terms
and conditions of the contract result in the customer assuming the principal risks and rewards of ownership of the underlying
asset, the contractual arrangement is considered a finance lease, which results in the recognition of finance lease income.
Where we retain the principal risks and rewards, the contractual arrangement is an operating lease. Rental income, including
contingent rents where applicable, is recognized over the term of the contract. Revenues associated with non-lease elements
are recognized as goods or services revenues as outlined above.
Commodity risk management activities involve the use of derivatives such as physical and financial swaps, forward sales
contracts, and futures contracts and options, to earn trading revenues and to gain market information. These derivatives are
accounted for using fair value accounting when hedge accounting is not applied. The initial recognition of fair value and
subsequent changes in fair value affect reported earnings in the period the change occurs. The fair values of instruments that
remain open at the end of a reporting period represent unrealized gains or losses and are presented on the Consolidated
Statements of Financial Position as risk management assets or liabilities.
The determination of the fair value of commodity risk management contracts and derivative instruments is complex and relies
on judgments concerning future prices, volatility, and liquidity, among other factors. Some of our derivatives are not traded on
an active exchange or extend beyond the time period for which exchange-based quotes are available, requiring us to use
internal valuation techniques or models.
Financial Instruments
The fair value of a financial instrument is the price that would be received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the measurement date. Fair values can be determined by reference to
prices for instruments in active markets to which we have access. In the absence of an active market, we determine fair values
based on valuation models or by reference to other similar products in active markets.
Fair values determined using valuation models require the use of assumptions. In determining those assumptions, we look
primarily to external readily observable market inputs. However, if not available, we use inputs that are not based on
observable market data.
Level Determinations and Classifications
The Level I, II, and III classifications in the fair value hierarchy utilized by the Corporation are defined below. The fair value
measurement of a financial instrument is included in only one of the three levels, the determination of which is based on the
lowest level input that is significant to the derivation of the fair value.
Level I
Fair values are determined using inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities
that we have the ability to access. In determining Level I fair values, we use quoted prices for identically traded commodities
obtained from active exchanges such as the New York Mercantile Exchange.
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Management’s Discussion and Analysis
Level II
Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability.
Fair values falling within the Level II category are determined through the use of quoted prices in active markets, which in
some cases are adjusted for factors specific to the asset or liability, such as basis, credit valuation, and location differentials.
Our commodity risk management Level II financial instruments include over-the-counter derivatives with values based on
observable commodity futures curves and derivatives with inputs validated by broker quotes or other publicly available
market data providers. Level II fair values are also determined using valuation techniques, such as option pricing models and
regression or extrapolation formulas, where the inputs are readily observable, including commodity prices for similar assets or
liabilities in active markets, and implied volatilities for options.
In determining Level II fair values of other risk management assets and liabilities, we use observable inputs other than
unadjusted quoted prices that are observable for the asset or liability, such as interest rate yield curves and currency rates. For
certain financial instruments where insufficient trading volume or lack of recent trades exists, we rely on similar interest or
currency rate inputs and other third-party information such as credit spreads.
Level III
Fair values are determined using inputs for the asset or liability that are not readily observable.
We may enter into commodity transactions for which market-observable data is not available. In these cases, Level III fair
values are determined using valuation techniques such as the Black-Scholes, mark-to-forecast, and historical bootstrap
models with inputs that are based on historical data such as unit availability, transmission congestion, demand profiles for
individual non-standard deals and structured products, and/or volatilities and correlations between products derived from
historical prices. We also have various contracts with terms that extend beyond a liquid trading period. As forward market
prices are not available for the full period of these contracts, the value of these contracts is derived by reference to a forecast
that is based on a combination of external and internal fundamental modelling, including discounting. As a result, these
contracts are classified in Level III.
We have a Commodity Exposure Management Policy, which governs both the commodity transactions undertaken in our
proprietary trading business and those undertaken to manage commodity price exposures in our generation business. This
Policy defines and specifies the controls and management responsibilities associated with commodity trading activities, as
well as the nature and frequency of required reporting of such activities.
Methodologies and procedures regarding commodity risk management Level III fair value measurements are determined by
our risk management department. Level III fair values are calculated within our energy trading risk management system based
on underlying contractual data as well as observable and non-observable inputs. Development of non-observable inputs
requires the use of judgment. To ensure reasonability, system-generated Level III fair value measurements are reviewed and
validated by the risk management and finance departments. Review occurs formally on a quarterly basis or more frequently if
daily review and monitoring procedures identify unexpected changes to fair value or changes to key parameters.
The effect of using reasonably possible alternative assumptions as inputs to valuation techniques from which the Level III
commodity risk management fair values are determined at Dec. 31, 2016, is an estimated total upside of $93 million
(2015 - $156 million upside) and total downside of $89 million (2015 - $211 million) impact to the carrying value of the
financial instruments. Fair values are stressed for volumes and prices. The amount of $75 million upside (2015 - $125 million
upside) and $69 million downside (2015 - $186 million downside) in the stress values stems from a long-dated power sale
contract in the Pacific Northwest that is designated as a cash flow hedge utilizing assumed power prices ranging from
US$24 to US$40 for the period from 2019 to 2025, while the remaining amounts account for the rest of the portfolio. The
variable volumes are stressed up and down one standard deviation from historically available production data. Prices are
stressed for longer-term deals where there are no liquid market quotes using various internal and external forecasting sources
to establish a high and a low price range.
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TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Valuation of PP&E and Associated Contracts
At the end of each reporting period, we assess whether there is any indication that a PP&E or intangible asset is impaired.
Impairment exists when the carrying amount of the asset or CGU to which it belongs exceeds its recoverable amount, which is
the higher of fair value less costs of disposal and value in use.
Factors that could indicate that an impairment exists include: significant underperformance relative to historical or projected
operating results; significant changes in the manner in which an asset is used or in our overall business strategy; or significant
negative industry or economic trends. In some cases, these events are clear. However, in many cases, a clearly identifiable
event indicating possible impairment does not occur. Instead, a series of individually insignificant events occur over a period
of time leading to an indication that an asset may be impaired. This can be further complicated in situations where we are not
the operator of the facility. Events can occur in these situations that may not be known until a date subsequent to their
occurrence.
Our operations, the market, and business environment are routinely monitored, and judgments and assessments are made to
determine whether an event has occurred that indicates a possible impairment. If such an event has occurred, an estimate is
made of the recoverable amount of the PP&E or CGU to which it belongs. Recoverable amount is the higher of an asset’s fair value
less costs of disposal and its value in use. Fair value is the price that would be received to sell an asset in an orderly transaction
between market participants at the measurement date. In determining fair value less costs of disposal, information about third-
party transactions for similar assets is used and if none is available, other valuation techniques, such as discounted cash flows,
are used. Value in use is computed using the present value of management’s best estimates of future cash flows based on the
current use and present condition of the asset. In estimating either fair value less costs of disposal or value in use using
discounted cash flow methods, estimates and assumptions must be made about sales prices, cost of sales, production, fuel
consumed, retirement costs, and other related cash inflows and outflows over the life of the facilities, which can range from 30 to
60 years. In developing these assumptions, management uses estimates of contracted and future market prices based on
expected market supply and demand in the region in which the plant operates, anticipated production levels, planned and
unplanned outages, and transmission capacity or constraints for the remaining life of the facilities. Appropriate discount rates
reflecting the risks specific to the asset under review are used in the assessments. These estimates and assumptions are
susceptible to change from period to period and actual results can, and often do, differ from the estimates, and can have either a
positive or negative impact on the estimate of the impairment charge, and may be material.
The impairment outcome can also be impacted by the determination of CGUs or groups of CGUs for asset and goodwill
impairment testing. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely
independent of the cash inflows from other assets or groups of assets, and goodwill is allocated to each CGU or group of
CGUs that is expected to benefit from the synergies of the acquisition from which the goodwill arose. The allocation of
goodwill is reassessed upon changes in the composition of segments, CGUs, or groups of CGUs. In respect of determining
CGUs, significant judgment is required to determine what constitutes independent cash flows between power plants that are
connected to the same system. We evaluate the market design, transmission constraints, and the contractual profile of each
facility, as well as our commodity price risk management plans and practices, in order to inform this determination. With
regard to the allocation or reallocation of goodwill, significant judgment is required to evaluate synergies and their impacts.
Minimum thresholds also exist with respect to segmentation and internal monitoring activities. We evaluate synergies with
regard to opportunities from combined talent and technology, functional organization, and future growth potential, and we
consider our own performance measurement processes in making this determination.
As a result of our review in 2016 and other specific events, various analyses were completed to assess the significance of
possible impairment indicators. Refer to the Asset Impairment Charges and Reversals section of this MD&A for further
details.
Impairment charges can be reversed in future periods if circumstances improve. No assurances can be given if any reversal
will occur or the amount or timing of any such reversal.
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Management’s Discussion and Analysis
Project Development Costs
Deferred project development costs include external, direct, and incremental costs that are necessary for completing an
acquisition or construction project. These costs are recognized in operating expenses until construction of a plant or
acquisition of an investment is likely to occur, there is reason to believe that future costs are recoverable, and that efforts will
result in future value to us, at which time the costs incurred subsequently are included in PP&E or investments. The
appropriateness of capitalization of these costs is evaluated each reporting period, and amounts capitalized for projects no
longer probable of occurring are charged to net earnings.
Useful Life of PP&E
Each significant component of an item of PP&E is depreciated over its estimated useful life. A component is a tangible asset
that can be separately identified as an asset and is expected to provide a benefit of greater than one year. Estimated useful
lives are determined based on current facts and past experience, and take into consideration the anticipated physical life of
the asset, existing long-term sales agreements and contracts, current and forecasted demand, the potential for technological
obsolescence, and regulations. The useful lives of PP&E and depreciation rates used are reviewed at least annually to ensure
they continue to be appropriate.
In 2016, total depreciation and amortization expense was $664 million (2015 - $605 million), of which $63 million
(2014 - $59 million) relates to mining equipment and is included in fuel and purchased power.
As a result of the Alberta OCA, we will cease coal-fired emissions by the end of 2030. The useful lives of the PP&E and
amortizable intangibles associated with the coal assets were reduced to 2030. We also entered a Non-Utility Generator
Enhanced Dispatch Contract for the Mississauga plant in December 2016. As a result, the useful life of the plant was
shortened to the end of 2016.
Valuation of Goodwill
We evaluate goodwill for impairment at least annually, or more frequently if indicators of impairment exist. If the carrying
amount of a CGU or group of CGUs, including goodwill, exceeds the unit’s fair value, the excess represents a goodwill
impairment loss. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely independent of
the cash inflows from other assets or groups of assets.
For purposes of the 2016 and 2015 annual goodwill impairment review, the Corporation determined the recoverable amounts
of the test units by calculating the fair value less costs of disposal using discounted cash flow projections based on the
Corporation’s long-range forecasts for the period extending to the last planned asset retirement in 2073. The resulting fair
value measurement is categorized within Level III of the fair value hierarchy.
We reviewed the carrying amount of goodwill prior to year-end and determined that the fair values of the related CGUs or
groups of CGUs to which goodwill relates, based on estimates of future cash flows, exceeded their carrying amounts, and no
goodwill impairments existed.
Determining the fair value of the CGUs or group of CGUs is susceptible to changes from period to period as management is
required to make assumptions about future cash flows, production and trading volumes, margins, and fuel and operating
costs. Had assumptions been made that resulted in fair values of the CGUs or groups of CGUs declining by five per cent from
current levels, there would not have been any impairment of goodwill.
Leases
In determining whether the Corporation’s PPAs and other long-term electricity and thermal sales contracts contain, or are,
leases, management must use judgment in assessing whether the fulfillment of the arrangement is dependent on the use of a
specific asset and the arrangement conveys the right to use the asset. For those agreements considered to contain, or be,
leases, further judgment is required to determine whether substantially all of the significant risks and rewards of ownership
are transferred to the customer or remain with TransAlta, to appropriately account for the agreement as either a finance or
operating lease. These judgments can be significant to how we classify amounts related to the arrangement as either PP&E or
as a finance lease receivable on the Consolidated Statements of Financial Position, and therefore the value of certain items of
revenue and expense is dependent upon such classifications.
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Management’s Discussion and Analysis
Income Taxes
In accordance with IFRS, we use the liability method of accounting for income taxes. Under the liability method, deferred
income tax assets and liabilities are recognized on the differences between the carrying amounts of assets and liabilities and
their respective income tax basis.
Preparation of the consolidated financial statements involves determining an estimate of, or provision for, income taxes in each of
the jurisdictions in which we operate. The process also involves making an estimate of taxes currently payable and taxes
expected to be payable or recoverable in future periods, referred to as deferred income taxes. Deferred income taxes result from
the effects of temporary differences due to items that are treated differently for tax and accounting purposes. The tax effects of
these differences are reflected in the Consolidated Statements of Financial Position as deferred income tax assets and liabilities.
An assessment must also be made to determine the likelihood that our future taxable income will be sufficient to permit the
recovery of deferred income tax assets. To the extent that such recovery is not probable, deferred income tax assets must be
reduced. The reduction of the deferred income tax asset can be reversed if the estimated future taxable income improves. No
assurances can be given if any reversal will occur or the amount or timing of any such reversal. Management must exercise
judgment in its assessment of continually changing tax interpretations, regulations, and legislation to ensure deferred income tax
assets and liabilities are complete and fairly presented. Differing assessments and applications than our estimates could
materially impact the amount recognized for deferred income tax assets and liabilities. Our tax filings are subject to audit by
taxation authorities. The outcome of some audits may change our tax liability, although we believe that we have adequately
provided for income taxes in accordance with IFRS based on all information currently available. The outcome of pending audits is
not known nor is the potential impact on the consolidated financial statements determinable.
Deferred income tax assets of $53 million (2015 - $71 million) have been recorded on the Consolidated Statements of
Financial Position as at Dec. 31, 2016. These assets primarily relate to net operating loss carryforwards. We believe there will
be sufficient taxable income that will permit the use of these loss carryforwards in the tax jurisdictions where they exist.
Deferred income tax liabilities of $712 million (2015 - $647 million) have been recorded on the Consolidated Statements of
Financial Position as at Dec. 31, 2016. These liabilities are comprised primarily of taxes on unrealized gains from risk
management transactions and income tax deductions in excess of related depreciation of PP&E.
Employee Future Benefits
We provide selected pension and post-employment benefits to employees. The cost of providing these benefits is dependent
upon many factors that result from actual plan experience and assumptions of future experience.
The liabilities for future benefits and associated pension costs included in annual compensation expenses are impacted by
employee demographics, including age, compensation levels, employment periods, the level of contributions made to the
plans, and earnings on plan assets.
Changes to the provisions of the plans may also affect current and future pension costs. Pension costs may also be
significantly impacted by changes in key actuarial assumptions, including, for example, the discount rates used in determining
the defined benefit obligation and the net interest cost on the net defined benefit liability. The discount rate used to estimate
our obligation reflects high-quality corporate fixed income securities currently available and expected to be available during
the period to maturity of the pension benefits.
The plan assets are comprised primarily of equity and fixed income investments. Fluctuations in the return on plan assets as a
result of actual equity market returns and changes in interest rates may result in increased or decreased pension costs in
future periods.
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Management’s Discussion and Analysis
Decommissioning and Restoration Provisions
We recognize decommissioning and restoration provisions for PP&E in the period in which they are incurred if there is a legal
or constructive obligation to reclaim the plant or site. The amount recognized as a provision is the best estimate of the
expenditures required to settle the provision. Expected values are probability weighted to deal with the risks and uncertainties
inherent in the timing and amount of settlement of many decommissioning and restoration provisions. Expected values are
discounted at the risk-free interest rate adjusted to reflect the market’s evaluation of our credit standing.
As at Dec. 31, 2016, the decommissioning and restoration provisions recorded on the Consolidated Statements of Financial
Position were $293 million (2015 - $233 million). We estimate the undiscounted amount of cash flow required to settle the
decommissioning and restoration provisions is approximately $1.1 billion, which will be incurred between 2017 and 2073. The
majority of these costs will be incurred between 2020 and 2050. Some of the facilities that are co-located with mining
operations do not currently have any decommissioning obligations recorded as the obligations associated with the facilities
are indeterminate at this time.
Sensitivities for the major assumptions are as follows:
Factor
Discount rate
Undiscounted decommissioning and restoration provision
Increase or
decrease (%)
Approximate impact
on net earnings
1
10
2
1
Other Provisions
Where necessary, we recognize provisions arising from ongoing business activities, such as interpretation and application of
contract terms and force majeure claims. These provisions, and subsequent changes thereto, are determined using our best
estimate of the outcome of the underlying event and can also be impacted by determinations made by third parties, in
compliance with contractual requirements. The actual amount of the provisions that may be required could differ materially
from the amount recognized.
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Management’s Discussion and Analysis
Accounting Changes
A. Current Accounting Changes
I. Operating and Reportable Segments
During the first quarter, we disaggregated presentation of the previous Gas reportable segment into its two operating
segments: Canadian Gas and Australian Gas. Previously included legacy costs of the non-operating U.S. Gas function have
been reallocated to U.S. Coal to align with management’s internal monitoring practices. Comparative segmented results for
2015 and 2014 have been restated to align with separate reporting of the two segments and the reallocation of the non-
operating costs.
II. Change in Estimates – Useful Lives
As a result of the Alberta OCA described above, we will cease coal-fired emissions by the end of 2030. The useful lives of the
PP&E and amortizable intangibles associated with the Alberta coal assets were reduced to 2030 at the end of 2016. The
useful lives may be revised or extended in compliance with our accounting policies, dependent upon future operating
decisions and events.
We entered into a Non-Utility Generator Contract for the Mississauga plant in December 2016. As a result, the useful life of
the plant was shortened to the end of 2016.
B. Future Accounting Changes
Accounting standards that have been previously issued by the IASB, but are not yet effective and have not been applied by us,
include:
I. IFRS 15 Revenue from Contracts with Customers
In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers, which replaces existing revenue recognition
guidance with a single comprehensive accounting model. The model specifies that an entity recognizes revenue when it
transfers promised goods or services to customers in an amount that reflects the consideration to which it expects to be
entitled in exchange for those goods or services. In April 2016, the IASB issued an amendment to IFRS 15 to clarify the
identification of performance obligations, principal versus agent considerations, licences of intellectual property, and
transition practical expedients. IFRS 15, including the amendment, is required to be adopted either retrospectively or using a
modified retrospective approach for annual periods beginning on or after Jan. 1, 2018, with earlier adoption permitted. IFRS 15
will be applied by us on Jan. 1, 2018.
We have created an implementation plan and are currently in the process of reviewing our various revenue streams and
underlying contracts with customers to determine the impact that the adoption of IFRS 15 will have on our financial
statements. Our implementation plan includes an assessment of the impacts on processes and controls which may be
significant. Based on our initial scoping assessment, we have identified sources of revenue that are accounted for as leases or
financial instruments that are excluded from the scope of IFRS 15. Thus, we are currently focusing efforts on evaluating the
effect of IFRS 15 on revenue contracts such as our long-term electricity and thermal contracts, contracts for the sale of
renewable attributes, merchant power revenue, and contracts for the sale of generation byproducts. Once we have developed
the necessary accounting policies, estimates, judgments, and processes with respect to our revenue streams, the incremental
compilation of historical data to make reasonable quantitative estimates of the effects of the new standard will commence.
We have made progress on the implementation plan for IFRS 15 during 2016; however, it is not yet possible to make a reliable
estimate of the impact of IFRS 15 on our financial statements and disclosures.
Our current estimate of the time and effort necessary to complete our implementation plan for IFRS 15 extends into mid to
late 2017.
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Management’s Discussion and Analysis
II. IFRS 9 Financial Instruments
In July 2014, on completion of the impairment phase of the project to reform accounting for financial instruments and replace
IAS 39 Financial Instruments: Recognition and Measurement, the IASB issued the final version of IFRS 9 Financial
Instruments. IFRS 9 includes guidance on the classification and measurement of financial assets and financial liabilities,
impairment of financial assets (i.e., recognition of credit losses), and a new hedge accounting model. IFRS 9 is effective for
annual periods beginning on or after Jan. 1, 2018 with early application permitted. IFRS 9 will be applied by us on Jan. 1, 2018.
Under the classification and measurement requirements, financial assets must be classified and measured at either amortized
cost, at fair value through profit or loss, or through OCI, depending on the basis of the entity’s business model for managing
the financial asset and the contractual cash flow characteristics of the financial asset. The classification requirements for
financial liabilities are unchanged from IAS 39. IFRS 9 requirements address the problem of volatility in net earnings arising
from an issuer choosing to measure certain liabilities at fair value and require that the portion of the change in fair value due
to changes in the entity’s own credit risk be presented in OCI, rather than within net earnings.
The new general hedge accounting model is intended to be simpler and more closely focus on how an entity manages its risks,
replaces the IAS 39 effectiveness testing requirements with the principle of an economic relationship, and eliminates the
requirement for retrospective assessment of hedge effectiveness.
The new requirements for impairment of financial assets introduce an expected loss impairment model that requires more
timely recognition of expected credit losses. IAS 39 impairment requirements are based on an incurred loss model where
credit losses are not recognized until there is evidence of a trigger event.
We have created an implementation plan and are currently in the process of reviewing our various types of financial
instruments to determine the potential impact. Our implementation plan includes an assessment of the impacts on processes
and controls that may be significant. Based on our initial assessments, we anticipate financial statement impacts resulting
from the implementation of the expected loss impairment model. The assessment of the financial statement impacts of
implementing the classification and measure of financial assets and liabilities and hedge accounting model under IFRS 9 are
ongoing. We made progress on the implementation plan for IFRS 9 during 2016; however, it is not yet possible to make a
reliable estimate of the impact of IFRS 9 on our financial statements and disclosures.
Our current estimate of the time and effort necessary to complete our implementation plan for IFRS 9 extends into mid to late
2017.
III. IFRS 16 Leases
In January 2016, the IASB issued IFRS 16 Leases, which replaces the current IFRS guidance on leases. Under current guidance,
lessees are required to determine if the lease is a finance or operating lease, based on specified criteria. Finance leases are
recognized on the statement of financial position, while operating leases are not. Under IFRS 16, lessees must recognize a
lease liability and a right-of-use asset for virtually all lease contracts. An optional exemption to not recognize certain short-
term leases and leases of low value can be applied by lessees. For lessors, the accounting remains essentially unchanged.
IFRS 16 is effective for annual periods beginning on or after Jan. 1, 2019, with early application permitted if IFRS 15 is also
applied at the same time. The standard is required to be adopted either retrospectively or using a modified retrospective
approach. IFRS 16 will be applied by us on Jan. 1, 2019.
We are in the process of completing our initial scoping assessment and expect to have an implementation plan in place by
mid-2017. We anticipate most the effort under the implementation plan will occur in late 2017 through mid-2018. It is not yet
possible to make reliable estimates of the potential impact of IFRS 16 on our financial statements and disclosures.
M83
TransAlta Corporation | 2016 Annual Integrated Report
Fourth Quarter
Consolidated Financial Highlights
Three months ended Dec. 31
Revenues
Comparable EBITDA(1)
Net earnings (loss) attributable to common shareholders
Comparable net earnings attributable to common shareholders(1)
Comparable FFO(1)
Cash flow from operating activities
Comparable FCF(1)
Net earnings (loss) per share attributable to common
shareholders, basic and diluted
Comparable net earnings per share(1)
Comparable FFO per share(1)
Comparable FCF per share(1)
Dividends declared per common share
1
Management’s Discussion and Analysis
2016
717
374
61
51
228
122
93
0.21
0.18
0.79
0.32
0.08
2015
595
268
(7)
3
243
118
174
(0.02)
0.01
0.86
0.61
0.18
Financial Highlights
Comparable EBITDA for the fourth quarter of 2016 improved by $106 million compared to the same period in 2015, primarily
as a result of the reversal of an $80 million provision relating to our Keephills 1 outage in 2013. Last year’s comparable EBITDA
was impacted by an increase to our provision of $59 million relating to prior years’ Keephills 1 outage in 2013. Excluding the
change to our provision, comparable EBITDA in the fourth quarter of 2016 was $33 million lower than the fourth quarter of
2015. Unrealized mark-to-market gains on our gas positions favourably affected our comparable EBITDA, but were offset by
lower prices and lower availability in both our Canadian and U.S. Coal segments. Also impacting our results this quarter is
lower margins from our Energy Marketing segment.
Comparable FFO decreased by $15 million to $228 million for the three months ended Dec. 31, 2016, compared to same
period in 2015. The year-over-year non-cash change in our provisions totalled approximately $160 million and is excluded
from comparable FFO. Comparable EBITDA also included $9 million of unrealized non-cash mark-to-market losses compared
to a $6 million unrealized mark-to-market gain in 2015.
Fourth quarter comparable net earnings attributable to common shareholders was $51 million ($0.18 per share), up from the
comparable net earnings of $3 million ($0.01 per share) in the same quarter last year. The Keephills 1 outage provision
reversal as described above favourably impacted net earnings.
Reported net earnings attributable to common shareholders was $61 million ($0.21 per share) for the fourth quarter
compared to a net loss of $7 million ($0.02 net loss per share) for the same period in 2015. The difference between
comparable and reported net earnings includes the net gain on the Mississauga cogeneration facility recontracting, partially
offsetting the Wintering Hills wind facility impairment charge during the quarter.
(1) These items are not defined under IFRS. Presenting these items from period to period provides management and investors with the ability to evaluate earnings trends more
readily in comparison with prior periods’ results. Refer to the Comparable Funds from Operations and Comparable Free Cash Flow and Earnings on a Comparable Basis
sections of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.
TransAlta Corporation | 2016 Annual Integrated Report
M84
Management’s Discussion and Analysis
Segmented Operational Results
Comparable EBITDA and operational performance for the business is as follows:
Three months ended Dec. 31
Availability (%)(1)
Adjusted availability (%)(2)
Production (GWh)(1)
Comparable EBITDA
Canadian Coal
U.S. Coal(3)
Canadian Gas(3)
Australian Gas(3)
Wind and Solar
Hydro
Energy Marketing
Corporate
Total comparable EBITDA
2016
88.9
88.9
10,624
178
14
70
32
66
20
13
(19)
374
2015
92.9
88.4
11,107
67
22
57
34
65
19
26
(22)
268
1
Availability and Production
Adjusted availability for the three months ended Dec. 31, 2016, was consistent with the same period in 2015. Lower production for
the three months ended Dec. 31, 2016, compared to the same period in 2015 are primarily due to higher outages and derates,
partially offset by paid curtailments at our Canadian Coal segment, and higher economic dispatching in Ontario as a result of lower
prices at our Canadian Gas segment.
(cid:131)
Canadian Coal: Comparable EBITDA totalled $178 million in the fourth quarter of 2016, including the reversal of the
Keephills 1 outage provision of $80 million, partially offset by unrealized losses on hedging activities. The
quarter-over-quarter change in our provisions was $139 million. Excluding the adjustment to our provision, comparable
EBITDA was down $28 million compared to last year mainly due to lower realized prices and lower availability due to
outages and derates.
U.S. Coal: Comparable EBITDA was down $8 million in the fourth quarter compared to the same period in 2015. The
unfavourable impact of mark-to-market losses on certain forward financial contracts that do not qualify for hedge
accounting was partially offset by coal inventory recoveries. In addition, lower revenue and pricing was offset by lower
delivered coal costs.
Canadian Gas: Comparable EBITDA was $70 million in the fourth quarter of 2016, an increase of $13 million, compared
to the same period in 2015, primarily due to favourable unrealized mark-to-market gains on our gas positon.
Australian Gas: Comparable EBITDA was down by $2 million during the fourth quarter of 2016, compared to the same
period in 2015. The addition of capacity payments for the gas conversion project at our Solomon gas plant was offset by
increased repair and maintenance expenses and unfavourable Canadian dollar foreign exchange translation.
(cid:131)
(cid:131)
(cid:131)
(cid:131) Wind and Solar: Comparable EBITDA was consistent in the fourth quarter with the same period in 2015.
(cid:131)
(cid:131)
Hydro: Comparable EBITDA was consistent in the fourth quarter with the same period in 2015.
Energy Marketing: Comparable EBITDA was down $13 million in the fourth quarter compared to the same period in 2015
due to lower margins and increased OM&A costs associated with share-based payment expenses.
Corporate: Lower costs in our Corporate Segment mainly due to realized benefits of cost efficiency initiatives which were
offset by reduced allocations to our business segments.
(cid:131)
(1) Availability and production includes all generating assets under generation operations that we operate and finance leases and excludes hydro assets and equity
investments. Production includes all generating assets, irrespective of investment vehicle and fuel type.
(2) Adjusted for economic dispatching at U.S. Coal.
(3) See the Accounting Changes section of this MD&A for information on changes in the presentation of the Gas reportable segment.
M85
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Reconciliation of Non-IFRS Measures
We evaluate our performance and the performance of our business segments using a variety of measures. Those discussed
below, and elsewhere in this MD&A, are not defined under IFRS and, therefore, should not be considered in isolation or as an
alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from operating
activities, as determined in accordance with IFRS, when assessing our financial performance or liquidity. These measures are
not necessarily comparable to a similarly titled measure of another company.
Comparable Funds from Operations and Comparable Free Cash Flow
Comparable FFO per share and comparable FCF per share are calculated as follows using the weighted average number of
common shares outstanding during the period.
Cash flow from operating activities
Change in non-cash operating working capital balances
Cash flow from operations before changes in working capital
Adjustments
Decrease in finance lease receivable
Restructuring costs
MSA settlement payment
Maintenance costs related to Alberta flood of 2013,
net of insurance recoveries
Other
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
3 months ended Dec. 31
2016
2015
122
61
183
15
3
25
-
2
228
(85)
-
(10)
(40)
93
288
0.79
0.32
118
76
194
15
11
31
(10)
2
243
(52)
23
(11)
(29)
174
284
0.86
0.61
TransAlta Corporation | 2016 Annual Integrated Report
M86
Management’s Discussion and Analysis
The table below provides a reconciliation of our comparable EBITDA to our comparable FFO and comparable FCF.
Comparable EBITDA
Provisions
Interest expense
Unrealized (gains) losses from risk management activities
Current income tax expense
Decommissioning and restoration costs settled
Realized foreign exchange gain (loss)
Non-cash gain on curtailment and amendment
gain on empoyee future benefits
Capital insurance recoveries
Other non-cash 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
3 months ended Dec. 31
2016
374
(79)
(47)
9
(6)
(8)
(1)
-
-
(14)
228
(85)
-
(10)
(40)
93
288
0.79
0.32
2015
268
76
(63)
(6)
(7)
(4)
1
(8)
(5)
(9)
243
(52)
23
(11)
(29)
174
284
0.86
0.61
M87
TransAlta Corporation | 2016 Annual Integrated Report
Management’s Discussion and Analysis
Reconciliation of Comparable EBITDA and Comparable Net Earnings
A reconciliation of reported results to comparable results for the three months ended Dec. 31, 2016 and 2015 is as follows:
3 months ended Dec. 31, 2016
Comparable
adjustments
Comparable
reclassifications
Reported
Comparable
total
Reported
3 months ended Dec. 31, 2015
Comparable
adjustments
Comparable
reclassifications
Comparable
total
Revenues
Fuel and purchased power
Gross margin
Operations, maintenance, and administration
Asset impairment reversals
Restructuring provision
Taxes, other than income taxes
Net other operating (income) losses
EBITDA
Depreciation and amortization
Operating income
Finance lease income
Foreign exchange gain (loss)
Gain 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
717
280
437
125
28
-
7
(193)
470
187
283
17
(3)
3
300
47
82
171
90
81
20
61
288
0.21
(1, 2)
32
(3)
(19)
51
-
-
-
-
-
51
34
17
(2, 3)
(1)
(17)
-
-
-
-
-
-
-
-
-
-
(4)
(8)
2
(14)
16
-
(28)
(7)
-
-
191
(147)
(46)
(101)
(8)
(8)
-
(3)
(4)
(11)
(10)
(12, 13)
(14)
(108)
-
(40)
(68)
(58)
(10)
-
(10)
(1, 2)
32
(3)
(16)
48
-
-
-
-
-
48
31
17
(2, 3)
(1)
(17)
-
-
-
-
-
-
-
-
-
-
(4)
(5)
(7)
(9)
(6)
(11)
(10)
13
-
13
10
1
(4)
-
18
(12)
-
(12)
-
8
1
(3)
-
(13)
(6)
3
(14)
(7)
10
-
10
751
247
504
125
-
-
7
(2)
374
175
199
-
(6)
(1)
192
47
42
103
32
71
20
51
288
0.18
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)
640
256
384
119
-
-
8
(11)
268
167
101
-
11
-
112
69
(10)
53
39
14
11
3
284
0.01
TransAlta Corporation | 2016 Annual Integrated Report
M88
Management’s Discussion and Analysis
The adjustments made to calculate comparable earnings for the three months ended Dec. 31, 2016 and 2015 are as follows.
References are to the previous reconciliation table.
1
Reference
number
Adjustment
Reclassifications:
Segment
Financial statement
line item
3 months ended Dec. 31
2016
2015
1
2
3
Finance lease income used as a proxy for
operating revenue
Decrease in finance lease receivable used as
a proxy for operating revenue and depreciation
Australian Gas
Revenues
Canadian Gas
Revenues
Canadian Gas
Revenues
Australian Gas
Revenues
Reclassification of mine depreciation from fuel
and purchased power
Canadian Coal
Fuel and
purchased power
Adjustments (increasing (decreasing) earnings to arrive at comparable results):
4
5
6
7
8
9
Impacts to revenue associated with certain
de-designated and economic hedges
Maintenance costs related to the Alberta
flood of 2013, net of insurance recoveries
Non-comparable portion of insurance
recovery received
Asset impairment reversals
Mississauga recontracting(1)
Restructuring expense
U.S. Coal
Revenues
Hydro
OM&A
Hydro
U.S. Coal
Wind and Solar
Canadian Gas
Canadian Coal
Net other operating
(income) losses
Asset impairment
(reversals)
Asset impairment
(reversals)
Net other operating
(income) losses
Restructuring provision
Corporate
Restructuring provision
10
Gain on Poplar Creek contract restructuring
Canadian Gas
Gain on sale of assets
Non-comparable gain on sale of assets
Corporate
Gain on sale of assets
11
12
13
14
Economic hedges of non-controlling interest in
intercompany foreign exchange contracts
Net tax effect on comparable adjustments
subject to tax
Reversal of a writedown of
deferred income tax assets
Non-comparable items attributable to
non-controlling interests
Unassigned
Foreign exchange loss
Unassigned
Unassigned
Unassigned
Income tax expense
(recovery)
Income tax expense
(recovery)
Non-controlling
interests
13
4
14
1
19
2
-
-
-
28
(131)
-
-
-
(4)
(3)
9
31
58
13
4
15
-
16
13
(10)
(18)
(1)
-
-
2
2
1
-
8
-
6
7
(1) Reported in net other operating (income) loss of ($191 million), depreciation and amortization of ($46 million) and fuel and purchased power of ($14 million).
M89
TransAlta Corporation | 2016 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.
1
Revenues
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(1)
Comparable net earnings (loss) per share, basic and diluted(1)
Revenues
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(1)
Comparable net earnings (loss) per share, basic and diluted(1)
Q1 2016
Q2 2016
Q3 2016
Q4 2016
568
279
196
62
14
0.22
0.05
492
248
175
6
(20)
620
244
163
(12)
(11)
0.02
(0.04)
(0.07)
(0.04)
717
374
228
61
51
0.21
0.18
Q1 2015
Q2 2015
Q3 2015
Q4 2015
593
275
211
(40)
26
438
183
160
(131)
(44)
641
219
126
154
(33)
595
268
243
(7)
3
(0.14)
(0.47)
0.55
(0.02)
0.09
(0.16)
(0.12)
0.01
(1) Basic and diluted earnings per share attributable to common shareholders and comparable earnings per share are calculated each period using the weighted average
common shares outstanding during the period. As a result, the sum of the earnings per share for the four quarters making up the calendar year may sometimes differ from
the annual earnings per share.
TransAlta Corporation | 2016 Annual Integrated Report
M90
Management’s Discussion and Analysis
Comparable net earnings, comparable EBITDA, and comparable FFO are generally higher in the first and fourth quarters due to
higher demand associated with winter cold in the markets in which we operate and lower planned outages.
Net earnings attributable to common shareholders has also been impacted by the following variations and events:
gain on disposal of assets, following the Poplar Creek contract restructuring in the third quarter of 2015,
(cid:131)
U.S. Solar and Wind acquisitions in the third quarter of 2015,
(cid:131)
settlement with the Market Surveillance Administrator in the third quarter of 2015,
(cid:131)
a recovery of a writedown of deferred tax assets in the fourth quarter of 2014, the third quarter of 2015, and the first and
(cid:131)
second quarters of 2016,
change in income tax rates in Alberta in the second quarter of 2015,
deferred income tax impacts of the sale of an economic interest in Australian Assets to TransAlta Renewables in the first
and second quarters of 2015,
effects of non-comparable unrealized losses on intercompany financial instruments that are attributable only to the
non-controlling interests in the first, second, and third quarters of 2016,
effects of the Mississauga facility recontracting during the fourth quarter of 2016, and
effects of the Wintering Hills impairment charge during the fourth quarter of 2016.
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
Disclosure Controls and Procedures
Management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness
of our disclosure controls and procedures as of the end of the period covered by this report. Disclosure controls and
procedures refer to controls and other procedures designed to ensure that information required to be disclosed in the reports
we file or submit under the Securities Exchange Act of 1934, as amended (“Exchange Act”) are recorded, processed,
summarized, and reported within the time periods specified in the rules and forms of the U.S. Securities and Exchange
Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that
information required to be disclosed by us in our reports that we file or submit under the Exchange Act is accumulated and
communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow
timely decisions regarding our required disclosure. In designing and evaluating our disclosure controls and procedures,
management recognizes that any controls and procedures, no matter how well designed and operated, can provide only
reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in
evaluating and implementing possible controls and procedures.
During the first quarter of 2016, we completed the implementation of a new energy trading and risk management system. In
connection with the implementation, we updated the processes that constitute our internal control over financial reporting, as
necessary, to accommodate related changes to our business processes and accounting procedures.
Except as otherwise described above, there have been no other changes in our internal control over financial reporting during
the year ended Dec. 31, 2016 that have materially affected, or are reasonably likely to materially affect our internal control
over financial reporting. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have
concluded that, as at Dec. 31, 2016, the end of the period covered by this report, our disclosure controls and procedures were
effective.
M91
TransAlta Corporation | 2016 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 fulfils 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
March 2, 2017
TransAlta Corporation | 2016 Annual Integrated Report
F1
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 2016 consolidated
financial statements of TransAlta included $626 million and $592 million of total and net assets, respectively, as of December
31, 2016, and $138 million and $13 million of revenues and net loss, 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, 2016,
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, 2016,
has also issued a report on internal control over financial reporting under the standards 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
March 2, 2017
F2
TransAlta Corporation | 2016 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, 2016, 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 2016 consolidated financial
statements of the Corporation and constituted $626 million and $592 million of total and net assets, respectively, as of
December 31, 2016, and $138 million and $13 million of revenues and net loss, 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, 2016, 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, 2016 and 2015, 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, 2016 of TransAlta Corporation and our report dated March 2, 2017 expressed an unqualified opinion thereon.
Chartered Professional Accountants
Calgary, Canada
March 2, 2017
TransAlta Corporation | 2016 Annual Integrated Report
F3
Consolidated Financial Statements
Independent Auditors’ Report of 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, 2016 and 2015, 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, 2016, 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, 2016 and 2015, and its financial performance and its cash flows for each of the years in the
three-year period ended December 31, 2016, 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, 2016, 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 March 2, 2017 expressed an unqualified opinion on TransAlta Corporation’s internal
control over financial reporting.
Chartered Professional Accountants
Calgary, Canada
March 2, 2017
F4
TransAlta Corporation | 2016 Annual Integrated Report
Consolidated Financial Statements
Consolidated Statements of Earnings (Loss)
Year ended Dec. 31 (in millions of Canadian dollars except where noted)
2016
2015
2014
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)
Net interest expense (Note 9)
Foreign exchange gain (loss)
Gain on sale of assets (Note 4)
Earnings before income taxes
Income tax expense (Note 10)
Net earnings
Net earnings attributable to:
TransAlta shareholders
Non-controlling interests (Note 11)
Net earnings 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 (millions)
2,397
963
1,434
489
601
28
1
31
(194)
478
66
(229)
(5)
4
314
38
276
169
107
276
169
52
117
288
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
Net earnings (loss) per share attributable to common shareholders,
basic and diluted (Note 23)
0.41
(0.09)
0.52
See accompanying notes.
TransAlta Corporation | 2016 Annual Integrated Report
F5
Consolidated Financial Statements
Consolidated Statements of Comprehensive Income (Loss)
Year ended Dec. 31 (in millions of Canadian dollars)
Net earnings
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)
Total items that will not be reclassified subsequently to net earnings
Gains (losses) on translating net assets of foreign operations, net of tax(3)
Reclassification of translation gains on net assets of divested
foreign operations (Note 4)
Gains (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)
2016
276
8
(1)
7
(71)
-
18
-
179
(48)
78
85
361
215
146
361
2015
116
4
3
7
247
(10)
(172)
6
375
(194)
252
259
375
272
103
375
2014
232
(20)
(1)
(21)
75
(7)
(58)
7
215
(45)
187
166
398
348
50
398
(1) Net of income tax expense of 4 for the year ended Dec. 31, 2016 (2015 - nil, 2014 - 7 recovery).
(2) Net of income tax expense of nil the year ended Dec. 31, 2016 (2015 - 1 expense, 2014 - nil).
(3) Net of income tax expense of 11 for the year ended Dec. 31, 2016 (2015 - nil, 2014 - nil).
(4) Net of income tax expense of 5 for the year ended Dec. 31, 2016 (2015 - 7 expense, 2014 - 7 recovery).
(5) Net of reclassification of income tax recovery of nil for the year ended Dec. 31, 2016 (2015 - 1 recovery, 2014 - 1 recovery).
(6) Net of income tax expense of 92 for the year ended Dec. 31, 2016 (2015 - 138 expense, 2014 - 91 expense).
(7) Net of reclassification of income tax expense of 41 for the year ended Dec. 31, 2016 (2015 - 50 expense, 2014 - 3 expense).
See accompanying notes.
F6
TransAlta Corporation | 2016 Annual Integrated Report
Consolidated Statements of Financial Position
Consolidated Financial Statements
As at Dec. 31 (in millions of Canadian dollars)
Cash and cash equivalents
Trade and other receivables (Note 12)
Prepaid expenses
Risk management assets (Notes 13 and 14)
Inventory (Note 15)
Assets held for sale (Note 4)
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 10)
Risk management assets (Notes 13 and 14)
Other assets (Note 19)
Total assets
Accounts payable and accrued liabilities
Current portion of decommissioning and other provisions (Note 20)
Risk management liabilities (Notes 13 and 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 20)
Deferred income tax liabilities (Note 10)
Risk management liabilities (Notes 13 and 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
Commitments and contingencies (Note 32)
Subsequent events (Note 34)
See accompanying notes.
On behalf of the Board:
Gordon D. Giffin
Director
Alan J. Fohrer
Director
2016
305
703
23
249
213
61
1,554
719
12,773
(5,949)
6,824
464
355
53
785
242
2015
54
567
26
298
219
-
1,164
775
12,854
(5,681)
7,173
465
369
71
797
133
10,996
10,947
413
39
66
6
54
639
1,217
3,722
304
712
48
330
3,094
942
9
(933)
399
3,511
1,152
4,663
10,996
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
TransAlta Corporation | 2016 Annual Integrated Report
F7
Consolidated Financial Statements
Consolidated Statements of Changes in Equity
(in millions of Canadian dollars)
Common
shares
Preferred
shares
Contributed
surplus
2,999
942
Accumulated other
comprehensive
income(1)
Attributable to
shareholders
Attributable to
non-controlling
interests
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
Net earnings
Other comprehensive income (loss):
Net losses 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, 2016
-
-
-
-
-
-
-
-
-
76
3,075
-
-
-
-
-
-
-
-
-
19
3,094
-
-
-
-
-
-
-
-
-
-
942
-
-
-
-
-
-
-
-
-
-
Deficit
(770)
22
-
-
-
-
22
(203)
(46)
(21)
-
-
(1,018)
169
-
-
-
-
169
(58)
(52)
26
-
-
9
-
-
-
-
-
-
-
-
-
-
9
-
-
-
-
-
-
-
-
-
-
104
-
71
177
4
(2)
250
-
-
(1)
-
-
353
-
(53)
106
8
(15)
46
-
-
-
-
-
3,284
22
71
177
4
(2)
272
(203)
(46)
(22)
-
76
3,361
169
(53)
106
8
(15)
215
(58)
(52)
26
-
19
Total
3,878
116
71
184
4
-
375
(203)
(46)
594
94
-
7
-
2
103
-
-
437
415
(105)
(105)
-
1,029
107
76
4,390
276
-
24
-
15
146
-
-
(53)
130
8
-
361
(58)
(52)
138
164
(161)
-
(161)
19
942
9
(933)
399
3,511
1,152
4,663
(1) Refer to Note 25 for details on components of, and changes in, accumulated other comprehensive income (loss).
See accompanying notes.
F8
TransAlta Corporation | 2016 Annual Integrated Report
Consolidated Financial Statements
Consolidated Statements of Cash Flows
Year ended Dec. 31 (in millions of Canadian dollars)
2016
2015
2014
Operating activities
Net earnings
Depreciation and amortization (Note 33)
Gain on sale of assets (Note 4)
California claim (Note 8)
Accretion of provisions (Note 20)
276
116
232
664
605
595
(1)
(262)
(2)
-
-
(28)
20
21
18
Decommissioning and restoration costs settled (Note 20)
(23)
(24)
(16)
Deferred income tax expense (recovery) (Note 10)
15
86
(26)
Unrealized (gain) loss from risk management activities
58
61
(50)
Unrealized foreign exchange (gain) loss
Provisions
Asset impairment charges (reversals) (Note 6)
Other non-cash items
(1)
13
11
(123)
101
-
28
(2)
(6)
(242)
(41)
(5)
Cash flow from operations before changes in working capital
671
674
723
Change in non-cash operating working capital balances (Note 29)
73
(242)
73
Cash flow from operating activities
Investing activities
744
432
796
Additions to property, plant, and equipment (Notes 16 and 33)
(358)
(476)
(487)
Additions to intangibles (Notes 18 and 33)
(21)
(26)
(34)
Acquisition of renewable energy facilities, net of cash acquired (Note 4)
-
(101)
-
Addition to assets held for sale
Proceeds on sale of property, plant, and equipment
-
-
(13)
6
7
6
Proceeds on sale of investments and development projects (Note 4)
-
-
224
Realized losses on financial instruments
Decrease in finance lease receivable
Other
(6)
(12)
(2)
56
23
3
2
24
9
Change in non-cash investing working capital balances
(6)
(12)
2
Cash flow used in investing activities
Financing activities
(327)
(573)
(292)
Net increase (decrease) in borrowings under credit facilities (Note 21)
(315)
218
(436)
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)
(88)
(758)
(551)
361
487
434
(69)
(124)
(140)
(42)
(46)
(41)
Net proceeds on issuance of preferred shares (Note 24)
-
-
161
Net proceeds on sale of non-controlling interest in subsidiary (Note 4)
162
404
129
Realized gains (losses) on financial instruments
(2)
87
35
Distributions paid to subsidiaries' non-controlling interests (Note 11)
(151)
(99)
(84)
Decrease in finance lease obligations (Note 21)
Other
Cash flow from (used in) financing activities
(16)
(13)
(10)
(3)
(7)
-
(163)
149
(503)
Cash flow from operating, investing, and financing activities
254
8
1
Effect of translation on foreign currency cash
(3)
3
-
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 accompanying notes.
251
11
1
54
43
42
305
54
43
27
17
31
235
242
230
TransAlta Corporation | 2016 Annual Integrated Report
F9
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
(Tabular amounts in millions of Canadian dollars, except as otherwise noted)
(Tabular amounts in millions of Canadian dollars, except as otherwise noted)
1. Corporate Information
A. Description of the Business
TransAlta Corporation (“TransAlta” or the “Corporation”) was incorporated under the Canada Business Corporations 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 six generation segments of the Corporation are as follows: Canadian Coal, U.S. Coal, Canadian Gas, Australian 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 investor relation 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 and
assets held for sale, which are measured at fair value, as explained in the following accounting policies.
These consolidated financial statements were authorized for issue by the Board on March 2, 2017.
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 | 2016 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, US, 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.
TransAlta Corporation | 2016 Annual Integrated Report
F11
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
TransAlta Corporation | 2016 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.
TransAlta Corporation | 2016 Annual Integrated Report
F13
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.
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TransAlta Corporation | 2016 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
Hydro generation
Wind generation
Mining property and equipment
Capital spares and other
3-50 years
2-30 years
3-60 years
3-30 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.
TransAlta Corporation | 2016 Annual Integrated Report
F15
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 license 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.
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TransAlta Corporation | 2016 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.
TransAlta Corporation | 2016 Annual Integrated Report
F17
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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TransAlta Corporation | 2016 Annual Integrated Report
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. Emission credits and 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.
TransAlta Corporation | 2016 Annual Integrated Report
F19
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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TransAlta Corporation | 2016 Annual Integrated Report
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:
TransAlta Corporation | 2016 Annual Integrated Report
F21
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 2014 to 2016 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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TransAlta Corporation | 2016 Annual Integrated Report
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.
TransAlta Corporation | 2016 Annual Integrated Report
F23
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).
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:
(cid:131)
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.
(cid:131)
(cid:131)
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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TransAlta Corporation | 2016 Annual Integrated Report
Notes to Consolidated Financial Statements
3. Accounting Changes
A. Current Accounting Changes
I. Operating and Reportable Segments
During the first quarter, the Corporation disaggregated presentation of the previous Gas reportable segment into its two
operating segments: Canadian Gas and Australian Gas. Previously included legacy costs of the non-operating U.S. Gas
function have been reallocated to U.S. Coal to align with management’s internal monitoring practices. Comparative
segmented results for 2015 and 2014 have been restated to align with separate reporting of the two segments and the
reallocation of the non-operating costs.
II. Change in Estimates – Useful Lives
As a result of the Alberta Off-Coal Arrangement described in Note 4(A), the Corporation will cease coal-fired emissions by
the end of 2030. On Jan. 1, 2017, the useful lives of the PP&E and amortizable intangibles associated with the Alberta coal
assets were reduced to 2030. The useful lives may be revised or extended in compliance with the Corporation’s accounting
policies, dependent upon future operating decisions and events.
The Corporation entered into a Non-Utility Generator (“NUG”) Enhanced Dispatch Contract (the “NUG Contract”) for the
Mississauga plant in December 2016 as described in Note 4(D). As a result, the useful life of the plant was shortened to the
end of 2016.
B. Future Accounting Changes
Accounting standards that have been previously issued by the IASB, but are not yet effective and have not been applied by the
Corporation include:
I. IFRS 15 Revenue from Contracts with Customers
In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers, which replaces existing revenue recognition
guidance with a single comprehensive accounting model. The model specifies that an entity recognizes revenue when it
transfers promised goods or services to customers in an amount that reflects the consideration to which it expects to be
entitled in exchange for those goods or services. In April 2016, the IASB issued an amendment to IFRS 15 to clarify the
identification of performance obligations, principal versus agent considerations, licenses of intellectual property, and
transition practical expedients. IFRS 15, including the amendment, is required to be adopted either retrospectively or using a
modified retrospective approach for annual periods beginning on or after Jan. 1, 2018, with earlier adoption permitted. IFRS 15
will be applied by the Corporation on Jan. 1, 2018.
The Corporation has created an implementation plan and is currently in the process of reviewing its various revenue streams
and underlying contracts with customers to determine the impact that the adoption of IFRS 15 will have on its financial
statements. The Corporation’s implementation plan includes an assessment of the impacts on processes and controls which
may be significant. Based on the Corporation’s initial scoping assessment, we have identified sources of revenue that are
accounted for as leases or financial instruments that are excluded from the scope of IFRS 15. Thus, the Corporation is
currently focusing efforts on evaluating the effect of IFRS 15 on revenue contracts such as the Corporation’s long-term
electricity and thermal contracts, contracts for the sale of renewable attributes, merchant power revenue, and contracts for
the sale of generation byproducts. Once the Corporation has developed the necessary accounting policies, estimates,
judgments and processes with respect to the Corporation’s revenue streams, the incremental compilation of historical data to
make reasonable quantitative estimates of the effects of the new standard will commence. The Corporation has made
progress on the implementation plan for IFRS 15 during 2016; however, it is not yet possible to make a reliable estimate of the
impact of IFRS 15 on the Corporation’s financial statements and disclosures.
The Corporation’s current estimate of the time and effort necessary to complete our implementation plan for IFRS 15 extends
into mid to late 2017. The Corporation anticipates finalizing a decision with respect to our transition method by mid-2017.
TransAlta Corporation | 2016 Annual Integrated Report
F25
Notes to Consolidated Financial Statements
II. IFRS 9 Financial Instruments
In July 2014, on completion of the impairment phase of the project to reform accounting for financial instruments and replace
IAS 39 Financial Instruments: Recognition and Measurement, the IASB issued the final version of IFRS 9 Financial
Instruments. IFRS 9 includes guidance on the classification and measurement of financial assets and financial liabilities,
impairment of financial assets (i.e., recognition of credit losses), and a new hedge accounting model. IFRS 9 is effective for
annual periods beginning on or after Jan. 1, 2018 with early application permitted. IFRS 9 will be applied by the Corporation on
Jan. 1, 2018.
Under the classification and measurement requirements, financial assets must be classified and measured at either amortized
cost, at fair value through profit or loss, or through OCI, depending on the basis of the entity’s business model for managing
the financial asset and the contractual cash flow characteristics of the financial asset. The classification requirements for
financial liabilities are unchanged from IAS 39. IFRS 9 requirements address the problem of volatility in net earnings arising
from an issuer choosing to measure certain liabilities at fair value and require that the portion of the change in fair value due
to changes in the entity’s own credit risk be presented in OCI, rather than within net earnings.
The new general hedge accounting model is intended to be simpler and more closely focus on how an entity manages its risks,
replaces the IAS 39 effectiveness testing requirements with the principle of an economic relationship, and eliminates the
requirement for retrospective assessment of hedge effectiveness.
The new requirements for impairment of financial assets introduce an expected loss impairment model that requires more
timely recognition of expected credit losses. IAS 39 impairment requirements are based on an incurred loss model where
credit losses are not recognized until there is evidence of a trigger event.
The Corporation has created an implementation plan and is currently in the process of reviewing its various types of financial
instruments to determine the potential impact. The Corporation’s implementation plan includes an assessment of the impacts
on processes and controls that may be significant. Based on our initial assessments, the Corporation anticipates financial
statement impacts resulting from the implementation of the expected loss impairment model. The assessment of the financial
statement impacts of implementing the classification and measure of financial assets and liabilities and hedge accounting
model under IFRS 9 are ongoing. The Corporation has made progress on the implementation plan for IFRS 9 during 2016;
however, it is not yet possible to make a reliable estimate of the impact of IFRS 9 on our financial statements and disclosures.
The Corporation’s current estimate of the time and effort necessary to complete our implementation plan for IFRS 9 extends
into mid to late 2017.
III. IFRS 16 Leases
In January 2016, the IASB issued IFRS 16 Leases, which replaces the current IFRS guidance on leases. Under current guidance,
lessees are required to determine if the lease is a finance or operating lease, based on specified criteria. Finance leases are
recognized on the statement of financial position, while operating leases are not. Under IFRS 16, lessees must recognize a
lease liability and a right-of-use asset for virtually all lease contracts. An optional exemption to not recognize certain short-
term leases and leases of low value can be applied by lessees. For lessors, the accounting remains essentially unchanged.
IFRS 16 is effective for annual periods beginning on or after Jan. 1, 2019, with early application permitted if IFRS 15 is also
applied at the same time. The standard is required to be adopted either retrospectively or using a modified retrospective
approach. IFRS 16 will be applied by the Corporation on Jan. 1, 2019.
The Corporation is in the process of completing its initial scoping assessment and expects to have an implementation plan in
place by mid-2017. We anticipate most the effort under the implementation plan will occur in late 2017 through mid-2018. It
is not yet possible to make reliable estimates of the potential impact of IFRS 16 on the Corporation’s financial statements and
disclosures.
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.
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TransAlta Corporation | 2016 Annual Integrated Report
Notes to Consolidated Financial Statements
4. Significant Events
A. Alberta Off-Coal Agreement
On Nov. 24, 2016, the Corporation announced that it had entered into an agreement with the Government of Alberta (the
“Government”) on transition payments for the cessation of coal-fired emissions from the Keephills 3, Genesee 3 and
Sheerness coal-fired plants on or before Dec. 31, 2030.
Under the terms of the Off-Coal Agreement (“OCA”), the Corporation will receive annual cash payments of approximately
$37.4 million, net to the Corporation, commencing in 2017 and terminating in 2030. Receipt of the payments is subject to
certain terms and conditions. The Off-Coal Agreement’s main condition is the cessation of all coal-fired emissions on or
before Dec. 31, 2030. Other conditions include: maintaining prescribed spending on investment and investment related
activities in Alberta; maintaining a significant business presence in Alberta (including through the maintenance of prescribed
employment levels); and maintaining spending on programs and initiatives to support the communities surrounding the
plants, the employees of the Corporation negatively impacted by the phase-out of coal generation, and fulfilling all obligations
to affected employees. The affected plants are not, however, precluded from generating electricity at any time by any method,
other than the combustion of coal.
The Corporation entered into a Memorandum of Understanding with the Government to collaborate and co-operate in the
development of a policy framework to facilitate coal-to-gas fired conversions and renewable electricity development, and
ensure existing generation is able to effectively participate in a future capacity market to be developed for the Province of
Alberta.
B. Force Majeure Relief - Keephills 1
Keephills 1 tripped off-line on March 5, 2013, due to a suspected winding failure within the generator. After extensive testing
and analysis, it was determined that a full rewind of the generator stator was required. After completing the repairs, the unit
returned to service on Oct. 6, 2013. The Corporation claimed force majeure relief on March 26, 2013. The buyer, ENMAX,
disputed the claim of force majeure, which triggered the need for an arbitration hearing that took place in May 2016. On
Nov. 18, 2016, the Corporation announced that the independent arbitration panel confirmed the Corporation’s claim for force
majeure relief. Accordingly, the Corporation reversed a provision of approximately $94 million. The buyer and the Balancing
Pool are seeking to appeal or set the arbitration panel’s decision aside in the Court of Queen’s Bench of Alberta. TransAlta is
opposing these steps and believes they are without merit. No provision has been recognized with respect to this.
C. Poplar Creek Financing
On Dec. 7, 2016, the Corporation announced that its indirect wholly owned subsidiary, TAPC Holdings LP (“TAPCLP”), which
holds the Corporation’s interest in the Poplar Creek cogeneration facility, completed the private placement of a
$202.5 million aggregate principal amount of senior secured floating rate bonds. The bonds, which mature on
Dec. 31, 2030, are secured by a first ranking charge over the equity interests of the issuer that issued such bonds. The bonds
are amortizing and bear interest for each quarterly interest period at a rate per annum equal to the three-month Canadian
Dollar Offered Rate in effect on the first day of such quarterly interest period plus 395 basis points. The interest rate for the
initial period commencing on the date of issue and ending on Dec. 31, 2016 is 4.828% per annum.
D. Mississauga Cogeneration Facility NUG Contract
On Dec. 22, 2016, the Corporation announced it had signed the NUG Contract with the Ontario’s Independent Electricity
System Operator (the “IESO)” for its Mississauga cogeneration facility. The NUG Contract is effective on Jan. 1, 2017, and in
conjunction with the execution of the NUG Contract, the Corporation agreed to terminate effective Dec. 31, 2016, the facility’s
existing contract with the Ontario Electricity Financial Corporation, which would have otherwise terminated December 2018.
The NUG Contract provides the Corporation with fixed monthly payments until Dec. 31, 2018, with no delivery obligations,
and maintains the Corporation’s operational flexibility to pursue opportunities for the facility to meet power market needs in
northeastern Ontario. Further details on the NUG Contract and its impact to these financial statements can be found in
Note 8.
TransAlta Corporation | 2016 Annual Integrated Report
F27
Notes to Consolidated Financial Statements
E. Wintering Hills Assets Held for Sale
The Corporation acquired its interest in Wintering Hills in 2015 in connection with the restructuring of the arrangements
associated with its Poplar Creek cogeneration facility. At Dec. 31, 2016, the criteria for Wintering Hills to be classified as held
for sale were met. The assets held for sale are measured at the lower of carrying amount and fair value less costs to sell.
Accordingly, the Corporation has recorded an impairment charge of $28 million, included in the Wind and Solar segment.
F. Project Financing of a Quebec Wind Asset by TransAlta Renewables
On June 3, 2016, TransAlta Renewables Inc.’s (“TransAlta Renewables”) subsidiary, New Richmond Wind L.P. (the “NRWLP”),
closed a bond offering of approximately $159 million, which is secured by a first ranking charge over all assets of the NRWLP.
The bonds are amortizing and bear interest at a rate of 3.963 per cent, payable semi-annually, and mature on June 30, 2032.
G. Investment in and Acquisition by TransAlta Renewables of the Sarnia Cogeneration Plant,
Le Nordais Wind Farm, and Ragged Chute Hydro Facility (the “Canadian Assets”)
On Jan. 6, 2016, TransAlta Renewables completed its investment in an economic interest based on the cash flows of the
Corporation’s Canadian Assets for a combined aggregate value of approximately $540 million. The Canadian Assets consist
of approximately 611 megawatts (“MW”) of highly contracted power generation assets located in Ontario and Québec. The
transaction was originally announced on Nov. 23, 2015.
As consideration, TransAlta Renewables provided to the Corporation $173 million in cash, issued 15,640,583 common shares
with an aggregate value of $152 million, and issued a $215 million convertible unsecured subordinated debenture. The
debenture issued by TransAlta Renewables to the Corporation is on an interest-only basis at a coupon of 4.5 per cent per
annum payable semi-annually in arrears on June 30 and December 31, and will mature on Dec. 31, 2020. On the maturity
date, the Corporation will have the right, at its sole option, to convert the outstanding principal amount of the debenture, in
whole or in part, into common shares of TransAlta Renewables at a conversion price of $13.16 per common share, being a
35 per cent premium to the offering price on the closing date of the investment in the Canadian Assets. If TransAlta does not
exercise its conversion option, TransAlta Renewables may satisfy the principal obligation by issuing common shares with a
unit value corresponding to 95 per cent of its then-current common share value.
TransAlta Renewables funded the cash proceeds through the public issuance of 17,692,750 subscription receipts at a price of
$9.75 per subscription receipt. Upon the closing of the transaction, each holder of subscription receipts received, for no
additional consideration, one common share of TransAlta Renewables and a cash dividend equivalent payment of $0.07 for
each subscription receipt held. As a result, TransAlta Renewables issued 17,692,750 common shares and paid a total dividend
equivalent of $1 million. Share issuance costs amounted to $8 million, net of $2 million income tax recovery.
On Nov. 30, 2016, TransAlta Renewables acquired direct ownership of the Canadian Assets from the Corporation for a
purchase price of $520 million by issuing a promissory note. At the same time, the Corporation’s subsidiary redeemed the
preferred shares that it had issued to TransAlta Renewables in January 2016 when TransAlta Renewables acquired an
economic interest in the Canadian Assets as described above for $520 million. The two transactions were subject to a set-off
arrangement and resulted in no cash payments. TransAlta Renewables also acquired working capital and certain capital
spares totalling $19 million, through the issuance of a non-interest bearing loan payable to the Corporation.
The acquisition of the Canadian Assets was accounted for by TransAlta Renewables as a business combination under
common control, requiring the application of the pooling of interests method of accounting, whereby the Canadian Assets’
assets and liabilities acquired were recognized at the book values previously recognized by TransAlta at Nov. 30, 2016, and
not at their fair values. As a result, the Corporation recognized a transfer of equity from the non-controlling interests in the
amount of $38 million.
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TransAlta Corporation | 2016 Annual Integrated Report
Notes to Consolidated Financial Statements
H. 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, Alberta.
The Corporation’s Poplar Creek cogeneration facility, which has a maximum capacity of 376 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 provides 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 was accounted for as a joint operation. At Dec. 31, 2016, the Wintering
Hills facility is classified as assets held for sale (see Note 4(E)).
The following table outlines the impacts of the transaction on closing in 2015, 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 payments under the finance lease include $57 million annually from 2016 to 2018, and $20 million annually from 2019 to 2030. Payments have been discounted at a
rate of 2.68%, based on comparative yield on borrowings of the counterparty with equivalent maturities at the time of closing.
The acquired wind farms’ contribution to the Corporation’s revenue and operating income since the date of acquisition until
Dec. 31, 2015, was nominal. Had the acquisition taken place at the beginning of 2015, the wind farms would have contributed
$8 million to revenues and reduced earnings before taxes by $2 million.
TransAlta Corporation | 2016 Annual Integrated Report
F29
Notes to Consolidated Financial Statements
I. 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.
At the 2015 acquisition dates, the fair values of the identifiable assets and liabilities of Odin Wind Power LLC and RC Solar LLC
were as follows:
Assets
Property, plant, and equipment
Inventory (SREC-I)
Net working capital
Total assets acquired
Liabilities
Non-recourse debt
Tax equity liability
Deferred tax liabilities(1)
Decomissioning and restoration provision
Total liabilities assumed
Total consideration transferred
217
10
6
233
55
50
18
4
127
106
(1) The Corporation has recognized a corresponding deferred tax recovery in the Consolidated Statement of Earnings upon acquisition, representing deductible temporary
differences now expected to be recovered.
The acquired assets’ contribution to the Corporation’s revenue and operating income since the date of acquisition until the
end of Dec. 31, 2015, was nominal. Had the acquisition taken place at the beginning of 2015, the assets would have
contributed $14 million to revenues and reduced earnings before taxes by $6 million.
J. Sale of Economic Interest in Australian Assets to TransAlta Renewables Inc.
On May 7, 2015, the Corporation closed the acquisition by TransAlta Renewables of an economic interest based on the cash
flows of the Corporation’s Australian assets. 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. 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.
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TransAlta Corporation | 2016 Annual Integrated Report
Notes to Consolidated Financial Statements
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.
K. Sale of TransAlta Renewables Shares to Alberta Investment Management Corporation
On Nov. 26, 2015, the Corporation 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.
L. 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.
M. 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.
N. Disposal of CE Generation, LLC
On June 12, 2014, the Corporation closed the sale of its 50 per cent ownership of CE Generation, LLC, 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.
TransAlta Corporation | 2016 Annual Integrated Report
F31
Notes to Consolidated Financial Statements
5. Expenses by Nature
Expenses classified by nature are as follows:
Year ended Dec. 31
2016
2015
2014
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 (recovery)
Purchased power
Mine depreciation
Salaries and benefits
Other operating
expenses
Total
755
(4)
143
63
6
-
963
-
-
-
-
249
240
489
775
22
147
59
5
-
1,008
-
-
-
-
250
242
492
937
19
75
56
5
-
1,092
-
-
-
-
280
262
542
6. Asset Impairment Charges and Reversals
As part of the Corporation’s monitoring controls, long-range forecasts are prepared for each CGU. The long-range forecast
estimates are used to assess the significance of potential indicators of impairment and provide criteria to evaluate adverse
changes in operations. The Corporation also considers the relationship between its market capitalization and its book value,
among other factors, when reviewing for indicators of impairment. When indicators of impairment are present, 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.
A. 2016
In 2016, the Corporation concluded that an indicator of possible impairment existed with respect to its U.S. Coal facility as the
plant has merchant exposure and price expectations in the Pacific Northwest region continued to decline. The results of the
impairment analysis are outlined in section III below.
During 2016, uncertainty continued to exist within the province of Alberta regarding the government’s previously announced
Climate Leadership Plan and the future design parameters of the electricity market. Additionally, economic conditions, while
more stable than in 2015, contributed to continued over-supply conditions and depressed market prices. The Corporation
assessed whether these factors presented an indicator of impairment for its Alberta Merchant CGU, and in consideration of
the composition of this CGU and events arising during the latter part of 2016, which are more fully discussed below in I,
determined that no indicators of impairment were present with respect to the Alberta Merchant CGU. Due to this
determination, the Corporation did not perform an in-depth impairment analysis, but sensitivities associated with these
factors were performed to confirm the continued existence of an adequate excess of estimated recoverable amount over net
book value.
Through the Corporation’s ongoing monitoring of potential factors, such as market, economic, and operating conditions, in
other jurisdictions in which its plants operate, it concluded that no indicators of impairment were present as related to its
other plants.
F32
TransAlta Corporation | 2016 Annual Integrated Report
Notes to Consolidated Financial Statements
There was one impairment charge of $28 million related to the Wintering Hills facility (see Note 4(E) and III below) and no
reversals of impairment made during the year ended Dec. 31, 2016.
I. Alberta Merchant CGU
In 2015, the Government of Alberta announced its Climate Leadership Plan (“CLP”), which broadly called for the phase-out of
coal-generated electricity by 2030, and proposed the imposition of additional compliance obligations for greenhouse gas
(“GHG”) emissions in the province. In 2016, the Alberta government refined its approach to GHG by instituting a levy on
carbon emissions in excess of defined limits, amounting to $20 per tonne in 2017 and $30 per tonne in 2018. At the federal
level, the Canadian government announced its intention to implement a national price on greenhouse gas emissions. Under
this proposal, beginning in 2018, there would be a price of $10 per tonne of carbon dioxide equivalent emitted, rising to
$50 per tonne by 2022.
On Nov. 24, 2016, the Corporation reached an Off-Coal Agreement with the Alberta government to receive annual cash
payments of approximately $37.4 million, net to the Corporation (see Note 4(A) for further details) in return for ceasing coal-
fired generation by the end of 2030, among other conditions. Furthermore, the Corporation entered into a Memorandum of
Understanding (the “MOU”) on Nov. 24, 2016, with the purpose of collaborating and co-operating to advance objectives of
the Alberta Climate Leadership Plan. Specifically, the parties undertook to collaborate on, among other things:
(cid:131)
(cid:131)
(cid:131)
a move toward a capacity market, commencing in 2021, compared to the current energy-only market. Under a capacity
market, generators are compensated for their available capacity;
development of a policy and to facilitate the economic conversion of some coal-fired generation to natural-gas-fired
generation in Alberta, including securing regulatory co-operation from the federal government; and
policy development to address the value of carbon reductions in the generation of electricity from existing wind and hydro
production, the development of effective supporting mechanisms to ensure that existing renewable generation is not
adversely impacted by the implementation of a capacity market in Alberta, and the development of regulatory clarity and
alignment so as to permit the economic and timely development of hydroelectric projects within Alberta.
The MOU does not create any legally binding obligations between the Alberta government and the Corporation and does not
impose any obligations on, or constrain the discretion and authority of the Alberta government. The announcement of the
intention to move to a capacity market is expected to impact the Alberta market mechanisms. The Alberta government has
not provided further detail on the market rules or construct. The introduction of a capacity market to replace Alberta’s current
market structure could impact the Corporation’s determination of the Alberta Merchant CGU; however, there is not currently
sufficient information from the Alberta Government to determine if a change is required. The Corporation has not modified its
previous conclusions on the determination of the Alberta Merchant CGU.
During the year, the Corporation monitored the potential impacts of the CLP and other announcements on the Alberta CGU.
A sensitivity analysis on these estimates to assess potential impacts of the Alberta and federal government policies on the
carbon levy and GHG emissions, as well as the impacts of the Off-Coal Agreement and MOU. The analysis of the Alberta
Merchant CGU continued to demonstrate a substantial cushion at the Alberta Merchant CGU due to the Corporation’s large
merchant renewable fleet in the province.
II. Wintering Hills
On Jan. 26, 2017, the Corporation announced the sale of its 51 per cent interest in the Wintering Hills merchant wind facility
for approximately $61 million (see Note 4(E)). In connection with this sale, the Wintering Hills assets were accounted for as
held for sale at December 31, 2016. As required, the Corporation assessed the assets for impairment prior to classifying them
as held for sale. Accordingly, the Corporation has recorded an impairment charge of $28 million using the purchase price in
the sale agreement as the indicator of fair value less cost of disposal.
TransAlta Corporation | 2016 Annual Integrated Report
F33
Notes to Consolidated Financial Statements
III. U.S. Coal
The Corporation 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. 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$22.00 to US$46.00 per MWh
US$1.69 to US$2.09 per gallon
5.4 to 5.7 per cent
B. 2015
In 2015, the Corporation concluded that an indicator of possible impairment existed with respect to its U.S. Coal facility as the
plant has merchant exposure and price expectations in the Pacific Northwest region continued to decline. The results of the
impairment analysis are outlined in section II below.
During 2016, uncertainty existed within the province of Alberta regarding the government’s announced Climate Leadership
Plan. Additionally, economic conditions contributed to continued over-supply conditions and depressed market prices. The
Corporation assessed whether these factors presented an indicator of impairment for its Alberta Merchant CGU, and
determined that no indicators of impairment were present with respect to the Alberta Merchant CGU. See section I below for
further assessment.
There were no impairment charges and one reversal of $2 million made during the year ended Dec. 31, 2015.
I. Alberta Merchant CGU
The slowdown in the oil and gas sector put Alberta into a recession, and placed 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.
During the fourth quarter of 2015, the Corporation completed a sensitivity analysis on the estimates for the Alberta Merchant
CGU 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.
II. U.S. Coal
The Corporation 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. 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$24.00 to US$50.00 per MWh
US$2.44 to US$2.90 per gallon
5.2 to 6.2 per cent
III. Centralia Gas
Impairment reversals of $2 million resulted from additional recoveries from the disposal of the Centralia gas plant in 2014.
B. 2014
In 2014, the Corporation concluded that an indicator of possible impairment existed with respect to its U.S. Coal facility as the
plant has merchant exposure and price expectations in the Pacific Northwest region continued to decline. The results of the
impairment analysis are outlined in section I below.
F34
TransAlta Corporation | 2016 Annual Integrated Report
Notes to Consolidated Financial Statements
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 US$52.00 per MWh
US$3.06 to US$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.
7. Finance Lease Receivables
Amounts receivable under the Corporation’s finance leases, associated with the Fort Saskatchewan cogeneration facility, the
Solomon power station, and 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
2016
2015
Minimum
lease
payments
Present value of
minimum lease
payments
Minimum
lease
payments
Present value of
minimum lease
payments
124
376
637
1,137
592
233
778
59
719
778
116
326
337
779
-
51
830
119
291
311
721
-
57
778
121
414
714
1,249
648
229
830
55
775
830
TransAlta Corporation | 2016 Annual Integrated Report
F35
Notes to Consolidated Financial Statements
8. Net Other Operating (Income) Losses
Net other operating (income) losses are comprised of the following:
Year ended Dec. 31
Mississauga cogeneration facility NUG Contract
MSA settlement
Insurance recoveries
California claim
Supplier settlement
Net other operating (income) losses
2016
(191)
-
(3)
-
-
(194)
2015
2014
-
56
(31)
-
-
25
-
-
(10)
5
(9)
(14)
A. Mississauga Cogeneration Facility Contract
On Dec. 22, 2016, the Corporation announced it had signed a NUG Contract with the Ontario IESO for its Mississauga
cogeneration facility. The contract is effective on Jan. 1, 2017. The Corporation has agreed to terminate the existing contract
with the Ontario Electricity Financial Corporation early, which would have otherwise terminated in December 2018.
As a result of the NUG Contract, the Corporation recognized a pre-tax gain of approximately $191 million. The predominant
components of the gain relate to recognition of a one-time discounted revenue amount of approximately $207 million, offset
by onerous contract expenses and other termination charges totalling approximately $16 million. The Corporation also
recognized $46 million in accelerated depreciation resulting from the change in useful life of the asset. The Corporation
released and recognized in earnings unrealized pre-tax net losses of $14 million from AOCI due to cash flow hedges de-
designated for accounting purposes. The cash flow hedges were in respect of future gas purchases denominated in US dollars
and expected to occur, between 2017 and 2018. In the fourth quarter of 2016, the forecasted gas consumption was no longer
expected to occur which resulted in the cumulative loss on the hedging instrument being released from AOCI and recognized
in earnings.
B. 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 PPA 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 was paid in the fourth quarter of 2015, and the $25 million
administrative penalty was paid in November of 2016. As a result of the approval, the Corporation discontinued the appeal of
the AUC’s decision.
F36
TransAlta Corporation | 2016 Annual Integrated Report
Notes to Consolidated Financial Statements
C. Insurance Recoveries
During 2016, the Corporation received $3 million in insurance recoveries (2015 - $31 million, 2014 - $10 million), of which
$2 million (2015 - $6 million, 2014 - $6 million) relates to business interruption insurance claims and $1 million relates to
claims for replacement and refurbishment of equipment for certain wind facilities (2015 – $7 million for Canadian Coal
facilities).
In 2015 and 2014 the Corporation received $18 million and $4 million of insurance recoveries, respectively, relating to claims
for the replacement and refurbishment for certain hydro facilities as a result of the flooding in Southern Alberta in 2013.
Additionally, in 2015 and 2014, $12 million and $18 million, respectively, 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 costs.
D. 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.
E. Supplier Settlement
During 2014, the Corporation settled a dispute with a supplier in relation to an equipment failure in prior years.
9. Net Interest Expense
The components of net interest expense are as follows:
Year ended Dec. 31
Interest on debt
Capitalized interest (Note 16)
Loss on redemption of bonds (Note 10)
Interest on finance lease obligations
Other
2016
2015
2014
236 228
238
(16) (9) (3)
1
-
-
3
4
1
(5) (2) (1)
Keephills 1 outage interest accruals (reversals) (Note 4)
(10)
9
1
Accretion of provisions (Note 20)
Net interest expense
20
21 18
229
251
254
TransAlta Corporation | 2016 Annual Integrated Report
F37
Notes to Consolidated Financial Statements
10. Income Taxes
A. Consolidated Statements of Earnings
I. Rate Reconciliations
Year ended Dec. 31
Earnings before income taxes
2016
2015
2014
314
221
239
Net earnings attributable to non-controlling interests not subject to tax
(109) (34) (37)
Adjusted earnings before income taxes
Statutory Canadian federal and provincial income tax rate (%)
Expected income tax expense
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
Reversal of writedown of deferred income tax assets
Statutory and other rate differences
Resolution of uncertain tax matters
Divestiture of investment
Other
Income tax expense
Effective tax rate (%)
205
187
202
26.7
25.9
25.0
55
48 51
(16) (16) (3)
11
95
-
-
14
-
(10) (56) (5)
1
20 -
-
-
(1)
-
-
(38)
(3) -
3
38
105
7
19
56
3
F38
TransAlta Corporation | 2016 Annual Integrated Report
II. Components of Income Tax Expense
The components of income tax expense are as follows:
Year ended Dec. 31
Current income tax expense
Adjustments in respect of current income tax of previous years
Adjustments in respect of deferred income tax of previous years
Deferred income tax expense 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 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 recovery arising from the
reversal of writedown of deferred income tax assets(3)
Income tax expense
Year ended Dec. 31
Current income tax expense
Deferred income tax expense (recovery)
Income tax expense
Notes to Consolidated Financial Statements
2016
2015
2014
23
24 33
-
(5) -
(3) 5
2
16
22
12
11
95
-
1
20 -
-
-
(35)
(10) (56) (5)
38
105
7
2016
2015
2014
23
19 33
15
86 (26)
38
105
7
(1) In 2016, reorganizations of certain TransAlta subsidiaries were completed in connection with the New Richmond project financing and the disposition of the Canadian Assets to TransAlta
Renewables. The reorganizations resulted in the recognition of deferred tax liabilities of $3 million and $8 million, respectively. In 2015, in order to give effect to the sale of an economic interest in the
Australian assets to TransAlta Renewables, a reorganization of certain TransAlta subsidiaries was completed. The reorganization resulted in the recognition of a $95 million deferred tax liability on
TransAlta's investment in a subsidiary. For both 2015 and 2016, the deferred tax liabilities had not been recognized previously, as prior to the reorganizations, the taxable temporary differences were not
expected to reverse in the foreseeable future.
(2) 2016 relates to the impact of increase in the New Brunswick corporate income tax rate from 12 per cent to 14 per cent, enacted Feb. 3, 2016. 2015 relates to the impact of an increase in the Alberta
corporate income tax rate from 10 per cent to 12 per cent, enacted June 18, 2015.
(3) During the year ended Dec. 31, 2016, the Corporation reversed a previous writedown of deferred income tax assets of $10 million (2015 - $56 million writedown reversal, 2014 - $5 million writedown
reversal). 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 utlize 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, 2016 and 2015 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
2016
2015
2014
51
89 88
16
8
(6)
4
-
(7)
-
(4) (1)
-
(8) -
71
85
74
TransAlta Corporation | 2016 Annual Integrated Report
F39
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
2016
2015
768
822
103
91
(1,114) (1,124)
(282) (250)
70
70
90
91
69
74
17
16
3
(4)
(276) (214)
(383) (362)
(659) (576)
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
2016
2015
53
71
(712) (647)
(659)
(576)
(1) The deferred income tax assets presented on the Consolidated Statements of Financial Position are recoverable based on estimated future earnings and tax planning
strategies. The assumptions used in the estimate of future earnings are based on the Corporation’s long-range forecasts.
D. Contingencies
As of Dec. 31, 2016, the Corporation had recognized a net liability of $7 million (2015 - $7 million) related to uncertain tax
positions. There were no changes in the liability for uncertain tax positions for the year ended Dec. 31, 2016.
F40
TransAlta Corporation | 2016 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(1)
(1) Owned by TransAlta Renewables.
Non-controlling interest as at Dec. 31, 2016
49.99% - Canadian Power Holdings Inc.
40.2% - Public shareholders
17% - Natural Forces Technologies Inc.
TransAlta Cogeneration L.P. (“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 in TransAlta
Renewables has fluctuated since its formation as follows:
Period
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 and thereafter
Ownership and voting
rights percentage
Equity participation
percentage
80.7
70.3
76.1
66.6
64.0
80.7
70.3
72.8
62.0
59.8
As the Class B shares issued to the Corporation in the sale of the Australian assets 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
2016
259
1
40
2
18
83
2015
236
198
204
63
65
43
TransAlta Corporation | 2016 Annual Integrated Report
2014
233
52
52
15
15
28
F41
Notes to Consolidated Financial Statements
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
2016
109
3,732
(537)
(1,237)
(2,067)
(851)
40.2
2015
74
3,262
(190)
(1,120)
(2,026)
(787)
37.96
2016
2015
2014
274
211
258
105
128
68
288
305
61
77
31
38
56
2016
171
538
(65)
(35)
(609)
(301)
49.99
71
72
35
35
56
2015
82
535
(75)
(54)
(488)
(242)
49.99
2016
2015
558
433
9
5
59
55
77
74
703
567
F42
TransAlta Corporation | 2016 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:
Carrying value as at Dec. 31, 2016
Financial assets
Cash and cash equivalents(1)
Trade and other receivables
Long-term portion of finance lease receivables
Other assets
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(2)
(1) Includes cash equivalents of $103 million.
(2) Includes current portion.
Derivatives
used for
hedging
Derivatives
classified as
held for
trading
Loans and
receivables
Other
financial
liabilities
Total
-
-
-
-
192
749
-
-
1
4
-
-
-
-
-
57
36
-
-
65
44
-
305
703
719
116
-
-
.
-
-
-
-
-
-
-
-
-
-
-
413
54
-
-
305
703
719
116
249
785
413
54
66
48
4,361
4,361
TransAlta Corporation | 2016 Annual Integrated Report
F43
Notes to Consolidated Financial Statements
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) Includes current portion.
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
-
-
-
-
-
-
-
Total
54
567
775
298
797
334
63
200
69
-
-
-
-
-
334
63
-
-
4,495
4,495
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.
F44
TransAlta Corporation | 2016 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, which governs both the commodity transactions undertaken
in its proprietary trading business and those undertaken to manage commodity price exposures in its generation business.
This Policy defines and specifies the controls and management responsibilities associated with commodity trading activities,
as well as the nature and frequency of required reporting of such activities.
Methodologies and procedures regarding commodity risk management Level III fair value measurements are determined by
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.
TransAlta Corporation | 2016 Annual Integrated Report
F45
Notes to Consolidated Financial Statements
As at Dec. 31
Description
Long-term power sale - U.S.
Long-term power sale - Alberta
Unit contingent power purchases
Structured products - Eastern U.S.
Hydro slice products - Western U.S.
Others
2016
2015
Base fair value
Sensitivity
Base fair value
Sensitivity
907
(3)
13
24
-
6
+75
-69
+5
-5
+2
-4
+8
-8
-
-
+3
-3
863
(13)
(70)
18
(6)
(3)
+125
-186
+13
-7
+9
-8
+6
-4
+1
-4
+2
-2
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: 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 2018, 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). Forward power price ranges per MWh used in determining the
Level III base fair value at Dec. 31, 2016 are US$24 - US$40 (Dec. 31, 2015 - US$28 - US$45). The sensitivity analysis has
been prepared using the Corporation’s assessment that a US$5 price increase or decrease in the forward power prices is a
reasonably possible change.
The contract is denominated in US dollars. With the weakening of the US dollar relative to the Canadian dollar from
Dec. 31, 2015 to Dec. 31, 2016, the base fair value and the sensitivity values have decreased by approximately
$26 million and $2 million, respectively.
ii. Long-Term Power Sale - 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 2021, 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, 2016 are $55 - $107 (Dec. 31, 2015 - $86 - $93). The sensitivity analysis has been prepared using the Corporation’s
assessment that a 20 per cent increase or decrease in the forward power prices is a reasonably possible change.
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.
F46
TransAlta Corporation | 2016 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.
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, 2016 are 0.53 per cent to 0.94 per cent (Dec. 31,
2015 - 0 per cent to 2.8 per cent) and 8.41 per cent to 21.08 per cent (Dec. 31, 2015 – 1.7 per cent to 7.4 per cent),
respectively. The sensitivity analysis has been prepared using the Corporation’s assessment of a reasonably possible change
in price discount ranges of approximately 0.75 per cent and a change in volumetric discount rates of approximately 15.5
per cent, which approximate one standard deviation for each input.
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, 2016, are 66 per cent to 128 per cent and
42 per cent to 95 per cent (Dec. 31, 2015 – 85 per cent to 116 per cent and 65 per cent to 109 per cent), respectively. The
sensitivity analysis has been prepared using the Corporation’s assessment of a reasonably possible change in market forward
spreads of approximately 5 per cent and a change in non-standard shape factors of approximately 9 per cent, which
approximate one standard deviation for each input.
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, 2016 are 18 per cent to 59 per cent
and 63 per cent to 77 per cent (Dec. 31, 2015 – 18 per cent to 71 per cent and 39 per cent to 80 per cent), respectively. The
sensitivity analysis has been prepared using the Corporation’s assessment of a reasonably possible change in implied
volatilities and correlation of approximately 10 per cent, respectively.
v. Hydro Slice Products – Western U.S.
The Corporation 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 were accounted for as held for trading and expired during the fourth quarter of 2016.
The key unobservable inputs used in the Dec. 31, 2015 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.
TransAlta Corporation | 2016 Annual Integrated Report
F47
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, 2016 and 2015, respectively:
Net risk management assets (liabilities) at
Dec. 31, 2015
Changes attributable to:
Market price changes on existing
contracts
Market price changes on new contracts
Contracts settled
Change in foreign exchange rates
Discontinued hedge accounting on
certain contracts (see Note 4)
Net risk management assets (liabilities)
at Dec. 31, 2016
Additional Level III information:
Gains recognized in OCI
Total gains included in earnings
before income taxes
Unrealized gains included in earnings
before income taxes relating to net
assets held at Dec. 31, 2016
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
Change in foreign exchange rates
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
Hedges
Non-Hedges
Total
Level I
Level II
Level III
Level I
Level II
Level III
Level I
Level II
Level III
-
-
-
-
-
-
-
(58)
640
44
5
20
1
31
43
163
-
(50)
(27)
-
726
136
50
-
-
-
-
-
-
-
-
128
(98)
(10)
(23)
(121)
-
(31)
13
29
88
-
-
(57)
32
-
-
-
-
-
-
-
70
542
34
(18)
(101)
1
-
176
29
38
(27)
-
(14)
758
-
42
130
136
92
130
Hedges
Non-Hedges
Total
Level I
Level II
Level III
Level I
Level II
Level III
Level I
Level II
Level III
-
-
-
-
-
-
(59)
314
(18)
1
26
(8)
261
-
(28)
93
(58)
640
-
-
-
-
-
-
180
(97)
49
51
(159)
7
(25)
(48)
76
(4)
128
(98)
-
-
-
-
-
-
121
217
31
52
(133)
(1)
236
(48)
48
89
70
542
354
28
-
-
(77)
(1)
354
(49)
(1)
F48
TransAlta Corporation | 2016 Annual Integrated Report
Notes to Consolidated Financial Statements
Significant changes in commodity net risk management assets (liabilities) during the year ended Dec. 31, 2016, are primarily
attributable to the following factors:
(cid:131)
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;
change in value of Alberta power sale contracts and eastern Canadian gas purchase contracts (Level II hedge); and
(cid:131)
(cid:131) maturity of power contracts in the Northeast U.S. (Level II non-hedge) and maturities of unit contingent power purchases
described in the section (B)(I)(c)(iii) of this note (Level III non-hedges).
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 $176 million as at Dec. 31, 2016
(Dec. 31, 2015 - $214 million net asset) are classified as Level II fair value measurements. The significant changes in other net
risk management assets during the period ended Dec. 31, 2016 are primarily attributable to the weakening 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, 2016
Long-term debt(1) - Dec. 31, 2015
Fair value
Level I
Level II
Level III
Total
-
-
4,271
4,067
-
-
4,271
4,067
Total
carrying
value
4,221
4,344
(1) Includes current portion and excludes $67 million (Dec. 31, 2015 - $69 million) of debt measured and carried at fair value.
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.
TransAlta Corporation | 2016 Annual Integrated Report
F49
Notes to Consolidated Financial Statements
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
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, 2016
2016
202
10
(4)
(60)
148
2015
188
28
28
(42)
202
2014
160
23
14
(9)
188
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 (liabilities)
Other
Current
Long-term
Net other risk management assets
Total net risk management assets (liabilities)
-
-
-
-
-
-
-
86
683
769
105
59
164
933
-
-
-
-
3
3
3
Total
70
674
744
113
63
176
(16)
(9)
(25)
8
1
9
(16)
920
F50
TransAlta Corporation | 2016 Annual Integrated Report
Notes to Consolidated Financial Statements
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)
Net
investment
hedges
Cash flow
hedges
Fair value
hedges
Not
designated
as a hedge
-
-
-
(7)
-
(7)
(7)
31
551
582
20
207
227
809
-
-
-
-
5
5
5
57
(27)
30
(3)
(8)
(11)
19
Total
88
524
612
10
204
214
826
Additional information on derivative instruments has been presented on a net basis below.
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
315
(24)
2016
Long-term
financial
assets
744
(3)
Current
financial
liabilities
(113)
24
2015
Long-term
financial
liabilities
Current
financial
assets
Long-term
financial
assets
Current
financial
liabilities
Long-term
financial
liabilities
(53)
3
534
(105)
1,048
(12)
(350)
105
(93)
12
291
741
(89)
(50)
429
1,036
(245)
(81)
II. Hedges
a. Net Investment Hedges
The Corporation’s hedges of its net investment in foreign operations are comprised of US-dollar-denominated long-term debt
with a face value of US$630 million (2015 - US$580 million) and the following foreign currency forward contracts:
As at Dec. 31
Notional
amount
sold
Notional
amount
purchased
Foreign Currency Forward Contracts
2016
Fair
value
liability
2015
Notional
amount
sold
Notional
amount
purchased
Fair
value
liability
Maturity
Maturity
-
-
-
-
-
-
-
-
AUD297
USD76
CAD293
CAD104
(6)
(1)
2016
2016
During 2016, the Corporation de-designated its foreign currency forward contracts from its net investment hedges. The
cumulative unrealized losses on these contracts will be deferred in AOCI until the disposal of the related foreign operation.
TransAlta Corporation | 2016 Annual Integrated Report
F51
Notes to Consolidated Financial Statements
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)
2016
Notional
amount
sold
4,916
-
Notional
amount
purchased
-
-
2015
Notional
amount
sold
7,006
Notional
amount
purchased
-
-
22,485
During 2016, additional unrealized pre-tax gains of $nil (2015 - $3 million, 2014 - $2 million) 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, 2016, cumulative gains of $4 million (2015 - $4 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
2016
2015
Fair value
asset
Maturity
Notional
amount
sold
Notional
amount
purchased
Fair value
asset
Foreign Exchange Forward Contracts - foreign-denominated receipts/expenditures
-
AUD8
-
JPY710
-
1
-
2017
CAD138
AUD19
USD126
JPY1,683
Foreign Exchange Forward Contracts - foreign-denominated debt
CAD26
USD20
-
2018
CAD95
USD70
Cross-Currency Swaps - foreign-denominated debt
CAD434
CAD306
USD400
USD270
104
59
2017
2018
CAD434
CAD306
USD400
USD270
36
1
2
116
72
Maturity
2016-2018
2016-2017
2016-2018
2017
2018
F52
TransAlta Corporation | 2016 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, 2016
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
304
Revenue
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
Fuel and purchased
power
(5)
Revenue
Property, plant,
and equipment
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
(1)
(2)
(25)
-
Interest expense
271
OCI impact
(169)
Revenue
Fuel and purchased
power
44
(16)
Revenue
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
-
53
(23)
6
Interest expense
(105)
Net earnings impact
-
31
(15)
-
-
-
-
16
During December 2016, the Corporation entered into a new contract with the Ontario IESO relating to the Mississauga
cogeneration facility that principally terminates the generation effective Jan. 1, 2017. Accordingly, the Corporation reclassified
unrealized pre-tax cash flow commodity hedge losses of $31 million and $15 million of unrealized pre-tax cash flow foreign
exchange hedge gains from AOCI to net earnings due to hedge de-designations for accounting purposes. The cash flow
hedges were in respect of future gas purchases expected to occur between 2017 and 2018. See Note 8(A) for further details.
During 2015 and 2014, total unrealized pre-tax gains of $6 million and $3 million, respectively, were released from AOCI and
recognized in earnings due to hedge de-designations for accounting purposes.
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
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
308
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
TransAlta Corporation | 2016 Annual Integrated Report
5
-
-
-
-
-
-
5
F53
Notes to Consolidated Financial Statements
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
212
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
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)
Over the next 12 months, the Corporation estimates that approximately $83 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 6.90 per cent (2015 - 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
2016
Fair
value
asset
3
Maturity
2018
2015
Fair
value
asset
5
Notional
amount
USD50
Maturity
2018
Including interest rate swaps, 6 per cent of the Corporation’s debt as at Dec. 31, 2016 is subject to floating interest rates
(2015 - 9 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
2016
2015
2014
(2)
2
-
(1)
1
-
(1)
1
-
F54
TransAlta Corporation | 2016 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)
Heating oil (gallons)
b. Other Non-Hedge Derivatives
2016
2015
Notional
amount
sold
19,362
146,113
-
1,370
-
Notional
amount
purchased
19,060
173,187
3,429
1,370
294
Notional
amount
sold
42,975
106,203
-
960
-
Notional
amount
purchased
38,565
101,100
5,014
960
-
As at Dec. 31
Notional
amount
sold
Notional
amount
purchased
2016
Fair value
asset
(liability)
Foreign Exchange Forward Contracts
2015
Notional
amount
sold
Notional
amount
purchased
Fair value
asset
(liability)
Maturity
USD152
AUD232
CAD216
CAD219
12
(3)
2017-2020
2017-2020
-
Derivatives embedded in supplier contracts (1)
-
-
-
-
-
-
-
USD41
AUD89
AUD5
CAD54
CAD79
USD4
USD4
AUD5
(3)
(8)
1
(1)
(1) Result from payments that are not denominated in the functional currency of either party under a contract with a supplier.
Maturity
2016-2018
2016-2020
2016
2016
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, 2016, the Corporation recognized a net unrealized loss of $63 million (2015 - loss of $51 million,
2014 - gain of $54 million) related to commodity derivatives.
For the year ended Dec. 31, 2016, a gain of $9 million (2015 - loss of $1 million, 2014 - gain of $10 million) related to foreign
exchange and other derivatives was recognized and is comprised of net unrealized gains of $4 million (2015 - loss of
$11 million, 2014 - gain of $2 million) and net realized gains of $5 million (2015 - gain of $10 million, 2014 - gain of $8 million).
TransAlta Corporation | 2016 Annual Integrated Report
F55
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 Commodity Exposure Management 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 level, resulting from normal market fluctuations. VaR is estimated using the
historical variance/covariance approach.
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, 2016, associated with the Corporation’s proprietary trading activities was $2 million (2015 - $5 million,
2014 - $5 million).
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 byproducts, 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.
F56
TransAlta Corporation | 2016 Annual Integrated Report
Notes to Consolidated Financial Statements
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, 2016, associated with the Corporation’s commodity derivative instruments used in generation hedging
activities was $19 million (2015 - $24 million, 2014 - $27 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, 2016, associated with these transactions was $7 million (2015 - $1 million,
2014 - $7 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 (2015 - 15 basis point, 2014 - 15 basis point) increase or decrease is a reasonable potential change over the next quarter
in market interest rates.
Year ended Dec. 31
2016
Net earnings
increase(1)
OCI loss(1)
2015
Net earnings
increase(1)
OCI loss(1)
2014
Net earnings
increase(1)
OCI loss(1)
Basis point change
-
-
1
-
-
-
(1)This calculation assumes a decrease in market interest rates. An increase would have the opposite effect.
c. Currency Rate Risk
The Corporation has exposure to various currencies, such as 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 Australian assets transaction described in Note 4(J), the Corporation 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$239 million remaining investments to fund the South Hedland project. In addition, the Corporation 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 Australian Assets
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 entered into foreign
currency contracts 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 contracts and accordingly, the loss on the contracts,
recognized as a foreign exchange loss, was $5 million for the year ended Dec. 31, 2016 (2015 – loss $8 million).
The Corporation also uses foreign currency contracts to hedge its expected foreign operating cash flows. Hedge accounting is
not applied to these foreign currency contracts.
TransAlta Corporation | 2016 Annual Integrated Report
F57
Notes to Consolidated Financial Statements
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 (2015 and 2014 - four 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
2016
2015
2014
Currency
USD
AUD
Total
Net earnings
increase
(decrease)(1)
(5)
(7)
(12)
OCI gain(1), (2)
Net earnings
increase(1)
OCI gain(1), (2)
Net earnings
decrease(1)
OCI gain(1), (2)
-
-
-
2
(3)
(1)
5
-
5
4
(2)
2
5
-
5
(1) These calculations assume an increase in the value of these currencies relative to the Canadian dollar. A decrease would have the opposite effect.
(2) The foreign exchange impact related to financial instruments designated as hedging instruments in net investment hedges has been excluded.
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 fulfil 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.
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, including the distribution of credit ratings, as at Dec. 31, 2016:
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)
92
36
100
8
64
-
100
100
100
Total
amount
703
719
1,034
2,456
(1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts.
(2) The Corporation has one non-investment grade customer whose outstanding balance accounted for $445 million (Dec. 31, 2015 - $446 million). Risk of significant loss
arising from this counterparty has been assessed as low in the near term, but could increase to moderate in an environment of sustained low commodity prices over the mid-
to long term. The Corporation's assessment takes into consideration the counterparty's financial position, external rating assessments, how the Corporation provides its
services in an area of the counterparty's lower-cost operations, and the Corporation's other credit risk management practices.
F58
TransAlta Corporation | 2016 Annual Integrated Report
Notes to Consolidated Financial Statements
The Corporation’s maximum exposure to credit risk at Dec. 31, 2016, without taking into account collateral held or right of set-
off, is represented by the current carrying amounts of receivables 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, 2016, was $14 million (2015 - $44 million).
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 U.S. bonds one notch from Baa3 to Ba1. During the first quarter of 2016, two rating
agencies affirmed the Corporation’s long-term issuer rating as investment grade, but revised their outlook to negative, from a
previous stable outlook. As at Dec. 31, 2016, TransAlta maintains investment grade ratings from three credit rating agencies.
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:
2017
2018
2019
2020
2021
2022 and
thereafter
Accounts payable and accrued liabilities
Long-term debt(1)
Commodity risk management assets
Other risk management (assets) liabilities
Finance lease obligations
Interest on long-term debt and finance lease obligations(2)
Dividends payable
Total
413
623
(69)
(114)
16
219
54
-
959
(73)
(67)
14
174
-
1,142
1,007
-
461
(80)
3
10
143
-
537
(1) Excludes impact of hedge accounting.
(2) Not recognized as a financial liability on the Consolidated Statements of Financial Position.
Total
413
4,311
-
460
-
63
-
1,745
(79)
(100)
(343)
(744)
2
8
117
-
508
-
6
91
-
60
-
19
(176)
73
764
1,508
-
54
2,185
5,439
TransAlta Corporation | 2016 Annual Integrated Report
F59
Notes to Consolidated Financial Statements
C. Collateral
I. Financial Assets Provided as Collateral
At Dec. 31, 2016, the Corporation provided $77 million (2015 - $74 million) in cash and cash equivalents as collateral to
regulated clearing agents as security for commodity trading activities. These funds are held in segregated accounts by the
clearing agents. Collateral provided is recorded in accounts receivable in the statement of financial position.
II. Financial Assets Held as Collateral
At Dec. 31, 2016, the Corporation held $21 million (2015 - $15 million) 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. Collateral held is contained in accounts payable in the statement of financial
position.
III. 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, 2016, the Corporation had posted collateral of $116 million (Dec. 31, 2015 - $220 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 $49 million (Dec. 31, 2015 -
$44 million) of collateral to its counterparties.
F60
TransAlta Corporation | 2016 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
The change in inventory is as follows:
Balance, Dec. 31, 2014
Net additions
Acquisition (Note 4)
Writedowns
Change in foreign exchange rates
Balance, Dec. 31, 2015
Net use
Writedowns
Reversal of writedowns
Change in foreign exchange rates
Balance, Dec. 31, 2016
No inventory is pledged as security for liabilities.
2016
2015
110
65
12
17
9
213
116
56
14
8
25
219
196
47
10
(22)
(12)
219
(12)
(9)
13
2
213
TransAlta Corporation | 2016 Annual Integrated Report
F61
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)
Cost
As at 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
Additions
Additions - finance lease
Disposals
Impairment charges - Wintering Hills (Note 4)
Other (Note 6)
Revisions and additions to
decommissioning and restoration
costs
Retirement of assets
Change in foreign exchange rates
Reclassification to held for sale (Note 4)
Transfers (2)
As at Dec. 31, 2016
Accumulated depreciation
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
Depreciation
Retirement of assets
Disposals
Change in foreign exchange rates
Reclassification to held for sale (Note 4)
Transfers (2)
As at Dec. 31, 2016
Carrying amount
As at Dec. 31, 2014
As at Dec. 31, 2015
As at Dec. 31, 2016
82
1
-
-
(2)
-
-
-
-
3
11
95
2
-
(1)
-
-
-
-
(1)
-
-
95
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
82
95
95
5,803
1,869
-
-
-
-
-
-
(42)
(106)
220
216
6,091
-
-
-
-
-
14
(96)
(38)
-
(95)
3
-
-
(13)
(429)
2
(10)
(19)
33
48
2,882
-
321
-
-
-
-
(21)
(18)
27
74
1,159
-
-
13
-
-
-
(13)
(11)
18
42
1,484
3,265
1,208
-
-
(3)
-
-
12
(3)
(16)
-
51
1
-
(1)
(28)
-
4
(14)
(10)
(67)
62
-
7
(1)
-
-
36
(6)
(3)
-
24
5,876
1,525
3,212
1,265
2,941
279
(96)
-
-
155
1
3,280
284
(85)
-
(28)
-
(239)
3,212
2,862
2,811
2,664
993
85
(15)
(8)
(202)
21
(1)
873
118
(4)
(1)
(10)
-
51
1,027
876
611
498
713
107
(12)
-
-
2
-
810
127
(7)
-
-
(6)
(2)
922
2,169
2,455
2,290
544
60
(7)
-
-
7
-
604
59
(2)
(1)
(1)
-
-
659
615
604
606
341
474
-
-
-
-
-
-
-
16
(480)
351
353
-
-
-
-
-
-
(13)
-
(284)
407
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
341
351
407
Total
12,407
476
321
13
(15)
(436)
2
(86)
(158)
325
5
12,854
358
7
(9)
(28)
(1)
71
(122)
(85)
(67)
(205)
271
(2)
-
-
-
(7)
-
-
(4)
8
94
360
2
-
(3)
-
(1)
5
(3)
(4)
-
37
393
12,773
103
14
(4)
-
-
1
-
114
19
(3)
-
-
-
(1)
129
168
246
264
5,294
545
(134)
(8)
(202)
186
-
5,681
607
(101)
(2)
(39)
(6)
(191)
5,949
7,113
7,173
6,824
(1) Includes major spare parts and stand-by equipment available, but not in service, and spare parts used for routine, preventive, or planned maintenance.
(2) Net transfers of $14 million relate to the transfer of gas equipment to finance lease receivables.
F62
TransAlta Corporation | 2016 Annual Integrated Report
Notes to Consolidated Financial Statements
The Corporation capitalized $16 million of interest to PP&E in 2016 (2015 - $9 million) at a weighted average rate of
5.93 per cent (2015 – 5.83 per cent).
Finance lease additions in 2016 and 2015 are for mining equipment at the Highvale mine. The carrying amount of total assets
under finance leases as at Dec. 31, 2016 was $76 million (2015 - $81 million).
17. Goodwill
Goodwill acquired through business combinations has been allocated to CGUs that are expected to benefit from the synergies
of the acquisitions. Goodwill by segments are as follows:
As at Dec. 31
Hydro
Wind and Solar
Energy Marketing
Total goodwill
2016
259
175
30
464
2015
259
176
30
465
During 2015, the Corporation systemized allocations of certain costs to each fuel type within the broad generation segment.
Accordingly, the Corporation disaggregated the generation segment into distinct generation segments as reportable
segments. Accordingly, the Corporation re-allocated goodwill on a relative fair value basis in 2015. 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 2016 and 2015 annual goodwill impairment review, the Corporation determined the recoverable amounts
of the test units by calculating the fair value less costs of disposal using discounted cash flow projections based on the
Corporation’s long-range forecasts for the period extending to the last planned asset retirement in 2073. The resulting fair
value measurement is categorized within Level III of the fair value hierarchy.
The key assumption impacting the determination of fair value for the wind and solar and hydro segments 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 2016 models
ranged between $32 to $301 per MWh during the forecast period (2015 - $26 to $311 per MWh). Discount rates used for the
goodwill impairment calculation in 2016 ranged from 5.5 per cent to 6.0 per cent (2015 – 5.3 per cent to 6.5 per cent). No
reasonable possible change in the assumptions would have resulted in an impairment of goodwill.
TransAlta Corporation | 2016 Annual Integrated Report
F63
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
Cost
As at Dec. 31, 2014
Additions
Acquisitions (Note 4)
Retirements
Change in foreign exchange rates
Transfers
As at Dec. 31, 2015
Additions
Additions - capital lease
Retirements
Change in foreign exchange rates
Transfers
As at Dec. 31, 2016
Accumulated amortization
As at Dec. 31, 2014
Amortization
Change in foreign exchange rates
Transfers
As at Dec. 31, 2015
Amortization
Retirements
As at Dec. 31, 2016
Carrying amount
As at Dec. 31, 2014
As at Dec. 31, 2015
As at Dec. 31, 2016
178
206
-
-
-
-
-
178
-
-
-
-
-
1
-
(1)
8
42
256
-
3
(3)
(1)
13
186
-
37
-
-
-
223
-
-
-
-
-
178
268
223
106
3
-
-
109
6
-
115
72
69
63
124
20
3
(5)
142
24
(3)
163
82
114
105
43
9
-
-
52
8
-
60
143
171
163
34
25
-
-
-
(44)
15
21
-
-
(1)
(11)
24
-
-
-
-
-
-
-
-
34
15
24
Total
604
26
37
(1)
8
(2)
672
21
3
(3)
(2)
2
693
273
32
3
(5)
303
38
(3)
338
331
369
355
F64
TransAlta Corporation | 2016 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
Mississauga long-term receivable (Note 4)
Long-term prepaids and other
Keephills Unit 3 transmission deposit
Total other assets
Notes to Consolidated Financial Statements
2016
2015
15
46
16
116
44
5
242
16
42
17
-
52
6
133
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.
Mississauga long-term receivable relates to amounts recognized as a result of entering into the new contract. Fixed monthly
payments are to be received until Dec. 31, 2018. See Note 4 for further details.
Long-term prepaids 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 five years to 2021, as long as certain performance criteria are met.
TransAlta Corporation | 2016 Annual Integrated Report
F65
Notes to Consolidated Financial Statements
20. Decommissioning and Other Provisions
The change in decommissioning and other provision balances is as follows:
Balance, Dec. 31, 2014
Liabilities incurred
Liabilities acquired
Liabilities settled
Liabilities disposed
Accretion
Revisions in estimated cash flows
Revisions in discount rates
Reversals
Change in foreign exchange rates
Balance, Dec. 31, 2015
Liabilities incurred
Liabilities settled
Accretion
Revisions in estimated cash flows
Revisions in discount rates
Reversals
Change in foreign exchange rates
Balance, Dec. 31, 2016
Balance, Dec. 31, 2015
Current portion
Non-current portion
Balance, Dec. 31, 2016
Current portion
Non-current portion
Decommissioning and
restoration
Other
305
6
7
(24)
(11)
20
1
(89)
-
18
233
11
(23)
19
12
44
-
(3)
293
51
58
-
(14)
(1)
1
71
-
(2)
1
165
12
(36)
1
5
-
(96)
(1)
50
Total
356
64
7
(38)
(12)
21
72
(89)
(2)
19
398
23
(59)
20
17
44
(96)
(4)
343
Decommissioning and
restoration
Other
Total
233
30
203
293
27
266
165
136
29
50
12
38
398
166
232
343
39
304
F66
TransAlta Corporation | 2016 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 $1.1 billion, which will be incurred
between 2017 and 2073. The majority of the costs will be incurred between 2020 and 2050. At Dec. 31, 2016, the
Corporation had provided a surety bond in the amount of US$139 million (2015 - US$139 million) in support of future
decommissioning obligations at the Centralia coal mine. At Dec. 31, 2016, the Corporation had provided letters of credit in the
amount of $117 million (2015 - $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, relating to the force majeure claim at
Keephills 1. However, on Nov. 18, 2016, force majeure relief was granted to the Corporation and accordingly approximately
$94 million was reversed during the last quarter of 2016 as disclosed in Note 4(B).
TransAlta Corporation | 2016 Annual Integrated Report
F67
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
2016
Carrying
Face
Carrying
value
value
Interest(1)
-
1,045
2,151
-
1,051
2,158
1,038
1,048
54
54
4,288
4,311
-
6.0%
5.0%
4.5%
9.2%
73
4,361
(623)
(16)
(639)
3,722
2015
Face
value
315
1,051
2,221
773
67
Interest(1)
3.1%
6.0%
4.9%
4.5%
9.3%
value
315
1,044
2,221
766
67
4,413
4,427
82
4,495
(72)
(15)
(87)
4,408
(1) Interest is an average rate weighted by principal amounts outstanding before the effect of hedging.
(2) Composed of bankers' acceptances and other commercial borrowings under long-term committed credit facilities.
(3) US face value at Dec. 31, 2016 - US$1.6 billion (Dec. 31, 2015 - US$1.6 billion).
(4) Includes US$53 million at Dec. 31, 2016 (Dec. 31, 2015 - US$59 million).
(5) Includes US$29 million at Dec. 31, 2016 (Dec. 31, 2015 - US$36 million) of tax equity financing.
Credit facilities 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. 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 in committed bilateral credit facilities which expire in 2018 and a US$200
million committed bilateral credit facility expiring in 2020.
During 2016, the Corporation:
(cid:131)
paid out the credit facilities balance from a combination of cash flows from operations and net cash proceeds of
$173 million received from the sale of the economic interest of the Canadian Assets that closed Jan. 6, 2016
(see Note 4);
extended the four-year revolving $1.5 billion committed syndicated credit facility and three bilateral credit facilities by one
year to 2020 and 2018, respectively, with key terms and covenants unchanged; and
extended the four-year US$200 million bilateral credit facility to 2020. The amount available was reduced from
US$300 million to US$200 million. The remaining key terms and covenants were unchanged.
(cid:131)
(cid:131)
Of the $2.0 billion (2015 - $2.2 billion) of committed credit facilities, $1.4 billion (2015 - $1.3 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
$1.4 billion available under the credit facilities, TransAlta also has $305 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.
F68
TransAlta Corporation | 2016 Annual Integrated Report
During 2016:
(cid:131)
(cid:131)
During 2015:
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
Notes to Consolidated Financial Statements
Senior notes bear interest at rates ranging from 1.90 per cent to 6.90 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.
A total of US$630 million (2015 - 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 2017 to 2032 and bear interest at
rates ranging from 2.95 per cent to 7.31 per cent.
the Corporation’s $27 million 5.69 per cent non-recourse debenture matured and was paid out using existing liquidity;
the Corporation’s subsidiary New Richmond Wind L.P. issued a non-recourse bond in the amount of $159 million, bearing
interest at 3.963 per cent, with principal and interest payable semi-annually, and maturing on June 30, 2032 (see Note 4);
the Corporation made a scheduled semi-annual $4.2 million principal payment on the New Richmond Wind L.P. bond;
the Corporation made scheduled semi-annual principal payments of approximately $35 million on the Melancthon-Wolfe
Wind L.P. bond;
the Corporation’s indirect wholly-owned subsidiary TAPC Holdings L.P. issued a non-recourse bond in the amount of
$202.5 million, bearing a variable interest rate at the Canadian Dollar Offered Rate plus 395 basis points, with principal
and interest payable quarterly, maturing on Dec. 31, 2030 (see Note 4), and;
early redeemed $10 million of non-recourse bonds, which resulted in a $1 million loss recognized in interest expense.
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.
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.
the Corporation’s subsidiary Melancthon-Wolfe Wind L.P. 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).
TransAlta's debt has terms and conditions, including financial covenants, that are considered normal and customary. As at
Dec. 31, 2016, the Corporation was in compliance with all debt covenants.
B. Restrictions on Non-Recourse Debt and Security
Non-recourse debentures of $193 million (2015 - $230 million) issued by the Corporation’s subsidiary, CHD, include
restrictive covenants requiring the cash proceeds received from the sale of assets to be reinvested into similar renewable
assets or to repay the non-recourse debentures.
TransAlta Corporation | 2016 Annual Integrated Report
F69
Notes to Consolidated Financial Statements
Other non-recourse debt of $845 million in total (2015 - $536 million) is subject to customary financing restrictions that
restrict the Corporation’s ability to access funds generated by certain facilities’ operations. Upon meeting certain distribution
tests, typically performed once per quarter, the funds are able to be distributed by the subsidiary entities to their respective
parent entity. At Dec. 31, 2016, $24 million of cash was subject to these financial restrictions. Non-recourse debts of
$644 million are each secured by a first ranking charge over all of the respective assets of the Corporation’s subsidiaries that
issued the bonds, which includes renewable generation facilities with total carrying amounts of $956 million at Dec. 31, 2016
(2015 - $798 million). A non-recourse bond of approximately $201 million is secured by a first ranking charge over the equity
interests of the issuer that issued the non-recourse bond.
C. Principal Repayments
Principal repayments(1)
(1) Excludes impact of derivatives.
2017
623
2018
959
2019
2020
2021
2022 and
thereafter
Total
461
460
63
1,745
4,311
D. Finance Lease Obligations
Amounts payable for mining assets and other finance leases are as follows:
As at Dec. 31
2016
2015
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
19
44
21
84
11
73
16
57
73
18
44
20
82
-
82
19
39
15
73
-
73
18
49
29
96
14
82
15
67
82
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, 2016 was $566 million (2015 - $575 million) with no (2015 - nil) amounts
exercised by third parties under these arrangements.
F70
TransAlta Corporation | 2016 Annual Integrated Report
Notes to Consolidated Financial Statements
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
2016
208
62
14
46
330
2015
222
60
8
58
348
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 $10 million (2015 - $11 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.
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
2016
Common
shares
(millions)
284.0
3.9
287.9
-
287.9
Amount
3,077
18
3,095
(1)
3,094
2015
Common
shares
(millions)
275.0
9.0
284.0
-
284.0
Amount
3,001
76
3,077
(2)
3,075
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 22, 2016. 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.
TransAlta Corporation | 2016 Annual Integrated Report
F71
Notes to Consolidated Financial Statements
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. On Jan. 14, 2016, the Corporation announced the
suspension of the Premium DividendTM, Dividend Reinvestment and Optional Common Share Purchase Plan (the “DRIP”), in
order to stop shareholder dilution.
On Jan. 1, 2016, 3.9 million common shares were issued for dividends reinvested.
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
2016
117
288
0.41
2015
(24)
280
(0.09)
2014
141
273
0.52
E. Dividends
On Jan. 14, 2016, the Corporation announced the resizing of its dividend from $0.72 annually to $0.16 annually, as part of a
plan to maximize the Company’s long-term financial flexibility.
On Oct. 17, 2016, the Corporation declared a quarterly dividend of $0.04 per common share, payable on Jan. 1, 2017.
On Dec. 19, 2016, the Corporation declared a quarterly dividend of $0.04 per common share, payable on April 1, 2017.
There have been no other transactions involving common shares between the reporting date and the date of completion of
these consolidated financial statements.
F72
TransAlta Corporation | 2016 Annual Integrated Report
Notes to 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
2016
2015
Series
Series A
Series B
Series C
Series E
Series G
Issued and outstanding, end of year
Number of shares
(millions)
Amount
Number of shares
(millions)
Amount
10.2
1.8
11.0
9.0
6.6
38.6
248
45
269
219
161
942
12.0
-
11.0
9.0
6.6
38.6
293
-
269
219
161
942
I. Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares conversion
On March 17, 2016, the Corporation announced that 1,824,620 of its 12.0 million Series A Cumulative Fixed Redeemable Rate
Reset Preferred Shares (“Series A Shares”) were tendered for conversion, on a one-for-one basis, into Series B Cumulative
Redeemable Floating Rate Preferred Shares (“Series B Shares”) after having taken into account all election notices. As a result
of the conversion, the Corporation has 10.2 million Series A Shares and 1.8 million Series B Shares issued and outstanding at
Dec. 31, 2016.
The Series A Shares pay fixed cumulative preferential cash dividends on a quarterly basis, for the five-year period from and
including March 31, 2016 to but excluding March 31, 2021, if, as and when declared by the Board based on an annual fixed
dividend rate of 2.709 per cent.
The Series B Shares pay quarterly floating rate cumulative preferential cash dividends for the five-year period from and
including March 31, 2016 to but excluding March 31, 2021, if, as and when declared by the Board based on an annualized fixed
dividend rate of 2.539 per cent, and will reset every quarter.
II. Preferred Share Series Information
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:
(cid:131) Redeemable at the option of the Corporation, in whole or in part, for $25.00 per share, plus all declared and unpaid
dividends at the time of redemption.
(cid:131) Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred
shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then
Government of Canada 90-day Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The cumulative
floating rate first preferred shares are also redeemable at the option of the Corporation and convertible back into each
original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same terms as
noted above.
TransAlta Corporation | 2016 Annual Integrated Report
F73
Notes to Consolidated Financial Statements
Characteristics specific to each first preferred share series as at Dec. 31, 2016, are as follows:
Series
Rate during term
A
B
C
D
E
F
G
H
Fixed
Floating
Fixed
Floating
Fixed
Floating
Fixed
Floating
Annual dividend
rate per share ($)
0.79543
0.47608
1.15
-
1.25
-
1.325
-
Next
Conversion
Date
Rate spread
over Benchmark
(per cent)
Convertible to
Series
March 31, 2021
March 31, 2021
June 30, 2017
-
Sept. 30, 2017
-
Sept. 30, 2019
-
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 2016, 2015, and 2014:
Series
A
B
C
E
G
Total for the year
Total dividends declared ($)
2016
10
2015
14
2014
14
1
-
-
16
14
11
52
13
11
8
46
13
11
3
41
On Dec. 19, 2016, the Corporation declared a quarterly dividend of $0.16931 per share on the Series A preferred shares,
$0.15651 per share on the Series B preferred shares, $0.2875 per share on the Series C preferred shares, $0.3125 per share on
the Series E preferred shares, and $0.33125 per share on the Series G preferred shares, all payable on March 31, 2017.
F74
TransAlta Corporation | 2016 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 (losses) on translating net assets of foreign operations, net of
reclassifications to net earnings, net of tax(1)
(Gains) losses on financial instruments designated as hedges of foreign
operations, net of reclassifications to net earnings, net of tax(2)
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(3)
Balance, Dec. 31
Employee future benefits
Opening balance, Jan. 1
Net actuarial gains on defined benefit plans, net of tax(4)
Balance, Dec. 31
Other
Opening balance, Jan. 1
Intercompany available for sale investments
Balance, Dec. 31
Accumulated other comprehensive income
(1) Net of income tax expense of 11 for the year ended Dec. 31, 2016 (2015 - nil).
(2) Net of income tax expense of 5 for the year ended Dec. 31, 2016 (2015 - 8 expense).
(3) Net of income tax expense of 51 for the year ended Dec. 31, 2016 (2015 - 89 expense).
(4) Net of income tax expense of 4 for the year ended Dec. 31, 2016 (2015 - nil).
2016
2015
52
(19)
(71)
237
18
(1)
350
106
456
(46)
8
(38)
(3)
(15)
(18)
399
(166)
52
173
177
350
(50)
4
(46)
-
(3)
(3)
353
TransAlta Corporation | 2016 Annual Integrated Report
F75
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 compensation expense related to PSUs and RSUs in 2016 was $17 million (2015 - $3 million reversal,
2014 - $8 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 compensation expense related to the DSUs was $3 million in
2016 (2015 - $2 million reversal, 2014 - nil).
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.
In February 2016, the Corporation granted executive officers of the Corporation a total of 1.1 million stock options with an
exercise price of $5.93 that vest after a three-year period and expire seven years after issuance. The expense recognized
relating to this grant during 2016 was less than $1 million.
F76
TransAlta Corporation | 2016 Annual Integrated Report
The total options outstanding and exercisable under these stock option plans at Dec. 31, 2016 are outlined below:
Notes to Consolidated Financial Statements
Range of exercise prices
($ per share)
5.00 - 6.00
22.00 - 30.00(1)
31.00 - 48.00(1)
5.00 - 48.00
(1) Options currently exerciseable.
Number of
options at
Dec. 31, 2016
(millions)
1.1
0.6
0.5
2.2
Options outstanding
Weighted
average
remaining
contractual
life (years)
Weighted
average
exercise
price
($ per share)
6.1
3.1
1.1
4.2
5.93
23.60
34.35
28.93
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, 2016, amounts receivable from employees under the plan totaled $1 million (2015 - $2 million).
On Jan. 14, 2016, the Corporation suspended its employee share purchase plan.
TransAlta Corporation | 2016 Annual Integrated Report
F77
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, 2016, 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, 2016.
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 U.S. The latest
actuarial valuation for funding purposes of the Canadian registered plans was completed in early 2016 with an effective date
of Dec. 31, 2015. The latest actuarial valuation for funding purposes of the U.S. pension plan was Jan. 1, 2016. As permitted by
the regulators, the TransAlta Corporation pension plan uses a letter of credit to secure the required solvency special
payments. The Corporation posted a letter of credit in the amount of $75 million for the annual period commencing in
July 2016.
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 $73 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, 2016 and Jan. 1, 2016, respectively. The measurement date used to determine the present
value of the defined benefit obligation for both plans was Dec. 31, 2016.
The Corporation provides several defined contribution plans, including a U.S. 401(k) savings plan, that provide for company
contributions from 5 per cent to 10 per cent, depending on the plan. Optional employee contributions are allowed for all the
defined contribution plans.
F78
TransAlta Corporation | 2016 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:
Year ended Dec. 31, 2016
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, 2015
Current service cost
Administration expenses
Interest cost on defined benefit obligation
Interest on plan assets
Curtailment and amendment gain(1)
Defined benefit expense
Defined contribution expense
Net expense
Registered
Supplemental
Other
Total
7
2
21
(16)
-
14
15
29
2
-
3
-
-
5
-
5
2
-
1
-
-
3
-
3
11
2
25
(16)
-
22
15
37
Registered
Supplemental
Other
Total
7
2
21
(16)
-
14
21
35
2
-
3
-
(5)
-
-
-
2
-
1
-
(3)
-
-
-
11
2
25
(16)
(8)
14
21
35
(1) Relates to the reduction in the number of employees associated with the restructuring intative described in Note 4(L).
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
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
TransAlta Corporation | 2016 Annual Integrated Report
F79
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, 2016
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, 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
Registered
Supplemental
Other
423
(554)
(131)
(15)
(116)
(131)
10
(82)
(72)
(6)
(66)
(72)
-
(27)
(27)
(1)
(26)
(27)
Registered
Supplemental
Other
429
(566)
(137)
(11)
(126)
(137)
9
(80)
(71)
(5)
(66)
(71)
-
(32)
(32)
(2)
(30)
(32)
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, 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
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, 2016
427
16
6
12
(36)
(2)
6
429
16
10
11
(40)
(2)
(1)
423
8
-
-
7
-
-
-
1
(6)
(1)
-
-
9
-
-
6
(5)
-
-
10
-
-
-
-
-
1
(1)
-
-
-
Total
433
(663)
(230)
(22)
(208)
(230)
Total
438
(678)
(240)
(18)
(222)
(240)
Total
435
16
6
20
(43)
(2)
6
438
16
10
18
(46)
(2)
(1)
433
F80
TransAlta Corporation | 2016 Annual Integrated Report
The fair value of the Corporation’s defined benefit plan assets by major category is as follows:
Notes to Consolidated Financial Statements
Year ended Dec. 31, 2016
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, 2015
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
-
3
4
76
30
120
-
47
58
55
22
5
14
427
-
-
-
2
-
-
-
-
-
-
2
76
30
120
2
47
58
55
23
5
17
433
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
Plan assets do not include any common shares of the Corporation at Dec. 31, 2016 and Dec. 31, 2015. The Corporation
charged the registered plan $0.1 million for administrative services provided for the year ended Dec. 31, 2016 (2015 -
$0.1 million).
TransAlta Corporation | 2016 Annual Integrated Report
F81
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, 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
Current service cost
Interest cost
Benefits paid
Actuarial 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, 2016
565
7
21
(36)
(1)
3
-
-
7
566
7
21
(40)
(1)
2
-
(1)
554
86
2
3
(6)
-
2
(2)
(5)
-
80
2
3
(5)
-
-
2
-
82
30
2
1
(1)
-
2
(2)
(3)
3
32
2
1
(1)
(4)
-
(2)
(1)
27
681
11
25
(43)
(1)
7
(4)
(8)
10
678
11
25
(46)
(5)
2
-
(2)
663
The weighted average duration of the defined benefit plan obligation as at Dec. 31, 2016 is 13.6 years.
F. Contributions
The expected employer contributions for 2017 for the defined benefit pension and other post-employment benefit plans are
as follows:
Expected employer contributions
Registered
Supplemental
Other
15
6
1
Total
22
F82
TransAlta Corporation | 2016 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:
(per 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, 2016
As at Dec. 31, 2015
Registered
Supplemental
Other
Registered
Supplemental
Other
3.7
2.9
-
-
-
3.8
3.0
-
-
-
3.6
3.0
-
-
-
3.8
3.0
-
-
-
3.7
-
7.9(1)
4.0
-
3.8
-
7.8(2)
4.0
5.0
3.8
3.0
-
-
-
3.8
3.0
-
-
-
3.6
3.0
-
-
-
3.8
3.0
-
-
-
3.8
-
7.8(3)
4.0
5.0
3.8
-
7.5(4)
4.0
5.0
(1) Post- and Pre 65 rates: decreasing gradually to 4.5% by 2026 and remaining at that level thereafter for the U.S. and decreasing gradually by
0.3% per year to 4.5% in 2027 for Canada.
(2) Post- and Pre 65 rates: decreasing gradually to 4.5% by 2024 and remaining at that level thereafter for the U.S. and decreasing gradually by
0.35% per year to 5% in 2024 for Canada.
(3) Post- and Pre 65 rates: decreasing gradually to 4.5% by 2024 and remaining at that level thereafter for the U.S. and decreasing gradually by
0.35% per year to 5% in 2024 for Canada.
(4) Post- and Pre 65 rates: decreasing gradually to 5% by 2019-2020 and remaining at that level thereafter for the U.S. and decreasing gradually by
0.35% per year to 5% in 2024 for Canada.
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, 2016
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
9
-
17
12
1
-
2
2
-
2
-
3
-
-
1
1
-
-
-
TransAlta Corporation | 2016 Annual Integrated Report
F83
Notes to Consolidated Financial Statements
28. Joint Arrangements
Joint arrangements at Dec. 31, 2016 included the following:
Joint operations
Sheerness
Segment
Coal
Ownership
(per cent)
50
Genesee Unit 3
Keephills Unit 3
Goldfields Power
Fort Saskatchewan
Fortescue River Gas
Pipeline
Wintering Hills (1)
McBride Lake
Soderglen
Pingston
Coal
Coal
Gas
Gas
Gas
Wind
Wind
Wind
Hydro
50
50
50
60
43
51
50
50
50
(1) Classified as held for sale as at Dec. 31, 2016 (See Note 4(E)).
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
2016
2015
2014
(23)
5
(4)
11
81
3
73
(77)
(3)
1
(9)
(152)
(2)
(242)
59
(1)
1
7
8
(1)
73
F84
TransAlta Corporation | 2016 Annual Integrated Report
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
Notes to Consolidated Financial Statements
2016
4,361
3,094
942
9
(933)
399
1,152
(305)
(163)
8,556
2015
4,495
3,075
942
9
(1,018)
353
1,029
(54)
(190)
8,641
Increase/
(decrease)
(134)
19
-
-
85
46
123
(251)
27
(85)
(1) Includes finance lease obligations, amounts outstanding under credit facilities, tax equity liability, and current portion of long-term debt.
(2) The Corporation includes available cash and cash equivalents as a reduction in the calculation of capital as capital is managed internally and evaluated by
management using a net debt position. In this regard, these funds may be available, and used to facilitate repayment of debt.
(3) The Corporation includes the fair value of hedging instruments on debt in an asset, or liability, position as a reduction, or increase, in the calculation of capital, as the
carrying value of the related debt has either increased, or decreased, due to changes in foreign exchange rates.
In 2016, the Corporation focused on raising non-recourse debt to fund upcoming corporate debt maturities. The Corporation’s
overall capital management strategy and
from
Dec. 31, 2015 and are as follows:
in managing capital have remained unchanged
its objectives
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 (stable outlook), DBRS (negative outlook), and Fitch
(negative outlook). In December 2015, Moody's downgraded the Corporation below investment grade to Ba1 with a stable
outlook. During the first quarter of 2016, two rating agencies affirmed the Corporation’s long-term issuer rating as investment
grade, but revised their outlook to negative, from a previous stable outlook. The Corporation is focused on strengthening its
financial position and cash flow coverage ratios to achieve 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.
TransAlta Corporation | 2016 Annual Integrated Report
F85
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)
2016
3.8
17.0
2015
3.8
15.2
Target
4 to 5
20 to 25
3.8
5.0
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 capitalized interest) divided by interest on debt plus 50 per cent of dividends paid on
preferred shares. 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 2016 is consistent with 2015. 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 increased in 2016 compared to 2015 due to the increase in comparable FFO, and lower debt due to
repayments and the strengthening of the Canadian dollar in 2016. 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 2016 improved compared to 2015
due to the lower debt balance due to repayments and the strengthening of the Canadian dollar, and higher comparable
EBITDA. 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 2016, the Corporation continued to strengthen its financial position and reduce debt; using proceeds from the
dropdown of the Canadian Assets to pay out the credit facility balance, and reducing the Corporation’s dividend to
$0.16 per common share on an annualized basis from $0.72 per common share.
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.
F86
TransAlta Corporation | 2016 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, 2016 and 2015, 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
(1) Includes growth capital associated with the South Hedland power project.
2016
744
(73)
671
(69)
(42)
(151)
(358)
-
51
2015
432
242
674
(124)
(46)
(99)
(476)
(101)
(172)
Increase
(decrease)
312
(315)
(3)
55
4
(52)
118
101
223
TransAlta maintains sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to its
business. At Dec. 31, 2016, $1.4 billion (2015 - $1.3 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 replacing additional maturing recourse debt with debt secured by contracted cash flows.
During 2016, the Corporation paid out the credit facilities balance from a combination of cash flows from operations and net
cash proceeds of $173 million received from the sale of the economic interest of the Canadian assets that closed Jan. 6, 2016,
(see Note 4), extended the Corporation’s committed syndicated credit facility by one year to 2020, extended four bilateral
credit facilities to 2018 and 2020, paid out a matured $27 million non-recourse debenture using existing liquidity, the
Corporation’s subsidiary New Richmond Wind L.P. issued a $159 million non-recourse bond, the Corporation’s indirect wholly-
owned subsidiary TAPC Holdings L.P. issued a $202.5 million non-recourse bond, and converted 1.8 million of the Series A
Shares into Series B Shares. For further details see Notes 21 and 24.
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.
TransAlta Corporation | 2016 Annual Integrated Report
F87
Notes to Consolidated Financial Statements
31. Related-Party Transactions
Details of the Corporation’s principal operating subsidiaries at Dec. 31, 2016 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
64.0
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
Termination benefits
Share-based payments
2016
20
8
2
-
10
2015
9
8
2
1
(2)
2014
13
8
2
-
3
F88
TransAlta Corporation | 2016 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 other contractual
commitments, either directly or through its interests in joint operations. 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(1)
Growth
TransAlta Energy Bill
Total
2017
2018
2019
2020
2021
2022 and
thereafter
Total
40
9
163
79
7
181
6
485
13
11
48
29
7
5
6
119
6
8
49
24
7
1
6
101
5
8
51
41
7
-
6
5
4
52
30
7
-
6
100
3
472
51
68
-
12
169
43
835
254
103
187
42
118
104
706
1,633
(1) Includes amounts under certain evergreen contracts on the assumption of the Corporation's continued operations.
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 2025.
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. Some of these agreements
and the related commitments may be impacted by the cessation of coal-fired emissions from the Genesee 3 and Sheerness
coal-fired plants on or before Dec. 31, 2030.
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. Non-Cancellable Operating Leases
TransAlta has operating leases in place for buildings, vehicles, and various types of equipment and commitments for water
rights and transmission tower right of ways.
During the year ended Dec. 31, 2016, $9 million (2015 - $9 million, 2014 - $10 million) was recognized as an expense in
respect of these operating leases. Sublease payments received during 2016 and 2015 were less than $1 million (2015 – less
than $1 million). No contingent rental payments were made in respect of these operating leases.
TransAlta Corporation | 2016 Annual Integrated Report
F89
Notes to Consolidated Financial Statements
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, 2016, the Corporation has funded approximately US$22 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.
I. Line Loss Rule Proceeding
The Corporation is participating in a line loss rule proceeding (the "LLRP") which is currently before the AUC. The AUC
determined that it had the ability to retroactively adjust line loss rates beginning in 2006 and has directed the Alberta Electric
System Operator (the "AESO"), among other actions, to perform such calculations. The various decisions by the AUC are
subject to appeal and challenge. The Corporation may incur additional transmission charges as a result of the LLRP. The
outcome of the LLRP remains uncertain and the potential exposure, if any, cannot be calculated with any degree of certainty
until the retroactive calculations are made available. The AESO expects retroactive calculations to be available mid-2017, at
the earliest. As a result, no provision has been recorded. Certain PPAs for the Corporation’s Alberta facilities provide for the
pass through of these types of transmission charges to the Corporation’s buyers.
F90
TransAlta Corporation | 2016 Annual Integrated Report
Notes to Consolidated Financial Statements
33. Segment Disclosures
A. Description of Reportable Segments
The Corporation has eight reportable segments as described in Note 1. During 2016, the Corporation disaggregated
presentation of the previous Gas reportable segment into its two operating segments; Canadian Gas and Australian Gas. See
Note 3 for further details.
B. Reported Segment Earnings (Loss) and Segment Assets
I. Earnings Information
Year ended Dec. 31, 2016
Revenues
Fuel and purchased power
Gross margin
Operations, maintenance, and administration
Depreciation and amortization
Asset impairment
Restructuring provision
Taxes, other than income taxes
Net other operating income
Operating income (loss)
Finance lease income
Gain on sale of assets
Net interest expense
Foreign exchange loss
Earnings before income taxes
Year ended Dec. 31, 2015
(Restated - See Note 3)
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
Canadian
Coal
1,048
451
597
178
242
-
-
13
(2)
166
-
-
Canadian
Coal
912
441
471
194
237
-
11
12
(7)
24
-
-
U.S.
Coal
Canadian
Gas
Australian
Gas
Wind and
Solar
Hydro
Energy
Marketing
Corporate
Total
354
281
73
54
61
-
-
4
-
(46)
-
-
402
185
217
54
100
-
-
1
(191)
253
14
-
119
20
99
25
17
-
-
1
-
56
52
-
272
18
254
52
119
28
-
8
(1)
48
-
-
126
8
118
33
33
-
-
3
-
49
-
-
76
-
76
24
3
-
-
-
-
49
-
-
-
-
-
69
26
-
1
1
-
(97)
-
-
2,397
963
1,434
489
601
28
1
31
(194)
478
66
4
(229)
(5)
314
U.S.
Coal
372
316
56
50
63
(2)
1
3
-
(59)
-
-
Canadian
Gas
Australian
Gas
Wind and
Solar
Hydro
Energy
Marketing
Corporate
Total
454
204
250
67
75
-
1
3
-
104
9
262
114
20
94
21
20
-
-
-
-
53
49
-
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
TransAlta Corporation | 2016 Annual Integrated Report
F91
Notes to Consolidated Financial Statements
Year ended Dec. 31, 2014
(Restated - see Note 3)
Revenues
Fuel and purchased power
Gross margin
Operations, maintenance, and administration
Depreciation and amortization
Asset impairment reversals
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
Canadian
Coal
U.S.
Coal
Canadian
Gas
Australian
Gas
Wind
Hydro
Energy
Marketing
Corporate
Total
1,023
492
531
196
235
-
12
(9)
97
-
423
255
168
49
54
(5)
3
-
67
-
573
299
274
69
94
(1)
4
-
108
7
118
23
95
33
17
-
-
-
45
42
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
Included in revenues of the Wind and Solar Segment for the year ended Dec. 31, 2016 are $19 million (2015 - $20 million,
2014 - $21 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 $221 million for the year ended Dec. 31, 2016 (2014 - $230 million, 2014 -
$219 million).
II. Selected Consolidated Statements of Financial Position Information
As at Dec. 31, 2016
Goodwill
PP&E
Intangible assets
Canadian
Coal
U.S.
Coal
Canadian
Gas
Australian
Gas
Wind and
Solar
-
3,069
93
-
428
7
-
414
4
175
1,856
163
527
12
As at Dec. 31, 2015
Goodwill
PP&E (Restated - Note 3)
Intangibles (Restated - Note 3)
Canadian
Coal
U.S.
Coal
Canadian
Gas
Australian
Gas
Wind and
Solar
-
3,148
92
-
484
6
-
512
2
-
472
13
176
2,043
176
Hydro
259
503
3
Hydro
259
486
3
Energy
Marketing
Corporate
30
2
15
-
25
58
Total
464
6,824
355
Energy
Marketing
Corporate
Total
30
2
17
-
26
60
465
7,173
369
F92
TransAlta Corporation | 2016 Annual Integrated Report
Notes to Consolidated Financial Statements
III. Selected Consolidated Statements of Cash Flows Information
Additions to non-current assets are as follows:
Year ended
Dec. 31, 2016
Canadian
Coal
U.S.
Coal
Canadian
Gas
Australian
Gas
Wind and
Solar
Hydro
Energy
Marketing
Corporate
Total
Additions to non-current assets:
PP&E
Intangible assets
Year ended
Dec. 31, 2015
Additions to non-current assets:
159
3
15
1
11
1
107
-
16
-
43
-
-
-
7
16
358
21
Canadian
Coal
U.S.
Coal
Canadian
Gas
Australian
Gas
Wind and
Solar
Hydro
Energy
Marketing
Corporate
Total
PP&E (Restated - Note 3)
Intangibles (Restated - Note 3)
179
6
13
-
19
-
204
-
13
-
43
-
1
3
4
17
476
26
Year ended
Dec. 31, 2014
Canadian
Coal
U.S.
Coal
Canadian
Gas
Australian
Gas
Wind and
Solar
Hydro
Energy
Marketing
Corporate
Total
Additions to non-current assets:
PP&E (Restated - Note 3)
Intangibles (Restated - Note 3)
206
2
14
-
58
-
148
7
13
-
42
-
1
8
5
17
487
34
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
2016
2015
2014
601
545
538
63
59 56
-
1
1
664
605
595
C. Geographic Information
I. Revenues
Year ended Dec. 31
Canada
U.S.
Australia
Total revenue
2016
1,828
450
119
2,397
2015
1,705
448
114
2,267
2014
1,989
516
118
2,623
TransAlta Corporation | 2016 Annual Integrated Report
F93
Notes to Consolidated Financial Statements
II. Non-Current Assets
As at Dec. 31
Canada
U.S.
Australia
Total
Property, plant, and
equipment
2016
5,583
714
527
6,824
2015
5,902
799
472
7,173
Intangible assets
Other assets
Goodwill
2016
315
28
12
355
2015
328
28
13
369
2016
184
42
16
242
2015
79
37
17
133
2016
417
47
-
464
2015
417
48
-
465
D. Significant Customer
During the year ended Dec. 31, 2016, sales to two customers represented 25 per cent and 16 per cent, respectively, of the
Corporation’s total revenue (2015 - 13 per cent and 17 per cent).
34. Subsequent Events
A. Preferred Share Exchange
On Feb. 10, 2017, the Corporation announced that it would not proceed with the transaction previously announced on Dec. 19,
2016, pursuant to which all currently outstanding first preferred shares in the capital of the Corporation would be exchanged
for shares in a single new series of cumulative redeemable minimum rate reset first preferred shares in the capital of the
Corporation.
B. Wintering Hills
On Jan. 26, 2017, the Corporation announced the sale of its 51 per cent interest in the Wintering Hills merchant wind facility
for approximately $61 million. The sale closed March 1, 2017.
F94
TransAlta Corporation | 2016 Annual Integrated Report
Exhibit 1
Exhibit 1
(Unaudited)
The information set out below is referred to as “unaudited” as a means of clarifying that it is not covered by the audit opinion
of the independent registered public accounting firm that has audited and reported on the “Consolidated Financial
Statements”.
To the Financial Statements of TransAlta Corporation
EARNINGS COVERAGE RATIO
The following selected financial ratio is calculated for the year ended Dec. 31, 2016:
Earnings coverage on long-term debt supporting the Corporation’s Shelf Prospectus
1.85 times
Earnings coverage on long-term debt on a net earnings basis is equal to net earnings before interest expense and income taxes, divided by interest expense including
capitalized interest.
TransAlta Corporation | 2016 Annual Integrated Report
F95
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)
2016
2015
2014
2,397
478
117
10,996
334
3,722
1,152
942
2,569
(163)
8,556
744
(327)
0.41
0.13
0.30
8.92
7.54
3.76
7.43
51.0
44.2
3.8
5.4
1.7
5.3
4.4
1.7
7.8
1,145
11.5
4.0
17.0
3.8
288
288
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
2,341
2,380
2,786
5,131
1,482
2,334
–
8,947
38,157
5,126
1,405
2,350
–
8,881
40,673
5,111
1,531
2,204
–
8,846
45,002
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”)
190
TransAlta Corporation | 2016 Annual Integrated Report
Eleven-Year Financial and Statistical Summary
2013
2012
2011
2010
2009
2008
2007
2006
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
2,210
(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
2,772
2,084
2,235
2,389
2,343
2,200
2,201
2,687
5,111
1,779
2,202
396
9,488
42,482
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
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
TransAlta Corporation | 2016 Annual Integrated Report
191
Capacity
(MW)(1)
2,141
Ownership
(%)
100%
Net capacity
ownership interest
(MW)(1)(2)
Region
2,141 Western Canada
Plant Summary
As of Dec. 31, 2016
Coal
6 Facilities
Total Coal
Gas
13 Facilities
Total Gas
Wind
21 Facilities
Total Wind
Solar
1 Facility
Total Solar
Hydro
27 Facilities
Facility*
Sundance, AB
Keephills, AB
Keephills 3, AB
Genesee 3, AB
Sheerness, AB
Centralia, WA
Poplar Creek, AB(9)
Fort Saskatchewan, AB
Sarnia, ON*
Mississauga, ON
Ottawa, ON
Windsor, ON
Southern Cross, WA*(10)(11)
South Hedland, WA*(11)(12)
Solomon, WA*(11)
Parkeston, WA*(11)
Summerview 1, AB*
Summerview 2, AB*
Ardenville, AB*
Blue Trail, AB*
Wintering Hills, AB(13)
Castle River, AB*(14)
McBride Lake, AB*
Soderglen, AB*
Cowley North, AB*
Sinnott, AB*
Macleod Flats, AB*
Melancthon, ON*(15)
Wolfe Island, ON*
Kent Breeze, ON
Kent Hills, NB*(15)
Le Nordais, QC*
New Richmond, QC*
Wyoming Wind, WY*
Lakeswind, MN
Mass Solar, MA(16)
Brazeau, AB
Bighorn, 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*
Ragged Chute, ON*
Misema, ON*
Galetta, ON*
Appleton, ON*
Moose Rapids, ON*
Skookumchuck, WA
Total Hydro
Total
* TransAlta Renewables Inc. facility.
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%
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
790
1,340
5,990
230
118
506
108
74
72
245
150
125
110
1,738
70
66
69
66
88
44
75
71
20
7
3
200
198
20
150
98
68
144
50
1,505
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
10,202
(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 December 31, 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) Merchant capacity refers to uprates on unit 1 (10 MW).
(7) LTC refers to Long-Term Contract.
Revenue
source
Alberta PPA(3)/
Merchant(4)
Alberta PPA/
Merchant(5)
Merchant
Merchant
Alberta PPA/
Merchant(6)
LTC(7)/Merchant
LTC
LTC
LTC
LTC
LTC/Merchant
LTC/Merchant
LTC
LTC
LTC
LTC
Merchant
Merchant
Merchant
Merchant
Merchant
Merchant
LTC
Merchant
Merchant
Merchant
Merchant
LTC
LTC
LTC
LTC
LTC
LTC
LTC
LTC
Contract
expiry date
2017-2020
2020
-
-
2020
2020-2025(8)
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
198 Western Canada
1,340
4,933
United States
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
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
1,363
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
8,716
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
2046
2029
2027
2030
2030
2030
2020
(8) Contract is in place until 2025; however, one unit is set to retire in 2020.
(9) The Poplar Creek plant is operated by Suncor and ownership of the facility will transfer
to Suncor in 2030.
(10) Comprised of four facilities.
(11) Gas/diesel.
(12) Plant is under construction and expected to be fully commissioned in mid-2017.
(13) On January 16, 2017 we announced the sale of our 51% interest in Wintering Hills.
The transaction closed in the first quarter of 2017.
(14) Includes seven individual turbines at other locations.
(15) Comprised of two facilities.
(16) Comprised of four ground-mounted projects and four roof-top projects.
192
TransAlta Corporation | 2016 Annual Integrated Report
Sustainability Performance Indicators
Corporate Statistics
Environment, Health and Safety Management Systems
2016
2015
2014
Facilities with ISO 14001 and/or OHSAS 18001-based management systems (percentage)(1)
Management system audits(2)
97
35
97
23
98
26
Environmental Performance
Resource or Energy Use(3)
Coal combustion (tonnes) ✓
Natural gas combustion (GJ) ✓
Diesel combustion (L) ✓
Gasoline consumption: vehicle (L) ✓
Diesel consumption: vehicle (L) ✓
Propane consumption: vehicle (L) ✓
Electricity: building operations (MWh) ✓
Natural gas: building operations (GJ) ✓
Propane: building operations (L) ✓
Kerosene: building operations (L) ✓
Total resource or energy use (GJ) ✓
Greenhouse Gas Emissions(4)
Carbon dioxide (tonnes CO2e) ✓
Methane (tonnes CO2e) ✓
Nitrous oxide (tonnes CO2e) ✓
Sulphur hexafluoride (tonnes CO2e)
Total greenhouse gas emissions (tonnes CO2e)(5) ✓
Greenhouse gas emission intensity (tonnes CO2e/MWh)(6) ✓
Air Emissions(7)
Total sulphur dioxide emissions (tonnes) ✓
Sulphur dioxide emission intensity (kg/MWh)(8) ✓
Total nitrogen oxide emissions (tonnes) ✓
Nitrogen oxide emission intensity (kg/MWh)(8) ✓
Total particulate matter emissions (tonnes) ✓
Particulate matter emission intensity (kg/MWh)(8) ✓
Total mercury emissions (kilograms) ✓
Mercury emission intensity (mg/MWh)(8) ✓
Water Management(9)
Water intake (million m3) ✓
Water discharge (million m3) ✓
Water consumption (million m3) ✓
Water intensity (m3/MWh)(10) ✓
Waste Management(11)
Non-Hazardous
Landfill (tonnes) ✓
Landfill (L) ✓
Ash disposal: mine (tonnes)(12) ✓
Ash disposal: lagoon (tonnes)(13) ✓
Recycled (tonnes) ✓
Recycled (L) ✓
Reuse (tonnes) ✓
Storage (tonnes) ✓
2016
2015
2014
15,735,300
62,490,800
43,824,800
1,487,200
40,226,100
78,800
359,300
58,300
127,500
56,500
17,851,900
58,273,000
261,400
1,474,100
40,959,900
135,900
244,800
72,400
63,600
54,800
528,353,700 542,362,600 584,070,500
16,222,300
63,411,200
22,557,000
1,376,300
43,182,100
113,600
220,800
58,500
102,700
60,100
30,375,900
114,200
224,500
20
30,714,600
0.84
31,902,700
112,600
212,400
20
32,227,800
0.87
34,724,400
119,200
231,200
10
35,074,800
0.88
39,600
1.09
48,400
1.33
4,900
0.14
130
3.54
247
188
59
2
41,800
1.13
48,000
1.30
4,900
0.13
170
4.50
272
198
74
2
47,600
1.2
52,900
1.34
5,200
0.13
220
5.66
243
172
71
2
2,100
518,400
1,315,000
527,700
18,000
212,100
700,700
8,300
2,400
131,200
1,346,900
501,600
151,100
222,100
707,800
14,800
2,500
42,300
1,636,200
532,800
89,000
157,500
846,300
33,600
TransAlta Corporation | 2016 Annual Integrated Report
193
Sustainability Performance Indicators
Environmental Performance (continued)
2016
2015
2014
Waste Management (continued)
Hazardous(14)
Landfill (tonnes) ✓
Landfill (L) ✓
Recycled (tonnes) ✓
Recycled (L) ✓
Land Use and Reclamation(15)
Land used in mining activities: disturbed (cumulative hectares)
Land used in mining activities: reclaimed (cumulative hectares)
Land reclamation (% of land disturbed)(16)
Land used in mining activities: disturbed minus reclaimed (hectares)
Land used by plants, offices, and equipment (hectares)
Total land use (cumulative hectares)
Environmental Incidents
Total environmental incidents(17) ✓
Environmental enforcement actions
Environmental fines ($ thousands)
Spills(18)
Volume of significant spills (m3)
Volume of significant spills recovered (m3)
% of spills recovered
Social Performance
Workplace Practices
Employees
Number of full-time employees
Number of part-time employees
Number of contingent employees
Employees represented by independent trade union organizations (%)(19)
Voluntary employee turnover rate (%)(20)
Diversity
Women in workforce (%)
Women in senior management (%)
Women on Board of Directors (%)
Health and Safety
Health and safety enforcement actions(21)
Health and safety fines ($ thousands)
Employee & contractor fatalities ✓
Lost-time injury (absence from work) ✓
Medical aids (no absence from work) ✓
Total injuries to employees & contractors ✓
Total injury frequency rate (employees and contractors)(22) ✓
Reportable vehicle incidents
Community Relations
Community investments ($ millions)(23)
2016 data has been third-party assured to a limited assurance level by Ernst & Young LLP.
✓
Please see “Discussion and Notes on Numbers” for footnote explanations.
40
13,100
60
17,209,600
40
3,300
80
536,100
10
569,100
50
352,400
11,800
4,600
39
7,200
3,900
11,100
16
0
0
61
47
78
11,700
4,500
39
7,200
3,900
11,100
12
1
2
19
19
99
11,600
4,500
39
7,100
3,700
10,900
15
0
0
463
446
96
2016
2015
2014
2,341
2,267
26
48
53
6.71
18
26
33
4
5
0
4
20
24
0.85
33
2,380
2,301
26
53
54
5.22
18
25
30
0
0
0
5
20
25
0.75
28
2.5
3.5
2,786
2,629
79
78
53
6.97
19
35
36
0
0
0
5
17
22
0.86
37
3.6
194
TransAlta Corporation | 2016 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)
(2)
(3)
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, regulatory frameworks, and against the Alberta Certificate of Recognition standard.
Energy use is calculated and reported from TransAlta-operated facilities following the same approach we use for greenhouse gas reporting, which is
application of an Operational Control boundary.
(4) Greenhouse gas emissions (GHG) are calculated and reported from TransAlta-operated facilities in line with carbon regulation where the facility is
located and with The Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard (specifically ‘Setting Organizational Boundaries:
Operational Control’ methodology). As per the Operational Control methodology, TransAlta reports 100 per cent of GHG emissions from facilities at
which we are the operator. GHG emissions include emissions from stationary combustion, transportation use, building use, and fugitive emissions.
(5) Gross GHG emissions or gross carbon dioxide equivalent (CO2e) emissions is the sum of carbon dioxide, methane, nitrous oxide, and sulphur
hexafluoride. Coincidentally, the sum of scope 1 and 2 emissions will equate to gross CO2e emissions or gross GHG emissions.
(6) GHG emission intensity is calculated by dividing total operational emissions by 100 per cent of production (MWh) from operated facilities, irrespective
of financial ownership.
(7) Air emissions are reported from TransAlta-operated facilities, following the same approach we use for GHG reporting, which is application of an
Operational Control boundary. Air emissions are expressed in tonnes, except for mercury emissions, which are represented in kilograms. Particulate
matter emissions include both PM2.5 and PM10.
(8) Air emission intensities are calculated by dividing total operational emissions by 100 per cent of production (MWh) from operated facilities,
irrespective of financial ownership.
(9) Water usage is reported from TransAlta-operated facilities, following the same approach we use for GHG reporting, which is application of an
Operational Control boundary. Total water consumed is measured by total water intake minus water discharge. Water is used primarily for cooling by
our thermal power plants. Evaporative losses from the cooling ponds and cooling towers account for 95 per cent of the consumptive loss. The water
lost to evaporation is not returned directly to the water body, but the water remains in the hydrologic cycle.
(10) Water usage intensity is calculated by dividing total operational water consumption (m3) by 100 per cent of production (MWh) from operated
facilities, irrespective of financial ownership.
(11) Non-hazardous waste includes, but is not limited to, water treatment chemicals, coal refuse (including ash-byproducts), metals, paper, cardboard and
building materials.
(12) Ash disposal: mine is fly ash and bottom ash from coal production, which is treated and then returned to its original source, the mine, for landfill/disposal.
(13) Ash disposal: lagoon is fly ash and bottom ash from Keephills coal production, which is treated and then sent to ash lagoons for disposal.
(14) Hazardous wastes are substances going for disposal, which – either in the short or the long term – can be harmful to people, plants, animals, or
the environment.
(15) Total land use is mining land use plus land used by plants, offices, and equipment.
(16) Disturbed land use and reclaimed volumes were restated in 2016 for 2014-2016, due to an internal reconciliation reporting error.
(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.
(19) TransAlta has over 1,200 unionized workers working primarily at our operations.
(20) Voluntary turnover is aligned with our Human Resources voluntary turnover reporting methodology. As per this methodology, voluntary turnover is
any full-time, part-time, or contingent employee initiated exit, excluding retirement. Summer students and temporary workers are not considered
within voluntary turnover.
(21) Health and safety incidents are those 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. In 2016 we had four traffic enforcement actions that resulted in fines of C$5,000.
(22) 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.
(23) Cumulative of donations and sponsorship totals in the respective calendar year. This investment figure does not include donations from our employees.
TransAlta Corporation | 2016 Annual Integrated Report
195
Independent Sustainability Assurance Statement
To the Board of Directors and Management of TransAlta Corporation (“TransAlta”).
Scope of Ernst & Young LLP (“EY”)
Engagement
EY responsibilities included providing limited assurance over
• Energy use: Coal combustion (tonnes)
• Energy use: Natural gas combustion (GJ)
• Energy use: Diesel combustion (L)
a selection of performance indicators.
Subject Matter
We have performed limited assurance procedures for the
following quantitative performance indicators (“Subject
Matter”) for the year ending December 31, 2016.
• 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)
• Gross greenhouse gas emissions and emissions intensity
(tonnes CO2e, tonnes CO2e/GWh)
• Total environmental incidents
• Lost time incident for employees and contractors
(LTI) (absence from work)
• Energy use: Gasoline combustion: vehicle (L)
• Energy use: Diesel combustion: vehicle (L)
• Energy use: Propane combustion: vehicle (L)
• Energy use: Electricity – building operations (MWh)
• Energy use: Natural gas – building operations (GJ)
• Energy use: Propane – building operations (L)
• Energy use: Kerosene – building operations (L)
• Water intake, discharge, consumption (million m3)
• Water intensity (m3/MWh)
• Waste Management – Non-hazardous
• Landfill (tonnes, L)
• Ash Disposal: mine, lagoon (tonnes)
• Recycled (tonnes, L)
• Reuse (tonnes)
• Storage (tonnes)
• Waste Management – Hazardous
• Landfill (tonnes, L)
• Recycled (tonnes, L)
Criteria
TransAlta has prepared its specified performance information
in accordance with industry standards and, where relevant,
• Medical aids (MA) for employees and contractors
internally developed criteria.
(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 fatalities
TransAlta Management Responsibilities
The Subject Matter was prepared by the management of
TransAlta, who is responsible for the assertions, statements,
and claims made therein including the assertions we have
been engaged to provide limited assurance over, collection,
quantification and presentation of the performance
indicators and the criteria used in determining that the
information is appropriate for the purpose of disclosure
in this Report (“the Report”). In addition, management is
responsible for maintaining adequate records and internal
controls that are designed to support the reporting process.
196
TransAlta Corporation | 2016 Annual Integrated Report
Independent Sustainability Assurance Statement
EY Responsibilities
Our limited assurance procedures have been planned and
Limitations of EY Work Performed
Our scope of work did not include expressing conclusions in
performed in accordance with the International Standard
relation to:
on Assurance Engagements (“ISAE”) 3000 “Assurance
• The materiality, completeness or accuracy of data sets or
Engagements other than Audits or Reviews of Historical
information relating to areas other than the selected
Financial Information”.
Our procedures were designed to obtain a limited level of
assurance on which to base our conclusion. 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 reasonable level of
assurance. While we considered the effectiveness of
performance data, and any site-specific information.
• Management’s forward looking statements.
• Any comparisons made by TransAlta against historical data.
• The appropriateness of definitions for internally developed
criteria.
Independence and Competency Statement
In conducting our engagement, we have complied with
management’s internal controls when determining the nature
the applicable requirements of the Code of Ethics for
and extent of our procedures, our assurance engagement
Professional Accountants issued by the International Ethics
was not designed to provide assurance on internal controls
Standards Board for Accountants (“IESBA”).
and, accordingly, we express no conclusions thereon.
This assurance statement has been prepared for TransAlta
EY Conclusion
Based on our procedures for this limited assurance
for the purpose of assisting management in determining
engagement described in this statement, nothing has come
whether the Subject Matter is in accordance with the criteria
to our attention that causes us to believe that the Subject
and for no other purpose. Our assurance statement is made
Matter is not, in all material respects, reported in accordance
solely to TransAlta in accordance with the terms of our
with the relevant criteria.
engagement. We do not accept or assume responsibility
to anyone other than TransAlta for our work, or for the
conclusions we have reached in this assurance statement.
Assurance Procedures
We planned and performed our work to obtain all the
Ernst & Young LLP
Calgary, Canada
evidence, information and explanations considered necessary
March 2, 2017
in relation to the above scope. Our assurance procedures
included but were not limited to:
• Interviewing relevant personnel at the head office and at
various sites to understand data management processes
related to the selected performance indicators.
• Checking the accuracy of calculations performed – on a test
basis – primarily through inquiry, variance analysis and
performance of re-calculations.
• Assessing risk of material misstatement due to fraud or
errors relating to the selected performance indicators.
• Evaluating the overall presentation of the Report, including
the consistency of the Subject Matter.
TransAlta Corporation | 2016 Annual Integrated Report
197
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 2016
Record Date
Payment Date
Ex-Dividend Date
April 1, 2016
July 1, 2016
Oct. 1, 2016
Jan. 1, 2017
April 1, 2017
March 1, 2016
June 1, 2016
Sept. 1, 2016
Dec. 1, 2016
March 1, 2017
Feb. 26, 2016
May 30, 2016
Aug. 30, 2016
Nov. 29, 2016
Feb. 27, 2017
Dividend
$0.04
$0.04
$0.04
$0.04
$0.04
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 Thursday, April 20, 2017 at
BMO Centre (Stampede Park)
20 Roundup Way 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.E, 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.
198
TransAlta Corporation | 2016 Annual Integrated Report
Shareholder Information
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 SW
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
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 $0.67724 per share from and including
March 31, 2016 to but excluding March 31, 2021.
Series B: Floating cumulative preferential cash dividends are paid quarterly
when declared by the Board from and including March 31, 2016 to but excluding
March 31, 2021.
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 2016
Series A
Payment Date
March 31, 2016
June 30, 2016
Sept. 30, 2016
Dec. 31, 2016
March 31, 2017
Record Date
March 1, 2016
June 1, 2016
Sept. 1, 2016
Dec. 1, 2016
March 1, 2017
Ex-Dividend Date
Feb. 26, 2016
May 30, 2016
Aug. 30, 2016
Nov. 29, 2016
Feb. 27, 2017
Series B
Payment Date
June 30, 2016
Sept. 30, 2016
Dec. 31, 2016
March 31, 2017
Series C
Payment Date
March 31, 2016
June 30, 2016
Sept. 30, 2016
Dec. 31, 2016
March 31, 2017
Series E
Payment Date
March 31, 2016
June 30, 2016
Sept. 30, 2016
Dec. 31, 2016
March 31, 2017
Series G
Payment Date
March 31, 2016
June 30, 2016
Sept. 30, 2016
Dec. 31, 2016
March 31, 2017
Record Date
June 1, 2016
Sept. 1, 2016
Dec. 1, 2016
March 1, 2017
Record Date
March 1, 2016
June 1, 2016
Sept. 1, 2016
Dec. 1, 2016
March 1, 2017
Record Date
March 1, 2016
June 1, 2016
Sept. 1, 2016
Dec. 1, 2016
March 1, 2017
Record Date
March 1, 2016
June 1, 2016
Sept. 1, 2016
Dec. 1, 2016
March 1, 2017
Ex-Dividend Date
May 30, 2016
Aug. 30, 2016
Nov. 29, 2016
Feb. 27, 2017
Ex-Dividend Date
Feb. 26, 2016
May 30, 2016
Aug. 30, 2016
Nov. 29, 2016
Feb. 27, 2017
Ex-Dividend Date
Feb. 26, 2016
May 30, 2016
Aug. 30, 2016
Nov. 29, 2016
Feb. 27, 2017
Ex-Dividend Date
Feb. 26, 2016
May 30, 2016
Aug. 30, 2016
Nov. 29, 2016
Feb. 27, 2017
Dividend
$0.2875
$0.16931
$0.16931
$0.16931
$0.16931
Dividend
$0.15490
$0.16144
$0.15974
$0.15651
Dividend
$0.2875
$0.2875
$0.2875
$0.2875
$0.2875
Dividend
$0.3125
$0.3125
$0.3125
$0.3125
$0.3125
Dividend
$0.33125
$0.33125
$0.33125
$0.33125
$0.33125
Dividends are paid on the last day of the month in March, June, September, and December. When a dividend
payment date falls on a weekend or holiday, the payment is made on the following business day. Only dividend
payments that have been approved by the Board of Directors are included in this table.
TransAlta Corporation | 2016 Annual Integrated Report
199
Shareholder Highlights
150
125
100
75
50
25
Total Shareholder Return vs. S&P/TSX Composite Index
Year ended Dec. 31 ($)
TransAlta
S&P/TSX Composite
07
100
100
08
75
65
09
77
85
10
73
97
11
77
86
12
59
90
13
57
98
14
48
106
15
24
94
16
39
111
This chart compares what $100 invested in TransAlta and the S&P/TSX Composite at the end of 2007 would be
worth today, assuming the reinvestment of all dividends.
07
08
09
10
11
12
13
14
15
16
TransAlta
S&P/TSX Composite
Source: FactSet
40.00
30.00
20.00
10.00
Ten-Year Trading Range and Market Value vs. Book Value
Year ended Dec. 31 ($ per share)
07
08
09
10
11
12
13
14
Market Value
33.35 24.30 23.48
21.15
21.02
15.12
13.48
10.52
Book Value
11.39
12.70
13.41
12.85
12.08
8.78
7.92
8.52
15
4.91
8.52
16
7.43
8.92
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).
07
08
09
10
11
12
13
14
15
16
Market Value
Book Value
Trading Range
Source: FactSet and TransAlta
30
20
10
$9
$6
$3
Monthly Volume and Market Prices
(2016)
Volume (millions)
Jan
29
Feb Mar Apr May
25
30
21
25
Jun
17
Jul Aug
Sep Oct Nov Dec
13
11
17
10
22
15
TSX closing price
4.92
5.93 6.04 6.56 6.30 6.72 6.23 5.68 5.83
5.91
7.35
7.43
J
JMAMF
DNOSAJ
Volume
(millions of shares)
TSX closing price
($ per share)
Source: FactSet
30
20
10
0
(10)
(20)
(30)
200
Return on Common Shareholders’ Equity
(%)
ROE
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)
16
5.4
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
07
08
09
10
11
12
13
14
15
16
TransAlta Corporation | 2016 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 Chairs, 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
Email: 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
Wayne A. Collins
Executive Vice-President,
Coal and Mining Operations
Aron J. Willis
Senior Vice-President,
Gas & Renewables
Jennifer M. Pierce
Senior Vice-President,
Trading & Marketing
Todd J. Stack
Managing Director,
Corporate Controller
Scott T. Jeffers
Assistant Corporate Secretary
and Legal Counsel
TransAlta Corporation | 2016 Annual Integrated Report
201
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.
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 assets 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.
202
TransAlta Corporation | 2016 Annual Integrated Report
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.
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.
Glossary of Key Terms
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 mailings 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.
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TransAlta Corporation
110 - 12th Avenue SW
Box 1900, Station “M”
Calgary, Alberta
Canada T2P 2M1
403.267.7110
www.transalta.com